GEORGIA POWER CO - Quarter Report: 2012 June (Form 10-Q)
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2012
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number |
Registrant, State of Incorporation, Address and Telephone Number |
I.R.S. Employer Identification No. | ||
1-3526 |
The Southern Company (A Delaware Corporation) 30 Ivan Allen Jr. Boulevard, N.W. Atlanta, Georgia 30308 (404) 506-5000 |
58-0690070 | ||
1-3164 |
Alabama Power Company (An Alabama Corporation) 600 North 18th Street Birmingham, Alabama 35203 (205) 257-1000 |
63-0004250 | ||
1-6468 |
Georgia Power Company (A Georgia Corporation) 241 Ralph McGill Boulevard, N.E. Atlanta, Georgia 30308 (404) 506-6526 |
58-0257110 | ||
001-31737 |
Gulf Power Company (A Florida Corporation) One Energy Place Pensacola, Florida 32520 (850) 444-6111 |
59-0276810 | ||
001-11229 |
Mississippi Power Company (A Mississippi Corporation) 2992 West Beach Gulfport, Mississippi 39501 (228) 864-1211 |
64-0205820 | ||
333-98553 |
Southern Power Company (A Delaware Corporation) 30 Ivan Allen Jr. Boulevard, N.W. Atlanta, Georgia 30308 (404) 506-5000 |
58-2598670 |
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Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No ¨
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes þ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
Registrant |
Large Accelerated Filer |
Accelerated Filer |
Non- accelerated Filer |
Smaller Reporting Company | ||||
The Southern Company |
X | |||||||
Alabama Power Company |
X | |||||||
Georgia Power Company |
X | |||||||
Gulf Power Company |
X | |||||||
Mississippi Power Company |
X | |||||||
Southern Power Company |
X |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes ¨ No þ (Response applicable to all registrants.)
Registrant |
Description of |
Shares Outstanding at June 30, 2012 | ||
The Southern Company |
Par Value $5 Per Share | 874,796,883 | ||
Alabama Power Company |
Par Value $40 Per Share | 30,537,500 | ||
Georgia Power Company |
Without Par Value | 9,261,500 | ||
Gulf Power Company |
Without Par Value | 4,542,717 | ||
Mississippi Power Company |
Without Par Value | 1,121,000 | ||
Southern Power Company |
Par Value $0.01 Per Share | 1,000 |
This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Southern Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.
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INDEX TO QUARTERLY REPORT ON FORM 10-Q
June 30, 2012
Page Number |
||||||
5 | ||||||
7 | ||||||
PART IFINANCIAL INFORMATION | ||||||
Item 1. |
Financial Statements (Unaudited) |
|||||
Item 2. |
Managements Discussion and Analysis of Financial Condition and Results of Operations |
|||||
10 | ||||||
11 | ||||||
12 | ||||||
13 | ||||||
Managements Discussion and Analysis of Financial Condition and Results of Operations |
15 | |||||
38 | ||||||
38 | ||||||
39 | ||||||
40 | ||||||
Managements Discussion and Analysis of Financial Condition and Results of Operations |
42 | |||||
59 | ||||||
59 | ||||||
60 | ||||||
61 | ||||||
Managements Discussion and Analysis of Financial Condition and Results of Operations |
63 | |||||
83 | ||||||
83 | ||||||
84 | ||||||
85 | ||||||
Managements Discussion and Analysis of Financial Condition and Results of Operations |
87 | |||||
106 | ||||||
106 | ||||||
107 | ||||||
108 | ||||||
Managements Discussion and Analysis of Financial Condition and Results of Operations |
110 | |||||
133 | ||||||
133 | ||||||
134 | ||||||
135 | ||||||
Managements Discussion and Analysis of Financial Condition and Results of Operations |
137 | |||||
150 | ||||||
Item 3. |
36 | |||||
Item 4. |
36 |
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INDEX TO QUARTERLY REPORT ON FORM 10-Q
June 30, 2012
Page Number |
||||||
PART IIOTHER INFORMATION | ||||||
Item 1. |
185 | |||||
Item 1A. |
185 | |||||
Item 2. |
Unregistered Sales of Equity Securities and Use of Proceeds |
Inapplicable | ||||
Item 3. |
Defaults Upon Senior Securities |
Inapplicable | ||||
Item 4. |
Mine Safety Disclosures |
Inapplicable | ||||
Item 5. |
Other Information |
Inapplicable | ||||
Item 6. |
186 | |||||
190 |
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Term | Meaning | |
2010 ARP | Alternate Rate Plan approved by the Georgia PSC for Georgia Power, which became effective January 1, 2011 and will continue through December 31, 2013 | |
2011 IRP Update | Georgia Powers 2011 Integrated Resource Plan update filed with the Georgia PSC on August 4, 2011 | |
AFUDC | Allowance for funds used during construction | |
Alabama Power | Alabama Power Company | |
ARO | Asset retirement obligation | |
Clean Air Act | Clean Air Act Amendments of 1990 | |
CPCN | Certificate of public convenience and necessity | |
CWIP | Construction work in progress | |
DOE | U.S. Department of Energy | |
ECO Plan | Mississippi Powers Environmental Compliance Overview Plan | |
EPA | U.S. Environmental Protection Agency | |
FERC | Federal Energy Regulatory Commission | |
Fitch | Fitch, Inc. | |
Form 10-K | Combined Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power for the year ended December 31, 2011 | |
GAAP | Generally accepted accounting principles | |
Georgia Power | Georgia Power Company | |
Gulf Power | Gulf Power Company | |
IIC | Intercompany Interchange Contract | |
Internal Revenue Code | Internal Revenue Code of 1986, as amended | |
IRS | Internal Revenue Service | |
Kemper IGCC | Integrated coal gasification combined cycle facility under construction in Kemper County, Mississippi | |
KWH | Kilowatt-hour | |
LIBOR | London Interbank Offered Rate | |
Mississippi Power | Mississippi Power Company | |
mmBtu | Million British thermal unit | |
Moodys | Moodys Investors Service, Inc. | |
MW | Megawatt | |
MWH | Megawatt-hour | |
NCCR | Georgia Powers Nuclear Construction Cost Recovery | |
NDR | Alabama Powers natural disaster reserve | |
NRC | Nuclear Regulatory Commission | |
NSR | New Source Review | |
OCI | Other Comprehensive Income | |
PEP | Mississippi Powers Performance Evaluation Plan | |
Plant Vogtle Units 3 and 4 | Two new nuclear generating units under construction at Plant Vogtle | |
Power Pool | The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power are subject to joint commitment and dispatch in order to serve their combined load obligations | |
PPA | Power Purchase Agreement | |
PSC | Public Service Commission | |
registrants | Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power |
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ROE | Return on equity | |
SEC | Securities and Exchange Commission | |
SEGCO | Southern Electric Generating Company | |
SMEPA | South Mississippi Electric Power Association | |
Southern Company | The Southern Company | |
Southern Company system | Southern Company, the traditional operating companies, Southern Power, and other subsidiaries | |
Southern Nuclear | Southern Nuclear Operating Company, Inc. | |
Southern Power |
Southern Power Company | |
S&P |
Standard and Poors Ratings Services, a division of The McGraw Hill Companies, Inc. | |
traditional operating companies |
Alabama Power, Georgia Power, Gulf Power, and Mississippi Power | |
Westinghouse |
Westinghouse Electric Company LLC | |
wholesale revenues |
revenues generated from sales for resale |
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales, retail rates, economic recovery, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related estimated expenditures, access to sources of capital, projections for the qualified pension plan and other postretirement benefit plan contributions, financing activities, start and completion of construction projects, plans and estimated costs for new generation resources, filings with state and federal regulatory authorities, impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, estimated sales and purchases under new power sale and purchase agreements, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as may, will, could, should, expects, plans, anticipates, believes, estimates, projects, predicts, potential, or continue or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
| the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water, coal combustion byproducts, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, financial reform legislation, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations; |
| current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and IRS and state tax audits; |
| the effects, extent, and timing of the entry of additional competition in the markets in which Southern Companys subsidiaries operate; |
| variations in demand for electricity, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), and the effects of energy conservation measures; |
| available sources and costs of fuels; |
| effects of inflation; |
| ability to control costs and avoid cost overruns during the development and construction of facilities; |
| investment performance of Southern Companys employee benefit plans and nuclear decommissioning trust funds; |
| advances in technology; |
| state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms; |
| regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals, NRC actions, and potential DOE loan guarantees; |
| regulatory approvals and actions related to the Kemper IGCC, including Mississippi PSC approvals, potential DOE loan guarantees, the SMEPA purchase decision, utilization of investment tax credits, and the outcome of any further proceedings regarding the Mississippi PSCs issuance of the CPCN; |
| the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities; |
| internal restructuring or other restructuring options that may be pursued; |
| potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries; |
| the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required; |
| the ability to obtain new short- and long-term contracts with wholesale customers; |
| the direct or indirect effect on Southern Companys business resulting from terrorist incidents and the threat of terrorist incidents, including cyber intrusion; |
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| interest rate fluctuations and financial market conditions and the results of financing efforts, including Southern Companys and its subsidiaries credit ratings; |
| the impacts of any potential U.S. credit rating downgrade or other sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the availability or benefits of proposed DOE loan guarantees; |
| the ability of Southern Company and its subsidiaries to obtain additional generating capacity at competitive prices; |
| catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as influenzas, or other similar occurrences; |
| the direct or indirect effects on Southern Companys business resulting from incidents affecting the U.S. electric grid or operation of generating resources; |
| the effect of accounting pronouncements issued periodically by standard setting bodies; and |
| other factors discussed elsewhere herein and in other reports filed by the registrants from time to time with the SEC. |
The registrants expressly disclaim any obligation to update any forward-looking statements.
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AND SUBSIDIARY COMPANIES
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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the Three Months Ended June 30, |
For the Six Months Ended June 30, |
|||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in millions) | (in millions) | |||||||||||||||
Operating Revenues: |
||||||||||||||||
Retail revenues |
$ | 3,597 | $ | 3,842 | $ | 6,689 | $ | 7,238 | ||||||||
Wholesale revenues |
415 | 507 | 764 | 956 | ||||||||||||
Other electric revenues |
154 | 154 | 302 | 303 | ||||||||||||
Other revenues |
15 | 18 | 30 | 36 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total operating revenues |
4,181 | 4,521 | 7,785 | 8,533 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Operating Expenses: |
||||||||||||||||
Fuel |
1,290 | 1,673 | 2,354 | 3,149 | ||||||||||||
Purchased power |
150 | 145 | 291 | 245 | ||||||||||||
Other operations and maintenance |
944 | 910 | 1,911 | 1,854 | ||||||||||||
MC Asset Recovery insurance settlement |
(19 | ) | | (19 | ) | | ||||||||||
Depreciation and amortization |
445 | 430 | 886 | 848 | ||||||||||||
Taxes other than income taxes |
228 | 227 | 453 | 447 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total operating expenses |
3,038 | 3,385 | 5,876 | 6,543 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Operating Income |
1,143 | 1,136 | 1,909 | 1,990 | ||||||||||||
Other Income and (Expense): |
||||||||||||||||
Allowance for equity funds used during construction |
32 | 36 | 63 | 71 | ||||||||||||
Interest expense, net of amounts capitalized |
(220 | ) | (199 | ) | (431 | ) | (421 | ) | ||||||||
Other income (expense), net |
13 | (4 | ) | 11 | (2 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other income and (expense) |
(175 | ) | (167 | ) | (357 | ) | (352 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Earnings Before Income Taxes |
968 | 969 | 1,552 | 1,638 | ||||||||||||
Income taxes |
329 | 349 | 529 | 580 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Consolidated Net Income |
639 | 620 | 1,023 | 1,058 | ||||||||||||
Dividends on Preferred and Preference Stock of Subsidiaries |
16 | 16 | 32 | 32 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries |
$ | 623 | $ | 604 | $ | 991 | $ | 1,026 | ||||||||
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|
|
|
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|
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Common Stock Data: |
||||||||||||||||
Earnings per share (EPS) - |
||||||||||||||||
Basic EPS |
$ | 0.71 | $ | 0.71 | $ | 1.14 | $ | 1.20 | ||||||||
Diluted EPS |
$ | 0.71 | $ | 0.70 | $ | 1.13 | $ | 1.20 | ||||||||
Average number of shares of common stock outstanding (in millions) |
||||||||||||||||
Basic |
872 | 855 | 870 | 851 | ||||||||||||
Diluted |
880 | 862 | 879 | 858 | ||||||||||||
Cash dividends paid per share of common stock |
$ | 0.4900 | $ | 0.4725 | $ | 0.9625 | $ | 0.9275 |
The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.
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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
For the Three
Months Ended June 30, |
For the Six Months Ended June 30, |
|||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in millions) | (in millions) | |||||||||||||||
Consolidated Net Income |
$ | 639 | $ | 620 | $ | 1,023 | $ | 1,058 | ||||||||
Other comprehensive income (loss): |
||||||||||||||||
Qualifying hedges: |
||||||||||||||||
Changes in fair value, net of tax of $(8), $-, $(5) and $2, respectively |
(10 | ) | | (7 | ) | 3 | ||||||||||
Reclassification adjustment for amounts included in net income, net of tax of $2, $1, $3 and $3, respectively |
2 | | 4 | 3 | ||||||||||||
Marketable securities: |
||||||||||||||||
Change in fair value, net of tax of $-, $2, $- and $1, respectively |
| 3 | | 2 | ||||||||||||
Pension and other post retirement benefit plans: |
||||||||||||||||
Reclassification adjustment for amounts included in net income, net of tax of $1, $(1), $1 and $1, respectively |
1 | 1 | 2 | | ||||||||||||
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|
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Total other comprehensive income (loss) |
(7 | ) | 4 | (1 | ) | 8 | ||||||||||
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Dividends on preferred and preference stock of subsidiaries |
(16 | ) | (16 | ) | (32 | ) | (32 | ) | ||||||||
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Comprehensive Income |
$ | 616 | $ | 608 | $ | 990 | $ | 1,034 | ||||||||
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|
|
|
|
|
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.
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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
For the Six Months Ended June 30, |
||||||||
2012 | 2011 | |||||||
(in millions) | ||||||||
Operating Activities: |
||||||||
Consolidated net income |
$ | 1,023 | $ | 1,058 | ||||
Adjustments to reconcile consolidated net income to net cash provided from operating activities |
||||||||
Depreciation and amortization, total |
1,064 | 1,011 | ||||||
Deferred income taxes |
327 | 427 | ||||||
Allowance for equity funds used during construction |
(63 | ) | (71 | ) | ||||
Pension, postretirement, and other employee benefits |
13 | (38 | ) | |||||
Stock based compensation expense |
35 | 27 | ||||||
Retail fuel cost over recoverylong-term |
44 | | ||||||
Other, net |
(17 | ) | (6 | ) | ||||
Changes in certain current assets and liabilities |
||||||||
-Receivables |
(55 | ) | (156 | ) | ||||
-Fossil fuel stock |
(305 | ) | 81 | |||||
-Other current assets |
(53 | ) | (106 | ) | ||||
-Accounts payable |
(167 | ) | 58 | |||||
-Accrued taxes |
45 | 300 | ||||||
-Accrued compensation |
(216 | ) | (193 | ) | ||||
-Retail fuel cost over recoveryshort-term |
101 | (6 | ) | |||||
-Other current liabilities |
(19 | ) | 3 | |||||
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|
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|
|||||
Net cash provided from operating activities |
1,757 | 2,389 | ||||||
|
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|
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Investing Activities: |
||||||||
Property additions |
(2,356 | ) | (2,126 | ) | ||||
Investment in restricted cash |
(230 | ) | (3 | ) | ||||
Distribution of restricted cash |
49 | 61 | ||||||
Nuclear decommissioning trust fund purchases |
(576 | ) | (1,405 | ) | ||||
Nuclear decommissioning trust fund sales |
574 | 1,401 | ||||||
Proceeds from property sales |
2 | 17 | ||||||
Cost of removal, net of salvage |
(58 | ) | (68 | ) | ||||
Change in construction payables |
(134 | ) | 37 | |||||
Other investing activities |
(62 | ) | 22 | |||||
|
|
|
|
|||||
Net cash used for investing activities |
(2,791 | ) | (2,064 | ) | ||||
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|
|||||
Financing Activities: |
||||||||
Decrease in notes payable, net |
(406 | ) | (440 | ) | ||||
Proceeds |
||||||||
Long-term debt issuances |
2,487 | 1,950 | ||||||
Interest-bearing refundable deposit related to asset sale |
150 | | ||||||
Common stock issuances |
316 | 482 | ||||||
Redemptions |
||||||||
Long-term debt |
(1,319 | ) | (1,504 | ) | ||||
Payment of common stock dividends |
(837 | ) | (787 | ) | ||||
Payment of dividends on preferred and preference stock of subsidiaries |
(32 | ) | (32 | ) | ||||
Other financing activities |
19 | (4 | ) | |||||
|
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|
|
|||||
Net cash provided from (used for) financing activities |
378 | (335 | ) | |||||
|
|
|
|
|||||
Net Change in Cash and Cash Equivalents |
(656 | ) | (10 | ) | ||||
Cash and Cash Equivalents at Beginning of Period |
1,315 | 447 | ||||||
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|
|||||
Cash and Cash Equivalents at End of Period |
$ | 659 | $ | 437 | ||||
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Supplemental Cash Flow Information: |
||||||||
Cash paid (received) during the period for |
||||||||
Interest (net of $41 and $35 capitalized for 2012 and 2011, respectively) |
$ | 391 | $ | 419 | ||||
Income taxes, net |
(34 | ) | (355 | ) | ||||
Noncash transactions accrued property additions at end of period |
488 | 407 |
The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.
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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Assets |
At June 30, 2012 |
At December 31, 2011 |
||||||
(in millions) | ||||||||
Current Assets: |
||||||||
Cash and cash equivalents |
$ | 659 | $ | 1,315 | ||||
Restricted cash and cash equivalents |
192 | 8 | ||||||
Receivables |
||||||||
Customer accounts receivable |
1,164 | 1,074 | ||||||
Unbilled revenues |
497 | 376 | ||||||
Under recovered regulatory clause revenues |
20 | 143 | ||||||
Other accounts and notes receivable |
261 | 282 | ||||||
Accumulated provision for uncollectible accounts |
(23 | ) | (26 | ) | ||||
Fossil fuel stock, at average cost |
1,672 | 1,367 | ||||||
Materials and supplies, at average cost |
919 | 903 | ||||||
Vacation pay |
161 | 160 | ||||||
Prepaid expenses |
577 | 385 | ||||||
Other regulatory assets, current |
208 | 239 | ||||||
Other current assets |
66 | 46 | ||||||
|
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|
|
|||||
Total current assets |
6,373 | 6,272 | ||||||
|
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|
|||||
Property, Plant, and Equipment: |
||||||||
In service |
61,577 | 59,744 | ||||||
Less accumulated depreciation |
21,616 | 21,154 | ||||||
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|
|||||
Plant in service, net of depreciation |
39,961 | 38,590 | ||||||
Other utility plant, net |
53 | 55 | ||||||
Nuclear fuel, at amortized cost |
807 | 774 | ||||||
Construction work in progress |
5,745 | 5,591 | ||||||
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Total property, plant, and equipment |
46,566 | 45,010 | ||||||
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|
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Other Property and Investments: |
||||||||
Nuclear decommissioning trusts, at fair value |
1,235 | 1,207 | ||||||
Leveraged leases |
660 | 649 | ||||||
Miscellaneous property and investments |
260 | 262 | ||||||
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|
|||||
Total other property and investments |
2,155 | 2,118 | ||||||
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Deferred Charges and Other Assets: |
||||||||
Deferred charges related to income taxes |
1,390 | 1,365 | ||||||
Unamortized debt issuance expense |
157 | 156 | ||||||
Unamortized loss on reacquired debt |
288 | 285 | ||||||
Deferred under recovered regulatory clause revenues |
29 | 48 | ||||||
Other regulatory assets, deferred |
3,484 | 3,532 | ||||||
Other deferred charges and assets |
455 | 481 | ||||||
|
|
|
|
|||||
Total deferred charges and other assets |
5,803 | 5,867 | ||||||
|
|
|
|
|||||
Total Assets |
$ | 60,897 | $ | 59,267 | ||||
|
|
|
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.
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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholders Equity |
At June 30, 2012 |
At December 31, 2011 |
||||||
(in millions) | ||||||||
Current Liabilities: |
||||||||
Securities due within one year |
$ | 2,075 | $ | 1,717 | ||||
Interest-bearing refundable deposit related to asset sale |
150 | | ||||||
Notes payable |
453 | 859 | ||||||
Accounts payable |
1,253 | 1,553 | ||||||
Customer deposits |
363 | 347 | ||||||
Accrued taxes |
||||||||
Accrued income taxes |
17 | 13 | ||||||
Unrecognized tax benefits |
6 | 22 | ||||||
Other accrued taxes |
337 | 425 | ||||||
Accrued interest |
237 | 226 | ||||||
Accrued vacation pay |
204 | 205 | ||||||
Accrued compensation |
246 | 450 | ||||||
Liabilities from risk management activities |
160 | 209 | ||||||
Other regulatory liabilities, current |
144 | 125 | ||||||
Other current liabilities |
443 | 426 | ||||||
|
|
|
|
|||||
Total current liabilities |
6,088 | 6,577 | ||||||
|
|
|
|
|||||
Long-term Debt |
19,459 | 18,647 | ||||||
|
|
|
|
|||||
Deferred Credits and Other Liabilities: |
||||||||
Accumulated deferred income taxes |
9,352 | 8,809 | ||||||
Deferred credits related to income taxes |
216 | 224 | ||||||
Accumulated deferred investment tax credits |
704 | 611 | ||||||
Employee benefit obligations |
2,409 | 2,442 | ||||||
Asset retirement obligations |
1,385 | 1,321 | ||||||
Other cost of removal obligations |
1,195 | 1,165 | ||||||
Other regulatory liabilities, deferred |
295 | 297 | ||||||
Other deferred credits and liabilities |
588 | 514 | ||||||
|
|
|
|
|||||
Total deferred credits and other liabilities |
16,144 | 15,383 | ||||||
|
|
|
|
|||||
Total Liabilities |
41,691 | 40,607 | ||||||
|
|
|
|
|||||
Redeemable Preferred Stock of Subsidiaries |
375 | 375 | ||||||
|
|
|
|
|||||
Stockholders Equity: |
||||||||
Common Stockholders Equity: |
||||||||
Common stock, par value $5 per share |
||||||||
Authorized 1.5 billion shares |
||||||||
Issued June 30, 2012: 875 million shares |
||||||||
December 31, 2011: 866 million shares |
||||||||
Treasury June 30, 2012: 0.6 million shares |
||||||||
December 31, 2011: 0.5 million shares |
||||||||
Par value |
4,377 | 4,328 | ||||||
Paid-in capital |
4,755 | 4,410 | ||||||
Treasury, at cost |
(18 | ) | (17 | ) | ||||
Retained earnings |
9,122 | 8,968 | ||||||
Accumulated other comprehensive loss |
(112 | ) | (111 | ) | ||||
|
|
|
|
|||||
Total Common Stockholders Equity |
18,124 | 17,578 | ||||||
Preferred and Preference Stock of Subsidiaries |
707 | 707 | ||||||
|
|
|
|
|||||
Total Stockholders Equity |
18,831 | 18,285 | ||||||
|
|
|
|
|||||
Total Liabilities and Stockholders Equity |
$ | 60,897 | $ | 59,267 | ||||
|
|
|
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.
14
Table of Contents
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SECOND QUARTER 2012 vs. SECOND QUARTER 2011
AND
YEAR-TO-DATE 2012 vs. YEAR-TO-DATE 2011
OVERVIEW
Southern Company is a holding company that owns all of the common stock of the traditional operating companiesAlabama Power, Georgia Power, Gulf Power, and Mississippi Powerand Southern Power and other direct and indirect subsidiaries. Discussion of the results of operations is focused on the Southern Company systems primary business of electricity sales by the traditional operating companies and Southern Power. The four traditional operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Companys other business activities include investments in leveraged lease projects and telecommunications. For additional information on these businesses, see BUSINESSThe Southern Company SystemTraditional Operating Companies, Southern Power, and Other Businesses in Item 1 of the Form 10-K.
Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and earnings per share. For additional information on these indicators, see MANAGEMENTS DISCUSSION AND ANALYSISOVERVIEWKey Performance Indicators of Southern Company in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$19 |
3.1 | $(35) | (3.4) |
Southern Companys second quarter 2012 net income after dividends on preferred and preference stock of subsidiaries was $623 million ($0.71 per share) compared to $604 million ($0.71 per share) for the second quarter 2011. The increase for the second quarter 2012 when compared to the corresponding period in 2011 was primarily the result of increases in revenues associated with the elimination of a tax-related adjustment under Alabama Powers rate structure, an increase related to retail revenue rate effects at Georgia Power, an increase related to retail base revenues at Gulf Power, increases in usage and customer growth, an insurance recovery received related to the litigation settlement with MC Asset Recovery, LLC, and lower income taxes. The net income increase for the second quarter 2012 was partially offset by a decrease in revenues due to milder weather, an increase in operations and maintenance expenses, an increase in depreciation on additional plant in service related to new generation, transmission, distribution, and environmental projects, an increase in interest expense, and lower energy revenues at Southern Power.
Southern Companys year-to-date 2012 net income after dividends on preferred and preference stock of subsidiaries was $991 million ($1.14 per share) compared to $1.03 billion ($1.20 per share) for year-to-date 2011. The net income decrease for year-to-date 2012 when compared to the corresponding period in 2011 was primarily the result of a decrease in revenues due to milder weather, an increase in operations and maintenance expenses, an increase in depreciation on additional plant in service related to new generation, transmission, distribution, and environmental projects, an increase in interest expense, and lower energy revenues at Southern Power. The net income decrease for year-to-date 2012 was partially offset by increases in revenues associated with the elimination of a tax-related adjustment under Alabama Powers rate structure, an increase related to retail revenue rate effects at Georgia Power, an increase related to retail base and retail interim revenues at Gulf Power, increases in usage and customer growth, and an insurance recovery received related to the litigation settlement with MC Asset Recovery, LLC.
15
Table of Contents
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(245) |
(6.4) | $(549) | (7.6) |
In the second quarter 2012, retail revenues were $3.60 billion compared to $3.84 billion for the corresponding period in 2011. For year-to-date 2012, retail revenues were $6.69 billion compared to $7.24 billion for the corresponding period in 2011.
Details of the change to retail revenues were as follows:
Second Quarter 2012 |
Year-to-Date 2012 |
|||||||||||||||
(in millions) | (% change) | (in millions) | (% change) | |||||||||||||
Retail prior year |
$3,842 | $7,238 | ||||||||||||||
Estimated change in |
||||||||||||||||
Rates and pricing |
75 | 2.0 | 134 | 1.9 | ||||||||||||
Sales growth (decline) |
23 | 0.6 | 40 | 0.5 | ||||||||||||
Weather |
(84) | (2.2) | (197) | (2.7) | ||||||||||||
Fuel and other cost recovery |
(259) | (6.8) | (526) | (7.3) | ||||||||||||
|
||||||||||||||||
Retail current year |
$3,597 | (6.4)% | $ 6,689 | (7.6)% | ||||||||||||
|
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 primarily due to the elimination of a tax-related adjustment under Alabama Powers rate structure and an increase related to retail base and retail interim revenues at Gulf Power. Also contributing to the increase were increases in retail revenues at Georgia Power due to base tariff increases effective April 1, 2012 related to placing Plant McDonough-Atkinson Units 4 and 5 in service, the NCCR and demand-side management tariff increases effective January 1, 2012, as approved by the Georgia PSC, and the rate pricing effect of decreased customer usage, partially offset by lower contributions from market-driven rates from commercial and industrial customers.
Revenues attributable to changes in sales increased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011. For second quarter 2012, the increase was due to a 2.1% increase in weather-adjusted residential KWH sales and a 1.2% increase in weather-adjusted commercial KWH sales, partially offset by a 0.1% decrease in industrial KWH sales. The increases in weather-adjusted residential and commercial KWH sales for the second quarter 2012 are due to increases in usage and customer growth. The decrease in industrial KWH sales for the second quarter 2012 is primarily due to decreases in the textiles and paper sectors, largely offset by increases in the pipeline and transportation sectors. For year-to-date 2012, the increase was due to a 1.3% increase in weather-adjusted residential KWH sales and a 0.9% increase in industrial KWH sales, while weather-adjusted commercial KWH sales remained flat. The increase in weather-adjusted residential KWH sales for year-to-date 2012 is due to increases in usage and customer growth. The increase in industrial KWH sales year-to-date 2012 is primarily due to increases in the pipeline, lumber, and transportation sectors, partially offset by decreases in the textiles sector.
Revenues resulting from changes in weather decreased $84 million in the second quarter 2012 and $197 million year-to-date 2012 when compared to the corresponding periods in 2011 as a result of milder weather.
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Table of Contents
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and other cost recovery revenues decreased $259 million in the second quarter 2012 and decreased $526 million for year-to-date 2012 when compared to the corresponding periods in 2011. Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.
Wholesale Revenues
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(92) |
(18.1) | $(192) | (20.1) | |||
|
Wholesale revenues consist of PPAs with investor-owned utilities and electric cooperatives, unit power sales contracts, and short-term opportunity sales. Wholesale revenues from PPAs and unit power sales contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company systems generation, demand for energy within the Southern Company systems service territory, and the availability of the Southern Company systems generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company systems variable cost to produce the energy.
In the second quarter 2012, wholesale revenues were $415 million compared to $507 million for the corresponding period in 2011, reflecting a $106 million decrease in energy revenues, partially offset by a $14 million increase in capacity revenues. The decrease in energy revenues was primarily related to a reduction in the average price of energy and lower energy sales mainly due to lower customer demand.
For year-to-date 2012, wholesale revenues were $764 million compared to $956 million for the corresponding period in 2011, reflecting a $213 million decrease in energy revenues, partially offset by a $21 million increase in capacity revenues. The decrease in energy revenues was primarily related to a reduction in the average price of energy and lower energy sales mainly due to lower customer demand.
Fuel and Purchased Power Expenses
Second Quarter 2012 Second Quarter 2011 |
Year-to-Date 2012 Year-to-Date 2011 | |||||||||||
| ||||||||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||||||||
Fuel |
$(383) | (22.9) | $(795) | (25.2) | ||||||||
Purchased power |
5 | 3.4 | 46 | 18.8 | ||||||||
|
|
|
||||||||||
Total fuel and purchased power expenses |
$(378) | $(749) | ||||||||||
|
|
|
In the second quarter 2012, total fuel and purchased power expenses were $1.44 billion compared to $1.82 billion for the corresponding period in 2011. The decrease was primarily the result of a $415 million decrease in the average cost of fuel and purchased power and a $133 million decrease in the volume of KWHs generated, partially offset by a $170 million increase in the volume of KWHs purchased.
For year-to-date 2012, total fuel and purchased power expenses were $2.64 billion compared to $3.39 billion for the corresponding period in 2011. The decrease was primarily the result of a $777 million decrease in the average cost of fuel and purchased power and a $430 million decrease in the volume of KWHs generated, partially offset by a $458 million increase in the volume of KWHs purchased.
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Table of Contents
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel expenses at the traditional operating companies are generally offset by fuel revenues and do not have a significant effect on net income. See FUTURE EARNINGS POTENTIALPSC MattersRetail Fuel Cost Recovery herein for additional information. Fuel expenses incurred under Southern Powers PPAs are generally the responsibility of the counterparties and do not significantly affect net income.
Details of the Southern Company systems generation and purchased power were as follows:
Second Quarter 2012 |
Second Quarter 2011 |
Year-to-Date 2012 |
Year-to-Date 2011 | |||||
| ||||||||
Total generation (billions of KWHs) |
44 | 48 | 83 | 94 | ||||
Total purchased power (billions of KWHs) |
5 | 2 | 9 | 4 | ||||
| ||||||||
Sources of generation (percent) |
||||||||
Coal |
41 | 56 | 38 | 54 | ||||
Nuclear |
17 | 15 | 18 | 16 | ||||
Gas |
41 | 26 | 41 | 27 | ||||
Hydro |
1 | 3 | 3 | 3 | ||||
| ||||||||
Cost of fuel, generated (cents per net KWH) |
||||||||
Coal |
4.18 | 4.06 | 4.14 | 4.01 | ||||
Nuclear |
0.83 | 0.72 | 0.81 | 0.70 | ||||
Gas |
2.56 | 4.23 | 2.66 | 4.08 | ||||
| ||||||||
Average cost of fuel, generated (cents per net KWH) |
2.94 | 3.56 | 2.90 | 3.48 | ||||
Average cost of purchased power (cents per net KWH)(a) |
4.09 | 7.51 | 3.98 | 8.07 | ||||
|
(a) | Average cost of purchased power includes fuel purchased by the electric utilities for tolling agreements where power is generated by the provider. |
Fuel
In the second quarter 2012, fuel expense was $1.29 billion compared to $1.67 billion for the corresponding period in 2011. The decrease was primarily due to a 39.5% decrease in the average cost of gas per KWH generated, a higher percentage of generation from lower cost natural gas-fired resources, and lower customer demand mainly due to milder weather.
For year-to-date 2012, fuel expense was $2.35 billion compared to $3.15 billion for the corresponding period in 2011. The decrease was primarily due to a 34.8% decrease in the average cost of gas per KWH generated, a higher percentage of generation from lower cost natural gas-fired resources, and lower customer demand mainly due to milder weather.
Purchased Power
In the second quarter 2012, purchased power expense was $150 million compared to $145 million for the corresponding period in 2011. The increase was primarily due to a 93.3% increase in the volume of KWHs purchased as the market cost of available energy was lower than the marginal cost of generation available, partially offset by a 45.5% decrease in the average cost per KWH purchased.
For year-to-date 2012, purchased power expense was $291 million compared to $245 million for the corresponding period in 2011. The increase was primarily due to a 158.9% increase in the volume of KWHs purchased as the market cost of available energy was lower than the marginal cost of generation available, partially offset by a 50.7% decrease in the average cost per KWH purchased.
Energy purchases will vary depending on demand for energy within the Southern Company systems service territory, the market prices of wholesale energy as compared to the cost of the Southern Company systems generation, and the availability of the Southern Company systems generation.
18
Table of Contents
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Operations and Maintenance Expenses
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$34 |
3.7 | $57 | 3.1 | |||
|
In the second quarter 2012, other operations and maintenance expenses were $944 million compared to $910 million for the corresponding period in 2011. The increase was primarily the result of a $28 million increase in administrative and general costs primarily due to increases in pension costs and other employee benefits and a $16 million increase in transmission and distribution costs. The increase was partially offset by a $10 million decrease at Mississippi Power related to the expiration of an operating lease for Plant Daniel Units 3 and 4, as well as a $4 million decrease primarily related to scheduled outage and maintenance costs and commodity and labor costs.
For year-to-date 2012, other operations and maintenance expenses were $1.91 billion compared to $1.85 billion for the corresponding period in 2011. The increase was primarily the result of a $71 million increase in administrative and general costs primarily due to increases in pension costs, outside services, and other employee benefits. Also contributing to the increase was a $15 million increase in transmission and distribution costs and a $6 million net increase in customer accounts and customer service related costs. The increase was partially offset by a $21 million decrease at Mississippi Power related to the expiration of an operating lease for Plant Daniel Units 3 and 4, as well as an $18 million decrease primarily related to scheduled outage and maintenance costs and commodity and labor costs.
See MANAGEMENTS DISCUSSION AND ANALYSISFINANCIAL CONDITION AND LIQUIDITYPurchase of the Plant Daniel Combined Cycle Generating Units of Southern Company in Item 7 of the Form 10-K for additional information.
MC Asset Recovery Insurance Settlement
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(19) |
N/M | $(19) | N/M | |||
|
N/M Not meaningful
In the second quarter 2012, Southern Company received an insurance recovery related to the litigation settlement with MC Asset Recovery, LLC, which resulted in income of $19 million. See Note (B) to the Condensed Financial Statements under Insurance Recovery herein for additional information.
Depreciation and Amortization
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$15 |
3.5 | $38 | 4.5 | |||
|
In the second quarter 2012, depreciation and amortization was $445 million compared to $430 million for the corresponding period in 2011. For year-to-date 2012, depreciation and amortization was $886 million compared to $848 million for the corresponding period in 2011. The increases were primarily the result of an increase in depreciation due to additional plant in service related to new generation at Georgia Powers Plant McDonough-Atkinson Units 4 and 5, as well as transmission, distribution, and environmental projects.
19
Table of Contents
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Allowance for Equity Funds Used During Construction
Second Quarter 2012 vs. Second Quarter 2011 |
Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
(change in millions) |
(% change) | (change in millions) | (% change) | |||
$(4) |
(11.1) | $(8) | (11.3) |
In the second quarter 2012, AFUDC equity was $32 million compared to $36 million for the corresponding period in 2011. For year-to-date 2012, AFUDC equity was $63 million compared to $71 million for the corresponding period in 2011. The decreases were primarily due to the completion of Georgia Powers Plant McDonough-Atkinson Units 4 and 5 in December 2011 and April 2012, respectively, partially offset by increases in CWIP related to Mississippi Powers Kemper IGCC.
Interest Expense, Net of Amounts Capitalized
Second Quarter 2012 vs. Second Quarter 2011 |
Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
(change in millions) |
(% change) | (change in millions) | (% change) | |||
$21 |
10.6 | $10 | 2.4 |
In the second quarter 2012, interest expense, net of amounts capitalized was $220 million compared to $199 million for the corresponding period in 2011. For year-to-date 2012, interest expense, net of amounts capitalized was $431 million compared to $421 million for the corresponding period in 2011. The increases were primarily due to a $23 million reduction in interest expense in 2011 at Georgia Power resulting from the settlement of litigation with the Georgia Department of Revenue and a net increase in interest expense related to senior notes. The increases were partially offset by a decrease related to the conclusion of certain state and federal income tax audits, a decrease in interest expense on existing variable rate pollution control revenue bonds, and an increase in capitalized interest associated with construction projects at Mississippi Power and Southern Power.
Other Income (Expense), Net
Second Quarter 2012 vs. Second Quarter 2011 |
Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
(change in millions) |
(% change) | (change in millions) | (% change) | |||
$17 |
N/M | $13 | N/M |
N/M Not meaningful
In the second quarter 2012, other income (expense), net was $13 million compared to $(4) million for the corresponding period in 2011. For year-to-date 2012, other income (expense), net was $11 million compared to $(2) million for the corresponding period in 2011. The increases were primarily due to the conclusion of certain federal income tax audits.
Income Taxes
Second Quarter 2012 vs. Second Quarter 2011 |
Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
(change in millions) |
(% change) | (change in millions) | (% change) | |||
$(20) |
(5.7) | $(51) | (8.8) |
In the second quarter 2012, income taxes were $329 million compared to $349 million for the corresponding period in 2011. For year-to-date 2012, income taxes were $529 million compared to $580 million for the corresponding period in 2011. The decreases were primarily due to lower pre-tax earnings and state income tax credits. See Note (G) to the Condensed Financial Statements herein under Unrecognized Tax Benefits for additional information.
20
Table of Contents
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Companys future earnings potential. The level of Southern Companys future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Companys primary business of selling electricity. These factors include the traditional operating companies ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Another major factor is the profitability of the competitive wholesale supply business. Future earnings for the electricity business in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities and other wholesale customers, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale supply business also depends on numerous factors including creditworthiness of customers, total generating capacity available and related costs, future acquisitions and construction of generating facilities, and the successful remarketing of capacity as current contracts expire. Changes in economic conditions impact sales for the traditional operating companies and Southern Power, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under Environmental Matters in Item 8 of the Form 10-K for additional information.
New Source Review Actions
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters New Source Review Actions of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under Environmental Matters New Source Review Actions in Item 8 of the Form 10-K for additional information. On February 23, 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power (including claims related to a unit co-owned by Mississippi Power). The U.S. District Court for the Northern District of Alabama has not ruled on the EPAs motion seeking vacatur of the judgment. The ultimate outcome of this matter cannot be determined at this time.
Climate Change Litigation
Hurricane Katrina Case
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Climate Change Litigation Hurricane Katrina Case of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under Environmental Matters Climate Change Litigation Hurricane Katrina Case in Item 8 of the Form 10-K for additional information. On March 20, 2012, the U.S. District Court for the
21
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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern District of Mississippi dismissed the amended class action complaint filed in May 2011 by the plaintiffs. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
General
See MANAGEMENTS DISCUSSION AND ANALYSISFUTURE EARNINGS POTENTIALEnvironmental Matters Environmental Statutes and Regulations General of Southern Company in Item 7 of the Form 10-K for information regarding the Southern Company systems estimated base level capital expenditures to comply with existing statutes and regulations for 2012 through 2014, as well as the Southern Company systems preliminary estimates for potential incremental environmental compliance investments associated with complying with the EPAs final Mercury and Air Toxics Standards (MATS) rule (formerly referred to as the Utility Maximum Achievable Control Technology rule) and the EPAs proposed water and coal combustion byproducts rules.
The Southern Company system is continuing to develop its compliance strategy and to assess the potential costs of complying with the MATS rule and the EPAs proposed water and coal combustion byproducts rules. As part of the development of its compliance strategy for the MATS rule, the Southern Company system has entered into agreements for the construction of baghouses to control the emissions of mercury and particulates from certain generating units. While further analysis of the MATS rule is required and the ultimate costs remain uncertain, the compliance decisions made through the second quarter 2012 have allowed the Southern Company system to further develop its cost estimates for compliance with the MATS rule. As a result, estimated compliance costs for the MATS rule in the 2012 through 2014 period have been revised from up to $2.7 billion to approximately $1.8 billion as follows:
2012 | 2013 | 2014 | ||||||||
|
||||||||||
(in millions) | ||||||||||
MATS rule |
$ | 150 | $440 | $ | 1,215 | |||||
|
In addition, the Southern Company system has further developed its estimated capital expenditures and associated timing of these expenditures to comply with the proposed water and coal combustion byproducts rules, resulting in a reduction, due primarily to timing, in estimated compliance costs for 2012 through 2014. Potential incremental environmental compliance investments to comply with the proposed water and coal combustion byproducts rules have been revised from up to $1.5 billion to approximately $500 million over the 2012 through 2014 period based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule. These potential incremental environmental compliance investments are estimated as follows:
2012 | 2013 | 2014 | ||||||||
|
||||||||||
(in millions) | ||||||||||
Proposed water and coal combustion byproducts rules |
$ | 10 | $85 | $ | 405 | |||||
|
While the Southern Company systems ultimate costs of compliance with the MATS rule and the proposed water and coal combustion byproducts rules remain uncertain, the Southern Company system estimates that compliance costs through 2021 (assuming that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) will be at the low end of the $13 billion to $18 billion range provided in the Form 10-K. Included in this amount is approximately $750 million that is also included in the 2012 through 2014 base level capital investment of the traditional operating companies described in the Form 10-K in anticipation of these rules.
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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Southern Company systems ultimate compliance strategy and actual future environmental capital expenditures are dependent on a final assessment of the MATS rule and will be affected by the final requirements of new or revised environmental regulations that are promulgated; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and the fuel mix of the electric utilities. Compliance costs may arise from retirement and replacement of existing units, installation of additional environmental controls, upgrades to the transmission system, and changing fuel sources for certain existing units. The Southern Company systems preliminary analysis further indicates that the short timeframe for compliance with the MATS rule could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters cannot be determined at this time.
As part of SEGCOs environmental compliance strategy, the Board of Directors of SEGCO approved adding natural gas as the primary fuel source in 2015 for its 1,000 MWs of generating capacity and the construction of the necessary natural gas pipeline. SEGCO is jointly owned by Alabama Power and Georgia Power. The capacity of SEGCOs units is sold to Alabama Power and Georgia Power through a PPA. The impact of SEGCOs ultimate compliance strategy on the PPA costs cannot be determined at this time; however, if such costs cannot continue to be recovered through retail rates, they could have a material impact on Southern Companys financial statements.
Air Quality
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations Air Quality of Southern Company in Item 7 of the Form 10-K for additional information on the eight-hour ozone and fine particulate matter air quality standards and the MATS rule.
On May 1, 2012, the EPA released its final determination of nonattainment areas based on the 2008 eight-hour ozone air quality standards. The only area within the traditional operating companies service territory designated as a nonattainment area was a 15-county area within metropolitan Atlanta. The potential impact of the revised standard and nonattainment designation will depend on further evaluation and implementation by the Georgia Environmental Protection Division and cannot be determined at this time.
On June 14, 2012, the EPA proposed a rule that would increase the stringency of the fine particulate matter national ambient air quality standards. If adopted, the proposed standards could result in the designation of new nonattainment areas within the Southern Company systems service territory. As part of a related settlement, the EPA has agreed to finalize the proposed rule by December 14, 2012. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Numerous petitions for administrative reconsideration of the MATS rule, including a petition by Southern Company and its subsidiaries, have been filed with the EPA. Challenges to the final rule have also been filed in the U.S. District Court for the District of Columbia by numerous states, environmental organizations, industry groups, and others. The impact of the MATS rule will depend on the outcome of these and any other legal challenges and, therefore, cannot be determined at this time.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Water Quality
See MANAGEMENTS DISCUSSION AND ANALYSISFUTURE EARNINGS POTENTIALEnvironmental MattersEnvironmental Statutes and Regulations Water Quality of Southern Company in Item 7 of the Form 10-K for additional information on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Byproducts
See MANAGEMENTS DISCUSSION AND ANALYSISFUTURE EARNINGS POTENTIALEnvironmental MattersEnvironmental Statutes and RegulationsCoal Combustion Byproducts of Southern Company in Item 7 of the Form 10-K for additional information. Environmental groups and other parties have filed lawsuits in the U.S. District Court for the District of Columbia seeking to require the EPA to complete its rulemaking process and issue final regulations pertaining to the regulation of coal combustion byproducts. The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENTS DISCUSSION AND ANALYSISFUTURE EARNINGS POTENTIALEnvironmental MattersGlobal Climate Issues of Southern Company in Item 7 of the Form 10-K for additional information.
On April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.
On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPAs actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.
PSC Matters
Retail Fuel Cost Recovery
The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. The traditional operating companies have experienced lower pricing for natural gas resulting in an increase in natural gas generation and a decrease in coal generation, which is currently more costly. The lower cost of natural gas has resulted in total over recovered fuel costs at Georgia Power, Gulf Power, and Mississippi Power included in Southern Companys Condensed Balance Sheet herein of approximately $196 million at June 30, 2012. At June 30, 2012, Alabama Power had under recovered fuel costs included in Southern Companys Condensed Balance Sheet herein of approximately $16 million. At December 31, 2011, total under recovered fuel costs at Alabama Power and Georgia Power included in Southern Companys Condensed Balance Sheet herein were approximately $169 million, and Gulf Power and Mississippi Power had a total over recovered fuel balance included in Southern Companys Condensed Balance Sheet herein of approximately $52 million. Fuel cost recovery revenues are adjusted for differences in actual
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Companys revenues or net income, but will affect annual cash flow. The traditional operating companies continuously monitor their under or over recovered fuel cost balances.
On June 21, 2012, the Georgia PSC approved a decrease in Georgia Powers fuel cost recovery rates of 19%, which reduced annual billings by $567 million effective June 1, 2012. The decrease in fuel costs resulted from lower natural gas prices as a result of increased natural gas supplies.
See MANAGEMENTS DISCUSSION AND ANALYSISFUTURE EARNINGS POTENTIALPSC MattersFuel Cost Recovery of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under Retail Regulatory Matters Alabama Power Fuel Cost Recovery and Retail Regulatory Matters Georgia Power Fuel Cost Recovery in Item 8 of the Form 10-K for additional information.
Alabama Power
Rate CNP
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIALPSC MattersAlabama Power Rate CNP of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under Retail Regulatory MattersAlabama PowerRate CNP in Item 8 of the Form 10-K for additional information regarding Alabama Powers recovery of retail costs through Rate Certificated New Plant Power Purchase Agreement (Rate CNP) and Rate Certificated New Plant Environmental (Rate CNP Environmental). Alabama Powers under recovered Rate CNP balance as of June 30, 2012 was $2 million as compared to $6 million at December 31, 2011. Alabama Powers under recovered Rate CNP Environmental balance as of June 30, 2012 was $26 million as compared to $11 million at December 31, 2011. These under recovered balances at June 30, 2012 are included in deferred under recovered regulatory clause revenues on Southern Companys Condensed Balance Sheet herein. For Rate CNP, this classification is based on an estimate, which includes such factors as purchased power capacity and energy demand. For Rate CNP Environmental, this classification is based on an estimate, which includes such factors as costs to comply with environmental mandates and energy demand. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered retail costs.
Natural Disaster Cost Recovery
See MANAGEMENTS DISCUSSION AND ANALYSISFUTURE EARNINGS POTENTIALPSC MattersAlabama Power Natural Disaster Reserve of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under Retail Regulatory MattersAlabama PowerNatural Disaster Reserve in Item 8 of the Form 10-K for additional information regarding natural disaster cost recovery. At June 30, 2012, the NDR had an accumulated balance of $105 million, which is included in Southern Companys Condensed Balance Sheet herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in Southern Companys Condensed Statement of Income herein.
Georgia Power
2011 Integrated Resource Plan Update
See MANAGEMENTS DISCUSSION AND ANALYSISFUTURE EARNINGS POTENTIALEnvironmental Matters Environmental Statutes and RegulationsAir Quality, Water Quality, and Coal Combustion Byproducts of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under Retail Regulatory MattersGeorgia Power Rate Plans and 2011 Integrated Resource Plan Update in Item 8 of the Form 10-K for additional information regarding proposed and final EPA rules and regulations, including the MATS rule for coal- and oil-fired electric utility steam generating units, revisions to effluent guidelines for steam electric power plants,
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and additional regulation of coal combustion byproducts; the State of Georgias Multi-Pollutant Rule; Georgia Powers analysis of the potential costs and benefits of installing the required controls on its fossil generating units in light of these regulations; the 2010 ARP; and the 2011 IRP Update.
On March 20, 2012, the Georgia PSC approved Georgia Powers request to decertify and retire two coal-fired generation units at Plant Branch as of October 31, 2013 and December 31, 2013 and an oil-fired unit at Plant Mitchell as of March 26, 2012, which was included in Georgia Powers 2011 IRP Update. The Georgia PSC also approved three PPAs totaling 998 MWs with Southern Power for capacity and energy that will commence in 2015 and end in 2030. The PPAs remain subject to FERC approval. The ultimate outcome of this matter cannot be determined at this time.
Income Tax Matters
Bonus Depreciation
In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Southern Company through 2013. Due to the significant amount of estimated bonus depreciation for 2012, a portion of Southern Companys tax credit utilization will be deferred. Consequently, Southern Companys positive cash flow benefit is estimated to be between $535 million and $725 million in 2012.
Construction Program
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new generating facilities, including natural gas, biomass, and solar units at Southern Power, natural gas units and Plant Vogtle Units 3 and 4 at Georgia Power, and the Kemper IGCC at Mississippi Power, as well as adding or changing fuel sources for certain existing units, adding environmental control equipment, and expanding the transmission and distribution systems. For the traditional operating companies, major generation construction projects are subject to state PSC approvals in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. See Note 7 to the financial statements of Southern Company under Construction Program in Item 8 of the Form 10-K for estimated construction expenditures for the next three years. In addition, see Note 3 to the financial statements of Southern Company under Retail Regulatory MattersGeorgia PowerNuclear Construction, Retail Regulatory Matters Georgia PowerOther Construction, and Integrated Coal Gasification Combined Cycle in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under Retail Regulatory MattersGeorgia PowerNuclear Construction and Integrated Coal Gasification Combined Cycle herein for additional information.
Investments in Leveraged Leases
See MANAGEMENTS DISCUSSION AND ANALYSISFUTURE EARNINGS POTENTIALInvestments in Leveraged Leases of Southern Company in Item 7 and Note 1 to the financial statements of Southern Company under Leveraged Leases in Item 8 of the Form 10-K for additional information.
The recent financial and operational performance of one of Southern Companys lessees and the associated generation assets has raised potential concerns on the part of Southern Company as to the credit quality of the lessee and the residual value of the assets. Current projections indicate significant uncertainty as to whether the lessee will be able to pay the
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
December 2012 semi-annual rent payment in full. Southern Company is currently engaged in discussions with the lessee and the holders of the projects nonrecourse debt to restructure the debt payments and the related rental payments to allow additional capital investment in the project to be made to improve the operation of the generation assets and the financial viability of the lease transaction. Southern Company believes there is a reasonable possibility that it will be able to reach an agreement with the lessee and the debtholders to restructure the project. However, due to continued poor performance of the generation assets and the uncertainties surrounding the receipt of the December 2012 semi-annual rent payment and its ability to successfully restructure the project, Southern Company has placed the lease on nonaccrual status whereby income associated with this investment will not be recognized in the financial statements beginning in July 2012. If the attempts at restructuring the project are unsuccessful and the project is ultimately abandoned, the potential impairment loss that would be incurred is approximately $90 million on an after-tax basis. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Companys subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) herein or in Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Companys financial statements.
See the Notes to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
See MANAGEMENTS DISCUSSION AND ANALYSISFUTURE EARNINGS POTENTIALOther Matters of Southern Company in Item 7 of the Form 10-K for additional information regarding the earthquake and tsunami that struck Japan in March 2011. On March 12, 2012, the NRC issued three orders and a request for information based on the NRC task force report recommendations that included, among other items, additional mitigation strategies for beyond-design-basis events, enhanced spent fuel pool instrumentation capabilities, hardened vents for certain classes of containment structures, including the one in use at Plant Hatch, site specific evaluations for seismic and flooding hazards, and various plant evaluations to ensure adequate coping capabilities during station blackout and other conditions. The staff of the NRC expects to issue additional implementation guidance by the end of August 2012. The final form and the resulting impact of any changes to safety requirements for nuclear reactors will be dependent on further review and action by the NRC and cannot be determined at this time. See RISK FACTORS of Southern Company in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. The ultimate outcome of these events cannot be determined at this time.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Companys results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENTS DISCUSSION AND ANALYSIS ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Companys critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITYOverview of Southern Company in Item 7 of the Form 10-K for additional information. Southern Companys financial condition remained stable at June 30, 2012. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See Sources of Capital, Financing Activities, and Capital Requirements and Contractual Obligations herein for additional information.
Net cash provided from operating activities totaled $1.8 billion for the first six months of 2012, a decrease of $632 million from the corresponding period in 2011. Significant changes in operating cash flow for the first six months of 2012 compared to the corresponding period in 2011 include an increase in fossil fuel stock as a result of milder weather in the first six months of 2012 and lower natural gas prices and a decrease in accrued taxes due to the timing of tax payments. Net cash used for investing activities totaled $2.8 billion for the first six months of 2012, an increase of $727 million from the corresponding period in 2011. The increase was primarily due to property additions to utility plant. Net cash provided from financing activities totaled $378 million for the first six months of 2012 compared to $335 million net cash used for financing activities in the corresponding period in 2011. The change was primarily due to an increase in long-term debt issuances and the receipt of an interest bearing refundable deposit related to a pending asset sale at Mississippi Power.
Significant balance sheet changes for the first six months of 2012 include an increase of $1.6 billion in total property, plant, and equipment for the construction of generation, transmission, and distribution facilities. Other significant changes include an increase in long-term debt of $812 million due to senior note issuances.
The market price of Southern Companys common stock at the end of the second quarter 2012 was $46.30 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $20.72 per share, representing a market-to-book ratio of 223%, compared to $40.38, $19.80, and 204%, respectively, at the end of 2011. The dividend for the second quarter 2012 was $0.49 per share compared to $0.4725 per share in the second quarter 2011.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Capital Requirements and Contractual Obligations
See MANAGEMENTS DISCUSSION AND ANALYSISFINANCIAL CONDITION AND LIQUIDITYCapital Requirements and Contractual Obligations of Southern Company in Item 7 of the Form 10-K for a description of Southern Companys capital requirements for the construction programs of the Southern Company system, including estimated capital expenditures to comply with existing environmental regulations, and other funding requirements associated with scheduled maturities of long-term debt, as well as the related interest, preferred and preference stock dividends, leases, trust funding requirements, other purchase commitments, unrecognized tax benefits and interest, and derivative obligations. Approximately $2.1 billion will be required through June 30, 2013 to fund maturities of long-term debt.
See FUTURE EARNINGS POTENTIALEnvironmental Statutes and RegulationsGeneral herein for a description of the Southern Company systems estimated capital expenditures to comply with the MATS rule and proposed water and coal combustion byproducts rules.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Southern Company intends to meet its future capital needs through internal cash flow and external security issuances. Equity capital can be provided from any combination of Southern Companys stock plans, private placements, or public offerings. The amount and timing of additional equity capital to be raised will be contingent on Southern Companys investment opportunities.
Except as described below with respect to potential DOE loan guarantees, the traditional operating companies and Southern Power plan to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, security issuances, term loans, short-term borrowings, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENTS DISCUSSION AND ANALYSISFINANCIAL CONDITION AND LIQUIDITYSources of Capital of Southern Company in Item 7 of the Form 10-K for additional information.
In June 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future Georgia Power borrowings related to the construction of Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Powers 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of 70% of eligible project costs, or approximately $3.46 billion, and are expected to be funded by the Federal Financing Bank. Final approval and issuance of loan guarantees by the DOE are subject to negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. In the event that the DOE does not issue a loan guarantee or Georgia Power determines that the final terms and conditions of the loan guarantee by the DOE are not in the best interest of its customers, Georgia Power expects to finance the construction of Plant Vogtle Units 3 and 4 through traditional capital markets financings. There can be no assurance that the DOE will issue loan guarantees for Georgia Power.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In addition, Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE. There can be no assurance that the DOE will issue federal loan guarantees for Mississippi Power. In the event that the DOE does not issue a conditional commitment or a final definitive loan guarantee, Mississippi Power intends to finance the construction of the Kemper IGCC through traditional capital markets financings. Mississippi Power also received DOE grant funds of $245 million that were used for the construction of the Kemper IGCC. An additional $25 million is expected to be received for the initial operation of the Kemper IGCC.
Southern Companys current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business of the Southern Company system. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets, including commercial paper programs which are backed by bank credit facilities.
At June 30, 2012, Southern Company and its subsidiaries had approximately $659 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2012, including expiration dates, were as follows:
Expires | Executable Term Loans |
Due Within One Year(a) |
||||||||||||||||||||||||||||||||||
Company | 2012 | 2013 | 2014 and |
Total | Unused | One Year |
Two Years |
Term Out |
No Term Out |
|||||||||||||||||||||||||||
(in millions) | (in millions) | (in millions) | (in millions) | |||||||||||||||||||||||||||||||||
Southern Company |
$ | $ | $1,000 | $1,000 | $1,000 | $ | $ | $ | $ | |||||||||||||||||||||||||||
Alabama Power |
37 | 101 | 1,150 | 1,288 | 1,288 | 51 | | 51 | 52 | |||||||||||||||||||||||||||
Georgia Power |
| | 1,750 | 1,750 | 1,745 | | | | | |||||||||||||||||||||||||||
Gulf Power |
20 | 60 | 195 | 275 | 275 | 45 | | 45 | 35 | |||||||||||||||||||||||||||
Mississippi Power |
41 | 95 | 165 | 301 | 301 | 25 | 41 | 66 | 70 | |||||||||||||||||||||||||||
Southern Power |
| | 500 | 500 | 500 | | | | | |||||||||||||||||||||||||||
Other |
| 50 | | 50 | 50 | 25 | | 25 | | |||||||||||||||||||||||||||
|
||||||||||||||||||||||||||||||||||||
Total |
$98 | $306 | $4,760 | $5,164 | $5,159 | $146 | $41 | $187 | $157 | |||||||||||||||||||||||||||
|
(a) | Reflects facilities expiring on or before June 30, 2013. |
(b) | All remaining Gulf Power and Mississippi Power credit agreements in this column expire in 2014. |
See Note 6 to the financial statements of Southern Company under Bank Credit Arrangements in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under Bank Credit Arrangements herein for additional information.
Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of the individual company. Southern Company and its subsidiaries are currently in compliance with all such covenants.
A portion of the unused credit with banks is allocated to provide liquidity support to the traditional operating companies variable rate pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2012 was approximately $1.8 billion.
The traditional operating companies may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of each of the traditional operating companies.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of short-term borrowings, excluding $2 million of notes payable related to other energy service contracts, were as follows:
Short-term Debt at the End of the Period |
Short-term Debt During the Period (a) | |||||||||||
Amount Outstanding |
Weighted Rate |
Average Outstanding |
Weighted Average Interest Rate |
Maximum Amount Outstanding | ||||||||
|
| |||||||||||
(in millions) | (in millions) | (in millions) | ||||||||||
June 30, 2012: |
||||||||||||
Commercial paper |
$445 | 0.4% | $477 | 0.4% | $735 | |||||||
Short-term bank debt |
| % | 175 | 1.1% | 300 | |||||||
|
|
|||||||||||
Total |
$445 | 0.4% | $652 | 0.5% | ||||||||
|
|
(a) | Average and maximum amounts are based upon daily balances during the period. |
Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
Credit Rating Risk
Southern Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, energy price risk management, and construction of new generation. The maximum potential collateral requirements under these contracts at June 30, 2012 were as follows:
Credit Ratings | Maximum Potential Requirements | |
| ||
(in millions) | ||
At BBB and Baa2 |
$ 9 | |
At BBB- and/or Baa3 |
613 | |
Below BBB- and/or Baa3 |
2,668 | |
|
On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. Until the acquisition is closed, the deposit bears interest at Mississippi Powers AFUDC rate, which was 9.967% per annum as of June 30, 2012, and is refundable to SMEPA upon termination of the asset purchase agreement related to such purchase, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPAs discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moodys or ceases to be rated by either of these rating agencies.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Companys ability to access capital markets, particularly the short-term debt market.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Market Price Risk
Southern Company is exposed to market risks, primarily commodity price risk and interest rate risk. Southern Company may also occasionally have limited exposure to foreign currency exchange rates. To manage the volatility attributable to these exposures, Southern Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Southern Companys policies in areas such as counterparty exposure and risk management practices. Southern Companys policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional operating companies continue to have limited exposure to market volatility in interest rates, foreign currency, commodity fuel prices, and prices of electricity. In addition, Southern Powers exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional operating companies enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. The traditional operating companies continue to manage fuel-hedging programs implemented per the guidelines of their respective state PSCs. Southern Company had no material change in market risk exposure for the second quarter 2012 when compared with the December 31, 2011 reporting period.
The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three and six months ended June 30, 2012 were as follows:
Second Quarter 2012 Changes |
Year-to-Date 2012 Changes |
|||||||
|
||||||||
Fair Value | ||||||||
|
||||||||
(in millions) | ||||||||
Contracts outstanding at the beginning of the period, assets (liabilities), net |
$(265) | $(231) | ||||||
Contracts realized or settled |
77 | 126 | ||||||
Current period changes(a) |
18 | (65) | ||||||
|
||||||||
Contracts outstanding at the end of the period, assets (liabilities), net |
$(170) | $(170) | ||||||
|
(a) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
The changes in the fair value positions of the energy-related derivative contracts, which are substantially all attributable to both the volume and the price of natural gas, for the three and six months ended June 30, 2012 were as follows:
Second Quarter 2012 Changes |
Year-to-Date 2012 Changes |
|||||||
|
||||||||
Fair Value | ||||||||
|
||||||||
(in millions) | ||||||||
Natural gas swaps |
$ 78 | $ 59 | ||||||
Natural gas options |
17 | 3 | ||||||
Other energy-related derivatives |
| (1) | ||||||
|
||||||||
Total changes |
$ 95 | $61 | ||||||
|
32
Table of Contents
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The net hedge volumes of energy-related derivative contracts were as follows:
June 30, 2012 |
March 31, 2012 |
December 31, 2011 | ||||
| ||||||
mmBtu Volume | ||||||
(in millions) | ||||||
CommodityNatural gas swaps |
141 | 123 | 123 | |||
CommodityNatural gas options |
101 | 98 | 66 | |||
| ||||||
Total hedge volume |
242 | 221 | 189 | |||
|
The weighted average swap contract cost above market prices was approximately $0.95 per mmBtu as of June 30, 2012, $1.71 per mmBtu as of March 31, 2012, and $1.51 per mmBtu as of December 31, 2011. The change in option premiums is primarily attributable to the volatility of the market and the underlying change in the natural gas price. The majority of the natural gas hedge gains and losses are recovered through the traditional operating companies fuel cost recovery clauses.
The net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:
Asset (Liability) Derivatives | June 30, 2012 |
December 31, 2011 | ||
| ||||
(in millions) | ||||
Regulatory hedges |
$(164) | $(221) | ||
Cash flow hedges |
(1) | (1) | ||
Not designated |
(5) | (9) | ||
| ||||
Total fair value |
$(170) | $(231) | ||
|
Energy-related derivative contracts which are designated as regulatory hedges relate to the traditional operating companies fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clauses. Gains and losses on energy-related derivatives that are designated as cash flow hedges are mainly used by Southern Power to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Total net unrealized pre-tax gains (losses) recognized in income for the three and six months ended June 30, 2012 were $10 million and $4 million, respectively, and were not material for the corresponding periods in 2011.
Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at June 30, 2012 were as follows:
June 30, 2012 Fair Value Measurements | ||||||||
| ||||||||
Total | Maturity | |||||||
Fair Value | Year 1 | Years 2&3 | Years 4&5 | |||||
| ||||||||
(in millions) | ||||||||
Level 1 |
$ | $ | $ | $ | ||||
Level 2 |
(170) | (116) | (52) | (2) | ||||
Level 3 |
| | | | ||||
| ||||||||
Fair value of contracts outstanding at end of period |
$(170) | $(116) | $(52) | $ (2) | ||||
|
33
Table of Contents
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Southern Company. Regulations to implement the Dodd-Frank Act will impose additional requirements on the use of over-the-counter derivatives for both Southern Company and its subsidiaries and their derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Southern Company does not expect the impact of these rules to be material.
For additional information, see MANAGEMENTS DISCUSSION AND ANALYSISFINANCIAL CONDITION AND LIQUIDITYMarket Price Risk of Southern Company in Item 7 and Note 1 under Financial Instruments and Note 11 to the financial statements of Southern Company in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
During the first six months of 2012, Southern Company issued approximately 9.7 million shares of common stock for $317 million through employee and director stock plans. Since mid-2011, Southern Company has issued additional equity only through its employee and director stock plans. Southern Company plans to use the proceeds received from stock option exercises during 2012 (including the $317 million received through June 30, 2012) and 2013 to repurchase shares to partially offset the incremental shares issued under its employee and director stock plans. Pursuant to board approval, Southern Company may repurchase shares through open market purchases or privately negotiated transactions, in accordance with applicable securities laws.
In addition, Southern Company is not currently issuing shares of common stock through the Southern Investment Plan or its employee savings plan. All sales under the Southern Investment Plan and the employee savings plan are currently being funded with shares acquired on the open market by the independent plan administrators.
The following table outlines the debt financing activities during the first six months of 2012:
Company | Senior Note Issuances |
Senior Note Redemptions and Maturities |
Pollution Control Bond Issuances |
Pollution Control Bond Redemptions |
Other Long-Term Debt Issuances |
Other Long- Term Debt Redemptions and Maturities | ||||||
| ||||||||||||
(in millions) | ||||||||||||
Southern Company |
$ | $500 | $ | $ | $ | $ | ||||||
Alabama Power |
250 | 250 | | 1 | | | ||||||
Georgia Power |
1,500 | | 234 | 49 | | 250 | ||||||
Gulf Power |
100 | 91 | | | | | ||||||
Mississippi Power |
400 | 90 | | | | 75 | ||||||
Southern Power |
| | | | 4 | | ||||||
| ||||||||||||
Total |
$2,250 | $931 | $234 | $ 50 | $ 4 | $325 | ||||||
|
Southern Companys subsidiaries used the proceeds of the debt issuances shown in the table above for the redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including their respective continuous construction programs.
On January 17, 2012, Southern Companys $500 million aggregate principal amount of Series 2007A 5.30% Senior Notes matured.
34
Table of Contents
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. Until the acquisition is closed, the deposit bears interest at Mississippi Powers AFUDC rate, which was 9.967% per annum at June 30, 2012 and is refundable to SMEPA upon termination of the asset purchase agreement related to such purchase, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPAs discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moodys or ceases to be rated by either of these rating agencies.
Subsequent to June 30, 2012, Georgia Power redeemed $300 million aggregate principal amount of its Series 2007D 6.375% Senior Notes due July 15, 2047.
Subsequent to June 30, 2012, $85 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2005 and $100 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2005 were redeemed.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
35
Table of Contents
Item 3. Quantitative And Qualitative Disclosures About Market Risk.
See MANAGEMENTS DISCUSSION AND ANALYSISFINANCIAL CONDITION AND LIQUIDITYMarket Price Risk herein for each registrant and Note 1 to the financial statements of each registrant under Financial Instruments, Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power and Mississippi Power, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also, see Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
Item 4. Controls and Procedures.
(a) | Evaluation of disclosure controls and procedures. |
As of the end of the period covered by this quarterly report, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power conducted separate evaluations under the supervision and with the participation of each companys management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
(b) | Changes in internal controls. |
There have been no changes in Southern Companys, Alabama Powers, Georgia Powers, Gulf Powers, Mississippi Powers, or Southern Powers internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the second quarter 2012 that have materially affected or are reasonably likely to materially affect Southern Companys, Alabama Powers, Georgia Powers, Gulf Powers, Mississippi Powers, or Southern Powers internal control over financial reporting.
36
Table of Contents
37
Table of Contents
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
For the Three Months | For the Six Months | |||||||||||||||
Ended June 30, | Ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in millions) | (in millions) | |||||||||||||||
Operating Revenues: |
||||||||||||||||
Retail revenues |
$ | 1,254 | $ | 1,244 | $ | 2,346 | $ | 2,370 | ||||||||
Wholesale revenues, non-affiliates |
70 | 70 | 131 | 138 | ||||||||||||
Wholesale revenues, affiliates |
6 | 75 | 20 | 150 | ||||||||||||
Other revenues |
47 | 51 | 96 | 102 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total operating revenues |
1,377 | 1,440 | 2,593 | 2,760 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Operating Expenses: |
||||||||||||||||
Fuel |
343 | 428 | 649 | 823 | ||||||||||||
Purchased power, non-affiliates |
17 | 17 | 32 | 28 | ||||||||||||
Purchased power, affiliates |
66 | 57 | 106 | 103 | ||||||||||||
Other operations and maintenance |
316 | 290 | 637 | 587 | ||||||||||||
Depreciation and amortization |
160 | 159 | 317 | 316 | ||||||||||||
Taxes other than income taxes |
85 | 85 | 171 | 170 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total operating expenses |
987 | 1,036 | 1,912 | 2,027 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Operating Income |
390 | 404 | 681 | 733 | ||||||||||||
Other Income and (Expense): |
||||||||||||||||
Allowance for equity funds used during construction |
4 | 6 | 9 | 11 | ||||||||||||
Interest income |
4 | 5 | 8 | 9 | ||||||||||||
Interest expense, net of amounts capitalized |
(73 | ) | (77 | ) | (146 | ) | (151 | ) | ||||||||
Other income (expense), net |
(4 | ) | (7 | ) | (11 | ) | (13 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other income and (expense) |
(69 | ) | (73 | ) | (140 | ) | (144 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Earnings Before Income Taxes |
321 | 331 | 541 | 589 | ||||||||||||
Income taxes |
126 | 131 | 210 | 227 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net Income |
195 | 200 | 331 | 362 | ||||||||||||
Dividends on Preferred and Preference Stock |
10 | 10 | 20 | 20 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net Income After Dividends on Preferred and Preference Stock |
$ | 185 | $ | 190 | $ | 311 | $ | 342 | ||||||||
|
|
|
|
|
|
|
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
For the Three Months | For the Six Months | |||||||||||||||
Ended June 30, | Ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in millions) | (in millions) | |||||||||||||||
Net Income After Dividends on Preferred and Preference Stock |
$ | 185 | $ | 190 | $ | 311 | $ | 342 | ||||||||
Other comprehensive income (loss): |
||||||||||||||||
Qualifying hedges: |
||||||||||||||||
Changes in fair value, net of tax of $(7), $(1), $(4) and $1, respectively |
(11 | ) | 1 | (7 | ) | 3 | ||||||||||
Reclassification adjustment for amounts included in net income, net of tax of $-, $(1), $- and $(1), respectively |
| (2 | ) | | (2 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other comprehensive income (loss) |
(11 | ) | (1 | ) | (7 | ) | 1 | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Comprehensive Income |
$ | 174 | $ | 189 | $ | 304 | $ | 343 | ||||||||
|
|
|
|
|
|
|
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
38
Table of Contents
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
For the Six Months Ended June 30, |
||||||||
2012 | 2011 | |||||||
(in millions) | ||||||||
Operating Activities: |
||||||||
Net income |
$ | 331 | $ | 362 | ||||
Adjustments to reconcile net income to net cash provided from operating activities |
||||||||
Depreciation and amortization, total |
380 | 373 | ||||||
Deferred income taxes |
85 | 174 | ||||||
Allowance for equity funds used during construction |
(9 | ) | (11 | ) | ||||
Pension, postretirement, and other employee benefits |
(8 | ) | (24 | ) | ||||
Stock based compensation expense |
6 | 4 | ||||||
Other, net |
(24 | ) | (3 | ) | ||||
Changes in certain current assets and liabilities |
||||||||
-Receivables |
(46 | ) | (57 | ) | ||||
-Fossil fuel stock |
(125 | ) | 13 | |||||
-Materials and supplies |
(6 | ) | (5 | ) | ||||
-Other current assets |
(31 | ) | (66 | ) | ||||
-Accounts payable |
(145 | ) | (77 | ) | ||||
-Accrued taxes |
128 | 193 | ||||||
-Accrued compensation |
(45 | ) | (52 | ) | ||||
-Other current liabilities |
(10 | ) | (5 | ) | ||||
|
|
|
|
|||||
Net cash provided from operating activities |
481 | 819 | ||||||
|
|
|
|
|||||
Investing Activities: |
||||||||
Property additions |
(436 | ) | (485 | ) | ||||
Distribution of restricted cash from pollution control revenue bonds |
| 11 | ||||||
Nuclear decommissioning trust fund purchases |
(88 | ) | (252 | ) | ||||
Nuclear decommissioning trust fund sales |
88 | 252 | ||||||
Cost of removal, net of salvage |
(7 | ) | (47 | ) | ||||
Change in construction payables |
(12 | ) | (14 | ) | ||||
Other investing activities |
(9 | ) | (22 | ) | ||||
|
|
|
|
|||||
Net cash used for investing activities |
(464 | ) | (557 | ) | ||||
|
|
|
|
|||||
Financing Activities: |
||||||||
Proceeds |
||||||||
Capital contributions from parent company |
11 | 5 | ||||||
Senior notes issuances |
250 | 700 | ||||||
Redemptions |
||||||||
Pollution control revenue bonds |
(1 | ) | | |||||
Senior notes |
(250 | ) | (650 | ) | ||||
Payment of preferred and preference stock dividends |
(20 | ) | (20 | ) | ||||
Payment of common stock dividends |
(270 | ) | (277 | ) | ||||
Other financing activities |
(3 | ) | (12 | ) | ||||
|
|
|
|
|||||
Net cash used for financing activities |
(283 | ) | (254 | ) | ||||
|
|
|
|
|||||
Net Change in Cash and Cash Equivalents |
(266 | ) | 8 | |||||
Cash and Cash Equivalents at Beginning of Period |
344 | 154 | ||||||
|
|
|
|
|||||
Cash and Cash Equivalents at End of Period |
$ | 78 | $ | 162 | ||||
|
|
|
|
|||||
Supplemental Cash Flow Information: |
||||||||
Cash paid (received) during the period for |
||||||||
Interest (net of $3 and $5 capitalized for 2012 and 2011, respectively) |
$ | 136 | $ | 141 | ||||
Income taxes, net |
31 | (100 | ) | |||||
Noncash transactionsaccrued property additions at end of period |
7 | 14 |
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
39
Table of Contents
CONDENSED BALANCE SHEETS (UNAUDITED)
Assets |
At June 30, 2012 |
At December 31, 2011 |
||||||
(in millions) | ||||||||
Current Assets: |
||||||||
Cash and cash equivalents |
$ | 78 | $ | 344 | ||||
Restricted cash and cash equivalents |
| 1 | ||||||
Receivables |
||||||||
Customer accounts receivable |
368 | 332 | ||||||
Unbilled revenues |
160 | 126 | ||||||
Under recovered regulatory clause revenues |
16 | | ||||||
Other accounts and notes receivable |
34 | 35 | ||||||
Affiliated companies |
57 | 79 | ||||||
Accumulated provision for uncollectible accounts |
(9 | ) | (10 | ) | ||||
Fossil fuel stock, at average cost |
469 | 344 | ||||||
Materials and supplies, at average cost |
380 | 375 | ||||||
Vacation pay |
59 | 59 | ||||||
Prepaid expenses |
135 | 74 | ||||||
Other regulatory assets, current |
32 | 44 | ||||||
Other current assets |
8 | 11 | ||||||
|
|
|
|
|||||
Total current assets |
1,787 | 1,814 | ||||||
|
|
|
|
|||||
Property, Plant, and Equipment: |
||||||||
In service |
21,110 | 20,809 | ||||||
Less accumulated provision for depreciation |
7,562 | 7,344 | ||||||
|
|
|
|
|||||
Plant in service, net of depreciation |
13,548 | 13,465 | ||||||
Nuclear fuel, at amortized cost |
347 | 330 | ||||||
Construction work in progress |
390 | 374 | ||||||
|
|
|
|
|||||
Total property, plant, and equipment |
14,285 | 14,169 | ||||||
|
|
|
|
|||||
Other Property and Investments: |
||||||||
Equity investments in unconsolidated subsidiaries |
61 | 62 | ||||||
Nuclear decommissioning trusts, at fair value |
571 | 540 | ||||||
Miscellaneous property and investments |
73 | 73 | ||||||
|
|
|
|
|||||
Total other property and investments |
705 | 675 | ||||||
|
|
|
|
|||||
Deferred Charges and Other Assets: |
||||||||
Deferred charges related to income taxes |
529 | 532 | ||||||
Prepaid pension costs |
74 | 59 | ||||||
Deferred under recovered regulatory clause revenues |
29 | 48 | ||||||
Other regulatory assets, deferred |
1,001 | 994 | ||||||
Other deferred charges and assets |
144 | 186 | ||||||
|
|
|
|
|||||
Total deferred charges and other assets |
1,777 | 1,819 | ||||||
|
|
|
|
|||||
Total Assets |
$ | 18,554 | $ | 18,477 | ||||
|
|
|
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
40
Table of Contents
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholders Equity |
At June
30, 2012 |
At December 31, 2011 |
||||||
(in millions) | ||||||||
Current Liabilities: |
||||||||
Securities due within one year |
$ | 500 | $ | 500 | ||||
Accounts payable |
||||||||
Affiliated |
176 | 203 | ||||||
Other |
196 | 322 | ||||||
Customer deposits |
86 | 85 | ||||||
Accrued taxes |
||||||||
Accrued income taxes |
99 | 32 | ||||||
Other accrued taxes |
80 | 34 | ||||||
Accrued interest |
65 | 63 | ||||||
Accrued vacation pay |
48 | 48 | ||||||
Accrued compensation |
51 | 95 | ||||||
Liabilities from risk management activities |
54 | 54 | ||||||
Other regulatory liabilities, current |
3 | 18 | ||||||
Other current liabilities |
40 | 38 | ||||||
|
|
|
|
|||||
Total current liabilities |
1,398 | 1,492 | ||||||
|
|
|
|
|||||
Long-term Debt |
5,630 | 5,632 | ||||||
|
|
|
|
|||||
Deferred Credits and Other Liabilities: |
||||||||
Accumulated deferred income taxes |
3,319 | 3,257 | ||||||
Deferred credits related to income taxes |
81 | 83 | ||||||
Accumulated deferred investment tax credits |
145 | 149 | ||||||
Employee benefit obligations |
339 | 343 | ||||||
Asset retirement obligations |
571 | 553 | ||||||
Other cost of removal obligations |
736 | 703 | ||||||
Other regulatory liabilities, deferred |
165 | 156 | ||||||
Other deferred credits and liabilities |
84 | 82 | ||||||
|
|
|
|
|||||
Total deferred credits and other liabilities |
5,440 | 5,326 | ||||||
|
|
|
|
|||||
Total Liabilities |
12,468 | 12,450 | ||||||
|
|
|
|
|||||
Redeemable Preferred Stock |
342 | 342 | ||||||
|
|
|
|
|||||
Preference Stock |
343 | 343 | ||||||
|
|
|
|
|||||
Common Stockholders Equity: |
||||||||
Common stock, par value $40 per share |
||||||||
Authorized - 40,000,000 shares |
||||||||
Outstanding - 30,537,500 shares |
1,222 | 1,222 | ||||||
Paid-in capital |
2,207 | 2,182 | ||||||
Retained earnings |
1,997 | 1,956 | ||||||
Accumulated other comprehensive loss |
(25 | ) | (18 | ) | ||||
|
|
|
|
|||||
Total common stockholders equity |
5,401 | 5,342 | ||||||
|
|
|
|
|||||
Total Liabilities and Stockholders Equity |
$ | 18,554 | $ | 18,477 | ||||
|
|
|
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
41
Table of Contents
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SECOND QUARTER 2012 vs. SECOND QUARTER 2011
AND
YEAR-TO-DATE 2012 vs. YEAR-TO-DATE 2011
OVERVIEW
Alabama Power operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service territory located within the State of Alabama in addition to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Alabama Powers business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel, capital expenditures, and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future.
Alabama Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENTS DISCUSSION AND ANALYSIS OVERVIEW Key Performance Indicators of Alabama Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(5) |
(2.6) | $(31) |
(9.1) | |||
|
Alabama Powers net income after dividends on preferred and preference stock for the second quarter 2012 was $185 million compared to $190 million for the corresponding period in 2011. Alabama Powers net income after dividends on preferred and preference stock for year-to-date 2012 was $311 million compared to $342 million for the corresponding period in 2011. The decreases for the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 were related to decreases in weather-related revenues due to milder weather and increases in operations and maintenance expenses in 2012. These decreases were partially offset by increases in revenues associated with the elimination of a tax-related adjustment under Alabama Powers rate structure and increases in energy sales due to increases in usage and customer growth. See BUSINESS Rate Matters Rate Structure and Cost Recovery Plans of Alabama Power in Item 1 and MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Retail Rate Adjustments of Alabama Power in Item 7 of the Form 10-K for information regarding the rate structure of Alabama Power.
Retail Revenues
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$10 |
0.8 | $(24) |
(1.0) | |||
|
In the second quarter 2012, retail revenues were $1.25 billion compared to $1.24 billion for the corresponding period in 2011. For year-to-date 2012, retail revenues were $2.35 billion compared to $2.37 billion for the corresponding period in 2011.
42
Table of Contents
ALABAMA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the change to retail revenues were as follows:
Second Quarter 2012 |
Year-to-Date 2012 | |||||||
| ||||||||
(in millions) | (% change) | (in millions) | (% change) | |||||
Retail prior year |
$1,244 | $2,370 | ||||||
Estimated change in |
||||||||
Rates and pricing |
31 | 2.5 | 56 | 2.4 | ||||
Sales growth (decline) |
25 | 2.0 | 45 | 1.9 | ||||
Weather |
(38) | (3.0) | (88) | (3.7) | ||||
Fuel and other cost recovery |
(8) | (0.7) | (37) | (1.6) | ||||
| ||||||||
Retail current year |
$1,254 | 0.8% | $2,346 | (1.0)% | ||||
|
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 primarily due to the elimination of a tax-related adjustment under Alabama Powers rate structure that was effective with October 2011 billings, slightly offset by decreased revenues associated with Rate Certificated New Plant Environmental (Rate CNP Environmental).
Revenues attributable to changes in sales increased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011. Weather-adjusted residential KWH energy sales increased 5.6% in the second quarter and 3.5% for year-to-date 2012 as a result of increases in usage and customer growth. Weather-adjusted commercial KWH energy sales increased 3.6% in the second quarter 2012 and 1.7% for year-to-date 2012 as a result of increases in usage. Industrial KWH energy sales increased 2.3% in the second quarter 2012 and 2.8% for year-to-date 2012 due to an increase in usage resulting from changes in production levels primarily in the primary metals, chemicals, automotive and plastics, and forest products sectors, partially offset by decreases in the stone, clay, and glass and textiles sectors.
Revenues resulting from changes in weather decreased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011. Alabama Powers service territory experienced milder weather conditions in the second quarter and year-to-date 2012 when compared to the corresponding periods in the prior year. The resulting decreases for the second quarter 2012 were 5.4% and 2.5% for residential and commercial sales revenue, respectively. The resulting decreases for year-to-date 2012 were 7.1% and 2.1% for residential and commercial sales revenue, respectively.
Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 primarily due to lower fuel costs associated with decreased KWH generation and lower average cost per KWH generated due to lower natural gas prices. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income.
See BUSINESS Rate Matters Rate Structure and Cost Recovery Plans of Alabama Power in Item 1, MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Retail Rate Adjustments of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under Retail Regulatory Matters in Item 8 of the Form 10-K for additional information.
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ALABAMA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues Non-Affiliates
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$ |
| $(7) |
(5.1) | |||
|
Wholesale revenues from sales to non-affiliates will vary depending on the market prices of available wholesale energy compared to the cost of Alabama Powers and the Southern Company systems generation, demand for energy within the Southern Company systems service territory, and availability of the Southern Company systems generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.
In the second quarter 2012 and the second quarter 2011, wholesale revenues from non-affiliates were $70 million. For year-to-date 2012, wholesale revenues from non-affiliates were $131 million compared to $138 million for the corresponding period in 2011. The decrease was primarily due to a 4.1% decrease in KWH sales and a 1.2% decrease in the price of energy.
Wholesale Revenues Affiliates
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(69) |
(92.0) | $(130) |
(86.7) | |||
|
Wholesale revenues from sales to affiliated companies within the Southern Company system will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Powers energy cost recovery clauses.
In the second quarter 2012, wholesale revenues from affiliates were $6 million compared to $75 million for the corresponding period in 2011. The decrease was primarily due to a 90.2% decrease in KWH sales.
For year-to-date 2012, wholesale revenues from affiliates were $20 million compared to $150 million for the corresponding period in 2011. The decrease was due to an 82.6% decrease in KWH sales and a 23.5% decrease in the price of energy.
Fuel and Purchased Power Expenses
Second Quarter 2012 vs. Second Quarter 2011 |
Year-to-Date 2012 vs. Year-to-Date 2011 | |||||||
| ||||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||||
Fuel |
$(85) | (19.9) | $(174) | (21.1) | ||||
Purchased power non-affiliates |
| | 4 | 14.3 | ||||
Purchased power affiliates |
9 | 15.8 | 3 | 2.9 | ||||
|
|
|||||||
Total fuel and purchased power expenses |
$(76) | $(167) | ||||||
|
|
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Table of Contents
ALABAMA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the second quarter 2012, total fuel and purchased power expenses were $426 million compared to $502 million for the corresponding period in 2011. The decrease was primarily due to a $64 million decrease related to a reduction in total KWHs generated as a result of milder weather in the second quarter 2012, a $22 million decrease in the cost of fuel, and a $46 million decrease in the average cost of purchased power, partially offset by a $55 million increase in KWHs purchased.
For year-to-date 2012, total fuel and purchased power expenses were $787 million compared to $954 million for the corresponding period in 2011. The decrease was primarily due to a $149 million decrease related to a reduction in total KWHs generated as a result of milder weather for year-to-date 2012, a $25 million decrease in the cost of fuel, and a $51 million decrease in the average cost of purchased power, partially offset by a $58 million increase in KWHs purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Powers Energy Cost Recovery Rate mechanism. See FUTURE EARNINGS POTENTIAL PSC Matters Retail Fuel Cost Recovery herein for additional information.
Details of Alabama Powers generation and purchased power were as follows:
Second Quarter 2012 |
Second Quarter 2011 |
Year-to-Date 2012 |
Year-to-Date 2011 | |||||
| ||||||||
Total generation (billions of KWHs) |
13 | 17 | 27 | 33 | ||||
Total purchased power (billions of KWHs) |
2 | 1 | 3 | 2 | ||||
| ||||||||
Sources of generation (percent) |
||||||||
Coal |
53 | 56 | 48 | 56 | ||||
Nuclear |
24 | 23 | 26 | 23 | ||||
Gas |
21 | 16 | 20 | 15 | ||||
Hydro |
2 | 5 | 6 | 6 | ||||
| ||||||||
Cost of fuel, generated (cents per net KWH) |
||||||||
Coal |
3.29 | 3.13 | 3.35 | 3.06 | ||||
Nuclear |
0.82 | 0.64 | 0.78 | 0.65 | ||||
Gas |
2.76 | 4.19 | 2.88 | 4.18 | ||||
| ||||||||
Average cost of fuel, generated (cents per net KWH)(a) |
2.57 | 2.71 | 2.54 | 2.67 | ||||
Average cost of purchased power (cents per net KWH)(b) |
3.89 | 6.02 | 4.14 | 5.66 | ||||
|
(a) | KWHs generated by hydro are excluded from the average cost of fuel, generated. |
(b) | Average cost of purchased power includes fuel purchased by Alabama Power for tolling agreements where power is generated by the provider. |
Fuel
In the second quarter 2012, fuel expense was $343 million compared to $428 million for the corresponding period in 2011. The $85 million decrease was due to a 34.1% decrease in the average cost of KWHs generated by natural gas, which excludes fuel associated with tolling agreements, and a 23.5% decrease in KWHs generated by coal, slightly offset by a 6.9% increase in KWHs generated by natural gas.
For year-to-date 2012, fuel expense was $649 million compared to $823 million for the corresponding period in 2011. The $174 million decrease was due to a 31.0% decrease in the average cost of KWHs generated by natural gas, which excludes fuel associated with tolling agreements, and a 29.4% decrease in KWHs generated by coal, slightly offset by an 8.4% increase in KWHs generated by natural gas.
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Table of Contents
ALABAMA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Purchased Power Non-Affiliates
In the second quarter 2012 and the second quarter 2011, purchased power expense from non-affiliates was $17 million. For year-to-date 2012, purchased power expense from non-affiliates was $32 million compared to $28 million for the corresponding period in 2011. The increase was related to a 388.0% increase in the amount of energy purchased, partially offset by a 76.6% decrease in the average cost per KWH.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company systems generation, demand for energy within the Southern Company systems service territory, and the availability of the Southern Company systems generation.
Purchased Power Affiliates
In the second quarter 2012, purchased power expense from affiliates was $66 million compared to $57 million for the corresponding period in 2011. The increase was related to a 54.4% increase in the amount of energy purchased, partially offset by a 26.2% decrease in the average cost per KWH.
For year-to-date 2012, purchased power expense from affiliates was $106 million compared to $103 million for the corresponding period in 2011. The increase was related to a 23.2% increase in the amount of energy purchased, partially offset by a 17.0% decrease in the average cost per KWH.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$26 |
9.0 | $50 | 8.5 | |||
|
In the second quarter 2012, other operations and maintenance expenses were $316 million compared to $290 million for the corresponding period in 2011. Administrative and general expenses increased $15 million primarily due to pension and other benefit-related expenses. Distribution expenses increased $7 million primarily due to increases in vegetation management and overhead line maintenance costs. Steam production expenses increased $3 million due to environmental mandates which were partially offset by revenues associated with Rate CNP Environmental.
For year-to-date 2012, other operations and maintenance expenses were $637 million compared to $587 million for the corresponding period in 2011. Administrative and general expenses increased $33 million primarily due to pension and other benefit-related expenses, affiliated service company expenses, labor expenses, and property insurance expenses. Nuclear production expenses increased $5 million primarily due to the amortization of nuclear outage expenses of $13 million, partially offset by a decrease in operation costs related to decreases in labor. See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Nuclear Outage Accounting Order of Alabama Power in Item 7 of the Form 10-K for additional information. Additionally, distribution and transmission expenses increased $4 million due to increases in labor expenses and vegetation management.
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Table of Contents
ALABAMA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(5) |
(3.8) | $(17) | (7.5) | |||
|
In the second quarter 2012, income taxes were $126 million compared to $131 million for the corresponding period in 2011. For year-to-date 2012, income taxes were $210 million compared to $227 million for the corresponding period in 2011. The decreases for the second quarter and year-to-date 2012 were primarily due to lower pre-tax earnings as a result of lower revenues due to milder weather and an increase in operations and maintenance expense.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Alabama Powers future earnings potential. The level of Alabama Powers future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Alabama Powers primary business of selling electricity. These factors include Alabama Powers ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which are subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Powers service territory. Changes in economic conditions impact sales for Alabama Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under Environmental Matters in Item 8 of the Form 10-K for additional information.
New Source Review Actions
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters New Source Review Actions of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under Environmental Matters New Source Review Actions in Item 8 of the Form 10-K for additional information. On February 23, 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power. The U.S. District Court for the Northern District of Alabama has not ruled on the EPAs motion seeking vacatur of the judgment. The ultimate outcome of this matter cannot be determined at this time.
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Table of Contents
ALABAMA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Climate Change Litigation
Hurricane Katrina Case
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Climate Change Litigation Hurricane Katrina Case of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under Environmental Matters Climate Change Litigation Hurricane Katrina Case in Item 8 of the Form 10-K for additional information. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the amended class action complaint filed in May 2011 by the plaintiffs. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
General
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations General of Alabama Power in Item 7 of the Form 10-K for information regarding Alabama Powers estimated base level capital expenditures to comply with existing statutes and regulations for 2012 through 2014, as well as Alabama Powers preliminary estimates for potential incremental environmental compliance investments associated with complying with the EPAs final Mercury and Air Toxics Standards (MATS) rule (formerly referred to as the Utility Maximum Achievable Control Technology rule) and the EPAs proposed water and coal combustion byproducts rules.
Alabama Power is continuing to develop its compliance strategy and to assess the potential costs of complying with the MATS rule and the EPAs proposed water and coal combustion byproducts rules. As part of the development of its compliance strategy for the MATS rule, Alabama Power has entered into agreements for the construction of baghouses to control the emissions of mercury and particulates from generating units with an aggregate capacity of 1,901 MWs. While further analysis of the MATS rule is required and the ultimate costs remain uncertain, the compliance decisions made through the second quarter 2012 have allowed Alabama Power to further develop its cost estimates for compliance with the MATS rule. As a result, estimated compliance costs for the MATS rule in the 2012 through 2014 period have been revised from up to $1.2 billion to approximately $660 million as follows:
2012 | 2013 | 2014 | ||||||||||
|
||||||||||||
(in millions) | ||||||||||||
MATS rule |
$ | 65 | $ | 155 | $ | 440 | ||||||
|
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Table of Contents
ALABAMA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In addition, Alabama Power has further developed its estimated capital expenditures and associated timing of these expenditures to comply with the proposed water and coal combustion byproducts rules, resulting in a reduction, due primarily to timing, in estimated compliance costs for 2012 through 2014. Potential incremental environmental compliance investments to comply with the proposed water and coal combustion byproducts rules have been revised from up to $630 million to approximately $175 million over the 2012 through 2014 period, based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule. These potential incremental environmental compliance investments are estimated as follows:
2012 | 2013 | 2014 | ||||||||||
|
||||||||||||
(in millions) | ||||||||||||
Proposed water and coal combustion byproducts rules |
$5 | $10 | $160 | |||||||||
|
While Alabama Powers ultimate costs of compliance with the MATS rule and the proposed water and coal combustion byproducts rules remain uncertain, Alabama Power estimates that compliance costs through 2021 (assuming that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) will be at the low end of the $5 billion to $7 billion range provided in the Form 10-K.
Alabama Powers ultimate compliance strategy and actual future environmental capital expenditures are dependent on a final assessment of the MATS rule and will be affected by the final requirements of new or revised environmental regulations that are promulgated; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and Alabama Powers fuel mix. Compliance costs may arise from retirement and replacement of existing units, installation of additional environmental controls, upgrades to the transmission system, and changing fuel sources for certain existing units. Alabama Powers preliminary analysis further indicates that the short timeframe for compliance with the MATS rule could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters cannot be determined at this time.
As part of SEGCOs environmental compliance strategy, the Board of Directors of SEGCO approved adding natural gas as the primary fuel source in 2015 for its 1,000 MWs of generating capacity and the construction of the necessary natural gas pipeline. SEGCO is jointly owned by Alabama Power and Georgia Power. The capacity of SEGCOs units is sold to Alabama Power and Georgia Power through a PPA. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information. The impact of SEGCOs ultimate compliance strategy on the PPA costs cannot be determined at this time; however, if such costs cannot continue to be recovered through retail rates, they could have a material impact on Alabama Powers financial statements.
Air Quality
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations Air Quality of Alabama Power in Item 7 of the Form 10-K for additional information on the eight-hour ozone and fine particulate matter air quality standards and the MATS rule.
On May 1, 2012, the EPA released its final determination of nonattainment areas based on the 2008 eight-hour ozone air quality standards. None of the areas within Alabama Powers service territory were designated as nonattainment areas.
On June 14, 2012, the EPA proposed a rule that would increase the stringency of the fine particulate matter national ambient air quality standards. If adopted, the proposed standards could result in the designation of new nonattainment areas within Alabama Powers service territory. As part of a related settlement, the EPA has agreed to finalize the proposed rule by December 14, 2012. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
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Table of Contents
ALABAMA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Numerous petitions for administrative reconsideration of the MATS rule, including a petition by Southern Company and its subsidiaries, including Alabama Power, have been filed with the EPA. Challenges to the final rule have also been filed in the U.S. District Court for the District of Columbia by numerous states, environmental organizations, industry groups, and others. The impact of the MATS rule will depend on the outcome of these and any other legal challenges and, therefore, cannot be determined at this time.
Water Quality
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations Water Quality of Alabama Power in Item 7 of the Form 10-K for additional information on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Byproducts
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations Coal Combustion Byproducts of Alabama Power in Item 7 of the Form 10-K for additional information. Environmental groups and other parties have filed lawsuits in the U.S. District Court for the District of Columbia seeking to require the EPA to complete its rulemaking process and issue final regulations pertaining to the regulation of coal combustion byproducts. The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Global Climate Issues of Alabama Power in Item 7 of the Form 10-K for additional information.
On April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.
On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPAs actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.
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Table of Contents
ALABAMA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
PSC Matters
Rate CNP
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Retail Rate Adjustments Rate CNP of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under Retail Regulatory Matters Rate CNP in Item 8 of the Form 10-K for additional information regarding Alabama Powers recovery of retail costs through Rate Certificated New Plant Power Purchase Agreement (Rate CNP) and Rate CNP Environmental. Alabama Powers under recovered Rate CNP balance as of June 30, 2012 was $2 million as compared to $6 million at December 31, 2011. Alabama Powers under recovered Rate CNP Environmental balance as of June 30, 2012 was $26 million as compared to $11 million at December 31, 2011. These under recovered balances at June 30, 2012 are included in deferred under recovered regulatory clause revenues on Alabama Powers Condensed Balance Sheet herein. For Rate CNP, this classification is based on an estimate, which includes such factors as purchased power capacity and energy demand. For Rate CNP Environmental, this classification is based on an estimate, which includes such factors as costs to comply with environmental mandates and energy demand. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered retail costs.
Retail Fuel Cost Recovery
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Fuel Cost Recovery of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under Retail Regulatory Matters Fuel Cost Recovery in Item 8 of the Form 10-K for information regarding Alabama Powers fuel cost recovery. Alabama Powers under recovered fuel costs as of June 30, 2012 totaled $16 million as compared to $31 million at December 31, 2011. These under recovered fuel costs at June 30, 2012 are included in under recovered regulatory clause revenues on Alabama Powers Condensed Balance Sheet herein. This classification is based on an estimate which includes such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered fuel costs.
Natural Disaster Cost Recovery
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Natural Disaster Reserve of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under Retail Regulatory Matters Natural Disaster Reserve in Item 8 of the Form 10-K for additional information regarding natural disaster cost recovery. At June 30, 2012, the NDR had an accumulated balance of $105 million, which is included in Alabama Powers Condensed Balance Sheet herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in Alabama Powers Condensed Statement of Income herein.
Income Tax Matters
Bonus Depreciation
In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Alabama Power through 2013. Consequently, Alabama Powers positive cash flow benefit is estimated to be between $85 million and $110 million in 2012.
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Table of Contents
ALABAMA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Matters
Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Powers business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Alabama Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) herein or in Note 3 to the financial statements of Alabama Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Alabama Powers financial statements.
See the Notes to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Other Matters of Alabama Power in Item 7 of the Form 10-K for additional information regarding the earthquake and tsunami that struck Japan in March 2011. On March 12, 2012, the NRC issued three orders and a request for information based on the NRC task force report recommendations that included, among other items, additional mitigation strategies for beyond-design-basis events, enhanced spent fuel pool instrumentation capabilities, hardened vents for certain classes of containment structures, site specific evaluations for seismic and flooding hazards, and various plant evaluations to ensure adequate coping capabilities during station blackout and other conditions. The staff of the NRC expects to issue additional implementation guidance by the end of August 2012. The final form and the resulting impact of any changes to safety requirements for nuclear reactors will be dependent on further review and action by the NRC and cannot be determined at this time. See RISK FACTORS of Alabama Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. The ultimate outcome of these events cannot be determined at this time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Powers results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENTS DISCUSSION AND ANALYSIS ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Powers critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, and Pension and Other Postretirement Benefits.
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Table of Contents
ALABAMA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Overview of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Powers financial condition remained stable at June 30, 2012. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See Sources of Capital, Financing Activities, and Capital Requirements and Contractual Obligations herein for additional information.
Net cash provided from operating activities totaled $481 million for the first six months of 2012, a decrease of $338 million as compared to the first six months of 2011. The decrease in cash provided from operating activities was primarily due to an increase in fossil fuel stock, a decrease in deferred income taxes, and the timing of income tax payments and refunds associated with bonus depreciation. Net cash used for investing activities totaled $464 million for the first six months of 2012 primarily due to gross property additions related to nuclear fuel and transmission, distribution, and steam generating equipment. Net cash used for financing activities totaled $283 million for the first six months of 2012. This was primarily due to the payment of common stock dividends. Fluctuations in cash flow from financing activities vary year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first six months of 2012 include increases of $125 million in fossil fuel stock, at average cost, $116 million in property, plant, and equipment associated with routine property additions and nuclear fuel, $67 million in accrued income taxes, and $61 million in prepaid expenses and decreases of $266 million in cash and cash equivalents and $126 million in other accounts payable.
Capital Requirements and Contractual Obligations
See MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Capital Requirements and Contractual Obligations of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Powers capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental regulations, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $500 million will be required through June 30, 2013 to fund maturities of long-term debt.
See FUTURE EARNINGS POTENTIAL Environmental Statutes and Regulations General herein for a description of the Alabama Powers estimated capital expenditures to comply with the MATS rule and proposed water and coal combustion byproducts rules.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet new regulatory requirements; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
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Table of Contents
ALABAMA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Sources of Capital
Alabama Power plans to obtain the funds required for construction and other purposes from sources similar to those utilized in the past. Alabama Power has primarily utilized funds from operating cash flows, short-term debt, security issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Sources of Capital of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Powers current liabilities sometimes exceed current assets because of Alabama Powers debt due within one year and the periodic use of short-term debt as a funding source primarily to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business.
At June 30, 2012, Alabama Power had approximately $78 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2012, including expiration dates, were as follows:
Expires | Executable Term Loans |
Due Within One Year(a) | ||||||||||||||
|
|
| ||||||||||||||
2012 | 2013 | 2014 and |
Total | Unused | One Year |
Two Years |
Term Out |
No Term Out | ||||||||
|
|
|
| |||||||||||||
(in millions) | (in millions) | (in millions) | (in millions) | |||||||||||||
$37 | $101 | $1,150 | $1,288 | $1,288 | $51 | $ | $51 | $52 |
(a) | Reflects facilities expiring on or before June 30, 2013. |
See Note 6 to the financial statements of Alabama Power under Bank Credit Arrangements in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under Bank Credit Arrangements herein for additional information.
Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of Alabama Power. Alabama Power is currently in compliance with all such covenants. Alabama Power expects to renew its credit arrangements, as needed, prior to expiration. These credit arrangements provide liquidity support to Alabama Powers commercial paper borrowings and variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2012 was approximately $793 million.
Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each traditional operating company under these arrangements are several and there is no cross affiliate credit support.
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Table of Contents
ALABAMA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of short-term borrowings were as follows:
Short-term Debt at the End of the Period |
Short-term Debt During the Period (a) | |||||||||||||||||||
Amount Outstanding |
Weighted Average Interest Rate |
Average Outstanding |
Weighted Average Interest Rate |
Maximum Amount Outstanding |
||||||||||||||||
|
|
|
||||||||||||||||||
(in millions) | (in millions) | (in millions) | ||||||||||||||||||
June 30, 2012: |
||||||||||||||||||||
Commercial paper |
$ | % | $22 | 0.2% | $57 | |||||||||||||||
|
(a) | Average and maximum amounts are based upon daily balances during the period. |
Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
Credit Rating Risk
Alabama Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At June 30, 2012, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $311 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Alabama Powers ability to access capital markets, particularly the short-term debt market.
Market Price Risk
Alabama Powers market risk exposure relative to interest rate changes for the second quarter 2012 has not changed materially compared to the December 31, 2011 reporting period. Since a significant portion of outstanding indebtedness remains at fixed rates, Alabama Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Due to cost-based rate regulation and other various cost recovery mechanisms, Alabama Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Alabama Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. Alabama Power continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. As such, Alabama Power had no material change in market risk exposure for the second quarter 2012 when compared with the December 31, 2011 reporting period.
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Table of Contents
ALABAMA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three and six months ended June 30, 2012 were as follows:
Second Quarter 2012 Changes |
Year-to-Date 2012 Changes |
|||||||
|
||||||||
Fair Value | ||||||||
(in millions) | ||||||||
Contracts outstanding at the beginning of the period, assets (liabilities), net |
$(53) | $(48) | ||||||
Contracts realized or settled |
16 | 30 | ||||||
Current period changes(a) |
5 | (14) | ||||||
|
||||||||
Contracts outstanding at the end of the period, assets (liabilities), net |
$(32) | $(32) | ||||||
|
(a) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
The changes in the fair value positions of the energy-related derivative contracts, which are substantially all attributable to both the volume and the price of natural gas, for the three and six months ended June 30, 2012 were as follows:
Second Quarter 2012 Changes |
Year-to-Date 2012 Changes |
|||||||
|
||||||||
Fair Value | ||||||||
(in millions) | ||||||||
Natural gas swaps |
$16 | $14 | ||||||
Natural gas options |
5 | 2 | ||||||
Other energy-related derivatives |
| | ||||||
|
||||||||
Total changes |
$21 | $16 | ||||||
|
The net hedge volumes of energy-related derivative contracts were as follows:
June 30, 2012 |
March 31, 2012 |
December 31, 2011 |
||||||||||
|
||||||||||||
mmBtu Volume | ||||||||||||
(in millions) | ||||||||||||
Commodity Natural gas swaps |
32 | 27 | 30 | |||||||||
Commodity Natural gas options |
11 | 10 | 9 | |||||||||
|
||||||||||||
Total hedge volume |
43 | 37 | 39 | |||||||||
|
The weighted average swap contract cost above market prices was approximately $0.93 per mmBtu as of June 30, 2012, $1.72 per mmBtu as of March 31, 2012, and $1.45 per mmBtu as of December 31, 2011. The change in option premiums is primarily attributable to the volatility of the market and the underlying change in the natural gas price. A majority of the natural gas hedge gains and losses is recovered through Alabama Powers retail fuel cost recovery clause.
Regulatory hedges relate to Alabama Powers fuel-hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through Alabama Powers fuel cost recovery clause.
Unrealized pre-tax gains and losses recognized in income for the three and six months ended June 30, 2012 and 2011 for energy-related derivative contracts that are not hedges were not material.
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Table of Contents
ALABAMA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at June 30, 2012 were as follows:
June 30, 2012 Fair Value Measurements |
||||||||||||||||
|
||||||||||||||||
Total Fair Value |
Maturity | |||||||||||||||
Year 1 | Years 2&3 | Years 4&5 | ||||||||||||||
|
||||||||||||||||
(in millions) | ||||||||||||||||
Level 1 |
$ | $ | $ | $ | ||||||||||||
Level 2 |
(32) | (25) | (7) | | ||||||||||||
Level 3 |
| | | | ||||||||||||
|
||||||||||||||||
Fair value of contracts outstanding at end of period |
$(32) | $(25) | $(7) | $ | ||||||||||||
|
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Alabama Power. Regulations to implement the Dodd-Frank Act will impose additional requirements on the use of over-the-counter derivatives for both Alabama Power and its derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Alabama Power does not expect the impact of these rules to be material.
For additional information, see MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Market Price Risk of Alabama Power in Item 7 and Note 1 under Financial Instruments and Note 11 to the financial statements of Alabama Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
In January 2012, Alabama Power issued $250 million aggregate principal amount of Series 2012A 4.10% Senior Notes due January 15, 2042. The proceeds were used for general corporate purposes, including Alabama Powers continuous construction program. Alabama Power settled $100 million of interest rate swaps related to this issuance at a loss of $1 million. The loss is being amortized to interest expense, in earnings, over 10 years.
In March 2012, Alabama Power redeemed approximately $1 million aggregate principal amount of The Industrial Development Board of the Town of West Jefferson Solid Waste Disposal Revenue Bonds (Alabama Power Company Miller Plant Project), Series 2008.
In April 2012, Alabama Power redeemed $250 million aggregate principal amount of its Series 2007B 5.875% Senior Notes due April 1, 2047.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Alabama Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
57
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58
Table of Contents
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
For the Three Months Ended June 30, |
For the Six Months Ended June 30, |
|||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in millions) | (in millions) | |||||||||||||||
Operating Revenues: |
||||||||||||||||
Retail revenues |
$ | 1,857 | $ | 2,070 | $ | 3,451 | $ | 3,885 | ||||||||
Wholesale revenues, non-affiliates |
75 | 97 | 141 | 180 | ||||||||||||
Wholesale revenues, affiliates |
6 | 16 | 9 | 27 | ||||||||||||
Other revenues |
82 | 82 | 164 | 162 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total operating revenues |
2,020 | 2,265 | 3,765 | 4,254 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Operating Expenses: |
||||||||||||||||
Fuel |
572 | 784 | 1,012 | 1,461 | ||||||||||||
Purchased power, non-affiliates |
94 | 96 | 187 | 170 | ||||||||||||
Purchased power, affiliates |
129 | 157 | 288 | 320 | ||||||||||||
Other operations and maintenance |
411 | 419 | 845 | 841 | ||||||||||||
Depreciation and amortization |
185 | 178 | 373 | 351 | ||||||||||||
Taxes other than income taxes |
94 | 94 | 181 | 181 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total operating expenses |
1,485 | 1,728 | 2,886 | 3,324 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Operating Income |
535 | 537 | 879 | 930 | ||||||||||||
Other Income and (Expense): |
||||||||||||||||
Allowance for equity funds used during construction |
13 | 22 | 26 | 47 | ||||||||||||
Interest expense, net of amounts capitalized |
(90 | ) | (71 | ) | (181 | ) | (167 | ) | ||||||||
Other income (expense), net |
(6 | ) | (5 | ) | (9 | ) | (6 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other income and (expense) |
(83 | ) | (54 | ) | (164 | ) | (126 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Earnings Before Income Taxes |
452 | 483 | 715 | 804 | ||||||||||||
Income taxes |
152 | 169 | 244 | 280 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net Income |
300 | 314 | 471 | 524 | ||||||||||||
Dividends on Preferred and Preference Stock |
5 | 5 | 9 | 9 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net Income After Dividends on Preferred and Preference Stock |
$ | 295 | $ | 309 | $ | 462 | $ | 515 | ||||||||
|
|
|
|
|
|
|
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
For the Three Months Ended June 30, |
For the Six Months Ended June 30, |
|||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in millions) | (in millions) | |||||||||||||||
Net Income After Dividends on Preferred and Preference Stock |
$ | 295 | $ | 309 | $ | 462 | $ | 515 | ||||||||
Other comprehensive income (loss): |
||||||||||||||||
Qualifying hedges: |
||||||||||||||||
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $1 and $1, respectively |
| | 1 | 1 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other comprehensive income (loss) |
| | 1 | 1 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Comprehensive Income |
$ | 295 | $ | 309 | $ | 463 | $ | 516 | ||||||||
|
|
|
|
|
|
|
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
59
Table of Contents
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
For the Six Months Ended June 30, |
||||||||
2012 | 2011 | |||||||
(in millions) | ||||||||
Operating Activities: |
||||||||
Net income |
$ | 471 | $ | 524 | ||||
Adjustments to reconcile net income to net cash provided from operating activities |
||||||||
Depreciation and amortization, total |
458 | 426 | ||||||
Deferred income taxes |
128 | 189 | ||||||
Allowance for equity funds used during construction |
(26 | ) | (47 | ) | ||||
Retail fuel cost over recoverylong-term |
44 | | ||||||
Deferred expenses |
26 | 33 | ||||||
Other, net |
(3 | ) | (73 | ) | ||||
Changes in certain current assets and liabilities |
||||||||
-Receivables |
19 | (100 | ) | |||||
-Fossil fuel stock |
(147 | ) | 55 | |||||
-Prepaid income taxes |
13 | 77 | ||||||
-Other current assets |
8 | (14 | ) | |||||
-Accounts payable |
(37 | ) | 60 | |||||
-Accrued taxes |
(77 | ) | (123 | ) | ||||
-Accrued compensation |
(60 | ) | (42 | ) | ||||
-Retail fuel cost over recoveryshort-term |
55 | | ||||||
-Other current liabilities |
43 | 46 | ||||||
|
|
|
|
|||||
Net cash provided from operating activities |
915 | 1,011 | ||||||
|
|
|
|
|||||
Investing Activities: |
||||||||
Property additions |
(812 | ) | (931 | ) | ||||
Investment of restricted cash |
(234 | ) | | |||||
Distribution of restricted cash |
49 | | ||||||
Nuclear decommissioning trust fund purchases |
(488 | ) | (1,152 | ) | ||||
Nuclear decommissioning trust fund sales |
486 | 1,149 | ||||||
Cost of removal, net of salvage |
(34 | ) | (9 | ) | ||||
Change in construction payables, net of joint owner portion |
(161 | ) | 34 | |||||
Other investing activities |
(14 | ) | (12 | ) | ||||
|
|
|
|
|||||
Net cash used for investing activities |
(1,208 | ) | (921 | ) | ||||
|
|
|
|
|||||
Financing Activities: |
||||||||
Decrease in notes payable, net |
(513 | ) | (253 | ) | ||||
Proceeds |
||||||||
Capital contributions from parent company |
18 | 183 | ||||||
Pollution control revenue bonds issuances |
234 | 250 | ||||||
Senior notes issuances |
1,500 | 550 | ||||||
Other long-term debt issuances |
| 250 | ||||||
Redemptions |
||||||||
Pollution control revenue bonds |
(49 | ) | (197 | ) | ||||
Senior notes |
| (101 | ) | |||||
Other long-term debt |
(250 | ) | (300 | ) | ||||
Payment of preferred and preference stock dividends |
(9 | ) | (9 | ) | ||||
Payment of common stock dividends |
(454 | ) | (448 | ) | ||||
Other financing activities |
(9 | ) | (2 | ) | ||||
|
|
|
|
|||||
Net cash provided from (used for) financing activities |
468 | (77 | ) | |||||
|
|
|
|
|||||
Net Change in Cash and Cash Equivalents |
175 | 13 | ||||||
Cash and Cash Equivalents at Beginning of Period |
13 | 8 | ||||||
|
|
|
|
|||||
Cash and Cash Equivalents at End of Period |
$ | 188 | $ | 21 | ||||
|
|
|
|
|||||
Supplemental Cash Flow Information: |
||||||||
Cash paid (received) during the period for |
||||||||
Interest (net of $11 and $17 capitalized for 2012 and 2011, respectively) |
$ | 156 | $ | 177 | ||||
Income taxes, net |
44 | (15 | ) | |||||
Noncash transactionsaccrued property additions at end of period |
234 | 299 |
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
60
Table of Contents
CONDENSED BALANCE SHEETS (UNAUDITED)
Assets |
At June 30, 2012 |
At December 31, 2011 |
||||||
(in millions) | ||||||||
Current Assets: |
||||||||
Cash and cash equivalents |
$ | 188 | $ | 13 | ||||
Restricted cash and cash equivalents |
185 | | ||||||
Receivables |
||||||||
Customer accounts receivable |
596 | 571 | ||||||
Unbilled revenues |
244 | 172 | ||||||
Under recovered regulatory clause revenues |
| 137 | ||||||
Joint owner accounts receivable |
45 | 87 | ||||||
Other accounts and notes receivable |
98 | 61 | ||||||
Affiliated companies |
55 | 26 | ||||||
Accumulated provision for uncollectible accounts |
(12 | ) | (13 | ) | ||||
Fossil fuel stock, at average cost |
870 | 723 | ||||||
Materials and supplies, at average cost |
391 | 406 | ||||||
Vacation pay |
84 | 82 | ||||||
Prepaid income taxes |
140 | 71 | ||||||
Other regulatory assets, current |
93 | 108 | ||||||
Other current assets |
81 | 106 | ||||||
|
|
|
|
|||||
Total current assets |
3,058 | 2,550 | ||||||
|
|
|
|
|||||
Property, Plant, and Equipment: |
||||||||
In service |
28,549 | 27,804 | ||||||
Less accumulated provision for depreciation |
10,395 | 10,296 | ||||||
|
|
|
|
|||||
Plant in service, net of depreciation |
18,154 | 17,508 | ||||||
Other utility plant, net |
53 | 55 | ||||||
Nuclear fuel, at amortized cost |
460 | 443 | ||||||
Construction work in progress |
3,055 | 3,274 | ||||||
|
|
|
|
|||||
Total property, plant, and equipment |
21,722 | 21,280 | ||||||
|
|
|
|
|||||
Other Property and Investments: |
||||||||
Equity investments in unconsolidated subsidiaries |
61 | 63 | ||||||
Nuclear decommissioning trusts, at fair value |
665 | 667 | ||||||
Miscellaneous property and investments |
44 | 44 | ||||||
|
|
|
|
|||||
Total other property and investments |
770 | 774 | ||||||
|
|
|
|
|||||
Deferred Charges and Other Assets: |
||||||||
Deferred charges related to income taxes |
757 | 756 | ||||||
Other regulatory assets, deferred |
1,550 | 1,604 | ||||||
Other deferred charges and assets |
221 | 187 | ||||||
|
|
|
|
|||||
Total deferred charges and other assets |
2,528 | 2,547 | ||||||
|
|
|
|
|||||
Total Assets |
$ | 28,078 | $ | 27,151 | ||||
|
|
|
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
61
Table of Contents
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholders Equity |
At June 30, 2012 |
At December 31, 2011 |
||||||
(in millions) | ||||||||
Current Liabilities: |
||||||||
Securities due within one year |
$ | 1,340 | $ | 455 | ||||
Notes payable |
2 | 515 | ||||||
Accounts payable |
||||||||
Affiliated |
357 | 337 | ||||||
Other |
451 | 686 | ||||||
Customer deposits |
227 | 213 | ||||||
Accrued taxes |
||||||||
Accrued income taxes |
110 | 36 | ||||||
Other accrued taxes |
175 | 304 | ||||||
Accrued interest |
108 | 92 | ||||||
Accrued vacation pay |
60 | 60 | ||||||
Accrued compensation |
67 | 125 | ||||||
Liabilities from risk management activities |
52 | 68 | ||||||
Other regulatory liabilities, current |
79 | 65 | ||||||
Nuclear decommissioning trust securities lending collateral |
8 | 32 | ||||||
Other current liabilities |
197 | 153 | ||||||
|
|
|
|
|||||
Total current liabilities |
3,233 | 3,141 | ||||||
|
|
|
|
|||||
Long-term Debt |
8,570 | 8,018 | ||||||
|
|
|
|
|||||
Deferred Credits and Other Liabilities: |
||||||||
Accumulated deferred income taxes |
4,608 | 4,388 | ||||||
Deferred credits related to income taxes |
118 | 122 | ||||||
Accumulated deferred investment tax credits |
214 | 220 | ||||||
Employee benefit obligations |
892 | 905 | ||||||
Asset retirement obligations |
759 | 734 | ||||||
Other cost of removal obligations |
97 | 110 | ||||||
Other deferred credits and liabilities |
255 | 224 | ||||||
|
|
|
|
|||||
Total deferred credits and other liabilities |
6,943 | 6,703 | ||||||
|
|
|
|
|||||
Total Liabilities |
18,746 | 17,862 | ||||||
|
|
|
|
|||||
Preferred Stock |
45 | 45 | ||||||
|
|
|
|
|||||
Preference Stock |
221 | 221 | ||||||
|
|
|
|
|||||
Common Stockholders Equity: |
||||||||
Common stock, without par value |
||||||||
Authorized 20,000,000 shares |
||||||||
Outstanding 9,261,500 shares |
398 | 398 | ||||||
Paid-in capital |
5,557 | 5,522 | ||||||
Retained earnings |
3,119 | 3,112 | ||||||
Accumulated other comprehensive loss |
(8 | ) | (9 | ) | ||||
|
|
|
|
|||||
Total common stockholders equity |
9,066 | 9,023 | ||||||
|
|
|
|
|||||
Total Liabilities and Stockholders Equity |
$ | 28,078 | $ | 27,151 | ||||
|
|
|
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SECOND QUARTER 2012 vs. SECOND QUARTER 2011
AND
YEAR-TO-DATE 2012 vs. YEAR-TO-DATE 2011
OVERVIEW
Georgia Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Georgia Powers business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, and fuel prices. In addition, Georgia Power is currently constructing two new nuclear units and one new combined cycle generating unit. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.
Georgia Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENTS DISCUSSION AND ANALYSIS OVERVIEW Key Performance Indicators of Georgia Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(14) |
(4.5) | $(53) | (10.3) | |||
|
Georgia Powers net income after dividends on preferred and preference stock for the second quarter 2012 was $295 million compared to $309 million for the corresponding period in 2011. Georgia Powers net income after dividends on preferred and preference stock for year-to-date 2012 was $462 million compared to $515 million for the corresponding period in 2011. The decreases were primarily due to decreases in operating revenues primarily as a result of milder weather, higher depreciation, and lower AFUDC, partially offset by lower income taxes and an increase related to retail revenue rate effects. The decreases were also due to lower interest expense in 2011 resulting from the settlement of litigation with the Georgia Department of Revenue (DOR), partially offset by a reduction in 2012 related to the conclusion of certain state and federal income tax audits.
Retail Revenues
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(213) |
(10.3) | $(434) | (11.2) | |||
|
In the second quarter 2012, retail revenues were $1.86 billion compared to $2.07 billion for the corresponding period in 2011. For year-to-date 2012, retail revenues were $3.45 billion compared to $3.89 billion for the corresponding period in 2011.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the change to retail revenues were as follows:
Second Quarter 2012 |
Year-to-Date 2012 |
|||||||||||||||
|
||||||||||||||||
(in millions) | (% change) | (in millions) | (% change) | |||||||||||||
Retail prior year |
$ 2,070 | $3,885 | ||||||||||||||
Estimated change in |
||||||||||||||||
Rates and pricing |
25 | 1.2 | 48 | 1.2 | ||||||||||||
Sales growth (decline) |
3 | 0.1 | (5) | (0.1) | ||||||||||||
Weather |
(43) | (2.1) | (93) | (2.4) | ||||||||||||
Fuel cost recovery |
(198) | (9.5) | (384) | (9.9) | ||||||||||||
|
||||||||||||||||
Retail current year |
$ 1,857 | (10.3)% | $ 3,451 | (11.2)% | ||||||||||||
|
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 due to base tariff increases effective April 1, 2012 related to placing Plant McDonough-Atkinson Units 4 and 5 in service, the NCCR and demand-side management tariff increases effective January 1, 2012, as approved by the Georgia PSC, and the rate pricing effect of decreased customer usage. These increases were partially offset by lower contributions from market-driven rates from commercial and industrial customers.
Revenues attributable to changes in sales remained flat in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011. Weather-adjusted residential KWH sales increased 0.8%, weather-adjusted commercial KWH sales increased 1.0%, and weather-adjusted industrial KWH sales decreased 1.1% in the second quarter 2012 when compared to the corresponding period in 2011. Weather-adjusted residential KWH sales increased 0.4%, weather-adjusted commercial KWH sales decreased 0.6%, and weather-adjusted industrial KWH sales decreased 0.6% year-to-date 2012 when compared to the corresponding period in 2011. The increase in residential sales is primarily due to customer growth. The economy continues to impact commercial and industrial sales.
Revenues resulting from changes in weather decreased in the second quarter 2012 when compared to the corresponding period in 2011 due to milder weather. Revenues resulting from changes in weather decreased year-to-date 2012 when compared to the corresponding period in 2011 as a result of milder weather in 2012 and cold weather in January 2011.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased $198 million and $384 million in the second quarter and year-to-date 2012, respectively, when compared to the corresponding periods in 2011 due to decreased KWH energy sales and lower costs primarily due to lower natural gas prices.
Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income. Georgia Power implemented reduced fuel rates effective June 1, 2012. See FUTURE EARNINGS POTENTIAL PSC Matters Fuel Cost Recovery herein for additional information.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues Non-Affiliates
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(22) |
(22.7) | $(39) | (21.7) | |||
|
Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Powers and the Southern Company systems generation, demand for energy within the Southern Company systems service territory, and the availability of the Southern Company systems generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Powers variable cost of energy.
In the second quarter 2012, wholesale revenues from non-affiliates were $75 million compared to $97 million in the corresponding period in 2011. For year-to-date 2012, wholesale revenues from non-affiliates were $141 million compared to $180 million in the corresponding period in 2011. The decreases were primarily due to 32.5% and 36.7% decreases in KWH sales in the second quarter and year-to-date 2012, respectively, due to lower demand resulting from milder weather.
Wholesale Revenues Affiliates
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(10) |
(62.5) | $(18) | (66.7) | |||
|
Wholesale revenues from sales to affiliated companies within the Southern Company system will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost.
In the second quarter 2012, wholesale revenues from affiliates were $6 million compared to $16 million in the corresponding period in 2011. For year-to-date 2012, wholesale revenues from affiliates were $9 million compared to $27 million in the corresponding period in 2011. The decreases were primarily due to 43.6% and 48.9% decreases in KWH sales in the second quarter and year-to-date 2012, respectively, due to lower demand resulting from milder weather and the availability of market energy at a lower cost than Georgia Power-owned generation.
Fuel and Purchased Power Expenses
Second Quarter 2012 vs. Second Quarter 2011 |
Year-to-Date 2012 vs. Year-to-Date 2011 |
|||||||||||||||
|
||||||||||||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||
Fuel |
$ | (212) | (27.0) | $ | (449) | (30.7) | ||||||||||
Purchased power non-affiliates |
(2) | (2.1) | 17 | 10.0 | ||||||||||||
Purchased power affiliates |
(28) | (17.8) | (32) | (10.0) | ||||||||||||
|
|
|
||||||||||||||
Total fuel and purchased power expenses |
$ | (242) | $ | (464) | ||||||||||||
|
|
|
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the second quarter 2012, total fuel and purchased power expenses were $795 million compared to $1.04 billion in the corresponding period in 2011. For year-to-date 2012, total fuel and purchased power expenses were $1.49 billion compared to $1.95 billion for the corresponding period in 2011. The decreases were primarily due to the lower cost of natural gas used for generation and lower demand related to milder weather in 2012.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Georgia Powers fuel cost recovery mechanism. See FUTURE EARNINGS POTENTIAL PSC Matters Fuel Cost Recovery herein for additional information.
Details of Georgia Powers generation and purchased power were as follows:
Second Quarter 2012 |
Second Quarter 2011 |
Year-to-Date 2012 |
Year-to-Date 2011 |
|||||||||||||||
|
|
|
||||||||||||||||
Total generation (billions of KWHs) |
16 | 18 | 29 | 34 | ||||||||||||||
Total purchased power (billions of KWHs) |
7 | 6 | 15 | 12 | ||||||||||||||
|
|
|
||||||||||||||||
Sources of generation (percent) |
||||||||||||||||||
Coal |
44 | 67 | 43 | 65 | ||||||||||||||
Nuclear |
26 | 20 | 28 | 22 | ||||||||||||||
Gas |
29 | 11 | 28 | 11 | ||||||||||||||
Hydro |
1 | 2 | 1 | 2 | ||||||||||||||
|
|
|
||||||||||||||||
Cost of fuel, generated (cents per net KWH) |
||||||||||||||||||
Coal |
5.00 | 4.70 | 4.86 | 4.72 | ||||||||||||||
Nuclear |
0.84 | 0.80 | 0.85 | 0.74 | ||||||||||||||
Gas |
2.71 | 5.39 | 2.90 | 4.88 | ||||||||||||||
|
|
|
||||||||||||||||
Average cost of fuel, generated (cents per net KWH) |
3.25 | 3.97 | 3.18 | 3.85 | ||||||||||||||
Average cost of purchased power (cents per net KWH)(a) |
4.24 | 5.79 | 4.03 | 5.68 | ||||||||||||||
|
|
|
(a) | Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider. |
Fuel
In the second quarter 2012, fuel expense was $572 million compared to $784 million in the corresponding period in 2011. The decrease was due to a 9.6% decrease of KWHs generated as a result of lower KWH demand and an 18.1% decrease in the average cost of fuel per KWH generated primarily due to lower natural gas prices.
For year-to-date 2012, fuel expense was $1.01 billion compared to $1.46 billion in the corresponding period in 2011. The decrease was primarily due to a 15.6% decrease of KWHs generated as a result of lower KWH demand and a 17.4% decrease in the average cost of fuel per KWH generated primarily due to lower natural gas prices.
Purchased Power Non-Affiliates
In the second quarter 2012, purchased power expense from non-affiliates was $94 million compared to $96 million in the corresponding period in 2011. The decrease was immaterial.
For year-to-date 2012, purchased power expense from non-affiliates was $187 million compared to $170 million in the corresponding period in 2011. The increase was due to an 84.4% increase in KWHs purchased as the market cost of available energy was lower than the additional Georgia Power-owned generation available, partially offset by a decrease of 40.8% in the average cost per KWH purchased primarily due to lower natural gas prices.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company systems generation, demand for energy within the Southern Company systems service territory, and the availability of the Southern Company systems generation.
Purchased Power Affiliates
In the second quarter 2012, purchased power expense from affiliates was $129 million compared to $157 million in the corresponding period in 2011. The decrease was due to a 25.3% decrease in the average cost per KWH purchased, reflecting lower natural gas prices.
For year-to-date 2012, purchased power expense from affiliates was $288 million compared to $320 million in the corresponding period in 2011. The decrease was due to a 28.3% decrease in the average cost per KWH purchased, reflecting lower natural gas prices, partially offset by a 12.6% increase in the volume of KWHs purchased as the cost of the available energy was lower than the Georgia Power-owned generation.
Energy purchases from affiliates will vary depending on the demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(8) |
(1.9) | $4 | 0.5 | |||
|
In the second quarter 2012, other operations and maintenance expenses were $411 million compared to $419 million in the corresponding period in 2011. The decrease was primarily due to a $9 million decrease in fossil generation expense due to a decrease in KWHs generated as a result of lower demand due to milder weather, a $5 million decrease in nuclear generation expense related to a nuclear fuel disposal settlement, and a $7 million decrease in uncollectible accounts expense, partially offset by a $10 million increase in employee pension expense and a $6 million increase in demand-side management program costs. See Note (B) under Nuclear Fuel Disposal Cost Litigation and Note (F) to the Condensed Financial Statements herein for additional information.
For year-to-date 2012, other operations and maintenance expenses were $845 million compared to $841 million in the corresponding period in 2011. The increase was primarily due to a $20 million increase in employee pension expense and an $11 million increase in demand-side management program costs, partially offset by a $19 million decrease in fossil generation expense due to a decrease in KWHs generated as a result of lower demand due to milder weather and a $10 million decrease in uncollectible accounts expense. The decrease in fossil generation was also due to outage timing and scope of outage work performed in the first quarter 2012. See Note (F) to the Condensed Financial Statements herein for additional information.
Depreciation and Amortization
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$7 |
3.9 | $22 | 6.3 | |||
|
In the second quarter 2012, depreciation and amortization was $185 million compared to $178 million in the corresponding period in 2011. For year-to-date 2012, depreciation and amortization was $373 million compared to $351 million in the corresponding period in 2011. The increases were primarily due to increases of $14 million and $27 million in depreciation in the second quarter and year-to-date 2012, respectively, on additional plant in service related to
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
new generation at Plant McDonough-Atkinson Units 4 and 5, partially offset by $9 million in amortization of the regulatory liability for state income tax credits beginning April 1, 2012, as authorized by the Georgia PSC. See Note 3 to the financial statements of Georgia Power under Construction Other Construction in Item 8 of the Form 10-K for additional information.
Allowance for Equity Funds Used During Construction
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(9) |
(40.9) | $(21) | (44.7) | |||
|
In the second quarter 2012, AFUDC equity was $13 million compared to $22 million in the corresponding period in 2011. For year-to-date 2012, AFUDC equity was $26 million compared to $47 million in the corresponding period in 2011. The decreases were primarily due to the completion of Plant McDonough-Atkinson Units 4 and 5 in December 2011 and April 2012, respectively.
Interest Expense, Net of Amounts Capitalized
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$19 |
26.8 | $14 | 8.4 | |||
|
In the second quarter 2012, interest expense, net of amounts capitalized was $90 million compared to $71 million in the corresponding period in 2011. For year-to-date 2012, interest expense, net of amounts capitalized was $181 million compared to $167 million in the corresponding period in 2011. The increases were primarily due to a $23 million reduction in interest expense in 2011 resulting from the settlement of litigation with the Georgia DOR, partially offset by a $9 million reduction in 2012 related to the conclusion of certain state and federal income tax audits.
Income Taxes
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(17) |
(10.1) | $(36) | (12.9) | |||
|
In the second quarter 2012, income taxes were $152 million compared to $169 million in the corresponding period in 2011. For year-to-date 2012, income taxes were $244 million compared to $280 million in the corresponding period in 2011. The decreases were primarily due to lower pre-tax earnings and state income tax credits, partially offset by decreases in non-taxable AFUDC equity. See Note (G) to the Condensed Financial Statements under Unrecognized Tax Benefits herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Georgia Powers future earnings potential. The level of Georgia Powers future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Powers business of selling electricity. These factors include Georgia Powers ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Powers service territory. Changes in economic conditions impact sales for Georgia Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RISK FACTORS in Item 1A and MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under Environmental Matters in Item 8 of the Form 10-K for additional information.
New Source Review Actions
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters New Source Review Actions of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under Environmental Matters New Source Review Actions in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under Environmental Matters New Source Review Actions herein for additional information. The case against Georgia Power was administratively closed in 2001 and has not been reopened. The ultimate outcome of this matter cannot be determined at this time.
Climate Change Litigation
Hurricane Katrina Case
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Climate Change Litigation Hurricane Katrina Case of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under Environmental Matters Climate Change Litigation Hurricane Katrina Case in Item 8 of the Form 10-K for additional information. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the amended class action complaint filed in May 2011 by the plaintiffs. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
General
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations General of Georgia Power in Item 7 of the Form 10-K for information regarding Georgia Powers estimated base level capital expenditures to comply with existing statutes and regulations for 2012 through 2014, as well as Georgia Powers preliminary estimates for potential incremental environmental compliance investments associated with complying with the EPAs final Mercury and Air Toxics Standards (MATS) rule (formerly referred to as the Utility Maximum Achievable Control Technology rule) and the EPAs proposed water and coal combustion byproducts rules.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Georgia Power is continuing to develop its compliance strategy and to assess the potential costs of complying with the MATS rule and the EPAs proposed water and coal combustion byproducts rules. As part of the development of its compliance strategy for the MATS rule, Georgia Power has entered into agreements for the construction of baghouses to control the emissions of mercury and particulates from certain generating units. While further analysis of the MATS rule is required and the ultimate costs remain uncertain, the compliance decisions made through the second quarter 2012 have allowed Georgia Power to further develop its cost estimates for compliance with the MATS rule. As a result, estimated compliance costs for the MATS rule in the 2012 through 2014 period (in addition to $237 million included in base environmental capital disclosed in the Form 10-K) have been revised from up to $320 million to approximately $440 million as follows:
2012 | 2013 | 2014 | ||||||||
|
||||||||||
(in millions) | ||||||||||
MATS rule |
$ | | $ | $ | 440 | |||||
|
In addition, Georgia Power has further developed its estimated capital expenditures and associated timing of these expenditures to comply with the proposed water and coal combustion byproducts rules, resulting in a reduction, due primarily to timing, in estimated compliance costs for 2012 through 2014. Potential incremental environmental compliance investments to comply with the proposed water and coal combustion byproducts rules have been revised from up to $640 million to approximately $250 million over the 2012 through 2014 period, based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule. These potential incremental environmental compliance investments are estimated as follows:
2012 | 2013 | 2014 | ||||||||
|
||||||||||
(in millions) | ||||||||||
Proposed water and coal combustion byproducts rules |
$5 | $55 | $ | 190 | ||||||
|
While Georgia Powers ultimate costs of compliance with the MATS rule and the proposed water and coal combustion byproducts rules remain uncertain, Georgia Power estimates that compliance costs through 2021 (assuming that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) will be at the low end of the $5 billion to $7 billion range provided in the Form 10-K.
Georgia Powers ultimate compliance strategy and actual future environmental capital expenditures are dependent on a final assessment of the MATS rule and will be affected by the final requirements of new or revised environmental regulations that are promulgated; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and Georgia Powers fuel mix. Compliance costs may arise from retirement and replacement of existing units, installation of additional environmental controls, upgrades to the transmission system, and changing fuel sources for certain existing units. Georgia Powers preliminary analysis further indicates that the short timeframe for compliance with the MATS rule could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters cannot be determined at this time.
As part of SEGCOs environmental compliance strategy, the Board of Directors of SEGCO approved adding natural gas as the primary fuel source in 2015 for its 1,000 MWs of generating capacity and the construction of the necessary natural gas pipeline. SEGCO is jointly owned by Georgia Power and Alabama Power. The capacity of SEGCOs units is sold to Georgia Power and Alabama Power through a PPA. See Note 4 to the financial statements of Georgia Power in Item 8 of the Form 10-K for additional information. The impact of SEGCOs ultimate compliance strategy on the PPA costs cannot be determined at this time; however, if such costs cannot continue to be recovered through retail rates, they could have a material impact on Georgia Powers financial statements.
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Air Quality
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations Air Quality of Georgia Power in Item 7 of the Form 10-K for additional information on the eight-hour ozone and fine particulate matter air quality standards and the MATS rule.
On May 1, 2012, the EPA released its final determination of nonattainment areas based on the 2008 eight-hour ozone air quality standards. The only area within Georgia Powers service territory designated as a nonattainment area was a 15-county area within metropolitan Atlanta. The potential impact of the revised standard and nonattainment designation will depend on further evaluation and implementation by the Georgia Environmental Protection Division and cannot be determined at this time.
On June 14, 2012, the EPA proposed a rule that would increase the stringency of the fine particulate matter national ambient air quality standards. If adopted, the proposed standards could result in the designation of new nonattainment areas within Georgia Powers service territory. As part of a related settlement, the EPA has agreed to finalize the proposed rule by December 14, 2012. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Numerous petitions for administrative reconsideration of the MATS rule, including a petition by Southern Company and its subsidiaries, including Georgia Power, have been filed with the EPA. Challenges to the final rule have also been filed in the U.S. District Court for the District of Columbia by numerous states, environmental organizations, industry groups, and others. The impact of the MATS rule will depend on the outcome of these and any other legal challenges and, therefore, cannot be determined at this time.
Water Quality
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations Water Quality of Georgia Power in Item 7 of the Form 10-K for additional information on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Byproducts
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations Coal Combustion Byproducts of Georgia Power in Item 7 of the Form 10-K for additional information. Environmental groups and other parties have filed lawsuits in the U.S. District Court for the District of Columbia seeking to require the EPA to complete its rulemaking process and issue final regulations pertaining to the regulation of coal combustion byproducts. The ultimate outcome of these matters cannot be determined at this time.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Global Climate Issues
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Global Climate Issues of Georgia Power in Item 7 of the Form 10-K for additional information.
On April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.
On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPAs actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.
PSC Matters
Fuel Cost Recovery
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Fuel Cost Recovery of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under Retail Regulatory Matters Fuel Cost Recovery in Item 8 of the Form 10-K for additional information.
On June 21, 2012, the Georgia PSC approved a decrease in Georgia Powers fuel cost recovery rates of 19%, which reduced annual billings by $567 million effective June 1, 2012. The decrease in fuel costs resulted from lower natural gas prices as a result of increased natural gas supplies.
Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor will not have a significant effect on Georgia Powers revenues or net income, but will affect cash flow. See Note (B) to the Condensed Financial Statements under Retail Regulatory Matters Georgia Power Fuel Cost Recovery herein for additional information.
2011 Integrated Resource Plan Update
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations Air Quality, Water Quality, and Coal Combustion Byproducts of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under Retail Regulatory Matters Rate Plans and 2011 Integrated Resource Plan Update in Item 8 of the Form 10-K for additional information regarding proposed and final EPA rules and regulations, including the MATS rule for coal- and oil-fired electric utility steam generating units, revisions to effluent guidelines for steam electric power plants, and additional regulation of coal combustion byproducts; the State of Georgias Multi-Pollutant Rule; Georgia Powers analysis of the potential costs and benefits of installing the required controls on its fossil generating units in light of these regulations; the 2010 ARP; and the 2011 IRP Update.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On March 20, 2012, the Georgia PSC approved Georgia Powers request to decertify and retire two coal-fired generation units at Plant Branch as of October 31, 2013 and December 31, 2013 and an oil-fired unit at Plant Mitchell as of March 26, 2012, which was included in Georgia Powers 2011 IRP Update. The Georgia PSC also approved three PPAs totaling 998 MWs with Southern Power for capacity and energy that will commence in 2015 and end in 2030. The PPAs remain subject to FERC approval. The ultimate outcome of this matter cannot be determined at this time.
Income Tax Matters
Bonus Depreciation
In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Georgia Power through 2013. Consequently, Georgia Powers positive cash flow benefit is estimated to be between $320 million and $420 million in 2012.
Construction
Nuclear
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Construction Nuclear of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under Construction Nuclear in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4.
On February 16, 2012, a group of petitioners who had intervened in the NRCs combined construction and operating licenses (COLs) proceedings for Plant Vogtle Units 3 and 4 filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review and a stay of the NRCs issuance of the COLs. In addition, on February 16, 2012, another group of petitioners filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review of the NRCs certification of the Westinghouse Design Certification Document, as amended (DCD). On April 3, 2012, the U.S. Court of Appeals for the District of Columbia Circuit granted a motion filed by these two groups of petitioners to consolidate their challenges. On April 18, 2012, another group of petitioners filed a motion to stay the effectiveness of the order issuing the COLs for Plant Vogtle Units 3 and 4 with the U.S. District Court for the District of Columbia. On July 11, 2012, the U.S. Court of Appeals for the District of Columbia Circuit denied the petitioners motion to stay the effectiveness of the COLs. Georgia Power has intervened in and intends to vigorously contest these petitions.
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. In addition, the Georgia PSC voted to approve inclusion of the related CWIP accounts in rate base. Also in 2009, the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that allows Georgia Power to recover financing costs for nuclear construction projects by including the related CWIP accounts in rate base during the construction period. With respect to Plant Vogtle Units 3 and 4, this legislation allows Georgia Power to recover projected financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion. The Georgia PSC has ordered Georgia Power to report against this total certified cost of approximately $6.1 billion. In addition, in December 2010, the Georgia PSC approved Georgia Powers NCCR tariff. The NCCR tariff became effective January 1, 2011 and adjustments are filed with the Georgia PSC on November 1 of each year to become effective on January 1 of the following year. Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs, capitalized in 2009 and 2010, over the five-year period ending December
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
31, 2015, in addition to the ongoing financing costs. At June 30, 2012, approximately $64 million of these 2009 and 2010 costs remained in CWIP.
Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners (collectively, Owners) and Westinghouse and Stone & Webster, Inc. (collectively, Contractor) have established both informal and formal dispute resolution procedures in accordance with the engineering, procurement, and construction agreement to design, engineer, procure, construct, and test two AP1000 nuclear units with electric generating capacity of approximately 1,100 MWs each and related facilities, structures, and improvements at Plant Vogtle entered into by the parties (Vogtle 3 and 4 Agreement) in order to resolve issues arising during the course of constructing a project of this magnitude. The Contractor and Georgia Power (on behalf of the Owners) have successfully initiated both formal and informal claims through these procedures, including ongoing claims, to resolve disputes. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and Georgia Power (on behalf of the Owners) are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.
During the course of construction activities, issues have arisen that may impact the project budget and schedule. The most significant issues relate to costs associated with design changes to the DCD and costs associated with delays in the project schedule related to the timing of approval of the DCD and issuance of the COLs by the NRC. The Owners and the Contractor have begun negotiations regarding these issues, including the assertion by the Contractor that the Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Through correspondence sent to the Owners, the Contractor has provided its proposed adjustment to the contract price and has initiated the formal dispute resolution process. The Contractors estimated adjustment attributable to Georgia Power (based on Georgia Powers ownership interest regarding these issues) is approximately $425 million (in 2008 dollars) with respect to these issues. Georgia Power has not agreed with the amount of these proposed adjustments or that the Owners have responsibility for any costs related to these issues. While the formal dispute resolution process has been initiated, Georgia Power expects negotiations with the Contractor to continue over the next several months with respect to cost and schedule during which time the parties will attempt to reach a mutually acceptable compromise of their positions. Georgia Power intends to vigorously defend its positions. If these costs ultimately are imposed upon the Owners, Georgia Power would seek an amendment to the certified cost of Plant Vogtle Units 3 and 4, if necessary. In connection with these negotiations, the Owners are evaluating whether maintaining the currently scheduled commercial operation dates of 2016 and 2017 remains in the best interest of their customers. Additional claims by the Contractor or Georgia Power (on behalf of the Owners) are expected to arise throughout the construction of Plant Vogtle Units 3 and 4.
In addition, there are processes in place to assure compliance with the design requirements specified in the DCD and the COLs, including rigorous inspection by Southern Nuclear and the NRC that occurs throughout construction. During a routine inspection in April 2012, the NRC identified that certain details of the rebar construction in the Plant Vogtle Unit 3 nuclear island were not consistent with the DCD. In May 2012, Southern Nuclear received an official notice of violation relating to these findings from the NRC. The design changes were determined to have minimal safety significance and, on August 1, 2012, Southern Nuclear filed a license amendment request with the NRC to clarify that the nuclear island concrete and rebar construction will conform to NRC requirements. Various inspection and other issues are expected to arise from time to time as construction proceeds, which may result in additional license amendments or require other resolution.
There are pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, including legal challenges to the NRC issuance of the COLs and certification of the DCD. Similar additional challenges at the state and federal level are expected as construction proceeds.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See RISK FACTORS of Georgia Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.
The ultimate outcome of these matters cannot be determined at this time.
Other Construction
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Construction Other Construction of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under Construction Other Construction in Item 8 of the Form 10-K for additional information.
Plant McDonough Unit 1 was retired on February 29, 2012. Georgia Power placed Plant McDonough-Atkinson Unit 5 into service on April 26, 2012. Plant McDonough-Atkinson Unit 6 is scheduled to be placed into service in November 2012.
Other Matters
Georgia Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Powers business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Georgia Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) herein or in Note 3 to the financial statements of Georgia Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia Powers financial statements.
See the Notes to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Other Matters of Georgia Power in Item 7 of the Form 10-K for additional information regarding the earthquake and tsunami that struck Japan in March 2011. On March 12, 2012, the NRC issued three orders and a request for information based on the NRC task force report recommendations that included, among other items, additional mitigation strategies for beyond-design-basis events, enhanced spent fuel pool instrumentation capabilities, hardened vents for certain classes of containment structures, including the one in use at Plant Hatch, site specific evaluations for seismic and flooding hazards, and various plant evaluations to ensure adequate coping capabilities during station blackout and other conditions. The staff of the NRC expects to issue additional implementation guidance by the end of August 2012. The final form and the resulting impact of any changes to safety requirements for nuclear reactors will be dependent on further review and action by the NRC and cannot be determined at this time. See RISK FACTORS of Georgia Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. The ultimate outcome of these events cannot be determined at this time.
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GEORGIA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Powers results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENTS DISCUSSION AND ANALYSIS ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Powers critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Overview of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Powers financial condition remained stable at June 30, 2012. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See Sources of Capital, Financing Activities, and Capital Requirements and Contractual Obligations herein for additional information.
Net cash provided from operating activities totaled $915 million for the first six months of 2012 compared to $1.01 billion for the corresponding period in 2011. The $96 million decrease was primarily due to lower retail operating revenues, higher fuel inventory additions in 2012, and lower deferred taxes due to the effect of bonus depreciation in 2011, partially offset by higher recovery of retail fuel costs. Net cash used for investing activities totaled $1.2 billion primarily due to gross property additions to utility plant together with a net increase in restricted cash of $185 million in the first six months of 2012. Net cash provided from financing activities totaled $468 million for the first six months of 2012 compared to $77 million used for financing activities in the corresponding period in 2011. The $545 million increase is primarily due to increased debt issuances in 2012.
Significant balance sheet changes for the first six months of 2012 include increases of $442 million in total property, plant, and equipment, $147 million in fossil fuel stock, $552 million in long-term debt, and $185 million in restricted cash, as well as a $236 million change in under/over recovered fuel.
Capital Requirements and Contractual Obligations
See MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Capital Requirements and Contractual Obligations of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Powers capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $1.3 billion will be required through June 30, 2013 to fund maturities of long-term debt.
See FUTURE EARNINGS POTENTIAL Environmental Statutes and Regulations General herein for a description of Georgia Powers estimated capital expenditures to comply with the MATS rule and proposed water and coal combustion byproducts rules.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On March 20, 2012, the Georgia PSC approved three PPAs totaling 998 MWs with Southern Power for capacity and energy that will commence in 2015 and end in 2030. However, these PPAs remain subject to FERC approval. See FUTURE EARNINGS POTENTIAL PSC Matters 2011 Integrated Resource Plan Update herein for additional information. These PPAs will be accounted for as leases and are expected to result in additional obligations of approximately $56 million in 2015, $66 million in 2016, and a total of $973 million thereafter. The ultimate outcome of this matter cannot be determined at this time.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet new regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Except as described below with respect to potential DOE loan guarantees, Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, security issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Sources of Capital of Georgia Power in Item 7 of the Form 10-K for additional information.
In June 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future borrowings by Georgia Power related to the construction of Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Powers 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of 70% of eligible project costs, or approximately $3.46 billion, and are expected to be funded by the Federal Financing Bank. Final approval and issuance of loan guarantees by the DOE are subject to negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. In the event that the DOE does not issue a loan guarantee or Georgia Power determines that the final terms and conditions of the loan guarantee by the DOE are not in the best interest of its customers, Georgia Power expects to finance the construction of Plant Vogtle Units 3 and 4 through traditional capital markets financings. There can be no assurance that the DOE will issue loan guarantees for Georgia Power. See FUTURE EARNINGS POTENTIAL Construction Nuclear herein for more information on Plant Vogtle Units 3 and 4.
Georgia Powers current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business.
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GEORGIA POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At June 30, 2012, Georgia Power had approximately $188 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2012, including expiration dates, were as follows:
Expires |
Executable Term Loans |
Due Within One Year(a) | ||||||||||||||
2012 | 2013 | 2014 and Beyond |
Total | Unused | One Year | Two Years | Term Out | No Term Out | ||||||||
|
|
|
| |||||||||||||
(in millions) | (in millions) | (in millions) | (in millions) | |||||||||||||
$ |
$ | $1,750 | $1,750 | $1,745 | $ | $ | $ | $ |
(a) | Reflects facilities expiring on or before June 30, 2013. |
See Note 6 to the financial statements of Georgia Power under Bank Credit Arrangements in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under Bank Credit Arrangements herein for additional information.
Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of Georgia Power. Georgia Power is currently in compliance with all such covenants. Georgia Power expects to renew its credit arrangements, as needed, prior to expiration. These credit arrangements provide liquidity support to Georgia Powers commercial paper borrowings and variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2012 was approximately $868 million.
Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each traditional operating company under these arrangements are several and there is no cross affiliate credit support.
Georgia Power had no short-term debt outstanding as of June 30, 2012. Details of short-term borrowings during the period, excluding $2 million of notes payable related to other energy service contracts, were as follows:
Short-term Debt During the Period (a) | ||||||
Average Outstanding |
Weighted Average Interest Rate |
Maximum Amount Outstanding | ||||
|
| |||||
(in millions) | (in millions) | |||||
June 30, 2012: |
||||||
Commercial paper |
$ 85 | 0.3% | $ 312 | |||
Short-term bank debt |
175 | 1.1% | 300 | |||
|
||||||
Total |
$ 260 | 1.0% | ||||
|
(a) | Average and maximum amounts are based upon daily balances during the period. |
Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Credit Rating Risk
Georgia Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, and construction of new generation. The maximum potential collateral requirements under these contracts at June 30, 2012 were as follows:
Credit Ratings | Maximum Potential Collateral Requirements | |
| ||
(in millions) | ||
At BBB- and/or Baa3 |
$ 65 | |
Below BBB- and/or Baa3 |
1,316 | |
|
Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Georgia Powers ability to access capital markets, particularly the short-term debt market.
Market Price Risk
Georgia Powers market risk exposure relative to interest rate changes for the second quarter 2012 has not changed materially compared with the December 31, 2011 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Georgia Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Due to cost-based rate regulation and other various cost recovery mechanisms, Georgia Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Georgia Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. Georgia Power continues to manage a fuel-hedging program implemented per the guidelines of the Georgia PSC. As such, Georgia Power had no material change in market risk exposure for the second quarter 2012 relative to fuel and electricity prices when compared with the December 31, 2011 reporting period.
The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three and six months ended June 30, 2012 were as follows:
Second Quarter 2012 Changes |
Year-to-Date 2012 Changes | |||
Fair Value | ||||
(in millions) | ||||
Contracts outstanding at the beginning of the period, assets (liabilities), net |
$(86) | $(82) | ||
Contracts realized or settled |
26 | 44 | ||
Current period changes(a) |
2 | (20) | ||
| ||||
Contracts outstanding at the end of the period, assets (liabilities), net |
$(58) | $(58) | ||
|
(a) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The changes in the fair value positions of the energy-related derivative contracts, which are substantially all attributable to both the volume and the price of natural gas, for the three and six months ended June 30, 2012 were as follows:
Second Quarter 2012 Changes |
Year-to-Date 2012 Changes |
|||||||
|
||||||||
Fair Value | ||||||||
(in millions) | ||||||||
Natural gas swaps |
$ 22 | $ 26 | ||||||
Natural gas options |
6 | (2) | ||||||
Other energyrelated derivatives |
| | ||||||
|
||||||||
Total changes |
$ 28 | $ 24 | ||||||
|
The net hedge volumes of energy-related derivative contracts were as follows:
June 30, 2012 |
March 31, 2012 |
December 31, 2011 | ||||
| ||||||
mmBtu Volume | ||||||
(in millions) | ||||||
CommodityNatural gas swaps |
23 | 25 | 29 | |||
CommodityNatural gas options |
73 | 60 | 44 | |||
| ||||||
Total hedge volume |
96 | 85 | 73 | |||
|
The weighted average swap contract cost above market prices was approximately $1.37 per mmBtu as of June 30, 2012, $2.13 per mmBtu as of March 31, 2012, and $1.65 per mmBtu as of December 31, 2011. The change in option premiums is primarily attributable to the volatility of the market and the underlying change in the natural gas price. All natural gas hedge gains and losses are recovered through Georgia Powers fuel cost recovery mechanism.
Regulatory hedges relate to Georgia Powers fuel-hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through Georgia Powers fuel cost recovery mechanism.
Unrealized pre-tax gains and losses recognized in income for the three and six months ended June 30, 2012 and 2011 for energy-related derivative contracts that are not hedges were not material.
Georgia Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at June 30, 2012 were as follows:
June 30, 2012 Fair Value Measurements | ||||||
| ||||||
Total | Maturity | |||||
Fair Value | Year 1 | Years 2&3 | ||||
| ||||||
(in millions) | ||||||
Level 1 |
$ | $ | $ | |||
Level 2 |
(58) | (40) | (18) | |||
Level 3 |
| | | |||
| ||||||
Fair value of contracts outstanding at end of period |
$(58) | $(40) | $(18) | |||
|
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Georgia Power. Regulations to implement the Dodd-Frank Act will impose additional requirements on the use of over-the-counter derivatives for both Georgia Power and its derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Georgia Power does not expect the impact of these rules to be material.
For additional information, see MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Market Price Risk of Georgia Power in Item 7 and Note 1 under Financial Instruments and Note 11 to the financial statements of Georgia Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
In January 2012, Georgia Power entered into a six-month floating rate bank loan in an aggregate amount of $100 million, bearing interest based on one-month LIBOR. The proceeds were used for general corporate purposes, including Georgia Powers continuous construction program.
In March 2012 and May 2012, Georgia Power issued $750 million and $350 million, respectively, aggregate principal amount of Series 2012A 4.30% Senior Notes due March 15, 2042. Also in May 2012, Georgia Power issued $400 million aggregate principal amount of Series 2012B 2.85% Senior Notes due May 15, 2022. The net proceeds from the sale of the Series 2012B Senior Notes, together with the net proceeds from the sale of the Series 2012A Senior Notes, were used by Georgia Power to repay a portion of Georgia Powers short-term debt and bank loans, for the redemption in July 2012 of $300 million aggregate principal amount of Georgia Powers Series 2007D 6.375% Senior Notes due July 15, 2047, and for general corporate purposes, including Georgia Powers continuous construction program.
In May 2012, the Development Authority of Monroe County issued $48.72 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2012, for the benefit of Georgia Power. The proceeds were used to redeem in June 2012 the $48.72 million aggregate principal amount of Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2006.
In June 2012, the Development Authority of Burke County issued $85 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2012 and $100 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2012 for the benefit of Georgia Power. The proceeds were used to redeem in July 2012 the $85 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2005 and the $100 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2005.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Georgia Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
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CONDENSED STATEMENTS OF INCOME (UNAUDITED)
For the Three Months Ended June 30, |
For the Six Months Ended June 30, |
|||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in thousands) | (in thousands) | |||||||||||||||
Operating Revenues: |
||||||||||||||||
Retail revenues |
$ | 294,878 | $ | 320,474 | $ | 533,398 | $ | 595,300 | ||||||||
Wholesale revenues, non-affiliates |
28,729 | 38,874 | 55,847 | 69,893 | ||||||||||||
Wholesale revenues, affiliates |
28,702 | 22,857 | 65,066 | 26,992 | ||||||||||||
Other revenues |
17,899 | 17,060 | 32,142 | 31,688 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total operating revenues |
370,208 | 399,265 | 686,453 | 723,873 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Operating Expenses: |
||||||||||||||||
Fuel |
141,220 | 178,686 | 262,308 | 310,468 | ||||||||||||
Purchased power, non-affiliates |
12,085 | 10,889 | 23,310 | 17,892 | ||||||||||||
Purchased power, affiliates |
5,210 | 12,549 | 7,723 | 29,167 | ||||||||||||
Other operations and maintenance |
79,779 | 72,583 | 155,009 | 153,092 | ||||||||||||
Depreciation and amortization |
35,173 | 32,304 | 68,480 | 64,060 | ||||||||||||
Taxes other than income taxes |
25,276 | 24,867 | 49,060 | 49,763 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total operating expenses |
298,743 | 331,878 | 565,890 | 624,442 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Operating Income |
71,465 | 67,387 | 120,563 | 99,431 | ||||||||||||
Other Income and (Expense): |
||||||||||||||||
Allowance for equity funds used during construction |
1,736 | 2,522 | 2,973 | 4,657 | ||||||||||||
Interest income |
1,809 | 20 | 1,396 | 34 | ||||||||||||
Interest expense, net of amounts capitalized |
(15,698 | ) | (14,423 | ) | (31,066 | ) | (28,052 | ) | ||||||||
Other income (expense), net |
(697 | ) | (447 | ) | (1,293 | ) | (1,010 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other income and (expense) |
(12,850 | ) | (12,328 | ) | (27,990 | ) | (24,371 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Earnings Before Income Taxes |
58,615 | 55,059 | 92,573 | 75,060 | ||||||||||||
Income taxes |
22,102 | 20,157 | 33,843 | 26,916 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net Income |
36,513 | 34,902 | 58,730 | 48,144 | ||||||||||||
Dividends on Preference Stock |
1,550 | 1,550 | 3,101 | 3,101 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net Income After Dividends on Preference Stock |
$ | 34,963 | $ | 33,352 | $ | 55,629 | $ | 45,043 | ||||||||
|
|
|
|
|
|
|
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
For the Three Months Ended June 30, |
For the Six Months Ended June 30, |
|||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in thousands) | (in thousands) | |||||||||||||||
Net Income After Dividends on Preference Stock |
$ | 34,963 | $ | 33,352 | $ | 55,629 | $ | 45,043 | ||||||||
Other comprehensive income (loss): |
||||||||||||||||
Qualifying hedges: |
||||||||||||||||
Reclassification adjustment for amounts included in net income, net of tax of $90, $90, $180 and $180, respectively |
143 | 144 | 286 | 287 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other comprehensive income (loss) |
143 | 144 | 286 | 287 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Comprehensive Income |
$ | 35,106 | $ | 33,496 | $ | 55,915 | $ | 45,330 | ||||||||
|
|
|
|
|
|
|
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
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Table of Contents
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
For the Six Months Ended June 30, |
||||||||
2012 | 2011 | |||||||
(in thousands) | ||||||||
Operating Activities: |
||||||||
Net income |
$ | 58,730 | $ | 48,144 | ||||
Adjustments to reconcile net income to net cash provided from operating activities |
||||||||
Depreciation and amortization, total |
71,707 | 67,129 | ||||||
Deferred income taxes |
70,153 | 20,411 | ||||||
Allowance for equity funds used during construction |
(2,973 | ) | (4,657 | ) | ||||
Pension, postretirement, and other employee benefits |
2,383 | (993 | ) | |||||
Stock based compensation expense |
1,044 | 789 | ||||||
Other, net |
7,503 | (3,496 | ) | |||||
Changes in certain current assets and liabilities |
||||||||
-Receivables |
(18,580 | ) | (33,496 | ) | ||||
-Prepayments |
1,813 | 1,373 | ||||||
-Fossil fuel stock |
3,982 | 21,458 | ||||||
-Materials and supplies |
(4,100 | ) | (4,088 | ) | ||||
-Prepaid income taxes |
(3,566 | ) | 35,287 | |||||
-Other current assets |
| 23 | ||||||
-Accounts payable |
(17,481 | ) | (1,710 | ) | ||||
-Accrued taxes |
6,788 | 28,851 | ||||||
-Accrued compensation |
(6,239 | ) | (6,132 | ) | ||||
-Over recovered regulatory clause revenues |
25,099 | 4,027 | ||||||
-Other current liabilities |
(1,659 | ) | 2,274 | |||||
|
|
|
|
|||||
Net cash provided from operating activities |
194,604 | 175,194 | ||||||
|
|
|
|
|||||
Investing Activities: |
||||||||
Property additions |
(169,462 | ) | (168,986 | ) | ||||
Cost of removal, net of salvage |
(14,817 | ) | (6,616 | ) | ||||
Change in construction payables |
3,661 | (31 | ) | |||||
Payments pursuant to long-term service agreements |
(4,086 | ) | (4,162 | ) | ||||
Other investing activities |
18 | 222 | ||||||
|
|
|
|
|||||
Net cash used for investing activities |
(184,686 | ) | (179,573 | ) | ||||
|
|
|
|
|||||
Financing Activities: |
||||||||
Increase in notes payable, net |
5,980 | 1,392 | ||||||
Proceeds |
||||||||
Common stock issued to parent |
40,000 | 50,000 | ||||||
Capital contributions from parent company |
954 | 1,014 | ||||||
Senior notes |
100,000 | 125,000 | ||||||
Redemptions |
||||||||
Senior notes |
(91,363 | ) | (352 | ) | ||||
Other long-term debt |
| (110,000 | ) | |||||
Payment of preference stock dividends |
(3,101 | ) | (3,101 | ) | ||||
Payment of common stock dividends |
(57,900 | ) | (55,000 | ) | ||||
Other financing activities |
(653 | ) | (3,679 | ) | ||||
|
|
|
|
|||||
Net cash provided from (used for) financing activities |
(6,083 | ) | 5,274 | |||||
|
|
|
|
|||||
Net Change in Cash and Cash Equivalents |
3,835 | 895 | ||||||
Cash and Cash Equivalents at Beginning of Period |
17,328 | 16,434 | ||||||
|
|
|
|
|||||
Cash and Cash Equivalents at End of Period |
$ | 21,163 | $ | 17,329 | ||||
|
|
|
|
|||||
Supplemental Cash Flow Information: |
||||||||
Cash paid (received) during the period for |
||||||||
Interest (net of $1,185 and $1,856 capitalized for 2012 and 2011, respectively) |
$ | 30,100 | $ | 26,288 | ||||
Income taxes, net |
(32,848 | ) | (46,824 | ) | ||||
Noncash transactions accrued property additions at end of period |
27,127 | 14,924 |
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
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Table of Contents
CONDENSED BALANCE SHEETS (UNAUDITED)
Assets |
At June 30, 2012 |
At December 31, 2011 |
||||||
(in thousands) | ||||||||
Current Assets: |
||||||||
Cash and cash equivalents |
$ | 21,163 | $ | 17,328 | ||||
Receivables |
||||||||
Customer accounts receivable |
83,682 | 72,754 | ||||||
Unbilled revenues |
57,575 | 49,921 | ||||||
Under recovered regulatory clause revenues |
4,070 | 5,530 | ||||||
Other accounts and notes receivable |
10,819 | 13,350 | ||||||
Affiliated companies |
15,189 | 14,844 | ||||||
Accumulated provision for uncollectible accounts |
(1,463 | ) | (1,962 | ) | ||||
Fossil fuel stock, at average cost |
143,588 | 147,567 | ||||||
Materials and supplies, at average cost |
53,881 | 49,781 | ||||||
Other regulatory assets, current |
35,670 | 35,849 | ||||||
Prepaid expenses |
71,492 | 28,327 | ||||||
Other current assets |
1,523 | 2,051 | ||||||
|
|
|
|
|||||
Total current assets |
497,189 | 435,340 | ||||||
|
|
|
|
|||||
Property, Plant, and Equipment: |
||||||||
In service |
4,130,575 | 3,846,446 | ||||||
Less accumulated provision for depreciation |
1,154,842 | 1,124,291 | ||||||
|
|
|
|
|||||
Plant in service, net of depreciation |
2,975,733 | 2,722,155 | ||||||
Construction work in progress |
158,639 | 287,173 | ||||||
|
|
|
|
|||||
Total property, plant, and equipment |
3,134,372 | 3,009,328 | ||||||
|
|
|
|
|||||
Other Property and Investments |
16,377 | 16,394 | ||||||
|
|
|
|
|||||
Deferred Charges and Other Assets: |
||||||||
Deferred charges related to income taxes |
50,696 | 48,210 | ||||||
Other regulatory assets, deferred |
332,325 | 323,116 | ||||||
Other deferred charges and assets |
27,567 | 39,493 | ||||||
|
|
|
|
|||||
Total deferred charges and other assets |
410,588 | 410,819 | ||||||
|
|
|
|
|||||
Total Assets |
$ | 4,058,526 | $ | 3,871,881 | ||||
|
|
|
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
85
Table of Contents
GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholders Equity |
At June 30, 2012 |
At December 31, 2011 |
||||||
(in thousands) | ||||||||
Current Liabilities: |
||||||||
Notes payable |
$ | 116,907 | $ | 114,507 | ||||
Accounts payable |
||||||||
Affiliated |
58,897 | 54,874 | ||||||
Other |
50,348 | 63,265 | ||||||
Customer deposits |
36,028 | 35,779 | ||||||
Accrued taxes |
||||||||
Accrued income taxes |
68 | 1,362 | ||||||
Other accrued taxes |
20,147 | 12,114 | ||||||
Accrued interest |
11,911 | 14,018 | ||||||
Accrued compensation |
8,245 | 14,485 | ||||||
Other regulatory liabilities, current |
56,999 | 35,639 | ||||||
Liabilities from risk management activities |
20,485 | 22,786 | ||||||
Other current liabilities |
23,880 | 22,916 | ||||||
|
|
|
|
|||||
Total current liabilities |
403,915 | 391,745 | ||||||
|
|
|
|
|||||
Long-term Debt |
1,245,567 | 1,235,447 | ||||||
|
|
|
|
|||||
Deferred Credits and Other Liabilities: |
||||||||
Accumulated deferred income taxes |
559,600 | 458,978 | ||||||
Accumulated deferred investment tax credits |
6,084 | 6,760 | ||||||
Employee benefit obligations |
109,200 | 109,740 | ||||||
Other cost of removal obligations |
212,981 | 214,598 | ||||||
Other regulatory liabilities, deferred |
47,229 | 44,843 | ||||||
Other deferred credits and liabilities |
209,965 | 186,824 | ||||||
|
|
|
|
|||||
Total deferred credits and other liabilities |
1,145,059 | 1,021,743 | ||||||
|
|
|
|
|||||
Total Liabilities |
2,794,541 | 2,648,935 | ||||||
|
|
|
|
|||||
Preference Stock |
97,998 | 97,998 | ||||||
|
|
|
|
|||||
Common Stockholder's Equity: |
||||||||
Common stock, without par value |
||||||||
Authorized 20,000,000 shares |
||||||||
Outstanding June 30, 2012: 4,542,717 shares |
||||||||
December 31, 2011: 4,142,717 shares |
393,060 | 353,060 | ||||||
Paid-in capital |
545,733 | 542,709 | ||||||
Retained earnings |
229,062 | 231,333 | ||||||
Accumulated other comprehensive loss |
(1,868 | ) | (2,154 | ) | ||||
|
|
|
|
|||||
Total common stockholders equity |
1,165,987 | 1,124,948 | ||||||
|
|
|
|
|||||
Total Liabilities and Stockholders Equity |
$ | 4,058,526 | $ | 3,871,881 | ||||
|
|
|
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
86
Table of Contents
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SECOND QUARTER 2012 vs. SECOND QUARTER 2011
AND
YEAR-TO-DATE 2012 vs. YEAR-TO-DATE 2011
OVERVIEW
Gulf Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service territory located in northwest Florida and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Gulf Powers business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel prices, and storm restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future.
On March 12, 2012, the Florida PSC approved a permanent increase in retail base rates and charges of $64 million effective April 11, 2012. The amount of the permanent increase includes the previously approved $38.5 million interim retail rate increase implemented in September 2011. The Florida PSCs decision on the amount of the permanent increase also included a determination that none of the base rate revenues collected on an interim basis would be refunded. Gulf Powers authorized retail ROE is a range of 9.25% to 11.25% with new retail base rates set at the midpoint retail ROE of 10.25%. In addition, the Florida PSC also approved a step increase to Gulf Powers retail base rates and charges of $4 million to be effective in January 2013. On April 18, 2012, Gulf Power filed a motion to reconsider one aspect of the decision dealing with property acquired as a potential site for a future generating plant. On July 17, 2012, the Florida PSC denied Gulf Powers motion and reaffirmed its earlier decision.
Gulf Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. For additional information on these indicators, see MANAGEMENTS DISCUSSION AND ANALYSIS OVERVIEW Key Performance Indicators of Gulf Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$1.6 |
4.8 | $10.6 | 23.5 | |||
|
Gulf Powers net income after dividends on preference stock for the second quarter 2012 was $35.0 million compared to $33.4 million for the corresponding period in 2011. The increase was primarily due to higher retail base revenues resulting from the retail base rate increase effective April 11, 2012, partially offset by an increase in operations and maintenance expenses in 2012 and a decrease in retail energy sales in 2012 due to a decrease in customer usage.
Gulf Powers net income after dividends on preference stock for year-to-date 2012 was $55.6 million compared to $45.0 million for the corresponding period in 2011. The increase was primarily due to higher retail base revenues resulting from the retail base rate increase effective April 11, 2012, an increase related to retail interim revenues, and higher wholesale capacity revenues from non-affiliates in 2012. These increases were partially offset by milder weather in 2012 and a decrease in retail energy sales in 2012 due to a decrease in customer usage.
87
Table of Contents
GULF POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(25.6) |
(8.0) | $(61.9) | (10.4) | |||
|
In the second quarter 2012, retail revenues were $294.9 million compared to $320.5 million for the corresponding period in 2011. For year-to-date 2012, retail revenues were $533.4 million compared to $595.3 million for the corresponding period in 2011.
Details of the change to retail revenues were as follows:
Second Quarter 2012 |
Year-to-Date 2012 | |||||||
| ||||||||
(in millions) | (% change) | (in millions) | (% change) | |||||
Retail prior year |
$ 320.5 | $ 595.3 | ||||||
Estimated change in |
||||||||
Rates and pricing |
19.7 | 6.1 | 32.2 | 5.4 | ||||
Sales growth (decline) |
(6.5) | (2.0) | (5.3) | (0.9) | ||||
Weather |
(0.3) | (0.1) | (8.6) | (1.4) | ||||
Fuel and other cost recovery |
(38.5) | (12.0) | (80.2) | (13.5) | ||||
| ||||||||
Retail current year |
$ 294.9 | (8.0)% | $ 533.4 | (10.4)% | ||||
|
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under Revenues and Note 3 to the financial statements of Gulf Power under Retail Regulatory Matters in Item 8 of the Form 10-K for additional information regarding Gulf Powers retail base rate case and cost recovery clauses, including Gulf Powers fuel cost recovery, purchased power capacity recovery, environmental cost recovery, and energy conservation cost recovery.
Revenues associated with changes in rates and pricing increased in the second quarter 2012 when compared to the corresponding period in 2011 primarily due to higher retail base revenues resulting from the retail base rate increase effective April 11, 2012 and revenues associated with higher recoverable costs under Gulf Powers energy conservation cost recovery clause. These increases were partially offset by revenues associated with lower recoverable costs under Gulf Powers environmental cost recovery clause.
Revenues associated with changes in rates and pricing increased year-to-date 2012 when compared to the corresponding period in 2011 primarily due to higher retail base revenues resulting from the retail base rate increase effective April 11, 2012, an increase related to retail interim revenues, and revenues associated with higher recoverable costs under Gulf Powers energy conservation cost recovery clause. These increases were partially offset by revenues associated with lower recoverable costs under Gulf Powers environmental cost recovery clause.
Revenues attributable to changes in sales decreased in the second quarter 2012 when compared to the corresponding period in 2011. Weather-adjusted KWH energy sales to residential and commercial customers decreased primarily due to lower use per customer. KWH energy sales to industrial customers decreased 9.0% primarily due to increased customer co-generation due to the lower cost of natural gas in 2012 and changes in customer production levels.
Revenues attributable to changes in sales decreased year-to-date 2012 when compared to the corresponding period in 2011. Weather-adjusted KWH energy sales to residential and commercial customers decreased 1.8% and 1.9%, respectively, due to lower use per customer. KWH energy sales to industrial customers decreased 8.0% primarily due to increased customer co-generation due to the lower cost of natural gas in 2012 and changes in customer production levels.
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Table of Contents
GULF POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Revenues attributable to changes in weather decreased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 due to milder weather in 2012.
Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 primarily due to lower revenues associated with recoverable fuel cost for generation and purchased power energy costs in addition to fewer KWH energy sales. Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and the difference between projected and actual costs and revenues related to energy conservation and environmental compliance. See FUTURE EARNINGS POTENTIAL PSC Matters Cost Recovery Clauses Fuel Cost Recovery herein for additional information.
Wholesale Revenues Non-Affiliates
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(10.2) |
(26.1) | $(14.1) | (20.1) | |||
|
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Gulf Powers and the Southern Company systems generation, demand for energy within the Southern Company systems service territory, and availability of the Southern Company systems generation. Wholesale revenues from non-affiliates include unit power sales under long-term contracts to other utilities in Florida and Georgia. Wholesale revenues from these contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost.
In the second quarter 2012, wholesale revenues from non-affiliates were $28.7 million compared to $38.9 million for the corresponding period in 2011. The decrease was primarily due to lower energy revenues related to a 53.0% decrease in KWH sales as a result of less energy scheduled by unit power customers.
For year-to-date 2012, wholesale revenues from non-affiliates were $55.8 million compared to $69.9 million for the corresponding period in 2011. The decrease was primarily due to lower energy revenues related to a 55.5% decrease in KWH sales as a result of less energy scheduled by unit power customers, partially offset by a 14.3% increase in capacity revenues related to higher capacity rates resulting from change-in-law contract provisions that provide for recovery of costs related to the generating resources compliance with new environmental requirements.
Wholesale Revenues Affiliates
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$5.8 |
25.6 | $38.1 | 141.1 | |||
|
Wholesale revenues from sales to affiliated companies within the Southern Company system will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the fuel revenue related to energy sales and the cost of energy purchases are both included in the determination of recoverable fuel costs and are generally offset by revenues collected in Gulf Powers fuel cost recovery clause.
In the second quarter 2012, wholesale revenues from affiliates were $28.7 million compared to $22.9 million for the corresponding period in 2011. The increase was primarily due to higher energy revenues related to a 116.2% increase in KWH energy sales resulting from the availability of Gulf Powers lower priced natural gas resources to serve affiliate demand.
89
Table of Contents
GULF POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2012, wholesale revenues from affiliates were $65.1 million compared to $27.0 million for the corresponding period in 2011. The increase was primarily due to higher energy revenues related to a 327.0% increase in KWH energy sales resulting from the availability of Gulf Powers lower priced natural gas resources to serve affiliate demand.
Fuel and Purchased Power Expenses
Second Quarter 2012 vs. Second Quarter 2011 |
Year-to-Date 2012 vs. Year-to-Date 2011 | |||||||
| ||||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||||
Fuel |
$ (37.5) | (21.0) | $ (48.2) | (15.5) | ||||
Purchased power non-affiliates |
1.2 | 11.0 | 5.4 | 30.3 | ||||
Purchased power affiliates |
(7.3) | (58.5) | (21.5) | (73.5) | ||||
|
|
|||||||
Total fuel and purchased power expenses |
$ (43.6) | $ (64.3) | ||||||
|
|
In the second quarter 2012, total fuel and purchased power expenses were $158.5 million compared to $202.1 million for the corresponding period in 2011. The decrease in fuel and purchased power expenses was primarily due to a $47.2 million decrease in the average cost of generated and purchased power and a $28.8 million decrease related to the volume of KWHs generated, partially offset by a $32.4 million increase related to the volume of KWHs purchased.
For year-to-date 2012, total fuel and purchased power expenses were $293.3 million compared to $357.6 million for the corresponding period in 2011. The decrease in fuel and purchased power expenses was primarily due to a $109.9 million decrease in the average cost of generated and purchased power and a $53.4 million decrease related to the volume of KWHs generated, partially offset by a $99.0 million increase related to the volume of KWHs purchased.
Fuel and purchased power transactions do not have a significant impact on earnings since energy and purchased power expenses are generally offset by energy and capacity revenues through Gulf Powers fuel cost and purchased power capacity recovery clauses. See FUTURE EARNINGS POTENTIAL PSC Matters Cost Recovery Clauses Fuel Cost Recovery and Purchased Power Capacity Recovery herein for additional information.
Details of Gulf Powers generation and purchased power were as follows:
Second Quarter 2012 |
Second Quarter 2011 |
Year-to-Date 2012 |
Year-to-Date 2011 | |||||
| ||||||||
Total generation (millions of KWHs) |
2,650 | 3,229 | 4,991 | 6,031 | ||||
Total purchased power (millions of KWHs) |
1,609 | 947 | 3,360 | 1,395 | ||||
| ||||||||
Sources of generation (percent) |
||||||||
Coal |
66 | 72 | 60 | 70 | ||||
Gas |
34 | 28 | 40 | 30 | ||||
| ||||||||
Cost of fuel, generated (cents per net KWH) |
||||||||
Coal |
4.34 | 5.00 | 4.32 | 5.01 | ||||
Gas |
4.27 | 4.37 | 3.81 | 4.18 | ||||
| ||||||||
Average cost of fuel, generated (cents per net KWH) |
4.32 | 4.82 | 4.12 | 4.76 | ||||
Average cost of purchased power (cents per net KWH)(a) |
2.74 | 4.89 | 2.61 | 5.05 | ||||
|
(a) | Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider. |
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GULF POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel
In the second quarter 2012, fuel expense was $141.2 million compared to $178.7 million for the corresponding period in 2011. The decrease was primarily due to a higher utilization of lower cost natural gas-fired sources, a 2.3% decrease in the average cost of natural gas per KWH generated, and a 17.9% decrease in KWHs generated as a result of displacement of coal-fired generation by energy purchases. These decreases were partially offset by a 69.9% increase in KWHs purchased.
For year-to-date 2012, fuel expense was $262.3 million compared to $310.5 million for the corresponding period in 2011. The decrease was primarily due to a higher utilization of lower cost natural gas-fired sources, an 8.9% decrease in the average cost of natural gas per KWH generated, and a 17.3% decrease in KWHs generated as a result of displacement of coal-fired generation by energy purchases. These decreases were partially offset by a 140.8% increase in KWHs purchased.
In the second quarter and year-to-date 2012, the decrease in the average cost of fuel was a result of decreases in the average costs of natural gas and coal per KWH generated and a higher percentage of utilization of Gulf Powers lower cost natural gas-fired generation sources.
Purchased Power Non-Affiliates
In the second quarter 2012, purchased power expense from non-affiliates was $12.1 million compared to $10.9 million for the corresponding period in 2011. The increase was primarily due to a $1.2 million increase in energy costs resulting from a 119% increase in KWHs purchased as the cost through third party PPAs was lower than the cost of available Gulf Power-owned generation.
For year-to-date 2012, purchased power expense from non-affiliates was $23.3 million compared to $17.9 million for the corresponding period in 2011. The increase was primarily due to a $5.4 million increase in energy costs resulting from a 316% increase in KWHs purchased as the cost through third party PPAs was lower than the cost of available Gulf Power-owned generation.
In the second quarter 2012, the average cost of purchased power from non-affiliates was 2.5 cents per net KWH compared to 4.7 cents per net KWH for the corresponding period in 2011. For year-to-date 2012, the average cost of purchased power from non-affiliates was 2.4 cents per net KWH compared to 5.2 cents per net KWH for the corresponding period in 2011. The decreases were primarily the result of a decrease in the average cost of natural gas.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company systems generation, demand for energy within the Southern Company systems service territory, and the availability of the Southern Company systems generation.
Purchased Power Affiliates
In the second quarter 2012, purchased power expense from affiliates was $5.2 million compared to $12.5 million for the corresponding period in 2011. The decrease was primarily due to a 72.7% decrease in the volume of KWHs purchased.
For year-to-date 2012, purchased power expense from affiliates was $7.7 million compared to $29.2 million for the corresponding period in 2011. The decrease was primarily due to an 86.1% decrease in the volume of KWHs purchased.
In the second quarter 2012, the average cost of purchased power from affiliates was 8.7 cents per net KWH compared to 5.4 cents per net KWH for the corresponding period in 2011. For year-to-date 2012, the average cost of purchased power from affiliates was 9.9 cents per net KWH compared to 4.9 cents per net KWH for the corresponding period in 2011.
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The increases were primarily due to comparable total capacity costs for fewer KWHs purchased, partially offset by lower energy costs per KWHs.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$7.2 | 9.9 | $1.9 | 1.3 | |||
|
In the second quarter 2012, other operations and maintenance expenses were $79.8 million compared to $72.6 million for the corresponding period in 2011. The increase was primarily due to increases of $3.3 million for labor and benefit-related expenses, $2.0 million in marketing programs, $1.1 million in routine and planned outage maintenance expense at generation facilities, and $1.1 million in other energy services projects. The increased expense from energy service projects did not have a material impact on earnings since it was offset by associated revenues.
For year-to-date 2012, other operations and maintenance expenses were $155.0 million compared to $153.1 million for the corresponding period in 2011. The increase was primarily due to increases of $6.7 million for labor and benefit-related expenses, $3.4 million in marketing programs, and $1.8 million in other energy services projects, partially offset by a $10.2 million decrease in routine and planned outage maintenance expense at generation facilities. The increased expense from energy service projects did not have a material impact on earnings since it was offset by associated revenues.
Depreciation and Amortization
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$2.9 | 8.9 | $4.4 | 6.9 | |||
|
In the second quarter 2012, depreciation and amortization was $35.2 million compared to $32.3 million for the corresponding period in 2011. For year-to-date 2012, depreciation and amortization was $68.5 million compared to $64.1 million for the corresponding period in 2011. The increases were primarily due to additions of environmental control projects at generation facilities and net additions to transmission and distribution facilities.
Allowance for Equity Funds Used During Construction
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(0.8) | (31.2) | $(1.7) | (36.2) | |||
|
In the second quarter 2012, AFUDC equity was $1.7 million compared to $2.5 million for the corresponding period in 2011. The decrease was primarily due to an environmental control project at Plant Crist being placed into service in the second quarter 2012.
For year-to-date 2012, AFUDC equity was $3.0 million compared to $4.7 million for the corresponding period in 2011. The decrease was primarily due to an adjustment related to deferred future generation carrying costs, partially offset by increases related to construction of environmental control projects at generating facilities.
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Interest Income
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$1.8 | N/M | $1.4 | N/M | |||
|
N/M Not meaningful
In the second quarter and year-to-date 2012, interest income was $1.8 million and $1.4 million, respectively. The amounts for the corresponding periods in 2011 were immaterial. The increases were primarily due to an IRS refund of interest claims for multiple tax years.
Interest Expense, Net of Amounts Capitalized
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$1.3 | 8.8 | $3.0 | 10.7 | |||
|
In the second quarter 2012, interest expense, net of amounts capitalized was $15.7 million compared to $14.4 million for the corresponding period in 2011. For year-to-date 2012, interest expense, net of amounts capitalized was $31.1 million compared to $28.1 million for the corresponding period in 2011. The increases were primarily due to net increases in long-term debt.
Income Taxes
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$1.9 | 9.6 | $6.9 | 25.7 | |||
|
In the second quarter 2012, income taxes were $22.1 million compared to $20.2 million for the corresponding period in 2011. The increase was primarily due to higher pre-tax earnings and a reduction in the tax benefits associated with a decrease in AFUDC equity, which is non-taxable.
For year-to-date 2012, income taxes were $33.8 million compared to $26.9 million for the corresponding period in 2011. The increase was primarily due to higher pre-tax earnings.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Gulf Powers future earnings potential. The level of Gulf Powers future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Powers business of selling electricity. These factors include Gulf Powers ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Gulf Powers service territory. Changes in economic conditions impact sales for Gulf Power, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.
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Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under Environmental Matters in Item 8 of the Form 10-K for additional information.
New Source Review Actions
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters New Source Review Actions of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under Environmental Matters New Source Review Actions in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under Environmental Matters New Source Review Actions herein for additional information. The case against Georgia Power (including claims related to the unit co-owned by Gulf Power) was administratively closed in 2001 and has not been reopened. The ultimate outcome of this matter cannot be determined at this time.
Climate Change Litigation
Hurricane Katrina Case
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Climate Change Litigation Hurricane Katrina Case of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under Environmental Matters Climate Change Litigation Hurricane Katrina Case in Item 8 of the Form 10-K for additional information. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the amended class action complaint filed in May 2011 by the plaintiffs. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
General
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations General of Gulf Power in Item 7 of the Form 10-K for information regarding Gulf Powers estimated base level capital expenditures to comply with existing statutes and regulations for 2012 through 2014, as well as Gulf Powers preliminary estimates for potential incremental environmental compliance investments associated with complying with the EPAs final Mercury and Air Toxics Standards (MATS) rule (formerly referred to as the Utility Maximum Achievable Control Technology rule) and the EPAs proposed water and coal combustion byproducts rules.
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Gulf Power is continuing to develop its compliance strategy and to assess the potential costs of complying with the MATS rule and the EPAs proposed water and coal combustion byproducts rules. While further analysis of the MATS rule is required and the ultimate costs remain uncertain, the compliance decisions made through the second quarter 2012 have allowed Gulf Power to further develop its cost estimates for compliance with the MATS rule. As a result, estimated compliance costs for the MATS rule in the 2012 through 2014 period have been revised from up to $375 million to up to $300 million as follows:
2012 | 2013 | 2014 | ||||||||||
(in millions) | ||||||||||||
MATS rule |
Up to $35 | Up to $85 | Up to $180 | |||||||||
In addition, Gulf Power has further developed its estimated capital expenditures and associated timing of these expenditures to comply with the proposed water and coal combustion byproducts rules, resulting in a reduction, due primarily to timing, in estimated compliance costs for 2012 through 2014. Potential incremental environmental compliance investments to comply with the proposed water and coal combustion byproducts rules have been revised from up to $105 million to up to $35 million over the 2012 through 2014 period, based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule. These potential incremental environmental compliance investments are estimated as follows:
2012 | 2013 | 2014 | ||||||||||
(in millions) | ||||||||||||
Proposed water and coal combustion byproducts rules |
| Up to $10 | Up to $25 | |||||||||
While Gulf Powers ultimate costs of compliance with the MATS rule and the proposed water and coal combustion byproducts rules remain uncertain, Gulf Power estimates that compliance costs through 2021 (assuming that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) could be approximately $1.6 billion. Included in this amount is approximately $400 million that is also included in the 2012 through 2014 base level capital investment of Gulf Power described in the Form 10-K in anticipation of these rules.
Gulf Powers ultimate compliance strategy and actual future environmental capital expenditures are dependent on a final assessment of the MATS rule and will be affected by the final requirements of new or revised environmental regulations that are promulgated; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and Gulf Powers fuel mix. Compliance costs may arise from retirement and replacement of existing units, installation of additional environmental controls, upgrades to the transmission system, and changing fuel sources for certain existing units. Gulf Powers preliminary analysis further indicates that the short timeframe for compliance with the MATS rule could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters cannot be determined at this time.
Air Quality
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations Air Quality of Gulf Power in Item 7 of the Form 10-K for additional information on the eight-hour ozone and fine particulate matter air quality standards and the MATS rule.
On May 1, 2012, the EPA released its final determination of nonattainment areas based on the 2008 eight-hour ozone air quality standards. None of the areas within Gulf Powers service territory were designated as nonattainment areas.
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On June 14, 2012, the EPA proposed a rule that would increase the stringency of the fine particulate matter national ambient air quality standards. If adopted, the proposed standards could result in the designation of new nonattainment areas within Gulf Powers service territory. As part of a related settlement, the EPA has agreed to finalize the proposed rule by December 14, 2012. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Numerous petitions for administrative reconsideration of the MATS rule, including a petition by Southern Company and its subsidiaries, including Gulf Power, have been filed with the EPA. Challenges to the final rule have also been filed in the U.S. District Court for the District of Columbia by numerous states, environmental organizations, industry groups, and others. The impact of the MATS rule will depend on the outcome of these and any other legal challenges and, therefore, cannot be determined at this time.
Water Quality
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations Water Quality of Gulf Power in Item 7 of the Form 10-K for additional information on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Byproducts
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations Coal Combustion Byproducts of Gulf Power in Item 7 of the Form 10-K for additional information. Environmental groups and other parties have filed lawsuits in the U.S. District Court for the District of Columbia seeking to require the EPA to complete its rulemaking process and issue final regulations pertaining to the regulation of coal combustion byproducts. The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Global Climate Issues of Gulf Power in Item 7 of the Form 10-K for additional information.
On April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.
On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPAs actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.
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PSC Matters
Retail Base Rate Case
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Retail Base Rate Case of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under Retail Regulatory Matters Retail Base Rate Case in Item 8 of the Form 10-K for additional information.
On March 12, 2012, the Florida PSC approved a permanent increase in retail base rates and charges of $64 million effective April 11, 2012. The amount of the permanent increase includes the previously approved $38.5 million interim retail rate increase implemented in September 2011. The Florida PSCs decision on the amount of the permanent increase also included a determination that none of the base rate revenues collected on an interim basis would be refunded. Gulf Powers authorized retail ROE is a range of 9.25% to 11.25% with new retail base rates set at the midpoint retail ROE of 10.25%. In addition, the Florida PSC also approved a step increase to Gulf Powers retail base rates and charges of $4 million to be effective in January 2013. On April 18, 2012, Gulf Power filed a motion to reconsider one aspect of the decision dealing with property acquired as a potential site for a future generating plant. On July 17, 2012, the Florida PSC denied Gulf Powers motion and reaffirmed its earlier decision.
Cost Recovery Clauses
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Cost Recovery Clauses of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under Retail Regulatory Matters Cost Recovery Clauses in Item 8 of the Form 10-K for additional information.
Fuel Cost Recovery
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Fuel Cost Recovery of Gulf Power in Item 7 and Notes 1 and 3 to the financial statements of Gulf Power under Revenues and Retail Regulatory Matters Fuel Cost Recovery, respectively, in Item 8 of the Form 10-K for additional information.
On June 19, 2012, the Florida PSC approved a decrease in Gulf Powers fuel rates of 7.8%, which will reduce annual billings by approximately $58.8 million effective July 2, 2012.
Over recovered fuel costs at June 30, 2012 totaled $41.6 million compared to $9.9 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Powers Condensed Balance Sheets herein.
Purchased Power Capacity Recovery
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Purchased Power Capacity Recovery of Gulf Power in Item 7 and Notes 1 and 3 to the financial statements of Gulf Power under Revenues and Retail Regulatory Matters Purchased Power Capacity Recovery, respectively, in Item 8 of the Form 10-K for additional information.
Over recovered purchased power capacity costs at June 30, 2012 totaled $7.9 million compared to $8.0 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Powers Condensed Balance Sheets herein.
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Environmental Cost Recovery
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Environmental Cost Recovery of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under Retail Regulatory Matters Environmental Cost Recovery in Item 8 of the Form 10-K for additional information.
On April 3, 2012, the Mississippi PSC approved Mississippi Powers request for a CPCN to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. On May 3, 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court of Harrison County, Mississippi. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, excluding AFUDC, and it is scheduled for completion in December 2015. Gulf Powers portion of the cost is expected to be recovered through the environmental cost recovery clause. The ultimate outcome of this matter cannot be determined at this time.
Over recovered environmental costs at June 30, 2012 totaled $3.6 million compared to $10.0 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Powers Condensed Balance Sheets herein.
Energy Conservation Cost Recovery
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Energy Conservation Cost Recovery of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under Retail Regulatory Matters Energy Conservation Cost Recovery in Item 8 of the Form 10-K for additional information.
Under recovered energy conservation costs at June 30, 2012 totaled $1.6 million compared to $3.1 million at December 31, 2011. These amounts are included in under recovered regulatory clause revenues on Gulf Powers Condensed Balance Sheets herein.
Income Tax Matters
Bonus Depreciation
In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Gulf Power through 2013. Consequently, Gulf Powers positive cash flow benefit is estimated to be between $105 million and $135 million in 2012.
Other Matters
Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Powers business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the U.S. In
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particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Gulf Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) herein or in Note 3 to the financial statements of Gulf Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Gulf Powers financial statements.
See the Notes to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Gulf Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Gulf Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Gulf Powers results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENTS DISCUSSION AND ANALYSIS ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates of Gulf Power in Item 7 of the Form 10-K for a complete discussion of Gulf Powers critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Overview of Gulf Power in Item 7 of the Form 10-K for additional information. Gulf Powers financial condition remained stable at June 30, 2012. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See Sources of Capital, Financing Activities, and Capital Requirements and Contractual Obligations herein for additional information.
Net cash provided from operating activities totaled $194.6 million for the first six months of 2012 compared to $175.2 million for the corresponding period in 2011. The $19.4 million increase was primarily due to a $49.7 million increase in deferred income taxes related to bonus depreciation, partially offset by a $17.5 million decrease resulting from lower fuel inventory reductions in 2012 as compared to 2011.
Net cash used for investing activities totaled $184.7 million in the first six months of 2012 compared to $179.6 million for the corresponding period in 2011. The $5.1 million increase was primarily due to an increase in cost of removal, net of salvage.
Net cash used for financing activities totaled $6.1 million for the first six months of 2012 compared to $5.3 million provided from financing activities for the corresponding period in 2011. The $11.4 million decrease was primarily due to a $25.0 million decrease in issuance of senior notes and a $10.0 million decrease in issuance of common stock, partially offset by $19.0 million fewer redemptions of senior notes and other long-term debt in 2012.
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Significant balance sheet changes for the first six months of 2012 include a net increase of $125.0 million in property, plant, and equipment, primarily due to the addition of environmental control projects, an increase of $100.6 million in accumulated deferred income taxes, primarily related to bonus depreciation, a $43.2 million increase in prepaid expenses, primarily due to an increase in prepaid income taxes, and the issuance of common stock to Southern Company for $40 million.
Capital Requirements and Contractual Obligations
See MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Capital Requirements and Contractual Obligations of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Powers capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental regulations, maturities of long-term debt, as well as the related interest, leases, derivative obligations, preference stock dividends, purchase commitments, and trust funding requirements. There are no requirements through June 30, 2013 to fund maturities of long-term debt.
See FUTURE EARNINGS POTENTIAL Environmental Statutes and Regulations General herein for a description of Gulf Powers estimated capital expenditures to comply with the MATS rule and proposed water and coal combustion byproducts rules.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet new regulatory requirements; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Gulf Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, security issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Sources of Capital of Gulf Power in Item 7 of the Form 10-K for additional information.
Gulf Powers current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business.
At June 30, 2012, Gulf Power had approximately $21.2 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2012, including expiration dates, were as follows:
Expires | Executable Term Loans |
Due Within One Year(a) | ||||||||||||||
2012 | 2013 | 2014 | Total | Unused | One Year |
Two Years |
Term Out |
No Term Out | ||||||||
|
|
|
| |||||||||||||
(in millions) | (in millions) | (in millions) | (in millions) | |||||||||||||
$20 | $60 | $195 | $275 | $275 | $45 | $ | $45 | $35 |
(a) | Reflects facilities expiring on or before June 30, 2013. |
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See Note 6 to the financial statements of Gulf Power under Bank Credit Arrangements in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under Bank Credit Arrangements herein for additional information.
Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of Gulf Power. Gulf Power is currently in compliance with all such covenants. Gulf Power expects to renew its credit arrangements, as needed, prior to expiration. These credit arrangements provide liquidity support to Gulf Powers commercial paper borrowings and variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2012 was approximately $69 million.
Gulf Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Gulf Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Gulf Power are loaned directly to Gulf Power. The obligations of each traditional operating company under these arrangements are several and there is no cross affiliate credit support.
Details of short-term borrowings were as follows:
Short-term Debt at
the End of the Period |
Short-term Debt During the Period(a) | |||||||||
Amount Outstanding |
Weighted Average Interest Rate |
Average Outstanding |
Weighted Average Interest Rate |
Maximum Amount Outstanding | ||||||
|
| |||||||||
(in millions) | (in millions) | (in millions) | ||||||||
June 30, 2012: |
||||||||||
Commercial paper |
$114 | 0.3% | $68 | 0.3% | $116 | |||||
|
(a) | Average and maximum amounts are based upon daily balances during the period. |
Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and cash.
Credit Rating Risk
Gulf Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management. The maximum potential collateral requirements under these contracts at June 30, 2012 were as follows:
Credit Ratings | Maximum Potential Collateral Requirements | |
| ||
(in millions) | ||
At BBB- and/or Baa3 |
$120 | |
Below BBB- and/or Baa3 |
530 | |
|
Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Gulf Powers ability to access capital markets, particularly the short-term debt market.
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GULF POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Market Price Risk
Gulf Powers market risk exposure relative to interest rate changes for the second quarter 2012 has not changed materially compared with the December 31, 2011 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Gulf Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Due to cost-based rate regulation and other various cost recovery mechanisms, Gulf Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. Gulf Power continues to manage a financial hedging program for fuel purchased to operate its electric generating fleet implemented per the guidelines of the Florida PSC. As such, Gulf Power had no material change in market risk exposure for the second quarter 2012 when compared with the December 31, 2011 reporting period.
The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three and six months ended June 30, 2012 were as follows:
Second Quarter 2012 Changes |
Year-to-Date 2012 Changes | |||
| ||||
Fair Value | ||||
(in millions) | ||||
Contracts outstanding at the beginning of the period, assets (liabilities), net |
$(54) | $(41) | ||
Contracts realized or settled |
12 | 18 | ||
Current period changes(a) |
5 | (14) | ||
| ||||
Contracts outstanding at the end of the period, assets (liabilities), net |
$(37) | $(37) | ||
|
(a) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
The changes in the fair value positions of the energy-related derivative contracts, which are substantially all attributable to both the volume and the price of natural gas, for the three and six months ended June 30, 2012 were as follows:
Second Quarter 2012 Changes |
Year-to-Date 2012 Changes | |||
| ||||
Fair Value | ||||
(in millions) | ||||
Natural gas swaps |
$16 | $4 | ||
Natural gas options |
1 | | ||
Other energy-related derivatives |
| | ||
| ||||
Total changes |
$17 | $4 | ||
|
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GULF POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The net hedge volumes of energy-related derivative contracts were as follows:
June 30, 2012 |
March 31, 2012 |
December 31, 2011 | ||||
| ||||||
mmBtu Volume | ||||||
| ||||||
(in millions) | ||||||
Commodity Natural gas swaps |
50 | 41 | 35 | |||
Commodity Natural gas options |
1 | 2 | 3 | |||
| ||||||
Total hedge volume |
51 | 43 | 38 | |||
|
The weighted average swap contract cost above market prices was approximately $0.72 per mmBtu as of June 30, 2012, $1.27 per mmBtu as of March 31, 2012, and $1.14 per mmBtu as of December 31, 2011. The change in option premiums is primarily attributable to the volatility of the market and the underlying change in the natural gas price. Natural gas settlements are recovered through Gulf Powers fuel cost recovery clause.
Regulatory hedges relate to Gulf Powers fuel-hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through Gulf Powers fuel cost recovery clause.
Unrealized pre-tax gains and losses recognized in income for the three and six months ended June 30, 2012 and 2011 for energy-related derivative contracts that are not hedges were not material.
Gulf Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at June 30, 2012 were as follows:
June 30, 2012 Fair Value Measurements | ||||||||
| ||||||||
Total | Maturity | |||||||
| ||||||||
Fair Value | Year 1 | Years 2&3 | Years 4&5 | |||||
| ||||||||
(in millions) | ||||||||
Level 1 |
$ | $ | $ | $ | ||||
Level 2 |
(37) | (20) | (16) | (1) | ||||
Level 3 |
| | | | ||||
| ||||||||
Fair value of contracts outstanding at end of period |
$(37) | $(20) | $(16) | $(1) | ||||
|
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Gulf Power. Regulations to implement the Dodd-Frank Act will impose additional requirements on the use of over-the-counter derivatives for both Gulf Power and its derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Gulf Power does not expect the impact of these rules to be material.
For additional information, see MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Market Price Risk of Gulf Power in Item 7 and Note 1 under Financial Instruments and Note 10 to the financial statements of Gulf Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
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Table of Contents
GULF POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financing Activities
In January 2012, Gulf Power issued to Southern Company 400,000 shares of Gulf Powers common stock, without par value, and realized proceeds of $40 million. The proceeds were used to repay a portion of Gulf Powers short-term debt and for other general corporate purposes, including Gulf Powers continuous construction program.
In May 2012, Gulf Power issued $100 million aggregate principal amount of Series 2012A 3.10% Senior Notes due May 15, 2022. The proceeds from the sale of the Series 2012A Senior Notes were used by Gulf Power for the redemption in June 2012 of all of approximately $61 million aggregate principal amount of Gulf Powers Series F 5.60% Senior Insured Quarterly Notes due April 1, 2033 and $30 million aggregate principal amount of Gulf Powers Series H 5.25% Senior Notes due July 15, 2033, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Gulf Powers continuous construction program.
In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm-recovery, Gulf Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
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105
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CONDENSED STATEMENTS OF INCOME (UNAUDITED)
For the Three Months | For the Six Months | |||||||||||||||
Ended June 30, | Ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in thousands) | (in thousands) | |||||||||||||||
Operating Revenues: |
||||||||||||||||
Retail revenues |
$ | 192,177 | $ | 207,005 | $ | 358,448 | $ | 387,479 | ||||||||
Wholesale revenues, non-affiliates |
64,116 | 67,813 | 118,347 | 137,664 | ||||||||||||
Wholesale revenues, affiliates |
5,324 | 6,303 | 9,364 | 15,603 | ||||||||||||
Other revenues |
4,467 | 4,920 | 8,639 | 8,571 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total operating revenues |
266,084 | 286,041 | 494,798 | 549,317 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Operating Expenses: |
||||||||||||||||
Fuel |
105,469 | 123,674 | 194,088 | 244,728 | ||||||||||||
Purchased power, non-affiliates |
1,134 | 1,336 | 3,077 | 2,346 | ||||||||||||
Purchased power, affiliates |
10,843 | 19,867 | 19,703 | 28,217 | ||||||||||||
Other operations and maintenance |
60,501 | 64,512 | 115,396 | 134,879 | ||||||||||||
Depreciation and amortization |
22,517 | 20,345 | 44,998 | 40,208 | ||||||||||||
Taxes other than income taxes |
18,634 | 17,251 | 40,337 | 34,732 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total operating expenses |
219,098 | 246,985 | 417,599 | 485,110 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Operating Income |
46,986 | 39,056 | 77,199 | 64,207 | ||||||||||||
Other Income and (Expense): |
||||||||||||||||
Allowance for equity funds used during construction |
13,870 | 4,991 | 25,697 | 8,122 | ||||||||||||
Interest income |
380 | 401 | 500 | 743 | ||||||||||||
Interest expense, net of amounts capitalized |
(13,023 | ) | (5,532 | ) | (20,828 | ) | (11,545 | ) | ||||||||
Other income (expense), net |
(539 | ) | (613 | ) | (781 | ) | (1,016 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other income and (expense) |
688 | (753 | ) | 4,588 | (3,696 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Earnings Before Income Taxes |
47,674 | 38,303 | 81,787 | 60,511 | ||||||||||||
Income taxes |
12,214 | 12,587 | 20,639 | 19,745 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net Income |
35,460 | 25,716 | 61,148 | 40,766 | ||||||||||||
Dividends on Preferred Stock |
433 | 433 | 866 | 866 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net Income After Dividends on Preferred Stock |
$ | 35,027 | $ | 25,283 | $ | 60,282 | $ | 39,900 | ||||||||
|
|
|
|
|
|
|
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
For the Three Months | For the Six Months | |||||||||||||||
Ended June 30, | Ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in thousands) | (in thousands) | |||||||||||||||
Net Income After Dividends on Preferred Stock |
$ | 35,027 | $ | 25,283 | $ | 60,282 | $ | 39,900 | ||||||||
Other comprehensive income (loss): |
||||||||||||||||
Qualifying hedges: |
||||||||||||||||
Changes in fair value, net of tax of $-, $7, $(296) and $6, respectively |
| 13 | (478 | ) | 11 | |||||||||||
Reclassification adjustment for amounts included in net income, net of tax of $132, $-, $148 and $-, respectively |
212 | | 238 | | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other comprehensive income (loss) |
212 | 13 | (240 | ) | 11 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Comprehensive Income |
$ | 35,239 | $ | 25,296 | $ | 60,042 | $ | 39,911 | ||||||||
|
|
|
|
|
|
|
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
For the Six Months | ||||||||
Ended June 30, | ||||||||
2012 | 2011 | |||||||
(in thousands) | ||||||||
Operating Activities: |
||||||||
Net income |
$ | 61,148 | $ | 40,766 | ||||
Adjustments to reconcile net income to net cash provided from operating activities |
||||||||
Depreciation and amortization, total |
43,955 | 43,032 | ||||||
Deferred income taxes |
1,280 | (8,136 | ) | |||||
Investment tax credits received |
13,974 | 29,556 | ||||||
Allowance for equity funds used during construction |
(25,697 | ) | (8,122 | ) | ||||
Pension, postretirement, and other employee benefits |
3,993 | 1,601 | ||||||
Hedge settlements |
(15,983 | ) | | |||||
Stock based compensation expense |
1,344 | 1,060 | ||||||
Other, net |
(2,648 | ) | (5,584 | ) | ||||
Changes in certain current assets and liabilities |
||||||||
-Receivables |
(12,424 | ) | (8,041 | ) | ||||
-Fossil fuel stock |
(32,797 | ) | (8,838 | ) | ||||
-Materials and supplies |
212 | (603 | ) | |||||
-Prepaid income taxes |
11,974 | 17,075 | ||||||
-Other current assets |
(7,281 | ) | 1,021 | |||||
-Accounts payable |
3,408 | 17,927 | ||||||
-Accrued taxes |
(16,785 | ) | (6,227 | ) | ||||
-Accrued compensation |
(7,002 | ) | (7,064 | ) | ||||
-Over recovered regulatory clause revenues |
15,871 | (10,748 | ) | |||||
-Other current liabilities |
7,640 | 2,066 | ||||||
|
|
|
|
|||||
Net cash provided from operating activities |
44,182 | 90,741 | ||||||
|
|
|
|
|||||
Investing Activities: |
||||||||
Property additions |
(763,641 | ) | (365,261 | ) | ||||
Cost of removal, net of salvage |
(1,217 | ) | (4,339 | ) | ||||
Construction payables |
57,283 | 31,949 | ||||||
Capital grant proceeds |
6,146 | 91,650 | ||||||
Distribution of restricted cash |
| 50,000 | ||||||
Other investing activities |
(9,690 | ) | (2,217 | ) | ||||
|
|
|
|
|||||
Net cash used for investing activities |
(711,119 | ) | (198,218 | ) | ||||
|
|
|
|
|||||
Financing Activities: |
||||||||
Proceeds |
||||||||
Capital contributions from parent company |
277,633 | 100,878 | ||||||
Senior notes issuances |
400,000 | | ||||||
Interest-bearing refundable deposit related to asset sale |
150,000 | | ||||||
Other long-term debt issuances |
| 75,000 | ||||||
Redemptions |
||||||||
Capital leases |
(633 | ) | (705 | ) | ||||
Other long-term debt |
(165,000 | ) | (130,000 | ) | ||||
Payment of preferred stock dividends |
(866 | ) | (866 | ) | ||||
Payment of common stock dividends |
(53,400 | ) | (37,750 | ) | ||||
Other financing activities |
998 | (134) | ||||||
Net cash provided from financing activities |
608,732 | 6,423 | ||||||
Net Change in Cash and Cash Equivalents |
(58,205 | ) | (101,054 | ) | ||||
Cash and Cash Equivalents at Beginning of Period |
211,585 | 160,779 | ||||||
|
|
|
|
|||||
Cash and Cash Equivalents at End of Period |
$ | 153,380 | $ | 59,725 | ||||
|
|
|
|
|||||
Supplemental Cash Flow Information: |
||||||||
Cash paid (received) during the period for |
||||||||
Interest (paid $29,433 and $12,050, net of $12,476 and $2,572 capitalized for 2012 and 2011, respectively) |
$ | 16,603 | $ | 9,505 | ||||
Income taxes, net |
(7,756 | ) | (32,648 | ) | ||||
Noncash transactionsaccrued property additions at end of period |
193,184 | 70,772 |
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
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Table of Contents
CONDENSED BALANCE SHEETS (UNAUDITED)
Assets |
At June 30, 2012 |
At December 31, 2011 |
||||||
(in thousands) | ||||||||
Current Assets: |
||||||||
Cash and cash equivalents |
$ | 153,380 | $ | 211,585 | ||||
Receivables |
||||||||
Customer accounts receivable |
37,632 | 32,551 | ||||||
Unbilled revenues |
36,060 | 27,239 | ||||||
Other accounts and notes receivable |
5,072 | 7,080 | ||||||
Affiliated companies |
25,497 | 23,078 | ||||||
Accumulated provision for uncollectible accounts |
(306 | ) | (547 | ) | ||||
Fossil fuel stock, at average cost |
172,970 | 140,173 | ||||||
Materials and supplies, at average cost |
30,576 | 30,787 | ||||||
Other regulatory assets, current |
65,251 | 69,201 | ||||||
Prepaid income taxes |
192,067 | 37,793 | ||||||
Other current assets |
6,230 | 8,881 | ||||||
|
|
|
|
|||||
Total current assets |
724,429 | 587,821 | ||||||
|
|
|
|
|||||
Property, Plant, and Equipment: |
||||||||
In service |
2,956,019 | 2,902,240 | ||||||
Less accumulated provision for depreciation |
1,052,399 | 1,019,251 | ||||||
|
|
|
|
|||||
Plant in service, net of depreciation |
1,903,620 | 1,882,989 | ||||||
Construction work in progress |
1,699,239 | 955,135 | ||||||
|
|
|
|
|||||
Total property, plant, and equipment |
3,602,859 | 2,838,124 | ||||||
|
|
|
|
|||||
Other Property and Investments |
5,970 | 6,520 | ||||||
|
|
|
|
|||||
Deferred Charges and Other Assets: |
||||||||
Deferred charges related to income taxes |
47,979 | 25,009 | ||||||
Other regulatory assets, deferred |
195,721 | 185,694 | ||||||
Other deferred charges and assets |
37,640 | 28,674 | ||||||
|
|
|
|
|||||
Total deferred charges and other assets |
281,340 | 239,377 | ||||||
|
|
|
|
|||||
Total Assets |
$ | 4,614,598 | $ | 3,671,842 | ||||
|
|
|
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
108
Table of Contents
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholders Equity |
At June 30, 2012 |
At December 31, 2011 |
||||||
(in thousands) | ||||||||
Current Liabilities: |
||||||||
Securities due within one year |
$ | 165,000 | $ | 240,633 | ||||
Interest-bearing refundable deposit related to asset sale |
150,000 | | ||||||
Accounts payable |
||||||||
Affiliated |
62,007 | 62,650 | ||||||
Other |
228,506 | 168,309 | ||||||
Customer deposits |
14,190 | 13,658 | ||||||
Accrued taxes |
||||||||
Accrued income taxes |
3,803 | 3,813 | ||||||
Other accrued taxes |
37,327 | 53,825 | ||||||
Accrued interest |
20,095 | 12,750 | ||||||
Accrued compensation |
8,887 | 15,889 | ||||||
Other regulatory liabilities, current |
5,553 | 5,779 | ||||||
Over recovered regulatory clause liabilities |
76,373 | 60,502 | ||||||
Liabilities from risk management activities |
26,699 | 54,127 | ||||||
Other current liabilities |
21,913 | 17,533 | ||||||
|
|
|
|
|||||
Total current liabilities |
820,353 | 709,468 | ||||||
|
|
|
|
|||||
Long-term Debt |
1,410,660 | 1,103,596 | ||||||
|
|
|
|
|||||
Deferred Credits and Other Liabilities: |
||||||||
Accumulated deferred income taxes |
377,763 | 270,397 | ||||||
Deferred credits related to income taxes |
10,536 | 11,058 | ||||||
Accumulated deferred investment tax credits |
206,607 | 109,761 | ||||||
Employee benefit obligations |
162,266 | 161,065 | ||||||
Other cost of removal obligations |
135,540 | 126,424 | ||||||
Other regulatory liabilities, deferred |
64,710 | 60,848 | ||||||
Other deferred credits and liabilities |
57,181 | 37,228 | ||||||
|
|
|
|
|||||
Total deferred credits and other liabilities |
1,014,603 | 776,781 | ||||||
|
|
|
|
|||||
Total Liabilities |
3,245,616 | 2,589,845 | ||||||
|
|
|
|
|||||
Redeemable Preferred Stock |
32,780 | 32,780 | ||||||
|
|
|
|
|||||
Common Stockholders Equity: |
||||||||
Common stock, without par value |
||||||||
Authorized 1,130,000 shares |
||||||||
Outstanding1,121,000 shares |
37,691 | 37,691 | ||||||
Paid-in capital |
975,198 | 694,855 | ||||||
Retained earnings |
332,450 | 325,568 | ||||||
Accumulated other comprehensive loss |
(9,137 | ) | (8,897 | ) | ||||
|
|
|
|
|||||
Total common stockholders equity |
1,336,202 | 1,049,217 | ||||||
|
|
|
|
|||||
Total Liabilities and Stockholder's Equity |
$ | 4,614,598 | $ | 3,671,842 | ||||
|
|
|
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
109
Table of Contents
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SECOND QUARTER 2012 vs. SECOND QUARTER 2011
AND
YEAR-TO-DATE 2012 vs. YEAR-TO-DATE 2011
OVERVIEW
Mississippi Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service territory located within the State of Mississippi and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Mississippi Powers business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel prices, capital expenditures, and restoration following major storms. In addition, Mississippi Power is currently constructing the Kemper IGCC. Mississippi Power has various regulatory mechanisms that operate to address cost recovery. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.
On June 22, 2012, the Mississippi PSC denied the proposed Certificated New Plant-A (CNP-A) rate schedule and the 2012 rate recovery filings submitted by Mississippi Power, pending a final ruling from the Mississippi Supreme Court regarding the motion for stay and notice of appeal filed by the Sierra Club on April 26, 2012 relating to the Mississippi PSCs issuance of the CPCN for the Kemper IGCC. On July 9, 2012, Mississippi Power appealed the Mississippi PSCs June 22, 2012 decision to the Mississippi Supreme Court and requested interim rates under bond of $55.3 million. On July 31, 2012, the Mississippi Supreme Court denied Mississippi Powers request for interim rates under bond while the Mississippi Supreme Court decides Mississippi Powers appeal of the Mississippi PSCs June 22, 2012 decision. The ultimate outcome of this matter cannot be determined at this time.
Mississippi Power continues to focus on several key performance indicators. In recognition that Mississippi Powers long-term financial success is dependent upon how well it satisfies its customers needs, Mississippi Powers retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to Mississippi Powers allowed return. In addition to the PEP performance indicators, Mississippi Power focuses on other performance measures, including broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock. For additional information on these indicators, see MANAGEMENTS DISCUSSION AND ANALYSIS OVERVIEW Key Performance Indicators of Mississippi Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$9.7 |
38.5 | $20.4 | 51.1 | |||
|
Mississippi Powers net income after dividends on preferred stock for the second quarter 2012 was $35.0 million compared to $25.3 million for the corresponding period in 2011. The increase in net income after dividends on preferred stock for the second quarter 2012 was the result of an increase in AFUDC equity primarily related to the construction of the Kemper IGCC, a decrease in operations and maintenance expenses, and an increase in territorial base revenues primarily due to a wholesale base rate increase effective April 1, 2012, partially offset by an increase in interest expense, net of amounts capitalized.
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MISSISSIPPI POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Mississippi Powers net income after dividends on preferred stock for year-to-date 2012 was $60.3 million compared to $39.9 million for the corresponding period in 2011. The increase in net income after dividends on preferred stock for year-to-date 2012 was primarily due to an increase in AFUDC equity primarily related to the construction of the Kemper IGCC and a decrease in operations and maintenance expenses. These factors were partially offset by a decrease in territorial base revenues resulting from milder weather in 2012 and an increase in interest expense, net of amounts capitalized.
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Integrated Coal Gasification Combined Cycle and Note (B) to the Condensed Financial Statements herein for additional information regarding the Kemper IGCC.
Retail Revenues
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(14.8) |
(7.2) | $(29.1) | (7.5) | |||
|
In the second quarter 2012, retail revenues were $192.2 million compared to $207.0 million for the corresponding period in 2011. For year-to-date 2012, retail revenues were $358.4 million compared to $387.5 million for the corresponding period in 2011.
Details of the change to retail revenues were as follows:
Second Quarter 2012 |
Year-to-Date 2012 | |||||||
| ||||||||
(in millions) | (% change) | (in millions) | (% change) | |||||
Retail prior year |
$207.0 | $387.5 | ||||||
Estimated change in |
||||||||
Rates and pricing |
(0.6) | (0.3) | (1.7) | (0.4) | ||||
Sales growth (decline) |
2.1 | 1.0 | 5.2 | 1.3 | ||||
Weather |
(2.8) | (1.4) | (7.8) | (2.0) | ||||
Fuel and other cost recovery |
(13.5) | (6.5) | (24.8) | (6.4) | ||||
| ||||||||
Retail current year |
$192.2 | (7.2)% | $358.4 | (7.5)% | ||||
|
Revenues associated with changes in rates and pricing decreased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 due to decreases of $0.6 million and $1.7 million, respectively, related to the ECO Plan rate.
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Environmental Compliance Overview Plan of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL PSC Matters Environmental Compliance Overview Plan herein for additional information.
Revenues attributable to changes in sales increased in the second quarter 2012 when compared to the corresponding period in 2011. KWH energy sales to industrial customers increased 3.3% due to increased production for several large industrial customers resulting from continued economic recovery. Weather-adjusted KWH energy sales to residential and commercial customers increased 3.6% and 1.5%, respectively, when compared to the corresponding period in 2011 due to a small increase in the number of residential customers and improving economic conditions.
Revenues attributable to changes in sales increased for year-to-date 2012 when compared to the corresponding period in 2011 due to an increase in sales to residential, commercial, and industrial customers. KWH energy sales to industrial customers increased 3.9% due to increased production for some of the larger customers resulting from an improving economy. Weather-adjusted KWH energy sales to residential and commercial customers increased 2.3% and 1.3%,
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respectively, when compared to the corresponding period in 2011. The increase in residential and commercial sales was primarily due to a small increase in the number of residential customers and improving economic conditions.
Revenues attributable to changes in weather decreased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 primarily due to milder weather.
Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 primarily as a result of lower recoverable fuel costs, partially offset by an increase in revenues related to the retail portion of ad valorem taxes. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Powers service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income. The retail portion of ad valorem tax expense is recoverable under Mississippi Powers ad valorem tax cost recovery clause and, therefore, does not affect net income.
Wholesale Revenues Non-Affiliates
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(3.7) |
(5.5) | $(19.4) | (14.0) | |||
|
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Powers and the Southern Company systems generation, demand for energy within the Southern Company systems service territory, and the availability of the Southern Company systems generation. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.
In the second quarter 2012, wholesale revenues from non-affiliates were $64.1 million compared to $67.8 million for the corresponding period in 2011. The decrease was due to a $10.1 million decrease in energy revenues, of which $2.1 million was associated with a decrease in KWH sales due to lower demand primarily resulting from milder weather in the second quarter 2012 compared to the corresponding period in 2011 and $8.0 million was associated with lower fuel prices, partially offset by a $6.4 million increase in revenues primarily resulting from a wholesale base rate increase effective April 1, 2012.
For year-to-date 2012, wholesale revenues from non-affiliates were $118.3 million compared to $137.7 million for the corresponding period in 2011. The decrease was due to a $21.0 million decrease in energy revenues, of which $7.2 million was associated with a decrease in KWH sales due to lower demand primarily resulting from milder weather in 2012 compared to the corresponding period in 2011 and $13.8 million was associated with lower fuel prices, partially offset by a $1.6 million increase in revenues primarily resulting from a wholesale base rate increase effective April 1, 2012.
Wholesale Revenues Affiliates
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(1.0) |
(15.5) | $(6.2) | (40.0) | |||
|
Wholesale revenues from sales to affiliated companies within the Southern Company system will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost.
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In the second quarter 2012, wholesale revenues from affiliates were $5.3 million compared to $6.3 million for the corresponding period in 2011. The decrease was primarily due to a $0.4 million decrease in capacity revenues and a $0.6 million decrease in energy revenues, of which $4.3 million was associated with lower prices, partially offset by $3.7 million associated with an increase in KWH sales.
For year-to-date 2012, wholesale revenues from affiliates were $9.4 million compared to $15.6 million for the corresponding period in 2011. The decrease was primarily due to a $0.4 million decrease in capacity revenues and a $5.8 million decrease in energy revenues, of which $6.1 million was associated with lower prices, partially offset by $0.3 million associated with an increase in KWH sales.
Fuel and Purchased Power Expenses
Second Quarter 2012 vs. Second Quarter 2011 |
Year-to-Date 2012 vs. Year-to-Date 2011 | |||||||
| ||||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||||
Fuel |
$ (18.2) | (14.7) | $ (50.6) | (20.7) | ||||
Purchased power non-affiliates |
(0.2) | (15.1) | 0.8 | 31.2 | ||||
Purchased power affiliates |
(9.1) | (45.4) | (8.5) | (30.2) | ||||
|
|
|||||||
Total fuel and purchased power expenses |
$ (27.5) | $ (58.3) | ||||||
|
|
In the second quarter 2012, total fuel and purchased power expenses were $117.4 million compared to $144.9 million for the corresponding period in 2011. The decrease was primarily due to a $27.0 million decrease in the cost of fuel and purchased power and a $0.5 million decrease in total KWHs generated and purchased.
For year-to-date 2012, total fuel and purchased power expenses were $216.9 million compared to $275.2 million for the corresponding period in 2011. The decrease was primarily due to a $44.8 million decrease in the cost of fuel and purchased power and a $13.5 million decrease in total KWHs generated and purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Powers fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL PSC Matters herein for additional information.
Details of Mississippi Powers generation and purchased power were as follows:
Second Quarter 2012 |
Second Quarter 2011 |
Year-to-Date 2012 |
Year-to-Date 2011 | |||||
| ||||||||
Total generation (millions of KWHs) |
3,359 | 3,226 | 6,341 | 6,590 | ||||
Total purchased power (millions of KWHs) |
466 | 578 | 912 | 882 | ||||
| ||||||||
Sources of generation (percent) |
||||||||
Coal |
29 | 46 | 25 | 41 | ||||
Gas |
71 | 54 | 75 | 59 | ||||
| ||||||||
Cost of fuel, generated (cents per net KWH) |
||||||||
Coal |
4.88 | 4.34 | 4.83 | 4.29 | ||||
Gas |
2.72 | 3.98 | 2.77 | 3.84 | ||||
| ||||||||
Average cost of fuel, generated (cents per net KWH) |
3.39 | 4.16 | 3.34 | 4.04 | ||||
Average cost of purchased power (cents per net KWH) |
2.57 | 3.67 | 2.50 | 3.47 | ||||
|
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Fuel
In the second quarter 2012, fuel expense was $105.5 million compared to $123.7 million for the corresponding period in 2011. The decrease was primarily due to a 31.7% decrease in the average cost of natural gas per KWH generated primarily resulting from lower gas prices, partially offset by a 4.7% increase in generation from Mississippi Powers facilities resulting from higher energy demand in the second quarter 2012.
For year-to-date 2012, fuel expense was $194.1 million compared to $244.7 million for the corresponding period in 2011. The decrease was primarily due to a 27.9% decrease in the average cost of natural gas per KWH generated primarily resulting from lower gas prices and a 4.2% decrease in generation from Mississippi Powers facilities resulting from lower energy demand primarily due to milder weather in 2012.
Purchased Power Non-Affiliates
In the second quarter 2012, purchased power expense from non-affiliates was $1.1 million compared to $1.3 million for the corresponding period in 2011. The decrease was primarily the result of a 63.1% decrease in the average cost of purchased power per KWH, partially offset by a 129.8% increase in KWH volume purchased. The increase in the volume of KWHs purchased was due to a lower marginal cost of fuel compared to the cost of generation. The decrease in the average cost per KWH purchased was due to a lower marginal cost of fuel.
For year-to-date 2012, purchased power expense from non-affiliates was $3.1 million compared to $2.3 million for the corresponding period in 2011. The increase was primarily the result of a 96.7% increase in KWH volume purchased, partially offset by a 33.3% decrease in the average cost of purchased power per KWH. The increase in the volume of KWHs purchased was due to a lower marginal cost of fuel compared to the cost of generation.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy compared to the cost of the Southern Company systems generation, demand for energy within the Southern Company systems service territory, and the availability of the Southern Company systems generation.
Purchased Power Affiliates
In the second quarter 2012, purchased power expense from affiliates was $10.8 million compared to $19.9 million for the corresponding period in 2011. The decrease was primarily due to a 27.9% decrease in KWH volume purchased and a 24.3% decrease in the average cost of purchased power per KWH.
For year-to-date 2012, purchased power expense from affiliates was $19.7 million compared to $28.2 million for the corresponding period in 2011. The decrease was primarily due to a 6.5% decrease in KWH volume purchased and a 25.4% decrease in the average cost of purchased power per KWH.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC, as approved by the FERC.
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Other Operations and Maintenance Expenses
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(4.0) | (6.2) | $(19.5) | (14.4) | |||
|
In the second quarter 2012, other operations and maintenance expenses were $60.5 million compared to $64.5 million for the corresponding period in 2011. The decrease was primarily due to a $9.7 million decrease in rent expense and expenses under a long-term service agreement resulting from the expiration of an operating lease for Plant Daniel Units 3 and 4 in October 2011. The decrease was partially offset by a $3.4 million increase in generation expenses primarily related to scheduled outages and a $2.0 million increase in administrative and general expenses.
For year-to-date 2012, other operations and maintenance expenses were $115.4 million compared to $134.9 million for the corresponding period in 2011. The decrease was primarily due to a $20.5 million decrease in rent expense and expenses under a long-term service agreement resulting from the expiration of an operating lease for Plant Daniel Units 3 and 4 in October 2011 and a $3.1 million decrease in generation maintenance expenses. These decreases were partially offset by a $3.3 million increase in administrative and general expenses.
See Notes 1 and 7 to the financial statements of Mississippi Power under Purchase of the Plant Daniel Combined Cycle Generating Units and Long-Term Service Agreements, respectively, in Item 8 of the Form 10-K for additional information.
Depreciation and Amortization
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$2.2 | 10.7 | $4.8 | 11.9 | |||
|
In the second quarter 2012, depreciation and amortization was $22.5 million compared to $20.3 million for the corresponding period in 2011. The increase was primarily due to a $3.4 million increase in depreciation on additional plant in service and a $1.9 million increase in amortization resulting from the plant acquisition adjustment related to the purchase of Plant Daniel Units 3 and 4. These increases were partially offset by a $2.6 million decrease in amortization primarily resulting from a regulatory deferral associated with the purchase of Plant Daniel Units 3 and 4 and a $0.5 million decrease in ARO amortization resulting from the deferral of the gain on the settlement of an ARO in 2011.
For year-to-date 2012, depreciation and amortization was $45.0 million compared to $40.2 million for the corresponding period in 2011. The increase was primarily due to a $6.7 million increase in depreciation on additional plant in service and a $3.9 million increase in amortization resulting from the plant acquisition adjustment related to the purchase of Plant Daniel Units 3 and 4. These increases were partially offset by a $5.3 million decrease in amortization primarily resulting from a regulatory deferral associated with the purchase of Plant Daniel Units 3 and 4 and a $0.5 million decrease in ARO amortization resulting from the deferral of the gain on the settlement of an ARO in 2011.
See Note 1 to the financial statements of Mississippi Power under Purchase of the Plant Daniel Combined Cycle Generating Units and Depreciation and Amortization in Item 8 of the Form 10-K for additional information.
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Taxes Other Than Income Taxes
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$1.3 |
8.0 | $5.6 | 16.1 | |||
|
In the second quarter 2012, taxes other than income taxes were $18.6 million compared to $17.3 million for the corresponding period in 2011. The increase was primarily due to a $2.6 million increase in ad valorem taxes resulting from the expiration of a tax exemption related to Plant Daniel Units 3 and 4, partially offset by a $1.5 million decrease in franchise taxes.
For year-to-date 2012, taxes other than income taxes were $40.3 million compared to $34.7 million for the corresponding period in 2011. The increase was primarily due to a $6.6 million increase in ad valorem taxes resulting from the expiration of a tax exemption related to Plant Daniel Units 3 and 4, partially offset by a $1.3 million decrease in franchise taxes.
The retail portion of ad valorem taxes is recoverable under Mississippi Powers ad valorem tax cost recovery clause and, therefore, does not affect net income.
Allowance for Equity Funds Used During Construction
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$8.9 |
177.9 | $17.6 | 216.4 | |||
|
In the second quarter 2012, AFUDC equity was $13.9 million compared to $5.0 million for the corresponding period in 2011. For year-to-date 2012, AFUDC equity was $25.7 million compared to $8.1 million for the corresponding period in 2011. These increases were primarily due to the construction of the Kemper IGCC.
See Note 3 to the financial statements of Mississippi Power under Integrated Coal Gasification Combined Cycle in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL Integrated Coal Gasification Combined Cycle herein for additional information regarding the Kemper IGCC.
Interest Expense, Net of Amounts Capitalized
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$7.5 |
135.4 | $9.3 | 80.4 | |||
|
In the second quarter 2012, interest expense, net of amounts capitalized was $13.0 million compared to $5.5 million for the corresponding period in 2011. Capitalized interest primarily resulting from AFUDC debt associated with the Kemper IGCC in the second quarter 2012 was $5.9 million compared to $1.6 million for the corresponding period in 2011. The increase in interest expense, net of amounts capitalized was primarily due to an $11.4 million increase in interest expense associated with the issuances of new long-term debt in September 2011, October 2011, and March 2012 and a $3.8 million increase in interest expense resulting from the receipt of a $150 million interest-bearing refundable deposit from SMEPA in March 2012 related to its pending purchase of an undivided interest in the Kemper IGCC. The increase was partially offset by a $4.3 million increase in capitalized interest primarily resulting from AFUDC debt associated with the Kemper IGCC and a $1.9 million decrease in interest expense resulting from the amortization of the fair value adjustment on the assumed debt related to the purchase of Plant Daniel Units 3 and 4 in October 2011.
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For year-to-date 2012, interest expense, net of amounts capitalized was $20.8 million compared to $11.5 million for the corresponding period in 2011. Capitalized interest primarily resulting from AFUDC debt associated with the Kemper IGCC for year-to-date 2012 was $12.5 million compared to $2.6 million for the corresponding period in 2011. The increase in interest expense, net of amounts capitalized was primarily due to a $19.9 million increase in interest expense associated with the issuances of new long-term debt in September 2011, October 2011, and March 2012 and a $4.8 million increase in interest expense resulting from the receipt of a $150 million interest-bearing refundable deposit from SMEPA in March 2012 related to its pending purchase of an undivided interest in the Kemper IGCC. The increase was partially offset by a $9.9 million increase in capitalized interest primarily resulting from AFUDC debt associated with the Kemper IGCC and a $3.8 million decrease in interest expense resulting from the amortization of the fair value adjustment on the assumed debt related to the purchase of Plant Daniel Units 3 and 4 in October 2011.
See Note 1 to the financial statements of Mississippi Power under Purchase of the Plant Daniel Combined Cycle Generating Units in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL Integrated Coal Gasification Combined Cycle herein for additional information.
Income Taxes
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(0.4) |
(3.0) | $0.9 | 4.5 | |||
|
In the second quarter 2012, income taxes were $12.2 million compared to $12.6 million for the corresponding period in 2011. The decrease was primarily due to a $3.3 million decrease resulting from higher AFUDC equity, which is non-taxable, and a $0.6 million decrease in unrecognized tax benefits, partially offset by a $3.2 million increase resulting from higher pre-tax earnings and a $0.3 million increase due to lower State of Mississippi manufacturing investment tax credits.
For year-to-date 2012, income taxes were $20.6 million compared to $19.7 million for the corresponding period in 2011. The increase was primarily due to a $7.8 million increase resulting from higher pre-tax earnings and a $0.6 million increase due to lower State of Mississippi manufacturing investment tax credits, partially offset by a $6.7 million decrease resulting from higher AFUDC equity, which is non-taxable, and a $0.8 million decrease in unrecognized tax benefits.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Mississippi Powers future earnings potential. The level of Mississippi Powers future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Powers business of selling electricity. These factors include Mississippi Powers ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Mississippi Powers service territory. Changes in economic conditions impact sales for Mississippi Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered
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through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under Environmental Matters in Item 8 of the Form 10-K for additional information.
New Source Review Actions
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters New Source Review Actions of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under Environmental Matters New Source Review Actions in Item 8 of the Form 10-K for additional information. On February 23, 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power (including claims related to the unit co-owned by Mississippi Power). The U.S. District Court for the Northern District of Alabama has not ruled on the EPAs motion seeking vacatur of the judgment. The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
General
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations General of Mississippi Power in Item 7 of the Form 10-K for information regarding Mississippi Powers estimated base level capital expenditures to comply with existing statutes and regulations for 2012 through 2014, as well as Mississippi Powers preliminary estimates for potential incremental environmental compliance investments associated with complying with the EPAs final Mercury and Air Toxics Standards (MATS) rule (formerly referred to as the Utility Maximum Achievable Control Technology rule) and the EPAs proposed water and coal combustion byproducts rules.
Mississippi Power is continuing to develop its compliance strategy and to assess the potential costs of complying with the MATS rule and the EPAs proposed water and coal combustion byproducts rules. While further analysis of the MATS rule is required and the ultimate costs remain uncertain, the compliance decisions made through the second quarter 2012 have allowed Mississippi Power to further develop its cost estimates for compliance with the MATS rule. As a result, estimated compliance costs for the MATS rule in the 2012 through 2014 period have been revised from up to $430 million to approximately $55 million as follows:
2012 | 2013 | 2014 | ||||
| ||||||
(in millions) | ||||||
MATS rule |
| $5 | $50 | |||
|
In addition, Mississippi Power has further developed its estimated capital expenditures and associated timing of these expenditures to comply with the proposed water and coal combustion byproducts rules, resulting in a reduction, due primarily to timing, in estimated compliance costs for 2012 through 2014. Potential incremental environmental compliance investments to comply with the proposed water and coal combustion byproducts rules have been revised from up to $121 million to approximately $40 million over the 2012 through 2014 period, based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule. These potential incremental environmental compliance investments are estimated as follows:
2012 | 2013 | 2014 | ||||
| ||||||
(in millions) | ||||||
Proposed water and coal combustion byproducts rules |
$1 | $10 | $30 | |||
|
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While Mississippi Powers ultimate costs of compliance with the MATS rule and the proposed water and coal combustion byproducts rules remain uncertain, Mississippi Power estimates that compliance costs through 2021 (assuming that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) will be at the low end of the $1 billion to $2 billion range provided in the Form 10-K. Included in this amount is approximately $354 million that is also included in the 2012 through 2014 base level capital investment of Mississippi Power described herein in anticipation of these rules. See FINANCIAL CONDITION AND LIQUIDITY Capital Requirements and Contractual Obligations herein for additional information.
Mississippi Powers ultimate compliance strategy and actual future environmental capital expenditures are dependent on a final assessment of the MATS rule and will be affected by the final requirements of new or revised environmental regulations that are promulgated; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and Mississippi Powers fuel mix. Compliance costs may arise from retirement and replacement of existing units, installation of additional environmental controls, upgrades to the transmission system, and changing fuel sources for certain existing units. Mississippi Powers preliminary analysis further indicates that the short timeframe for compliance with the MATS rule could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters cannot be determined at this time.
Air Quality
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations Air Quality of Mississippi Power in Item 7 of the Form 10-K for additional information on the eight-hour ozone and fine particulate matter air quality standards and the MATS rule.
On May 1, 2012, the EPA released its final determination of nonattainment areas based on the 2008 eight-hour ozone air quality standards. None of the areas within Mississippi Powers service territory were designated as nonattainment areas.
On June 14, 2012, the EPA proposed a rule that would increase the stringency of the fine particulate matter national ambient air quality standards. If adopted, the proposed standards could result in the designation of new nonattainment areas within Mississippi Powers service territory. As part of a related settlement, the EPA has agreed to finalize the proposed rule by December 14, 2012. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Numerous petitions for administrative reconsideration of the MATS rule, including a petition by Southern Company and its subsidiaries, including Mississippi Power, have been filed with the EPA. Challenges to the final rule have also been filed in the U.S. District Court for the District of Columbia by numerous states, environmental organizations, industry groups, and others. The impact of the MATS rule will depend on the outcome of these and any other legal challenges and, therefore, cannot be determined at this time.
Water Quality
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations Water Quality of Mississippi Power in Item 7 of the Form 10-K for additional information on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
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Coal Combustion Byproducts
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations Coal Combustion Byproducts of Mississippi Power in Item 7 of the Form 10-K for additional information. Environmental groups and other parties have filed lawsuits in the U.S. District Court for the District of Columbia seeking to require the EPA to complete its rulemaking process and issue final regulations pertaining to the regulation of coal combustion byproducts. The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Global Climate Issues of Mississippi Power in Item 7 of the Form 10-K for additional information.
On April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.
On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPAs actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.
FERC Matters
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL FERC Matters of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under FERC Matters in Item 8 of the Form 10-K for additional information.
On January 20, 2012, Mississippi Power reached a settlement agreement with its wholesale customers, which was executed by all parties on March 9, 2012. The settlement agreement provides that base rates under the cost-based electric tariff will increase by approximately $22.6 million over a 12-month period with revised rates effective April 1, 2012. In 2012, the amount of base rate revenues to be received from the agreed upon increase will be approximately $17.0 million. On March 12, 2012, Mississippi Power filed an unopposed motion to place wholesale Municipal and Rural Associations (MRA) interim rates into effect pending approval of the settlement agreement between the parties by the FERC. On March 28, 2012, the FERC approved the motion to place interim rates into effect beginning in May 2012. Approval of the settlement agreement by the FERC has been delayed until later in 2012. The ultimate outcome of this matter cannot be determined at this time.
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MISSISSIPPI POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
PSC Matters
Performance Evaluation Plan
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Performance Evaluation Plan of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under Retail Regulatory Matters Performance Evaluation Plan in Item 8 of the Form 10-K for additional information regarding Mississippi Powers base rates.
On April 2, 2012, Mississippi Power filed a motion to suspend the 2011 PEP lookback filing. Unresolved matters related to certain costs included in the 2010 PEP lookback filing also impact the 2011 PEP lookback filing, making it impractical to determine Mississippi Powers actual retail return on investment for 2011 for purposes of the 2011 PEP lookback filing. An order granting the suspension of the 2011 PEP lookback was signed by the Mississippi PSC on May 8, 2012. The ultimate outcome of these matters cannot be determined at this time.
Environmental Compliance Overview Plan
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Environmental Compliance Overview Plan of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under Retail Regulatory Matters Environmental Compliance Overview Plan in Item 8 of the Form 10-K for information on Mississippi Powers annual environmental filing with the Mississippi PSC.
On February 14, 2012, Mississippi Power submitted its 2012 ECO Plan filing, which proposed a 0.3% increase in annual revenues for Mississippi Power. In compliance with the CPCN to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2, Mississippi Power revised the 2012 ECO Plan filing to exclude scrubber expenditures from rate base, which resulted in a 0.16% decrease in annual revenues. On June 22, 2012, the 2012 ECO Plan filing, including the proposed rate decrease, was approved by the Mississippi PSC, effective on June 29, 2012.
On April 3, 2012, the Mississippi PSC approved Mississippi Powers request for a CPCN to construct a scrubber on Plant Daniel Units 1 and 2. On May 3, 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court of Harrison County, Mississippi (Chancery Court). These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Powers portion being $330 million, excluding AFUDC. The project is scheduled for completion in December 2015. Mississippi Powers portion of the cost is expected to be recovered through the ECO Plan. As of June 30, 2012, total project expenditures were $82.0 million, with Mississippi Powers portion being $41.0 million. The ultimate outcome of this matter cannot be determined at this time.
Certificated New Plant
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Certificated New Plant of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under Retail Regulatory Matters Certificated New Plant in Item 8 of the Form 10-K and Integrated Coal Gasification Combined Cycle herein for additional information.
On May 23, 2012, the Mississippi Public Utilities Staff signed a joint stipulation with Mississippi Power to establish a new rate schedule for CNP-A, a proposed cost recovery mechanism designed specifically to recover financing costs during the construction phase of the Kemper IGCC. An amended and restated stipulation was subsequently executed and filed on June 1, 2012. On June 14, 2012, Mississippi Power submitted to the Mississippi PSC a proposed supplemental compliance filing to establish the new CNP-A rate schedule and a stipulated rate increase based upon the revenue request of between $55.3 million and $58.6 million to recover financing costs over the remainder of 2012.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On June 22, 2012, the Mississippi PSC denied the proposed CNP-A rate schedule and the 2012 rate recovery filings submitted by Mississippi Power, pending a final ruling from the Mississippi Supreme Court regarding the motion for stay and notice of appeal filed by the Sierra Club on April 26, 2012 relating to the Mississippi PSCs issuance of the CPCN for the Kemper IGCC. On July 9, 2012, Mississippi Power appealed the Mississippi PSCs June 22, 2012 decision to the Mississippi Supreme Court and requested interim rates under bond of $55.3 million. On July 31, 2012, the Mississippi Supreme Court denied Mississippi Powers request for interim rates under bond while the Mississippi Supreme Court decides Mississippi Powers appeal of the Mississippi PSCs June 22, 2012 decision. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Fuel Cost Recovery of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under Retail Regulatory Matters Fuel Cost Recovery in Item 8 of the Form 10-K for information regarding Mississippi Powers fuel cost recovery.
At June 30, 2012, the amount of over recovered retail fuel costs included in Mississippi Powers Condensed Balance Sheets herein was $55.5 million compared to $42.4 million at December 31, 2011. Mississippi Power also has wholesale MRA and Market Based (MB) fuel cost recovery factors. At June 30, 2012, the amount of over recovered wholesale MRA and MB fuel costs included in Mississippi Powers Condensed Balance Sheets herein was $17.4 million and $2.4 million, respectively, compared to $14.3 million and $2.2 million, respectively, at December 31, 2011. In addition, at June 30, 2012 and December 31, 2011, the amount of over recovered MRA emissions allowance cost included in Mississippi Powers Condensed Balance Sheets herein was $1.0 million and $1.7 million, respectively. Mississippi Powers operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, any changes in the billing factors will not have a significant effect on Mississippi Powers revenues or net income, but will affect annual cash flow.
Integrated Coal Gasification Combined Cycle
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Integrated Coal Gasification Combined Cycle of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under Integrated Coal Gasification Combined Cycle in Item 8 of the Form 10-K for information regarding Mississippi Powers construction of the Kemper IGCC.
In May 2010, Mississippi Power filed a motion with the Mississippi PSC accepting the conditions contained in the Mississippi PSC order confirming Mississippi Powers application for a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC. In June 2010, the Mississippi PSC issued the CPCN (2010 MPSC Order).
In June 2010, the Sierra Club filed an appeal of the Mississippi PSCs June 2010 decision to grant the CPCN for the Kemper IGCC with the Chancery Court. Subsequently, in July 2010, the Sierra Club also filed an appeal directly with the Mississippi Supreme Court. In October 2010, the Mississippi Supreme Court dismissed the Sierra Clubs direct appeal. In February 2011, the Chancery Court issued a judgment affirming the 2010 MPSC Order and, in March 2011, the Sierra Club appealed the Chancery Courts decision to the Mississippi Supreme Court. On March 15, 2012, the Mississippi Supreme Court reversed the Chancery Courts decision and the 2010 MPSC Order and remanded the matter to the Mississippi PSC to correct the 2010 MPSC Order. The Mississippi Supreme Court concluded that the 2010 MPSC Order did not cite in sufficient detail substantial evidence upon which the Mississippi Supreme Court could determine the basis for the findings of the Mississippi PSC granting the CPCN.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On March 30, 2012, the Mississippi PSC issued temporary authorization for the continuation of construction of the Kemper IGCC. On April 24, 2012, the Mississippi PSC issued a detailed order on remand (2012 MPSC Order) confirming the CPCN for the Kemper IGCC subject to the same conditions set forth in the 2010 MPSC Order. On April 26, 2012, the Sierra Club filed a motion for stay and a notice of appeal of the 2012 MPSC Order with the Chancery Court. On May 18, 2012, Mississippi Powers motion to join the appeal was approved.
The certificated cost estimate of the Kemper IGCC is $2.4 billion, net of $245.3 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (CCPI2) and excluding the cost of the lignite mine and equipment and the carbon dioxide (CO2) pipeline facilities. The 2012 MPSC Order, like the 2010 MPSC Order, (1) approved a construction cost cap of up to $2.88 billion (exemptions from the cost cap include the cost of the lignite mine and equipment and the CO2 pipeline facilities and certain general exceptions, including change of law, force majeure, and beneficial capital), (2) provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Powers proposal, and (3) approved financing cost recovery on CWIP balances not to exceed the certificated cost estimate, which provided for the accrual of AFUDC in 2010 and 2011 and provides for the current recovery of financing costs on 100% of CWIP in 2012, 2013, and through May 1, 2014, (provided that the amount of CWIP allowed is (i) reduced by the amount of state and federal government construction cost incentives received by Mississippi Power in excess of $296 million to the extent that such amount increases cash flow for the pertinent regulatory period and (ii) justified by a showing that such CWIP allowance will benefit customers over the life of the Kemper IGCC). The current cost estimate of the Kemper IGCC is $2.88 billion, including a $72 million contingency.
The Mississippi PSC order established periodic prudence reviews during the annual CWIP review process. Of the total costs incurred through March 2009, $46 million has been reviewed and approved by the Mississippi PSC. A decision regarding the remaining $5 million has been deferred to a later date. The timing of the review of the remaining Kemper IGCC costs has not been determined.
The Kemper IGCC, expected to begin commercial operation in May 2014, will use locally mined lignite (an abundant, lower heating value coal) from a mine adjacent to the Kemper IGCC as fuel. The mine is scheduled to be placed into service in June 2013. In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site in Kemper County. The estimated capital cost of the mine is approximately $245 million, of which $99.9 million has been incurred through June 30, 2012.
In May 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC, a subsidiary of The North American Coal Corporation (Liberty Fuels), which will develop, construct, and manage the mining operations. Due to the fact that Liberty Fuels conducts all of its activities on behalf of Mississippi Power, Liberty Fuels qualifies as a variable interest entity for which Mississippi Power is the primary beneficiary. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. Consistent with the requirements of consolidation accounting, Liberty Fuels is consolidated in the financial statements of Mississippi Power and accordingly the asset retirement cost and the ARO have been recorded in Mississippi Powers financial statements. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses.
In December 2011, the Mississippi Department of Environmental Quality (MDEQ) approved the surface coal mining and the water pollution control permits for the mining operations operated by Liberty Fuels. On January 12, 2012, two individuals each filed a notice of appeal and a request for evidentiary hearing with the MDEQ regarding the surface coal mining and water pollution control permits. On March 8, 2012, the MDEQ permit board affirmed its issuance of the surface coal mining and water pollution control permits.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In 2009, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $133 million of Internal Revenue Code Section 48A tax credits (Phase I) to Mississippi Power. In April 2011, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $279 million of Internal Revenue Code Section 48A tax credits (Phase II) to Mississippi Power. The utilization of Phase I and Phase II credits is dependent upon meeting the IRS certification requirements, including an in-service date no later than May 11, 2014 for the Phase I credits and April 19, 2016 for the Phase II credits. In order to remain eligible for the Phase II credits, Mississippi Power plans to capture and sequester (via enhanced oil recovery) at least 65% of the CO2 produced by the Kemper IGCC during operations in accordance with the recapture rules for Section 48A investment tax credits. Through June 30, 2012, Mississippi Power received or accrued tax benefits totaling $197 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC. Based on current tax laws and regulations in effect, Mississippi Power expects to receive substantially all of the tax credits accrued through June 30, 2012 by June 30, 2013.
In July 2010, Mississippi Power and SMEPA entered into an asset purchase agreement whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In December 2010, Mississippi Power and SMEPA filed a joint petition with the Mississippi PSC requesting regulatory approval of SMEPAs 17.5% undivided interest in the Kemper IGCC. On February 28, 2012, the Mississippi PSC approved the joint petition for the sale and transfer of 17.5% of the Kemper IGCC to SMEPA. On June 29, 2012, Mississippi Power and SMEPA signed an amendment to the asset purchase agreement whereby SMEPA extended its option to purchase until December 31, 2012 and reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC, subject to approval by the Mississippi PSC. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions.
On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the purchase. While the expectation is that the amount will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposit upon the termination of the asset purchase agreement, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPAs discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moodys or ceases to be rated by either of these rating agencies. Given the interest-bearing nature of the deposit and SMEPAs ability to request a refund, the deposit has been presented as a current liability in Mississippi Powers Condensed Balance Sheet herein and as financing proceeds in Mississippi Powers Condensed Statement of Cash Flows herein.
As of June 30, 2012, Mississippi Power had spent a total of $1.7 billion on the Kemper IGCC including the cost of the lignite mine and equipment, the CO2 pipeline facilities, and regulatory filing costs. Of this total, $1.6 billion was included in CWIP (which is net of $245.3 million of CCPI2 grant funds), $29.0 million was recorded in other regulatory assets, $2.6 million was recorded in other deferred charges and assets, and $1.0 million was previously expensed.
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters Certificated New Plant of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under Retail Regulatory Matters Certificated New Plant in Item 8 of the Form 10-K and PSC Matters Certificated New Plant herein for information on the proposed rate schedules related to the Kemper IGCC.
The ultimate outcome of these matters cannot be determined at this time.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Tax Matters
Bonus Depreciation
In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013). Due to the significant amount of estimated bonus depreciation for 2012, the utilization of a portion of Mississippi Powers tax credits has been delayed, thereby offsetting the positive cash flow benefit of bonus depreciation for Mississippi Power in 2012. Mississippi Power expects to receive substantially all of the tax credits accrued through June 30, 2012 by June 30, 2013.
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Integrated Coal Gasification Combined Cycle herein for additional information.
Other Matters
Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Powers business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) herein or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Powers financial statements.
See the Notes to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Mississippi Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Mississippi Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Mississippi Powers results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENTS DISCUSSION AND ANALYSIS ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates of Mississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Powers critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Overview of Mississippi Power in Item 7 of the Form 10-K for additional information. Mississippi Powers financial condition remained stable at June 30, 2012. Mississippi Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See Sources of Capital, Financing Activities, and Capital Requirements and Contractual Obligations herein for additional information.
Net cash provided from operating activities totaled $44.2 million for the first six months of 2012 compared to $90.7 million for the corresponding period in 2011. The $46.5 million decrease in cash provided from operating activities is primarily due to a $15.6 million decrease in investment tax credits received, a $16.0 million decrease in hedge settlements related to the settlement of interest rate swaps, a $24.0 million increase in fuel inventory, and a $14.5 million decrease in accounts payable primarily due to timing of cash payments. These decreases in cash provided from operating activities are partially offset by a $26.6 million increase in over recovered regulatory clause revenues primarily due to lower fuel costs.
Net cash used for investing activities totaled $711.1 million for the first six months of 2012 compared to $198.2 million for the corresponding period in 2011. The $512.9 million increase in net cash used for investing activities is primarily due to an increase in property additions of $398.4 million primarily related to the Kemper IGCC, a $50.0 million decrease in restricted cash, a $25.3 million increase in construction payable, and an $85.5 million decrease in capital grant proceeds related to CCPI2 and smart grid investment grants.
Net cash provided from financing activities totaled $608.7 million for the first six months of 2012 compared to $6.4 million for the corresponding period in 2011. The $602.3 million increase in net cash provided from financing activities was primarily due to the issuance of $400.0 million of senior notes in March 2012, a $176.8 million increase in capital contributions from Southern Company, a $75.0 million decrease in other long-term debt issuances, and the receipt of a $150.0 million interest-bearing refundable deposit related to a pending asset sale, partially offset by a $35.0 million increase in redemptions of long-term debt in the second quarter 2012 compared to the corresponding period in 2011.
Significant balance sheet changes for the first six months of 2012 include a decrease in cash and cash equivalents of $58.2 million primarily due to $165.0 million of long-term debt redemptions and payments and increased capital spending, partially offset by the issuance of $400.0 million of senior notes and the receipt of a $150.0 million interest-bearing refundable deposit from SMEPA to be applied towards its pending purchase of an undivided interest in the Kemper IGCC. Prepaid income taxes increased $154.3 million primarily due to the Kemper IGCC investment tax credit. Total property, plant, and equipment increased $764.7 million primarily due to the increase in CWIP related to the Kemper IGCC. Interest-bearing refundable deposit related to an asset sale increased $150.0 million due to the receipt of the $150.0 million interest-bearing refundable deposit from SMEPA. Long-term debt increased $307.1 million primarily due to the issuance of $400.0 million of senior notes, partially offset by the redemption of $90.0 million of senior notes. Paid-in capital increased $280.3 million primarily due to a $275.0 million capital contribution from Southern Company.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Capital Requirements and Contractual Obligations
See MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Capital Requirements and Contractual Obligations of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Powers capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental regulations, lease obligations, purchase commitments, derivative obligations, preferred stock dividends, and trust funding requirements. Approximately $165 million will be required through June 30, 2013 to fund maturities of long-term debt.
See FUTURE EARNINGS POTENTIAL Environmental Statutes and Regulations General herein for a description of Mississippi Powers estimated capital expenditures to comply with the MATS rule and proposed water and coal combustion byproducts rules.
See Note 7 to the financial statements of Mississippi Power in Item 8 of the Form 10-K for information on Mississippi Powers construction program. The construction program of Mississippi Power is currently estimated to include a base level investment of $1.8 billion, $843 million, and $418 million for 2012, 2013, and 2014, respectively. Included in these estimated amounts are expenditures related to the Kemper IGCC of $1.6 billion, $603 million, and $141 million in 2012, 2013, and 2014, respectively, which include additional AFUDC due to the delay in the rate recovery and are net of SMEPAs 15% expected ownership share of the Kemper IGCC of approximately $482 million and $14 million in 2013 and 2014, respectively. See FUTURE EARNINGS POTENTIAL PSC Matters Certificated New Plant and Integrated Coal Gasification Combined Cycle herein for additional information.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet new regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Except as described below with respect to potential DOE loan guarantees, Mississippi Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily funds from operating cash flows, security issuances, term loans, short-term borrowings, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. During the first six months of 2012, Mississippi Power received $275 million in capital contributions from Southern Company. On July 13, 2012, Mississippi Power received $150 million in additional capital contributions from Southern Company. On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA towards its pending purchase of an undivided interest in the Kemper IGCC. Until the acquisition is closed, the deposit bears interest at Mississippi Powers AFUDC rate, which was 9.967% per annum at June 30, 2012. While the expectation is that the amount will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposit upon the termination of the asset purchase agreement, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPAs discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moodys or ceases to be rated by either of these rating agencies. See MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Sources of Capital of Mississippi Power in Item 7 of the Form 10-K for additional information.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE. There can be no assurance that the DOE will issue federal loan guarantees to Mississippi Power. In the event that the DOE does not issue a conditional commitment or a final definitive loan guarantee, Mississippi Power intends to finance the construction of the Kemper IGCC through traditional capital markets financings. Mississippi Power has received $245.3 million in DOE CCPI2 grant funds that were used for the construction of the Kemper IGCC. An additional $25 million in CCPI2 grant funds is expected to be received for the initial operation of the Kemper IGCC.
Mississippi Powers current liabilities sometimes exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business.
At June 30, 2012, Mississippi Power had approximately $153.4 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2012, including expiration dates, were as follows:
Expires | Executable Term Loans |
Due Within One Year(a) | ||||||||||||||
2012 | 2013 | 2014 | Total | Unused | One Year |
Two Years |
Term Out |
No Term Out | ||||||||
|
|
|
| |||||||||||||
(in millions) | (in millions) | (in millions) | (in millions) | |||||||||||||
$41 | $95 | $165 | $301 | $301 | $25 | $41 | $66 | $70 |
(a) | Reflects facilities expiring on or before June 30, 2013. |
See Note 6 to the financial statements of Mississippi Power under Bank Credit Arrangements in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under Bank Credit Arrangements herein for additional information.
Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of Mississippi Power. Mississippi Power is currently in compliance with all such covenants. Mississippi Power expects to renew its credit arrangements, as needed, prior to expiration. These credit arrangements provide liquidity support to Mississippi Powers commercial paper borrowings and variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2012 was approximately $40 million.
Mississippi Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Mississippi Power are loaned directly to Mississippi Power. The obligations of each traditional operating company under these arrangements are several and there is no cross affiliate credit support.
Mississippi Power had no commercial paper or short-term debt outstanding during the six months ended June 30, 2012.
Management believes that the need for working capital can be adequately met by utilizing commercial paper, lines of credit, and cash.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Credit Rating Risk
Mississippi Power does not have any credit arrangements with banks that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are for physical electricity sales, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At June 30, 2012, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $311 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Mississippi Power also has entered into an asset purchase agreement with SMEPA for the pending purchase of an undivided interest in the Kemper IGCC that could require a refund of the $150 million deposit within 15 days at SMEPAs discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moodys or ceases to be rated by either of these rating agencies. Additionally, any credit rating downgrade could impact Mississippi Powers ability to access capital markets, particularly the short-term debt market.
On July 3, 2012, Fitch downgraded the issuer default and unsecured long-term debt ratings of Mississippi Power to A- from A and to A from A+, respectively. Fitch also announced that it had downgraded the pollution control revenue bond ratings of Mississippi Power to A from A+ and the preferred stock ratings of Mississippi Power to BBB+ from A-. Fitch revised the ratings outlook for Mississippi Power to negative from stable.
Market Price Risk
Mississippi Powers market risk exposure relative to interest rate changes for the second quarter 2012 has not changed materially compared with the December 31, 2011 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Mississippi Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Due to cost-based rate regulation and other various cost recovery mechanisms, Mississippi Power continues to have limited exposure to market volatility in interest rates, foreign currency, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Mississippi Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Mississippi Power continues to manage retail fuel-hedging programs implemented per the guidelines of the Mississippi PSC and wholesale fuel-hedging programs under agreements with wholesale customers. As such, Mississippi Power had no material change in market risk exposure for the second quarter 2012 when compared with the December 31, 2011 reporting period.
The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three and six months ended June 30, 2012 were as follows:
Second Quarter 2012 Changes |
Year-to-Date 2012 Changes | |||
| ||||
Fair Value | ||||
(in millions) | ||||
Contracts outstanding at the beginning of the period, assets (liabilities), net |
$(56) | $(51) | ||
Contracts realized or settled |
15 | 25 | ||
Current period changes(a) |
4 | (11) | ||
| ||||
Contracts outstanding at the end of the period, assets (liabilities), net |
$(37) | $(37) | ||
|
(a) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The changes in the fair value positions of the energy-related derivative contracts, which are substantially all attributable to both the volume and the price of natural gas, for the three and six months ended June 30, 2012 were as follows:
Second Quarter 2012 Changes |
Year-to-Date 2012 Changes | |||
| ||||
Fair Value | ||||
| ||||
(in millions) | ||||
Natural gas swaps |
$14 | $11 | ||
Natural gas options |
5 | 3 | ||
Other energy-related derivatives |
| | ||
| ||||
Total changes |
$19 | $14 | ||
|
The net hedge volumes of energy-related derivative contracts were as follows:
June 30, 2012 |
March 31, 2012 |
December 31, 2011 | ||||
| ||||||
mmBtu Volume | ||||||
(in millions) | ||||||
Commodity Natural gas swaps |
29 | 21 | 22 | |||
Commodity Natural gas options |
5 | 7 | 9 | |||
| ||||||
Total hedge volume |
34 | 28 | 31 | |||
|
The weighted average swap contract cost above market prices was approximately $1.08 per mmBtu as of June 30, 2012, $2.13 per mmBtu as of March 31, 2012, and $1.98 per mmBtu as of December 31, 2011. The change in option premiums is primarily attributable to the volatility of the market and the underlying change in the natural gas price. The majority of the costs associated with natural gas hedges are recovered through Mississippi Powers energy cost management clause (ECM).
Regulatory hedges relate to Mississippi Powers fuel-hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through Mississippi Powers ECM.
Unrealized pre-tax gains and losses recognized in income for the three and six months ended June 30, 2012 and 2011 for energy-related derivative contracts that are not hedges were not material.
Mississippi Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at June 30, 2012 were as follows:
June 30, 2012 Fair Value Measurements | ||||||||
| ||||||||
Total | Maturity | |||||||
Fair Value | Year 1 | Years 2&3 | Years 4&5 | |||||
| ||||||||
(in millions) | ||||||||
Level 1 |
$ | $ | $ | $ | ||||
Level 2 |
(37) | (25) | (11) | (1) | ||||
Level 3 |
| | | | ||||
| ||||||||
Fair value of contracts outstanding at end of period |
$(37) | $(25) | $(11) | $(1) | ||||
|
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MISSISSIPPI POWER COMPANY
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Mississippi Power. Regulations to implement the Dodd-Frank Act will impose additional requirements on the use of over-the-counter derivatives for both Mississippi Power and its derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Mississippi Power does not expect the impact of these rules to be material.
For additional information, see MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Market Price Risk of Mississippi Power in Item 7 and Note 1 under Financial Instruments and Note 10 to the financial statements of Mississippi Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
In March 2012, Mississippi Power issued $250 million aggregate principal amount of Series 2012A 4.25% Senior Notes due March 15, 2042 and an additional $150 million aggregate principal amount of Series 2011A 2.35% Senior Notes due October 15, 2016. The Series 2011A Senior Notes were of the same series of notes that were originally issued in October 2011 in the aggregate principal amount of $150 million. Upon completion of this offering, the aggregate principal amount of the outstanding Series 2011A Senior Notes was $300 million. The proceeds from the sales of the Series 2012A Senior Notes and the Series 2011A Senior Notes were used to repay a bank loan in an aggregate principal amount of $75 million and for general corporate purposes, including Mississippi Powers continuous construction program.
In March 2012, $300 million in interest rate swaps were settled, of which $250 million related to the Series 2012A Senior Notes at a loss of approximately $13.3 million, which will be amortized to interest expense, in earnings, over 10 years, and $50 million related to the Series 2011A Senior Notes at a loss of approximately $2.7 million, which will be amortized to interest expense, in earnings, over 10 years.
On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. Until the acquisition is closed, the deposit bears interest at Mississippi Powers AFUDC rate, which was 9.967% per annum at June 30, 2012, and is refundable to SMEPA upon termination of the asset purchase agreement related to such purchase, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPAs discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moodys or ceases to be rated by either of these rating agencies.
In May 2012, Mississippi Power redeemed $90 million aggregate principal amount of Series E 5-5/8% Senior Notes due May 1, 2033.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Mississippi Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
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AND SUBSIDIARY COMPANIES
132
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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the Three Months Ended June 30, |
For the Six Months Ended June 30, |
|||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in thousands) | (in thousands) | |||||||||||||||
Operating Revenues: |
||||||||||||||||
Wholesale revenues, non-affiliates |
$ | 177,865 | $ | 232,960 | $ | 318,422 | $ | 430,126 | ||||||||
Wholesale revenues, affiliates |
105,950 | 70,569 | 217,738 | 153,843 | ||||||||||||
Other revenues |
1,990 | 1,680 | 3,326 | 3,027 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total operating revenues |
285,805 | 305,209 | 539,486 | 586,996 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Operating Expenses: |
||||||||||||||||
Fuel |
91,551 | 101,158 | 180,629 | 203,873 | ||||||||||||
Purchased power, non-affiliates |
22,514 | 19,664 | 43,164 | 28,606 | ||||||||||||
Purchased power, affiliates |
2,914 | 22,178 | 5,254 | 37,277 | ||||||||||||
Other operations and maintenance |
40,205 | 40,047 | 88,594 | 82,801 | ||||||||||||
Depreciation and amortization |
34,016 | 30,805 | 65,929 | 60,972 | ||||||||||||
Taxes other than income taxes |
4,567 | 4,565 | 9,535 | 9,328 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total operating expenses |
195,767 | 218,417 | 393,105 | 422,857 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Operating Income |
90,038 | 86,792 | 146,381 | 164,139 | ||||||||||||
Other Income and (Expense): |
||||||||||||||||
Interest expense, net of amounts capitalized |
(13,949 | ) | (17,774 | ) | (27,591 | ) | (36,603 | ) | ||||||||
Other income (expense), net |
(194 | ) | (260 | ) | (164 | ) | (201 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other income and (expense) |
(14,143 | ) | (18,034 | ) | (27,755 | ) | (36,804 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Earnings Before Income Taxes |
75,895 | 68,758 | 118,626 | 127,335 | ||||||||||||
Income taxes |
29,293 | 24,157 | 42,708 | 44,991 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net Income |
$ | 46,602 | $ | 44,601 | $ | 75,918 | $ | 82,344 | ||||||||
|
|
|
|
|
|
|
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
For the Three Months Ended June 30, |
For the Six Months Ended June 30, |
|||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in thousands) | (in thousands) | |||||||||||||||
Net Income |
$ | 46,602 | $ | 44,601 | $ | 75,918 | $ | 82,344 | ||||||||
Other comprehensive income (loss): |
||||||||||||||||
Qualifying hedges: |
||||||||||||||||
Changes in fair value, net of tax of $53, $(23), $(120) and $400, respectively |
88 | (35 | ) | (186 | ) | 608 | ||||||||||
Reclassification adjustment for amounts included in net income, net of tax of $956, $1,084, $1,912 and $2,155, respectively |
1,529 | 1,631 | 3,039 | 3,261 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other comprehensive income (loss) |
1,617 | 1,596 | 2,853 | 3,869 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Comprehensive Income |
$ | 48,219 | $ | 46,197 | $ | 78,771 | $ | 86,213 | ||||||||
|
|
|
|
|
|
|
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.
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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
For the Six Months Ended June 30, |
||||||||
2012 | 2011 | |||||||
(in thousands) | ||||||||
Operating Activities: |
||||||||
Net income |
$ | 75,918 | $ | 82,344 | ||||
Adjustments to reconcile net income to net cash provided from operating activities |
||||||||
Depreciation and amortization, total |
71,834 | 65,877 | ||||||
Deferred income taxes |
58,921 | 12,315 | ||||||
Convertible investment tax credits |
1,750 | 62,298 | ||||||
Deferred revenues |
(16,431 | ) | (23,776 | ) | ||||
Mark-to-market adjustments |
(3,847 | ) | 853 | |||||
Other, net |
1,927 | 3,590 | ||||||
Changes in certain current assets and liabilities |
||||||||
-Receivables |
(30,101 | ) | (19,276 | ) | ||||
-Fossil fuel stock |
(3,301 | ) | 41 | |||||
-Materials and supplies |
(7,761 | ) | (4,431 | ) | ||||
-Prepaid income taxes |
(32,804 | ) | 1,282 | |||||
-Other current assets |
(377 | ) | 1,810 | |||||
-Accounts payable |
(494 | ) | 3,079 | |||||
-Accrued taxes |
13,295 | 7,737 | ||||||
-Accrued interest |
409 | 50 | ||||||
-Other current liabilities |
(195 | ) | (497 | ) | ||||
|
|
|
|
|||||
Net cash provided from operating activities |
128,743 | 193,296 | ||||||
|
|
|
|
|||||
Investing Activities: |
||||||||
Plant acquisition |
(86,500 | ) | | |||||
Property additions |
(67,846 | ) | (162,004 | ) | ||||
Change in construction payables |
(1,168 | ) | (14,231 | ) | ||||
Payments pursuant to long-term service agreements |
(36,316 | ) | (24,874 | ) | ||||
Other investing activities |
153 | (3,212 | ) | |||||
|
|
|
|
|||||
Net cash used for investing activities |
(191,677 | ) | (204,321 | ) | ||||
|
|
|
|
|||||
Financing Activities: |
||||||||
Increase (decrease) in notes payable, net |
107,147 | (68,941 | ) | |||||
Proceeds Capital contributions |
490 | 120,574 | ||||||
Other long-term debt |
3,590 | | ||||||
Repayments Other long-term debt |
(650 | ) | (3,116 | ) | ||||
Payment of common stock dividends |
(63,500 | ) | (45,600 | ) | ||||
Other financing activities |
2,746 | 146 | ||||||
|
|
|
|
|||||
Net cash provided from financing activities |
49,823 | 3,063 | ||||||
|
|
|
|
|||||
Net Change in Cash and Cash Equivalents |
(13,111 | ) | (7,962 | ) | ||||
Cash and Cash Equivalents at Beginning of Period |
16,943 | 14,204 | ||||||
|
|
|
|
|||||
Cash and Cash Equivalents at End of Period |
$ | 3,832 | $ | 6,242 | ||||
|
|
|
|
|||||
Supplemental Cash Flow Information: |
||||||||
Cash paid (received) during the period for |
||||||||
Interest (net of $12,941 and $8,855 capitalized for 2012 and 2011, respectively) |
$ | 21,461 | $ | 37,413 | ||||
Income taxes, net |
13,708 | (31,142 | ) | |||||
Noncash transactions accrued property additions at end of period |
46,922 | 21,077 |
The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.
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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Assets |
At June 30, 2012 |
At December 31, 2011 |
||||||
(in thousands) | ||||||||
Current Assets: |
||||||||
Cash and cash equivalents |
$ | 3,832 | $ | 16,943 | ||||
Receivables |
||||||||
Customer accounts receivable |
74,413 | 59,360 | ||||||
Other accounts receivable |
2,792 | 2,122 | ||||||
Affiliated companies |
52,796 | 36,508 | ||||||
Fossil fuel stock, at average cost |
16,339 | 13,038 | ||||||
Materials and supplies, at average cost |
45,700 | 37,603 | ||||||
Prepaid service agreementscurrent |
59,784 | 28,621 | ||||||
Prepaid income taxes |
43,720 | 5,192 | ||||||
Other prepaid expenses |
4,390 | 4,645 | ||||||
Assets from risk management activities |
393 | 177 | ||||||
|
|
|
|
|||||
Total current assets |
304,159 | 204,209 | ||||||
|
|
|
|
|||||
Property, Plant, and Equipment: |
||||||||
In service |
3,602,377 | 3,167,840 | ||||||
Less accumulated provision for depreciation |
710,351 | 652,087 | ||||||
|
|
|
|
|||||
Plant in service, net of depreciation |
2,892,026 | 2,515,753 | ||||||
Construction work in progress |
407,289 | 666,280 | ||||||
|
|
|
|
|||||
Total property, plant, and equipment |
3,299,315 | 3,182,033 | ||||||
|
|
|
|
|||||
Other Property and Investments: |
||||||||
Goodwill |
1,839 | 1,839 | ||||||
Other intangible assets, net of amortization of $1,867 and $1,476 at June 30, 2012 and December 31, 2011, respectively |
47,253 | 47,644 | ||||||
|
|
|
|
|||||
Total other property and investments |
49,092 | 49,483 | ||||||
|
|
|
|
|||||
Deferred Charges and Other Assets: |
||||||||
Prepaid long-term service agreements |
100,971 | 115,838 | ||||||
Other deferred charges and assets affiliated |
5,259 | 3,029 | ||||||
Other deferred charges and assets non-affiliated |
26,637 | 26,385 | ||||||
|
|
|
|
|||||
Total deferred charges and other assets |
132,867 | 145,252 | ||||||
|
|
|
|
|||||
Total Assets |
$ | 3,785,433 | $ | 3,580,977 | ||||
|
|
|
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.
135
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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholders Equity |
At June 30, 2012 |
At December 31, 2011 |
||||||
(in thousands) | ||||||||
Current Liabilities: |
||||||||
Securities due within one year |
$ | | $ | 555 | ||||
Notes payable non-affiliated |
289,241 | 179,520 | ||||||
Accounts payable |
||||||||
Affiliated |
60,378 | 63,609 | ||||||
Other |
46,360 | 44,321 | ||||||
Accrued taxes |
||||||||
Accrued income taxes |
5,473 | 2,548 | ||||||
Other accrued taxes |
10,526 | 2,158 | ||||||
Accrued interest |
22,284 | 21,874 | ||||||
Liabilities from risk management activities |
6,645 | 9,651 | ||||||
Other current liabilities |
18,940 | 7,401 | ||||||
|
|
|
|
|||||
Total current liabilities |
459,847 | 331,637 | ||||||
|
|
|
|
|||||
Long-term Debt |
1,303,691 | 1,302,758 | ||||||
|
|
|
|
|||||
Deferred Credits and Other Liabilities: |
||||||||
Accumulated deferred income taxes |
382,832 | 319,790 | ||||||
Deferred convertible investment tax credits |
131,696 | 125,065 | ||||||
Deferred capacity revenues affiliated |
8,389 | 20,637 | ||||||
Other deferred credits and liabilities affiliated |
3,147 | 3,618 | ||||||
Other deferred credits and liabilities non-affiliated |
4,743 | 4,965 | ||||||
|
|
|
|
|||||
Total deferred credits and other liabilities |
530,807 | 474,075 | ||||||
|
|
|
|
|||||
Total Liabilities |
2,294,345 | 2,108,470 | ||||||
|
|
|
|
|||||
Redeemable Noncontrolling Interest |
6,644 | 3,825 | ||||||
|
|
|
|
|||||
Common Stockholders Equity: |
||||||||
Common stock, par value $.01 per share |
||||||||
Authorized 1,000,000 shares |
||||||||
Outstanding 1,000 shares |
| | ||||||
Paid-in capital |
1,028,701 | 1,028,210 | ||||||
Retained earnings |
459,719 | 447,301 | ||||||
Accumulated other comprehensive loss |
(3,976 | ) | (6,829 | ) | ||||
|
|
|
|
|||||
Total common stockholders equity |
1,484,444 | 1,468,682 | ||||||
|
|
|
|
|||||
Total Liabilities and Stockholders Equity |
$ | 3,785,433 | $ | 3,580,977 | ||||
|
|
|
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.
136
Table of Contents
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SECOND QUARTER 2012 vs. SECOND QUARTER 2011
AND
YEAR-TO-DATE 2012 vs. YEAR-TO-DATE 2011
OVERVIEW
Southern Power and its wholly-owned subsidiaries construct, acquire, own, and manage generation assets, including renewable energy projects, and sell electricity at market-based prices in the wholesale market. Southern Power continues to execute its strategy through a combination of acquiring and constructing new power plants and by entering into PPAs primarily with investor owned utilities, independent power producers, municipalities, and electric cooperatives. In accordance with this strategy, the Nacogdoches biomass plant began commercial operation on June 22, 2012. See FUTURE EARNINGS POTENTIAL Construction Projects herein for additional information.
To evaluate operating results and to ensure Southern Powers ability to meet its contractual commitments to customers, Southern Power focuses on several key performance indicators. These indicators include peak season equivalent forced outage rate (Peak Season EFOR), contract availability, and net income. Peak Season EFOR defines the hours during peak demand times when Southern Powers generating units are not available due to forced outages (the lower the better). Contract availability measures the percentage of scheduled hours that a unit was available. Net income is the primary measure of Southern Powers financial performance. For additional information on these indicators, see MANAGEMENTS DISCUSSION AND ANALYSIS OVERVIEW Key Performance Indicators of Southern Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$2.0 |
4.5 | $(6.4) | (7.8) | |||
|
Southern Powers net income for the second quarter 2012 was $46.6 million compared to $44.6 million for the corresponding period in 2011. The increase was primarily due to an increase in energy revenues from sales to affiliates under the IIC, lower fuel and purchased power expenses, and lower interest expense. The increase was partially offset by a decrease in energy revenues from non-affiliates, a decrease in capacity revenues due to a reduction in total MWs of capacity under long-term contracts, increased depreciation, and higher income taxes.
Southern Powers net income for year-to-date 2012 was $75.9 million compared to $82.3 million for the corresponding period in 2011. The decrease was primarily due to a decrease in energy revenues from non-affiliates, a decrease in capacity revenues due to a reduction in total MWs of capacity under long-term contracts, an increase in depreciation, and an increase in other operations and maintenance expenses. The decrease was partially offset by an increase in energy revenues from sales to affiliates under the IIC, lower fuel and purchased power expenses, and lower interest expense.
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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues Non-Affiliates
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(55.1) |
(23.6) | $(111.7) | (26.0) | |||
|
Wholesale energy sales to non-affiliates will vary depending on the energy demand of those customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Powers energy. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.
Wholesale revenues from non-affiliates for the second quarter 2012 were $177.9 million compared to $233.0 million for the corresponding period in 2011. The decrease was primarily due to a $60.8 million decrease in energy sales, reflecting a 40.3% decrease in the average price of energy, partially offset by a 1.8% increase in KWH sales. The decrease in revenue from energy sales was partially offset by a $5.7 million increase in capacity revenue due to an increase in the total MWs of capacity under contract with non-affiliates.
Wholesale energy sales to non-affiliates for year-to-date 2012 were $318.4 million compared to $430.1 million for the corresponding period in 2011. The decrease was primarily due to a $121.3 million decrease in energy sales, reflecting a 41.7% decrease in the average price of energy and a 4.0% decrease in KWH sales. The decrease in revenue from energy sales was partially offset by a $9.6 million increase in capacity revenue due to an increase in the total MWs of capacity under contract with non-affiliates.
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Power Sales Agreements of Southern Power in Item 7 of the Form 10-K for additional information.
Wholesale Revenues Affiliates
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$35.4 |
50.1 | $63.9 | 41.5 | |||
|
Wholesale energy sales to affiliated companies within the Southern Company system will vary depending on demand and the availability and cost of generating resources at each company. Sales to affiliate companies that are not covered by PPAs are made in accordance with the IIC, as approved by the FERC.
Wholesale revenues from affiliates for the second quarter 2012 were $106.0 million compared to $70.6 million for the corresponding period in 2011. The increase was primarily the result of a $45.4 million increase in energy sales under the IIC, reflecting a 435.1% increase in KWH sales, partially offset by a 37.4% reduction in the average price of energy. The increase in revenue from energy sales was partially offset by an $8.6 million decrease in capacity revenue due to a decrease in total MWs of capacity under contract with affiliates.
Wholesale revenues from affiliates for year-to-date 2012 were $217.7 million compared to $153.8 million for the corresponding period in 2011. The increase was primarily the result of an $87.2 million increase in energy sales under the IIC, reflecting a 360.3% increase in KWH sales, partially offset by a 40.6% reduction in the average price of energy. The increase in revenue from energy sales was partially offset by a $20.6 million decrease in capacity revenue due to a decrease in total MWs of capacity under contract with affiliates.
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Power Sales Agreements of Southern Power in Item 7 of the Form 10-K for additional information.
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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
Second Quarter 2012 vs. Second Quarter 2011 |
Year-to-Date 2012 vs. Year-to-Date 2011 | |||||||
| ||||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||||
Fuel |
$(9.6) | (9.5) | $(23.3) | (11.4) | ||||
Purchased power non-affiliates |
2.9 | 14.5 | 14.5 | 50.9 | ||||
Purchased power affiliates |
(19.3) | (86.9) | (32.0) | (85.9) | ||||
|
|
|||||||
Total fuel and purchased power expenses |
$(26.0) | $(40.8) | ||||||
|
|
Southern Power PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in fuel costs is generally accompanied by an increase or decrease in related fuel revenues and does not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the market or sold to affiliates under the IIC.
Purchased power expenses will vary depending on demand and the availability and cost of generating resources throughout the Southern Company system and other available contract resources. Load requirements are submitted to the Power Pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, affiliate-owned generation, or external purchases.
In the second quarter 2012, total fuel and purchased power expenses were $117.0 million compared to $143.0 million for the corresponding period in 2011. Fuel and purchased power expenses decreased $83.3 million due to a 44.8% decrease in the average cost of fuel and a 26.1% decrease in the average cost of purchased power. The decrease was partially offset by a $57.3 million net increase associated with a 43.1% increase in the volume of KWHs generated and purchased.
For year-to-date 2012, total fuel and purchased power expenses were $229.0 million compared to $269.8 million for the corresponding period in 2011. Fuel and purchased power expenses decreased $146.9 million due to a 41.8% decrease in the average cost of fuel and a 25.9% decrease in the average cost of purchased power. The decrease was partially offset by a $106.2 million net increase associated with a 41.3% increase in the volume of KWHs generated and purchased.
In the second quarter 2012, fuel expense was $91.6 million compared to $101.2 million for the corresponding period in 2011. The decrease was due to a $74.4 million decrease associated with the cost of fuel, partially offset by a $64.8 million increase associated with the volume of KWHs generated.
For year-to-date 2012, fuel expense was $180.6 million compared to $203.9 million for the corresponding period in 2011. The decrease was due to a $130.0 million decrease associated with the cost of fuel, partially offset by a $106.8 million increase associated with the volume of KWHs generated.
In the second quarter 2012, purchased power expenses were $25.4 million compared to $41.8 million for the corresponding period in 2011. The decrease was due to an $8.9 million decrease associated with the cost of purchased power and a $7.5 million decrease associated with the volume of KWHs purchased.
For year-to-date 2012, purchased power expenses were $48.4 million compared to $65.9 million for the corresponding period in 2011. The decrease was due to a $16.9 million decrease associated with the cost of purchased power and a $0.5 million decrease associated with the volume of KWHs purchased.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Operations and Maintenance Expenses
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$0.2 |
0.4 | $5.8 | 7.0 | |||
|
In the second quarter 2012, other operations and maintenance expenses were $40.2 million compared to $40.0 million for the corresponding period in 2011. The increase was not material.
For year-to-date 2012, other operations and maintenance expenses were $88.6 million compared to $82.8 million for the corresponding period in 2011. The increase was primarily due to a $4.0 million increase in administrative and general expenses primarily due to increases in business development expenses and affiliate service company expense allocated based on load and fuel burn and a $1.1 million increase in transmission cost.
Depreciation and Amortization
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$3.2 |
10.4 | $5.0 | 8.1 | |||
|
In the second quarter 2012, depreciation and amortization was $34.0 million compared to $30.8 million for the corresponding period in 2011. The increase was primarily due to a $1.3 million increase in depreciation resulting from an increase in plant in service, a $0.9 million increase due to higher depreciation rates from a depreciation study adopted in January 2012, and a $1.0 million increase in depreciation related to asset retirements.
For year-to-date 2012, depreciation and amortization was $65.9 million compared to $60.9 million for the corresponding period in 2011. The increase was primarily due to a $2.6 million increase in depreciation resulting from an increase in plant in service, a $1.7 million increase due to higher depreciation rates from a depreciation study adopted in January 2012, and a $0.6 million increase in depreciation related to asset retirements.
Interest Expense, Net of Amounts Capitalized
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$(3.9) |
(21.5) | $(9.0) | (24.6) | |||
|
In the second quarter 2012, interest expense, net of amounts capitalized was $13.9 million compared to $17.8 million for the corresponding period in 2011. The decrease was primarily due to a $2.2 million expense reduction associated with the refinancing of $575 million in long-term debt in 2011 and a $1.8 million increase in capitalized interest associated with the construction of the Cleveland County combustion turbine generating plant and the Nacogdoches biomass plant.
For year-to-date 2012, interest expense, net of amounts capitalized was $27.6 million compared to $36.6 million for the corresponding period in 2011. The decrease was primarily due to a $4.4 million expense reduction associated with the refinancing of $575 million in long-term debt in 2011 and a $4.1 million increase in capitalized interest associated with the construction of the Cleveland County combustion turbine generating plant and the Nacogdoches biomass plant.
See FUTURE EARNINGS POTENTIAL Construction Projects herein for additional information.
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Income Taxes
Second Quarter 2012 vs. Second Quarter 2011 | Year-to-Date 2012 vs. Year-to-Date 2011 | |||||
| ||||||
(change in millions) | (% change) | (change in millions) | (% change) | |||
$5.1 |
21.3 | $(2.3) | (5.1) | |||
|
In the second quarter 2012, income taxes were $29.3 million compared to $24.2 million for the corresponding period in 2011. The increase was primarily due to a $2.9 million increase associated with higher pre-tax earnings, a $1.2 million increase related to a decrease in investment tax credits (ITCs) recognized associated with the construction of the Nacogdoches biomass plant, and a $1.2 million increase in Alabama state income taxes due to a decrease in the state income tax deduction for federal income taxes paid.
For year-to-date 2012, income taxes were $42.7 million compared to $45.0 million for the corresponding period in 2011. The decrease was primarily due to a $3.4 million decrease associated with lower pre-tax earnings and a $2.2 million decrease due to the conclusion of prior year IRS audits, partially offset by a $2.5 million increase related to a decrease in ITCs recognized associated with the construction of the Nacogdoches biomass plant and a $1.2 million increase in Alabama state income taxes due to a decrease in the state income tax deduction for federal income taxes paid.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Powers future earnings potential. The level of Southern Powers future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Powers competitive wholesale business. These factors include: Southern Powers ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Powers target market areas; the successful remarketing of capacity as current contracts expire; and Southern Powers ability to execute its acquisition strategy and to construct generating facilities. Other factors that could influence future earnings include weather, demand, generation patterns, and operational limitations. General economic conditions have lowered demand and have negatively impacted capacity revenues under Southern Powers PPAs where the amounts purchased are based on demand. Southern Power is unable to predict whether demand under these PPAs will return to pre-recession levels. The timing and extent of the economic recovery is uncertain and will impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.
Environmental Matters
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Powers PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such regulatory or legislative changes cannot be determined at this time.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Climate Change Litigation
Hurricane Katrina Case
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Climate Change Litigation Hurricane Katrina Case of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under Climate Change Litigation Hurricane Katrina Case in Item 8 of the Form 10-K for additional information. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the amended class action complaint filed in May 2011 by the plaintiffs. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. The ultimate outcome of this matter cannot be determined at this time.
Water Quality
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations Water Quality of Southern Power in Item 7 of the Form 10-K for additional information on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Global Climate Issues
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters Global Climate Issues of Southern Power in Item 7 of the Form 10-K for additional information.
On April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.
On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPAs actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.
Income Tax Matters
Bonus Depreciation
In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Southern Power through 2013. Consequently, Southern Powers positive cash flow benefit is estimated to be between $145 million and $190 million in 2012.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Acquisitions
Apex Nevada Solar, LLC Acquisition
On June 29, 2012, Southern Power and Turner Renewable Energy, Inc. (TRE), through a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Apex Nevada Solar, LLC (Apex) from Sun Edison, LLC, the original developer of the project. Apex constructed and owns a 20-MW solar photovoltaic facility in North Las Vegas, Nevada. Commercial operation of the solar facility was declared by Apex on July 21, 2012. The output of the plant is contracted under a PPA with Nevada Power Company, a subsidiary of NV Energy, Inc., that began in 2012 and expires in 2037. See Note (I) to the Condensed Financial Statements herein for additional information.
Construction Projects
Cleveland County Units 1-4
In 2008, Southern Power announced plans to build an electric generating plant in Cleveland County, North Carolina. The plant will consist of four combustion turbine natural gas generating units with a total generating capacity of 720 MWs. The units are expected to begin commercial operation in December 2012. Construction costs incurred through June 30, 2012 were $292.5 million. The total estimated cost of the project is expected to be between $335 million and $365 million.
Nacogdoches Biomass Plant
In 2009, Southern Power acquired all of the outstanding membership interests of Nacogdoches Power, LLC (Nacogdoches) from American Renewables LLC, the original developer of the project. Nacogdoches constructed a biomass generating plant in Sacul, Texas with an estimated capacity of 100 MWs. The generating plant is fueled from wood waste. The plant began commercial operation on June 22, 2012. Project costs incurred through June 30, 2012 were $456.5 million. The final cost of the project is expected to be between $465 million and $470 million.
Power Sales Agreements
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Power Sales Agreements of Southern Power in Item 7 of the Form 10-K for additional information regarding Southern Powers PPAs with investor-owned utilities, independent power purchasers, municipalities, and electric cooperatives.
In June 2011, Southern Power entered into three PPAs with Georgia Power subject to Georgia PSC and FERC approval. These PPAs were approved by the Georgia PSC on March 20, 2012 and are still subject to approval by the FERC. The ultimate outcome of this matter cannot be determined at this time.
On June 29, 2012, a subsidiary of Southern Power assumed the PPA with Nevada Power Company in connection with the acquisition of Apex. Commercial operation was declared by Apex on July 21, 2012.
Other Matters
Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Powers business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common
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law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Power and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) herein or in Note 3 to the financial statements of Southern Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Powers financial statements.
See the Notes to the Condensed Financial Statements herein for a discussion of various other contingencies and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Power prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Powers results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENTS DISCUSSION AND ANALYSIS ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates of Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Powers critical accounting policies and estimates related to Revenue Recognition, Impairment of Long Lived Assets and Intangibles, Acquisition Accounting, Contingent Obligations, Depreciation, and Convertible Investment Tax Credits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Powers financial condition remained stable at June 30, 2012. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements as needed to meet future capital and liquidity needs. See Sources of Capital herein for additional information on lines of credit.
Net cash provided from operating activities totaled $128.7 million for the first six months of 2012 compared to $193.3 million for the corresponding period in 2011. The decrease was primarily due to cash received in 2011 for convertible ITCs. Net cash used for investing activities totaled $191.7 million for the first six months of 2012 compared to $204.3 million for the corresponding period in 2011. The decrease was primarily due to a decrease in CWIP expenditures related to construction activities at the Cleveland County and Nacogdoches facilities, partially offset by the acquisition of Apex. Net cash provided from financing activities totaled $49.8 million for the first six months of 2012 compared to $3.1 million for the corresponding period in 2011. The increase was primarily due to an increase in notes payable in 2012 and the repayment of a $65.9 million affiliate loan in 2011, partially offset by lower capital contributions from Southern Company due to contributions received in 2011 to fund construction activities.
Significant asset changes in the balance sheet for the first six months of 2012 include: a $15.1 million increase in accounts receivables from non-affiliated companies and a $16.3 million increase in accounts receivables from affiliated companies primarily due to the seasonality in PPAs; a $38.5 million increase in prepaid income taxes; and a $117.3 million increase in total property, plant, and equipment primarily due to the acquisition of Apex.
Significant liability and stockholders equity changes in the balance sheet for the first six months of 2012 include a $109.7 million increase in notes payable non-affiliated primarily due to the acquisition of Apex and a $63.0 million increase in accumulated deferred income taxes primarily due to bonus depreciation.
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Capital Requirements and Contractual Obligations
See MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Capital Requirements and Contractual Obligations of Southern Power in Item 7 of the Form 10-K for a description of Southern Powers capital requirements for its construction program, scheduled maturities of long-term debt, interest, leases, derivative obligations, purchase commitments, and long-term service agreements. There are no requirements through June 30, 2013 to fund maturities of long-term debt.
The construction program is subject to periodic review and revision; these amounts include estimates for potential plant acquisitions and new construction as well as ongoing capital improvements and work to be performed under long-term service agreements. Planned expenditures for plant acquisitions may vary due to market opportunities and Southern Powers ability to execute its growth strategy. Actual construction costs may vary from these estimates because of changes in factors such as: business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital.
Sources of Capital
Southern Power may use operating cash flows, external funds, or equity capital or loans from Southern Company to finance any new projects, acquisitions, and ongoing capital requirements. Southern Power expects to generate external funds from the issuance of unsecured senior debt and commercial paper or utilization of credit arrangements from banks. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Sources of Capital of Southern Power in Item 7 of the Form 10-K for additional information.
Southern Powers current liabilities frequently exceed current assets due to the use of short-term debt as a funding source, as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet liquidity and capital resource requirements, Southern Power had at June 30, 2012 cash and cash equivalents of approximately $3.8 million and a committed credit facility of $500 million (Facility) expiring in 2016. The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65% and contains a cross default provision that is restricted only to the indebtedness of Southern Power. Southern Power is currently in compliance with all such covenants. Proceeds from this Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Powers commercial paper program. See Note 6 to the financial statements of Southern Power under Bank Credit Arrangements in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under Bank Credit Arrangements herein for additional information.
Southern Powers commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes.
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Details of short-term borrowings were as follows:
Short-term Debt at the End of the Period |
Short-term Debt During the Period (a) | |||||||||||||||||||
Amount Outstanding |
Weighted Average Interest Rate |
Average Outstanding |
Weighted Average Interest Rate |
Maximum Amount Outstanding |
||||||||||||||||
|
|
|
||||||||||||||||||
(in millions) | (in millions) | (in millions) | ||||||||||||||||||
June 30, 2012: |
||||||||||||||||||||
Commercial paper |
$ | 287 | 0.5 | % | $ | 205 | 0.5 | % | $ | 287 | ||||||||||
|
(a) | Average and maximum amounts are based upon daily balances during the period. |
Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, and cash. In addition, $2.6 million in anticipated prepayment of notes payable to TRE has been reclassified as short-term debt.
Credit Rating Risk
Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.
The maximum potential collateral requirements under these contracts at June 30, 2012 were as follows:
Credit Ratings | Maximum Potential Collateral Requirements | |
| ||
(in millions) | ||
At BBB and Baa2 |
$ 9 | |
At BBB- and/or Baa3 |
451 | |
Below BBB- and/or Baa3 |
1,307 | |
|
Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Powers ability to access capital markets, particularly the short-term debt market.
In addition, through the acquisition of Plant Rowan, Southern Power assumed a PPA with North Carolina Municipal Power Agency No. 1 that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Powers credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade.
Market Price Risk
Southern Power is exposed to market risks, including changes in interest rates, certain energy-related commodity prices, and, occasionally, currency exchange rates. To manage the volatility attributable to these exposures, Southern Power takes advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Southern Powers policies in areas such as counterparty exposure and risk management practices. Southern Powers policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk
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management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress tests, and sensitivity analysis.
Southern Powers market risk exposure relative to interest rate changes for the second quarter 2012 has not changed materially compared with the December 31, 2011 reporting period. Since a significant portion of outstanding indebtedness bears interest at fixed rates, Southern Power is not aware of any facts or circumstances that would significantly affect exposure on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Because energy from Southern Powers facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, Southern Powers exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity.
The changes in fair value of energy-related derivative contracts for the three and six months ended June 30, 2012 were as follows:
Second Quarter 2012 Changes |
Year-to-Date 2012 Changes |
|||||||
|
||||||||
Fair Value | ||||||||
(in millions) | ||||||||
Contracts outstanding at the beginning of the period, assets (liabilities), net |
$ | (16.1) | $ | (9.2) | ||||
Contracts realized or settled |
8.4 | 9.2 | ||||||
Current period changes(a) |
2.0 | (5.7) | ||||||
|
||||||||
Contracts outstanding at the end of the period, assets (liabilities), net |
$ | (5.7) | $ | (5.7) | ||||
|
(a) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
The changes in the fair value positions of the energy-related derivative contracts for the three and six months ended June 30, 2012 were an increase of $10.4 million and $3.5 million, respectively, which are due to both power and natural gas positions. The changes are attributable to both the volume and prices of power and natural gas as follows:
June 30, 2012 |
March 31, 2012 |
December 31, 2011 | ||||
| ||||||
Power net purchased or (sold) |
||||||
| ||||||
MWHs (in millions) |
| (0.1) | 0.1 | |||
Weighted average contract cost per MWH above (below) market prices (in dollars) |
$ | $ (5.20) | $ (1.04) | |||
| ||||||
Natural gas net purchased |
||||||
| ||||||
Commodity million mmBtu |
18.3 | 28.2 | 8.3 | |||
Commodity weighted average contract cost per mmBtu above (below) market prices (in dollars) |
$0.83 | $ 1.57 | $ 1.18 | |||
|
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The fair value of energy-related derivative contracts by hedge designation reflected in the financial statements as assets (liabilities) consists of the following:
Asset (Liability) Derivatives | June 30, 2012 |
December 31, 2011 |
||||||
|
||||||||
(in millions) | ||||||||
Cash flow hedges |
$ (1.1) | $ (0.8) | ||||||
Not designated |
(4.6) | (8.4) | ||||||
|
||||||||
Total fair value |
$ (5.7) | $ (9.2) | ||||||
|
Gains and losses on energy-related derivatives used by Southern Power to hedge anticipated purchases and sales are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Total net unrealized pre-tax gains (losses) recognized in the statements of income for the three and six months ended June 30, 2012 for energy-related derivative contracts that were not hedges were $10.3 million and $3.8 million, respectively, and will continue to be marked to market until the settlement date. Included in these amounts are gains (losses) on derivative contracts payable to third parties in the amounts of $9.0 million and $3.8 million, respectively. For the three and six months ended June 30, 2011, the total net unrealized pre-tax gains (losses) recognized in the statements of income for energy-related derivative contracts that were not hedges were $(0.9) million and $(0.8) million, respectively.
Southern Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at June 30, 2012 were as follows:
June 30, 2012 Fair Value Measurements |
||||||||||||||||
|
||||||||||||||||
Total | Maturity | |||||||||||||||
Fair Value | Year 1 | Years 2&3 | Years 4&5 | |||||||||||||
|
||||||||||||||||
(in millions) | ||||||||||||||||
Level 1 |
$ | | $ | | $ | | $ | | ||||||||
Level 2 |
(5.7) | (6.2) | 0.1 | 0.4 | ||||||||||||
Level 3 |
| | | | ||||||||||||
|
||||||||||||||||
Fair value of contracts outstanding at end of period |
$ | (5.7) | $ | (6.2) | $ | 0.1 | $ | 0.4 | ||||||||
|
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Southern Power. Regulations to implement the Dodd-Frank Act will impose additional requirements on the use of over-the-counter derivatives for both Southern Power and its derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Southern Power does not expect the impact of these rules to be material.
For additional information, see MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Market Price Risk of Southern Power in Item 7 and Note 1 under Financial Instruments and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
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Financing Activities
In June 2012, Southern Power issued a $3.6 million promissory note, due June 15, 2032, to TRE related to the financing of Apex.
During the six months ended June 30, 2012, Southern Power prepaid $0.6 million of long-term debt.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS
FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
INDEX TO APPLICABLE NOTES TO
FINANCIAL STATEMENTS BY REGISTRANT
Registrant | Applicable Notes | |
Southern Company | A, B, C, D, E, F, G, H, J | |
Alabama Power | A, B, C, E, F, G, H | |
Georgia Power | A, B, C, E, F, G, H | |
Gulf Power | A, B, C, E, F, G, H | |
Mississippi Power | A, B, C, E, F, G, H | |
Southern Power | A, B, C, E, G, H, I |
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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
NOTES TO THE CONDENSED FINANCIAL STATEMENTS:
(A) | INTRODUCTION |
The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2011 have been derived from the audited financial statements of each registrant. In the opinion of each registrants management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2012 and 2011. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
Certain prior years data presented in the financial statements have been reclassified to conform to the current year presentation.
Investments in Leveraged Leases
See Note 1 to the financial statements of Southern Company under Leveraged Leases in Item 8 of the Form 10-K for additional information.
The recent financial and operational performance of one of Southern Companys lessees and the associated generation assets has raised potential concerns on the part of Southern Company as to the credit quality of the lessee and the residual value of the assets. Current projections indicate significant uncertainty as to whether the lessee will be able to pay the December 2012 semi-annual rent payment in full. Southern Company is currently engaged in discussions with the lessee and the holders of the projects nonrecourse debt to restructure the debt payments and the related rental payments to allow additional capital investment in the project to be made to improve the operation of the generation assets and the financial viability of the lease transaction. Southern Company believes there is a reasonable possibility that it will be able to reach an agreement with the lessee and the debtholders to restructure the project. However, due to continued poor performance of the generation assets and the uncertainties surrounding the receipt of the December 2012 semi-annual rent payment and its ability to successfully restructure the project, Southern Company has placed the lease on nonaccrual status whereby income associated with this investment will not be recognized in the financial statements beginning in July 2012. If the attempts at restructuring the project are unsuccessful and the project is ultimately abandoned, the potential impairment loss that would be incurred is approximately $90 million on an after-tax basis. The ultimate outcome of this matter cannot be determined at this time.
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(B) | CONTINGENCIES AND REGULATORY MATTERS |
See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.
General Litigation Matters
Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, business activities of Southern Companys subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of each registrant in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrants financial statements.
Insurance Recovery
Mirant Corporation (Mirant) was an energy company with businesses that included independent power projects and energy trading and risk management companies in the U.S. and other countries. Mirant was a wholly-owned subsidiary of Southern Company until its initial public offering in 2000. In 2001, Southern Company completed a spin-off to its stockholders of its remaining ownership, and Mirant became an independent corporate entity.
In 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. In 2005, Mirant, as a debtor in possession, and the unsecured creditors committee filed a complaint against Southern Company. Later in 2005, this complaint was transferred to MC Asset Recovery, LLC (MC Asset Recovery) as part of Mirants plan of reorganization. In 2009, Southern Company entered into a settlement agreement with MC Asset Recovery to resolve this action. The settlement included an agreement where Southern Company paid MC Asset Recovery $202 million. Southern Company filed an insurance claim in 2009 to recover a portion of this settlement and received a nontaxable $25 million payment from its insurance provider on June 14, 2012. Additionally, legal fees related to this insurance settlement totaled approximately $6 million. The net reduction to expense for this insurance settlement was approximately $19 million.
Environmental Matters
New Source Review Actions
In 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the NSR provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. The EPA alleged NSR violations at five coal-fired generating facilities operated by Alabama Power, including a unit co-owned by Mississippi Power, and three coal-fired generating facilities operated by Georgia Power, including a unit co-owned by Gulf Power. The civil action sought penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The case against Georgia Power (including claims related to the unit co-owned by Gulf Power) was administratively closed in 2001 and has not been reopened. After Alabama Power was dismissed from the original action, the EPA filed a separate action in 2001 against Alabama Power (including claims related to the unit co-owned by Mississippi Power) in the U.S. District Court for the Northern District of Alabama.
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In 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree, resolving claims relating to the alleged NSR violations at Plant Miller. In September 2010, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims, including one relating to the unit co-owned by Mississippi Power. In March 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power summary judgment on all remaining claims and dismissed the case with prejudice. That judgment is on appeal to the U.S. Court of Appeals for the Eleventh Circuit. On February 23, 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power (including claims related to a unit co-owned by Mississippi Power). The U.S. District Court for the Northern District of Alabama has not ruled on the EPAs motion seeking vacatur of the judgment.
Southern Company and each traditional operating company believe each such traditional operating company complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of these matters cannot be determined at this time.
Climate Change Litigation
Kivalina Case
In 2008, the Native Village of Kivalina and the City of Kivalina filed a lawsuit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs allege that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants (including Southern Company) acted in concert and are therefore jointly and severally liable for the plaintiffs damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. In 2009, the U.S. District Court for the Northern District of California granted the defendants motions to dismiss the case. The plaintiffs appealed the dismissal to the U.S. Court of Appeals for the Ninth Circuit. Southern Company believes that these claims are without merit. While Southern Company believes the likelihood of loss is remote based on existing case law, it is not possible to predict with certainty whether Southern Company will incur any liability in connection with this matter. The ultimate outcome of this matter cannot be determined at this time.
Hurricane Katrina Case
In 2005, immediately following Hurricane Katrina, a lawsuit was filed in the U.S. District Court for the Southern District of Mississippi by Ned Comer on behalf of Mississippi residents seeking recovery for property damage and personal injuries caused by Hurricane Katrina. In 2006, the plaintiffs amended the complaint to include Southern Company and many other electric utilities, oil companies, chemical companies, and coal producers. The plaintiffs allege that the defendants contributed to climate change, which contributed to the intensity of Hurricane Katrina. In 2007, the U.S. District Court for the Southern District of Mississippi dismissed the case. On appeal to the U.S. Court of Appeals for the Fifth Circuit, a three-judge panel reversed the U.S. District Court for the Southern District of Mississippi, holding that the case could proceed, but, on rehearing, the full U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs appeal, resulting in reinstatement of the decision of the U.S. District Court for the Southern District of Mississippi in favor of the defendants. In May 2011, the plaintiffs filed an amended version of their class action complaint, arguing that the earlier dismissal was on procedural grounds and under Mississippi law the plaintiffs have a right to re-file. The amended complaint was also filed against numerous chemical, coal, oil, and utility companies, including Alabama Power, Georgia Power, Gulf Power, and Southern Power. On March 20, 2012, the U.S. District Court for the Southern District of
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Mississippi dismissed the plaintiffs amended complaint. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. Each Southern Company entity named in the lawsuit believes that these claims are without merit. While each Southern Company entity named in the lawsuit believes the likelihood of loss is remote based on existing case law, it is not possible to predict with certainty whether any Southern Company entity named in the lawsuit will incur any liability in connection with this matter. The ultimate outcome of this matter cannot be determined at this time.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up properties. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs.
Georgia Powers environmental remediation liability as of June 30, 2012 was $20 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous Sites Inventory and the CERCLA NPL are anticipated.
In 2008, the EPA advised Georgia Power that it has been designated as a PRP at the Ward Transformer Superfund site located in Raleigh, North Carolina. Numerous other entities have also received notices regarding this site from the EPA. In September 2011, the EPA issued a unilateral administrative order (UAO) to Georgia Power and 22 other parties, ordering specific remedial action of certain areas at the Ward Transformer Superfund site. Georgia Power does not believe it is a liable party under CERCLA based on its alleged connection to the site. As a result, in November 2011, Georgia Power filed a response with the EPA indicating that Georgia Power is not willing to undertake the work set forth in the UAO because Georgia Power has sufficient cause to believe it is not a liable party. In November 2011, the EPA sent Georgia Power a letter stating that the EPA does not consider Georgia Power to be in compliance with the UAO. The EPA also stated that it is considering enforcement options against Georgia Power and other UAO recipients who are not complying with the UAO. The EPA may seek to enforce the UAO in court pursuant to its enforcement authority under CERCLA and may seek recovery of its costs in undertaking the UAO work. If the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the partys failure to comply with the UAO.
In addition to the EPAs action at the Ward Transformer Superfund site, in 2009, Georgia Power, along with many other parties, was sued by several existing PRPs for cost recovery for a removal action that is currently taking place. Georgia Power and numerous other defendants moved for a dismissal of these lawsuits. The court denied the dismissal of the lawsuits in March 2010 but granted Georgia Powers motion regarding the dismissal of the claim pertaining to the plaintiffs joint and several liability.
The ultimate outcome of the Brunswick CERCLA NPL and Ward Transformer Superfund site matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of the regulatory treatment, it is not expected to have a material impact on Southern Companys or Georgia Powers financial statements.
Gulf Powers environmental remediation liability includes estimated costs of environmental remediation projects of approximately $60 million as of June 30, 2012. These estimated costs relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects will be subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Powers environmental cost recovery clause; therefore, there was no impact on net income as a result of these estimates.
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In 2003, the Texas Commission on Environmental Quality (TCEQ) designated Mississippi Power as a PRP at a site in Texas. The site was owned by an electric transformer company that handled Mississippi Powers transformers as well as those of many other entities. The site owner is bankrupt and the State of Texas has entered into an agreement with Mississippi Power and several other utilities to investigate and remediate the site. The feasibility study/presumptive remedy document was originally filed with TCEQ in June 2011 and remains under consideration by the agency. Amounts expensed and accrued related to this work were not material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final impact of this matter on Mississippi Power will depend upon further environmental assessment and the ultimate number of potentially responsible parties. The remediation expenses incurred by Mississippi Power are expected to be recovered through the ECO Plan.
The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management of Southern Company, Georgia Power, Gulf Power, and Mississippi Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.
Nuclear Fuel Disposal Cost Litigation
Alabama Power and Georgia Power have contracts with the U.S., acting through the DOE, that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contracts, and Alabama Power and Georgia Power are pursuing legal remedies against the government for breach of contract.
In 2007, the U.S. Court of Federal Claims awarded Georgia Power approximately $30 million, based on its ownership interests, and awarded Alabama Power approximately $17 million, representing substantially all of the Southern Company systems direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004.
In 2008, the government filed an appeal and, in March 2011, the U.S. Court of Appeals for the Federal Circuit issued an order in which it affirmed the damage award to Alabama Power, but remanded the Georgia Power portion of the proceeding back to the U.S. Court of Federal Claims for reconsideration of the damages amount in light of the spent nuclear fuel acceptance rates adopted in a separate proceeding by the U.S. Court of Appeals for the Federal Circuit. In July 2011, the court entered final judgment in favor of Alabama Power and awarded Alabama Power approximately $17 million. In April 2012, the award was credited to cost of service for the benefit of Alabama Power customers.
On April 5, 2012, Georgia Power and the government entered into a stipulation to conclude this litigation, which provided for judgment in favor of Georgia Power and awarded Georgia Power approximately $27 million in damages, based on its ownership interests. On April 5, 2012, the stipulation was approved by the U.S. Court of Federal Claims. The proceeds were received and credited to the Georgia Power accounts where the original costs were charged and were used to reduce rate base, fuel, and cost of service for the benefit of Georgia Power customers.
In 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-mandated cut-off in the original claim) due to the governments alleged continuing breach of contract. The complaint does not contain any specific dollar amount for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of June 30, 2012 for the second claim. The final outcome of this matter cannot be determined at this time.
Sufficient pool storage capacity for spent fuel is available at Plant Vogtle Units 1 and 2 to maintain full-core discharge capability for both units into 2014. Construction of an on-site dry storage facility at Plant Vogtle Units 1 and 2 has begun and is expected to be operational in sufficient time to maintain pool full-core discharge capability. At Plants Hatch and Farley, on-site dry spent fuel storage facilities are operational and can be expanded to accommodate spent fuel through the expected life of each plant.
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FERC Matters
See Note 3 to the financial statements of Mississippi Power under FERC Matters in Item 8 of the Form 10-K for additional information regarding Mississippi Powers request for revised rates related to the wholesale Municipal and Rural Associations (MRA) cost-based electric tariff. See Note 3 to the financial statements of Southern Company and of Mississippi Power under Integrated Coal Gasification Combined Cycle in Item 8 of the Form 10-K for information regarding Mississippi Powers construction of the Kemper IGCC.
On January 20, 2012, Mississippi Power reached a settlement agreement with its wholesale customers, which was executed by all parties on March 9, 2012. The settlement agreement provides that base rates under the cost-based electric tariff will increase by approximately $22.6 million over a 12-month period with revised rates effective April 1, 2012. In 2012, the amount of base rate revenues to be received from the agreed upon increase will be approximately $17.0 million. On March 12, 2012, Mississippi Power filed an unopposed motion to place wholesale MRA interim rates into effect pending approval of the settlement agreement between the parties by the FERC. On March 28, 2012, the FERC approved the motion to place interim rates into effect beginning in May 2012. Approval of the settlement agreement by the FERC has been delayed until later in 2012. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Alabama Power
Rate CNP
See Note 3 to the financial statements of Southern Company and Alabama Power under Retail Regulatory Matters Alabama Power Rate CNP and Retail Regulatory Matters Rate CNP, respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Powers recovery of retail costs through Rate Certificated New Plant Power Purchase Agreement (Rate CNP) and Rate Certificated New Plant Environmental (Rate CNP Environmental). Alabama Powers under recovered Rate CNP balance as of June 30, 2012 was $2 million as compared to $6 million at December 31, 2011. Alabama Powers under recovered Rate CNP Environmental balance as of June 30, 2012 was $26 million as compared to $11 million at December 31, 2011. These under recovered balances at June 30, 2012 are included in deferred under recovered regulatory clause revenues on Southern Companys and Alabama Powers Condensed Balance Sheets herein. For Rate CNP, this classification is based on an estimate, which includes such factors as purchased power capacity and energy demand. For Rate CNP Environmental, this classification is based on an estimate, which includes such factors as costs to comply with environmental mandates and energy demand. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered retail costs.
Natural Disaster Cost Recovery
See Note 3 to the financial statements of Southern Company and Alabama Power under Retail Regulatory Matters Alabama Power Natural Disaster Reserve and Retail Regulatory Matters Natural Disaster Reserve, respectively, in Item 8 of the Form 10-K for additional information regarding natural disaster cost recovery. At June 30, 2012, the NDR had an accumulated balance of $105 million, which is included in Southern Companys and Alabama Powers Condensed Balance Sheets herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in Southern Companys and Alabama Powers Condensed Statements of Income herein.
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Georgia Power
Fuel Cost Recovery
See Note 3 to the financial statements of Southern Company and Georgia Power under Retail Regulatory Matters Georgia Power Fuel Cost Recovery and Retail Regulatory Matters Fuel Cost Recovery, respectively, in Item 8 of the Form 10-K for additional information.
On June 21, 2012, the Georgia PSC approved a decrease in Georgia Powers fuel cost recovery rates of 19%, which reduced annual billings by $567 million effective June 1, 2012. The decrease in fuel costs resulted from lower natural gas prices as a result of increased natural gas supplies.
As of June 30, 2012, Georgia Power had a total over recovered fuel cost balance of approximately $99 million compared to an under recovered balance of $137 million at December 31, 2011. The over recovered fuel costs at June 30, 2012 are included in other current liabilities and other deferred credits and liabilities on Southern Companys and Georgia Powers Condensed Balance Sheets herein. The under recovered fuel costs at December 31, 2011 are included in current assets on Southern Companys and Georgia Powers Condensed Balance Sheets herein. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor will not have a significant effect on Southern Companys or Georgia Powers revenues or net income, but will affect cash flow.
2011 Integrated Resource Plan Update
See Note 3 to the financial statements of Southern Company and Georgia Power under Retail Regulatory Matters Georgia Power 2011 Integrated Resource Plan Update and Retail Regulatory Matters 2011 Integrated Resource Plan Update, respectively, in Item 8 of the Form 10-K for additional information.
On March 20, 2012, the Georgia PSC approved Georgia Powers request to decertify and retire two coal-fired generation units at Plant Branch as of October 31, 2013 and December 31, 2013 and an oil-fired unit at Plant Mitchell as of March 26, 2012, which was included in Georgia Powers 2011 IRP Update. The Georgia PSC also approved three PPAs totaling 998 MWs with Southern Power for capacity and energy that will commence in 2015 and end in 2030. The PPAs remain subject to FERC approval. The ultimate outcome of this matter cannot be determined at this time.
Nuclear Construction
See Note 3 to the financial statements of Southern Company and Georgia Power under Retail Regulatory Matters Georgia Power Nuclear Construction and Construction Nuclear, respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Powers construction of Plant Vogtle Units 3 and 4.
On February 16, 2012, a group of petitioners who had intervened in the NRCs combined construction and operating licenses (COLs) proceedings for Plant Vogtle Units 3 and 4 filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review and a stay of the NRCs issuance of the COLs. In addition, on February 16, 2012, another group of petitioners filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review of the NRCs certification of the Westinghouse Design Certification Document, as amended (DCD). On April 3, 2012, the U.S. Court of Appeals for the District of Columbia Circuit granted a motion filed by these two groups of petitioners to consolidate their challenges. On April 18, 2012, another group of petitioners filed a motion to stay the effectiveness of the order issuing the COLs for Plant Vogtle Units 3 and 4 with the U.S. District Court for the District of Columbia. On July 11, 2012, the U.S. Court of Appeals for the District of Columbia Circuit denied the petitioners motion to stay the effectiveness of the COLs. Georgia Power has intervened in and intends to vigorously contest these petitions.
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In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. In addition, the Georgia PSC voted to approve inclusion of the related CWIP accounts in rate base. Also in 2009, the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that allows Georgia Power to recover financing costs for nuclear construction projects by including the related CWIP accounts in rate base during the construction period. With respect to Plant Vogtle Units 3 and 4, this legislation allows Georgia Power to recover projected financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion. The Georgia PSC has ordered Georgia Power to report against this total certified cost of approximately $6.1 billion. In addition, in December 2010, the Georgia PSC approved Georgia Powers NCCR tariff. The NCCR tariff became effective January 1, 2011 and adjustments are filed with the Georgia PSC on November 1 of each year to become effective on January 1 of the following year. Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs, capitalized in 2009 and 2010, over the five-year period ending December 31, 2015, in addition to the ongoing financing costs. At June 30, 2012, approximately $64 million of these 2009 and 2010 costs remained in CWIP.
Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners (collectively, Owners) and Westinghouse and Stone & Webster, Inc. (collectively, Contractor) have established both informal and formal dispute resolution procedures in accordance with the engineering, procurement, and construction agreement to design, engineer, procure, construct, and test two AP1000 nuclear units with electric generating capacity of approximately 1,100 MWs each and related facilities, structures, and improvements at Plant Vogtle entered into by the parties (Vogtle 3 and 4 Agreement) in order to resolve issues arising during the course of constructing a project of this magnitude. The Contractor and Georgia Power (on behalf of the Owners) have successfully initiated both formal and informal claims through these procedures, including ongoing claims, to resolve disputes. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and Georgia Power (on behalf of the Owners) are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.
During the course of construction activities, issues have arisen that may impact the project budget and schedule. The most significant issues relate to costs associated with design changes to the DCD and costs associated with delays in the project schedule related to the timing of approval of the DCD and issuance of the COLs by the NRC. The Owners and the Contractor have begun negotiations regarding these issues, including the assertion by the Contractor that the Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Through correspondence sent to the Owners, the Contractor has provided its proposed adjustment to the contract price and has initiated the formal dispute resolution process. The Contractors estimated adjustment attributable to Georgia Power (based on Georgia Powers ownership interest regarding these issues) is approximately $425 million (in 2008 dollars) with respect to these issues. Georgia Power has not agreed with the amount of these proposed adjustments or that the Owners have responsibility for any costs related to these issues. While the formal dispute resolution process has been initiated, Georgia Power expects negotiations with the Contractor to continue over the next several months with respect to cost and schedule during which time the parties will attempt to reach a mutually acceptable compromise of their positions. Georgia Power intends to vigorously defend its positions. If these costs ultimately are imposed upon the Owners, Georgia Power would seek an amendment to the certified cost of Plant Vogtle Units 3 and 4, if necessary. In connection with these negotiations, the Owners are evaluating whether maintaining the currently scheduled commercial operation dates of 2016 and 2017 remains in the best interest of their customers. Additional claims by the Contractor or Georgia Power (on behalf of the Owners) are expected to arise throughout the construction of Plant Vogtle Units 3 and 4.
In addition, there are processes in place to assure compliance with the design requirements specified in the DCD and the COLs, including rigorous inspection by Southern Nuclear and the NRC that occurs throughout construction. During a routine inspection in April 2012, the NRC identified that certain details of the rebar construction in the Plant Vogtle Unit 3 nuclear island were not consistent with the DCD. In May 2012, Southern Nuclear received an official notice of violation relating to these findings from the NRC. The design changes were determined to have minimal safety significance and, on August 1, 2012, Southern Nuclear filed a license amendment request with the NRC to clarify that the nuclear island concrete and rebar construction will conform to NRC requirements. Various inspection and other issues are expected to arise from time to time as construction proceeds, which may result in additional license amendments or require other resolution.
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There are pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, including legal challenges to the NRC issuance of the COLs and certification of the DCD. Similar additional challenges at the state and federal level are expected as construction proceeds.
The ultimate outcome of these matters cannot be determined at this time.
Other Construction
See Note 3 to the financial statements of Southern Company and Georgia Power under Retail Regulatory Matters Georgia Power Other Construction and Construction Other Construction, respectively, in Item 8 of the Form 10-K for additional information.
Plant McDonough Unit 1 was retired on February 29, 2012. Georgia Power placed Plant McDonough-Atkinson Unit 5 into service on April 26, 2012. Plant McDonough-Atkinson Unit 6 is scheduled to be placed into service in November 2012.
Gulf Power
Retail Base Rate Case
See Note 3 to the financial statements of Gulf Power under Retail Regulatory Matters Retail Base Rate Case in Item 8 of the Form 10-K for additional information.
On March 12, 2012, the Florida PSC approved a permanent increase in retail base rates and charges of $64 million effective April 11, 2012. The amount of the permanent increase includes the previously approved $38.5 million interim retail rate increase implemented in September 2011. The Florida PSCs decision on the amount of the permanent increase also included a determination that none of the base rate revenues collected on an interim basis would be refunded. Gulf Powers authorized retail ROE is a range of 9.25% to 11.25% with new retail base rates set at the midpoint retail ROE of 10.25%. In addition, the Florida PSC also approved a step increase to Gulf Powers retail base rates and charges of $4 million to be effective in January 2013. On April 18, 2012, Gulf Power filed a motion to reconsider one aspect of the decision dealing with property acquired as a potential site for a future generating plant. On July 17, 2012, the Florida PSC denied Gulf Powers motion and reaffirmed its earlier decision.
Cost Recovery Clauses
See Note 3 to the financial statements of Gulf Power under Retail Regulatory Matters Cost Recovery Clauses in Item 8 of the Form 10-K for additional information.
Fuel Cost Recovery
See Notes 1 and 3 to the financial statements of Gulf Power under Revenues and Retail Regulatory Matters Fuel Cost Recovery, respectively, in Item 8 of the Form 10-K for additional information.
On June 19, 2012, the Florida PSC approved a decrease in Gulf Powers fuel rates of 7.8%, which will reduce annual billings by approximately $58.8 million effective July 2, 2012.
Over recovered fuel costs at June 30, 2012 totaled $41.6 million compared to $9.9 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Powers Condensed Balance Sheets herein.
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Purchased Power Capacity Recovery
See Notes 1 and 3 to the financial statements of Gulf Power under Revenues and Retail Regulatory Matters Purchased Power Capacity Recovery, respectively, in Item 8 of the Form 10-K for additional information.
Over recovered purchased power capacity costs at June 30, 2012 totaled $7.9 million compared to $8.0 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Powers Condensed Balance Sheets herein.
Environmental Cost Recovery
See Note 3 to the financial statements of Gulf Power under Retail Regulatory Matters Environmental Cost Recovery in Item 8 of the Form 10-K for additional information.
On April 3, 2012, the Mississippi PSC approved Mississippi Powers request for a CPCN to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. On May 3, 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court of Harrison County, Mississippi (Chancery Court). These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, excluding AFUDC, and it is scheduled for completion in December 2015. Gulf Powers portion of the cost is expected to be recovered through the environmental cost recovery clause. The ultimate outcome of this matter cannot be determined at this time.
Over recovered environmental costs at June 30, 2012 totaled $3.6 million compared to $10.0 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Powers Condensed Balance Sheets herein.
Energy Conservation Cost Recovery
See Note 3 to the financial statements of Gulf Power under Retail Regulatory Matters Energy Conservation Cost Recovery in Item 8 of the Form 10-K for additional information.
Under recovered energy conservation costs at June 30, 2012 totaled $1.6 million compared to $3.1 million at December 31, 2011. These amounts are included in under recovered regulatory clause revenues on Gulf Powers Condensed Balance Sheets herein.
Mississippi Power
Performance Evaluation Plan
See Note 3 to the financial statements of Mississippi Power under Retail Regulatory Matters Performance Evaluation Plan in Item 8 of the Form 10-K for additional information regarding Mississippi Powers base rates.
On April 2, 2012, Mississippi Power filed a motion to suspend the 2011 PEP lookback filing. Unresolved matters related to certain costs included in the 2010 PEP lookback filing also impact the 2011 PEP lookback filing, making it impractical to determine Mississippi Powers actual retail return on investment for 2011 for purposes of the 2011 PEP lookback filing. An order granting the suspension of the 2011 PEP lookback was signed by the Mississippi PSC on May 8, 2012. The ultimate outcome of these matters cannot be determined at this time.
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System Restoration Rider
See Note 3 to the financial statements of Mississippi Power under Retail Regulatory Matters System Restoration Rider in Item 8 of the Form 10-K for additional information.
On February 2, 2012, Mississippi Power submitted its 2012 System Restoration Rider (SRR) rate filing with the Mississippi PSC, which proposed that the 2012 SRR rate level remain at zero and Mississippi Power be allowed to accrue approximately $3.7 million to the property damage reserve in 2012. On April 3, 2012, the filing was approved by the Mississippi PSC.
Environmental Compliance Overview Plan
See Note 3 to the financial statements of Mississippi Power under Retail Regulatory Matters Environmental Compliance Overview Plan in Item 8 of the Form 10-K for information on Mississippi Powers annual environmental filing with the Mississippi PSC.
On February 14, 2012, Mississippi Power submitted its 2012 ECO Plan filing, which proposed a 0.3% increase in annual revenues for Mississippi Power. In compliance with the CPCN to construct a scrubber on Plant Daniel Units 1 and 2, Mississippi Power revised the 2012 ECO Plan filing to exclude scrubber expenditures from rate base, which resulted in a 0.16% decrease in annual revenues. On June 22, 2012, the 2012 ECO Plan filing, including the proposed rate decrease, was approved by the Mississippi PSC, effective on June 29, 2012.
On April 3, 2012, the Mississippi PSC approved Mississippi Powers request for a CPCN to construct a scrubber on Plant Daniel Units 1 and 2. On May 3, 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Powers portion being $330 million, excluding AFUDC. The project is scheduled for completion in December 2015. Mississippi Powers portion of the cost is expected to be recovered through the ECO Plan. As of June 30, 2012, total project expenditures were $82.0 million, with Mississippi Powers portion being $41.0 million. The ultimate outcome of this matter cannot be determined at this time.
Certificated New Plant
See Note 3 to the financial statements of Mississippi Power under Retail Regulatory Matters Certificated New Plant in Item 8 of the Form 10-K and Integrated Coal Gasification Combined Cycle herein for additional information.
On May 23, 2012, the Mississippi Public Utilities Staff signed a joint stipulation with Mississippi Power to establish a new rate schedule for Certificated New Plant-A (CNP-A), a proposed cost recovery mechanism designed specifically to recover financing costs during the construction phase of the Kemper IGCC. An amended and restated stipulation was subsequently executed and filed on June 1, 2012. On June 14, 2012, Mississippi Power submitted to the Mississippi PSC a proposed supplemental compliance filing to establish the new CNP-A rate schedule and a stipulated rate increase based upon the revenue request of between $55.3 million and $58.6 million to recover financing costs over the remainder of 2012.
On June 22, 2012, the Mississippi PSC denied the proposed CNP-A rate schedule and the 2012 rate recovery filings submitted by Mississippi Power, pending a final ruling from the Mississippi Supreme Court regarding the motion for stay and notice of appeal filed by the Sierra Club on April 26, 2012 relating to the Mississippi PSCs issuance of the CPCN for the Kemper IGCC. On July 9, 2012, Mississippi Power appealed the Mississippi PSCs June 22, 2012 decision to the Mississippi Supreme Court and requested interim rates under bond of $55.3 million while the Mississippi Supreme Court decides Mississippi Powers appeal of the Mississippi PSCs June 22, 2012 decision. On July 31, 2012, the Mississippi Supreme Court denied Mississippi Powers request for interim rates under bond. The ultimate outcome of this matter cannot be determined at this time.
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Fuel Cost Recovery
See Note 3 to the financial statements of Mississippi Power under Retail Regulatory Matters Fuel Cost Recovery in Item 8 of the Form 10-K for information regarding Mississippi Powers fuel cost recovery.
At June 30, 2012, the amount of over recovered retail fuel costs included in Mississippi Powers Condensed Balance Sheets herein was $55.5 million compared to $42.4 million at December 31, 2011. Mississippi Power also has wholesale MRA and Market Based (MB) fuel cost recovery factors. At June 30, 2012, the amount of over recovered wholesale MRA and MB fuel costs included in Mississippi Powers Condensed Balance Sheets herein was $17.4 million and $2.4 million, respectively, compared to $14.3 million and $2.2 million, respectively, at December 31, 2011. In addition, at June 30, 2012 and December 31, 2011, the amount of over recovered MRA emissions allowance cost included in Mississippi Powers Condensed Balance Sheets herein was $1.0 million and $1.7 million, respectively. Mississippi Powers operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, any changes in the billing factors will not have a significant effect on Mississippi Powers revenues or net income, but will affect annual cash flow.
Integrated Coal Gasification Combined Cycle
See Note 3 to the financial statements of Southern Company and Mississippi Power under Integrated Coal Gasification Combined Cycle in Item 8 of the Form 10-K for information regarding Mississippi Powers construction of the Kemper IGCC.
In May 2010, Mississippi Power filed a motion with the Mississippi PSC accepting the conditions contained in the Mississippi PSC order confirming Mississippi Powers application for a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC. In June 2010, the Mississippi PSC issued the CPCN (2010 MPSC Order).
In June 2010, the Sierra Club filed an appeal of the Mississippi PSCs June 2010 decision to grant the CPCN for the Kemper IGCC with the Chancery Court. Subsequently, in July 2010, the Sierra Club also filed an appeal directly with the Mississippi Supreme Court. In October 2010, the Mississippi Supreme Court dismissed the Sierra Clubs direct appeal. In February 2011, the Chancery Court issued a judgment affirming the 2010 MPSC Order and, in March 2011, the Sierra Club appealed the Chancery Courts decision to the Mississippi Supreme Court. On March 15, 2012, the Mississippi Supreme Court reversed the Chancery Courts decision and the 2010 MPSC Order and remanded the matter to the Mississippi PSC to correct the 2010 MPSC Order. The Mississippi Supreme Court concluded that the 2010 MPSC Order did not cite in sufficient detail substantial evidence upon which the Mississippi Supreme Court could determine the basis for the findings of the Mississippi PSC granting the CPCN.
On March 30, 2012, the Mississippi PSC issued temporary authorization for the continuation of construction of the Kemper IGCC. On April 24, 2012, the Mississippi PSC issued a detailed order on remand (2012 MPSC Order) confirming the CPCN for the Kemper IGCC subject to the same conditions set forth in the 2010 MPSC Order. On April 26, 2012, the Sierra Club filed a motion for stay and a notice of appeal of the 2012 MPSC Order with the Chancery Court. On May 18, 2012, Mississippi Powers motion to join the appeal was approved.
The certificated cost estimate of the Kemper IGCC is $2.4 billion, net of $245.3 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (CCPI2) and excluding the cost of the lignite mine and equipment and the carbon dioxide (CO2) pipeline facilities. The 2012 MPSC Order, like the 2010 MPSC Order, (1) approved a construction cost cap of up to $2.88 billion (exemptions from the cost cap include the cost of the lignite mine and equipment and the CO2 pipeline facilities and certain general exceptions, including change of law, force majeure, and beneficial capital), (2) provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Powers proposal, and (3) approved financing cost recovery on CWIP balances not to exceed the certificated cost estimate, which provided for the accrual of AFUDC in 2010 and 2011 and provides for the current recovery of financing costs on 100% of CWIP in 2012, 2013, and through May 1, 2014, (provided that the amount of CWIP allowed is (i) reduced by the amount of state and federal government construction cost incentives received by
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Mississippi Power in excess of $296 million to the extent that such amount increases cash flow for the pertinent regulatory period and (ii) justified by a showing that such CWIP allowance will benefit customers over the life of the Kemper IGCC). The current cost estimate of the Kemper IGCC is $2.88 billion, including a $72 million contingency.
The Mississippi PSC order established periodic prudence reviews during the annual CWIP review process. Of the total costs incurred through March 2009, $46 million has been reviewed and approved by the Mississippi PSC. A decision regarding the remaining $5 million has been deferred to a later date. The timing of the review of the remaining Kemper IGCC costs has not been determined.
The Kemper IGCC, expected to begin commercial operation in May 2014, will use locally mined lignite (an abundant, lower heating value coal) from a mine adjacent to the Kemper IGCC as fuel. The mine is scheduled to be placed into service in June 2013. In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site in Kemper County. The estimated capital cost of the mine is approximately $245 million, of which $99.9 million has been incurred through June 30, 2012.
In May 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC, a subsidiary of The North American Coal Corporation (Liberty Fuels), which will develop, construct, and manage the mining operations. Due to the fact that Liberty Fuels conducts all of its activities on behalf of Mississippi Power, Liberty Fuels qualifies as a variable interest entity for which Mississippi Power is the primary beneficiary. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. Consistent with the requirements of consolidation accounting, Liberty Fuels is consolidated in the financial statements of Mississippi Power and accordingly the asset retirement cost and the ARO have been recorded in Mississippi Powers financial statements. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses.
In December 2011, the Mississippi Department of Environmental Quality (MDEQ) approved the surface coal mining and the water pollution control permits for the mining operations operated by Liberty Fuels. On January 12, 2012, two individuals each filed a notice of appeal and a request for evidentiary hearing with the MDEQ regarding the surface coal mining and water pollution control permits. On March 8, 2012, the MDEQ permit board affirmed its issuance of the surface coal mining and water pollution control permits.
In 2009, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $133 million of Internal Revenue Code Section 48A tax credits (Phase I) to Mississippi Power. In April 2011, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $279 million of Internal Revenue Code Section 48A tax credits (Phase II) to Mississippi Power. The utilization of Phase I and Phase II credits is dependent upon meeting the IRS certification requirements, including an in-service date no later than May 11, 2014 for the Phase I credits and April 19, 2016 for the Phase II credits. In order to remain eligible for the Phase II credits, Mississippi Power plans to capture and sequester (via enhanced oil recovery) at least 65% of the CO2 produced by the Kemper IGCC during operations in accordance with the recapture rules for Section 48A investment tax credits. Through June 30, 2012, Mississippi Power received or accrued tax benefits totaling $197 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC. Based on current tax laws and regulations in effect, Mississippi Power expects to receive substantially all of the tax credits accrued through June 30, 2012 by June 30, 2013.
In July 2010, Mississippi Power and SMEPA entered into an asset purchase agreement whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In December 2010, Mississippi Power and SMEPA filed a joint petition with the Mississippi PSC requesting regulatory approval of SMEPAs 17.5% undivided interest in the Kemper IGCC. On February 28, 2012, the Mississippi PSC approved the joint petition for the sale and transfer of 17.5% of the Kemper IGCC to SMEPA. On June 29, 2012, Mississippi Power and SMEPA signed an amendment to the asset purchase agreement whereby SMEPA extended its option to purchase until December 31, 2012 and reduced its purchase
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commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC, subject to approval by the Mississippi PSC. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions.
On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the purchase. While the expectation is that the amount will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposit upon the termination of the asset purchase agreement, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPAs discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moodys or ceases to be rated by either of these rating agencies. Given the interest-bearing nature of the deposit and SMEPAs ability to request a refund, the deposit has been presented as a current liability in Mississippi Powers Condensed Balance Sheet herein and as financing proceeds in Mississippi Powers Condensed Statement of Cash Flows herein.
As of June 30, 2012, Mississippi Power had spent a total of $1.7 billion on the Kemper IGCC including the cost of the lignite mine and equipment, the CO2 pipeline facilities, and regulatory filing costs. Of this total, $1.6 billion was included in CWIP (which is net of $245.3 million of CCPI2 grant funds), $29.0 million was recorded in other regulatory assets, $2.6 million was recorded in other deferred charges and assets, and $1.0 million was previously expensed.
See Note 3 to the financial statements of Mississippi Power under Retail Regulatory Matters Certificated New Plant in Item 8 of the Form 10-K and Retail Regulatory Matters Certificated New Plant herein for information on the proposed rate schedules related to the Kemper IGCC.
The ultimate outcome of these matters cannot be determined at this time.
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(C) FAIR VALUE MEASUREMENTS
As of June 30, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
Fair Value Measurements Using | ||||||||||||||||
As of June 30, 2012: | Quoted Prices Assets (Level 1) |
Significant Other Observable Inputs |
Significant Unobservable Inputs (Level 3) |
Total | ||||||||||||
|
||||||||||||||||
(in millions) | ||||||||||||||||
Southern Company |
||||||||||||||||
Assets: |
||||||||||||||||
Energy-related derivatives |
$ | | $ | 24 | $ | | $ | 24 | ||||||||
Interest rate derivatives |
| 12 | | 12 | ||||||||||||
Nuclear decommissioning trusts(a) |
450 | 784 | | 1,234 | ||||||||||||
Cash equivalents and restricted cash |
512 | | | 512 | ||||||||||||
Other investments |
1 | 53 | 15 | 69 | ||||||||||||
|
||||||||||||||||
Total |
$ | 963 | $ | 873 | $ | 15 | $ | 1,851 | ||||||||
|
||||||||||||||||
Liabilities: |
||||||||||||||||
Energy-related derivatives |
$ | | $ | 194 | $ | | $ | 194 | ||||||||
Interest rate derivatives |
| 28 | | 28 | ||||||||||||
Foreign currency derivatives |
| 2 | | 2 | ||||||||||||
|
||||||||||||||||
Total |
$ | | $ | 224 | $ | | $ | 224 | ||||||||
|
||||||||||||||||
Alabama Power |
||||||||||||||||
Assets: |
||||||||||||||||
Energy-related derivatives |
$ | | $ | 3 | $ | | $ | 3 | ||||||||
Nuclear decommissioning trusts:(b) |
||||||||||||||||
Domestic equity |
274 | 60 | | 334 | ||||||||||||
Foreign equity(d) |
25 | 49 | | 74 | ||||||||||||
U.S. Treasury and government agency securities |
| 23 | | 23 | ||||||||||||
Corporate bonds |
| 101 | | 101 | ||||||||||||
Mortgage and asset backed securities |
| 25 | | 25 | ||||||||||||
Other |
| 12 | | 12 | ||||||||||||
|
||||||||||||||||
Total |
$ | 299 | $ | 273 | $ | | $ | 572 | ||||||||
|
||||||||||||||||
Liabilities: |
||||||||||||||||
Energy-related derivatives |
$ | | $ | 35 | $ | | $ | 35 | ||||||||
Interest rate derivatives |
| 28 | | 28 | ||||||||||||
|
||||||||||||||||
Total |
$ | | $ | 63 | $ | | $ | 63 | ||||||||
|
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Fair Value Measurements Using | ||||||||||||||||
As of June 30, 2012: | Quoted Prices Assets (Level 1) |
Significant Other Observable Inputs |
Significant Unobservable Inputs (Level 3) |
Total | ||||||||||||
|
||||||||||||||||
(in millions) | ||||||||||||||||
Georgia Power |
||||||||||||||||
Assets: |
||||||||||||||||
Energy-related derivatives |
$ | | $ | 17 | $ | | $ | 17 | ||||||||
Nuclear decommissioning trusts:(b) (c) |
||||||||||||||||
Domestic equity |
151 | 1 | | 152 | ||||||||||||
Foreign equity(d) |
| 102 | | 102 | ||||||||||||
U.S. Treasury and government agency securities |
| 45 | | 45 | ||||||||||||
Municipal bonds |
| 103 | | 103 | ||||||||||||
Corporate bonds |
| 120 | | 120 | ||||||||||||
Mortgage and asset backed securities |
| 118 | | 118 | ||||||||||||
Other |
| 24 | | 24 | ||||||||||||
Cash equivalents |
149 | | | 149 | ||||||||||||
|
||||||||||||||||
Total |
$ | 300 | $ | 530 | $ | | $ | 830 | ||||||||
|
||||||||||||||||
Liabilities: |
||||||||||||||||
Energy-related derivatives |
$ | | $ | 75 | $ | | $ | 75 | ||||||||
|
||||||||||||||||
Gulf Power |
||||||||||||||||
Assets: |
||||||||||||||||
Energy-related derivatives |
$ | | $ | 2 | $ | | $ | 2 | ||||||||
Cash equivalents |
15 | | | 15 | ||||||||||||
|
||||||||||||||||
Total |
$ | 15 | $ | 2 | $ | | $ | 17 | ||||||||
|
||||||||||||||||
Liabilities: |
||||||||||||||||
Energy-related derivatives |
$ | | $ | 39 | $ | | $ | 39 | ||||||||
|
||||||||||||||||
Mississippi Power |
||||||||||||||||
Assets: |
||||||||||||||||
Energy-related derivatives |
$ | | $ | 1 | $ | | $ | 1 | ||||||||
Cash equivalents |
146 | | | 146 | ||||||||||||
|
||||||||||||||||
Total |
$ | 146 | $ | 1 | $ | | $ | 147 | ||||||||
|
||||||||||||||||
Liabilities: |
||||||||||||||||
Energy-related derivatives |
$ | | $ | 38 | $ | | $ | 38 | ||||||||
Foreign currency derivatives |
| 2 | | 2 | ||||||||||||
|
||||||||||||||||
Total |
$ | | $ | 40 | $ | | $ | 40 | ||||||||
|
||||||||||||||||
Southern Power |
||||||||||||||||
Assets: |
||||||||||||||||
Energy-related derivatives |
$ | | $ | 1 | $ | | $ | 1 | ||||||||
|
||||||||||||||||
Liabilities: |
||||||||||||||||
Energy-related derivatives |
$ | | $ | 7 | $ | | $ | 7 | ||||||||
|
(a) | For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table. |
(b) | Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. |
(c) | Includes the investment securities pledged to creditors and cash collateral received and payables related to the securities lending program. As of June 30, 2012, approximately $38 million of the fair market value of Georgia Powers nuclear decommissioning trust funds securities were on loan and pledged to creditors under the funds managers securities lending program. |
(d) | Level 1 securities consist of actively traded stocks, while Level 2 securities consist of pooled funds. |
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Valuation Methodologies
The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and LIBOR interest rates. Interest rate and foreign currency derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally implied volatility of interest rate options. Inputs for foreign currency derivatives are from observable market sources. See Note (H) herein for additional information on how these derivatives are used.
Other investments include investments in funds that are valued using the market approach and income approach. Securities that are traded in the open market are valued at the closing price on their principal exchange as of the measurement date. Discounts are applied in accordance with GAAP when certain trading restrictions exist. For investments that are not traded in the open market, the price paid will have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan execution. As the investments mature or if market conditions change materially, further analysis of the fair market value of the investment is performed. This analysis is typically based on a metric, such as multiple of earnings, revenues, earnings before interest and income taxes, or earnings adjusted for certain cash changes. These multiples are based on comparable multiples for publicly traded companies or other relevant prior transactions.
For fair value measurements of investments within the nuclear decommissioning trusts and rabbi trust funds, specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts and rabbi trust funds with each security discriminately assigned a primary pricing source, based on similar characteristics.
A market price secured from the primary source vendor is then used in the valuation of the assets within the trusts. As a general approach, market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information including live trading levels and pricing analysts judgment are also obtained when available.
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As of June 30, 2012, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
As of June 30, 2012: | Fair Value |
Unfunded Commitments |
Redemption Frequency |
Redemption Notice Period | ||||||
| ||||||||||
(in millions) | ||||||||||
Southern Company |
||||||||||
Nuclear decommissioning trusts: |
||||||||||
Corporate bonds commingled funds |
$ | 8 | None | Daily | 1 to 3 days | |||||
Other commingled funds |
73 | None | Daily/Monthly | Daily/7 days | ||||||
Trust-owned life insurance |
91 | None | Daily | 15 days | ||||||
Cash equivalents and restricted cash: |
||||||||||
Money market funds |
512 | None | Daily | Not applicable | ||||||
| ||||||||||
Alabama Power |
||||||||||
Nuclear decommissioning trusts: |
||||||||||
Other commingled funds |
49 | None | Daily/Monthly | Daily/7 days | ||||||
Trust-owned life insurance |
91 | None | Daily | 15 days | ||||||
| ||||||||||
Georgia Power |
||||||||||
Nuclear decommissioning trusts: |
||||||||||
Corporate bonds commingled funds |
8 | None | Daily | 1 to 3 days | ||||||
Other commingled funds |
24 | None | Daily | Not applicable | ||||||
Cash equivalents: |
||||||||||
Money market funds |
149 | None | Daily | Not applicable | ||||||
| ||||||||||
Gulf Power |
||||||||||
Cash equivalents: |
||||||||||
Money market funds |
15 | None | Daily | Not applicable | ||||||
| ||||||||||
Mississippi Power |
||||||||||
Cash equivalents: |
||||||||||
Money market funds |
146 | None | Daily | Not applicable | ||||||
|
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (the Funds) to comply with the NRCs regulations. The commingled funds in the nuclear decommissioning trusts are invested primarily in a diversified portfolio of high grade money market instruments, including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations having a maximum five-year final maturity with put features or floating rates with a reset date of 13 months or less. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity. The corporate bonds commingled funds represent the investment of cash collateral received under the Funds managers securities lending program that can only be sold upon the return of the loaned securities. See Note 1 to the financial statements of Southern Company and Georgia Power under Nuclear Decommissioning in Item 8 of the Form 10-K for additional information.
Alabama Powers nuclear decommissioning trust includes investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trust invests in the TOLI in order to minimize the impact of taxes on the portfolio and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trust does not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. The commingled funds primarily
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include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and, to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection.
Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three and six months ended June 30, 2012, the change in fair value of the funds, which includes reinvested interest and dividends and excludes the Funds expenses, is recorded in the regulatory liability and was a decrease of $22 million and an increase of $64 million, respectively, for Southern Company, a decrease of $16 million and an increase of $33 million, respectively, for Alabama Power, and a decrease of $6 million and an increase of $31 million, respectively, for Georgia Power.
The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the investment in the money market funds.
At June 30, 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:
Carrying Amount | Fair Value | |||
| ||||
(in millions) | ||||
Long-term debt: |
||||
Southern Company |
$21,451 | $23,477 | ||
Alabama Power |
$ 6,130 | $ 6,893 | ||
Georgia Power |
$ 9,856 | $10,703 | ||
Gulf Power |
$ 1,246 | $ 1,384 | ||
Mississippi Power |
$ 1,576 | $ 1,690 | ||
Southern Power |
$ 1,306 | $ 1,416 |
The fair values are primarily Level 2 and are based on quoted market prices for the same or similar issues or on the current rates offered to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power.
(D) STOCKHOLDERS EQUITY
Earnings per Share
For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effects of both stock options and performance share award units were determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:
Three Months June 30, 2012 |
Three Months June 30, 2011 |
Six Months June 30, 2012 |
Six Months June 30, 2011 | |||||
| ||||||||
(in millions) | ||||||||
As reported shares |
872 | 855 | 870 | 851 | ||||
Effect of options and performance share award units |
8 | 7 | 9 | 7 | ||||
| ||||||||
Diluted shares |
880 | 862 | 879 | 858 | ||||
|
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for both the three months and six months ended June 30, 2012 and 2011.
Changes in Stockholders Equity
The following table presents year-to-date changes in stockholders equity of Southern Company:
Number
of Common Shares |
Common Stockholders |
Preferred and Preference Stock of |
Total Stockholders | |||||||
Issued | Treasury | Equity | Subsidiaries | Equity | ||||||
| ||||||||||
(in thousands) | (in millions) | |||||||||
Balance at December 31, 2011 |
865,664 | (539) | $17,578 | $707 | $18,285 | |||||
Net income after dividends on preferred and preference stock |
| | 991 | | 991 | |||||
Other comprehensive income (loss) |
| | (1) | | (1) | |||||
Stock issued |
9,697 | | 395 | | 395 | |||||
Cash dividends on common stock |
| | (837) | | (837) | |||||
Other |
| (26) | (2) | | (2) | |||||
| ||||||||||
Balance at June 30, 2012 |
875,361 | (565) | $18,124 | $707 | $18,831 | |||||
| ||||||||||
Balance at December 31, 2010 |
843,814 | (474) | $16,202 | $707 | $16,909 | |||||
Net income after dividends on preferred and preference stock |
| | 1,026 | | 1,026 | |||||
Other comprehensive income (loss) |
| | 8 | | 8 | |||||
Stock issued |
14,337 | | 533 | | 533 | |||||
Cash dividends on common stock |
| | (787) | | (787) | |||||
Other |
| (25) | | | | |||||
| ||||||||||
Balance at June 30, 2011 |
858,151 | (499) | $16,982 | $707 | $17,689 | |||||
|
(E) FINANCING
Bank Credit Arrangements
Bank credit arrangements provide liquidity support to the registrants commercial paper borrowings and the traditional operating companies variable rate pollution control revenue bonds. See Note 6 to the financial statements of each registrant under Bank Credit Arrangements in Item 8 of the Form 10-K for additional information.
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
The following table outlines the credit arrangements by company as of June 30, 2012, including expiration dates:
Expires | Executable Term Loans |
Due Within
One Year(a) | ||||||||||||||||
Company | 2012 | 2013 | 2014 and |
Total | Unused | One Year |
Two Years |
Term Out |
No Term Out | |||||||||
| ||||||||||||||||||
(in millions) | (in millions) | (in millions) | (in millions) | |||||||||||||||
Southern Company |
$ | $ | $1,000 | $1,000 | $1,000 | $ | $ | $ | $ | |||||||||
Alabama Power |
37 | 101 | 1,150 | 1,288 | 1,288 | 51 | | 51 | 52 | |||||||||
Georgia Power |
| | 1,750 | 1,750 | 1,745 | | | | | |||||||||
Gulf Power |
20 | 60 | 195 | 275 | 275 | 45 | | 45 | 35 | |||||||||
Mississippi Power |
41 | 95 | 165 | 301 | 301 | 25 | 41 | 66 | 70 | |||||||||
Southern Power |
| | 500 | 500 | 500 | | | | | |||||||||
Other |
| 50 | | 50 | 50 | 25 | | 25 | | |||||||||
|
|
|
| |||||||||||||||
Total |
$98 | $306 | $4,760 | $5,164 | $5,159 | $146 | $ 41 | $187 | $157 | |||||||||
|
|
|
|
(a) | Reflects facilities expiring on or before June 30, 2013. |
(b) | All remaining Gulf Power and Mississippi Power credit agreements in this column expire in 2014. |
(F) RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2012. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.
See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K for additional information.
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
Components of the net periodic benefit costs for the three and six months ended June 30, 2012 and 2011 were as follows:
Pension Plans | Southern Company |
Alabama Power |
Georgia Power |
Gulf Power |
Mississippi Power | |||||
| ||||||||||
(in millions) | ||||||||||
Three Months Ended June 30, 2012 |
||||||||||
Service cost |
$ 49 | $ 11 | $ 15 | $ 3 | $ 3 | |||||
Interest cost |
99 | 24 | 36 | 4 | 4 | |||||
Expected return on plan assets |
(146) | (41) | (55) | (7) | (6) | |||||
Net amortization |
31 | 7 | 11 | 2 | 1 | |||||
| ||||||||||
Net cost (income) |
$ 33 | $ 1 | $7 | $ 2 | $ 2 | |||||
| ||||||||||
Six Months Ended June 30, 2012 |
||||||||||
Service cost |
$ 99 | $ 22 | $ 30 | $ 5 | $ 5 | |||||
Interest cost |
197 | 47 | 71 | 8 | 9 | |||||
Expected return on plan assets |
(291) | (81) | (110) | (13) | (12) | |||||
Net amortization |
62 | 15 | 22 | 3 | 2 | |||||
| ||||||||||
Net cost (income) |
$ 67 | $ 3 | $ 13 | $ 3 | $ 4 | |||||
| ||||||||||
Three Months Ended June 30, 2011 |
||||||||||
Service cost |
$ 46 | $ 10 | $ 15 | $ 2 | $ 2 | |||||
Interest cost |
97 | 24 | 36 | 5 | 5 | |||||
Expected return on plan assets |
(152) | (43) | (58) | (7) | (6) | |||||
Net amortization |
13 | 4 | 4 | | | |||||
| ||||||||||
Net cost (income) |
$ 4 | $ (5) | $ (3) | $ | $ 1 | |||||
| ||||||||||
Six Months Ended June 30, 2011 |
||||||||||
Service cost |
$ 92 | $ 21 | $ 29 | $ 4 | $ 4 | |||||
Interest cost |
195 | 48 | 72 | 9 | 9 | |||||
Expected return on plan assets |
(304) | (86) | (117) | (14) | (12) | |||||
Net amortization |
26 | 7 | 9 | 1 | 1 | |||||
| ||||||||||
Net cost (income) |
$ 9 | $ (10) | $ (7) | $ | $ 2 | |||||
|
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
Postretirement Benefits | Southern Company |
Alabama Power |
Georgia Power |
Gulf Power |
Mississippi Power | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||
Three Months Ended June 30, 2012 |
||||||||||||||||||||||||||||
Service cost |
$ | 6 | $ | 2 | $ | 2 | $ | 1 | $ | 1 | ||||||||||||||||||
Interest cost |
21 | 6 | 10 | 1 | 1 | |||||||||||||||||||||||
Expected return on plan assets |
(15 | ) | (6 | ) | (7 | ) | (1 | ) | (1 | ) | ||||||||||||||||||
Net amortization |
5 | 1 | 2 | | | |||||||||||||||||||||||
Net cost (income) |
$ | 17 | $ | 3 | $ | 7 | $ | 1 | $ | 1 | ||||||||||||||||||
Six Months Ended June 30, 2012 |
||||||||||||||||||||||||||||
Service cost |
$ | 11 | $ | 3 | $ | 3 | $ | 1 | $ | 1 | ||||||||||||||||||
Interest cost |
42 | 11 | 19 | 2 | 2 | |||||||||||||||||||||||
Expected return on plan assets |
(30 | ) | (12 | ) | (14 | ) | (1 | ) | (1 | ) | ||||||||||||||||||
Net amortization |
10 | 3 | 5 | | | |||||||||||||||||||||||
Net cost (income) |
$ | 33 | $ | 5 | $ | 13 | $ | 2 | $ | 2 | ||||||||||||||||||
Three Months Ended June 30, 2011 |
||||||||||||||||||||||||||||
Service cost |
$ | 5 | $ | 2 | $ | 2 | $ | 1 | $ | 1 | ||||||||||||||||||
Interest cost |
23 | 6 | 10 | 1 | 1 | |||||||||||||||||||||||
Expected return on plan assets |
(16 | ) | (7 | ) | (7 | ) | (1 | ) | (1 | ) | ||||||||||||||||||
Net amortization |
5 | 1 | 2 | | | |||||||||||||||||||||||
Net cost (income) |
$ | 17 | $ | 2 | $ | 7 | $ | 1 | $ | 1 | ||||||||||||||||||
Six Months Ended June 30, 2011 |
||||||||||||||||||||||||||||
Service cost |
$ | 10 | $ | 3 | $ | 4 | $ | 1 | $ | 1 | ||||||||||||||||||
Interest cost |
46 | 12 | 20 | 2 | 2 | |||||||||||||||||||||||
Expected return on plan assets |
(32 | ) | (13 | ) | (15 | ) | (1 | ) | (1 | ) | ||||||||||||||||||
Net amortization |
10 | 3 | 5 | | | |||||||||||||||||||||||
Net cost (income) |
$ | 34 | $ | 5 | $ | 14 | $ | 2 | $ | 2 | ||||||||||||||||||
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(G) EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS
Effective Tax Rate
See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for information on the effective income tax rate.
Southern Company
Southern Companys effective tax rate is typically lower than the statutory rate due to its employee stock plans dividend deduction and non-taxable AFUDC equity.
Southern Companys effective tax rate was 34.1% for the six months ended June 30, 2012 compared to 35.4% for the corresponding period in 2011. The decrease was primarily related to state income tax credits. See Unrecognized Tax Benefits herein for additional information.
Alabama Power
Alabama Powers effective tax rate was 38.9% for the six months ended June 30, 2012 compared to 38.5% for the corresponding period in 2011. The increase was due to an increase in Alabama state income taxes as a result of a decrease in the state income tax deduction for federal income taxes paid.
Georgia Power
Georgia Powers effective tax rate was 34.2% for the six months ended June 30, 2012 compared to 34.8% for the corresponding period in 2011. The decrease was primarily related to state income tax credits, partially offset by a decrease in non-taxable AFUDC equity. See Unrecognized Tax Benefits herein for additional information.
Gulf Power
Gulf Powers effective tax rate was 36.6% for the six months ended June 30, 2012 compared to 35.9% for the corresponding period in 2011. The increase was primarily due to a decrease in non-taxable AFUDC equity.
Mississippi Power
Mississippi Powers effective tax rate was 25.2% for the six months ended June 30, 2012 compared to 32.6% for the corresponding period in 2011. The decrease was primarily due to an increase in non-taxable AFUDC equity related to the Kemper IGCC construction.
Southern Power
Southern Powers effective tax rate was 35.9% for the six months ended June 30, 2012 compared to 35.3% for the corresponding period in 2011. The increase was due to less tax benefits from convertible investment tax credits associated with qualifying construction activity.
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
Unrecognized Tax Benefits
Changes during 2012 for unrecognized tax benefits were as follows:
Southern Company |
Alabama Power |
Georgia Power |
Gulf Power |
Mississippi Power |
Southern Power |
|||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Unrecognized tax benefits as of December 31, 2011 |
$ | 120 | $ | 32 | $ | 47 | $ | 3 | $ | 5 | $ | 3 | ||||||||||||
Tax positions from current periods |
4 | 2 | 2 | 1 | | | ||||||||||||||||||
Tax positions from prior periods |
(23 | ) | (3 | ) | (19 | ) | (1 | ) | (1 | ) | (2 | ) | ||||||||||||
Reductions due to settlements |
(5 | ) | (2 | ) | (4 | ) | (1 | ) | | 1 | ||||||||||||||
Reductions due to expired statute of limitations |
(3 | ) | | (3 | ) | | | | ||||||||||||||||
Balance as of June 30, 2012 |
$ | 93 | $ | 29 | $ | 23 | $ | 2 | $ | 4 | $ | 2 | ||||||||||||
The tax positions from current periods relate primarily to state income tax credits and the tax accounting method change for repairs-generation assets. See Tax Method of Accounting for Repairs herein for additional information. The decreases in tax positions from prior periods primarily relate to state income tax credits. The reductions due to settlements relate to a settlement with the IRS of the calculation methodology for the production activities deduction.
The impact on the effective tax rate, if recognized, was as follows:
As of June 30, 2012 | As of December 31, 2011 |
|||||||||||||||
|
||||||||||||||||
Georgia Power |
Other Registrants |
Southern Company |
Southern Company |
|||||||||||||
|
||||||||||||||||
(in millions) | ||||||||||||||||
Tax positions impacting the effective tax rate |
$ | 3 | $ | 4 | $ | 38 | $ | 69 | ||||||||
Tax positions not impacting the effective tax rate |
20 | 33 | 55 | 51 | ||||||||||||
|
||||||||||||||||
Balance of unrecognized tax benefits |
$ | 23 | $ | 37 | $ | 93 | $ | 120 | ||||||||
|
The tax positions impacting the effective tax rate primarily relate to state income tax credits and a litigation settlement refund claim for Southern Company. See Note 5 to the financial statements of Southern Company under Effective Tax Rate in Item 8 of the Form 10-K for additional information. The tax positions not impacting the effective tax rate relate to the timing difference associated with the tax accounting method change for repairs-generation assets. See Tax Method of Accounting for Repairs herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
Accrued interest for unrecognized tax benefits was as follows:
Georgia Power |
Other Registrants |
Southern Company |
||||||||||
|
||||||||||||
(in millions) | ||||||||||||
Interest accrued as of December 31, 2011 |
$ | 6 | $ | 3 | $ | 10 | ||||||
Interest reclassified due to settlements |
(6 | ) | (2 | ) | (9 | ) | ||||||
Interest accrued during the period |
| | | |||||||||
|
||||||||||||
Balance as of June 30, 2012 |
$ | | $ | 1 | $ | 1 | ||||||
|
All of the registrants classify interest on tax uncertainties as interest expense. The interest reclassified due to settlements is primarily associated with state income tax credits and a settlement with the IRS related to the calculation methodology for the production activities deduction.
None of the registrants accrued any penalties on uncertain tax positions.
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
It is reasonably possible that the amount of the unrecognized tax benefits associated with a majority of the registrants unrecognized tax positions will significantly increase or decrease within the next 12 months. The resolution of the tax accounting method change for repairs-generation assets, as well as the conclusion or settlement of federal and state audits, could also impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
Tax Method of Accounting for Repairs
Southern Company submitted a tax accounting method change for repair costs associated with its subsidiaries generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. In August 2011, the IRS issued a revenue procedure, which provides a safe harbor method of accounting that taxpayers may use to determine repair costs for transmission and distribution property. However, the IRS continues to work with the utility industry in an effort to resolve the repair costs for generation assets matter in a consistent manner for all utilities. In December 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2012. The utility industry anticipates more detailed guidance concerning these regulations. Due to uncertainty regarding the ultimate resolution of the repair costs for generation assets, an unrecognized tax position has been recorded for the tax accounting method change for repairs-generation assets. The ultimate outcome of this matter cannot be determined at this time.
(H) DERIVATIVES
Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk, interest rate risk, and occasionally foreign currency risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each companys policies in areas such as counterparty exposure and risk management practices. Each companys policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities.
Energy-Related Derivatives
The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. Southern Power has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity.
To mitigate residual risks relative to movements in electricity prices, the traditional operating companies and Southern Power may enter into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
Energy-related derivative contracts are accounted for in one of three methods:
| Regulatory Hedges Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional operating companies fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses. |
| Cash Flow Hedges Gains and losses on energy-related derivatives designated as cash flow hedges, which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions, are reflected in earnings. |
| Not Designated Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. |
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At June 30, 2012, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:
Net mmBtu |
Longest Hedge Date |
Longest Non-Hedge Date |
||||||||||
|
||||||||||||
(in millions) | ||||||||||||
Southern Company |
242 | 2017 | 2017 | |||||||||
Alabama Power |
43 | 2017 | | |||||||||
Georgia Power |
96 | 2017 | | |||||||||
Gulf Power |
51 | 2017 | | |||||||||
Mississippi Power |
34 | 2017 | | |||||||||
Southern Power |
18 | 2012 | 2017 | |||||||||
|
In addition to the volumes discussed in the above table, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 8 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 3 million mmBtu for Georgia Power, 1 million mmBtu for Gulf Power, 1 million mmBtu for Mississippi Power, and 2 million mmBtu for Southern Power.
For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending June 30, 2013 are immaterial for all registrants.
Interest Rate Derivatives
Southern Company and certain subsidiaries also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives fair value gains or losses and hedged items fair value gains or losses are both recorded directly to earnings, providing an offset with any difference representing ineffectiveness.
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
At June 30, 2012, the following interest rate derivatives were outstanding:
Notional Amount |
Interest Rate Received |
Interest Rate Paid |
Hedge Maturity Date |
Fair Value Gain (Loss) June 30, 2012 | ||||||||||||||
| ||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||
Cash flow hedges of forecasted transactions |
||||||||||||||||||
Alabama Power |
$ | 300 | |
3-month LIBOR |
|
2.90%(a) | December 2022 | $(28) | ||||||||||
Fair value hedges of existing debt |
||||||||||||||||||
Southern Company |
350 | 4.15% | |
3-month LIBOR + 1.96%(a) |
|
May 2014 | 12 | |||||||||||
|
| |||||||||||||||||
Total |
$ | 650 | $(16) | |||||||||||||||
|
|
(a) | Weighted Average |
The following table reflects the estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period ending June 30, 2013, together with the longest date that total deferred gains and losses are expected to be amortized into earnings.
Registrant | Estimated Gain (Loss) to be Reclassified for the 12 Months Ending June 30, 2013 |
Total Deferred Gains (Losses) |
||||
| ||||||
(in millions) | ||||||
Southern Company |
$(17) | 2037 | ||||
Alabama Power |
(1) | 2035 | ||||
Georgia Power |
(3) | 2037 | ||||
Gulf Power |
(1) | 2020 | ||||
Mississippi Power |
(1) | 2022 | ||||
Southern Power |
(11) | 2016 | ||||
|
Foreign Currency Derivatives
Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as fair value hedges where the derivatives fair value gains or losses and the hedged items fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as a cash flow hedge where the effective portion of the derivatives fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. Any ineffectiveness is typically recorded directly to earnings; however, Mississippi Power has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
At June 30, 2012, the following foreign currency derivatives were outstanding:
Notional Amount |
Forward Rate |
Hedge Maturity Date |
Fair Value Gain (Loss) June 30, 2012 | |||||
| ||||||||
(in millions) | (in millions) | |||||||
Fair value hedges of firm commitments |
||||||||
Mississippi Power |
EUR6.3 | 1.3850 Dollars per Euro(a) |
Various through March 2014 |
$(1) | ||||
Derivatives not designated as hedges |
||||||||
Mississippi Power |
EUR18.1 | 1.3186 Dollars per Euro(a) |
N/A | (1) | ||||
|
| |||||||
Total |
EUR24.4 | $(2) | ||||||
|
|
(a) | Weighted Average |
Derivative Financial Statement Presentation and Amounts
At June 30, 2012, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
Asset Derivatives at June 30, 2012 | ||||||||||||||||||||||||
|
||||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||
Derivative Category and Balance Sheet Location | Southern Company |
Alabama Power |
Georgia Power |
Gulf Power |
Mississippi Power |
Southern Power |
||||||||||||||||||
|
||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Derivatives designated as hedging instruments for regulatory purposes |
||||||||||||||||||||||||
Energy-related derivatives: |
||||||||||||||||||||||||
Other current assets |
$ | 14 | $ | 1 | $ | 13 | $ | | $ | | ||||||||||||||
Other deferred charges and assets |
9 | 2 | 4 | 2 | 1 | |||||||||||||||||||
|
||||||||||||||||||||||||
Total derivatives designated as hedging instruments for regulatory purposes |
$ | 23 | $ | 3 | $ | 17 | $ | 2 | $ | 1 | N/A | |||||||||||||
|
||||||||||||||||||||||||
Derivatives designated as hedging instruments in cash flow and fair value hedges |
||||||||||||||||||||||||
Interest rate derivatives: |
||||||||||||||||||||||||
Other current assets |
$ | 6 | $ | | $ | | $ | | $ | | $ | | ||||||||||||
Other deferred charges and assets |
6 | | | | | | ||||||||||||||||||
|
||||||||||||||||||||||||
Total derivatives designated as hedging instruments in cash flow and fair value hedges |
$ | 12 | $ | | $ | | $ | | $ | | $ | | ||||||||||||
|
||||||||||||||||||||||||
Derivatives not designated as hedging instruments |
||||||||||||||||||||||||
Energy-related derivatives: |
||||||||||||||||||||||||
Other deferred charges and assets |
$ | 1 | $ | | $ | | $ | | $ | | $ | 1 | ||||||||||||
|
||||||||||||||||||||||||
Total asset derivatives |
$ | 36 | $ | 3 | $ | 17 | $ | 2 | $ | 1 | $ | 1 | ||||||||||||
|
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
Liability Derivatives at June 30, 2012
| ||||||||||||
Fair Value | ||||||||||||
Derivative Category and Balance Sheet Location |
Southern Company |
Alabama Power |
Georgia Power |
Gulf Power |
Mississippi Power |
Southern Power | ||||||
| ||||||||||||
(in millions) | ||||||||||||
Derivatives designated as hedging instruments for regulatory purposes |
||||||||||||
Energy-related derivatives: |
||||||||||||
Liabilities from risk management activities |
$123 | $26 | $ 52 | $20 | $25 | |||||||
Other deferred credits and liabilities |
64 | 9 | 23 | 19 | 13 | |||||||
| ||||||||||||
Total derivatives designated as hedging instruments for regulatory purposes |
$187 | $35 | $75 | $39 | $38 | N/A | ||||||
| ||||||||||||
Derivatives designated as hedging instruments in cash flow and fair value hedges |
||||||||||||
Energy-related derivatives: |
||||||||||||
Liabilities from risk management activities |
$ 1 | $ | $ | $ | $ | $1 | ||||||
Interest rate derivatives: |
||||||||||||
Liabilities from risk management activities |
28 | 28 | | | | | ||||||
Foreign currency derivatives: |
||||||||||||
Liabilities from risk management activities |
1 | | | | 1 | | ||||||
| ||||||||||||
Total derivatives designated as hedging instruments in cash flow and fair value hedges |
$ 30 | $28 | $ | $ | $1 | $1 | ||||||
| ||||||||||||
Derivatives not designated as hedging instruments |
||||||||||||
Energy-related derivatives: |
||||||||||||
Liabilities from risk management activities |
$ 6 | $ | $ | $ | $ | $6 | ||||||
Foreign currency derivatives: |
||||||||||||
Liabilities from risk management activities |
1 | | | | 1 | | ||||||
| ||||||||||||
Total derivatives not designated as hedging instruments |
$ 7 | $ | $ | $ | $ 1 | $6 | ||||||
| ||||||||||||
Total liability derivatives |
$224 | $63 | $75 | $39 | $40 | $7 | ||||||
|
All derivative instruments are measured at fair value. See Note (C) herein for additional information.
At June 30, 2012, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet | ||||||||||||||||||||
|
||||||||||||||||||||
Derivative Category and Balance Sheet Location |
Southern Company |
Alabama Power |
Georgia Power |
Gulf Power |
Mississippi Power |
|||||||||||||||
|
||||||||||||||||||||
(in millions) | ||||||||||||||||||||
Energy-related derivatives: |
||||||||||||||||||||
Other regulatory assets, current |
$(123) | $(26) | $(52) | $(20) | $(25) | |||||||||||||||
Other regulatory assets, deferred |
(64) | (9) | (23) | (19) | (13) | |||||||||||||||
Other regulatory liabilities, current |
14 | 1 | 13 | | | |||||||||||||||
Other regulatory liabilities, deferred |
9 | 2 | | 2 | 1 | |||||||||||||||
Other deferred credits and liabilities(a) |
| | 4 | | | |||||||||||||||
|
||||||||||||||||||||
Total energy-related derivative gains (losses) |
$(164) | $(32) | $(58) | $(37) | $(37) | |||||||||||||||
|
(a) | Georgia Power includes Other regulatory liabilities, deferred in Other deferred credits and liabilities. |
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
For the three and six months ended June 30, 2012 and June 30, 2011, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments on Southern Companys statements of income were immaterial.
For the three and six months ended June 30, 2012 and June 30, 2011, the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on Southern Companys and Mississippi Powers statements of income were immaterial and were offset with changes in the fair value of the purchase commitment related to equipment purchases; therefore, there was no impact on Southern Companys or Mississippi Powers statements of income.
For the three months ended June 30, 2012 and 2011, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:
Derivatives in Cash Flow | Gain (Loss) Recognized in OCI on Derivative |
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | ||||||||
Hedging Relationships | (Effective Portion) | Statements of Income Location | Amount | |||||||
| ||||||||||
2012 | 2011 | 2012 | 2011 | |||||||
| ||||||||||
(in millions) | (in millions) | |||||||||
Southern Company |
||||||||||
Interest rate derivatives |
$ (18) | $ | Interest expense, net of amounts capitalized |
$ (4) | $ (1) | |||||
| ||||||||||
Alabama Power |
||||||||||
Interest rate derivatives |
$ (18) | $ | Interest expense, net of amounts capitalized |
$ | $ 3 | |||||
| ||||||||||
Georgia Power |
||||||||||
Interest rate derivatives |
$ | $ | Interest expense, net of amounts capitalized |
$ (1) | $ (1) | |||||
| ||||||||||
Southern Power |
||||||||||
Interest rate derivatives |
$ | $ | Interest expense, net of amounts capitalized |
$ (3) | $ (3) | |||||
|
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
For the six months ended June 30, 2012 and 2011, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:
Derivatives in Cash Flow Hedging |
Gain (Loss) Recognized in OCI on Derivative |
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | ||||||||
Relationships | (Effective Portion) | Statements of Income Location | Amount | |||||||
|
|
|
|
|
| |||||
2012 | 2011 | 2012 | 2011 | |||||||
| ||||||||||
(in millions) | (in millions) | |||||||||
Southern Company |
||||||||||
Energy-related derivatives |
$ | $ 1 | Fuel | $ | $ | |||||
Interest rate derivatives |
(12) | 4 | Interest expense, net of amounts capitalized | (7) | (6) | |||||
| ||||||||||
Total |
$ (12) | $ 5 | $ (7) | $ (6) | ||||||
| ||||||||||
Alabama Power |
||||||||||
Interest rate derivatives |
$ (11) | $ 4 | Interest expense, net of amounts capitalized |
$ | $ 3 | |||||
| ||||||||||
Georgia Power |
||||||||||
Interest rate derivatives |
$ | $ | Interest expense, net of amounts capitalized |
$ (2) | $ (2) | |||||
| ||||||||||
Mississippi Power |
||||||||||
Interest rate derivatives |
$ (1) | $ | Interest expense, net of amounts capitalized |
$ | $ | |||||
| ||||||||||
Southern Power |
||||||||||
Energy-related derivatives |
$ | $ 1 | Fuel | $ | $ | |||||
Interest rate derivatives |
| | Interest expense, net of amounts capitalized |
(5) | (6) | |||||
| ||||||||||
Total |
$ | $ 1 | $ (5) | $ (6) | ||||||
|
There was no material ineffectiveness recorded in earnings for any registrant for any period presented.
For the three and six months ended June 30, 2012, the net unrealized pre-tax gains from energy-related derivatives not designated as hedging instruments on Southern Companys and Southern Powers statements of income were $10 million and $4 million, respectively. For the three and six months ended June 30, 2011, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were immaterial for all registrants.
For the three and six months ended June 30, 2012, the pre-tax effects of foreign currency derivatives not designated as hedging instruments were recorded as regulatory assets and liabilities and were immaterial for Southern Company and Mississippi Power.
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
Contingent Features
The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At June 30, 2012, the fair value of derivative liabilities with contingent features, by registrant, was as follows:
Southern Company |
Alabama Power |
Georgia Power |
Gulf Power |
Mississippi Power |
Southern Power | |||||||
| ||||||||||||
(in millions) | ||||||||||||
Derivative liabilities |
$27 | $6 | $8 | $6 | $5 | $2 |
At June 30, 2012, the registrants had no collateral posted with their derivative counterparties. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $27 million for each registrant. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. For the traditional operating companies and Southern Power, included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade.
(I) | ACQUISITIONS |
Apex Nevada Solar, LLC Acquisition
On June 29, 2012, Southern Power and Turner Renewable Energy, Inc., through a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Apex Nevada Solar, LLC (Apex) from Sun Edison, LLC, the original developer of the project. Apex constructed and owns a 20-MW solar photovoltaic facility in North Las Vegas, Nevada. Commercial operation of the solar facility was declared by Apex on July 21, 2012. The output of the plant is contracted under a PPA with Nevada Power Company, a subsidiary of NV Energy, Inc., that began in 2012 and expires in 2037. This PPA will be accounted for as an operating lease. The acquisition is in accordance with Southern Powers overall growth strategy.
Southern Powers acquisition of Apex included cash consideration of $102 million, of which $86.5 million was paid at closing. The remaining $15.5 million will be paid upon achievement of certain milestones. Due to the proximity of the closing date to June 30, 2012, there has not been sufficient time to complete the final allocation of the purchase price to individual assets. As of June 30, 2012, the entire purchase price is reflected in CWIP on Southern Powers Condensed Balance Sheet herein.
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(J) | SEGMENT AND RELATED INFORMATION |
Southern Companys reportable business segments are the sale of electricity in the Southeast by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $106 million and $218 million for the three and six months ended June 30, 2012, respectively, and $71 million and $154 million for the three and six months ended June 30, 2011, respectively. The All Other column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications and leveraged lease projects. All other intersegment revenues are not material. Financial data for business segments and products and services was as follows:
Electric Utilities | ||||||||||||||||||||||||||||||||
Traditional Operating Companies |
Southern Power |
Eliminations | Total | All Other |
Eliminations | Consolidated | ||||||||||||||||||||||||||
|
|
|||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
Three Months Ended June 30, 2012: |
||||||||||||||||||||||||||||||||
Operating revenues |
$ | 3,989 | $ | 286 | $ | (109) | $ | 4,166 | $ | 35 | $ | (20) | $ | 4,181 | ||||||||||||||||||
Segment net income (loss)(a) |
549 | 47 | | 596 | 27 | | 623 | |||||||||||||||||||||||||
Six Months Ended June 30, 2012: |
||||||||||||||||||||||||||||||||
Operating revenues |
$ | 7,438 | $ | 539 | $ | (222) | $ | 7,755 | $ | 73 | $ | (43) | $ | 7,785 | ||||||||||||||||||
Segment net income (loss)(a) |
888 | 76 | | 964 | 28 | (1) | 991 | |||||||||||||||||||||||||
Total assets at June 30, 2012 |
$ | 56,726 | $ | 3,785 | $ | (126) | $ | 60,385 | $ | 1,132 | $ | (620) | $ | 60,897 | ||||||||||||||||||
|
||||||||||||||||||||||||||||||||
Three Months Ended June 30, 2011: |
||||||||||||||||||||||||||||||||
Operating revenues |
$ | 4,291 | $ | 305 | $ | (93) | $ | 4,503 | $ | 38 | $ | (20) | $ | 4,521 | ||||||||||||||||||
Segment net income (loss)(a) |
559 | 44 | | 603 | 1 | | 604 | |||||||||||||||||||||||||
Six Months Ended June 30, 2011: |
||||||||||||||||||||||||||||||||
Operating revenues |
$ | 8,101 | $ | 587 | $ | (191) | $ | 8,497 | $ | 76 | $ | (40) | $ | 8,533 | ||||||||||||||||||
Segment net income (loss)(a) |
943 | 82 | | 1,025 | 2 | (1) | 1,026 | |||||||||||||||||||||||||
Total assets at December 31, 2011 |
$ | 54,622 | $ | 3,581 | $ | (127 | ) | $ | 58,076 | $ | 1,592 | $ | (401) | $ | 59,267 | |||||||||||||||||
|
(a) After dividends on preferred and preference stock of subsidiaries
Products and Services
Electric Utilities Revenues | ||||||||||||||||
Period |
Retail | Wholesale | Other | Total | ||||||||||||
|
|
|||||||||||||||
(in millions) | ||||||||||||||||
Three Months Ended June 30, 2012 |
$ | 3,597 | $ | 415 | $ | 154 | $ | 4,166 | ||||||||
Three Months Ended June 30, 2011 |
3,842 | 507 | 154 | 4,503 | ||||||||||||
Six Months Ended June 30, 2012 |
$ | 6,689 | $ | 764 | $ | 302 | $ | 7,755 | ||||||||
Six Months Ended June 30, 2011 |
7,238 | 956 | 303 | 8,497 | ||||||||||||
|
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See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.
See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. There have been no material changes to these risk factors from those previously disclosed in the Form 10-K.
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(4) Instruments Describing Rights of Security Holders, Including Indentures
Georgia Power
(c)1 | - |
Forty-Seventh Supplemental Indenture to Senior Note Indenture dated as of May 11, 2012, providing for the issuance of the Series 2012B 2.85% Senior Notes due May 15, 2022. (Designated in Form 8-K dated May 8, 2012, File No. 1-6468, as Exhibit 4.2(b).) |
Gulf Power
(e)1 | - |
Nineteenth Supplemental Indenture to Senior Note Indenture dated as of May 18, 2012, providing for the issuance of the Series 2012A 3.10% Senior Notes due May 15, 2022. (Designated in Form 8-K dated May 15, 2012, File No. 001-31737, as Exhibit 4.2.) |
(10) Material Contracts
Southern Company
(a)1 | - | Retention and Restricted Stock Unit Award Agreement by and between Southern Company and Charles D. McCrary effective May 22, 2012. |
(a)2 | - | Consulting Agreement by and with Southern Company Services, Inc. and Anthony J. Topazi effective August 1, 2012. |
Alabama Power
(a)1 | - | Retention and Restricted Stock Unit Award Agreement by and between Southern Company and Charles D. McCrary effective May 22, 2012. See Exhibit 10(a)1 herein. |
(24) Power of Attorney and Resolutions
Southern Company
(a)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2011, File No. 1-3526 as Exhibit 24(a) and incorporated herein by reference.) |
Alabama Power
(b)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2011, File No. 1-3164 as Exhibit 24(b) and incorporated herein by reference.) |
Georgia Power
(c)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2011, File No. 1-6468 as Exhibit 24(c) and incorporated herein by reference.) |
Gulf Power
(d)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2011, File No. 001-31737 as Exhibit 24(d) and incorporated herein by reference.) |
(d)2 | - | Power of Attorney for S. W. Connally, Jr. |
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Mississippi Power | ||||
(e)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2011, File No. 001-11229 as Exhibit 24(e) and incorporated herein by reference.) | ||
Southern Power | ||||
(f)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2011, File No. 333-98553 as Exhibit 24(f) and incorporated herein by reference.) | ||
(31) Section 302 Certifications | ||||
Southern Company | ||||
(a)1 | - | Certificate of Southern Companys Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. | ||
(a)2 | - | Certificate of Southern Companys Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. | ||
Alabama Power | ||||
(b)1 | - | Certificate of Alabama Powers Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. | ||
(b)2 | - | Certificate of Alabama Powers Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. | ||
Georgia Power | ||||
(c)1 | - | Certificate of Georgia Powers Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. | ||
(c)2 | - | Certificate of Georgia Powers Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. | ||
Gulf Power | ||||
(d)1 | - | Certificate of Gulf Powers Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. | ||
(d)2 | - | Certificate of Gulf Powers Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. | ||
Mississippi Power | ||||
(e)1 | - | Certificate of Mississippi Powers Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. | ||
(e)2 | - | Certificate of Mississippi Powers Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
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Southern Power | ||||
(f)1 | - | Certificate of Southern Powers Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. | ||
(f)2 | - | Certificate of Southern Powers Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. | ||
(32) Section 906 Certifications | ||||
Southern Company | ||||
(a) | - | Certificate of Southern Companys Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. | ||
Alabama Power | ||||
(b) | - | Certificate of Alabama Powers Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. | ||
Georgia Power | ||||
(c) | - | Certificate of Georgia Powers Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. | ||
Gulf Power | ||||
(d) | - | Certificate of Gulf Powers Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. | ||
Mississippi Power | ||||
(e) | - | Certificate of Mississippi Powers Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. | ||
Southern Power | ||||
(f) | - | Certificate of Southern Powers Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. |
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(101) | XBRL Related Documents | |
INS | XBRL Instance Document | |
SCH | XBRL Taxonomy Extension Schema Document | |
CAL | XBRL Taxonomy Calculation Linkbase Document | |
DEF | XBRL Definition Linkbase Document | |
LAB | XBRL Taxonomy Label Linkbase Document | |
PRE | XBRL Taxonomy Presentation Linkbase Document |
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THE SOUTHERN COMPANY
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such companys report.
THE SOUTHERN COMPANY | ||
By |
Thomas A. Fanning | |
Chairman, President, and Chief Executive Officer | ||
(Principal Executive Officer) | ||
By |
Art P. Beattie | |
Executive Vice President and Chief Financial Officer | ||
(Principal Financial Officer) | ||
By |
/s/ Melissa K. Caen | |
(Melissa K. Caen, Attorney-in-fact) |
Date: August 6, 2012
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ALABAMA POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such companys report.
ALABAMA POWER COMPANY | ||
By |
Charles D. McCrary | |
President and Chief Executive Officer | ||
(Principal Executive Officer) | ||
By |
Philip C. Raymond | |
Executive Vice President, Chief Financial Officer, and Treasurer | ||
(Principal Financial Officer) | ||
By |
/s/ Melissa K. Caen | |
(Melissa K. Caen, Attorney-in-fact) |
Date: August 6, 2012
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GEORGIA POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such companys report.
GEORGIA POWER COMPANY | ||
By |
W. Paul Bowers | |
President and Chief Executive Officer | ||
(Principal Executive Officer) | ||
By |
Ronnie R. Labrato | |
Executive Vice President, Chief Financial Officer, and Treasurer | ||
(Principal Financial Officer) | ||
By |
/s/ Melissa K. Caen | |
(Melissa K. Caen, Attorney-in-fact) |
Date: August 6, 2012
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GULF POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such companys report.
GULF POWER COMPANY | ||
By |
S. W. Connally, Jr. | |
President and Chief Executive Officer | ||
(Principal Executive Officer) | ||
By |
Richard S. Teel | |
Vice President and Chief Financial Officer | ||
(Principal Financial Officer) | ||
By |
/s/ Melissa K. Caen | |
(Melissa K. Caen, Attorney-in-fact) |
Date: August 6, 2012
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MISSISSIPPI POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such companys report.
MISSISSIPPI POWER COMPANY | ||
By |
Edward Day, VI | |
President and Chief Executive Officer | ||
(Principal Executive Officer) | ||
By |
Moses H. Feagin | |
Vice President, Chief Financial Officer, and Treasurer | ||
(Principal Financial Officer) | ||
By |
/s/ Melissa K. Caen | |
(Melissa K. Caen, Attorney-in-fact) |
Date: August 6, 2012
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SOUTHERN POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such companys report.
SOUTHERN POWER COMPANY | ||
By |
Oscar C. Harper, IV | |
President and Chief Executive Officer | ||
(Principal Executive Officer) | ||
By |
Michael W. Southern | |
Senior Vice President, Chief Financial Officer, and Treasurer | ||
(Principal Financial Officer) | ||
By |
/s/ Melissa K. Caen | |
(Melissa K. Caen, Attorney-in-fact) |
Date: August 6, 2012
195