CONNECTICUT LIGHT & POWER CO - Quarter Report: 2008 March (Form 10-Q)
____________________________________________________________________________________
![[march2008form10qedgar001.jpg]](https://www.sec.gov/Archives/edgar/data/0000023426/000007274108000160/march2008form10qedgar001.jpg)
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE |
|
|
| For the Quarterly Period Ended March 31, 2008 |
| OR |
[ ] | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE |
|
|
| For the transition period from ____________ to ____________ |
Commission | Registrant; State of Incorporation; | I.R.S. Employer |
|
|
|
1-5324 | NORTHEAST UTILITIES | 04-2147929 |
|
|
|
0-00404 | THE CONNECTICUT LIGHT AND POWER COMPANY | 06-0303850 |
|
|
|
1-6392 | PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE | 02-0181050 |
|
|
|
0-7624 | WESTERN MASSACHUSETTS ELECTRIC COMPANY | 04-1961130 |
____________________________________________________________________________________
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 | No |
|
|
|
| Ö |
|
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (check one):
| Large |
| Accelerated |
| Non-accelerated |
|
|
|
|
|
|
Northeast Utilities | Ö |
|
|
|
|
The Connecticut Light and Power Company |
|
|
|
| Ö |
Public Service Company of New Hampshire |
|
|
|
| Ö |
Western Massachusetts Electric Company |
|
|
|
| Ö |
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act):
| Yes | No |
|
|
|
Northeast Utilities |
| Ö |
The Connecticut Light and Power Company |
| Ö |
Public Service Company of New Hampshire |
| Ö |
Western Massachusetts Electric Company |
| Ö |
Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date:
Company - Class of Stock | Outstanding at April 30, 2008 |
Northeast Utilities |
|
|
|
The Connecticut Light and Power Company |
|
|
|
Public Service Company of New Hampshire |
|
|
|
Western Massachusetts Electric Company |
|
Northeast Utilities holds all of the 6,035,205 shares, 301 shares, and 434,653 shares of the outstanding common stock of The Connecticut Light and Power Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company, respectively.
Public Service Company of New Hampshire and Western Massachusetts Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and therefore filed their 2007 Form 10-K with the reduced disclosure format specified in General Instruction I(2) to Form 10-K.
GLOSSARY OF TERMS | |
The following is a glossary of frequently used abbreviations or acronyms that are found in this report. | |
|
|
NU COMPANIES, SEGMENTS OR INVESTMENTS: | |
|
|
Boulos | E.S. Boulos Company |
CL&P | The Connecticut Light and Power Company |
Con Edison | Consolidated Edison, Inc. |
CRC | CL&P Receivables Corporation |
HWP | Holyoke Water Power Company |
Mt. Tom | Mt. Tom generating plant |
NGC | Northeast Generation Company |
NGS | Northeast Generation Services Company and subsidiaries |
NU or the company | Northeast Utilities |
NU Enterprises | At March 31, 2008, NU Enterprises, Inc. is the parent company of Select Energy, NGS, and Boulos. For further information, see Note 9, "Segment Information," to the condensed consolidated financial statements. |
NU parent and other companies | NU parent and other companies is comprised of NU parent, Northeast Utilities Service Company, HWP (since January 1, 2007) and other subsidiaries, including The Rocky River Realty Company and The Quinnehtuk Company (both real estate subsidiaries), Mode 1 Communications, Inc. (telecommunications) and the nonenergy-related subsidiaries of Yankee (Yankee Energy Services Company), Yankee Energy Financial Services Company, and NorConn Properties, Inc. |
PSNH | Public Service Company of New Hampshire |
Regulated companies | NU's regulated companies, comprised of the electric distribution and transmission segments of CL&P, PSNH, WMECO, the generation segment of PSNH and Yankee Gas, which is a natural gas local distribution company. For further information, see Note 9, "Segment Information," to the condensed consolidated financial statements. |
SECI | Select Energy Contracting, Inc. |
Select Energy | Select Energy, Inc. |
SESI | Select Energy Services, Inc. |
WMECO | Western Massachusetts Electric Company |
Yankee | Yankee Energy System, Inc. |
Yankee Gas | Yankee Gas Services Company |
|
|
REGULATORS: |
|
|
|
DPU | Massachusetts Department of Public Utilities (formerly the Massachusetts Department of Telecommunications and Energy (DTE)) |
DPUC | Connecticut Department of Public Utility Control |
FERC | Federal Energy Regulatory Commission |
NHPUC | New Hampshire Public Utilities Commission |
SEC | Securities and Exchange Commission |
i
OTHER: |
|
|
|
AFUDC | Allowance For Funds Used During Construction |
CfD | Contract for Differences |
CTA | Competitive Transition Assessment |
EPS | Earnings Per Share |
ES | Default Energy Service |
FASB | Financial Accounting Standards Board |
FMCC | Federally Mandated Congestion Charges |
GSC | Generation Service Charge |
ISO-NE | New England Independent System Operator or ISO New England, Inc. |
KWH | Kilowatt-Hour |
KV | Kilovolt |
LOC | Letter of Credit |
MW | Megawatts |
NU 2007 Form 10-K | The Northeast Utilities and Subsidiaries combined 2007 Annual Report on Form 10-K as filed with the SEC |
NYMPA | New York Municipal Power Agency |
PBOP | Postretirement Benefits Other Than Pensions |
Regulatory ROE | The average cost of capital method for calculating the return on equity related to the distribution and generation business segments excluding the wholesale transmission segment. |
RMR | Reliability Must Run |
ROE | Return on Equity |
SBC | System Benefits Charge |
SCRC | Stranded Cost Recovery Charge |
SFAS | Statement of Financial Accounting Standards |
TCAM | Transmission Cost Adjustment Mechanism |
TSO | Transitional Standard Offer |
UI | The United Illuminating Company |
VAR | Voltage Ampere Reactive |
ii
NORTHEAST UTILITIES AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
TABLE OF CONTENTS
iii
| Page | |
|
| |
ITEM 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations for the following companies: |
| |
| ||
48 | ||
| ||
68 | ||
| ||
71 | ||
| ||
73 | ||
| ||
ITEM 3 - Quantitative and Qualitative Disclosures About Market Risk | 75 | |
|
| |
76 | ||
| ||
PART II - OTHER INFORMATION | ||
| ||
77 | ||
| ||
77 | ||
| ||
ITEM 2 - Unregistered Sales of Equity Securities and Use of Proceeds | 77 | |
| ||
78 | ||
| ||
80 | ||
| ||
iv
NORTHEAST UTILITIES AND SUBSIDIARIES
1
2
3
4
5
NORTHEAST UTILITIES AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies)
A.
Presentation
Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). The accompanying unaudited condensed consolidated financial statements should be read in conjunction with the entirety of this Quarterly Report on Form 10-Q and the Annual Reports of Northeast Utilities (NU or the company), The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), and Western Massachusetts Electric Company (WMECO), which were filed with the SEC as part of the Northeast Utilities and subsidiaries combined 2007 Annual Report on Form 10-K (NU 2007 Form 10-K). The accompanying condensed consolidated financial statements contain, in the opinion of management, all adjustments (including normal, recurring adjustments) necessary to present fairly NU's and the above companies' financial position at March 31, 2008, and the results of operations and cash flows for the three months ended March 31, 2008 and 2007. The results of operations and cash flows for the three months ended March 31, 2008 and 2007 are not necessarily indicative of the results expected for a full year.
The condensed consolidated financial statements of NU and its subsidiaries, as applicable, include the accounts of all their respective subsidiaries. Intercompany transactions have been eliminated in consolidation.
The preparation of condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Certain reclassifications of prior period data included in the accompanying condensed consolidated financial statements have been made to conform with the current period's presentation.
NU's condensed consolidated statements of income for the three months ended March 31, 2007 classify activity related to the following subsidiaries as discontinued operations:
·
Northeast Generation Company (NGC),
·
The Mt. Tom generating plant (Mt. Tom) previously owned by Holyoke Water Power Company (HWP), and
·
Select Energy Contracting, Inc. (including Reeds Ferry Supply Co., Inc.) (SECI).
For the three months ended March 31, 2007, portions of SECI that were included in continuing operations have been reclassified to discontinued operations in the condensed consolidated statements of income as a result of winding down SECI operations in 2007. The amounts of these reclassifications are as follows:
(Millions of Dollars) |
|
|
| |
Operating revenues |
| $ | 0.8 |
|
Operating expenses |
|
| (1.1) |
|
Loss from discontinued operations |
|
| (0.3) |
|
Income tax benefit from discontinued operations |
|
| 0.1 |
|
Net loss from discontinued operations |
|
| (0.2) |
|
For further information regarding discontinued operations, see Note 7, "Discontinued Operations," to the condensed consolidated financial statements.
6
B.
Regulatory Accounting
The accounting policies of the regulated companies conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation."
The transmission and distribution segments of CL&P, PSNH and WMECO, along with PSNH's generation segment and Yankee Gas Service Company's (Yankee Gas) distribution segment, continue to be cost-of-service, rate regulated. Management believes that the application of SFAS No. 71 to those segments continues to be appropriate. Management also believes it is probable that NU's regulated companies will recover their investments in long-lived assets, including regulatory assets. All material net regulatory assets are earning an equity return, except for securitized regulatory assets and the majority of deferred benefit costs, which are not supported by equity. Amortization and deferrals of regulatory assets/(liabilities) are included on a net basis in amortization expense on the accompanying condensed consolidated statements of income.
Regulatory Assets: The components of regulatory assets are as follows:
|
| At March 31, 2008 | |||||||||||||
|
| NU |
|
|
|
|
|
|
| Yankee Gas | |||||
Securitized assets |
| $ | 847.2 |
| $ | 503.7 |
| $ | 261.4 |
| $ | 82.1 |
| $ | - |
Income taxes, net |
|
| 342.6 |
|
| 287.9 |
|
| 10.0 |
|
| 35.9 |
|
| 8.8 |
Deferred benefit costs |
|
| 191.9 |
|
| 68.2 |
|
| 48.5 |
|
| 7.5 |
|
| 67.7 |
Unrecovered contractual obligations |
|
| 184.5 |
|
| 144.1 |
|
| - |
|
| 40.4 |
|
| - |
Regulatory assets offsetting regulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CL&P CTA and SBC undercollections |
|
| 100.0 |
|
| 100.0 |
|
| - |
|
| - |
|
| - |
Other regulatory assets |
|
| 229.4 |
|
| 96.8 |
|
| 61.3 |
|
| 17.5 |
|
| 53.8 |
Totals |
| $ | 2,573.8 |
| $ | 1,878.9 |
| $ | 381.2 |
| $ | 183.4 |
| $ | 130.3 |
|
| At December 31, 2007 | |||||||||||||
|
| NU |
|
|
|
|
|
|
| Yankee Gas | |||||
Securitized assets |
| $ | 907.0 |
| $ | 548.2 |
| $ | 273.2 |
| $ | 85.6 |
| $ | - |
Income taxes, net |
|
| 335.5 |
|
| 279.4 |
|
| 10.3 |
|
| 38.2 |
|
| 7.6 |
Deferred benefit costs |
|
| 201.4 |
|
| 72.2 |
|
| 50.4 |
|
| 8.2 |
|
| 70.6 |
Unrecovered contractual obligations |
|
| 189.9 |
|
| 148.0 |
|
| - |
|
| 42.0 |
|
| (0.1) |
Regulatory assets offsetting regulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CL&P CTA and SBC undercollections |
|
| 90.6 |
|
| 90.6 |
|
| - |
|
| - |
|
| - |
Other regulatory assets |
|
| 210.4 |
|
| 71.8 |
|
| 65.0 |
|
| 19.9 |
|
| 53.7 |
Totals |
| $ | 2,057.1 |
| $ | 1,330.0 |
| $ | 401.4 |
| $ | 193.9 |
| $ | 131.8 |
For information regarding regulatory assets offsetting regulated company derivative liabilities, see Note 2, "Derivative Instruments," to the condensed consolidated financial statements.
Included in NU's other regulatory assets are the regulatory assets associated with the implementation of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $41.8 million at March 31, 2008 and $40.6 million at December 31, 2007. Of these amounts, $11.7 million and $11.6 million, respectively, have been approved for future recovery. Management believes that recovery of the remaining regulatory assets is probable.
Additionally, the regulated companies had $13.8 million and $11.9 million of regulatory costs at March 31, 2008 and December 31, 2007, respectively, that were included in deferred debits and other assets - other on the accompanying condensed consolidated balance sheets. These amounts represent regulatory costs that have not yet been approved for recovery by the applicable regulatory agency. Management believes these costs are recoverable in future cost-of-service regulated rates.
7
Regulatory Liabilities: The components of regulatory liabilities are as follows:
|
| At March 31, 2008 | |||||||||||||
|
| NU |
|
|
|
|
|
|
|
| |||||
Cost of removal |
| $ | 248.8 |
| $ | 103.2 |
| $ | 72.9 |
| $ | 21.1 |
| $ | 51.6 |
Regulatory liabilities offsetting |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CL&P GSC and FMCC overcollections |
|
| 59.5 |
|
| 59.5 |
|
| - |
|
| - |
|
| - |
Other regulatory liabilities |
|
| 146.0 |
|
| 64.5 |
|
| 41.8 |
|
| 12.5 |
|
| 27.2 |
Totals |
| $ | 752.3 |
| $ | 475.1 |
| $ | 164.7 |
| $ | 33.6 |
| $ | 78.9 |
|
| At December 31, 2007 | |||||||||||||
|
| NU |
|
|
|
|
|
|
|
| |||||
Cost of removal |
| $ | 262.6 |
| $ | 116.6 |
| $ | 72.8 |
| $ | 21.5 |
| $ | 51.7 |
Regulatory liabilities offsetting |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CL&P GSC and FMCC overcollections |
|
| 119.2 |
|
| 119.2 |
|
| - |
|
| - |
|
| - |
Other regulatory liabilities |
|
| 139.6 |
|
| 52.7 |
|
| 37.6 |
|
| 17.9 |
|
| 31.4 |
Totals |
| $ | 851.8 |
| $ | 601.5 |
| $ | 127.6 |
| $ | 39.4 |
| $ | 83.3 |
For information regarding regulatory liabilities offsetting regulated company derivative assets, see Note 2, "Derivative Instruments," to the condensed consolidated financial statements.
C.
Fair Value Measurements
On January 1, 2008, the company adopted SFAS No. 157, "Fair Value Measurements," which establishes a framework for defining and measuring fair value and requires expanded disclosures about fair value measurements. SFAS No. 157:
·
Defines fair value as the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price).
·
Establishes a three-level fair value hierarchy based upon the observability of inputs to the valuations of assets and liabilities.
·
Requires consideration of the company's own creditworthiness and risk of nonperformance when valuing its liabilities.
·
Requires prospective implementation with adjustments to fair value reflected in earnings, similar to a change in estimate, with exceptions including recognition of previously deferred initial gains or losses described below.
·
Requires recognition in retained earnings of previously deferred initial gains or losses on derivative contracts whose estimated fair values are based on significant unobservable inputs. Recognition of the initial gains or losses was previously prohibited under Emerging Issues Task Force Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." CL&P’s initial gains and losses on its contracts for differences (CfDs) that would have been recorded in retained earnings upon adoption were recorded as regulatory assets and liabilities because their costs or benefits are expected to be fully recovered from or refunded to customers.
The company applied SFAS No. 157 to the regulated and unregulated companies' derivative contracts that are recorded at fair value and to the marketable securities held in NU's Rabbi Trust and WMECO's prior spent nuclear fuel trust. SFAS No. 157 also applies to investment valuations for NU’s pension and other postretirement benefit plans beginning as of December 31, 2008, and beginning in 2009, to nonrecurring fair value measurements of non-financial assets and liabilities such as goodwill and asset retirement obligations.
As a result of adopting SFAS No. 157, the company recorded a pre-tax charge to earnings of $6.1 million as of January 1, 2008 related to derivative liabilities for its remaining unregulated wholesale marketing contracts. In the first quarter of 2008, the company recorded a $1.2 million pre-tax benefit to partially reverse the exit price impact recorded under SFAS No. 157 as the company served out rather than exited the contracts.
The company also recorded changes in fair value of certain derivative contracts of CL&P. Because CL&P is a cost-of-service, rate regulated entity, the cost or benefit of the contracts is expected to be fully recovered from or refunded to CL&P's customers and an offsetting regulatory asset or liability was recorded to reflect these changes. As of January 1, 2008, implementing SFAS No. 157
8
resulted in a total increase to CL&P's derivative liabilities, with an offset to regulatory assets, of approximately $590 million, and a total decrease to derivative assets, with an offset to regulatory liabilities, of approximately $30 million.
Fair Value Hierarchy: As required by SFAS No. 157, in measuring fair value the company uses observable market data when available and minimizes the use of unobservable inputs. Unobservable inputs are needed to value certain derivative contracts due to complexities in contractual terms and the long duration of a contract. SFAS No. 157 requires inputs used in fair value measurements to be categorized into three fair value hierarchy levels for disclosure purposes. The entire fair value measurement is categorized based on the lowest level of input that is significant to the fair value measurement.
The three levels of the fair value hierarchy are described below:
Level 1 – Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable.
Level 3 – Quoted market prices are not available. Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable. Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products. Significant unobservable inputs are used in the valuations, including items such as energy and energy-related product prices in future years for which observable prices are not yet available, future contract quantities under full-requirements or supplemental sales contracts, and market volatilities. Items valued using these valuation techniques are classified according to the lowest level for which there is at least one input that is significant to the valuation. Therefore, an item may be classified in Level 3 even though there may be some significant inputs that are readily observable.
Determination of Fair Value: The following is a description of the valuation techniques utilized in our fair value measurements:
Derivative contracts: Many of the company's derivative positions that are recorded at fair value are classified as Level 3 within the fair value hierarchy and are valued using models that incorporate both observable and unobservable inputs. Fair value is modeled using techniques such as discounted cash flow approaches adjusted for assumptions relating to exit price and the Black-Scholes option pricing model, incorporating the terms of the contracts. Significant unobservable inputs utilized in the valuations include energy and energy-related product prices for future years for long-dated derivative contracts, future contract quantities under full requirements and supplemental sales contracts, and market volatilities. Discounted cash flow valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using available historical market transaction information. Valuations of derivative contracts also reflect nonperformance risk, including credit. The derivative contracts classified as Level 3 include NU Enterprises, Inc.'s (NU Enterprises) remaining wholesale marketing contracts, CL&P's CfDs, CL&P's contracts with certain independent power producers (IPPs) and regulated company options and financial transmission rights (FTRs).
Other derivative contracts recorded at fair value are classified as Level 2 within the fair value hierarchy. An active market for the same or similar contracts exists for these contracts, which include regulated company forward contracts to purchase energy and interest rate swap agreements for the regulated companies and NU Parent. For these contracts, valuations are based on quoted prices in the market and include some modeling using market-based assumptions.
For further information on derivative contracts, see Note 2, "Derivative Instruments," to the condensed consolidated financial statements.
Marketable securities: The company holds in trust marketable securities, which include equity securities, mutual funds and cash equivalents, and fixed maturity securities.
Equity securities, mutual funds and cash equivalents are classified as Level 1 in the fair value hierarchy. These investments are traded in active markets and quoted prices are available for identical investments.
Fixed maturity securities classified as Level 2 within the fair value hierarchy include U.S. Treasury securities, corporate bonds, collateralized mortgage obligations, U.S. pass-through bonds, asset-backed securities, commercial mortgage-backed securities, and commercial paper. The fair value of these instruments is estimated using pricing models, quoted prices of securities with similar characteristics or discounted cash flows. The pricing models utilize observable inputs such as recent trades for the same or similar instruments, yield curves, discount margins and bond structures.
9
For further information see Note 3, "Fair Value Measurements," to the accompanying condensed consolidated financial statements.
D.
Allowance for Funds Used During Construction
The allowance for funds used during construction (AFUDC) is included in the cost of the regulated companies' utility plant and represents the cost of borrowed and equity funds used to finance construction. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of other interest expense, and the AFUDC related to equity funds is recorded as other income on the accompanying condensed consolidated statements of income:
| For the Three Months Ended | ||||
(Millions of Dollars, except percentages) | March 31, 2008 |
| March 31, 2007 | ||
Borrowed funds | $ | 4.7 |
| $ | 4.4 |
Equity funds |
| 8.3 |
|
| 2.4 |
Totals | $ | 13.0 |
| $ | 6.8 |
Average AFUDC rates |
| 8.2% |
|
| 6.8% |
The regulated companies' average AFUDC rate is based on a Federal Energy Regulatory Commission (FERC) prescribed formula that produces an average rate using the cost of a company's short-term financings as well as a company's capitalization (preferred stock, long-term debt and common equity). The average rate is applied to eligible construction work in progress (CWIP) amounts to calculate AFUDC. Although AFUDC is recorded on 100 percent of CL&P's CWIP for its major transmission projects in southwest Connecticut, 50 percent of this AFUDC is being reserved as a regulatory liability to reflect current rate base recovery for 50 percent of the CWIP as a result of FERC approved transmission incentives.
E.
Sale of Customer Receivables
CL&P Receivables Corporation (CRC), a consolidated, wholly-owned subsidiary of CL&P, has agreed to purchase an undivided interest in CL&P's accounts receivable and unbilled revenues and sell up to $100 million thereof to a financial institution. At March 31, 2008 and December 31, 2007, there were $100 million and $20 million in such sales, respectively.
At March 31, 2008 and December 31, 2007, amounts totaling $265.1 million and $308.2 million, respectively, sold to CRC by CL&P but not sold to the financial institution were included in investments in securitizable assets on the accompanying condensed consolidated balance sheets. These amounts would be excluded from CL&P's assets in the event of bankruptcy by CL&P.
On July 3, 2007, CL&P, CRC and the financial institution amended the Receivables Purchase and Sale Agreement, extending the financial institution's obligation through June 30, 2008, and extended the facility termination date to June 21, 2012. CL&P's continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables.
The transfer of receivables to the financial institution under this arrangement qualifies for sale treatment under SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - A Replacement of SFAS No. 125."
F.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and short-term cash investments that are highly liquid in nature and have original maturities of three months or less. At the end of each reporting period, any overdraft amounts are reclassified from cash and cash equivalents to accounts payable.
10
G.
Special Deposits
To the extent counterparties require collateral from Select Energy, Inc. (Select Energy), cash is held on deposit with unaffiliated counterparties and brokerage firms as a part of the total collateral required based on Select Energy's position in the transaction. Select Energy's right to use cash collateral is determined by the terms of the related agreements. Key factors affecting the unrestricted status of a portion of this cash collateral include the financial standing of Select Energy and of NU as its credit supporter.
Special deposits paid to unaffiliated counterparties and brokerage firms totaled $11.7 million and $18.9 million at March 31, 2008 and December 31, 2007, respectively. These amounts are recorded as current assets and are included as special deposits on the accompanying condensed consolidated balance sheets.
NU also had amounts on deposit related to four special purpose entities used to facilitate the issuance of rate reduction bonds and certificates. These amounts totaled $33.6 million and $43.5 million at March 31, 2008 and December 31, 2007, respectively. In addition, the company had $7 million and $6.4 million in other cash deposits held with unaffiliated parties at March 31, 2008 and December 31, 2007, respectively, primarily related to CL&P's transmission projects. These amounts are included in deferred debits and other assets - other on the accompanying condensed consolidated balance sheets.
H.
Other Income, Net
The pre-tax components of other income/(loss) items are as follows:
NU |
| For the Three Months Ended | ||||
(Millions of Dollars) |
| March 31, 2008 |
| March 31, 2007 | ||
Other Income: |
|
|
|
|
|
|
Investment income |
| $ | 1.9 |
| $ | 8.5 |
AFUDC - equity funds |
|
| 8.3 |
|
| 2.4 |
Energy Independence Act incentives |
|
| 5.5 |
|
| 2.7 |
Conservation and load management incentives |
|
| 0.3 |
|
| 0.2 |
Other |
|
| 0.2 |
|
| 0.3 |
Total Other Income |
|
| 16.2 |
|
| 14.1 |
Investment loss |
|
| (2.6) |
|
| - |
Total Other Income, Net |
| $ | 13.6 |
| $ | 14.1 |
CL&P |
| For the Three Months Ended | ||||
(Millions of Dollars) |
| March 31, 2008 |
| March 31, 2007 | ||
Other Income: |
|
|
|
|
|
|
Investment income |
| $ | 1.4 |
| $ | 1.4 |
AFUDC - equity funds |
|
| 6.6 |
|
| 1.5 |
Energy Independence Act incentives |
|
| 5.5 |
|
| 2.7 |
Conservation and load management incentives |
|
| 0.2 |
|
| 0.1 |
Other |
|
| 0.2 |
|
| 0.2 |
Total Other Income |
|
| 13.9 |
|
| 5.9 |
Investment loss |
|
| (1.8) |
|
| - |
Total Other Income, Net |
| $ | 12.1 |
| $ | 5.9 |
11
PSNH |
| For the Three Months Ended | ||||
(Millions of Dollars) |
| March 31, 2008 |
| March 31, 2007 | ||
Other Income: |
|
|
|
|
|
|
Investment income |
| $ | 0.3 |
| $ | 0.2 |
AFUDC - equity funds |
|
| 1.4 |
|
| 0.4 |
Other |
|
| - |
|
| 0.1 |
Total Other Income |
|
| 1.7 |
|
| 0.7 |
Investment loss |
|
| (0.4) |
|
| - |
Total Other Income, Net |
| $ | 1.3 |
| $ | 0.7 |
WMECO |
| For the Three Months Ended | ||||
(Millions of Dollars) |
| March 31, 2008 |
| March 31, 2007 | ||
Other Income: |
|
|
|
|
|
|
Investment income |
| $ | 0.2 |
| $ | 0.3 |
AFUDC - equity funds |
|
| 0.3 |
|
| - |
Conservation and load management incentives |
|
| 0.1 |
|
| 0.2 |
Total Other Income |
|
| 0.6 |
|
| 0.5 |
Investment loss |
|
| (0.4) |
|
| - |
Total Other Income, Net |
| $ | 0.2 |
| $ | 0.5 |
Investment income for NU includes equity in earnings of regional nuclear generating and transmission companies of $0.7 million for each of the three months ended March 31, 2008 and 2007. Equity in earnings relates to the company's investment in Connecticut Yankee Atomic Power Company (CYAPC), Maine Yankee Atomic Power Company, Yankee Atomic Electric Company and two regional transmission companies.
I.
Other Taxes
Certain excise taxes levied by state or local governments are collected by NU from its customers. These excise taxes are accounted for on a gross basis with collections in revenues and payments in expenses. For the three months ended March 31, 2008 and 2007, gross receipts taxes, franchise taxes and other excise taxes of $31 million and $31.7 million, respectively, were included in operating revenues and taxes other than income taxes on the accompanying condensed consolidated statements of income. Certain sales taxes are also collected by the regulated companies from their customers as agents for state and local governments and are recorded on a net basis with no impact on the accompanying condensed consolidated statements of income.
2.
DERIVATIVE INSTRUMENTS (NU, Select Energy, CL&P, PSNH, Yankee Gas)
Contracts that are derivatives and do not meet the requirements to be treated as a cash flow hedge or normal purchase or normal sale are recorded at fair value with changes in fair value included in earnings. For those contracts that meet the definition of a derivative and meet the cash flow hedge requirements, including those related to initial and ongoing documentation, the contract is recorded at fair value and the changes in the fair value of the effective portion of those contracts are recognized in accumulated other comprehensive income. Cash flow hedges include forward interest rate swap agreements on proposed debt issuances. When a cash flow hedge is settled, the settlement amount is recorded in accumulated other comprehensive income and is amortized into earnings over the term of the debt. Cash flow hedges impact net income when the hedged items affect earnings, when hedge ineffectiveness is measured and recorded, or when the forecasted transaction being hedged is improbable of occurring. Derivative contracts designated as fair value hedges and the items they are hedging are both recorded at fair value with changes in fair value of both items recognized in earnings. Derivative contracts that meet the requirements of a normal purchase or sale, and are so designated, are recognized in revenues or expenses, as applicable, when the quantity of the contract is delivered.
12
The fair value of the company's derivative contracts may not represent amounts that will be realized. For further information on the fair value of derivative contracts, see Note 1C, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 3, "Fair Value Measurements," to the condensed consolidated financial statements. On the accompanying condensed consolidated balance sheets at March 31, 2008 and December 31, 2007, these amounts are recorded as current or long-term derivative assets or liabilities and are summarized as follows:
|
| At March 31, 2008 | |||||||||||||
|
| Assets |
| Liabilities |
|
| |||||||||
|
| Current |
| Long-Term |
| Current |
| Long-Term |
| Net Totals | |||||
(Millions of Dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NU Enterprises - Wholesale |
| $ | 24.8 |
| $ | 12.1 |
| $ | (44.1) |
| $ | (73.9) |
| $ | (81.1) |
Regulated Companies - Gas: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply |
|
| 0.1 |
|
| - |
|
| - |
|
| - |
|
| 0.1 |
Interest Rate Hedging |
|
| - |
|
| - |
|
| (3.3) |
|
| - |
|
| (3.3) |
Regulated Companies - Electric: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply/Stranded Costs |
|
| 94.6 |
|
| 307.8 |
|
| (4.2) |
|
| (778.5) |
|
| (380.3) |
Interest Rate Hedging |
|
| - |
|
| - |
|
| (12.2) |
|
| - |
|
| (12.2) |
NU Parent: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Rate Hedging |
|
| - |
|
| 12.3 |
|
| (6.5) |
|
| - |
|
| 5.8 |
Totals |
| $ | 119.5 |
| $ | 332.2 |
| $ | (70.3) |
| $ | (852.4) |
| $ | (471.0) |
|
| At December 31, 2007 | |||||||||||||
|
| Assets |
| Liabilities |
|
| |||||||||
|
| Current |
| Long-Term |
| Current |
| Long-Term |
| Net Totals | |||||
(Millions of Dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NU Enterprises - Wholesale |
| $ | 36.2 |
| $ | 7.2 |
| $ | (64.9) |
| $ | (72.5) |
| $ | (94.0) |
Regulated Companies - Gas: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply |
|
| 0.2 |
|
| - |
|
| - |
|
| - |
|
| 0.2 |
Interest Rate Hedging |
|
| 0.9 |
|
| - |
|
| - |
|
| - |
|
| 0.9 |
Regulated Companies - Electric: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply/Stranded Costs |
|
| 59.8 |
|
| 290.8 |
|
| (6.7) |
|
| (136.0) |
|
| 207.9 |
Interest Rate Hedging |
|
| 3.3 |
|
| - |
|
| - |
|
| - |
|
| 3.3 |
NU Parent: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Rate Hedging |
|
| 5.1 |
|
| - |
|
| - |
|
| - |
|
| 5.1 |
Totals |
| $ | 105.5 |
| $ | 298.0 |
| $ | (71.6) |
| $ | (208.5) |
| $ | 123.4 |
For the regulated companies, except for existing interest rate swap agreements, offsetting regulatory assets or liabilities are recorded for the changes in fair value of their contracts, as these contracts were part of the stranded costs or are current regulated operating costs, and management believes that these costs will continue to be recovered or refunded in cost-of-service, regulated rates.
The business activities of NU Enterprises that result in the recognition of derivative assets also result in exposures to credit risk of energy marketing and trading counterparties. At March 31, 2008, Select Energy had $36.9 million of derivative assets from wholesale activities that are exposed to counterparty credit risk, a significant portion of which is contracted with multiple creditworthy and rated public entities.
NU Enterprises - Wholesale: Certain electric derivative contracts are part of NU Enterprises' remaining wholesale marketing business. These contracts include wholesale short-term and long-term electricity supply and sales contracts, including a full requirements contract to sell electricity to a utility that expires on May 31, 2008 (four other similar contracts expired on May 31, 2007), and a contract to sell electricity to the New York Municipal Power Agency (NYMPA) (an agency that is comprised of municipalities) that expires in 2013. The fair value of the contracts was determined using prices from external sources through 2011 and for on-peak periods in 2012, except for one contract, under which a portion of the fair value is also determined from a model based on natural gas prices and a heat-rate conversion factor to electricity for off-peak periods in 2012 and for all periods in 2013.
Regulated Companies - Gas - Supply: Yankee Gas's supply derivatives consist of peaking supply arrangements to serve winter load obligations and firm retail sales contracts with options to curtail delivery. These contracts are subject to fair value accounting as these contracts are derivatives that cannot be designated as normal purchases and sales because of the optionality in the contract terms. An offsetting regulatory liability was recorded for these amounts as management believes that these costs will be refunded in rates.
Regulated Companies - Gas - Interest Rate Hedging: Yankee Gas has a forward interest rate swap agreement to hedge the interest cash outflows associated with its proposed $100 million debt issuance in September 2008. The interest rate swap is based on a 10-year LIBOR swap rate and matches the index used for the debt issuance. As a cash flow hedge, the fair value of the hedge is recorded
13
as a derivative liability and derivative asset on the accompanying condensed consolidated balance sheets as of March 31, 2008 and December 31, 2007, respectively, with an offsetting amount, net of tax, included in accumulated other comprehensive income.
Regulated Companies - Electric - Supply/Stranded Costs: CL&P has contracts with two IPPs to purchase power that contain pricing provisions that are not clearly and closely related to the price of power and therefore do not qualify for the normal purchases and sales exception. The fair values of these derivatives at March 31, 2008 included a derivative asset with a fair value of $243.1 million and a derivative liability with a fair value of $60.1 million. An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of stranded costs, and management believes that these costs will continue to be recovered or refunded in cost-of-service, regulated rates. At December 31, 2007, the fair values of these derivatives included a derivative asset with a fair value of $311.2 million and a derivative liability with a fair value of $31.8 million.
CL&P has entered into FTR contracts and bilateral basis swaps to limit the congestion costs associated with its standard offer contracts. An offsetting regulatory asset or liability has been recorded as management believes that these costs will be recovered or refunded in rates. At March 31, 2008, the fair value of these contracts was recorded as a derivative asset of $4.8 million on the accompanying condensed consolidated balance sheets. At December 31, 2007, the fair value of these contracts was recorded as a derivative asset of $1.4 million and a derivative liability of $1.3 million on the accompanying condensed consolidated balance sheets.
Pursuant to Public Act 05-01, "An Act Concerning Energy Independence," in August 2007, the Connecticut Department of Public Utility Control (DPUC) approved two CL&P contracts associated with the capacity of two generating projects to be built or modified. The DPUC also approved two capacity-related contracts entered into by The United Illuminating Company (UI), one with a generating project to be built and one with a new demand response project. The total capacity of these four projects is expected to be approximately 787 megawatts (MW). The contracts, referred to as CfDs, obligate the utilities' customers to pay the difference between a set capacity price and the value that the projects receive in the New England Independent System Operator (ISO-NE) capacity markets for periods of up to 15 years beginning in 2009. CL&P has an agreement with UI under which it will share the costs and benefits of these four CfDs, with 80 percent to CL&P and 20 percent to UI. The ultimate cost to CL&P under the contracts will depend on the capacity prices that the projects receive in the ISO-NE capacity markets. At March 31, 2008, the fair value of the CL&P CfDs was recorded as a derivative liability of $722.6 million. The fair values of UI's share of the CL&P's contracts and CL&P's share of UI's contracts were recorded as a derivative asset of $104.5 million. An offsetting regulatory asset of $618.1 million was recorded, as management believes these amounts will be recovered from or refunded to customers in cost-of-service, regulated rates. The value of CL&P's CfDs at March 31, 2008 included approximately $100 million of initial gains and losses, previously deferred due to the use of significant unobservable inputs in the valuation, that were recorded upon adoption of SFAS No. 157 on January 1, 2008. At December 31, 2007, changes in CfD fair values since inception were recorded as a derivative liability of $107.1 million, and UI's share and one CL&P CfD were recorded as derivative assets of $20.8 million. Offsetting regulatory assets of $86.7 million and regulatory liabilities of $0.4 million were also recorded at December 31, 2007. A 2007 NRG Energy, Inc. (NRG) appeal of the DPUC's decision selecting the CfDs was taken into consideration in valuing the CfDs as of December 31, 2007, reducing the net negative derivative values by approximately $215 million. In February 2008, the appeal was denied, which increased derivative liabilities in the first quarter of 2008.
PSNH has electricity procurement contracts that are derivatives. The fair value of these contracts is calculated based on market prices and was recorded as a derivative asset of $27.2 million at March 31, 2008. At December 31, 2007, the fair value was recorded as a derivative asset of $1.5 million and a derivative liability of $2.5 million. An offsetting regulatory liability/asset was recorded as management believes that these costs will be refunded or recovered in rates as the energy is delivered.
PSNH has a contract to assign its transmission rights in a direct current transmission line in exchange for two energy call options which expire in 2010. These energy call options are derivatives that do not qualify for the normal purchases and sales exception and are accounted for at fair value based on market prices. At March 31, 2008, the options were recorded as a derivative asset of $22.8 million. An offsetting regulatory liability was recorded, as the benefit of this arrangement will be refunded to customers in rates. At December 31, 2007, the options were recorded as a derivative asset of $15.7 million.
Regulated Companies - Electric - Interest Rate Hedging: CL&P has two forward interest rate swap agreements to hedge the interest cash outflows associated with a proposed debt issuance of $300 million in May 2008. PSNH has a forward interest rate swap agreement to hedge the interest cash outflows associated with its proposed debt issuance of $110 million in May 2008. The interest rate swaps are based on a 10-year LIBOR swap rate and match the index used for the debt issuances. As cash flow hedges, the fair value of these hedges was recorded as a derivative liability and derivative asset for the periods ended March 31, 2008 and December 31, 2007, respectively, on the accompanying condensed consolidated balance sheets with an offsetting amount, net of tax, included in accumulated other comprehensive income.
NU Parent - Interest Rate Hedging: In March 2003, to manage the interest rate characteristics of the company's long-term debt, NU parent entered into a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed rate senior notes that mature on April 1, 2012. Under fair value hedge accounting, the changes in fair value of the swap and the interest component of the hedged long-term
14
debt instrument are recorded in interest expense, which generally offset each other in the condensed consolidated statements of income. The cumulative change in the fair value of the swap and the long-term debt was recorded as a derivative asset and an increase to long-term debt of $12.3 million and $4.2 million at March 31, 2008 and December 31, 2007, respectively.
NU parent has a forward interest rate swap agreement to hedge the interest cash outflows associated with its proposed debt issuance of $200 million in June 2008. The interest rate swap is based on a 5-year LIBOR swap rate and matches the index used for the debt issuance. As a cash flow hedge at March 31, 2008 and December 31, 2007, the fair value of the hedge was recorded as a $6.5 million derivative liability and a $0.9 million derivative asset, respectively, on the accompanying condensed consolidated balance sheets with an offsetting amount, net of tax, included in accumulated other comprehensive income.
3.
FAIR VALUE MEASUREMENTS (All Companies)
Items Measured at Fair Value on a Recurring Basis: The company's assets and liabilities recorded at fair value on a recurring basis have been categorized based upon the fair value hierarchy in accordance with SFAS No. 157. See Note 1C, "Summary of Significant Accounting Policies – Fair Value Measurements," for further information regarding the hierarchy and fair value measurements.
The following table presents the amounts of assets and liabilities carried at fair value at March 31, 2008 by the level in which they are classified within the SFAS No. 157 valuation hierarchy:
|
| Total NU |
| CL&P |
| PSNH |
| WMECO |
| NU |
| Yankee Gas |
| NU Parent | |||||||
Derivative Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Level 1 |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
Level 2 |
|
| 39.5 |
|
| - |
|
| 27.2 |
|
| - |
|
| - |
|
| - |
|
| 12.3 |
Level 3 |
|
| 412.2 |
|
| 352.4 |
|
| 22.8 |
|
| - |
|
| 36.9 |
|
| 0.1 |
|
| - |
Total |
| $ | 451.7 |
| $ | 352.4 |
| $ | 50.0 |
| $ | - |
| $ | 36.9 |
| $ | 0.1 |
| $ | 12.3 |
Derivative Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1 |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
Level 2 |
|
| (22.0) |
|
| (11.9) |
|
| (0.3) |
|
| - |
|
| - |
|
| (3.3) |
|
| (6.5) |
Level 3 |
|
| (900.7) |
|
| (782.7) |
|
| - |
|
| - |
|
| (118.0) |
|
| - |
|
| - |
Total |
| $ | (922.7) |
| $ | (794.6) |
| $ | (0.3) |
| $ | - |
| $ | (118.0) |
| $ | (3.3) |
| $ | (6.5) |
Marketable Securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1 |
| $ | 45.3 |
| $ | - |
| $ | - |
| $ | 8.0 |
| $ | - |
| $ | - |
| $ | 37.3 |
Level 2 |
|
| 76.0 |
|
| - |
|
| - |
|
| 48.3 |
|
| - |
|
| - |
|
| 27.7 |
Level 3 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
Total |
| $ | 121.3 |
| $ | - |
| $ | - |
| $ | 56.3 |
| $ | - |
| $ | - |
| $ | 65.0 |
The following table presents changes for the three months ended March 31, 2008 in the Level 3 category of assets and liabilities measured at fair value on a recurring basis. This category includes derivative assets and liabilities, which are presented net. The derivative amounts at January 1, 2008 reflect the fair values after initial adoption of SFAS No. 157. The company classifies assets and liabilities in Level 3 of the fair value hierarchy when there is reliance on at least one significant unobservable input to the valuation model. In addition to these unobservable inputs, the valuation models for Level 3 assets and liabilities typically also rely on a number of inputs that are observable either directly or indirectly. Thus, the gains and losses presented below include changes in fair value that are attributable to both observable and unobservable inputs. There were no transfers into or out of Level 3 assets and liabilities for the three months ended March 31, 2008.
15
|
| Total NU |
| CL&P |
| PSNH |
| NU |
| Yankee | |||||
Derivatives, Net: |
|
|
|
|
|
|
|
|
|
| |||||
Fair value at January 1, 2008 (1) |
| $ | (511.1) |
| $ | (426.9) |
| $ | 15.7 |
| $ | (100.1) |
| $ | 0.2 |
Net realized/unrealized |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (2) |
|
| 3.7 |
|
| - |
|
| - |
|
| 3.7 |
|
| - |
Regulatory assets/liabilities |
|
| 16.8 |
|
| 9.8 |
|
| 7.1 |
|
| - |
|
| (0.1) |
Purchases, issuances and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value at March 31, 2008 |
| $ | (488.5) |
| $ | (430.3) |
| $ | 22.8 |
| $ | (81.1) |
| $ | 0.1 |
Quarterly change in unrealized |
|
| 0.8 |
|
| - |
|
| - |
|
| 0.8 |
|
| - |
(1)
Amounts as of January 1, 2008 reflect fair values after initial adoption of SFAS No. 157. As a result of implementing SFAS No. 157, the company recorded an increase to derivative liabilities and a pre-tax charge to earnings of $6.1 million as of January 1, 2008 related to NU Enterprises' remaining derivative contracts. The company also recorded changes in fair value of CL&P's CfD and IPP contracts, resulting in increases to CL&P's derivative liabilities of approximately $590 million, with an offset to regulatory assets and a decrease to CL&P's derivative assets of approximately $30 million with an offset to regulatory liabilities.
(2)
Realized and unrealized gains and losses on derivatives included in earnings relate to the remaining Select Energy wholesale marketing contracts and are reported in fuel, purchased and net interchange power on the accompanying condensed consolidated statements of income.
4.
PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (All Companies)
NU's subsidiaries participate in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees and also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (post-retirement benefits other than pension (PBOP) Plan). In addition, NU maintains a Supplemental Executive Retirement Plan (SERP) which provides benefits to eligible participants, who are officers of NU, that would have been provided to them under the Pension Plan if certain Internal Revenue Code and other limitations were not imposed.
The components of net periodic benefit expense/(income) for the Pension Plan, PBOP Plan and SERP for the three months ended March 31, 2008 and 2007 are as follows:
NU |
| For the Three Months Ended March 31, | ||||||||||||||||
|
| Pension Benefits |
| SERP Benefits |
| Postretirement Benefits | ||||||||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2008 |
| 2007 |
| 2008 |
| 2007 | ||||||
Service cost |
| $ | 10.7 |
| $ | 11.7 |
| $ | 0.2 |
| $ | 0.2 |
| $ | 1.8 |
| $ | 2.1 |
Interest cost |
|
| 36.2 |
|
| 33.6 |
|
| 0.5 |
|
| 0.5 |
|
| 7.1 |
|
| 6.6 |
Expected return on plan assets |
|
| (50.1) |
|
| (47.2) |
|
| - |
|
| - |
|
| (5.3) |
|
| (4.5) |
Amortization of unrecognized net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost |
|
| 2.4 |
|
| 1.6 |
|
| - |
|
| - |
|
| (0.1) |
|
| (0.1) |
Amortization of actuarial loss |
|
| 1.4 |
|
| 6.8 |
|
| 0.1 |
|
| 0.2 |
|
| 2.6 |
|
| 2.9 |
Net periodic expense |
| $ | 0.7 |
| $ | 6.6 |
| $ | 0.8 |
| $ | 0.9 |
| $ | 9.0 |
| $ | 9.9 |
A portion of these pension amounts is capitalized related to current employees that are working on capital projects. Amounts capitalized were approximately $1.4 million and $0.6 million for the three months ended March 31, 2008 and 2007, respectively. The amount for the three months ended March 31, 2008 offsets capital costs, as pension income was recorded for certain of NU's subsidiaries.
16
CL&P |
| For the Three Months Ended March 31, | ||||||||||||||||
|
| Pension Benefits |
| SERP Benefits |
| Postretirement Benefits | ||||||||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2008 |
| 2007 |
| 2008 |
| 2007 | ||||||
Service cost |
| $ | 3.7 |
| $ | 3.8 |
| $ | - |
| $ | - |
| $ | 0.6 |
| $ | 0.7 |
Interest cost |
|
| 12.9 |
|
| 12.3 |
|
| 0.1 |
|
| 0.1 |
|
| 2.8 |
|
| 2.6 |
Expected return on plan assets |
|
| (23.4) |
|
| (22.1) |
|
| - |
|
| - |
|
| (2.1) |
|
| (1.8) |
Amortization of unrecognized net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost |
|
| 1.1 |
|
| 0.7 |
|
| - |
|
| - |
|
| - |
|
| - |
Amortization of actuarial loss |
|
| 0.3 |
|
| 2.5 |
|
| - |
|
| - |
|
| 1.1 |
|
| 1.2 |
Net periodic (income)/expense |
| $ | (5.4) |
| $ | (2.8) |
| $ | 0.1 |
| $ | 0.1 |
| $ | 3.9 |
| $ | 4.2 |
Not included in the pension (income)/expense amounts above are pension related intercompany allocations totaling $2.1 million and $3.1 million for the three months ended March 31, 2008 and 2007, respectively. Excluded from postretirement benefits are related intercompany allocations of $1.7 million and $1.8 million for the three months ended March 31, 2008 and 2007, respectively. Excluded from SERP expenses are related intercompany allocations of $0.4 million and $0.5 million for the three months ended March 31, 2008 and 2007, respectively.
For CL&P, a portion of the pension amounts, including intercompany allocations, is capitalized related to current employees that are working on capital projects. Amounts capitalized were $2.2 million and $0.6 million for the three months ended March 31, 2008 and 2007, respectively. These amounts offset capital project costs, as pension income was recorded for those periods.
PSNH |
| For the Three Months Ended March 31, | ||||||||||||||||
|
| Pension Benefits |
| SERP Benefits |
| Postretirement Benefits | ||||||||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2008 |
| 2007 |
| 2008 |
| 2007 | ||||||
Service cost |
| $ | 2.2 |
| $ | 2.5 |
| $ | - |
| $ | - |
| $ | 0.4 |
| $ | 0.4 |
Interest cost |
|
| 5.8 |
|
| 5.3 |
|
| - |
|
| - |
|
| 1.3 |
|
| 1.2 |
Expected return on plan assets |
|
| (4.5) |
|
| (4.3) |
|
| - |
|
| - |
|
| (1.0) |
|
| (0.8) |
Amortization of unrecognized net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost |
|
| 0.5 |
|
| 0.3 |
|
| - |
|
| - |
|
| - |
|
| - |
Amortization of actuarial loss |
|
| 0.4 |
|
| 1.2 |
|
| 0.1 |
|
| 0.1 |
|
| 0.4 |
|
| 0.6 |
Net periodic expense |
| $ | 4.5 |
| $ | 5.1 |
| $ | 0.1 |
| $ | 0.1 |
| $ | 1.7 |
| $ | 2.0 |
Not included in the pension expense amounts above are pension related intercompany allocations totaling $0.4 million and $0.5 million for the three months ended March 31, 2008 and 2007, respectively. Excluded from postretirement benefits are related intercompany allocations of $0.4 million and $0.3 million for the three months ended March 31, 2008 and 2007, respectively. Excluded from SERP expenses are related intercompany allocations of $0.1 million for both the three months ended March 31, 2008 and 2007.
For PSNH, a portion of these pension amounts, including intercompany allocations, is capitalized related to current employees that are working on capital projects. Amounts capitalized were $1.1 million and $1.3 million for the three months ended March 31, 2008 and 2007, respectively.
WMECO |
| For the Three Months Ended March 31, | ||||||||||
|
| Pension Benefits |
| Postretirement Benefits | ||||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2008 |
| 2007 | ||||
Service cost |
| $ | 0.7 |
| $ | 0.7 |
| $ | 0.1 |
| $ | 0.2 |
Interest cost |
|
| 2.6 |
|
| 2.5 |
|
| 0.6 |
|
| 0.6 |
Expected return on plan assets |
|
| (5.1) |
|
| (4.9) |
|
| (0.5) |
|
| (0.5) |
Amortization of unrecognized net |
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost |
|
| 0.2 |
|
| 0.2 |
|
| - |
|
| - |
Amortization of actuarial loss |
|
| - |
|
| 0.5 |
|
| 0.2 |
|
| 0.2 |
Net periodic (income)/expense |
| $ | (1.6) |
| $ | (1.0) |
| $ | 0.7 |
| $ | 0.8 |
A de minimis amount of SERP expense was recorded for WMECO for each of the three months ended March 31, 2008 and 2007.
17
Not included in the pension income amounts above are pension related intercompany allocations totaling $0.3 million and $0.5 million for the three months ended March 31, 2008 and 2007, respectively. Excluded from postretirement benefits are related intercompany allocations of $0.3 million for each of the three months ended March 31, 2008 and 2007.
For WMECO, a portion of these pension amounts, including intercompany allocations, is capitalized related to current employees that are working on capital projects. Amounts capitalized were $0.6 million and $0.3 million for the three months ended March 31, 2008 and 2007, respectively. These amounts offset capital project costs, as pension income was recorded for those periods.
5.
COMMITMENTS AND CONTINGENCIES
A.
Regulatory Developments and Rate Matters (CL&P, PSNH, WMECO, Yankee Gas)
Connecticut:
CTA and SBC Reconciliation: The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with its rate reduction bonds, amortization of regulatory assets, and IPP over-market costs, while the System Benefits Charge (SBC) allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced worker protection costs.
On March 31, 2008, CL&P filed with the DPUC its 2007 CTA and SBC reconciliation, which compared CTA and SBC revenues to revenue requirements. For the 12 months ended December 31, 2007, total CTA revenues exceeded CTA revenue requirements by $26.1 million. This amount was recorded as a decrease to the CTA regulatory asset on the accompanying condensed consolidated balance sheets. For the 12 months ended December 31, 2007, the SBC cost of service exceeded SBC revenues by $39.4 million. This amount was recorded as a regulatory asset on the accompanying condensed consolidated balance sheets. Management expects a decision in this docket from the DPUC by the end of 2008 and does not expect the outcome to have a material adverse impact on CL&P's net income, financial position or cash flows.
Procurement Fee Rate Proceedings: CL&P was allowed to collect a fixed procurement fee of 0.50 mills per kilowatt-hour (KWH) from customers that purchased transitional standard offer (TSO) service from 2004 through the end of 2006. One mill is equal to one tenth of a cent. That fee could increase to 0.75 mills per KWH if CL&P outperforms certain regional benchmarks. CL&P submitted to the DPUC its proposed methodology to calculate the variable incentive portion of the procurement fee and requested approval of $5.8 million in incentive fees. On December 8, 2005, a draft decision was issued in this docket, which accepted the methodology as proposed by CL&P and authorized payment of the pre-tax $5.8 million incentive fee. Subsequent to this draft decision the record has been re-opened for numerous inputs. On October 19, 2007, the DPUC released a recommendation prepared by its consultant relative to statistical adjustments to the incentive calculations. A date for the new draft decision in this docket has not yet been determined by the DPUC. Management continues to believe that final regulatory approval of the $5.8 million pre-tax amount, which was reflected in 2005 earnings, is probable.
Purchased Gas Adjustment: On September 9, 2005, the DPUC issued a draft decision regarding Yankee Gas's Purchased Gas Adjustment (PGA) clause charges for the period of September 1, 2003 through August 31, 2004. The draft decision disallowed approximately $9 million in previously recovered PGA revenues associated with two separate Yankee Gas unbilled sales and revenue adjustments. At the request of Yankee Gas, the DPUC reopened the PGA hearings on September 20, 2005 and requested that Yankee Gas file supplemental information regarding the two adjustments. Yankee Gas complied with this request. The DPUC issued a subsequent decision on April 20, 2006 requiring an audit of Yankee Gas's previously recovered PGA costs and deferred any conclusion on the $9 million of previously recovered revenues until the completion of the audit. In a subsequent draft decision regarding Yankee Gas PGA charges for the period September 1, 2004 through August 31, 2005, an additional $2 million related to previously recovered revenues was also identified, bringing the total maximum amount at issue with regard to PGA clause charges under audit to approximately $11 million.
The DPUC hired a consulting firm which concluded an audit of Yankee Gas's previously recovered PGA costs and submitted its final report. A DPUC hearing was held on October 9, 2007. There is currently no final schedule in this case. Management believes the unbilled sales and revenue adjustments and resulting charges to customers through the PGA clause for both periods were appropriate. Based on the facts of the case, the supplemental information provided to the DPUC and the consultant's final report, management believes the appropriateness of the PGA charges to customers for the time period under review will be approved, and has not reserved for any loss.
18
New Hampshire:
SCRC/ES Reconciliation: On an annual basis, PSNH files with the New Hampshire Public Utilities Commission (NHPUC) a stranded cost recovery charge/default energy service charge (SCRC/ES) reconciliation filing for the preceding year. The NHPUC reviews the filing, which includes a prudence review of PSNH's generation business segment operations. On May 1, 2008, PSNH filed its 2007 SCRC/ES reconciliation with the NHPUC. Management does not expect the outcome of the NHPUC review to have a material adverse impact on PSNH's net income, financial position or cash flows.
At March 31, 2008, SCRC revenues exceeded SCRC costs and PSNH deferred the $3.3 million difference for future refunding. At March 31, 2008, ES revenues exceeded ES costs and PSNH deferred the $25.5 million difference which is being refunded to customers through the 2008 ES rate.
Massachusetts:
Transition Cost Reconciliations: WMECO filed its 2005 transition cost reconciliation with the Massachusetts Department of Public Utilities (DPU) on March 31, 2006 and filed its 2006 transition cost reconciliation with the DPU on March 31, 2007. The DPU opened a proceeding for these filings, and evidentiary hearings were held on August 29, 2007. The briefing process was completed during October 2007. The timing of the decision in this docket is uncertain. Management does not expect the outcome of the DPU's review of these filings to have a material adverse impact on WMECO's net income, financial position or cash flows.
On March 13, 2008, WMECO requested that the DPU allow it to delay making its 2007 transition cost reconciliation filing until 30 days after an order is received on the 2005 and 2006 filings. The DPU granted WMECO's request on March 21, 2008.
B.
NRG Energy, Inc. Exposures (CL&P, Yankee Gas)
Certain subsidiaries of NU, including CL&P and Yankee Gas, entered into transactions with NRG and certain of its subsidiaries. On May 14, 2003, NRG and certain subsidiaries of NRG filed voluntary bankruptcy petitions, and on December 5, 2003, NRG emerged from bankruptcy. NU's NRG-related exposures as a result of these transactions relate, among other things now resolved, to the recovery of approximately $30.2 million of CL&P's station service billings from NRG, and the recovery of, among other claimed damages, approximately $17.5 million of capital costs and expenses incurred by Yankee Gas related to an NRG subsidiary's generating plant construction project that has ceased.
On February 15, 2008, CL&P and NRG, as well as Yankee Gas and NRG, entered into settlement agreements with respect to the two matters mentioned above. The settlements were contingent upon the satisfaction of several conditions related to NRG's RNS service through the ISO-NE which were materially satisfied in May 2008. The settlement did not have an adverse effect on NU's consolidated net income, financial position or cash flows in 2008.
C.
Long-Term Contractual Arrangements (Select Energy)
NU Enterprises:
Estimated Future Annual NU Enterprises Costs: The estimated future annual costs of NU Enterprises' significant contractual arrangements are as follows:
(Millions of Dollars) |
| 2008 |
| 2009 |
| 2010 |
| 2011 |
| 2012 |
| Thereafter |
| Total | |||||||
Select Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Select Energy Purchase Agreements: Select Energy maintains long-term agreements to purchase energy as part of its portfolio of resources to meet its actual or expected sales commitments. Most purchase commitments are recorded at their mark-to-market value with the exception of one non-derivative contract which is accounted for on the accrual basis.
Select Energy's purchase commitment amounts are reported on a net basis in fuel, purchased and net interchange power along with certain sales contracts and mark-to-market amounts. Therefore, the amount included in fuel, purchased and net interchange power will be less than the amounts included in the table above. Select Energy also maintains certain energy commitments for which mark-to-market values have been recorded on the condensed consolidated balance sheets as derivative assets and liabilities. These contracts are included in the table above.
The amount and timing of the costs associated with Select Energy's purchase agreements could be impacted by the exit from the NU Enterprises' businesses.
19
D.
Environmental Matters (HWP)
HWP is a subsidiary of NU that owns a minimal amount of transmission property and has limited operating activities. HWP continues to evaluate additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with a manufactured gas plant which it sold to Holyoke Gas and Electric (HG&E), a municipal electric utility, in 1902. HWP is at least partially responsible for this site, and substantial remediation activities at this site have already been conducted. HWP first established a reserve for this site in 1994. The cumulative expense recorded to this reserve was approximately $13 million, of which $12.5 million had been spent, leaving approximately $0.5 million in the reserve as of March 31, 2008. HWP's reserve is based on its most recent site and proposed risk assessment, which occurred in 2007.
The Massachusetts Department of Environmental Protection (MA DEP) issued an approval letter on April 3, 2008 to HWP and HG&E, an unaffiliated entity which shares responsibility for the site, authorizing, subject to certain conditions, additional investigatory and risk characterization activities and providing detailed comments on HWP’s 2007 proposed risk assessment. MA DEP also indicated that further remediation of certain upstream "soft" tar areas was required prior to commencing many of the additional studies and evaluation. MA DEP’s authorization, approval conditions and additional tar remediation requirements, including estimable costs and schedules, are currently being evaluated by HWP. A response to MA DEP is required by June 2, 2008, which management believes will be extended by the MA DEP. These matters are also subject to ongoing discussions with MA DEP and HG&E and may change from time to time.
At this time, management believes that the $0.5 million remaining in the reserve is the low end of a range of probable costs and that the $0.5 million will be sufficient for HWP to evaluate its approach to this matter. Since management has recorded the low end of the range of probable cost, there are many possible outcomes that would require an increase to the reserve, which will be reflected as a charge to pre-tax earnings. However, management cannot reasonably estimate the range of investigation and remediation costs because they will depend on, among other things, the level and extent of the remaining tar required to be removed, the extent of HWP’s responsibility and the related scope and timing, all of which are difficult to estimate because of a number of uncertainties at this time. Developments in this matter may require a material increase to the reserve.
HWP's share of the remediation costs related to this site is not recoverable from ratepayers. There were no changes to the environmental reserve for this site in the first quarter of 2008.
E.
Consolidated Edison, Inc. Merger Litigation (NU)
On March 13, 2008, NU entered into a settlement agreement with Consolidated Edison, Inc. (Con Edison) which settled all claims under the civil lawsuit between NU and Con Edison relating to their proposed but unconsummated merger. Under the terms of the settlement agreement, NU paid Con Edison $49.5 million on March 26, 2008, which is included in other operating expenses in the accompanying condensed consolidated statement of income for the three months ended March 31, 2008. This amount is not recoverable from ratepayers.
F.
Guarantees and Indemnifications (All Companies)
NU provides credit assurances on behalf of subsidiaries in the form of guarantees and letters of credit (LOCs) in the normal course of business. NU has also provided guarantees and various indemnifications on behalf of external parties as a result of the sales of Select Energy Services, Inc. (SESI), NU Enterprises' retail marketing business and its competitive generation business. The following table summarizes NU's maximum exposure at March 31, 2008, in accordance with FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," expiration dates, and fair value of amounts recorded.
|
|
|
|
|
|
|
|
| Fair Value |
On behalf of external parties: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SESI |
| General indemnifications in connection with the sale of SESI including completeness and accuracy of information provided, compliance with laws, and various claims |
| Not Specified | (1) |
| None |
| $ - |
|
|
|
|
|
|
|
|
|
|
|
| Specific indemnifications in connection with the sale of SESI for estimated costs to complete or modify specific projects |
| Not Specified | (1) |
| Through project completion |
| $0.2 |
|
|
|
|
|
|
|
|
|
|
20
|
| Indemnifications to lenders for payment of shortfalls in the event of early termination of government contracts |
| $1.9 |
|
| 2017-2018 |
| $0.1 |
|
|
|
|
|
|
|
|
|
|
|
| Surety bonds covering certain projects |
| $75.8 |
|
| Through project |
| $ - |
|
|
|
|
|
|
|
|
|
|
Hess Corporation (Retail Marketing Business) |
| General indemnifications in connection with the sale including compliance with laws, completeness and accuracy of information provided, and various claims |
| Not Specified | (1) |
| None |
| $ - |
|
|
|
|
|
|
|
|
|
|
Energy Capital Partners (Competitive Generation Business) |
| General indemnifications in connection with the sale of NGC and the generating assets of Mt. Tom including compliance with tax and environmental laws, and various claims |
| Not Specified | (1) |
| 2008-2009 |
| $ - |
|
|
|
|
|
|
|
|
|
|
On behalf of subsidiaries: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Companies |
| Surety bonds, primarily for self-insurance |
| $15.3 |
|
| None |
| N/A |
|
| Letters of credit |
| $26.0 |
|
| 2008 |
| N/A |
|
|
|
|
|
|
|
|
|
|
Rocky River Realty Company |
| Lease payments for real estate |
| $10.9 |
|
| 2024 |
| N/A |
|
|
|
|
|
|
|
|
|
|
NUSCO |
| Lease payments for fleet of vehicles |
| $9.9 |
|
| None |
| N/A |
|
|
|
|
|
|
|
|
|
|
E.S. Boulos Company (Boulos) |
| Surety bonds covering ongoing projects |
| $66.7 |
|
| Through project |
| N/A |
|
|
|
|
|
|
|
|
|
|
NGS |
| Performance guarantee and insurance bonds |
| $23.9 | (3) |
| 2020 (3) |
| N/A |
|
|
|
|
|
|
|
|
|
|
Select Energy |
| Performance guarantees and surety bonds for retail marketing contracts |
| $5.2 | (4) |
| None (5) |
| N/A |
|
|
|
|
|
|
|
|
|
|
|
| Performance guarantees for wholesale contracts |
| $80.5 | (4) |
| 2013 |
| N/A |
|
|
|
|
|
|
|
|
|
|
|
| Letters of credit |
| $2.0 |
|
| 2009 |
| N/A |
(1)
There is no specified maximum exposure included in the related sale agreements.
(2)
SESI recently completed the project that represents $64.5 million of the $75.8 million maximum bond exposure outstanding at March 31, 2008 and is in the process of closing out the surety bonds associated with the project.
(3)
Included in the maximum exposure is $22.7 million related to a performance guarantee of Northeast Generation Services Company (NGS) obligations for which there is no specified maximum exposure in the agreement. The maximum exposure is calculated based on limits on NGS's liability contained in the underlying service contract and assumes that NGS will perform under that contract through its expiration in 2020. The remaining $1.2 million of maximum exposure relates to insurance bonds with no expiration date which are billed annually on their anniversary date.
(4)
Maximum exposure is as of March 31, 2008; however, exposures vary with underlying commodity prices and for certain contracts are essentially unlimited.
(5)
NU does not currently anticipate that these remaining guarantees on behalf of Select Energy will result in significant guarantees of the performance of Hess Corporation.
Many of the underlying contracts that NU guarantees, as well as certain surety bonds, contain provisions that would require NU to post collateral in the event that NU's credit ratings are downgraded below investment grade.
In July 2006, under a guarantee of SESI obligations, NU purchased the right to contract payments relating to a SESI project that was financed and behind schedule. The carrying value of these assets was $8.8 million at March 31, 2008 and is included in other deferred debits on the accompanying condensed consolidated balance sheets. This carrying amount represents the amount expected to be received from refinancing through SESI's completion of the project. NU may record additional losses associated with this transaction, the amount of which will depend on changes in interest rates used to determine SESI's refinancing proceeds, the amount of project cash available to offset NU's costs, and other factors.
21
G.
Transmission Rate Matters and FERC Regulatory Issues (CL&P, PSNH, WMECO)
As a result of an order issued by the FERC on October 31, 2006 relating to incentives on new transmission facilities in New England (Initial Return on Equity (ROE) Order), NU recorded an estimated regulatory liability for refunds in 2006. In 2007, NU completed the customer refunds that were calculated in accordance with the compliance filing required by the Initial ROE Order, and refunded amounts to regional, local and localized transmission customers.
On March 24, 2008, the FERC issued an order on rehearing of its Initial ROE Order. In the rehearing order, the FERC, among other things, increased the base ROE on transmission projects for the transmission owners from the 10.2 percent allowed in the Initial ROE Order to 10.4 percent effective February 1, 2005 and reaffirmed its Initial ROE Order increasing the ROE by 74 basis points for the period beginning November 1, 2006 in recognition of higher bond yields. The rehearing order also modified the FERC's Initial ROE Order provision allowing 100 additional basis points for new transmission projects that are built as part of the ISO-NE Regional System Plan (RSP) by limiting the 100 basis points adder solely to projects that are "completed and on line" by December 31, 2008. In order to receive incentives for projects completed after December 31, 2008, the rehearing order requires transmission owners to file with the FERC project-specific requests that meet the nexus requirements under FERC guidelines. In addition, while not an issue in this rehearing, the provision of the Initial ROE Order increasing the ROE by 50 additional basis points for New England transmission owners joining a Regional Transmission Organization (RTO) and giving the RTO operational control of the transmission owner’s transmission facilities was left unchanged. In the first quarter of 2008, NU recognized $3.5 million in transmission segment income related to this order.
The following table is a summary of the changes in the ROEs for the applicable periods and projects as a result of the rehearing order:
|
| Local Network |
| Regional Network |
|
|
RTO - February 1, 2005 to October 31, 2006 | ||||||
Initial Order |
| 10.2% |
| 10.7% (base plus 0.5% |
| 11.7% (10.7% plus 1% |
|
|
|
|
|
|
|
Rehearing Order |
| 10.4% |
| 10.9% (base plus 0.5% |
| 11.9% (10.9% plus 1% |
RTO - November 1, 2006 forward | ||||||
Initial Order |
| 10.94% (10.2% plus |
| 11.44% (base plus 0.5% |
| 12.44% (11.44% plus 1% |
Rehearing Order |
| 11.14% |
| 11.64% (base plus 0.5% |
| 12.64% (11.64% plus 1% |
(1) 100 basis points adder for new investment under RSP; limited solely to projects completed by December 31, 2008.
6.
COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO, NU Enterprises, Yankee Gas)
Total comprehensive income, which includes all comprehensive income/(loss) items, net of tax and by category, for the three months ended March 31, 2008 and 2007 is as follows:
|
| Three Months Ended March 31, 2008 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
| NU |
| Yankee |
|
| |||||||
Net income/(loss) |
| $ | 58.4 |
| $ | 44.7 |
| $ | 16.7 |
| $ | 6.3 |
| $ | 1.9 |
| $ | 18.6 |
| $ | (29.8) |
Comprehensive (loss)/income items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified cash flow hedging instruments |
|
| (18.7) |
|
| (8.5) |
|
| (3.2) |
|
| - |
|
| - |
|
| (2.5) |
|
| (4.5) |
Unrealized (losses)/gains on securities |
|
| (0.7) |
|
| - |
|
| - |
|
| 0.1 |
|
| - |
|
| - |
|
| (0.8) |
Pension, SERP, and other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in comprehensive |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income/(loss) |
| $ | 40.2 |
| $ | 36.2 |
| $ | 13.5 |
| $ | 6.4 |
| $ | 2.2 |
| $ | 16.1 |
| $ | (34.2) |
22
|
| Three Months Ended March 31, 2007 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
| NU |
| Yankee |
|
| |||||||
Net income |
| $ | 75.1 |
| $ | 33.6 |
| $ | 10.0 |
| $ | 6.9 |
| $ | 4.8 |
| $ | 13.6 |
| $ | 6.2 |
Comprehensive (loss)/income items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified cash flow hedging instruments |
|
| (1.6) |
|
| (1.6) |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
Unrealized gains on securities |
|
| 0.2 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 0.2 |
Pension, SERP, and other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in comprehensive |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
| $ | 74.1 |
| $ | 32.0 |
| $ | 10.0 |
| $ | 6.9 |
| $ | 5.1 |
| $ | 13.6 |
| $ | 6.5 |
*After preferred dividends of subsidiary.
Comprehensive income amounts included in the Other column primarily relate to NU parent and Northeast Utilities Service Company (NUSCO).
Accumulated other comprehensive income fair value adjustments in NU's qualified cash flow hedging instruments for the three months ended March 31, 2008 and the twelve months ended December 31, 2007 are as follows:
|
| Three Months Ended |
| Twelve Months Ended | ||
Balance at beginning of period |
| $ | 2.3 |
| $ | 5.9 |
Hedged transactions recognized into earnings |
|
| 0.3 |
|
| 0.2 |
Change in fair value of interest rate swap agreements |
|
| (18.8) |
|
| - |
Cash flow transactions entered into for the period |
|
| (0.2) |
|
| (3.8) |
Net change associated with hedging transactions |
|
| (18.7) |
|
| (3.6) |
Total fair value adjustments included in accumulated |
|
|
|
|
|
|
NU parent, CL&P, PSNH and Yankee Gas have forward interest rate swap agreements associated with their respective planned 2008 long-term debt issuances. The fair value of interest rate swap agreements is recorded in accumulated other comprehensive income with a corresponding pre-tax amount recorded as derivative assets/liabilities. In March 2008, PSNH terminated its existing agreement and entered into a new forward interest rate swap agreement associated with its planned May 2008 debt issuance. The $2.4 million after-tax settlement amount, net of hedge ineffectiveness of $0.2 million, is included in accumulated other comprehensive income. At March 31, 2008, after-tax fair values of interest rate swap agreements of $7.2 million, $0.2 million, $2 million and $3.9 million were recorded in accumulated other comprehensive income of CL&P, PSNH, Yankee Gas and NU parent, respectively. At December 31, 2007, after-tax amounts of $1.4 million, $0.6 million, $0.5 million and $0.6 million were recorded in accumulated other comprehensive income of CL&P, PSNH, Yankee Gas and NU parent, respectively. For further information, see Note 2, "Derivative Instruments," to the condensed consolidated financial statements.
CL&P had two forward interest rate swap agreements to hedge the interest rates associated with $50 million of its $100 million, 10-year fixed rate 2007 long-term debt issuance and with $50 million of its $100 million, 30-year fixed rate 2007 long-term debt issuance. In September 2007, the debt was issued and the hedges were settled with an after-tax charge of $4.7 million ($7.7 million pre-tax) recorded in accumulated other comprehensive income to be amortized into earnings over the terms of the long-term debt. In addition, a net of tax charge of $67 thousand ($110 thousand pre-tax) was recorded related to hedge ineffectiveness.
WMECO had a forward interest rate swap agreement to hedge the interest rate associated with its $40 million, 30-year fixed rate 2007 long-term debt issuance. In August 2007, the debt was issued and the hedge was settled with an after-tax charge of $0.6 million ($1 million pre-tax) recorded in accumulated other comprehensive income to be amortized into earnings over the term of the long-term debt.
CL&P also had two forward interest rate swap agreements to hedge the interest rates associated with $75 million of its $150 million, 10-year fixed rate 2007 long-term debt issuance and with $75 million of its $150 million, 30-year fixed rate 2007 long-term debt issuance. In March 2007, the debt was issued and the hedges were settled with an after-tax charge of $1.6 million ($2.6 million pre-tax) recorded in accumulated other comprehensive income to be amortized into earnings over the terms of the long-term debt.
It is estimated that a charge of $0.1 million will be reclassified from accumulated other comprehensive income as a decrease to earnings over the next 12 months as a result of amortization of amounts due to forward interest rate swap agreements that have been settled. Assuming the fair values of existing forward interest rate swap agreements remain unchanged from March 31, 2008 to their planned settlement dates in 2008, it is estimated that $1.3 million will be reclassified from accumulated other comprehensive income
23
as a decrease to earnings over the next 12 months as a result of amortization of amounts due to the settlement of the forward interest rate swap agreements. At March 31, 2008, it is estimated that a pre-tax $0.1 million included in the accumulated other comprehensive income balance will be reclassified as an increase to earnings over the next 12 months related to Pension, SERP and other postretirement benefits adjustments.
7.
DISCONTINUED OPERATIONS (NU, NU Enterprises)
NU's condensed consolidated statements of income present NGC, Mt. Tom and SECI as discontinued operations. Under discontinued operations presentation, revenues and expenses of the businesses classified as discontinued operations are classified in loss from discontinued operations on the condensed consolidated statements of income, for all periods presented.
Summarized information for the discontinued operations is as follows:
|
| For the Three Months Ended | ||||
(Millions of Dollars) |
| March 31, 2008 |
| March 31, 2007 | ||
Operating revenues |
| $ | - |
| $ | 0.8 |
Operating expenses |
|
| - |
|
| (1.1) |
Loss from discontinued operations |
|
| - |
|
| (0.3) |
Loss from sale/disposition of discontinued operations |
|
| - |
|
| (1.9) |
Income tax benefit from discontinued operations |
|
| - |
|
| 0.9 |
Net loss from discontinued operations |
|
| - |
|
| (1.3) |
The loss from sale/disposition of discontinued operations in the first quarter of 2007 related to a purchase price adjustment from the sale of the competitive generation business.
No intercompany revenues were included in discontinued operations for either of the three months ended March 31, 2008 and 2007.
At March 31, 2008, NU did not have and does not expect to have significant ongoing involvement or continuing cash flows with the entities presented in discontinued operations.
8.
EARNINGS PER SHARE (NU)
Earnings per share (EPS) is computed based upon the weighted average number of common shares outstanding, excluding unallocated Employee Stock Ownership Plan (ESOP) shares, during each period. Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common stock. There were no antidilutive options for either of the three months ended March 31, 2008 and 2007.
The following table sets forth the components of basic and fully diluted EPS:
|
| For the Three Months Ended March 31, | ||||
(Millions of Dollars, except for share information) |
| 2008 |
| 2007 | ||
Income from continuing operations |
| $ | 58.4 |
| $ | 76.4 |
Loss from discontinued operations |
|
| - |
|
| (1.3) |
Net income |
| $ | 58.4 |
| $ | 75.1 |
Basic EPS common shares outstanding (average) |
|
| 155,286,111 |
|
| 154,349,473 |
Dilutive effect |
|
| 435,499 |
|
| 642,571 |
Fully diluted EPS common shares |
|
|
|
|
|
|
Basic and Fully Diluted EPS: |
|
|
|
|
|
|
Income from continuing operations |
| $ | 0.38 |
| $ | 0.50 |
Loss from discontinued operations |
|
| - |
|
| (0.01) |
Net income |
| $ | 0.38 |
| $ | 0.49 |
Restricted share units (RSUs) are included in basic common shares outstanding when shares are both vested and issued. The dilutive effect of RSUs granted but not issued is calculated using the treasury stock method. Assumed proceeds of RSUs under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the RSUs (the difference between the market value of RSUs using the average market price during the period and the grant date market value).
24
The dilutive effect of stock options is also calculated using the treasury stock method. Assumed proceeds for stock options consist of remaining compensation cost to be recognized, cash proceeds that would be received upon exercise, and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the stock options (the difference between the market value of the common shares underlying the stock options outstanding for the period using the average market price and the exercise price on the date of grant).
Allocated ESOP shares are included in basic common shares outstanding in the previous table.
9.
SEGMENT INFORMATION (All Companies)
Presentation: NU is organized between the regulated companies and NU Enterprises' businesses based on a combination of factors, including the characteristics of each business' products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates. Cash flows for total investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC and the capitalized portion of pension expense or income. Segment information for all periods presented has been reclassified to conform to the current period presentation, except as indicated.
The regulated companies segment, including the electric distribution, generation and transmission segments, as well as the gas distribution segment (Yankee Gas), represents approximately 98 percent and 96 percent of NU's total revenues for the three months ended March 31, 2008 and 2007, respectively. CL&P's, PSNH's and WMECO's complete condensed consolidated financial statements are included in this combined report on Form 10-Q. PSNH's distribution segment includes its generation activities. Also included in this combined report on Form 10-Q is detailed information regarding CL&P's, PSNH's, and WMECO's transmission segments.
At March 31, 2008, the NU Enterprises business segment included the following legal entities: 1) Select Energy (wholesale contracts), 2) NGS, 3) Boulos, and 4) NU Enterprises parent.
Other in the segment tables primarily consists of 1) the results of NU parent, which include other income related to the equity in earnings of NU parent's subsidiaries and interest income from the NU Money Pool, which are both eliminated in consolidation, and interest income and expense related to the cash and debt of NU parent, respectively, 2) the revenues and expenses of Northeast Utilities Services Company, most of which are eliminated in consolidation, and 3) the results of other subsidiaries, which include The Rocky River Realty Company and The Quinnehtuk Company (real estate subsidiaries), Mode 1 Communications, Inc. and the non-utility subsidiaries of Yankee Energy System, Inc. (Yankee Energy Services Company, Yankee Energy Financial Services Company and NorConn Properties, Inc.).
Effective January 1, 2007, financial information for the remaining operations of HWP that were not exited as part of the sale of the competitive generation business was included as part of the Other reportable segment as these operations were no longer considered part of NU Enterprises subsequent to the sale. Accordingly, HWP's remaining operations have been presented as part of the Other reportable segment for each of the three months ended March 31, 2008 and 2007.
NU's condensed consolidated statements of income for the three months ended March 31, 2007 present the remaining activity for NGC, Mt. Tom and SECI as discontinued operations. For further information and information regarding the exit from these businesses, see Note 7, "Discontinued Operations," to the condensed consolidated financial statements.
25
NU's segment information for the three months ended March 31, 2008 and 2007 is as follows (certain amounts presented in the financial statements may differ from amounts presented in the segment schedules due to rounding):
|
| For the Three Months Ended March 31, 2008 | ||||||||||||||||||||||
|
| Regulated Companies |
|
| ||||||||||||||||||||
|
| Distribution (1) |
|
|
|
| ||||||||||||||||||
(Millions of Dollars) |
| Electric |
| Gas |
| Transmission |
| NU Enterprises |
| Other |
| Eliminations |
| Total | ||||||||||
Operating revenues |
| $ | 1,198.1 |
| $ | 199.6 |
| $ | 94.8 |
| $ | 33.8 |
| $ | 100.0 |
| $ | (106.3) |
| $ | 1,520.0 | |||
Depreciation and amortization |
|
| (128.9) |
|
| (6.3) |
|
| (10.8) |
|
| (0.1) |
|
| (4.0) |
|
| 0.1 |
|
| (150.0) | |||
Other operating expenses |
|
| (981.7) |
|
| (158.3) |
|
| (31.7) |
|
| (29.2) |
|
| (140.7) |
|
| 103.9 |
|
| (1,237.7) | |||
Operating income/(loss) |
|
| 87.5 |
|
| 35.0 |
|
| 52.3 |
|
| 4.5 |
|
| (44.7) |
|
| (2.3) |
|
| 132.3 | |||
Interest expense, net of AFUDC |
|
| (41.6) |
|
| (5.3) |
|
| (10.4) |
|
| (1.6) |
|
| (5.9) |
|
| 2.2 |
|
| (62.6) | |||
Interest income |
|
| 0.9 |
|
| - |
|
| 0.4 |
|
| 0.3 |
|
| 1.7 |
|
| (2.2) |
|
| 1.1 | |||
Other income, net |
|
| 6.8 |
|
| - |
|
| 5.6 |
|
| - |
|
| 74.0 |
|
| (74.0) |
|
| 12.4 | |||
Income tax (expense)/benefit |
|
| (17.5) |
|
| (11.1) |
|
| (14.9) |
|
| (1.3) |
|
| 22.0 |
|
| (0.6) |
|
| (23.4) | |||
Preferred dividends |
|
| (0.9) |
|
| - |
|
| (0.5) |
|
| - |
|
| - |
|
| - |
|
| (1.4) | |||
Net income |
| $ | 35.2 |
| $ | 18.6 |
| $ | 32.5 |
| $ | 1.9 |
| $ | 47.1 |
| $ | (76.9) |
| $ | 58.4 | |||
Total assets (2) |
| $ | 10,742.3 |
| $ | 1,273.5 |
| $ | - |
| $ | 129.1 |
| $ | 4,178.6 |
| $ | (3,979.7) |
| $ | 12,343.8 | |||
Cash flows for total |
| $ |
|
| $ |
|
| $ |
|
| $ |
|
| $ |
|
|
|
|
| $ |
| |||
|
| For the Three Months Ended March 31, 2007 | ||||||||||||||||||||||
|
| Regulated Companies |
|
| ||||||||||||||||||||
|
| Distribution (1) |
|
|
|
| ||||||||||||||||||
(Millions of Dollars) |
| Electric |
| Gas |
| Transmission |
| NU Enterprises |
| Other |
| Eliminations |
| Total | ||||||||||
Operating revenues |
| $ | 1,381.4 |
| $ | 184.8 |
| $ | 69.0 |
| $ | 79.7 |
| $ | 94.0 |
| $ | (105.4) |
| $ | 1,703.5 | |||
Depreciation and amortization |
|
| (105.3) |
|
| (5.8) |
|
| (9.0) |
|
| (0.1) |
|
| (2.4) |
|
| 1.1 |
|
| (121.5) | |||
Other operating expenses |
|
| (1,189.2) |
|
| (154.5) |
|
| (28.3) |
|
| (69.8) |
|
| (87.7) |
|
| 103.2 |
|
| (1,426.3) | |||
Operating income |
|
| 86.9 |
|
| 24.5 |
|
| 31.7 |
|
| 9.8 |
|
| 3.9 |
|
| (1.1) |
|
| 155.7 | |||
Interest expense, net of AFUDC |
|
| (42.5) |
|
| (4.2) |
|
| (8.8) |
|
| (2.9) |
|
| (8.3) |
|
| 7.4 |
|
| (59.3) | |||
Interest income |
|
| 1.2 |
|
| - |
|
| 0.2 |
|
| 0.6 |
|
| 12.6 |
|
| (7.4) |
|
| 7.2 | |||
Other income, net |
|
| 4.3 |
|
| 0.4 |
|
| 1.3 |
|
| - |
|
| 56.5 |
|
| (55.6) |
|
| 6.9 | |||
Income tax expense |
|
| (14.2) |
|
| (7.1) |
|
| (8.2) |
|
| (1.4) |
|
| (1.3) |
|
| (0.5) |
|
| (32.7) | |||
Preferred dividends |
|
| (1.1) |
|
| - |
|
| (0.3) |
|
| - |
|
| - |
|
| - |
|
| (1.4) | |||
Income from continuing |
| $ |
|
| $ |
|
| $ |
|
| $ |
|
| $ |
|
|
|
|
|
|
| |||
Loss from |
|
|
|
|
|
|
|
|
|
|
|
|
|
| - |
|
|
|
|
|
| |||
Net income |
| $ | 34.6 |
| $ | 13.6 |
| $ | 15.9 |
| $ | 4.8 |
| $ | 63.4 |
| $ | (57.2) |
| $ | 75.1 | |||
Cash flows for total |
| $ |
|
| $ |
|
| $ |
|
| $ |
|
| $ |
|
|
|
|
| $ |
| |||
(1)
Includes PSNH's generation activities.
(2)
Information for segmenting total assets between electric distribution and transmission is not available at March 31, 2008. On an NU consolidated basis, these distribution and transmission assets are disclosed in the electric distribution columns above.
The regulated companies information related to the distribution and transmission segments for CL&P, PSNH and WMECO for the three months ended March 31, 2008 and 2007 is as follows:
|
| CL&P - For the Three Months Ended March 31, 2008 | |||||||
(Millions of Dollars) |
| Distribution |
| Transmission |
| Total | |||
Operating revenues |
| $ | 812.1 |
| $ | 73.4 |
| $ | 885.5 |
Depreciation and amortization |
|
| (88.0) |
|
| (8.5) |
|
| (96.5) |
Other operating expenses |
|
| (675.5) |
|
| (23.7) |
|
| (699.2) |
Operating income |
|
| 48.6 |
|
| 41.2 |
|
| 89.8 |
Interest expense, net of AFUDC |
|
| (26.3) |
|
| (8.7) |
|
| (35.0) |
Interest income |
|
| 0.6 |
|
| 0.4 |
|
| 1.0 |
Other income, net |
|
| 6.4 |
|
| 4.8 |
|
| 11.2 |
Income tax expense |
|
| (9.5) |
|
| (11.4) |
|
| (20.9) |
Preferred dividends |
|
| (0.9) |
|
| (0.5) |
|
| (1.4) |
Net income |
| $ | 18.9 |
| $ | 25.8 |
| $ | 44.7 |
Cash flows for total investments in plant |
| $ | 52.3 |
| $ | 144.7 |
| $ | 197.0 |
26
|
| CL&P - For the Three Months Ended March 31, 2007 | |||||||
(Millions of Dollars) |
| Distribution |
| Transmission |
| Total | |||
Operating revenues |
| $ | 991.3 |
| $ | 52.4 |
| $ | 1,043.7 |
Depreciation and amortization |
|
| (66.6) |
|
| (6.9) |
|
| (73.5) |
Other operating expenses |
|
| (871.1) |
|
| (20.1) |
|
| (891.2) |
Operating income |
|
| 53.6 |
|
| 25.4 |
|
| 79.0 |
Interest expense, net of AFUDC |
|
| (27.9) |
|
| (7.2) |
|
| (35.1) |
Interest income |
|
| 0.8 |
|
| 0.2 |
|
| 1.0 |
Other income, net |
|
| 3.7 |
|
| 1.2 |
|
| 4.9 |
Income tax expense |
|
| (8.5) |
|
| (6.3) |
|
| (14.8) |
Preferred dividends |
|
| (1.1) |
|
| (0.3) |
|
| (1.4) |
Net income |
| $ | 20.6 |
| $ | 13.0 |
| $ | 33.6 |
Cash flows for total investments in plant |
| $ | 53.5 |
| $ | 105.1 |
| $ | 158.6 |
|
| PSNH - For the Three Months Ended March 31, 2008 | |||||||
(Millions of Dollars) |
| Distribution (1) |
| Transmission |
| Total | |||
Operating revenues |
| $ | 276.7 |
| $ | 15.1 |
| $ | 291.8 |
Depreciation and amortization |
|
| (30.2) |
|
| (1.6) |
|
| (31.8) |
Other operating expenses |
|
| (219.8) |
|
| (5.3) |
|
| (225.1) |
Operating income |
|
| 26.7 |
|
| 8.2 |
|
| 34.9 |
Interest expense, net of AFUDC |
|
| (10.9) |
|
| (1.1) |
|
| (12.0) |
Interest income |
|
| 0.1 |
|
| 0.1 |
|
| 0.2 |
Other income, net |
|
| 0.4 |
|
| 0.7 |
|
| 1.1 |
Income tax expense |
|
| (4.8) |
|
| (2.7) |
|
| (7.5) |
Net income |
| $ | 11.5 |
| $ | 5.2 |
| $ | 16.7 |
Cash flows for total investments in plant |
| $ | 31.0 |
| $ | 25.7 |
| $ | 56.7 |
(1)
Includes PSNH's generation activities.
|
| PSNH - For the Three Months Ended March 31, 2007 | |||||||
(Millions of Dollars) |
| Distribution (1) |
| Transmission |
| Total | |||
Operating revenues |
| $ | 266.2 |
| $ | 10.9 |
| $ | 277.1 |
Depreciation and amortization |
|
| (28.6) |
|
| (1.4) |
|
| (30.0) |
Other operating expenses |
|
| (217.5) |
|
| (5.5) |
|
| (223.0) |
Operating income |
|
| 20.1 |
|
| 4.0 |
|
| 24.1 |
Interest expense, net of AFUDC |
|
| (10.4) |
|
| (1.1) |
|
| (11.5) |
Interest income |
|
| 0.2 |
|
| - |
|
| 0.2 |
Other income, net |
|
| 0.3 |
|
| 0.2 |
|
| 0.5 |
Income tax expense |
|
| (2.1) |
|
| (1.2) |
|
| (3.3) |
Net income |
| $ | 8.1 |
| $ | 1.9 |
| $ | 10.0 |
Cash flows for total investments in plant |
| $ | 31.3 |
| $ | 8.5 |
| $ | 39.8 |
(1)
Includes PSNH's generation activities.
|
| WMECO - For the Three Months Ended March 31, 2008 | |||||||
(Millions of Dollars) |
| Distribution |
| Transmission |
| Total | |||
Operating revenues |
| $ | 109.4 |
| $ | 6.4 |
| $ | 115.8 |
Depreciation and amortization |
|
| (10.7) |
|
| (0.7) |
|
| (11.4) |
Other operating expenses |
|
| (86.4) |
|
| (2.8) |
|
| (89.2) |
Operating income |
|
| 12.3 |
|
| 2.9 |
|
| 15.2 |
Interest expense, net of AFUDC |
|
| (4.4) |
|
| (0.7) |
|
| (5.1) |
Interest income |
|
| 0.1 |
|
| - |
|
| 0.1 |
Other income, net |
|
| - |
|
| 0.1 |
|
| 0.1 |
Income tax expense |
|
| (3.2) |
|
| (0.8) |
|
| (4.0) |
Net income |
| $ | 4.8 |
| $ | 1.5 |
| $ | 6.3 |
Cash flows for total investment in plant |
| $ | 6.9 |
| $ | 6.6 |
| $ | 13.5 |
27
|
| WMECO - For the Three Months Ended March 31, 2007 | |||||||
(Millions of Dollars) |
| Distribution |
| Transmission |
| Total | |||
Operating revenues |
| $ | 123.9 |
| $ | 5.7 |
| $ | 129.6 |
Depreciation and amortization |
|
| (10.1) |
|
| (0.7) |
|
| (10.8) |
Other operating expenses |
|
| (100.6) |
|
| (2.8) |
|
| (103.4) |
Operating income |
|
| 13.2 |
|
| 2.2 |
|
| 15.4 |
Interest expense, net of AFUDC |
|
| (4.2) |
|
| (0.5) |
|
| (4.7) |
Interest income |
|
| 0.2 |
|
| - |
|
| 0.2 |
Other income, net |
|
| 0.3 |
|
| - |
|
| 0.3 |
Income tax expense |
|
| (3.6) |
|
| (0.7) |
|
| (4.3) |
Net income |
| $ | 5.9 |
| $ | 1.0 |
| $ | 6.9 |
Cash flows for total investments in plant |
| $ | 8.0 |
| $ | 2.8 |
| $ | 10.8 |
28
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Trustees and Shareholders of Northeast Utilities:
We have reviewed the accompanying condensed consolidated balance sheet of Northeast Utilities and subsidiaries (the "Company") as of March 31, 2008, and the related condensed consolidated statements of income and cash flows for the three-month periods ended March 31, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.
We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
As discussed in Notes 1.C. and 3, the Company adopted Statement of Financial Accounting Standard No. 157, Fair Value Measurements, as of January 1, 2008.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and consolidated statement of capitalization of Northeast Utilities and subsidiaries as of December 31, 2007, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended (not presented herein); and in our report dated February 28, 2008 (which report included an explanatory paragraph related to the adoption of Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109, as of January 1, 2007), we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2007 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
/s/ | Deloitte & Touche LLP |
Hartford, Connecticut
May 9, 2008
29
This Page Intentionally Left Blank
30
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
31
32
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES | |||||
|
|
|
|
|
|
CONDENSED CONSOLIDATED BALANCE SHEETS |
|
|
|
|
|
(Unaudited) |
|
|
|
|
|
|
| March 31, |
|
| December 31, |
|
| 2008 |
|
| 2007 |
|
| (Thousands of Dollars) | |||
LIABILITIES AND CAPITALIZATION |
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
|
Notes payable to banks |
| $ 150,000 |
|
| $ - |
Notes payable to affiliated companies |
| 7,025 |
|
| 38,825 |
Accounts payable |
| 368,971 |
|
| 368,356 |
Accounts payable to affiliated companies |
| 45,010 |
|
| 53,096 |
Accrued taxes |
| 8,490 |
|
| - |
Accrued interest |
| 26,083 |
|
| 29,532 |
Derivative liabilities - current |
| 16,131 |
|
| 4,234 |
Other |
| 99,699 |
|
| 107,940 |
|
| 721,409 |
|
| 601,983 |
|
|
|
|
|
|
Rate Reduction Bonds |
| 504,150 |
|
| 548,686 |
|
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
|
Accumulated deferred income taxes |
| 745,138 |
|
| 698,789 |
Accumulated deferred investment tax credits |
| 20,761 |
|
| 21,412 |
Deferred contractual obligations |
| 147,033 |
|
| 152,735 |
Regulatory liabilities |
| 475,143 |
|
| 601,455 |
Derivative liabilities - long-term |
| 778,455 |
|
| 135,991 |
Accrued postretirement benefits |
| 76,309 |
|
| 78,587 |
Other |
| 195,953 |
|
| 191,464 |
|
| 2,438,792 |
|
| 1,880,433 |
Capitalization: |
|
|
|
|
|
Long-Term Debt |
| 2,030,313 |
|
| 2,028,546 |
|
|
|
|
|
|
Preferred Stock - Non-Redeemable |
| 116,200 |
|
| 116,200 |
|
|
|
|
|
|
Common Stockholder's Equity: |
|
|
|
|
|
Common stock, $10 par value - authorized |
|
|
|
|
|
24,500,000 shares; 6,035,205 shares outstanding |
|
|
|
|
|
in 2008 and 2007 |
| 60,352 |
|
| 60,352 |
Capital surplus, paid in |
| 1,301,125 |
|
| 1,243,940 |
Retained earnings |
| 556,201 |
|
| 538,138 |
Accumulated other comprehensive loss |
| (8,708) |
|
| (179) |
Common Stockholder's Equity |
| 1,908,970 |
|
| 1,842,251 |
Total Capitalization |
| 4,055,483 |
|
| 3,986,997 |
|
|
|
|
|
|
Commitments and Contingencies (Note 5) |
|
|
|
|
|
. |
|
|
|
|
|
Total Liabilities and Capitalization |
| $ 7,719,834 |
|
| $ 7,018,099 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed consolidated financial statements. | |||||
33
34
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES | ||||||
|
|
|
| |||
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||
(Unaudited) |
|
|
| |||
| Three Months Ended | |||||
| March 31, | |||||
| 2008 |
| 2007 | |||
| (Thousands of Dollars) | |||||
Operating Activities: |
|
|
| |||
Net income | $ 46,068 |
| $ 34,994 | |||
Adjustments to reconcile to net cash flows |
|
|
| |||
provided by/(used in) operating activities: |
|
|
| |||
Bad debt expense | 1,889 |
| 3,838 | |||
Depreciation | 38,869 |
| 38,189 | |||
Deferred income taxes | 33,694 |
| 7,337 | |||
Amortization of regulatory assets/(liabilities), net | 19,584 |
| (330) | |||
Amortization of rate reduction bonds | 38,031 |
| 35,661 | |||
Amortization of recoverable energy costs | - |
| 1,032 | |||
Pension income, net of capitalized portion | (2,853) |
| (1,609) | |||
Regulatory refunds and underrecoveries | (85,861) |
| (16,708) | |||
Deferred contractual obligations | (5,702) |
| (8,139) | |||
Other non-cash adjustments | 924 |
| 4,297 | |||
Other sources of cash | 105 |
| 3,974 | |||
Other uses of cash | (2,241) |
| (5,960) | |||
Changes in current assets and liabilities: |
|
|
| |||
Receivables and unbilled revenues, net | (14,813) |
| (7,091) | |||
Materials and supplies | (4,703) |
| (4,773) | |||
Investments in securitizable assets | 33,316 |
| (30,810) | |||
Other current assets | (7,529) |
| (8,460) | |||
Accounts payable | (17,742) |
| (12,614) | |||
Taxes receivable/accrued | 26,184 |
| (163,382) | |||
Other current liabilities | (4,930) |
| (13,788) | |||
Net cash flows provided by/(used in) operating activities | 92,290 |
| (144,342) | |||
|
|
|
| |||
Investing Activities: |
|
|
| |||
Investments in property and plant | (196,997) |
| (158,634) | |||
Proceeds from sales of investment securities | 626 |
| 263 | |||
Purchases of investment securities | (643) |
| (283) | |||
Rate reduction bond escrow and other deposits | 7,474 |
| 51,274 | |||
Other investing activities | 623 |
| 648 | |||
Net cash flows used in investing activities | (188,917) |
| (106,732) | |||
|
|
|
| |||
Financing Activities: |
|
|
| |||
Issuance of long-term debt | - |
| 300,000 | |||
Increase in short-term debt | 150,000 |
| - | |||
Retirement of rate reduction bonds | (44,536) |
| (77,796) | |||
Decrease in NU Money Pool borrowings | (31,800) |
| (162,500) | |||
Capital contributions from NU parent | 57,058 |
| 215,000 | |||
Cash dividends on preferred stock | (1,390) |
| (1,390) | |||
Cash dividends on common stock | (26,615) |
| (19,795) | |||
Other financing activities | (183) |
| (4,404) | |||
Net cash flows provided by financing activities | 102,534 |
| 249,115 | |||
Net increase/(decrease) in cash | 5,907 |
| (1,959) | |||
Cash - beginning of period | 538 |
| 3,310 | |||
Cash - end of period | $ 6,445 |
| $ 1,351 | |||
|
|
|
| |||
|
|
|
| |||
|
|
|
| |||
The accompanying notes are an integral part of these condensed consolidated financial statements. | ||||||
35
This Page Intentionally Left Blank
36
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
37
38
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES |
|
|
|
|
|
|
|
CONDENSED CONSOLIDATED BALANCE SHEETS |
|
|
|
(Unaudited) |
|
|
|
| March 31, |
| December 31, |
| 2008 |
| 2007 |
| (Thousands of Dollars) | ||
LIABILITIES AND CAPITALIZATION |
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
Notes payable to banks | $ 30,000 |
| $ 10,000 |
Notes payable to affiliated companies | 14,900 |
| 11,300 |
Accounts payable | 83,377 |
| 91,356 |
Accounts payable to affiliated companies | 17,901 |
| 15,717 |
Accrued interest | 12,809 |
| 9,175 |
Derivative liabilities - current | 266 |
| 2,453 |
Other | 32,064 |
| 22,664 |
| 191,317 |
| 162,665 |
|
|
|
|
Rate Reduction Bonds | 268,887 |
| 282,018 |
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
Accumulated deferred income taxes | 167,932 |
| 192,094 |
Accumulated deferred investment tax credits | 526 |
| 582 |
Deferred contractual obligations | 26,832 |
| 28,215 |
Regulatory liabilities | 164,736 |
| 127,569 |
Accrued pension | 141,894 |
| 138,346 |
Accrued postretirement benefits | 28,069 |
| 29,057 |
Other | 46,523 |
| 31,559 |
| 576,512 |
| 547,422 |
Capitalization: |
|
|
|
Long-Term Debt | 577,004 |
| 576,997 |
|
|
|
|
Common Stockholder's Equity: |
|
|
|
Common stock, $1 par value - authorized |
|
|
|
100,000,000 shares; 301 shares outstanding |
|
|
|
in 2008 and 2007 | - |
| - |
Capital surplus, paid in | 281,320 |
| 275,569 |
Retained earnings | 269,123 |
| 261,528 |
Accumulated other comprehensive (loss)/income | (2,450) |
| 770 |
Common Stockholder's Equity | 547,993 |
| 537,867 |
Total Capitalization | 1,124,997 |
| 1,114,864 |
|
|
|
|
|
|
|
|
Commitments and Contingencies (Note 5) |
|
|
|
|
|
|
|
Total Liabilities and Capitalization | $ 2,161,713 |
| $ 2,106,969 |
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed consolidated financial statements. | |||
39
40
41
This Page Intentionally Left Blank
42
WESTERN MASSACHUSETTS ELECTRIC COMPANY
43
44
45
46
47
NORTHEAST UTILITIES AND SUBSIDIARIES
Management's Discussion and Analysis of
Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with the condensed consolidated financial statements and related notes included in this Quarterly Report on Form 10-Q and the Northeast Utilities and subsidiaries combined 2007 Annual Report on Form 10-K as filed with the Securities and Exchange Commission (SEC) (2007 Form 10-K). References in this Form 10-Q to "NU" or "the company" are to Northeast Utilities combined with its subsidiaries, and the terms "we," "us" and "our" refer to NU. All per share amounts are reported on a fully diluted basis.
The only common equity securities that are publicly traded are common shares of NU. The earnings per share (EPS) of each segment discussed below does not represent a direct legal interest in the assets and liabilities allocated to such segment but rather represents a direct interest in our assets and liabilities as a whole. EPS by segment is a measure not recognized under accounting principles generally accepted in the United States of America (GAAP) that is calculated by dividing the net income or loss of each segment by the average fully diluted NU common shares outstanding for the period. We use this measure to provide segmented earnings guidance and believe that this measurement is useful to investors to evaluate the actual financial performance and contribution of our business segments. This non-GAAP measure should not be considered as an alternative to our consolidated fully diluted EPS determined in accordance with GAAP as an indicator of our operating performance.
The discussion below also references our 2008 earnings and EPS excluding a significant charge associated with the settlement of the 2001 litigation with Consolidated Edison, Inc. (Con Edison). We also discuss our 2007 operating cash flows excluding the cash effects from the Con Edison settlement and tax payments related to the sale of our competitive generation business, and including payments for the retirement of rate reduction bonds. We use these non-GAAP measures to more fully explain and compare the 2008 and 2007 results without the impact of certain non-recurring items, and including the impact of certain recurring items that are not included under GAAP. These measures should not be considered as alternatives to our reported net income, EPS or operating cash flows determined in accordance with GAAP as indicators of our operating performance.
Reconciliations of above non-GAAP measures to respective GAAP measures of consolidated fully diluted EPS, net income and operating cash flows are included under "-Financial Condition and Business Analysis-Overview-Consolidated," "-Financial Condition and Business Analysis-Future Outlook," and "-Financial Condition and Business Analysis-Liquidity" in this Management’s Discussion and Analysis.
FINANCIAL CONDITION AND BUSINESS ANALYSIS
Executive Summary
The following items in this executive summary are explained in more detail in this quarterly report:
Results, Strategy and Outlook:
·
We earned $58.4 million, or $0.38 per share, in the first quarter of 2008, compared with $75.1 million, or $0.49 per share, in the first quarter of 2007. Excluding an after-tax charge of $29.8 million at NU parent, or $0.19 per share, associated with the settlement of litigation with Con Edison, our first quarter 2008 earnings were $88.2 million, or $0.57 per share. The results in 2008 included regulated companies net income of $86.3 million, or $0.56 per share, after payment of preferred dividends, NU Enterprises, Inc. (NU Enterprises) net income of $1.9 million, or $0.01 per share, and NU parent and other companies net losses of $29.8 million, or $0.19 per share.
·
Earnings at the distribution segments of The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH) (including regulated generation), Western Massachusetts Electric Company (WMECO) and Yankee Gas Services Company (Yankee Gas) totaled $53.8 million in the first quarter of 2008, compared with $48.2 million in the first quarter of 2007.
·
The transmission segments of CL&P, PSNH and WMECO earned $32.5 million in the first quarter of 2008, compared with $15.9 million in the first quarter of 2007.
·
NU Enterprises earned $1.9 million in the first quarter of 2008, compared with $4.8 million in the first quarter of 2007. First quarter 2008 results include a net after-tax reduction of earnings of $3 million associated with the implementation of Statement of Financial Accounting Standards (SFAS) No. 157, "Fair Value Measurements."
48
·
CL&P continues to work on its three major transmission projects presently under construction in southwest Connecticut. The Glenbrook Cables and Long Island Replacement Cable projects are on schedule to be completed in 2008, and the Middletown-Norwalk project is ahead of schedule and is currently expected to be completed in early 2009 if construction continues at its current pace. For more information on these projects, see "Business Development and Capital Expenditures - Regulated Companies - Transmission Segment" in this Management's Discussion and Analysis.
·
We continue to project consolidated 2008 earnings of between $1.45 per share and $1.70 per share, including the charge associated with the Con Edison litigation settlement, and between $1.65 per share and $1.90 per share excluding it.
Legal, Regulatory and Other Items:
·
On March 24, 2008, the Federal Energy Regulatory Commission (FERC) issued an order on rehearing concerning the return on equity (ROE) allowed to owners of New England electric transmission facilities, including CL&P, PSNH and WMECO. In its order, the FERC raised the base ROE from 10.2 percent to 10.4 percent effective February 1, 2005, left unchanged an incremental 50 basis points provided in its prior order for transmission owners who are part of the New England Regional Transmission Organization (RTO), and reaffirmed its initial order providing an incremental 74 basis point increase effective November 1, 2006. The order also modified the FERC's earlier order concerning an incremental 100 basis points for facilities that are part of the New England Independent System Operator (ISO-NE) Regional System Plan (RSP) by limiting the 100 basis points adder solely to projects completed by December 31, 2008. For projects completed after this date, incentives will be approved by the FERC on a project-by-project basis. For Local Network Service (LNS) rates, the ROEs are 10.4 percent from February 1, 2005 to October 31, 2006 and 11.14 percent from November 1, 2006 forward. For Regional Network Service (RNS) rates, the ROEs are 10.9 percent plus an incremental 100 basis points for qualified projects from February 1, 2005 to October 31, 2006 and 11.64 percent plus an incremental 100 basis points for qualified projects from November 1, 2006 forward. In the first quarter of 2008, we recognized $3.5 million in transmission segment earnings related to this order, of which approximately $2.9 million related to the February 1, 2005 through December 31, 2007 time period.
·
On March 13, 2008, we entered into a settlement agreement with Con Edison which settled all claims under the civil lawsuit between Con Edison and us relating to our proposed but unconsummated merger. Under the terms of the settlement agreement, we paid Con Edison $49.5 million on March 26, 2008. This amount is not recoverable from ratepayers. For more information about the Con Edison litigation, please refer to "Item 3 - Legal Proceedings" of our Annual Report on Form 10-K for the year ended December 31, 2007.
·
On March 3, 2008, as required by the Connecticut Department of Public Utility Control (DPUC), CL&P filed a proposal with the DPUC to build a total of 265 megawatts (MW) of peaking generation in Lebanon and Waterbury, Connecticut. The DPUC is scheduled to issue a final ruling on all proposals, including CL&P's, on June 18, 2008.
·
On January 28, 2008, the DPUC approved annual increases in CL&P distribution rates of $77.8 million, effective February 1, 2008, and an incremental $20.1 million, effective February 1, 2009.
Liquidity:
·
Our cash capital expenditures totaled $288.1 million in the first quarter of 2008, compared with $227.7 million in the first quarter of 2007. The increase in our cash capital expenditures was primarily the result of higher transmission segment capital expenditures, particularly at CL&P.
·
Cash flows provided by operations were $35.2 million, including rate reduction bond payments of $61.1 million, in the first quarter of 2008, compared with cash flows used in operations of $360 million, including rate reduction bond payments of $93.4 million, in the first quarter of 2007. In the first quarter of 2007, federal and state income tax payments totaling approximately $400 million were made relating to the 2006 sale of the competitive generation business. Excluding these tax payments from first quarter 2007 cash flows, the 2008 operating cash flows were lower primarily as a result of $84.3 million in regulatory underrecoveries and refunds to customers, primarily related to Generation Service Charge (GSC) and Federally Mandated Congestion Charges (FMCC) at CL&P, and the $49.5 million payment to Con Edison, which will be partially offset over the remainder of the year by a related $19.7 million reduction in income tax payments. These negative cash flow items were partially offset by net proceeds of $80 million from the sale of CL&P accounts receivable and unbilled revenues in the first quarter of 2008.
49
Overview
Consolidated: We earned $58.4 million, or $0.38 per share, in the first quarter of 2008, compared with $75.1 million, or $0.49 per share, in the first quarter of 2007. Excluding an after-tax charge of $29.8 million, or $0.19 per share, associated with the settlement of litigation with Con Edison, our earnings in the first quarter of 2008 were $88.2 million, or $0.57 per share. A summary of our earnings by segment, which also reconciles consolidated net income and fully diluted EPS to the respective non-GAAP measures of consolidated non-GAAP earnings and EPS, as well as EPS by segment, for the first quarter of 2008 and 2007, is as follows:
|
| For the Three Months Ended March 31, | ||||||||||
|
| 2008 |
| 2007 | ||||||||
(Millions of Dollars. except per share amounts) |
| Amount |
| Per Share |
| Amount |
| Per Share | ||||
Net Income (GAAP) |
| $ | 58.4 |
| $ | 0.38 |
| $ | 75.1 |
| $ | 0.49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated companies |
| $ | 86.3 |
| $ | 0.56 |
| $ | 64.1 |
| $ | 0.42 |
NU Enterprises |
|
| 1.9 |
|
| 0.01 |
|
| 4.8 |
|
| 0.03 |
NU parent and other companies |
|
| - |
|
| - |
|
| 6.2 |
|
| 0.04 |
Non-GAAP earnings |
|
| 88.2 |
|
| 0.57 |
|
| 75.1 |
|
| 0.49 |
Con Edison litigation charge |
|
| (29.8) |
|
| (0.19) |
|
| - |
|
| - |
Net Income (GAAP) |
| $ | 58.4 |
| $ | 0.38 |
| $ | 75.1 |
| $ | 0.49 |
Regulated Companies: Our regulated companies, which are comprised of CL&P, PSNH, WMECO and Yankee Gas, segment their earnings between their electric transmission segment and their electric and gas distribution segments, with PSNH generation included with the electric distribution segment. A summary of regulated company earnings by segment for the first quarter of 2008 and 2007 is as follows:
|
| For the Three Months Ended March 31, | ||||
(Millions of Dollars) |
|
| 2008 |
|
| 2007 |
CL&P Transmission* |
| $ | 25.8 |
| $ | 13.0 |
PSNH Transmission |
|
| 5.2 |
|
| 1.9 |
WMECO Transmission |
|
| 1.5 |
|
| 1.0 |
Total Transmission |
|
| 32.5 |
|
| 15.9 |
CL&P Distribution* |
|
| 18.9 |
|
| 20.6 |
PSNH Distribution and Generation |
|
| 11.5 |
|
| 8.1 |
WMECO Distribution |
|
| 4.8 |
|
| 5.9 |
Yankee Gas |
|
| 18.6 |
|
| 13.6 |
Total Distribution and Generation |
|
| 53.8 |
|
| 48.2 |
Net Income - Regulated Companies |
| $ | 86.3 |
| $ | 64.1 |
*After preferred dividends in all periods.
The higher first quarter 2008 transmission segment earnings reflect a higher level of investment in this segment as we continue to build out our transmission infrastructure to meet the region’s reliability needs. CL&P’s transmission earnings increased primarily due to CL&P’s significant ongoing investment in projects in southwest Connecticut. The 2008 transmission segment results also included earnings of approximately $3.5 million associated with an order on rehearing issued by the FERC on March 24, 2008 concerning the ROE allowed to owners of New England electric transmission facilities, including CL&P, PSNH and WMECO.
CL&P’s first quarter 2008 distribution segment earnings were $1.7 million lower than the same period in 2007 primarily due to higher storm costs, operating costs, income taxes, and interest expense, and a decrease in retail sales of 2.3 percent in 2008. These items were partially offset by higher distribution revenues resulting from the distribution rate increase effective February 1, 2008, higher other revenues resulting from the 2005 "Act Concerning Energy Independence" that provides utilities with a financial incentive to promote distributed generation and demand side management, and lower carrying costs on FMCC overrecoveries. For the 12 months ended March 31, 2008, CL&P’s distribution segment Regulatory ROE was 7.6 percent. We expect CL&P to achieve a distribution Regulatory ROE close to 8 percent in calendar year 2008.
PSNH's first quarter 2008 distribution and generation segment earnings were $3.4 million higher than the same period in 2007 primarily due to a $37.7 million annualized energy delivery rate increase that took effect on July 1, 2007 and an additional $3 million annualized energy delivery rate increase that took effect on January 1, 2008, partially offset by higher storm costs and operating costs in 2008. For the 12 months ended March 31, 2008, PSNH’s combined distribution and generation segment Regulatory ROE was 9.8 percent. We expect PSNH to achieve a combined distribution and generation Regulatory ROE in the 9 percent to 9.5 percent range in calendar year 2008.
50
WMECO’s first quarter 2008 distribution segment earnings were $1.1 million lower than 2007 primarily due to higher operating costs and a 2.2 percent decline in retail sales in 2008, partially offset by a $3 million annualized distribution rate increase that took effect on January 1, 2008. For the 12 months ended March 31, 2008, WMECO’s distribution segment Regulatory ROE was 9.6 percent. We expect WMECO to achieve a distribution Regulatory ROE in the 9 percent to 9.5 percent range in calendar year 2008.
Yankee Gas’s first quarter earnings were $5 million higher than the same period in 2007 primarily due to a $22.1 million annualized distribution rate increase that took effect on July 1, 2007 partially offset by a 4.9 percent decrease in sales that was primarily due to warmer weather in 2008. For the 12 months ended March 31, 2008, Yankee Gas’s Regulatory ROE was 10.2 percent. We expect Yankee Gas to achieve a Regulatory ROE in the 9 percent to 9.5 percent range in calendar year 2008.
For the distribution segment of our regulated companies, a summary of changes in CL&P, PSNH and WMECO retail electric kilowatt-hour sales and Yankee Gas firm natural gas sales for the first quarter of 2008 as compared to the same period in 2007 on an actual and weather normalized basis (using a 30-year average) is as follows:
|
| Electric |
| Firm Natural Gas | ||||||||||||||||
|
| CL&P |
| PSNH |
| WMECO |
| Total |
| Yankee Gas | ||||||||||
|
|
|
| Weather |
|
|
| Weather |
|
|
| Weather |
|
|
| Weather |
|
|
| Weather |
Residential |
| (4.8)% |
| (3.4)% |
| (0.5)% |
| (0.3)% |
| (2.2)% |
| (1.1)% |
| (3.6)% |
| (2.5)% |
| (8.5)% |
| (4.3)% |
Commercial |
| 1.2 % |
| 1.4 % |
| 1.6 % |
| 1.7 % |
| (0.3)% |
| (0.2)% |
| 1.2 % |
| 1.4 % |
| (5.0)% |
| (1.2)% |
Industrial |
| (4.0)% |
| (4.0)% |
| (3.2)% |
| (3.2)% |
| (5.7)% |
| (5.7)% |
| (4.0)% |
| (4.0)% |
| 1.3 % |
| 2.7 % |
Other |
| (10.6)% |
| (10.6)% |
| 1.6 % |
| 1.6 % |
| (0.5)% |
| (0.5)% |
| (9.1)% |
| (9.1)% |
| 0.0 % |
| 0.0 % |
Total |
| (2.3)% |
| (1.6)% |
| (0.1)% |
| 0.0 % |
| (2.2)% |
| (1.6)% |
| (1.8)% |
| (1.2)% |
| (4.9)% |
| (1.5)% |
A summary of our retail electric sales in gigawatt hours for CL&P, PSNH and WMECO and firm natural gas sales in million cubic feet for Yankee Gas for the first quarter of 2008 and 2007 is as follows:
|
| For the Three Months Ended March 31, | ||||||||||
|
| Electric |
| Firm Natural Gas | ||||||||
|
|
|
| 2007 |
| Percentage |
| 2008 |
| 2007 |
| Percentage |
Residential |
| 3,985 |
| 4,136 |
| (3.6)% |
| 5,809 |
| 6,345 |
| (8.5)% |
Commercial |
| 3,716 |
| 3,672 |
| 1.2 % |
| 5,450 |
| 5,734 |
| (5.0)% |
Industrial |
| 1,234 |
| 1,286 |
| (4.0)% |
| 3,842 |
| 3,794 |
| 1.3 % |
Other |
| 91 |
| 100 |
| (9.1)% |
| - |
| - |
| 0.0 % |
Total |
| 9,026 |
| 9,194 |
| (1.8)% |
| 15,101 |
| 15,873 |
| (4.9)% |
First quarter 2008 weather normalized electric and natural gas sales were somewhat lower than we expected. We believe the lower sales were largely due to the sluggish economic conditions in the region and energy conservation measures implemented by customers. We cannot determine at this time whether these trends will continue in the future. We have experienced positive customer growth in the first quarter of 2008 consistent with our expectations, which indicates that the lower sales did not reflect any significant migration of customers out of our service territories.
NU Enterprises: NU Enterprises, which continues to manage to completion its remaining wholesale marketing contracts and energy services activities, earned $1.9 million in the first quarter of 2008, compared with $4.8 million in the first quarter of 2007. First quarter 2008 results include an after-tax reduction of earnings of $3 million associated with the implementation of SFAS No. 157, net of a $0.7 million benefit from partially reversing the SFAS No. 157 implementation charge as we served rather than exited Select Energy Inc.’s (Select Energy) wholesale marketing contracts in the first quarter. NU Enterprises' earnings for the first quarter of 2008 and 2007 included positive mark-to-market impacts of $0.5 million and $1.5 million, respectively, associated with the wholesale marketing contracts.
NU Parent and Other Companies: NU parent and other companies lost $29.8 million in the first quarter of 2008 compared with earnings of $6.2 million in the first quarter of 2007. The 2008 first quarter loss results from the payment by NU parent to Con Edison of $49.5 million in March 2008 as part of a comprehensive settlement of litigation that arose in 2001 over the proposed but unconsummated merger between the two companies. The decrease in earnings from 2007 was also the result of reduced interest income for NU parent on a significantly lower level of cash in 2008. NU parent carried a high level of cash in the first quarter of 2007 resulting from the sale of our competitive generation businesses on November 1, 2006. Most of that cash was either invested in the regulated companies in 2007 to support those companies’ capital programs or used to pay taxes due in March 2007 on the competitive generation business sales.
51
Future Outlook
2008 Earnings Projection: We continue to project consolidated 2008 earnings of between $1.45 per share and $1.70 per share, including the settlement with Con Edison, and between $1.65 per share and $1.90 per share excluding it. A summary of our projected 2008 EPS by segment, which also reconciles consolidated fully diluted EPS to the non-GAAP measures of non-GAAP consolidated EPS and EPS by segment, is as follows:
|
| 2008 EPS Range | ||||
(Approximate amounts) |
|
| Low |
|
| High |
Fully Diluted EPS (GAAP) |
| $ | 1.45 |
| $ | 1.70 |
|
|
|
|
|
|
|
Regulated companies: |
|
|
|
|
|
|
Distribution and generation segment |
| $ | 1.05 |
| $ | 1.15 |
Transmission segment |
|
| 0.75 |
|
| 0.85 |
Total regulated companies |
|
| 1.80 |
|
| 2.00 |
NU Enterprises |
|
| - |
|
| - |
NU parent and other companies |
|
| (0.15) |
|
| (0.10) |
Non-GAAP EPS |
|
| 1.65 |
|
| 1.90 |
Con Edison litigation charge |
|
| (0.19) |
|
| (0.19) |
Fully Diluted EPS (GAAP) |
| $ | 1.45 |
| $ | 1.70 |
Long-Term Growth Rate: We continue to project that we can achieve an average compounded annual EPS growth rate of between 8 percent and 11 percent over 2007 earnings of $1.59 per share for the period 2008 through 2012. This EPS growth rate assumes appropriate regulatory approvals and timely rate treatment associated with our electric transmission and distribution investments and natural gas distribution investments. It also assumes we achieve our projected levels of capital expenditures and rate base growth in accordance with our present schedule.
Liquidity
Consolidated: We had $25 million of cash and cash equivalents on hand at March 31, 2008, compared with $15.1 million at December 31, 2007. During the first quarter of 2008, our cash position increased primarily as a result of net borrowings totaling approximately $280 million from our credit facilities and net proceeds of $80 million from the sale of CL&P accounts receivable and unbilled revenues, offset by the continued funding of our capital expenditure programs, the litigation settlement payment to Con Edison of $49.5 million in March 2008, and an adverse change in working capital requirements, as discussed further below.
We had positive operating cash flows of $35.2 million, including rate reduction bond payments of $61.1 million, in the first quarter of 2008, compared with negative operating cash flows of $360 million, including rate reduction bond payments of $93.4 million, in the first quarter of 2007. The negative 2007 cash flows were primarily due to the payment of approximately $400 million in federal and state income taxes in the first quarter of 2007 related to the 2006 sale of the competitive generation business. Excluding these tax payments in 2007, our consolidated cash flows provided by operations, net of rate reduction bond payments, were approximately $40 million in the first quarter of 2007, compared to $85 million in the first quarter of 2008, which includes rate reduction bond payments and excludes the settlement payment to Con Edison. Operating cash flows in 2008 include $84.3 million in regulatory underrecoveries and refunds to customers, primarily related to GSC and FMCC charges at CL&P, the settlement payment to Con Edison of $49.5 million in March 2008, which will be partially offset over the remainder of the year by a related $19.7 million reduction in income tax payments, and an abnormal increase in accounts receivable and unbilled revenues from December 31, 2007, due to temporary difficulties in issuing billings to a limited number of customers on a timely basis at CL&P, which is expected to turn around over the remainder of the year. These negative cash flow items were partially offset by the $80 million in net proceeds from the sale of CL&P accounts receivables and unbilled revenues in the first quarter of 2008. Excluding the net effect of the Con Edison settlement payment, we project consolidated operating cash flows of approximately $450 million to $500 million in 2008, net of payments to retire our rate reduction bonds.
52
A reconciliation of consolidated operating cash flows to non-GAAP operating cash flows, which exclude the cash effects from the Con Edison settlement and the tax payments related to the 2006 sale of the competitive generation business, and include rate reduction bond payments, for the first quarter of 2008 and 2007, and for the 2008 projection, is as follows:
|
| For the Three Months |
| ||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
|
| 2008 Projection | ||
Consolidated operating cash flows, as |
|
| 96.3 |
|
| (266.6) |
|
| 650 - 700 |
Retirement of rate reduction bonds |
|
| (61.1) |
|
| (93.4) |
|
| (231) |
Con Edison settlement payment (projection |
|
| 49.5 |
|
| - |
|
| 29.8 |
Tax payments in 2007 on 2006 generation sale |
|
| - |
|
| 400 |
|
| - |
Non-GAAP operating cash flows (approximate) |
| $ | 85 |
| $ | 40 |
| $ | 450 - 500 |
We expect to issue approximately $660 million of debt in the second quarter of 2008, consisting of $300 million at CL&P and $110 million at PSNH to help fund the companies’ capital programs and about $250 million at NU parent, most of which will be used to refinance $150 million of senior notes maturing on June 1, 2008.
A summary of the current credit ratings and outlooks by Moody's Investors Service (Moody's), Standard & Poor's (S&P) and Fitch Ratings (Fitch) for NU parent and WMECO’s senior unsecured debt and CL&P and PSNH's first mortgage bonds is as follows:
|
| Moody's |
| S&P |
| Fitch | ||||||
|
| Current |
| Outlook |
| Current |
| Outlook |
| Current |
| Outlook |
NU Parent |
| Baa2 |
| Stable |
| BBB- |
| Stable |
| BBB |
| Stable |
CL&P |
| A3 |
| Stable |
| BBB+ |
| Stable |
| A- |
| Stable |
PSNH |
| Baa1 |
| Stable |
| BBB+ |
| Stable |
| BBB+ |
| Stable |
WMECO |
| Baa2 |
| Stable |
| BBB |
| Stable |
| BBB+ |
| Stable |
If NU parent’s senior unsecured debt ratings were to be reduced to a sub-investment grade level by either Moody's or S&P, a number of Select Energy's contracts would require Select Energy to post additional collateral in the form of cash or letters of credit (LOCs). Select Energy would, under its remaining contracts, be required to provide collateral or LOCs in the amount of $32.1 million to various unaffiliated counterparties and collateral or LOCs in the amount of $20.9 million to several independent system operators and unaffiliated local distribution companies (LDCs), in each case at March 31, 2008. If such a downgrade were to occur, NU parent would currently be able to provide that collateral.
NU parent paid common dividends of $31.3 million in the first quarter of 2008, compared with $29.2 million in the first quarter of 2007. The increase primarily reflects a 6.7 percent increase in NU parent's common dividend that took effect in the third quarter of 2007. On April 8, 2008, our Board of Trustees approved a quarterly dividend of $0.20 per share, payable on June 30, 2008 to shareholders of record as of June 1, 2008.
We expect to continue our current policy of dividend increases, subject to the approval of our Board of Trustees and to our future earnings and cash requirements. In general, the regulated companies pay approximately 60 percent of their cash earnings to NU parent in the form of common dividends. In the first quarter of 2008, CL&P, PSNH, WMECO and Yankee Gas paid $26.6 million, $9.1 million, $3.4 million, and $19 million, respectively, in common dividends to NU parent. For the three months ended March 31, 2008, NU parent contributed $57.1 million of equity to CL&P and $5.7 million to PSNH. There were no equity contributions made to WMECO and Yankee Gas in the first quarter of 2008.
NU parent's ability to pay dividends is not regulated under the Federal Power Act, but may be affected by certain state statutes, the leverage restrictions in its revolving credit agreement and the ability of its subsidiaries to pay dividends. Unless a higher amount is approved by the FERC, the Federal Power Act limits the payment of dividends by CL&P, PSNH and WMECO to their respective retained earnings balances, and PSNH is required to reserve an additional amount under its FERC hydroelectric license conditions. In addition, certain state statutes may impose additional limitations on the regulated companies. CL&P, PSNH, WMECO and Yankee Gas also are parties to a revolving credit agreement that imposes leverage restrictions.
Cash capital expenditures included on the accompanying condensed consolidated statements of cash flows and described in the liquidity section of this management's discussion and analysis do not include amounts incurred but not paid, cost of removal, the allowance for funds used during construction (AFUDC) related to equity funds, and the capitalized portion of pension expense or income. Our cash capital expenditures totaled $288.1 million in the first quarter of 2008, compared with $227.7 million in the first quarter of 2007. Our first quarter 2008 cash capital expenditures included $197 million by CL&P, $56.7 million by PSNH, $13.5
53
million by WMECO, $12.3 million by Yankee Gas and $8.6 million by other NU subsidiaries. The increase in our cash capital expenditures was primarily the result of higher transmission segment capital expenditures, particularly at CL&P.
NU Parent: NU parent maintains a credit line of $500 million that expires on November 6, 2010. At March 31, 2008, NU parent had $28 million of LOCs issued and $145 million of borrowings outstanding under that facility.
Regulated Companies: The regulated companies maintain a joint $400 million credit facility that expires on November 6, 2010. There were $258 million of borrowings outstanding under that facility at March 31, 2008.
In addition to this revolving credit facility, CL&P has an arrangement with CL&P Receivables Corporation (CRC) and a financial institution under which the financial institution can purchase up to $100 million of CL&P's accounts receivable and unbilled revenues. Receivables totaling $100 million were sold under that facility at March 31, 2008. For more information regarding CL&P's sale of receivables, see Note 1E, "Summary of Significant Accounting Policies - Sale of Customer Receivables," to the condensed consolidated financial statements.
Impact of Credit Markets: We plan to issue an aggregate of approximately $760 million of long-term debt in 2008 and have entered into forward interest rate swaps to hedge exposure to market rates for the majority of the planned issuances. Due to the overall uncertainties in the market, however, the credit spreads on these issuances may be higher than we have experienced in the past. We believe that the credit markets will continue to be supportive of these debt issuances and that, despite volatility in treasury rates and credit spreads, we will be able to issue this debt at competitive rates.
Certain bond insurers have experienced increasing ratings pressure and are on negative watch by the credit rating agencies. Credit ratings of certain of CL&P's and PSNH's Pollution Control Revenue Bonds (PCRBs) are enhanced with bond insurance. The credit rating of one of these bond insurers has recently been reduced by Fitch. We do not expect the financial condition of this and other bond insurers to have a material impact on CL&P or PSNH, although concerns regarding the bond insurers' credit strength could increase interest expense associated with $151 million of PCRBs that we may remarket in 2008. PSNH has $89 million of insured PCRBs that have a variable rate that continues to be set in a 35-day auction. CL&P has $62 million of insured PCRBs with a five-year fixed rate through October 1, 2008. We will evaluate the interest rate mode on these bonds at that time.
NU Enterprises: Most of the working capital and LOCs required by NU Enterprises are currently used to support Select Energy's remaining wholesale contracts. As these wholesale contracts expire or are exited, NU Enterprises' liquidity requirements will continue to decline.
Business Development and Capital Expenditures
Consolidated: Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portion of pension expense or income, totaled $305.6 million in the first quarter of 2008, compared with $221.4 million in the first quarter of 2007. Capital expenditures for the regulated companies are expected to total $1.3 billion in 2008, which includes $22 million related to our corporate service company and other affiliated companies that support the regulated companies.
Regulated Companies:
Transmission Segment: Transmission segment capital expenditures increased by $84.7 million, or 73 percent, in the first quarter of 2008 as compared with 2007 primarily due to expenditures at CL&P, which continues its significant enhancement of its transmission system in southwest Connecticut. Capital expenditures for the transmission segment are expected to total $0.7 billion in 2008. A summary of transmission segment capital expenditures by company in the first quarters of 2008 and 2007 is as follows (millions of dollars):
|
|
| For the Three Months Ended March 31, | |||
|
|
| 2008 |
|
| 2007 |
CL&P |
| $ | 171.1 |
| $ | 106.4 |
PSNH |
|
| 22.5 |
|
| 7.5 |
WMECO |
|
| 6.9 |
|
| 2.1 |
HWP |
|
| 0.2 |
|
| - |
Totals |
| $ | 200.7 |
| $ | 116.0 |
54
CL&P has three major transmission projects currently under construction in southwest Connecticut. They are:
·
A 69-mile, 345 kilovolt (KV)/115 KV transmission project from Middletown to Norwalk, Connecticut. CL&P's portion of this project is estimated to cost approximately $1.05 billion. Originally due to be in service by the end of 2009, construction is currently ahead of our recently reported mid-2009 schedule, and we now expect it to be completed by early 2009 if we maintain the current pace of construction. The total cost of this project will be reduced by approximately $4 million for every month the project is completed before the original completion date at the end of 2009. CL&P's portion of this project is approximately 79 percent complete. As of March 31, 2008, CL&P had capitalized $701 million associated with this project.
·
A two-cable, nine-mile, 115 KV underground transmission project between Norwalk and Stamford, Connecticut (Glenbrook Cables), construction of which began in October 2006. This project is estimated to cost approximately $223 million and is scheduled to be completed by the end of 2008. This project is approximately 79 percent complete. As of March 31, 2008, CL&P had capitalized $160 million associated with this project.
·
The replacement of the 138 KV, 11-mile undersea electric transmission cable between Norwalk, Connecticut and Northport-Long Island, New York (Long Island Replacement Cable). CL&P and the Long Island Power Authority each own approximately 50 percent of the line. CL&P's portion of the project is estimated to cost $72 million. The project is expected to be placed in service in the second half of 2008 and is approximately 85 percent complete. As of March 31, 2008, CL&P had capitalized $59 million associated with this project.
In addition to our current transmission construction in southwest Connecticut, we continue to work with ISO-NE to refine the design criteria for our next series of major transmission projects, the New England East-West Projects (NEEWS). That series of projects involves our construction of three new overhead 345 KV lines in Massachusetts and Connecticut as well as associated substation work and 115 KV rebuilds. One of the projects will connect to a new transmission line National Grid will build in Rhode Island.
We are working with ISO-NE to further refine the projects’ impact on reliability and operational flexibility, as well as their projected costs. We are completing that analysis and expect to provide an update later in the second quarter.
The first of these projects, the Greater Springfield Reliability Project, may be the most complicated transmission project we have undertaken. We continue to work with ISO-NE on the final design for the Springfield area solution, including the 115 KV Springfield Underground Cables project and expect to initiate the siting process in mid-2008.
The second project for which we expect to file with state authorities later this year is our Interstate Reliability Project, a 40-mile line from Lebanon, Connecticut to the Connecticut-Rhode Island border where it would connect with enhancements National Grid is designing. This project runs through a rural part of Connecticut and thus is less complex than the Greater Springfield project.
The third part of NEEWS is the Central Connecticut Reliability Project, which involves construction of a new line from Bloomfield, Connecticut to Watertown, Connecticut. That line would provide us with another 345 KV connection to move power into southwest Connecticut, where approximately half of the state’s electricity is consumed. The timing of this project would be six to twelve months behind the other two projects, and we would expect to initiate the siting process in mid-2009.
We have not yet adjusted our estimated cost for this series of projects from $1.4 billion. We expect this figure to increase somewhat before we begin the siting processes. We expect to update that figure during the second quarter. However, during siting, state regulators may require changes in configuration to address local concerns which could increase construction costs. Our current design for NEEWS does not contemplate any underground 345 KV lines. Building 345 KV lines underground would increase costs, and our estimate could be increased during the siting process, similar to our experience with our southwest Connecticut projects.
55
Distribution and Generation Segment: In 2008, CL&P, PSNH, WMECO and Yankee Gas are projecting distribution segment (and generation segment in the case of PSNH) capital expenditures of $312 million, $167 million, $35 million, and $56 million, respectively, totaling $0.6 billion. A summary of distribution and generation segment capital expenditures by company in the first quarters of 2008 and 2007 is as follows (millions of dollars):
|
|
| For the Three Months Ended March 31, | |||
|
|
| 2008 |
|
| 2007 |
CL&P |
| $ | 57.3 |
| $ | 56.1 |
PSNH |
|
| 28.2 |
|
| 27.2 |
WMECO |
|
| 6.9 |
|
| 7.6 |
Yankee Gas |
|
| 7.8 |
|
| 13.1 |
Other |
|
| 0.1 |
|
| 0.1 |
Totals |
| $ | 100.3 |
| $ | 104.1 |
The first quarter 2007 capital expenditures at Yankee Gas above included $4.5 million spent on its liquefied natural gas (LNG) storage and production facility in Waterbury, Connecticut. The facility was placed in service in July 2007 with a final cost of approximately $108 million and was filled with LNG by the end of October 2007 to serve customers in the 2007/2008 heating season. The capital cost of this facility has been included in Yankee Gas's rates since July 1, 2007.
Strategic Initiatives: We are evaluating certain development projects that would benefit our customers, such as new regulated generating facilities, investments in wide-spread advanced metering infrastructure (AMI) systems, and transmission projects to better interconnect new renewable generation in northern New England and Canada with southern New England, as well as interconnections within New Hampshire.
One project we are evaluating is building a new 115 KV transmission loop in northern New Hampshire to support the addition of 300 MW of wind and 100 MW of biomass generation, along with other upgrades to the New England transmission system. We are also working with NSTAR, a Massachusetts utility, on the best configuration and termination points for a new 660 MW undersea direct current transmission line that would run from Newington, New Hampshire to Boston, Massachusetts. Additionally, we have proposed construction of a 1,200 MW to 1,500 MW overhead direct current transmission line from the Hydro-Quebec system to Franklin, New Hampshire.
As our next step in the process of identifying potential solutions to the region’s energy and environmental needs, on March 31, 2008, we filed a formal request with ISO-NE to analyze potential increases in the North-South high voltage power transfer capacity from New Hampshire into Massachusetts to deliver additional power from renewable and low-carbon emitting resources in northern New England and Canada to southern New England. We requested that ISO-NE analyze the best methods of increasing that capability by 1,500 MW to 2,500 MW.
The estimated capital expenditures discussed above do not include expenditures related to any of these strategic initiatives.
Transmission Rate Matters and FERC Regulatory Issues
CL&P, PSNH and WMECO and most other New England utilities, generation owners and marketers are parties to a series of agreements that provide for coordinated planning and operation of the region's generation and transmission facilities and the market rules by which these parties participate in the wholesale markets and acquire transmission services. Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent from all market participants, has served as the RTO for New England since February 1, 2005. ISO-NE works to ensure the reliability of the New England transmission system, administers the independent system operator tariff (ISO Tariff), subject to FERC approval, oversees the efficient and competitive functioning of the regional wholesale power market and determines which portion of the costs of our major transmission facilities are regionalized throughout New England.
Transmission - Wholesale Rates: Wholesale transmission revenues are based on formula rates that are approved by the FERC. Most of our wholesale transmission revenues are collected under the ISO-NE FERC Electric Tariff No. 3, Transmission, Markets and Services Tariff (Tariff No. 3). Tariff No. 3 includes RNS and LNS rate schedules to recover transmission and other services. The RNS rate, administered by ISO-NE and billed to all New England transmission users, is reset on June 1st of each year and recovers the revenue requirements associated with transmission facilities that benefit the New England region. The LNS rate, which we administer, is reset on January 1st and June 1st of each year and recovers the revenue requirements for local transmission facilities and other transmission costs not recovered under the RNS rate, including 50 percent of the CWIP that is included in rate base on the remaining three southwest Connecticut projects (Middletown-Norwalk, Glenbrook Cables and Long Island Replacement Cable). The LNS rate calculation recovers total transmission revenue requirements net of revenues received from other sources (i.e., RNS, rentals, etc.), thereby ensuring that we recover all regional and local revenue requirements as prescribed in Tariff No. 3. Both the RNS and LNS rates provide for annual true-ups to actual costs. The financial impacts of differences between actual and projected costs are
56
deferred for future recovery from or refund to retail customers. At March 31, 2008, the LNS rates were in an underrecovery position of approximately $36 million, of which $23 million will be recovered from LNS customers in mid-2008. We believe that these rates will provide us with timely recovery of transmission costs, including costs of our major transmission projects.
FERC ROE Decision: As a result of an order issued by the FERC on October 31, 2006 relating to incentives on new transmission facilities in New England (Initial ROE Order), we recorded an estimated regulatory liability for refunds in 2006. In 2007, we completed the customer refunds that were calculated in accordance with the compliance filing required by the Initial ROE Order, and refunded amounts to regional, local and localized transmission customers.
On March 24, 2008, the FERC issued an order on rehearing of its Initial ROE Order. In the rehearing order, the FERC, among other things, increased the base ROE on transmission projects for the transmission owners from the 10.2 percent allowed in the Initial ROE Order to 10.4 percent effective February 1, 2005 and reaffirmed its Initial ROE Order increasing the ROE by 74 basis points for the period beginning November 1, 2006 in recognition of higher bond yields. The rehearing order also modified the FERC's Initial ROE Order provision allowing 100 additional basis points for new transmission projects that are built as part of the ISO-NE RSP by limiting the 100 basis points adder solely to projects that are "completed and on line" by December 31, 2008. In order to receive incentives for projects completed after December 31, 2008, the rehearing order requires transmission owners to file with the FERC project-specific requests that meet the nexus requirements under FERC guidelines. In addition, while not an issue in this rehearing, the provision of the Initial ROE Order increasing the ROE by 50 additional basis points for New England transmission owners joining an RTO and giving the RTO operational control of the transmission owner’s transmission facilities was left unchanged. In the first quarter of 2008, we recognized $3.5 million in transmission segment earnings related to this order, of which approximately $2.9 million related to the February 1, 2005 through December 31, 2007 time period. Going forward, the order is expected to have a modestly positive net effect on our earnings.
The following table is a summary of the changes in the ROEs for the applicable periods and projects as a result of the rehearing order:
|
| LNS (base) |
| RNS |
| New ISO-NE Approved (1) |
RTO - February 1, 2005 to October 31, 2006 | ||||||
Initial Order |
| 10.2% |
| 10.7% (base plus 0.5% |
| 11.7% (10.7% plus 1% |
|
|
|
|
|
|
|
Rehearing Order |
| 10.4% |
| 10.9% (base plus 0.5% |
| 11.9% (10.9% plus 1% |
RTO - November 1, 2006 forward | ||||||
Initial Order |
| 10.94% (10.2% plus |
| 11.44% (base plus 0.5% |
| 12.44% (11.44% plus 1% |
Rehearing Order |
| 11.14% |
| 11.64% (base plus 0.5% |
| 12.64% (11.64% plus 1% |
(1) 100 basis points adder for new investment under RSP; limited solely to projects completed by December 31, 2008.
We expect the Middletown-Norwalk project to qualify for ROE incentives under this FERC order, and we expect to file with the FERC later this quarter. We also expect to file with the FERC for incentives on any other of our major transmission projects that are completed after December 31, 2008, including our full investment in the NEEWS Overhead projects. Assuming these projects receive the incentives, we expect the projected overall blended ROE in our transmission segment to increase to approximately 12 percent in 2008 and 2009, rising to approximately 12.1 percent in 2010 through 2013.
Regulatory Developments and Rate Matters
Connecticut - CL&P:
Distribution Rates: On January 28, 2008, the DPUC issued a final decision in a rate case CL&P filed on July 30, 2007. As a result of the decision, CL&P implemented a $77.8 million annualized distribution rate increase effective February 1, 2008 and will implement an incremental $20.1 million annualized distribution rate increase effective February 1, 2009. These increases were based on an authorized Regulatory ROE of 9.4 percent. In addition, the DPUC approved substantially all of CL&P’s requested distribution segment capital program of $294 million for 2008 and $288 million for 2009. Because the DPUC denied recovery of certain requested expenses in rates and delayed implementation of new rates until February 1, 2008, CL&P estimates that its earned distribution segment Regulatory ROE will be approximately 8 percent in calendar year 2008 and between 8 percent and 8.5 percent for the 12 months beginning February 1, 2008 when the new rates took effect.
57
Peaking Generation Filing: In 2007, Connecticut Governor Rell signed into law "An Act Concerning Electricity and Energy Efficiency" (Energy Efficiency Act). Among other provisions, the Energy Efficiency Act required electric distribution companies, including CL&P, to file proposals with the DPUC to build cost-of-service peaking generation facilities. On March 3, 2008, as required by the DPUC, CL&P filed a proposal with the DPUC to build a total of 265 MW of peaking generation, comprised of 200 MW near a major transmission substation in Lebanon, Connecticut and 65 MW near the Yankee Gas LNG facility in Waterbury, Connecticut. CL&P estimates that construction of the Lebanon and Waterbury sites would cost approximately $176 million and $80 million, respectively. The DPUC received nine other proposals to build peaking generation facilities. CL&P’s bid requests a 10.5 percent ROE and a 50 percent debt to equity capital structure. The DPUC is scheduled to issue a final ruling on all proposals, including CL&P's, on June 18, 2008. If chosen, CL&P estimates that its proposed facilities would be completed in the first half of 2010, assuming no legal or other delays.
AMI Filing: On December 19, 2007, the DPUC issued a final decision on CL&P’s compliance plan that requires a pilot program to test customer interest in, and response to, peak-time based rates and technical capabilities of an advanced metering infrastructure (AMI). CL&P customers' response to peak-time based rates is a critical element of the AMI initiative. On May 2, 2008, the DPUC approved CL&P's revised pilot plan, which provides for a summer 2009 rate pilot supported by meters for 4,000 voluntary rate pilot customers. The restriction of meters to only rate pilot participants decreased the required number of meters from 10,000 to 4,000. The rate pilot customer enrollment campaign will begin in August 2008. CL&P is required to submit a report on the customer response to the pilot, including technical capabilities of AMI meters and customer response to peak-time based rates by December 1, 2009. As a result of the reduction in the number of meters required for the pilot program, the estimated capital cost of the program has decreased from a range of $8.5 million to $11.5 million to a range of $8 million to $10 million, and the incremental operating and maintenance expenses are projected to be less than $3 million. The costs associated with the pilot are authorized to be recovered from customers, initially through CL&P’s federally mandated congestion charges (FMCC).
FMCC Filing: On February 5, 2008, CL&P filed with the DPUC its semi-annual reconciliation to document actual FMCC charges (including Energy Independence Act charges), GSC revenues and expenses and Energy Adjustment Clause (EAC) charges for the period July 1, 2007 through December 31, 2007. This filing also contained CL&P's revenue and cost information for the period January 1, 2007 through June 30, 2007, for which the DPUC previously approved all costs as filed in its final decision issued January 23, 2008. This filing identified overrecoveries totaling approximately $105 million for the full year 2007. Of this total, approximately $88 million was included in the annual CL&P rate change effective January 1, 2008, and an additional approximately $1 million was included in CL&P's Last Resort Service (LRS) rate change effective April 1, 2008. Therefore, there is a net remaining overrecovery of approximately $16 million to benefit customers in the future. The DPUC has scheduled a hearing in May 2008 on the revenues and costs contained in this filing with a final decision expected in the second half of 2008.
Standard Service and Last Resort Service Rates: CL&P's residential and small commercial customers who do not choose competitive suppliers are served under Standard Service (SS) rates, and large commercial and industrial customers who do not choose competitive suppliers are served under LRS rates. On January 1, 2008, CL&P's combined average SS and LRS rates decreased approximately 1.1 percent and will remain in effect until July 1, 2008, in the case of the SS rate. On April 1, 2008, CL&P's average LRS rate decreased approximately 6.4 percent and will remain in effect until July 1, 2008. CL&P is fully and timely recovering the costs of its SS and LRS services.
Customer Service Docket: On February 27, 2008, the DPUC issued a final decision in a docket examining the manner of operation and accuracy of CL&P's electric meters. While finding that the meters generally operated within industry standards, the DPUC imposed significant new testing, analytical and reporting requirements on CL&P. The DPUC also found that CL&P failed to be responsive to customer complaints by refusing meter tests or not allowing customers to speak with supervisors. The decision acknowledges recent corrective actions taken by CL&P but requires changes in numerous CL&P customer service practices. The decision also places substantial new tracking and reporting obligations on CL&P. The DPUC did not fine CL&P but the decision holds that possibility open if CL&P fails to meet benchmarks to be established in this docket.
New Hampshire:
Delivery Service and TCAM Rate Increases: On January 1, 2008, PSNH’s distribution rates increased by approximately $3 million annually, pursuant to the New Hampshire Public Utilities Commission's (NHPUC) May 2007 approval of PSNH’s distribution and transmission rate case settlement agreement with the NHPUC staff and the New Hampshire Office of Consumer Advocate. The settlement agreement also included a distribution rate decrease effective on July 1, 2008 of approximately $9 million related to the recovery end date for certain recoupment underrecoveries incurred by PSNH while the rate case was pending. On April 30, 2008, PSNH filed with the NHPUC a proposal to increase distribution rates effective July 1, 2008 by approximately $3 million associated with additional deferred major storm reserve costs. In addition, PSNH plans to file for a July 1, 2008 increase to the transmission cost adjustment mechanism (TCAM) in May 2008. The TCAM and storm proposals will more than offset the $9 million recoupment decrease.
58
ES and SCRC Rates: On April 21, 2008, PSNH filed two petitions with the NHPUC requesting a change in its default energy service (ES) rate and the stranded cost recovery charge (SCRC) for the period July 1, 2008 through December 31, 2008. Consistent with previous filings, PSNH will update these filings for ES and SCRC in early June 2008 to reflect the most current energy market data.
Renewable Portfolio Standards: On May 11, 2007, New Hampshire Governor Lynch signed into law the "Renewable Energy Act," establishing renewable portfolio standards (RPS) requiring that 23.8 percent of the electricity sold to New Hampshire retail customers have direct ties to renewable sources. The renewable sourcing requirements begin in 2008 and increase each year to reach 23.8 percent by 2025.
PSNH plans to meet these standards, in part, through the purchase of renewable energy certificates (RECs) from a qualified renewable energy resource. For each MWH of energy produced from a qualifying renewable resource, the producer will receive one REC. Energy suppliers, like PSNH, will purchase these RECs from the producers and will use them to satisfy the RPS requirements. To the extent that PSNH is unable to purchase sufficient RECs, it will be required to make up the difference between the RECs purchased and its total obligation by making an alternative compliance payment (ACP) for each REC for which PSNH is deficient. The costs of both the RECs and ACPs will not directly impact earnings, as these costs will be recovered by PSNH through its ES rates.
Massachusetts:
Distribution Rate Increase: On January 1, 2008, WMECO’s distribution rates increased by $3 million annually as approved by the Massachusetts Department of Public Utilities (DPU) in December 2006. WMECO adjusted its rates to include the distribution increase, new basic service contracts, and changes in several tracking mechanisms.
Contingent Matters:
The items summarized below contain contingencies that may have an impact on our net income, financial position or cash flows. See Note 5A, "Commitments and Contingencies - Regulatory Developments and Rate Matters," to the condensed consolidated financial statements for further information regarding these matters.
·
CTA and SBC Reconciliation: On March 31, 2008, CL&P filed with the DPUC its 2007 Competitive Transition Assessment (CTA) and System Benefits Charge (SBC) reconciliation, which compared CTA and SBC revenues to revenue requirements. For the 12 months ended December 31, 2007, total CTA revenues exceeded CTA revenue requirements by $26.1 million, which has been recorded as a decrease to the CTA regulatory asset on the accompanying condensed consolidated balance sheets. For the 12 months ended December 31, 2007, the SBC cost of service exceeded SBC revenues by $39.4 million, which has been recorded as a regulatory asset on the accompanying condensed consolidated balance sheets. We expect a decision on this docket from the DPUC by the end of 2008.
·
Procurement Fee Rate Proceedings: CL&P submitted to the DPUC its proposed methodology to calculate the variable incentive portion of its procurement fee, which was effective through 2006, and requested approval of the pre-tax $5.8 million 2004 incentive fee. We have not recorded amounts related to the 2005 or 2006 procurement fee in earnings, although we estimate that if CL&P’s methodology is upheld, CL&P would record in 2008 after-tax amounts of $3.3 million for 2006 and $3.6 million for 2005.
We have recovered the $5.8 million pre-tax amount, which was recorded in 2005 earnings through the CTA reconciliation process. If the DPUC does not allow recovery of $5.8 million for procurement fees in its final decision, then CL&P would record a loss and establish an obligation to refund this amount to its customers. A date for the new draft decision in this docket has not yet been determined by the DPUC.
·
Purchased Gas Adjustment: In 2005 and 2006, the DPUC issued decisions regarding Yankee Gas’s Purchased Gas Adjustment (PGA) clause charges and required an audit of approximately $11 million in previously recovered PGA revenues associated with unbilled sales and revenue adjustments for the period of September 1, 2003 through August 31, 2005. The audit has concluded, and a final report has been submitted. A DPUC hearing was held on October 9, 2007. There is currently no final schedule in this case. We believe the unbilled sales and revenue adjustments and resulting charges to customers through the PGA clause for this period were appropriate and that the appropriateness of the PGA charges to customers for the time period under review will be approved.
·
SCRC/ES Reconciliation: On May 1, 2008, PSNH filed its 2007 SCRC/ES reconciliation with the NHPUC. We do not expect the outcome of the NHPUC's review of this filing to have a material adverse impact on PSNH's net income, financial position or cash flows.
59
·
Transition Cost Reconciliations: WMECO filed its 2005 transition cost reconciliation with the DPU on March 31, 2006 and filed its 2006 transition cost reconciliation with the DPU on March 31, 2007. The DPU opened a proceeding for these filings and evidentiary hearings were held on August 29, 2007. The briefing process was completed during October 2007. The timing of the decision in this docket is uncertain. We do not expect the outcome of the DPU's review of these filings to have a material adverse effect on WMECO's net income, financial position or cash flows. On March 13, 2008, WMECO requested that the DPU delay the 2007 transition cost reconciliation filing date until 30 days after an order is received on the 2006 and 2005 filings. The DPU granted WMECO’s request on March 21, 2008.
NU Enterprises Divestitures
We have exited most of our competitive businesses. NU Enterprises continues to manage to completion its remaining wholesale marketing contracts and energy services activities.
Wholesale Marketing: In the first quarter of 2008, Select Energy continued to manage its remaining PJM power pool wholesale sales contract, which will expire on May 31, 2008, and a long-term contract with the New York Municipal Power Agency (NYMPA), which will expire in 2013. The NYMPA and PJM contracts, as well as the related supply contracts, are derivatives that have been marked to market through earnings and had a negative fair value of $81.1 million as of March 31, 2008. In addition to the PJM and NYMPA contracts, Select Energy's only other long-term wholesale obligation is a non-derivative contract to purchase the output of a certain generating facility in New England through 2012. As a non-derivative contract, the fair value of the contract has not been reflected on the balance sheet, and the contract has not been marked to market. Based on the current estimated value of this non-derivative contract, when combined with the fair value of the derivative contracts at March 31, 2008, we believe, under present conditions, that the estimated total net cash cost at March 31, 2008 to exit the remaining wholesale contracts if served out or settled at the same time is approximately break-even.
Energy Services: Most of NU Enterprises' energy services businesses were sold in 2005 and 2006. Certain other businesses were wound down in 2007. We continue to own and manage E.S. Boulos Company.
In connection with the sale of the retail marketing business, the competitive generation business and certain of the energy services businesses, we provided various guarantees and indemnifications to the purchasers of those businesses. See Note 5F, "Commitments and Contingencies - Guarantees and Indemnifications," to the condensed consolidated financial statements for information regarding these items.
NU Enterprises Contracts
Wholesale Derivative Contracts: On January 1, 2008, we implemented SFAS No. 157. For further information on SFAS No. 157, see Note 1C, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 3, "Fair Value Measurements," to the condensed consolidated financial statements, and the "Critical Accounting Policies and Estimates Update" section of this Management’s Discussion and Analysis.
At March 31, 2008 and December 31, 2007, the fair value of NU Enterprises' wholesale derivative assets and derivative liabilities (through its subsidiary Select Energy), which are subject to mark-to-market accounting, are as follows:
(Millions of Dollars) |
| March 31, 2008 |
| December 31, 2007 | ||
Current wholesale derivative assets |
| $ | 24.8 |
| $ | 36.2 |
Long-term wholesale derivative assets |
|
| 12.1 |
|
| 7.2 |
Current wholesale derivative liabilities |
|
| (44.1) |
|
| (64.9) |
Long-term wholesale derivative liabilities |
|
| (73.9) |
|
| (72.5) |
Portfolio position |
| $ | (81.1) |
| $ | (94.0) |
Numerous factors could either positively or negatively affect the realization of the wholesale derivative net fair value amounts in cash. These factors include the volatility of commodity prices until the derivative contracts are exited or expire, differences between expected and actual volumes, the performance of counterparties, and other factors.
Select Energy has policies and procedures requiring all of its wholesale derivative energy positions to be valued daily and segregating responsibilities between the individuals actually transacting (front office) and those confirming the trades (middle office). The middle office is responsible for determining the portfolio's fair value independent from the front office.
The methods Select Energy used to determine the fair value of its wholesale derivative contracts are identified and segregated in the table of fair value of wholesale derivative contracts at March 31, 2008 and December 31, 2007. A description of each method is as follows: 1) prices actively quoted primarily represent New York Mercantile Exchange futures and swaps that are marked to closing
60
exchange prices; and 2) prices provided by external sources primarily include over-the-counter forwards and options, including bilateral contracts for the purchase or sale of electricity, and are marked to the mid-point of bid and ask market prices. The mid-points of market prices are adjusted to include all applicable market information, such as prior contract settlements with third parties. Currently, Select Energy also has a derivative contract for which a portion of the contract's fair value is determined based on a model. The model utilizes natural gas prices and a conversion factor to electricity for off-peak periods in 2012 and all periods for 2013. Broker quotes for electricity at locations for which Select Energy has entered into transactions are generally available through the year 2011 and for 2012 on-peak periods.
Generally, valuations of short-term derivative contracts derived from quotes or other external sources are more reliable should there be a need to liquidate the contracts, while valuations for longer-term derivative contracts are less certain. Accordingly, there is a risk that derivative contracts will not be realized at the amounts recorded.
The tables below disaggregate the estimated fair value of the wholesale derivative contracts. Valuations of individual contracts are broken into their component parts based upon prices actively quoted, prices provided by external sources and model-based amounts. Under SFAS No. 157, contracts are classified in their entirety according to the lowest level for which there is at least one input that is significant to the valuation. Therefore, these contracts are classified as Level 3 under SFAS No. 157. At March 31, 2008 and December 31, 2007, the sources of the fair value of wholesale derivative contracts are included in the following tables:
|
| Fair Value of Wholesale Contracts at March 31, 2008 | ||||||||||
(Millions of Dollars) |
| Maturity Less |
| Maturity of One |
| Maturity in |
|
| ||||
Prices actively quoted |
| $ | 0.1 |
| $ | 4.3 |
| $ | 0.5 |
| $ | 4.9 |
Prices provided by external sources |
|
| (18.1) |
|
| (39.2) |
|
| (8.3) |
|
| (65.6) |
Model-based (1) |
|
| (1.3) |
|
| (3.3) |
|
| (15.8) |
|
| (20.4) |
Totals |
| $ | (19.3) |
| $ | (38.2) |
| $ | (23.6) |
| $ | (81.1) |
|
| Fair Value of Wholesale Contracts at December 31, 2007 | ||||||||||
(Millions of Dollars) |
| Maturity Less |
| Maturity of One |
| Maturity in |
|
| ||||
Prices actively quoted |
| $ | (4.7) |
| $ | (0.2) |
| $ | 1.4 |
| $ | (3.5) |
Prices provided by external sources |
|
| (24.0) |
|
| (38.8) |
|
| (13.4) |
|
| (76.2) |
Model-based |
|
| - |
|
| 4.3 |
|
| (18.6) |
|
| (14.3) |
Totals |
| $ | (28.7) |
| $ | (34.7) |
| $ | (30.6) |
| $ | (94.0) |
(1) The model-based amounts include the effects of implementing SFAS No. 157.
For the three months ended March 31, 2008, the changes in fair value of these contracts are included in the following table:
|
| For the Three Months Ended |
| |
(Millions of Dollars) |
| Total Portfolio Fair Value |
| |
|
|
|
|
|
Fair value of wholesale contracts outstanding at the beginning of the period |
| $ | (94.0) |
|
Pre-tax effects of implementing SFAS No. 157 ($3.7 million after-tax) (1) |
|
| (6.1) |
|
Contracts realized or otherwise settled during the period (2) |
|
| 18.2 |
|
Quarterly change in unrealized gains/(losses) included in earnings |
|
| 0.8 |
|
Fair value of wholesale contracts outstanding at the end of the period |
| $ | (81.1) |
|
(1)
Pre-tax effect recorded in fuel, purchased and net interchange power on the accompanying condensed consolidated statement of income.
(2)
Amount includes purchases, issuances and settlements of $15.3 million and realized changes in fair value of $2.9 million.
For further information regarding Select Energy's derivative contracts, see Note 2, "Derivative Instruments," to the condensed consolidated financial statements.
Counterparty Credit: Counterparty credit risk relates to the risk of loss that Select Energy would incur because of non-performance by counterparties pursuant to the terms of their contractual obligations. Select Energy has established credit policies with regard to its counterparties to minimize overall credit risk. These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash advances, LOCs, and parent guarantees), and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in Select Energy establishing credit limits prior to entering into contracts. The
61
appropriateness of these limits is subject to our continuing review. Concentrations among these counterparties may affect Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions. At March 31, 2008, Select Energy's counterparty credit exposure to wholesale and trading counterparties of approximately one percent was collateralized, approximately 11 percent was rated BBB- or better and approximately 88 percent was non-rated. The composition of Select Energy's credit portfolio has shifted from being largely investment grade-rated to being mostly non-rated. This is largely due to the exit from the New England wholesale and retail portfolios and the expiration of PJM obligations. The bulk of the non-rated credit exposure is comprised of one counterparty, which is a non-rated public entity that we believe to be creditworthy.
Critical Accounting Policies and Estimates Update
The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and at times difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial statements. Our management communicates to and discusses with our Audit Committee of the Board of Trustees all critical accounting policies and estimates. All of these critical accounting policies and estimates were reported in the 2007 Form 10-K. There have been no material changes with regard to these critical accounting policies and estimates, except as follows:
Fair Value Measurements: We adopted SFAS No. 157 as of January 1, 2008. SFAS No. 157 defines fair value as the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). It establishes a framework for measuring fair value, using a three level hierarchy based upon the observability of inputs to the valuations. See Note 1C, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 3, "Fair Value Measurements," to the accompanying condensed consolidated financial statements for further information.
As of January 1, 2008, we applied SFAS No. 157 to our regulated and unregulated companies’ derivative contracts that are recorded at fair value and to the marketable securities held in NU’s Rabbi Trust and WMECO’s prior spent nuclear fuel trust. SFAS No. 157 also applies to investment valuations for our pension and other postretirement benefit plans beginning as of December 31, 2008, and beginning in 2009, to nonrecurring fair value measurements of non-financial assets and liabilities, such as goodwill and asset retirement obligations. Implementing SFAS No. 157 for our marketable securities expanded our financial statement disclosures, but did not affect the recorded fair value of investments.
In the first quarter of 2008, we recorded an after-tax reduction of earnings of $3 million as a result of applying SFAS No. 157 to derivative liabilities for Select Energy’s remaining wholesale marketing contracts, net of a $0.7 million benefit from partially reversing the implementation charge as we served rather than exited these contracts in the first quarter.
As a result of implementing SFAS No. 157, we also recorded changes in fair value of certain derivative contracts of CL&P. Because CL&P is a cost-of-service, rate regulated entity, the cost or benefit of the contracts is expected to be fully recovered from or refunded to CL&P's customers and an offsetting regulatory asset or liability was recorded to reflect these changes. SFAS No. 157 resulted in a total increase to CL&P's derivative liabilities, with an offset to regulatory assets of approximately $590 million and a total decrease to derivative assets, with an offset to regulatory liabilities, of approximately $30 million. The increase to CL&P's derivative liabilities primarily resulted from an increase in the negative fair value of a contract for differences with a generating plant to be built to reflect the estimated cost to exit this contract, reflecting an increase in the probability that the plant will be built and the recognition of a loss at the inception of the contract of approximately $100 million that was deferred under previous accounting guidance.
If we do not exit but rather serve out our derivative contracts, we will not realize portions of their recorded fair value in cash.
We use quoted market prices when available to determine fair values of financial instruments and classify those valuations as Level 1 within the fair value hierarchy. If quoted market prices are not available, fair value is determined using quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments that are not active and model-derived valuations in which all significant inputs are observable. These valuations are classified as Level 2 within the fair value hierarchy.
Many of our derivative contracts that are recorded at fair value are classified as Level 3 within the hierarchy and are valued using models that incorporate both observable and unobservable inputs. Fair value is modeled using techniques such as discounted cash flow approaches adjusted for assumptions relating to exit price and the Black-Scholes option pricing model, incorporating the terms of the contracts. Significant unobservable inputs utilized in the valuations include energy and energy-related product prices for future years for long-dated derivative contracts, future contract quantities under full requirements and supplemental sales contracts, and market volatilities. Discounted cash flow valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using available historical market transaction information. Valuations of derivative contracts also reflect nonperformance risk, including credit risk. Contracts valued using models are classified according to the lowest
62
level for which there is at least one input that is significant to the valuation. Therefore, an item may be classified as Level 3 even though there may be some significant inputs that are readily observable.
Total Level 3 assets were 72 percent of our total assets measured at fair value, and Level 3 liabilities were 98 percent of our total liabilities measured at fair value at March 31, 2008. A significant portion of our Level 3 liabilities relate to the regulated company derivative contracts for which changes in fair value do not affect our results of operations due to our use of regulatory accounting. Changes in fair value of these contracts are not material to our liquidity or capital resources because the costs and benefits of the contracts are recoverable from or refundable to customers on a timely basis.
We review and update our fair value hierarchy classifications on a quarterly basis. As of March 31, 2008, investment securities are classified in Levels 1 and 2. Classifications of an investment security or group of investment securities into Level 3 may occur if a significant amount of inputs to their valuation is no longer observable due to a decline in market activity or liquidity.
Changes in fair value of the remaining wholesale marketing contracts of our unregulated businesses are recorded in fuel, purchased and net interchange power on the accompanying condensed consolidated statements of income. For the three months ended March 31, 2008, there were net realized and unrealized gains of $2.2 million ($3.7 million pre-tax) related to the valuation of these contracts. Key drivers of variability in fair values include changes in energy prices and expected volumes under the contracts.
Changes in fair value of the regulated company derivative contracts are recorded as regulatory assets or liabilities, as we expect to recover these costs in rates. These valuations are sensitive to the prices of energy and energy related products in future years for which markets have not yet developed. Assumptions made to implement SFAS No. 157 had a significant effect on derivative values, and changes in assumptions may continue to have significant effects.
For further information on derivative contracts, see Note 2, "Derivative Instruments," to the condensed consolidated financial statements.
Accounting for Environmental Reserves: Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Adjustments made to environmental reserves could have a significant effect on earnings. Our approach estimates these liabilities based on the most likely action plan from a variety of available remediation options, ranging from no action to remedies ranging from establishing institutional controls to full site remediation and long-term monitoring. The estimates associated with each possible action plan are based on findings through various phases of site assessments.
These estimates are based on currently available information from presently enacted state and federal environmental laws and regulations and several cost estimates from third-party engineering and remediation contractors who would be performing the work. These estimates also take into consideration prior experience in remediating contaminated sites and data released by the United States Environmental Protection Agency and other organizations. These estimates are subjective in nature partly because there are usually several different remediation options from which to choose when working on a specific site. These estimates are subject to revisions in future periods based on actual costs or new information concerning either the level of contamination at the site or newly enacted laws and regulations. The amounts recorded as environmental liabilities on the condensed consolidated balance sheets represent our best estimate of the liability for environmental costs based on current site information from site assessments and remediation estimates. These liabilities are estimated on an undiscounted basis.
Holyoke Water Power Company (HWP) is a subsidiary of NU that owns a minimal amount of transmission property and has limited operating activities. HWP continues to evaluate additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with a manufactured gas plant which it sold to Holyoke Gas and Electric (HG&E), a municipal electric utility, in 1902. HWP is at least partially responsible for this site, and substantial remediation activities at this site have already been conducted. HWP first established a reserve for this site in 1994. The cumulative expense recorded to this reserve was approximately $13 million, of which $12.5 million had been spent, leaving approximately $0.5 million in the reserve as of March 31, 2008. HWP's reserve is based on its most recent site and proposed risk assessment, which occurred in 2007.
The Massachusetts Department of Environmental Protection (MA DEP) issued an approval letter on April 3, 2008 to HWP and HG&E, an unaffiliated entity which shares responsibility for the site, authorizing, subject to certain conditions, additional investigatory and risk characterization activities and providing detailed comments on HWP’s 2007 proposed risk assessment. MA DEP also indicated that further remediation of certain upstream "soft" tar areas was required prior to commencing many of the additional studies and evaluation. MA DEP’s authorization, approval conditions and additional tar remediation requirements, including estimable costs and schedules, are currently being evaluated by HWP. A response to MA DEP is required by June 2, 2008, which we believe will be extended by the MA DEP. These matters are also subject to ongoing discussions with MA DEP and HG&E and may change from time to time.
63
At this time, we believe that the $0.5 million remaining in the reserve is the low end of a range of probable costs and that the $0.5 million will be sufficient for HWP to evaluate its approach to this matter. Since we have recorded the low end of the range of probable cost, there are many possible outcomes that would require an increase to the reserve, which will be reflected as a charge to pre-tax earnings. However, we cannot reasonably estimate the range of investigation and remediation costs because they will depend on, among other things, the level and extent of the remaining tar required to be removed, the extent of HWP’s responsibility and the related scope and timing, all of which are difficult to estimate because of a number of uncertainties at this time. Developments in this matter may require a material increase to the reserve.
HWP's share of the remediation costs related to this site is not recoverable from ratepayers. There were no changes to the environmental reserve for this site in the first quarter of 2008.
Other Matters
Consolidated Edison, Inc. Merger Litigation:
On March 13, 2008, we entered into a settlement agreement with Con Edison which settled all claims under the civil lawsuit between both parties relating to the proposed but unconsummated merger. Under the terms of the settlement agreement, we paid Con Edison $49.5 million on March 26, 2008. This amount is not recoverable from ratepayers. For more information about the Con Edison litigation, please refer to "Item 3 - Legal Proceedings" of our Annual Report on Form 10-K for the year ended December 31, 2007.
For further information regarding other commitments and contingencies, see Note 5, "Commitments and Contingencies," to the condensed consolidated financial statements.
Forward Looking Statements: This discussion and analysis includes statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, financial performance or growth and other statements that are not historical facts. These statements are "forward looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can generally identify these "forward looking statements" through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and similar expressions. Forward looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in the forward looking statements. Factors that may cause actual results to differ materially from those included in the forward looking statements include, but are not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, changes in levels or timing of capital expenditures, developments in legal or public policy doctrines, technological developments, changes in accounting standards and financial reporting regulations, fluctuations in the value of our remaining competitive electricity positions, actions of rating agencies, and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports filed with the Securities and Exchange Commission. We undertake no obligation to update the information contained in any forward looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events.
Web Site: Additional financial information is available through our web site at www.nu.com.
64
RESULTS OF OPERATIONS - NU CONSOLIDATED
The following table provides the variances in income statement line items for the condensed consolidated statements of income for NU included in this report on Form 10-Q for the three months ended March 31, 2008:
| Income Statement Variances | |||||
| Amount |
| Percent | |||
Operating Revenues: | $ | (183) |
| (11) | % | |
|
|
|
|
|
| |
Operating Expenses: |
|
|
|
|
| |
Fuel, purchased and net interchange power |
| (247) |
| (23) |
| |
Other operation |
| 49 |
| 21 |
| |
Maintenance |
| 11 |
| 23 |
| |
Depreciation |
| 4 |
| 7 |
| |
Amortization |
| 23 |
| (a) |
| |
Amortization of rate reduction bonds |
| 1 |
| 3 |
| |
Taxes other than income taxes |
| (1) |
| (1) |
| |
Total operating expenses |
| (160) |
| (10) |
| |
|
|
|
|
|
| |
Operating Income |
| (23) |
| (15) |
| |
|
|
|
|
|
| |
Interest expense, net |
| 3 |
| 6 |
| |
Other income, net |
| (1) |
| (4) |
| |
Income/(loss) from continuing operations before income tax |
| (27) |
| (25) |
| |
Income tax expense/(benefit) |
| (9) |
| (28) |
| |
Preferred dividends of subsidiary |
| - |
| - |
| |
Income/(loss) from continuing operations |
| (18) |
| (24) |
| |
Income/(loss) from discontinued operations |
| 1 |
| 100 |
| |
Net Income/(Loss) | $ | (17) |
| (22) | % | |
(a) Percent greater than 100.
Comparison of the First Quarter of 2008 to the First Quarter of 2007
Net income was $17 million lower in the first quarter of 2008 primarily due to a $29.8 million after-tax charge associated with the settlement of litigation with Con Edison.
Operating Revenues
Operating revenues decreased $183 million in 2008 primarily due to lower revenues from the regulated companies ($144 million) and lower revenues from NU Enterprises ($39 million). NU Enterprises’ revenues decreased $39 million due to the exit from components of the competitive businesses. The lower regulated revenues were primarily due to the recovery of a lower level of CL&P distribution related expenses passed through to customers through regulatory tracking mechanisms.
Revenues from the regulated companies decreased $144 million due to lower distribution segment revenues ($168 million), partially offset by higher transmission segment revenues ($24 million). Distribution segment revenues decreased $168 million primarily due to lower electric distribution revenues ($182 million), partially offset by higher gas distribution revenues ($15 million). Transmission segment revenues increased $24 million primarily due to a higher transmission investment base, the impact of the March 24, 2008 FERC ROE decision and higher operating expenses which are recovered under FERC-approved transmission tariffs.
Lower electric distribution revenues include the components of CL&P, PSNH and WMECO retail revenues which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($203 million). The distribution revenue tracking components decrease of $203 million was primarily due to the pass-through of lower energy supply costs ($152 million), lower CL&P revenue associated with the recovery of delivery-related FMCC ($33 million), a decrease in PSNH’s SCRC revenues mainly as a result of a rate decrease effective for 2008 ($12 million) and lower WMECO pension and default service revenues ($4 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.
65
The distribution component of electric distribution segment revenues which flows through to earnings increased $20 million primarily due to increases in retail rates at each of the regulated companies ($26 million), partially offset by lower retail electric sales ($3 million). Retail electric sales decreased by 1.8 percent in 2008 compared with 2007 (a 1.2 percent decrease on a weather normalized basis). Firm gas sales decreased 4.9 percent in 2008 compared with 2007 (a 1.5 percent decrease on a weather normalized basis).
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expenses decreased $247 million in 2008 due to lower costs at the regulated companies ($203 million) and lower expenses at NU Enterprises ($44 million). Fuel expense from the regulated companies decreased primarily due to lower fuel, purchased and net interchange power expenses at CL&P and WMECO ($205 million), mainly due to a decrease in standard offer supply costs as a result of a reduction in load caused by customer migration to third party suppliers, partially offset by higher Yankee Gas fuel expense ($2 million). NU Enterprises' fuel expenses decreased due to the exit from significant components of the competitive businesses.
Other Operation
Other operation expenses increased $49 million in 2008 primarily due to the $49.5 million payment to Con Edison resulting from the settlement of litigation.
Maintenance
Maintenance expenses increased $11 million in 2008 primarily due to higher regulated company distribution expenses, mainly as a result of higher overhead line maintenance expenses due to more storm-related expenses ($6 million), tree trimming expenses ($3 million) and underground line expenses ($1 million).
Depreciation
Depreciation increased $4 million in 2008 primarily due to higher distribution and transmission depreciation expense as a result of higher plant balances from the ongoing construction program.
Amortization
Amortization increased $23 million in 2008 for the distribution segment primarily due to higher amortization at CL&P ($20 million). The higher CL&P amortization expense is primarily due to a credit in 2007 pertaining to the amortization of the GSC provision for rate refunds ($7 million), higher amortization of SBC ($8 million) and a higher recovery of transition costs ($4 million).
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased $1 million in 2008. The higher portion of principal within the rate reduction bonds payment resulted in a corresponding increase in the amortization of rate reduction bonds. This increase was partially offset by a decrease at PSNH resulting from the repayment of $50 million of rate reduction bonds in January 2008.
Taxes Other than Income Taxes
Taxes other than income taxes decreased $1 million in 2008 primarily due to lower sales and payroll taxes ($2 million), partially offset by higher property taxes ($1 million).
Interest Expense, Net
Interest expense, net, increased $3 million in 2008 primarily due to higher long-term debt interest at CL&P resulting from the $300 million new debt issuance in March 2007 ($4 million) and the $200 million new debt issuance in September 2007 ($3 million), partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($3 million) and lower FMCC deferral interest ($1 million).
Other Income, Net
Other income, net, decreased $1 million in 2008 primarily due to lower investment income ($9 million) resulting from a significantly lower level of cash at NU parent in 2008 due to increased equity investments in NU's utility subsidiaries, partially offset by higher AFUDC equity ($6 million) mainly as a result of higher eligible construction work in progress (CWIP) and lower short-term debt, resulting in an increase in the CWIP financed by permanent capital, and higher CL&P Energy Independence Act incentives ($3 million).
66
Income Tax Expense/(Benefit)
Income tax expense decreased $9 million; $23 million from NU parent and other companies, including $19.7 million from the Con Edison settlement and $3 million from other pre-tax expense increases, partially offset by pre-tax earnings related tax expense increases at CL&P ($6 million), PSNH ($4 million) and Yankee Gas ($4 million).
67
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of
Financial Condition and Results of Operations
CL&P is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's Management's Discussion and Analysis of Financial Condition and Results of Operations, condensed consolidated financial statements and footnotes in this Form 10-Q, and the NU 2007 Form 10-K.
RESULTS OF OPERATIONS
The following table provides the variances in income statement line items for the condensed consolidated statements of income for CL&P included in this report on Form 10-Q for the three months ended March 31, 2008:
| Income Statement Variances | |||||
| Amount |
| Percent | |||
Operating Revenues: | $ | (158) |
| (15) | % | |
|
|
|
|
|
| |
Operating Expenses: |
|
|
|
|
| |
Operation - Fuel, purchased and net interchange power |
| (195) |
| (28) |
| |
Other operation |
| (5) |
| (3) |
| |
Maintenance |
| 8 |
| 37 |
| |
Depreciation |
| 1 |
| 2 |
| |
Amortization of regulatory assets/(liabilities), net |
| 20 |
| (a) |
| |
Amortization of rate reduction bonds |
| 2 |
| 7 |
| |
Taxes other than income taxes |
| - |
| - |
| |
Total operating expenses |
| (169) |
| (18) |
| |
Operating Income |
| 11 |
| 14 |
| |
Interest expense, net |
| - |
| - |
| |
Other income, net |
| 6 |
| (a) |
| |
Income before income tax expense |
| 17 |
| 35 |
| |
Income tax expense |
| 6 |
| 41 |
| |
Net Income | $ | 11 |
| 32 | % | |
(a) Percent greater than 100.
Comparison of the First Quarter of 2008 to the First Quarter of 2007
Operating Revenues
Operating revenues decreased $158 million in 2008 due to lower distribution segment revenues ($179 million), partially offset by higher transmission segment revenues ($21 million).
The distribution segment revenues decreased $179 million primarily due to the components of revenues, which are included in DPUC approved tracking mechanisms that track the recovery of certain incurred costs ($192 million). The distribution segment revenue tracking components decreased $192 million primarily due to a decrease in revenues associated with the recovery of generation service and related congestion charges ($153 million) and lower delivery-related FMCC revenue ($33 million). The lower generation service and related congestion charge revenue was primarily due to a reduction in load caused primarily by customer migration to third party suppliers as well as lower congestion costs in 2008. The lower delivery-related FMCC revenue was primarily due to a decrease in this rate component in 2008 as a result of lower reliability must run (RMR), VAR support and southwest Connecticut energy resource costs in 2008. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.
The distribution component of revenues which impacts earnings increased $13 million as a result of the rate increases effective January 1, 2007 and February 1, 2008, partially offset by lower retail sales. Retail sales decreased 2.3 percent in 2008 compared to the same period in 2007.
68
Transmission segment revenues increased $21 million primarily due to a higher transmission investment base, the impact of the March 24, 2008 FERC ROE decision and higher operating expenses which are recovered under FERC-approved transmission tariffs.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $195 million primarily due to a decrease in generation service supply costs ($141 million), a decrease in deferred fuel costs ($47 million) and lower other purchased power costs ($7 million) all of which are included in DPUC approved tracking mechanisms. The $141 million decrease in supply costs was primarily due to a reduction in load caused primarily by customer migration to third party suppliers. These supply costs are the contractual amounts the company must pay to various suppliers that have earned the right to supply SS and LRS load through a competitive solicitation process. The $47 million decrease in deferred fuel costs was primarily due to the combined effect of CL&P having a delivery-related FMCC overrecovery in the first quarter of 2007 and a delivery-related FMCC underrecovery in the first quarter of 2008.
Other Operation
Other operation expenses decreased $5 million primarily due to lower distribution segment expenses relating to transmission ($14 million), partially offset by higher Energy Independence Act (EIA) expenses which will be recovered through the FMCC deferral mechanism ($4 million), Summer Saver Rewards Program which was implemented in 2007 as a result of a legislative act which will be recovered through the SBC deferral mechanism ($3 million) and RMR costs ($2 million) which is tracked and recovered through the FMCC.
Maintenance
Maintenance expenses increased $8 million in 2008 primarily due to higher distribution segment expenses related to overhead lines primarily due to more storms in the first quarter of 2008 compared to 2007 ($4 million) and tree trimming expenses ($2 million).
Depreciation
Depreciation expense increased $1 million primarily due to higher utility plant balances resulting from the ongoing construction program.
Amortization of Regulatory Assets/(Liabilities), Net
Amortization of regulatory assets/(liabilities), net increased $20 million primarily due to a credit in 2007 pertaining to the amortization of the GSC provision of rate refunds ($7 million), higher amortization of SBC ($8 million) and a higher recovery of transition costs ($4 million).
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased $2 million. The higher portion of principal within the rate reduction bonds’ payment results in a corresponding increase in the amortization of regulatory assets.
Interest Expense, Net
Interest expense, net had no variance as the higher interest on long-term debt ($7 million) mainly resulting from the $300 million of new debt issued in March 2007 and $200 million of new debt issued in September 2007 was offset by lower interest on debt due to associated companies ($3 million), lower rate reduction bond interest resulting from lower principal balances outstanding ($2 million), lower FMCC deferral interest ($1 million) and lower debt AFUDC ($1 million).
Other Income, Net
Other income, net increased $6 million primarily due to higher equity AFUDC income ($5 million) as a result of higher eligible CWIP due to the transmission construction program and lower short term debt resulting in an increase in CWIP financed by equity, higher EIA incentives ($3 million), partially offset by an investment loss in 2008 ($2 million).
Income Tax Expense
Income tax expense increased $6 million due primarily to higher pre-tax earnings being subject to tax at marginal rates.
69
LIQUIDITY
CL&P had positive consolidated operating cash flows of $47.8 million, including rate reduction bond payments of $44.5 million, in the first quarter of 2008, compared with negative operating cash flows of $222.1 million, including rate reduction bond payments of $77.8 million, in the first quarter of 2007. The improvement in 2008 operating cash flows was primarily due to the payment of $177.2 million in federal and state income taxes in the first quarter of 2007, which was a result of the 2006 sale of our competitive generation business, as well as net proceeds of $80 million from the sale of CL&P accounts receivable and unbilled revenues in the first quarter of 2008. These increases to 2008 operating cash flows were partially offset by $85.9 million in regulatory underrecoveries and refunds to customers primarily related to GSC and FMCC charges and an abnormal increase in accounts receivable and unbilled revenues from December 31, 2007, due to temporary difficulties in issuing billings to a limited number of customers on a timely basis, which is expected to turn around over the remainder of the year. We project consolidated operating cash flows at CL&P of approximately $300 million to $350 million in 2008, net of approximately $170 million of payments to retire CL&P's rate reduction bonds.
Cash capital expenditures included on the accompanying condensed consolidated statements of cash flows do not include amounts incurred but not paid, cost of removal, the AFUDC related to equity funds, and the capitalized portion of pension expense or income. CL&P’s first quarter 2008 cash capital expenditures were $197 million, compared with $158.6 million in the first quarter of 2007. This increase was primarily the result of higher transmission capital expenditures.
As of March 31, 2008, CL&P had $150 million of borrowings outstanding under the $400 million credit facility it shares with other NU subsidiaries. In addition, CL&P has an arrangement with CRC and a financial institution under which the financial institution can purchase up to $100 million of CL&P's accounts receivable and unbilled revenues. Receivables totaling $100 million were sold under that facility at March 31, 2008. Other financing activities for the first quarter of 2008 included a capital contribution from NU parent of $57.1 million, which was partially offset by $26.6 million in common dividends paid to NU parent.
70
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
PSNH is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, condensed consolidated financial statements and footnotes in this Form 10-Q and the NU 2007 Form 10-K.
RESULTS OF OPERATIONS
The following table provides the variances in income statement line items for the condensed consolidated statements of income for PSNH included in this report on Form 10-Q for the three months ended March 31, 2008:
| Income Statement Variances | |||||
| Amount |
| Percent | |||
Operating Revenues: | $ | 15 |
| 5 | % | |
|
|
|
|
|
| |
Operating Expenses: |
|
|
|
|
| |
Operation - Fuel, purchased and net interchange power |
| (1) |
| - |
| |
Other operation |
| - |
| - |
| |
Maintenance |
| 3 |
| 14 |
| |
Depreciation |
| - |
| - |
| |
Amortization of regulatory assets, net |
| 3 |
| 69 |
| |
Amortization of rate reduction bonds |
| (1) |
| (8) |
| |
Taxes other than income taxes |
| - |
| - |
| |
Total operating expenses |
| 4 |
| 2 |
| |
Operating Income |
| 11 |
| 45 |
| |
Interest expense, net |
| 1 |
| 5 |
| |
Other income, net |
| 1 |
| 97 |
| |
Income before income tax expense |
| 11 |
| 82 |
| |
Income tax expense |
| 4 |
| (a) |
| |
Net Income | $ | 7 |
| 67 | % | |
(a) Percent greater than 100.
Comparison of the First Quarter of 2008 to the First Quarter of 2007
Operating Revenues
Operating revenues increased $15 million in 2008 due to higher distribution segment revenues ($10 million) and higher transmission segment revenues ($4 million).
The distribution segment revenues increased $10 million due to an increase of the distribution component of PSNH’s retail revenues which impacts earnings ($7 million) and an increase of the components of revenues which are included in NHPUC approved tracking mechanisms that track the recovery of certain incurred costs ($3 million). The distribution component of PSNH’s retail revenues which impacts earnings increased $7 million as a result of the rate increases effective July 1, 2007 and January 1, 2008, partially offset by lower sales. Retail sales decreased 0.1 percent in 2008 compared to 2007.
The distribution revenue tracking components increased $3 million primarily due to the pass-through of higher energy supply costs ($7 million), higher retail transmission revenues ($6 million), higher REC revenue from the Northern Wood Power Plant ($3 million), partially offset by a decrease in the SCRC ($12 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.
71
Transmission segment revenues increased $4 million primarily due to a higher transmission investment base, the impact of the March 24, 2008 FERC ROE decision and higher operating expenses which are recovered under FERC-approved transmission tariffs.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power costs decreased $1 million primarily due to a decrease in payments to higher priced IPPs in 2008 as contracts expired, partially offset by additional expenses incurred under the New Hampshire Renewable Portfolio Standards which began in 2008.
Maintenance
Maintenance expenses increased $3 million primarily due to higher distribution segment expenses related to overhead lines ($2 million) and tree trimming ($1 million) primarily due to more storms in the first quarter of 2008 compared to 2007 as well as expenditures associated with the Regulatory Enhancement Program (REP) which began on July 1, 2007.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net increased $3 million primarily due to amortization requirements related to the rate case settlement issued in Docket DE 06-028 effective July 2007 ($2 million).
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds decreased $1 million primarily due to the repayment of $50 million of rate reduction bonds in January 2008.
Interest Expense, Net
Interest expense increased $1 million primarily due to an increase in interest on long-term debt as a result of the issuance of $70 million of first mortgage bonds in September 2007.
Other Income, Net
Other income, net increased $1 million primarily due to a higher AFUDC, as a result of a higher eligible CWIP and lower short-term debt resulting in an increase in construction work in progress financed by equity.
Income Tax Expense
Income tax expense increased $4 million due to higher pre-tax earnings and an increase in the effective tax rate. The effective tax rate increase resulted primarily from lower unitary benefit.
LIQUIDITY
PSNH had consolidated operating cash flows of $35.2 million, including rate reduction bond payments of $13.1 million, in the first quarter of 2008, compared with operating cash flows of $48 million, including rate reduction bond payments of $12.3 million, in the first quarter of 2007. The decrease in 2008 operating cash flows was primarily due to a timing difference in resource procurement and working capital requirements, represented by a $9.8 million decrease in the change in fuel, materials and supplies, and a $7.5 million decrease in accounts receivable and unbilled revenues. Operating cash flows in 2008 also included a $4.3 million payment upon the termination of PSNH’s forward interest rate swap agreement related to its planned debt issuance of $110 million.
Cash capital expenditures included on the accompanying condensed consolidated statements of cash flows do not include amounts incurred but not paid, cost of removal, the AFUDC related to equity funds, and the capitalized portion of pension expense or income. PSNH’s first quarter 2008 cash capital expenditures were $56.7 million, compared with $39.8 million in the first quarter of 2007. This increase was primarily the result of higher transmission capital expenditures in 2008.
As of March 31, 2008, PSNH had $30 million of borrowings outstanding under the $400 million credit facility it shares with other NU subsidiaries. Other financing activities for the first quarter of 2008 included a capital contribution from NU parent of $5.7 million and $9.1 million in common dividends paid to NU parent.
72
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
Management's Discussion and Analysis of
Financial Condition and Results of Operations
WMECO is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's Management's Discussion and Analysis of Financial Condition and Results of Operations, condensed consolidated financial statements and footnotes in this Form 10-Q and the NU 2007 Form 10-K.
RESULTS OF OPERATIONS
The following table provides the variances in income statement line items for the condensed consolidated statements of income for WMECO included in this report on Form 10-Q for the three months ended March 31, 2008:
| Income Statement Variances | |||||
| Amount |
| Percent | |||
Operating Revenues: | $ | (14) |
| (11) | % | |
|
|
|
|
|
| |
Operating Expenses: |
|
|
|
|
| |
Operation - Fuel, purchased and net interchange power |
| (9) |
| (13) |
| |
Other operation |
| (5) |
| (22) |
| |
Maintenance |
| - |
| - |
| |
Depreciation |
| - |
| - |
| |
Amortization of regulatory assets, net |
| - |
| - |
| |
Amortization of rate reduction bonds |
| - |
| - |
| |
Taxes other than income taxes |
| - |
| - |
| |
Total operating expenses |
| (14) |
| (12) |
| |
Operating Income |
| - |
| - |
| |
Interest expense, net |
| 1 |
| 8 |
| |
Other income, net |
| - |
| - |
| |
Income before income tax expense |
| (1) |
| (8) |
| |
Income tax expense |
| - |
| - |
| |
Net Income | $ | (1) |
| (9) | % | |
Comparison of the First Quarter of 2008 to the First Quarter of 2007
Operating Revenues
Operating revenues decreased $14 million in 2008 compared to the same period in 2007 due to lower distribution segment revenues ($15 million), partially offset by higher transmission segment revenues ($1 million).
The distribution segment revenues decreased $15 million primarily due to the components of revenues which are included in DPU approved tracking mechanisms that track the recovery of certain incurred costs ($15 million). The distribution revenue tracking components decreased $15 million primarily due to pass-through of lower energy supply costs ($6 million), lower pension tracker and default service true-up revenues ($4 million) resulting from the distribution rate settlement that took effect January 1, 2007 and lower retail transmission revenues ($3 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.
The distribution component of revenues which impacts earnings increased $0.5 million primarily due to the distribution rate increases effective January 1, 2007 and January 1, 2008, partially offset by lower retail sales. Retail sales decreased 2.2 percent compared to the same period of 2007.
Transmission segment revenues increased $1 million primarily due to a higher transmission investment base, the impact of the March 24, 2008 FERC ROE decision and higher operating expenses which are recovered under FERC-approved transmission tariffs.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $9 million primarily due to lower default service supply costs. The default service supply costs are the contractual amounts we must pay to various suppliers that serve default service load after winning
73
a competitive solicitation process. The decrease in these costs is the result of decreased load levels combined with decreased supplier rates in the first quarter 2008 as compared to the first quarter 2007.
Other Operation
Other operation expenses decreased $5 million primarily due to a decrease in retail transmission expenses ($4 million). The decrease in retail transmission expenses is mainly due to the deferral, resulting from the regulatory tracking mechanism as a result of the increase in retail transmission revenue rates.
Interest Expense, Net
Interest expense, net increased $1 million primarily due to higher interest on long-term debt mainly resulting from the issuance of $40 million of unsecured notes in August 2007.
LIQUIDITY
WMECO had positive consolidated operating cash flows of $1.8 million, including rate reduction bond payments of $3.5 million, in the first quarter of 2008, compared with negative operating cash flows of $32.7 million, including rate reduction bond payments of $3.3 million, in the first quarter of 2007. The improvement in 2008 operating cash flows was primarily due to the payment of $47.9 million in federal and state income taxes in the first quarter of 2007, which was a result of the 2006 sale of our competitive generation business, partially offset by a number of timing factors including lower retail transmission collections and higher interest payments on long-term debt in the first quarter of 2008.
Cash capital expenditures included on the accompanying condensed consolidated statements of cash flows do not include amounts incurred but not paid, cost of removal, the AFUDC related to equity funds, and the capitalized portion of pension expense or income. WMECO’s first quarter 2008 cash capital expenditures were $13.5 million, compared with $10.8 million in the first quarter of 2007. This increase was primarily the result of higher transmission capital expenditures.
As of March 31, 2008, WMECO had $10 million of borrowings outstanding under the $400 million credit facility it shares with other NU subsidiaries. Other financing activities for the first quarter of 2008 included $3.4 million in common dividends paid to NU parent.
74
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risk Information
We utilize the sensitivity analysis methodology to disclose quantitative information for our commodity price risks (including where applicable capacity and ancillary components). Sensitivity analysis provides a presentation of the potential loss of future earnings, fair values or cash flows from market risk-sensitive instruments over a selected time period due to one or more hypothetical changes in commodity price components, or other similar price changes. Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity components, contract prices and market prices represented by each derivative contract. For swaps, forward contracts and options, fair value reflects our best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments. Exchange-traded futures and options are recorded at fair value based on closing exchange prices. As Select Energy's contracts wind down, the risks associated with commodity prices are expected to be reduced.
Wholesale Portfolio: When conducting sensitivity analyses of the change in the fair value of the wholesale portfolio, which includes a non-derivative power purchase contract, which would result from a hypothetical change in the future market price of electricity, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments.
A hypothetical change in the fair value of the wholesale portfolio was determined assuming a 10 percent change in forward market prices. At March 31, 2008, we calculated the market price resulting from a 10 percent change in forward market prices of those contracts. A 10 percent increase in prices for all products would have resulted in a pre-tax increase in fair value of $4.3 million and a 10 percent decrease in prices for all products would have resulted in a pre-tax decrease in fair value of $4.5 million. A 10 percent increase in energy prices would have resulted in a $3.6 million pre-tax decrease, and a 10 percent decrease in energy prices would have resulted in a $3.4 million pre-tax increase. A 10 percent increase/(decrease) in capacity prices would have resulted in a $1.5 million pre-tax increase/(decrease). A 10 percent increase/(decrease) in ancillary prices would have resulted in a $6.4 million pre-tax increase/(decrease).
The impact of a change in electricity prices on wholesale transactions at March 31, 2008 are not necessarily representative of the results that will be realized, if such a change were to occur. Also, energy, capacity and ancillaries have different market volatilities. These transactions are accounted for at fair value, and changes in market prices impact earnings.
Other Risk Management Activities
Interest Rate Risk Management: We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt. At March 31, 2008, approximately 90 percent (83 percent including the long-term debt subject to the fixed-to-floating interest rate swap as variable rate long-term debt) of our long-term debt, including fees and interest due for spent nuclear fuel disposal costs, was at a fixed interest rate. The remaining long-term debt is at variable interest rates and is subject to interest rate risk that could result in earnings volatility. Assuming a one percentage point increase in our variable interest rate, annual interest expense would have increased by $3.7 million. At March 31, 2008, we maintained a fixed-to-floating interest rate swap at NU parent to manage the interest rate risk associated with its $263 million of fixed-rate long-term debt.
Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of customers and suppliers that include independent power producers (IPPs), industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms which, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.
Credit risks and market risks at NU Enterprises are monitored regularly by a Risk Oversight Council. The Risk Oversight Council is comprised of individuals from outside of the management of these activities that create these risk exposures and functions to ensure compliance with our stated risk management policies.
We track and re-balance the risk in our portfolio in accordance with fair value and other risk management methodologies that utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure.
The New York Mercantile Exchange (NYMEX) traded futures and option contracts cleared off the NYMEX exchange are ultimately guaranteed by NYMEX to Select Energy. Select Energy has established written credit policies with regard to its counterparties to minimize overall credit risk on all types of transactions. These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash in advance, LOCs, and parent
75
guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in establishing credit limits prior to Select Energy entering into energy contracts. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may impact Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions.
At March 31, 2008 and December 31, 2007, Select Energy had collateral balances deposited with counterparties of $11.7 million and $18.9 million, respectively, which are included in current liabilities - other on the accompanying condensed consolidated balance sheets.
Our regulated companies have a lower level of credit risk related to providing regulated electric and gas distribution service than NU Enterprises. However, our regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Our regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and maintain an oversight group that monitors contracting risks, including credit risk.
We have implemented an Enterprise Risk Management (ERM) methodology for identifying the principal risks of the company. ERM involves the application of a well-defined, enterprise-wide methodology that will enable our Risk and Capital Committee, comprised of our senior officers, to oversee the identification, management and reporting of the principal risks of the business. However, there can be no assurances that the ERM process will identify every risk or event that could impact our financial condition or results of operations. The findings of this process are periodically discussed with our Board of Trustees.
Additional quantitative and qualitative disclosures about market risk are set forth in Part I, Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," included in this combined report on Form 10-Q.
ITEM 4.
CONTROLS AND PROCEDURES
NU evaluated the design and operation of its disclosure controls and procedures at March 31, 2008 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Exchange Act and the rules and regulations of the SEC. This evaluation was made under the supervision and with the participation of management, including NU’s principal executive officer and principal financial officer, as of the end of the period covered by this report on Form 10-Q. The principal executive officer and principal financial officer have concluded, based on their review, that NU’s disclosure controls and procedures are effective to ensure that information required to be disclosed by NU in reports that it files under the Exchange Act i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and ii) is accumulated and communicated to management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
There have been no changes in internal controls over financial reporting for NU during the quarter ended March 31, 2008 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
76
PART II. OTHER INFORMATION
LEGAL PROCEEDINGS
We are parties to various legal proceedings. We have identified these legal proceedings in Part I, Item 3, "Legal Proceedings" and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2007. Other than as set forth below, there have been no material changes with regard to the legal proceedings previously disclosed in our most recent Form 10-K.
1.
Consolidated Edison, Inc. v. NU - Merger Litigation
In March 2001, Consolidated Edison, Inc. (Con Edison) advised us that it was unwilling to close its merger with us on the terms set forth in our 1999 merger agreement (the Merger Agreement) and filed suit in federal court seeking a declaratory judgment that we had suffered a material adverse change, as defined in the Merger Agreement, and that Con Edison was therefore excused from performing its obligations under the Merger Agreement. We subsequently filed suit against Con Edison seeking to recover the merger premium which totaled over $1 billion, for the benefit of our shareholders. In May 2001, Con Edison amended its complaint seeking an award of money damages (including merger-related expenses) to compensate it for what it claims was the portion of the projected synergy savings that would have inured to the benefit of former Con Edison shareholders if the merger had been consummated and the estimated savings had been realized.
In October 2005, the United States Court of Appeals for the Second Circuit issued a decision concluding that our shareholders did not have the right to sue Con Edison for the merger premium as a result of its alleged breach of the Merger Agreement but left intact the remaining claims between us and Con Edison for breach of contract, which included our claim for recovery of costs and expenses and Con Edison's claim for its alleged synergy damages plus expenses.
In January 2008, the trial judge denied a series of motions by both us and Con Edison that had been pending, including our motion for an order dismissing Con Edison's synergy damage claim.
On March 13, 2008, we and Con Edison entered into a settlement agreement which settled all of our respective claims arising out of the failed merger. Under the terms of the settlement agreement, we paid Con Edison $49.5 million.
For more information on the Con Edison litigation, please refer to "Item 3 - Legal Proceedings" in our Annual Report on Form 10-K for the year ended December 31, 2007.
ITEM 1A.
RISK FACTORS
NU is subject to a variety of significant risks in addition to the matters set forth under "Forward Looking Statements," in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Matters." We have identified a number of these risk factors in our Annual Report on Form 10-K for the year ended December 31, 2007. NU’s susceptibility to certain risks, including those discussed in detail in our Annual Report on Form 10-K, could exacerbate other risks. These risk factors should be considered carefully in evaluating NU’s risk profile. There have been no material changes with regard to the risk factors previously disclosed in our most recent Form 10-K.
ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
There were no purchases made by or on behalf of NU or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Exchange Act), of common stock during the quarter ended March 31, 2008.
77
ITEM 6.
EXHIBITS
Exhibit No.
Description
Listing of Exhibits (NU, CL&P, PSNH, WMECO)
10.1
Northeast Utilities Service Company Transmission and Ancillary Service Wholesale Revenue Allocation Methodology, dated as of January 1, 2008 among The Connecticut Light and Power Company, Western Massachusetts Electric Company, Public Service Company of New Hampshire, Holyoke Water Power Company and Holyoke Power and Electric Company
Listing of Exhibits (NU)
15
Deloitte & Touche LLP Letter Regarding Unaudited Financial Information
31
Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 9, 2008
31.1
Certification of David R. McHale, Senior Vice President and Chief Financial Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 9, 2008
32
Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities and David R. McHale, Senior Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 9, 2008
Listing of Exhibits (CL&P)
31
Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 9, 2008
31.1
Certification of David R. McHale, Senior Vice President and Chief Financial Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 9, 2008
32
Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company and David R. McHale, Senior Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 9, 2008
Listing of Exhibits (PSNH)
31
Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 9, 2008
31.1
Certification of David R. McHale, Senior Vice President and Chief Financial Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 9, 2008
32
Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire and David R. McHale, Senior Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 9, 2008
78
Listing of Exhibits (WMECO)
31
Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 9, 2008
31.1
Certification of David R. McHale, Senior Vice President and Chief Financial Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 9, 2008
32
Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company and David R. McHale, Senior Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 9, 2008
79
SIGNATURE
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 hereunto duly authorized.
NORTHEAST UTILITIES |
(Registrant) |
By | /s/ David R. McHale |
| Date |
| David R. McHale |
|
|
| Senior Vice President and Chief Financial Officer |
| May 9, 2008 |
| (for the Registrant and as Principal Financial Officer) |
|
|
____________________________________________________________________________________
SIGNATURE
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 hereunto duly authorized.
THE CONNECTICUT LIGHT AND POWER COMPANY |
(Registrant) |
By | /s/ David R. McHale |
| Date |
| David R. McHale |
|
|
| Senior Vice President and Chief Financial Officer |
| May 9, 2008 |
| (for the Registrant and as Principal Financial Officer) |
|
|
80
SIGNATURE
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 hereunto duly authorized.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE |
(Registrant) |
By | /s/ David R. McHale |
| Date |
| David R. McHale |
|
|
| Senior Vice President and Chief Financial Officer |
| May 9, 2008 |
| (for the Registrant and as Principal Financial Officer) |
|
|
____________________________________________________________________________________
SIGNATURE
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 hereunto duly authorized.
WESTERN MASSACHUSETTS ELECTRIC COMPANY |
(Registrant) |
By | /s/ David R. McHale |
| Date |
| David R. McHale |
|
|
| Senior Vice President and Chief Financial Officer |
| May 9, 2008 |
| (for the Registrant and as Principal Financial Officer) |
|
|
81