PACIFICORP /OR/ - Quarter Report: 2014 September (Form 10-Q)

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 Securities Exchange Act of 1934

For the quarterly period ended September 30, 2014

[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from ______ to ______



Commission	Exact name of registrant as specified in its charter;	IRS Employer
File Number	State or other jurisdiction of incorporation or organization	Identification No.

1-5152	PACIFICORP	93-0246090
	(An Oregon Corporation)
	825 N.E. Multnomah Street
	Portland, Oregon 97232
	503-813-5608

N/A
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has 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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.



Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

All of the shares of outstanding common stock are indirectly owned by Berkshire Hathaway Energy Company, 666 Grand Avenue, Des Moines, Iowa 50309-2580. As of October 31, 2014, 357,060,915 shares of common stock were outstanding.

TABLE OF CONTENTS



PART I

Item 1.	Financial Statements	1
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29
Item 4.	Controls and Procedures	29

PART II

Item 1.	Legal Proceedings	30
Item 1A.	Risk Factors	30
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	30
Item 3.	Defaults Upon Senior Securities	30
Item 4.	Mine Safety Disclosures	30
Item 5.	Other Information	30
Item 6.	Exhibits	30
Signatures		31
Exhibit Index		32

Definition of Abbreviations and Industry Terms

When used in Forward-Looking Statements, Part I - Items 2 through 4, and Part II - Items 1 through 6, the following terms have the definitions indicated.



PacifiCorp and Related Entities
BHE		Berkshire Hathaway Energy Company
PacifiCorp		PacifiCorp and its subsidiaries
PPW Holdings		PPW Holdings LLC, a wholly owned subsidiary of BHE and PacifiCorp's direct parent company
Lake Side 2		645-megawatt combined-cycle combustion turbine natural gas-fueled generating facility

Certain Industry Terms
AFUDC		Allowance for Funds Used During Construction
CPUC		California Public Utilities Commission
EPA		United States Environmental Protection Agency
GWh		Gigawatt Hours
IPUC		Idaho Public Utilities Commission
MWh		Megawatt Hours
OPUC		Oregon Public Utility Commission
REC		Renewable Energy Credit
UPSC		Utah Public Service Commission
WPSC		Wyoming Public Service Commission
WUTC		Washington Utilities and Transportation Commission

Forward-Looking Statements

This report contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can typically be identified by the use of forward-looking words, such as "will," "may," "could," "project," "believe," "anticipate," "expect," "estimate," "continue," "intend," "potential," "plan," "forecast" and similar terms. These statements are based upon PacifiCorp's current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the control of PacifiCorp and could cause actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others:


•	general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including reliability and safety standards, affecting PacifiCorp's operations or related industries;


•	changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce generating facility output, accelerate generating facility retirements or delay generating facility construction or acquisition;


•	the outcome of rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies and PacifiCorp's ability to recover costs in rates in a timely manner;


•	changes in economic, industry or weather conditions, as well as demographic trends, new technologies and various conservation, energy efficiency and distributed generation measures and programs, that could affect customer growth and usage, electricity supply or PacifiCorp's ability to obtain long-term contracts with customers and suppliers;


•	a high degree of variance between actual and forecasted load or generation that could impact PacifiCorp's hedging strategy and the cost of balancing its generation resources with its retail load obligations;


•	performance and availability of PacifiCorp's generating facilities, including the impacts of outages and repairs, transmission constraints, weather, including wind and hydroelectric conditions, and operating conditions;


•	changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generating capacity and energy costs;


•	hydroelectric conditions and the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings that could have a significant impact on generating capacity and cost and PacifiCorp's ability to generate electricity;


•	the effects of catastrophic and other unforeseen events, which may be caused by factors beyond PacifiCorp's control or by a breakdown or failure of PacifiCorp's operating assets, including storms, floods, fires, earthquakes, explosions, landslides, mining accidents, litigation, wars, terrorism and embargoes;


•	the financial condition and creditworthiness of PacifiCorp's significant customers and suppliers;


•	changes in business strategy or development plans;


•	availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in the London Interbank Offered Rate, the base interest rate for PacifiCorp's credit facilities;


•	changes in PacifiCorp's credit ratings;


•	the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts;


•	the impact of inflation on costs and PacifiCorp's ability to recover such costs in rates;


•	increases in employee healthcare costs, including the implementation of the Affordable Care Act;

iii


•	the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on pension and other postretirement benefits expense and funding requirements;


•	unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future generating facilities and infrastructure additions;


•	the impact of new accounting guidance or changes in current accounting estimates and assumptions on PacifiCorp's consolidated financial results; and


•	other business or investment considerations that may be disclosed from time to time in PacifiCorp's filings with the United States Securities and Exchange Commission or in other publicly disseminated written documents.

Further details of the potential risks and uncertainties affecting PacifiCorp are described in its filings with the United States Securities and Exchange Commission, including Part II, Item 1A and other discussions contained in this Form 10-Q. PacifiCorp undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing factors should not be construed as exclusive.

PART I


Item 1.	Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PacifiCorp

Portland, Oregon

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of September 30, 2014, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2014 and 2013, and of changes in shareholders' equity and cash flows for the nine-month periods ended September 30, 2014 and 2013. These interim financial statements are the responsibility of PacifiCorp'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 consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of PacifiCorp and subsidiaries as of December 31, 2013, and the related consolidated statements of operations, comprehensive income, changes in shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated March 3, 2014, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2013 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Portland, Oregon

November 7, 2014

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)



	As of
	September 30,		December 31,
	2014		2013
ASSETS

Current assets:
Cash and cash equivalents	$	116	$	53
Accounts receivable, net	698		700
Inventories:
Materials and supplies	220		213
Fuel	205		241
Deferred income taxes	20		66
Regulatory assets	124		94
Other current assets	65		75
Total current assets	1,448		1,442

Property, plant and equipment, net	18,733		18,507
Regulatory assets	1,211		1,290
Other assets	468		420

Total assets	$	21,860	$	21,659

The accompanying notes are an integral part of these consolidated financial statements.

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)



	As of
	September 30,			December 31,
	2014			2013
LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	473		$	504
Income taxes payable	27			22
Accrued employee expenses	122			79
Accrued interest	105			110
Accrued property and other taxes	121			58
Current portion of long-term debt and capital lease obligations	141			238
Regulatory liabilities	36			55
Other current liabilities	198			208
Total current liabilities	1,223			1,274

Regulatory liabilities	910			879
Long-term debt and capital lease obligations	6,935			6,639
Deferred income taxes	4,451			4,359
Other long-term liabilities	701			721
Total liabilities	14,220			13,872

Commitments and contingencies (Note 8)

Shareholders' equity:
Preferred stock	2			2
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding	—			—
Additional paid-in capital	4,479			4,479
Retained earnings	3,168			3,315
Accumulated other comprehensive loss, net	(9		)	(9		)
Total shareholders' equity	7,640			7,787

Total liabilities and shareholders' equity	$	21,860		$	21,659

The accompanying notes are an integral part of these consolidated financial statements.

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2014			2013			2014			2013

Operating revenue	$	1,438		$	1,398		$	3,969		$	3,845

Operating costs and expenses:
Energy costs	525			530			1,473			1,411
Operations and maintenance	267			267			781			805
Depreciation and amortization	185			169			541			506
Taxes, other than income taxes	44			43			126			126
Total operating costs and expenses	1,021			1,009			2,921			2,848

Operating income	417			389			1,048			997

Other income (expense):
Interest expense	(94		)	(96		)	(285		)	(286		)
Allowance for borrowed funds	5			6			20			21
Allowance for equity funds	10			13			40			42
Other, net	2			3			7			5
Total other income (expense)	(77		)	(74		)	(218		)	(218		)

Income before income tax expense	340			315			830			779
Income tax expense	101			99			252			237
Net income	$	239		$	216		$	578		$	542

The accompanying notes are an integral part of these consolidated financial statements.

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (Unaudited)

(Amounts in millions)



											Accumulated
						Additional					Other			Total
	Preferred			Common		Paid-in		Retained			Comprehensive			Shareholders'
	Stock			Stock		Capital		Earnings			Loss, Net			Equity

Balance at December 31, 2012	$	41		$	—	$	4,479	$	3,136		$	(12	)	$	7,644
Net income	—			—		—		542			—			542
Preferred stock dividends declared	—			—		—		(1		)	—			(1		)
Common stock dividends declared	—			—		—		(500		)	—			(500		)
Redemption of preferred stock	(5		)	—		—		—			—			(5		)
Balance at September 30, 2013	$	36		$	—	$	4,479	$	3,177		$	(12	)	$	7,680

Balance at December 31, 2013	$	2		$	—	$	4,479	$	3,315		$	(9	)	$	7,787
Net income	—			—		—		578			—			578
Common stock dividends declared	—			—		—		(725		)	—			(725		)
Balance at September 30, 2014	$	2		$	—	$	4,479	$	3,168		$	(9	)	$	7,640

The accompanying notes are an integral part of these consolidated financial statements.

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)



	Nine-Month Periods
	Ended September 30,
	2014			2013

Cash flows from operating activities:
Net income	$	578		$	542
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	541			506
Deferred income taxes and amortization of investment tax credits	145			123
Changes in regulatory assets and liabilities	(34		)	(16		)
Other, net	(22		)	(27		)
Changes in other operating assets and liabilities:
Accounts receivable and other assets	22			11
Derivative collateral, net	4			43
Inventories	29			(1		)
Income taxes	5			41
Accounts payable and other liabilities	89			75
Net cash flows from operating activities	1,357			1,297

Cash flows from investing activities:
Capital expenditures	(777		)	(752		)
Other, net	—			15
Net cash flows from investing activities	(777		)	(737		)

Cash flows from financing activities:
Proceeds from long-term debt	425			299
Repayments of long-term debt and capital lease obligations	(213		)	(272		)
Redemption of preferred stock	—			(5		)
Common stock dividends	(725		)	(500		)
Other, net	(4		)	(5		)
Net cash flows from financing activities	(517		)	(483		)

Net change in cash and cash equivalents	63			77
Cash and cash equivalents at beginning of period	53			80
Cash and cash equivalents at end of period	$	116		$	157

The accompanying notes are an integral part of these consolidated financial statements.

PACIFICORP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


(1)	General

PacifiCorp, which includes PacifiCorp and its subsidiaries, is a United States regulated electric utility company serving retail customers, including residential, commercial, industrial, irrigation and other customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, a number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp's subsidiaries support its electric utility operations by providing coal mining services. PacifiCorp is an indirect subsidiary of Berkshire Hathaway Energy Company ("BHE"), a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2014 and for the three- and nine-month periods ended September 30, 2014 and 2013. The results of operations for the three- and nine-month periods ended September 30, 2014 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2013 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in PacifiCorp's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2014.


(2)	New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09, which creates FASB Accounting Standards Codification ("ASC") Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. This guidance is effective for interim and annual reporting periods beginning after December 15, 2016. Early application is not permitted. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. PacifiCorp is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In February 2013, the FASB issued ASU No. 2013-04, which amends FASB ASC Topic 405, "Liabilities." The amendments in this guidance require an entity to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the amount the reporting entity agreed to pay plus any additional amounts the reporting entity expects to pay on behalf of its co-obligor. Additionally, the guidance requires the entity to disclose the nature and amount of the obligation, as well as other information about those obligations. PacifiCorp adopted this guidance on January 1, 2014. The adoption of this guidance did not have a material impact on PacifiCorp's disclosures included within Notes to Consolidated Financial Statements.


(3)	Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):



		As of
		September 30,			December 31,
	Depreciable Life	2014			2013

Property, plant and equipment in service	5-75 years	$	25,862		$	24,868
Accumulated depreciation and amortization		(8,055		)	(7,686		)
Net property, plant and equipment in service		17,807			17,182
Construction work-in-progress		926			1,325
Total property, plant and equipment, net		$	18,733		$	18,507

As a result of PacifiCorp's recent depreciation study approved by its state regulatory commissions, PacifiCorp revised its depreciation rates effective January 1, 2014. The approved depreciation rates resulted in an increase in depreciation expense of $9 million for the three-month period ended September 30, 2014 as compared to the three-month period ended September 30, 2013, and $26 million for the nine-month period ended September 30, 2014 as compared to the nine-month period ended September 30, 2013.


(4)	Recent Financing Transactions

In March 2014, PacifiCorp issued $425 million of its 3.60% First Mortgage Bonds due April 2024. The net proceeds were used to fund capital expenditures and for general corporate purposes, including retirement of short-term debt that was partially incurred to pay a $500 million common stock dividend in March 2014 to PPW Holdings LLC, a wholly owned subsidiary of BHE and PacifiCorp's direct parent company.

In March 2014, PacifiCorp arranged for the cancellation of $97 million of letters of credit previously issued to support variable-rate tax-exempt bond obligations. As of September 30, 2014, PacifiCorp had $451 million of fully available letters of credit issued under committed arrangements to support variable-rate tax-exempt bond obligations, of which $270 million were issued under revolving credit facilities. As of September 30, 2014, PacifiCorp had $142 million of variable-rate tax-exempt bond obligations outstanding supported by its revolving credit facilities.


(5)	Employee Benefit Plans

Net periodic benefit cost for the pension and other postretirement benefit plans included the following components (in millions):



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2014			2013			2014			2013
Pension:
Service cost	$	2		$	1		$	4		$	4
Interest cost	14			14			42			41
Expected return on plan assets	(19		)	(19		)	(57		)	(56		)
Net amortization	7			12			22			36
Net periodic benefit cost	$	4		$	8		$	11		$	25

Other postretirement:
Service cost	$	1		$	2		$	4		$	6
Interest cost	7			6			21			19
Expected return on plan assets	(8		)	(7		)	(23		)	(22		)
Net amortization	1			2			2			6
Net periodic benefit cost	$	1		$	3		$	4		$	9

Employer contributions to the pension and other postretirement benefit plans are expected to be $10 million and $1 million, respectively, during 2014. As of September 30, 2014, $9 million and $1 million of contributions had been made to the pension and other postretirement benefit plans, respectively.

Multiemployer Pension Plan

PacifiCorp believes it is reasonably possible that its subsidiary will withdraw from the multiemployer United Mine Workers of America 1974 Pension Plan to which the subsidiary contributes. The withdrawal obligation was most recently estimated to be $125 million based on a withdrawal occurring by July 1, 2014. In the event of withdrawal, PacifiCorp's subsidiary may elect to make a lump sum payment or annual installment payments to settle the withdrawal obligation. Additionally, PacifiCorp will seek recovery of the withdrawal obligation from its customers.

(6)Risk Management and Hedging Activities

PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt and future debt issuances. PacifiCorp does not engage in a material amount of proprietary trading activities.

PacifiCorp has established a risk management process that is designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in place during the periods presented. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Note 7 for additional information on derivative contracts.

The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):



	Other						Other			Other
	Current			Other			Current			Long-term
	Assets			Assets			Liabilities			Liabilities			Total

As of September 30, 2014
Not designated as hedging contracts⁽¹⁾:
Commodity assets	$	12		$	1		$	1		$	—		$	14
Commodity liabilities	(1		)	(1		)	(19		)	(22		)	(43		)
Total	11			—			(18		)	(22		)	(29		)

Total derivatives	11			—			(18		)	(22		)	(29		)
Cash collateral receivable	—			—			5			3			8
Total derivatives - net basis	$	11		$	—		$	(13	)	$	(19	)	$	(21	)

As of December 31, 2013
Not designated as hedging contracts⁽¹⁾:
Commodity assets	$	11		$	—		$	2		$	1		$	14
Commodity liabilities	(1		)	—			(29		)	(39		)	(69		)
Total	10			—			(27		)	(38		)	(55		)

Total derivatives	10			—			(27		)	(38		)	(55		)
Cash collateral receivable	—			—			—			12			12
Total derivatives - net basis	$	10		$	—		$	(27	)	$	(26	)	$	(43	)


(1)	PacifiCorp's commodity derivatives are generally included in rates and as of September 30, 2014 and December 31, 2013, a regulatory asset of $29 million and $55 million, respectively, was recorded related to the net derivative liability of $29 million and $55 million, respectively.

The following table reconciles the beginning and ending balances of PacifiCorp's regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in regulatory assets, as well as amounts reclassified to earnings (in millions):



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2014			2013			2014			2013

Beginning balance	$	—		$	85		$	55		$	121
Changes in fair value recognized in regulatory assets	34			8			(15		)	3
Net gains (losses) reclassified to operating revenue	2			8			(9		)	7
Net losses reclassified to energy costs	(7		)	(44		)	(2		)	(74		)
Ending balance	$	29		$	57		$	29		$	57

Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):



	Unit of	September 30,		December 31,
	Measure	2014		2013
Electricity sales	Megawatt hours	(3	)	(1	)
Natural gas purchases	Decatherms	116		120
Fuel oil purchases	Gallons	3		15

Credit Risk

PacifiCorp extends unsecured credit to other utilities, energy marketing companies, financial institutions and other market participants in conjunction with its wholesale energy supply and marketing activities. Credit risk relates to the risk of loss that might occur as a result of nonperformance by counterparties on their contractual obligations to make or take delivery of electricity, natural gas or other commodities and to make financial settlements of these obligations. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances involving other market participants that have a direct or indirect relationship with the counterparty.

PacifiCorp analyzes the financial condition of each significant wholesale counterparty before entering into any transactions, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To mitigate exposure to the financial risks of wholesale counterparties, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed fees for delayed payments. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

Collateral and Contingent Features

In accordance with industry practice, certain wholesale derivative contracts contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the three recognized credit rating agencies. These derivative contracts may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" in the event of a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2014, PacifiCorp's credit ratings from the three recognized credit rating agencies were investment grade.

The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $43 million and $68 million as of September 30, 2014 and December 31, 2013, respectively, for which PacifiCorp had posted collateral of $8 million and $12 million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of September 30, 2014 and December 31, 2013, PacifiCorp would have been required to post $32 million and $51 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.


(7)	Fair Value Measurements

The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. PacifiCorp has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:


•	Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the ability to access at the measurement date.

•

Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).


•	Level 3 - Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best information available, including its own data.

The following table presents PacifiCorp's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):



	Input Levels for Fair Value Measurements
	Level 1		Level 2			Level 3		Other⁽¹⁾			Total
As of September 30, 2014
Assets:
Commodity derivatives	$	—	$	14		$	—	$	(3	)	$	11
Money market mutual funds⁽²⁾	105		—			—		—			105
	$	105	$	14		$	—	$	(3	)	$	116

Liabilities - Commodity derivatives	$	—	$	(43	)	$	—	$	11		$	(32	)

As of December 31, 2013
Assets:
Commodity derivatives	$	—	$	12		$	2	$	(4	)	$	10
Money market mutual funds⁽²⁾	61		—			—		—			61
	$	61	$	12		$	2	$	(4	)	$	71

Liabilities - Commodity derivatives	$	—	$	(69	)	$	—	$	16		$	(53	)


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $8 million and $12 million as of September 30, 2014 and December 31, 2013, respectively.


(2)	Amounts are included in cash and cash equivalents, other current assets and other assets on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first six years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first six years. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. Refer to Note 6 for further discussion regarding PacifiCorp's risk management and hedging activities.

PacifiCorp's investments in money market mutual funds are accounted for as available-for-sale securities and are stated at fair value. PacifiCorp uses a readily observable quoted market price to record the fair value.

PacifiCorp's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of PacifiCorp's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of PacifiCorp's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt (in millions):



	As of September 30, 2014				As of December 31, 2013
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	7,042	$	8,243	$	6,828	$	7,626


(8)	Commitments and Contingencies

Legal Matters

PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. PacifiCorp is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.

USA Power

In October 2005, prior to BHE's ownership of PacifiCorp, PacifiCorp was added as a defendant to a lawsuit originally filed in February 2005 in the Third District Court of Salt Lake County, Utah ("Third District Court") by USA Power, LLC, USA Power Partners, LLC and Spring Canyon Energy, LLC (collectively, the "Plaintiff"). The Plaintiff's complaint alleged that PacifiCorp misappropriated confidential proprietary information in violation of Utah's Uniform Trade Secrets Act and accused PacifiCorp of breach of contract and related claims in regard to the Plaintiff's 2002 and 2003 proposals to build a natural gas-fueled generating facility in Juab County, Utah. In October 2007, the Third District Court granted PacifiCorp's motion for summary judgment on all counts and dismissed the Plaintiff's claims in their entirety. In February 2008, the Plaintiff filed a petition requesting consideration by the Utah Supreme Court. In May 2010, the Utah Supreme Court reversed summary judgment and remanded the case back to the Third District Court for further consideration, which led to a trial that began in April 2012. In May 2012, the jury reached a verdict in favor of the Plaintiff on its claims. The jury awarded damages to the Plaintiff for breach of contract and misappropriation of a trade secret in the amounts of $18 million for actual damages and $113 million for unjust enrichment. In May 2012, the Plaintiff filed a motion seeking exemplary damages. Under the Utah Uniform Trade Secrets law, the judge may award exemplary damages in an additional amount not to exceed twice the original award. The Plaintiff also filed a motion to seek recovery of attorneys' fees in an amount equal to 40% of all amounts ultimately awarded in the case. In October 2012, PacifiCorp filed post-trial motions for a judgment notwithstanding the verdict and a new trial (collectively, "PacifiCorp's post-trial motions"). The trial judge stayed briefing on the Plaintiff's motions, pending resolution of PacifiCorp's post-trial motions. As a result of a hearing in December 2012, the trial judge denied PacifiCorp's post-trial motions with the exception of reducing the aggregate amount of damages to $113 million. In January 2013, the Plaintiff filed a motion for prejudgment interest. In the first quarter of 2013, PacifiCorp filed its responses to the Plaintiff's post-trial motions for exemplary damages, attorneys' fees and prejudgment interest. An initial judgment was entered in April 2013 in which the trial judge denied the Plaintiff's motions for exemplary damages and prejudgment interest and ruled that PacifiCorp must pay the Plaintiff's attorneys' fees based on applying a reasonable rate to hours worked rather than the Plaintiff's request for an amount equal to 40% of all amounts ultimately awarded. In May 2013, a final judgment was entered against PacifiCorp in the amount of $115 million, which includes the $113 million of aggregate damages previously awarded and amounts awarded for the Plaintiff's attorneys' fees. The final judgment also ordered that postjudgment interest accrue beginning as of the date of the April 2013 initial judgment. In May 2013, PacifiCorp posted a surety bond issued by a subsidiary of Berkshire Hathaway to secure its estimated obligation. PacifiCorp strongly disagrees with the jury's verdict and is vigorously pursuing all appellate measures. Both PacifiCorp and the Plaintiff filed appeals with the Utah Supreme Court. Briefing before the Utah Supreme Court is complete and oral arguments will most likely be held in 2015. As of September 30, 2014, PacifiCorp had accrued $118 million for the final judgment and postjudgment interest, and believes the likelihood of any additional material loss is remote; however, any additional awards against PacifiCorp could also have a material effect on the consolidated financial results. Any payment of damages will be at the end of the appeals process, which could take as long as several years.

Sanpete County, Utah Rangeland Fire

In June 2012, a major rangeland fire occurred in Sanpete County, Utah. Certain parties allege that contact between two of PacifiCorp's transmission lines may have triggered a ground fault that led to the fire. PacifiCorp has engaged experts to review the cause and origin of the fire, as well as to assess the damages. PacifiCorp has accrued its best estimate of the potential loss and expected insurance recovery. PacifiCorp believes it is reasonably possible it may incur additional loss beyond the amount accrued, but does not believe the potential additional loss will have a material impact on its consolidated financial results.

Northwest Refund Case

In October 2011, the Federal Energy Regulatory Commission ("FERC") issued an order on remand by the United States Court of Appeals for the Ninth Circuit, in which it determined that additional procedures are needed to address possible unlawful activity that may have influenced prices in the Pacific Northwest wholesale spot market during the period from December 2000 through June 2001. PacifiCorp was a participant in the Pacific Northwest wholesale spot market during this period. The FERC ordered an evidentiary, trial-type hearing before an administrative law judge to permit parties to present evidence of alleged unlawful market activity. However, the FERC held the hearing in abeyance pending settlement discussions among all parties. The plaintiff parties to the proceeding filed claims against multiple parties, including PacifiCorp. PacifiCorp entered into settlements with the plaintiff parties, and the resulting settlements were approved by the FERC. The outcome of such settlements did not have a material impact on PacifiCorp's consolidated financial results. The FERC, however, declined to dismiss PacifiCorp from the case entirely, noting that additional parties may, in the future, assert sequential claims against parties to the case, including PacifiCorp. Although the FERC has not yet addressed sequential claims, based on the progress of the other parties' primary cases through the trial-type hearing and recently reached settlements between other parties, PacifiCorp believes it is remote that the outcome of the FERC's review of the sequential claims would have a material impact on its consolidated financial results.

Environmental Laws and Regulations


(9)	Related Party Transactions

Berkshire Hathaway includes BHE and its subsidiaries in its United States federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for income taxes has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income taxes are remitted to or received from BHE. For the nine-month periods ended September 30, 2014 and 2013, PacifiCorp made net cash payments for federal and state income taxes to BHE totaling $100 million and $69 million, respectively.


Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of PacifiCorp during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth and other factors. This discussion should be read in conjunction with PacifiCorp's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 1 of this Form 10‑Q. PacifiCorp's actual results in the future could differ significantly from the historical results.

Results of Operations for the Third Quarter and First Nine Months of 2014 and 2013

Overview

Net income for the third quarter of 2014 was $239 million, an increase of $23 million, or 11%, compared to 2013. Net income increased primarily due to higher retail prices and lower energy costs, partially offset by higher depreciation and amortization expense, lower REC revenue and lower wholesale electricity revenue. Retail customer load increased 0.6% for the third quarter of 2014 compared to 2013, primarily due to higher residential and commercial customer usage in Utah, higher industrial customer usage in Wyoming and higher average number of residential customers, substantially offset by the impacts of cooler weather on residential and commercial customers in Utah and irrigation customers in Idaho. Energy generated increased 3% for the third quarter of 2014 compared to 2013, due to higher natural gas-fueled generation, as a result of Lake Side 2 being placed in-service in May 2014, partially offset by lower wind-powered and hydroelectric generation. Wholesale electricity sales volumes decreased 9% and purchased electricity volumes decreased 21%.

Net income for the first nine months of 2014 was $578 million, an increase of $36 million, or 7%, compared to 2013. Net income increased primarily due to higher retail prices, lower operations and maintenance expense as a result of insurance recoveries expected from a fire claim and higher wholesale electricity revenue, partially offset by higher energy costs, higher depreciation and amortization expense and lower retail customer load. Retail customer load decreased 0.2% for the first nine months of 2014 compared to 2013, primarily due to the impacts of milder weather on residential and commercial customers primarily in Utah and irrigation customers in Idaho, partially offset by higher residential, commercial and industrial customer usage in Utah, higher average number of residential customers and higher irrigation customer usage primarily in Oregon. Energy generated increased 3% for the first nine months of 2014 compared to 2013, primarily due to higher natural gas-fueled generation, including the addition of Lake Side 2, and higher hydroelectric generation, partially offset by lower coal-fueled generation. Wholesale electricity sales volumes decreased 2% and purchased electricity volumes decreased 17%.

Operating revenue and energy costs are the key drivers of PacifiCorp's results of operations as they encompass retail and wholesale electricity revenue and the direct costs associated with providing electricity to customers. PacifiCorp believes that a discussion of gross margin, representing operating revenue less energy costs, is therefore meaningful.

A comparison of PacifiCorp's key operating results is as follows:



	Third Quarter									First Nine Months
	2014		2013		Change					2014		2013		Change

Gross margin (in millions):
Operating revenue	$	1,438	$	1,398	$	40		3	%	$	3,969	$	3,845	$	124		3	%
Energy costs	525		530		(5		)	(1	)	1,473		1,411		62			4
Gross margin	$	913	$	868	$	45		5		$	2,496	$	2,434	$	62		3

Sales (GWh):
Residential	3,974		4,037		(63		)	(2	)%	11,545		11,883		(338		)	(3	)%
Commercial	4,599		4,563		36			1		12,846		12,839		7			—
Industrial and irrigation	6,082		5,964		118			2		16,863		16,596		267			2
Other	113		114		(1		)	(1	)	322		334		(12		)	(4	)
Total retail	14,768		14,678		90			1		41,576		41,652		(76		)	—
Wholesale	2,251		2,478		(227		)	(9	)	7,153		7,288		(135		)	(2	)
Total sales	17,019		17,156		(137		)	(1	)	48,729		48,940		(211		)	—

Average number of retail customers (in thousands)	1,783		1,767		16			1	%	1,780		1,765		15			1	%

Average revenue per MWh:
Retail	$	89.65	$	86.67	$	2.98		3	%	$	86.17	$	83.55	$	2.62		3	%
Wholesale	$	33.69	$	32.81	$	0.88		3	%	$	33.62	$	30.91	$	2.71		9	%

Sources of energy (GWh)⁽¹⁾:
Coal	11,342		11,393		(51		)	—	%	31,403		32,637		(1,234		)	(4	)%
Natural gas	3,145		2,510		635			25		8,046		5,787		2,259			39
Hydroelectric⁽²⁾	501		530		(29		)	(5	)	2,750		2,458		292			12
Wind and other⁽²⁾	552		590		(38		)	(6	)	2,425		2,360		65			3
Total energy generated	15,540		15,023		517			3		44,624		43,242		1,382			3
Energy purchased	2,714		3,429		(715		)	(21	)	7,654		9,271		(1,617		)	(17	)
Total	18,254		18,452		(198		)	(1	)	52,278		52,513		(235		)	—

Average cost of energy per MWh:
Energy generated⁽³⁾	$	21.00	$	20.18	$	0.82		4	%	$	20.34	$	18.82	$	1.52		8	%
Energy purchased	$	58.93	$	58.08	$	0.85		1	%	$	58.99	$	53.19	$	5.80		11	%


(1)	GWh amounts are net of energy used by the related generating facilities.


(2)	All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities.


(3)	The average cost per MWh of energy generated includes the cost of fuel associated with the generating facilities and does not include other costs.

Gross margin increased $45 million, or 5%, for the third quarter of 2014 compared to 2013 primarily due to:


•	$49 million of higher retail prices;


•	$41 million of lower purchased electricity due to reduced volumes; and

•

$3 million from a 0.6% increase in retail customer load, with a 3.2% increase due to higher customer usage consisting of higher residential and commercial customer usage in Utah, higher industrial customer usage in Wyoming and higher average number of residential customers, substantially offset by a 2.6% decrease due to the impacts of cooler weather on residential and commercial customers in Utah and irrigation customers in Idaho.

The increase in gross margin was partially offset by:


•	$13 million of higher natural gas costs due to increased generation from Lake Side 2, partially offset by lower average unit costs;


•	$11 million of lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms;


•	$9 million of higher coal costs due to higher unit costs, partially offset by reduced volumes;


•	$7 million of lower REC revenue;


•	$6 million of lower wholesale electricity revenue due to reduced volumes; and


•	$3 million of higher transmission expense.

Depreciation and amortization increased $16 million, or 9%, for the third quarter of 2014 compared to 2013 due to the impact of PacifiCorp's depreciation rate study effective January 1, 2014 and higher plant in-service, including Lake Side 2.

Gross margin increased $62 million, or 3%, for the first nine months of 2014 compared to 2013 primarily due to:


•	$118 million of higher retail prices;


•	$47 million of lower purchased electricity due to reduced volumes, partially offset by higher average market prices; and


•	$15 million of higher wholesale electricity revenue due to higher average market prices, partially offset by reduced volumes.

The increase in gross margin was partially offset by:


•	$68 million of higher natural gas costs primarily due to increased generation, including the addition of Lake Side 2;


•	$25 million of higher coal costs due to higher unit costs, partially offset by reduced volumes;

•

$16 million from a 0.2% decrease in retail customer load, with a 2.2% decrease due to the impacts of milder weather on residential and commercial customers primarily in Utah and irrigation customers in Idaho, partially offset by a 2.0% higher customer usage consisting of higher residential, commercial and industrial customer usage in Utah, higher average number of residential customers and higher irrigation customer usage primarily in Oregon; and


•	$14 million of higher transmission expense.

Operations and maintenance decreased $24 million, or 3%, for the first nine months of 2014 compared to 2013 due to insurance recoveries expected from the Sanpete County, Utah rangeland fire and charges associated with the rangeland fire in 2013, partially offset by higher demand-side management expense in Utah. The Sanpete County, Utah rangeland fire is discussed in Note 8 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q.

Depreciation and amortization increased $35 million, or 7%, for the first nine months of 2014 compared to 2013 due to the impact of PacifiCorp's depreciation rate study effective January 1, 2014 and higher plant in-service, including Lake Side 2.

Income tax expense increased $15 million, or 6%, for the first nine months of 2014 compared to 2013 and the effective tax rate was 30% for the first nine months of 2014 and 2013. The increase in income tax expense was primarily due to higher pre-tax book income.

Liquidity and Capital Resources

As of September 30, 2014, PacifiCorp's total net liquidity was $904 million as follows (in millions):



Cash and cash equivalents	$	116

Credit facilities	1,200
Less:
Short-term debt	—
Letters of credit and tax-exempt bond support	(412		)
Net credit facilities	788

Total net liquidity	$	904

Credit facilities:
Maturity dates	2017, 2018
Largest single bank commitment as a % of total credit facilities	7		%

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2014 and 2013 were $1.357 billion and $1.297 billion, respectively. The $60 million increase was primarily due to higher collections from retail customers and lower pension contributions, partially offset by higher fuel payments, lower cash collateral inflows for derivative contracts and higher cash paid for income taxes.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2014 and 2013 were $(777) million and $(737) million, respectively. Capital expenditures increased $25 million and consisted of the following during the nine-month periods ended September 30 and exclude amounts for non-cash equity AFUDC and other non-cash items:

2014:


•	Transmission system investments totaling $215 million, including construction costs for the 170-mile single-circuit 345-kilovolt Sigurd-Red Butte ("Sigurd-Red Butte") transmission line expected to be placed in-service in 2015.


•	Emissions control equipment on existing generating facilities totaling $122 million for installation or upgrade of control systems for nitrogen oxides, particulate matter and mercury.


•	The construction of Lake Side 2 totaling $32 million, which was placed in-service in May 2014.


•	Routine expenditures for transmission, distribution, generation and other infrastructure totaling $408 million.

2013:


•	Transmission system investments totaling $181 million, including construction costs for the Sigurd-Red Butte transmission line and the 100-mile high-voltage Mona-Oquirrh ("Mona-Oquirrh") transmission line that was placed in-service in May 2013.


•	The construction of Lake Side 2 totaling $116 million.


•	Emissions control equipment on existing generating facilities totaling $31 million for installation or upgrade of control systems for nitrogen oxides, particulate matter and mercury.


•	Routine expenditures for transmission, distribution, generation and other infrastructure totaling $424 million.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2014 was $(517) million. Uses of cash consisted substantially of $725 million for common stock dividends paid to PPW Holdings and $212 million for the repayment of long-term debt. Sources of cash consisted of proceeds from the issuance of long-term debt.

Net cash flows from financing activities for the nine-month period ended September 30, 2013 was $(483) million. Uses of cash consisted substantially of $500 million for common stock dividends paid to PPW Holdings and $268 million for the repayment of long-term debt. Sources of cash consisted of proceeds from the issuance of long-term debt.

Long-term Debt

PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $1.575 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance.

Future Uses of Cash

PacifiCorp has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which PacifiCorp has access to external financing depends on a variety of factors, including PacifiCorp's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

PacifiCorp has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items, such as pollution-control technologies, replacement generation, hydroelectric relicensing, hydroelectric decommissioning and associated operating costs are generally incorporated into PacifiCorp's rates.

Forecasted capital expenditures, which exclude amounts for non-cash equity AFUDC and other non-cash items, are approximately $1.1 billion for the year ended December 31, 2014 and include the following:


•	$265 million for transmission system investments, including projects for the Energy Gateway Transmission Expansion Program, which includes construction costs of $131 million for the Sigurd-Red Butte transmission line.

•

$163 million for environmental projects, which includes emissions control equipment to meet anticipated air quality and visibility targets, including the reduction of nitrogen oxides, particulate matter and mercury emissions. This estimate includes the installation of new or the replacement of existing emissions control equipment at a number of units at several of PacifiCorp's coal-fueled generating facilities, including Jim Bridger Units 3 and 4 and Hunter Unit 1.


•	$37 million for construction of Lake Side 2, which was placed in-service in May 2014.


•	Remaining costs relate to routine expenditures for transmission, distribution, generation and other infrastructure needed to serve existing and expected demand.

Integrated Resource Plan

In April 2013, PacifiCorp filed its 2013 IRP with the state commissions. The WPSC accepted the 2013 IRP into its files and the IPUC, the WUTC and the UPSC acknowledged the 2013 IRP. The OPUC acknowledged the 2013 IRP with exceptions and revisions to specific action items.

Energy Imbalance Market

PacifiCorp and the California Independent System Operator Corporation ("California ISO") implemented a new energy imbalance market ("EIM") in October 2014 beginning with a 30-day transition period where the California ISO and PacifiCorp enabled their systems to interact and produce results reflecting realistic market conditions, but without financially binding settlements or dispatch instructions. The EIM transitioned to a fully operational, financially binding market on November 1, 2014. The EIM is expected to reduce costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, more effectively integrate renewables and enhance reliability through improved situational awareness and responsiveness. In today's environment, utilities in the west outside the California ISO rely upon a combination of automated and manual dispatch within the hour to balance generation and load to maintain reliable supply and have limited capability to transact within the hour outside their own borders. In contrast, the EIM will optimize and automate five-minute dispatch of generation to serve load across the entire six-state PacifiCorp and California ISO footprint. The EIM is voluntary and available to all balancing authorities in the Western United States. Benefits to customers are expected to increase as more entities join and the footprint grows, bringing incremental generation and load diversity. In June 2014, the FERC issued two orders on tariff revisions to implement the EIM proposed by PacifiCorp and the California ISO, respectively, subject to compliance filings. In October 2014, the FERC issued orders accepting PacifiCorp's and the California ISO's compliance filings, subject to an additional compliance filing by each entity no later than November 19, 2014.

Contractual Obligations

As of September 30, 2014, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2013 other than the 2014 debt issuance previously discussed.

Regulatory Matters

PacifiCorp is subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2013, and new regulatory matters occurring in 2014.

State Regulatory Matters

Utah

In January 2014, PacifiCorp filed a general rate case with the UPSC requesting an annual increase of $76 million, or an average price increase of 4%. PacifiCorp filed subsequent rebuttal testimony reducing the requested increase to $66 million. The requested increase includes recovery of PacifiCorp's investment in Lake Side 2, which was placed in-service in May 2014, and the Mona-Oquirrh transmission line investment found to be prudent in the prior general rate case. In August 2014, the UPSC approved a multi-party stipulation that provides for a two-step rate increase. The first increase of $35 million, or an average price increase of 2%, was effective September 2014, and the second increase of $19 million, or an average price increase of 1%, will be effective the later of September 2015 or the in-service date of the Sigurd-Red Butte transmission line. The stipulation resolved most issues in the general rate case, but did not settle the net metering facilities charge proposed by PacifiCorp, which was moved by the UPSC to a new docket for further analysis. The stipulation also specifies that September 2016 would be the earliest effective date that PacifiCorp could seek an increase to customers' rates in Utah, with the exception of the year-two increase agreed to above and other UPSC-approved and currently existing rate adjustment mechanisms, including the Energy Balancing Account ("EBA") pilot for which the stipulation provides a one-year extension through 2016.

In March 2014, PacifiCorp filed its annual EBA with the UPSC requesting $28 million, or an increase of 2%, for recovery of deferred net power costs for the period January 1, 2013 through December 31, 2013. In October 2014, the UPSC approved an all-party stipulation providing for a rate increase of $25 million, or 1%, effective November 2014. The parties to the stipulation agreed that, effective November 2014, the $25 million would be combined with the remaining deferral balances currently being collected in the EBA of $19 million, with the total balance of $44 million to be collected over a 12-month period beginning November 2014.

In March 2014, PacifiCorp filed its annual REC balancing account application with the UPSC requesting recovery of $17 million over a three-year period. In May 2014, the UPSC approved interim rates effective June 2014. In September 2014, the UPSC issued a final order approving the interim rates as final.

Oregon

In April 2014, PacifiCorp made its initial filing for the annual Transition Adjustment Mechanism with the OPUC for an annual increase of $18 million, or an average price increase of 2%, based on forecasted net power costs for calendar year 2015. In July 2014, PacifiCorp filed an all-party stipulation with the OPUC resolving all issues in the proceeding. The stipulation reflects an overall annual increase of $10 million, or an average price increase of 1%, subject to updates through November 2014. In October 2014, the OPUC issued an order approving the stipulation. The new rates will be effective January 2015.

In April 2014, PacifiCorp filed for a separate tariff rider with the OPUC to recover the Oregon-allocated costs of PacifiCorp's investment in Lake Side 2. The separate tariff rider was agreed to in the 2013 Oregon general rate case stipulation with final costs subject to a prudence determination. The filing supports an overall rate increase of $22 million, or an average price increase of 2%. In May 2014, the OPUC approved the new rates effective June 2014.

Wyoming

In March 2014, PacifiCorp filed a general rate case with the WPSC requesting an annual increase of $36 million, or an average price increase of 5%. In September 2014, PacifiCorp filed rebuttal testimony reducing the requested increase to $32 million, or an average price increase of 5%. The requested increase includes recovery of PacifiCorp's investments in Lake Side 2 and the Mona-Oquirrh transmission line. Hearings were held by the WPSC in October 2014. If approved by the WPSC, the new rates will be effective January 2015.

In March 2014, PacifiCorp filed its annual Energy Cost Adjustment Mechanism ("ECAM") and Renewable Energy Credit and Sulfur Dioxide Revenue Adjustment Mechanism ("RRA") applications with the WPSC. The ECAM filing requests recovery of $17 million of deferred net power costs for the period January 1, 2013 through December 31, 2013, and the RRA application requests a $4 million increase in the RRA surcharge. The two applications represent a combined total price increase of 3%. In May 2014, the WPSC approved the ECAM and RRA rates effective May 2014 on an interim basis subject to further investigation and hearing.

Washington

In December 2012, PacifiCorp submitted a compliance filing with the WUTC presenting Washington-allocated actual REC sales revenues of $17 million from January 1, 2009 through April 2, 2011. Also in December 2012, PacifiCorp filed for judicial review of the WUTC's August 2012 order requiring PacifiCorp to credit to its retail customers all proceeds from the sale of RECs attributable to Washington that were recorded on or after January 1, 2009, less any amounts already credited to retail customers, and the WUTC's November 2012 order denying PacifiCorp's petition for reconsideration and stay of the August 2012 order. In February 2013, PacifiCorp, WUTC staff and intervening parties submitted a joint filing with the WUTC proposing a tracking mechanism for REC sales revenues from April 3, 2011 forward. In March 2013, the WUTC issued a notice stating that the February 2013 joint filing failed to comply with the WUTC's orders, primarily requiring PacifiCorp and other parties to clarify the period over which amortization of historical REC sales revenues (revenues from January 1, 2009 through April 2, 2011) would occur. In March 2013, PacifiCorp filed a response to the WUTC notice requesting that the WUTC not require amortization of historical REC sales revenues until after resolution of the pending judicial review of the WUTC's orders. In June 2014, a multi-party stipulation was filed with the WUTC resolving the request for judicial review associated with the appropriate rate treatment of REC sales revenues from January 1, 2009 through April 2, 2011. The terms of the settlement include a one-time credit to customers totaling $13 million for REC sales revenues from January 1, 2009 through April 2, 2011. The WUTC approved the stipulation and the one-time credit to customers effective June 2014. In July 2014, the Washington State Court of Appeals granted the parties' joint motion to dismiss the petition for judicial review.

In May 2014, PacifiCorp filed a general rate case with the WUTC requesting an annual increase of $27 million, or an average price increase of 8%. If approved by the WUTC, the new rates will be effective March 2015.

In October 2014, PacifiCorp filed for a temporary rate increase of $5 million, or an average price increase of 2%, to recover the amount of RECs reflected in customers' rates in excess of actual RECs sold from April 3, 2011 through December 31, 2013. PacifiCorp's proposal is consistent with the joint filing for a REC tracking mechanism filed with the WUTC in February 2013. If approved by the WUTC, the new rates will be effective November 2014 and will remain in effect for approximately one year.

Idaho

In January 2014, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $13 million of deferred net power costs. In April 2014, the IPUC issued an order approving recovery of $12 million of deferred net power costs, of which $7 million will be collected over a 12-month period and the remainder collected over a 24-month period, with new rates effective April 2014.

California

In July 2014, PacifiCorp filed for a rate increase of $2 million, or 2%, pursuant to its Post Test-year Adjustment Mechanism ("PTAM") for major capital additions to add Lake Side 2 and the Hunter Unit 1 emissions control equipment to rates. The CPUC approved the new rates effective August 2014.

In August 2014, PacifiCorp filed for a rate increase of $5 million, or 4%, pursuant to its annual Energy Cost Adjustment Clause. If approved by the CPUC, the new rates will be effective January 2015.

In October 2014, PacifiCorp filed its annual PTAM attrition adjustment with the CPUC requesting an increase of $1 million, or an average price increase of 1%. If approved by the CPUC, the new rates will be effective January 2015.

Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various state and local agencies. PacifiCorp believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Refer to "Liquidity and Capital Resources" for discussion of PacifiCorp's forecasted environmental-related capital expenditures. The discussion below contains material developments to those matters disclosed in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2013.

Clean Air Act Regulations

The Clean Air Act is a federal law administered by the EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in State Implementation Plans ("SIPs"), which are a collection of regulations, programs and policies to be followed. SIPs vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA.

Mercury and Air Toxics Standards

The Clean Air Mercury Rule ("CAMR"), issued by the EPA in March 2005, was the United States' first attempt to regulate mercury emissions from coal-fueled generating facilities through the use of a market-based cap-and-trade system. The CAMR, which mandated emissions reductions of approximately 70% by 2018, was overturned by the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") in February 2008. In March 2011, the EPA proposed a new rule that would require coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards rather than a cap-and-trade system. The final rule, Mercury and Air Toxics Standards ("MATS"), was published in the Federal Register in February 2012, with an effective date of April 16, 2012, and requires that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources are required to comply with the new standards by April 16, 2015. Individual sources may be granted up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. PacifiCorp believes that its emissions reduction projects completed to date or currently permitted or planned for installation, including scrubbers, baghouses and electrostatic precipitators, are consistent with the EPA's MATS and will support PacifiCorp's ability to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants. PacifiCorp will be required to take additional actions to reduce mercury emissions through the installation of controls or use of sorbent injection at certain of its coal-fueled generating facilities and otherwise comply with the final rule's standards, which may include retiring certain units.

PacifiCorp continues to plan for retirement of the Carbon coal-fueled generating facility ("Carbon Facility") in early 2015 as the least-cost alternative to comply with the MATS and other environmental regulations. Efforts are underway to effectuate the decommissioning activities and transmission system modifications necessary to maintain system reliability following disconnection. The Carbon Facility produced 1.2 million MWh of electricity, or 2.1% of PacifiCorp's owned generation production, during 2013.

Incremental costs to install and maintain emissions control equipment at PacifiCorp's coal-fueled generating facilities and any requirement to shut down what have traditionally been low cost coal-fueled generating facilities will likely increase the cost of providing service to customers. In addition, numerous lawsuits were filed against the MATS in the D.C. Circuit. In April 2014, the D.C. Circuit upheld the MATS requirements.

Regional Haze

The EPA has initiated a regional haze program intended to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah, Wyoming and Arizona are subject to the Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit SIPs that address emissions from sources subject to best available retrofit technology ("BART") requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.

The state of Utah issued a regional haze SIP requiring the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the sulfur dioxide portion of the Utah regional haze SIP and disapproved the nitrogen oxides and particulate matter portions. Certain groups appealed the EPA's approval of the sulfur dioxide portion and oral argument was heard before the United States Court of Appeals for the Tenth Circuit ("Tenth Circuit") in March 2014. In October 2014, the Tenth Circuit upheld the EPA's approval of the sulfur dioxide portion of the SIP. The state of Utah and PacifiCorp filed petitions for administrative and judicial review of the EPA's final rule on the BART determinations for nitrogen oxides and particulate matter portions of Utah's regional haze SIP in March 2013. Oral argument was held before the Tenth Circuit in March 2014. In May 2014, the Tenth Circuit dismissed the petition, concluding that even though the EPA had changed the promulgation date for its final action, the EPA did not do so explicitly, the filing date for petitions for judicial review ran from the EPA's original action, and the Tenth Circuit had no jurisdiction to decide the case. The state of Utah and PacifiCorp then filed petitions for review of the Tenth Circuit's dismissal, which the Tenth Circuit again rejected in September 2014. In addition, and separate from the EPA's approval process and related litigation, the Utah Division of Air Quality has undertaken an additional BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2, which will be provided to the EPA as a supplement to the existing Utah SIP after the public comment period closes December 1, 2014, and the Utah Division of Air Quality responds to the public comments. It is unknown whether and how this supplemental analysis will impact the EPA's decision regarding the Utah SIP.

The state of Wyoming issued two regional haze SIPs requiring the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the sulfur dioxide SIP in December 2012. Certain groups have appealed the EPA's approval of the sulfur dioxide SIP, and PacifiCorp has intervened in that appeal. Oral argument was held before the Tenth Circuit in March 2014. In October 2014, the Tenth Circuit upheld the EPA's approval of the sulfur dioxide portion of the SIP. In addition, the EPA initially proposed in June 2012 to disapprove portions of the nitrogen oxides and particulate matter SIP and instead issue a federal implementation plan ("FIP"). The EPA withdrew its initial proposed actions on the nitrogen oxides and particulate matter SIP and the proposed FIP, published a re-proposed rule in June 2013, and finalized its determination on January 10, 2014, which aligns more closely with the SIP proposed by the state of Wyoming. The EPA's final action on the Wyoming SIP approved the state's plan to have PacifiCorp install low-nitrogen oxides burners at Naughton Units 1 and 2, selective catalytic reduction at Naughton Unit 3 by December 2014, selective catalytic reduction at Jim Bridger Units 1 through 4 between 2015 and 2022, and low-nitrogen oxides burners at Dave Johnston Unit 4. The EPA disapproved the Wyoming SIP and issued a FIP for Dave Johnston Unit 3, where it required the installation of selective catalytic reduction by 2019 or, in lieu of installing selective catalytic reduction, a commitment to shut down Dave Johnston Unit 3 by 2027, its currently approved depreciable life. The EPA also disapproved the Wyoming SIP and issued a FIP for the Wyodak coal-fueled generating facility ("Wyodak Facility"), requiring the installation of selective catalytic reduction within five years (i.e., by 2019). The EPA action became final on March 3, 2014. PacifiCorp filed an appeal of the EPA's final action on the Wyodak Facility in March 2014. The state of Wyoming has also filed an appeal of the EPA's final action, as have the Powder River Basin Resource Council, National Parks Conservation Association and Sierra Club. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for the Wyodak Facility, pending further action by the Tenth Circuit in the appeal. With respect to Naughton Unit 3, the EPA indicated it supported the conversion of the unit to natural gas and would expedite action relative to consideration of the natural gas conversion once the state of Wyoming submitted the requisite SIP amendment; nonetheless, the Naughton Unit 3 natural gas conversion remains subject to final approval by the EPA. In June 2014, the Wyoming Department of Environmental Quality issued a revised BART permit providing for the Naughton Unit 3 natural gas conversion in 2018 and allowing the unit to operate on coal through 2017.

A case was filed in the Tenth Circuit appealing a FIP issued by the EPA in New Mexico. In addition, two cases involving the EPA's issuance of a FIP were appealed to the United States Supreme Court in 2014, one from the Tenth Circuit based on the EPA rejecting portions of the Oklahoma SIP and one from the United States Court of Appeals for the Eighth Circuit based on the EPA's rejection of the North Dakota SIP. In May 2014, the United States Supreme Court issued its decisions denying review of the Oklahoma and North Dakota SIPs.

Until the EPA takes final action in each state and decisions have been made on each appeal, PacifiCorp cannot fully determine the impacts of the Regional Haze regulation on its generating facilities.

Climate Change

In June 2014, the EPA released proposed regulations to address greenhouse gas emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on four building blocks that it determined were the "Best System of Emission Reduction." The four building blocks include: (a) a 6% heat rate improvement from coal-fueled generating facilities; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities to 70%; (c) increased deployment of renewable and non-carbon generating resources; and (d) increased energy efficiency. Under the EPA's proposal, states may utilize any measure to achieve the specified emission reduction goals, with an initial implementation period of 2020-2029 and the final goal to be achieved by 2030. When fully implemented, the proposal is expected to reduce carbon dioxide emissions in the power sector to 30% below 2005 levels by 2030. The EPA is taking comment on its proposal until December 1, 2014 and is scheduled to issue final rules in June 2015. States are required to submit implementation plans by June 2016, but they may request an extension to June 2017, or June 2018 if they plan to participate in a regional compliance program. The impacts of the proposal on PacifiCorp cannot be determined until the EPA finalizes the proposal and the states develop their implementation plans. PacifiCorp has historically pursued cost-effective projects, including plant efficiency improvements, increased diversification of its generating fleet to include deployment of renewable and lower carbon generating resources, and advancement of customer energy efficiency programs.

Water Quality Standards

The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the "best technology available for minimizing adverse environmental impact" to aquatic organisms. In July 2004, the EPA established significant new technology-based performance standards for existing electricity generating facilities that take in more than 50 million gallons of water per day. These rules were aimed at minimizing the adverse environmental impacts of cooling water intake structures by reducing the number of aquatic organisms lost as a result of water withdrawals. In response to a legal challenge to the rule, in January 2007, the United States Court of Appeals for the Second Circuit ("Second Circuit") remanded almost all aspects of the rule to the EPA, without addressing whether companies with cooling water intake structures were required to comply with these requirements. On appeal from the Second Circuit, in April 2009, the United States Supreme Court ruled that the EPA permissibly relied on a cost-benefit analysis in setting the national performance standards regarding "best technology available for minimizing adverse environmental impact" at cooling water intake structures and in providing for cost-benefit variances from those standards as part of the §316(b) Clean Water Act Phase II regulations. The United States Supreme Court remanded the case back to the Second Circuit to conduct further proceedings consistent with its opinion.

In March 2011, the EPA released a proposed rule under §316(b) of the Clean Water Act to regulate cooling water intakes at existing facilities. The proposed rule establishes requirements for all power generating facilities that withdraw more than two million gallons per day, based on total design intake capacity, of water from waters of the United States and use at least 25% of the withdrawn water exclusively for cooling purposes. PacifiCorp's Dave Johnston generating facility withdraws more than two million gallons per day of water from waters of the United States for once-through cooling applications. PacifiCorp's Jim Bridger, Naughton, Gadsby, Hunter, Carbon and Huntington generating facilities currently utilize closed cycle cooling towers but withdraw more than two million gallons of water per day. The proposed rule includes impingement (i.e., when fish and other organisms are trapped against screens when water is drawn into a facility's cooling system) mortality standards to be met through average impingement mortality or intake velocity design criteria and entrainment (i.e., when organisms are drawn into the facility) standards to be determined on a case-by-case basis. The standards are required to be met as soon as possible after the effective date of the final rule, but no later than eight years thereafter. While the rule was required to be finalized by the EPA by July 2012, the deadline for finalizing the rule was extended to June 2013 and then again to January 2014. The final rule was released May 19, 2014, and allows facilities to choose one of seven options to reduce fish impingement. Facilities that withdraw at least 125 million gallons of water per day must conduct studies to help their permitting authority determine what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. PacifiCorp is assessing the options for compliance at its generating facilities impacted by the final rule and will complete impingement and entrainment studies. The costs of compliance with the cooling water intake structure rule cannot be determined until the prescribed studies are conducted. In the event that PacifiCorp's existing intake structures require modification, the costs are not anticipated to be significant to the consolidated financial statements.

In June 2013, the EPA published proposed effluent limitation guidelines and standards for the steam electric power generating sector. These guidelines, which had not been revised since 1982, were revised in response to the EPA's concerns that the addition of controls for air emissions have changed the effluent discharged from coal- and natural gas-fueled generating facilities. While the EPA expected the final rule to be published in May 2014, the final rule is now scheduled for release by September 30, 2015. It is likely that the new guidelines will impose more stringent limits on wastewater discharges from coal-fueled generating facilities and ash and scrubber ponds. However, until the revised guidelines are finalized, PacifiCorp cannot predict the impact on its generating facilities.

In April 2014, the EPA and the United States Army Corps of Engineers issued a joint proposal to address "Waters of the United States" to clarify protection under the Clean Water Act for streams and wetlands. The proposed rule comes as a result of United States Supreme Court decisions in 2001 and 2006 that created confusion regarding jurisdictional waters that were subject to permitting under either nationwide or individual permitting requirements. As currently proposed, a variety of projects that otherwise would have qualified for streamlined permitting processes under nationwide or regional general permits will be required to undergo more lengthy and costly individual permit procedures based on an extension of waters that will be deemed jurisdictional. The public comment period has been extended on the proposal to November 14, 2014. Until the rule is finalized, PacifiCorp cannot determine whether projects that include construction and demolition will face more complex permitting issues, higher costs or increased requirements for compensatory mitigation.

Collateral and Contingent Features

Debt and preferred securities of PacifiCorp are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of PacifiCorp's ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. As of September 30, 2014, PacifiCorp's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the three recognized credit rating agencies were investment grade.

PacifiCorp has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt and a change in ratings is not an event of default under the applicable debt instruments. PacifiCorp's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities. Certain authorizations or exemptions by regulatory commissions for the issuance of securities are valid as long as PacifiCorp maintains investment grade ratings on senior secured debt. A downgrade below that level would necessitate new regulatory applications and approvals.

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" in the event of a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of September 30, 2014, PacifiCorp would have been required to post $185 million of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors. Refer to Note 6 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for a discussion of PacifiCorp's collateral requirements specific to PacifiCorp's derivative contracts.

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting PacifiCorp, refer to Note 2 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of PacifiCorp's critical accounting estimates, see Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2013. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2013.


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk affecting PacifiCorp, see Item 7A of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2013. PacifiCorp's exposure to market risk and its management of such risk has not changed materially since December 31, 2013. Refer to Note 6 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for disclosure of PacifiCorp's derivative positions as of September 30, 2014.


Item 4.	Controls and Procedures

At the end of the period covered by this Quarterly Report on Form 10-Q, PacifiCorp carried out an evaluation, under the supervision and with the participation of PacifiCorp's management, including the Chief Executive Officer (principal executive officer) and the Chief Financial Officer (principal financial officer), of the effectiveness of the design and operation of PacifiCorp's disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended). Based upon that evaluation, PacifiCorp's management, including the Chief Executive Officer (principal executive officer) and the Chief Financial Officer (principal financial officer), concluded that PacifiCorp's disclosure controls and procedures were effective to ensure that information required to be disclosed by PacifiCorp in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to management, including PacifiCorp's Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer), or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There has been no change in PacifiCorp's internal control over financial reporting during the quarter ended September 30, 2014 that has materially affected, or is reasonably likely to materially affect, PacifiCorp's internal control over financial reporting.

PART II


Item 1.	Legal Proceedings

For a description of certain legal proceedings affecting PacifiCorp, refer to Note 8 of Notes to Consolidated Financial Statements included in Part I, Item 1 of this Form 10-Q.


Item 1A.	Risk Factors

There has been no material change to PacifiCorp's risk factors from those disclosed in Item 1A of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2013.


Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.


Item 3.	Defaults Upon Senior Securities

Not applicable.


Item 4.	Mine Safety Disclosures

Information regarding PacifiCorp's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 to this Form 10-Q.


Item 5.	Other Information

Not applicable.


Item 6.	Exhibits

The exhibits listed on the accompanying Exhibit Index are filed as part of this Quarterly Report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	PACIFICORP
	(Registrant)



Date: November 7, 2014	/s/ Douglas K. Stuver
	Douglas K. Stuver
	Senior Vice President and Chief Financial Officer
	(principal financial and accounting officer)

EXHIBIT INDEX

Exhibit No. Description


4.1*	Twenty-Seventh Supplemental Indenture, dated as of March 1, 2014, to PacifiCorp's Mortgage and Deed of Trust dated as of January 9, 1989 (Exhibit 4.1, Current Report on Form 8-K, filed March 13, 2014, File No. 1-5152).


15	Awareness Letter of Independent Registered Public Accounting Firm.


31.1	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


31.2	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


32.1	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


32.2	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


95	Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act.

101

The following financial information from PacifiCorp's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014 is formatted in XBRL (eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholders' Equity, (iv) the Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements, tagged in summary and detail.

*Incorporated by reference.