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, 2012
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from ______ to _______
Commission File Number | Exact name of registrant as specified in its charter; State or other jurisdiction of incorporation or organization | IRS Employer Identification No. | ||
001-14881 | MIDAMERICAN ENERGY HOLDINGS COMPANY | 94-2213782 | ||
(An Iowa Corporation) | ||||
666 Grand Avenue, Suite 500 | ||||
Des Moines, Iowa 50309-2580 | ||||
515-242-4300 | ||||
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 common equity of MidAmerican Energy Holdings Company are privately held by a limited group of investors. As of October 31, 2012, 74,609,001 shares of common stock were outstanding.
TABLE OF CONTENTS
PART I
PART II
i
Definition of Abbreviations and Industry Terms
When used in Part I, Items 2 through 4, and Part II, Items 1 through 6, the following terms have the definitions indicated.
MidAmerican Energy Holdings Company and Related Entities | ||
MEHC | MidAmerican Energy Holdings Company | |
Company | MidAmerican Energy Holdings Company and its subsidiaries | |
PacifiCorp | PacifiCorp and its subsidiaries | |
MidAmerican Funding | MidAmerican Funding, LLC | |
MidAmerican Energy | MidAmerican Energy Company | |
Northern Natural Gas | Northern Natural Gas Company | |
Kern River | Kern River Gas Transmission Company | |
Northern Powergrid Holdings | Northern Powergrid Holdings Company | |
MidAmerican Energy Pipeline Group | Consists of Northern Natural Gas and Kern River | |
MidAmerican Renewables | Consists of MidAmerican Renewables, LLC and CalEnergy Philippines | |
CE Casecnan | CE Casecnan Water and Energy Company, Inc. | |
HomeServices | HomeServices of America, Inc. and its subsidiaries | |
ETT | Electric Transmission Texas, LLC | |
Utilities | PacifiCorp and MidAmerican Energy Company | |
Domestic Regulated Businesses | PacifiCorp, MidAmerican Energy Company, Northern Natural Gas Company and Kern River Gas Transmission Company | |
Berkshire Hathaway | Berkshire Hathaway Inc. and its subsidiaries | |
Topaz | Topaz Solar Farms LLC | |
Topaz Project | Topaz Solar Farms LLC's 550-megawatt solar project | |
Agua Caliente | Agua Caliente Solar, LLC | |
Agua Caliente Project | Agua Caliente Solar, LLC's 290-megawatt solar project | |
Bishop Hill | Bishop Hill Energy II, LLC | |
Bishop Hill Project | Bishop Hill Energy II, LLC's 81-MW wind-powered generating project | |
Certain Industry Terms | ||
AFUDC | Allowance for Funds Used During Construction | |
Dodd-Frank Reform Act | Dodd-Frank Wall Street Reform and Consumer Protection Act | |
EPA | United States Environmental Protection Agency | |
ERCOT | Electric Reliability Council of Texas | |
FERC | Federal Energy Regulatory Commission | |
GHG | Greenhouse Gases | |
IPUC | Idaho Public Utilities Commission | |
IUB | Iowa Utilities Board | |
kV | Kilovolt | |
MW | Megawatts | |
OPUC | Oregon Public Utility Commission | |
REC | Renewable Energy Credit | |
RPS | Renewable Portfolio Standards | |
RTO | Regional Transmission Organization | |
UPSC | Utah Public Service Commission | |
WPSC | Wyoming Public Service Commission | |
WUTC | Washington Utilities and Transportation Commission |
ii
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 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 the Company'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 the Company 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 laws and regulations affecting the Company'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 facility output, accelerate facility retirements or delay facility construction or acquisition; |
• | the outcome of general rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies and the Company's ability to recover costs in rates in a timely manner; |
• | changes in economic, industry, competition or weather conditions, as well as demographic trends, that could affect customer growth and usage, electricity and natural gas supply or the Company's ability to obtain long-term contracts with customers and suppliers; |
• | a high degree of variance between actual and forecasted load that could impact the Company's hedging strategy and the cost of balancing its generation resources with its retail load obligations; |
• | performance and availability of the Company's facilities, including the impacts of outages and repairs, transmission constraints, weather and operating conditions; |
• | changes in prices, availability and demand for both purchases and sales of wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generating capacity and energy costs; |
• | the financial condition and creditworthiness of the Company'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 MEHC's and its subsidiaries' credit facilities; |
• | changes in MEHC's and its subsidiaries' credit ratings; |
• | risks relating to nuclear generation; |
• | the impact of derivative 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 derivative contracts; |
• | the impact of inflation on costs and the Company's ability to recover such costs in regulated rates; |
• | increases in employee healthcare costs; |
• | 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; |
• | changes in the residential real estate brokerage and mortgage industries and regulations that could affect brokerage and mortgage transaction levels; |
• | unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future facilities and infrastructure additions; |
• | the availability and price of natural gas in applicable geographic regions and demand for natural gas supply; |
• | the impact of new accounting guidance or changes in current accounting estimates and assumptions on the Company's consolidated financial results; |
• | the Company's ability to successfully integrate future acquired operations into its business; |
iii
• | other risks or unforeseen events, including the effects of storms, floods, fires, explosions, litigation, wars, terrorism, embargoes and other catastrophic events; and |
• | other business or investment considerations that may be disclosed from time to time in MEHC'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 the Company are described in MEHC's filings with the United States Securities and Exchange Commission, including Part II, Item 1A and other discussions contained in this Form 10-Q. The Company 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.
iv
PART I
Item 1. | Financial Statements |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
MidAmerican Energy Holdings Company
Des Moines, Iowa
We have reviewed the accompanying consolidated balance sheet of MidAmerican Energy Holdings Company and subsidiaries (the "Company") as of September 30, 2012, and the related consolidated statements of operations and comprehensive income for the three-month and nine-month periods ended September 30, 2012 and 2011, and of changes in equity and cash flows for the nine-month periods ended September 30, 2012 and 2011. These interim financial statements are the responsibility of the Company's management.
We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our reviews, we are not aware of any material modifications that should be made to such 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 MidAmerican Energy Holdings Company and subsidiaries as of December 31, 2011, and the related consolidated statements of operations, cash flows, changes in equity, and comprehensive income for the year then ended (not presented herein); and in our report dated February 27, 2012, 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, 2011 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
/s/ Deloitte & Touche LLP
Des Moines, Iowa
November 2, 2012
1
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
As of | |||||||
September 30, | December 31, | ||||||
2012 | 2011 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 1,860 | $ | 286 | |||
Trade receivables, net | 1,258 | 1,270 | |||||
Income taxes receivable | — | 456 | |||||
Inventories | 762 | 690 | |||||
Other current assets | 581 | 581 | |||||
Total current assets | 4,461 | 3,283 | |||||
Property, plant and equipment, net | 36,204 | 34,167 | |||||
Goodwill | 5,033 | 4,996 | |||||
Investments and restricted cash and investments | 2,076 | 1,948 | |||||
Regulatory assets | 2,770 | 2,835 | |||||
Other assets | 566 | 489 | |||||
Total assets | $ | 51,110 | $ | 47,718 |
The accompanying notes are an integral part of these consolidated financial statements.
2
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
As of | |||||||
September 30, | December 31, | ||||||
2012 | 2011 | ||||||
LIABILITIES AND EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 1,055 | $ | 989 | |||
Accrued employee expenses | 265 | 155 | |||||
Accrued interest | 327 | 326 | |||||
Accrued property, income and other taxes | 679 | 340 | |||||
Short-term debt | 178 | 865 | |||||
Current portion of long-term debt | 1,181 | 1,198 | |||||
Other current liabilities | 659 | 674 | |||||
Total current liabilities | 4,344 | 4,547 | |||||
Regulatory liabilities | 1,735 | 1,663 | |||||
MEHC senior debt | 4,621 | 4,621 | |||||
Subsidiary debt | 15,154 | 13,253 | |||||
Deferred income taxes | 7,556 | 7,076 | |||||
Other long-term liabilities | 2,216 | 2,293 | |||||
Total liabilities | 35,626 | 33,453 | |||||
Commitments and contingencies (Note 10) | |||||||
Equity: | |||||||
MEHC shareholders' equity: | |||||||
Common stock - 115 shares authorized, no par value, 75 shares issued and outstanding | — | — | |||||
Additional paid-in capital | 5,423 | 5,423 | |||||
Retained earnings | 10,455 | 9,310 | |||||
Accumulated other comprehensive loss, net | (565 | ) | (641 | ) | |||
Total MEHC shareholders' equity | 15,313 | 14,092 | |||||
Noncontrolling interests | 171 | 173 | |||||
Total equity | 15,484 | 14,265 | |||||
Total liabilities and equity | $ | 51,110 | $ | 47,718 |
The accompanying notes are an integral part of these consolidated financial statements.
3
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
Three-Month Periods | Nine-Month Periods | ||||||||||||||
Ended September 30, | Ended September 30, | ||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||
Operating revenue: | |||||||||||||||
Energy | $ | 2,636 | $ | 2,535 | $ | 7,593 | $ | 7,546 | |||||||
Real estate | 372 | 285 | 970 | 764 | |||||||||||
Total operating revenue | 3,008 | 2,820 | 8,563 | 8,310 | |||||||||||
Operating costs and expenses: | |||||||||||||||
Energy: | |||||||||||||||
Cost of sales | 884 | 897 | 2,576 | 2,709 | |||||||||||
Operating expense | 653 | 604 | 1,953 | 1,865 | |||||||||||
Depreciation and amortization | 367 | 324 | 1,072 | 988 | |||||||||||
Real estate | 347 | 267 | 921 | 739 | |||||||||||
Total operating costs and expenses | 2,251 | 2,092 | 6,522 | 6,301 | |||||||||||
Operating income | 757 | 728 | 2,041 | 2,009 | |||||||||||
Other income (expense): | |||||||||||||||
Interest expense | (298 | ) | (301 | ) | (884 | ) | (907 | ) | |||||||
Capitalized interest | 15 | 13 | 37 | 31 | |||||||||||
Interest and dividend income | 3 | 2 | 8 | 11 | |||||||||||
Other, net | 35 | 17 | 86 | 63 | |||||||||||
Total other income (expense) | (245 | ) | (269 | ) | (753 | ) | (802 | ) | |||||||
Income before income tax expense and equity income | 512 | 459 | 1,288 | 1,207 | |||||||||||
Income tax expense | 47 | 68 | 188 | 255 | |||||||||||
Equity income | 30 | 28 | 61 | 42 | |||||||||||
Net income | 495 | 419 | 1,161 | 994 | |||||||||||
Net income attributable to noncontrolling interests | 7 | 7 | 16 | 15 | |||||||||||
Net income attributable to MEHC shareholders | $ | 488 | $ | 412 | $ | 1,145 | $ | 979 |
The accompanying notes are an integral part of these consolidated financial statements.
4
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(Amounts in millions)
Three-Month Periods | Nine-Month Periods | ||||||||||||||
Ended September 30, | Ended September 30, | ||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||
Net income | $ | 495 | $ | 419 | $ | 1,161 | $ | 994 | |||||||
Other comprehensive income (loss), net of tax: | |||||||||||||||
Unrecognized amounts on retirement benefits, net of tax of $(2), $7, $1 and $7 | (5 | ) | 19 | 6 | 19 | ||||||||||
Foreign currency translation adjustment | 84 | (79 | ) | 113 | (1 | ) | |||||||||
Unrealized losses on available-for-sale securities, net of tax of $(11), $(143), $(35) and $(323) | (16 | ) | (216 | ) | (51 | ) | (487 | ) | |||||||
Unrealized gains on cash flow hedges, net of tax of $7, $2, $5 and $10 | 11 | 3 | 8 | 15 | |||||||||||
Total other comprehensive income (loss), net of tax | 74 | (273 | ) | 76 | (454 | ) | |||||||||
Comprehensive income | 569 | 146 | 1,237 | 540 | |||||||||||
Comprehensive income attributable to noncontrolling interests | 7 | 7 | 16 | 15 | |||||||||||
Comprehensive income attributable to MEHC shareholders | $ | 562 | $ | 139 | $ | 1,221 | $ | 525 |
The accompanying notes are an integral part of these consolidated financial statements.
5
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)
(Amounts in millions)
MEHC Shareholders' Equity | ||||||||||||||||||||||||||
Accumulated | ||||||||||||||||||||||||||
Additional | Other | |||||||||||||||||||||||||
Common | Paid-in | Retained | Comprehensive | Noncontrolling | Total | |||||||||||||||||||||
Shares | Stock | Capital | Earnings | Loss, Net | Interests | Equity | ||||||||||||||||||||
Balance at December 31, 2010 | 75 | $ | — | $ | 5,427 | $ | 7,979 | $ | (174 | ) | $ | 176 | $ | 13,408 | ||||||||||||
Net income | — | — | — | 979 | — | 15 | 994 | |||||||||||||||||||
Other comprehensive loss | — | — | — | — | (454 | ) | — | (454 | ) | |||||||||||||||||
Distributions | — | — | — | — | — | (19 | ) | (19 | ) | |||||||||||||||||
Other equity transactions | — | — | (4 | ) | — | — | 1 | (3 | ) | |||||||||||||||||
Balance at September 30, 2011 | 75 | $ | — | $ | 5,423 | $ | 8,958 | $ | (628 | ) | $ | 173 | $ | 13,926 | ||||||||||||
Balance at December 31, 2011 | 75 | $ | — | $ | 5,423 | $ | 9,310 | $ | (641 | ) | $ | 173 | $ | 14,265 | ||||||||||||
Net income | — | — | — | 1,145 | — | 16 | 1,161 | |||||||||||||||||||
Other comprehensive income | — | — | — | — | 76 | — | 76 | |||||||||||||||||||
Distributions | — | — | — | — | — | (18 | ) | (18 | ) | |||||||||||||||||
Balance at September 30, 2012 | 75 | $ | — | $ | 5,423 | $ | 10,455 | $ | (565 | ) | $ | 171 | $ | 15,484 |
The accompanying notes are an integral part of these consolidated financial statements.
6
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
Nine-Month Periods | |||||||
Ended September 30, | |||||||
2012 | 2011 | ||||||
Cash flows from operating activities: | |||||||
Net income | $ | 1,161 | $ | 994 | |||
Adjustments to reconcile net income to net cash flows from operating activities: | |||||||
Depreciation and amortization | 1,086 | 997 | |||||
Changes in regulatory assets and liabilities | (26 | ) | (7 | ) | |||
Deferred income taxes and amortization of investment tax credits | 655 | 475 | |||||
Other, net | (55 | ) | (54 | ) | |||
Changes in other operating assets and liabilities, net of effects from acquisitions: | |||||||
Trade receivables and other assets | 24 | 60 | |||||
Derivative collateral, net | 64 | 32 | |||||
Contributions to pension and other postretirement benefit plans, net | (107 | ) | (132 | ) | |||
Accrued property, income and other taxes | 824 | 395 | |||||
Accounts payable and other liabilities | 56 | (43 | ) | ||||
Net cash flows from operating activities | 3,682 | 2,717 | |||||
Cash flows from investing activities: | |||||||
Capital expenditures | (2,349 | ) | (1,912 | ) | |||
Acquisitions, net of cash acquired | (110 | ) | — | ||||
Purchases of available-for-sale securities | (84 | ) | (105 | ) | |||
Proceeds from sales of available-for-sale securities | 69 | 102 | |||||
Equity method investments | (310 | ) | (72 | ) | |||
Increase in restricted cash and investments | (45 | ) | (7 | ) | |||
Other, net | 12 | 1 | |||||
Net cash flows from investing activities | (2,817 | ) | (1,993 | ) | |||
Cash flows from financing activities: | |||||||
Proceeds from subsidiary debt | 2,199 | 790 | |||||
Repayments of subsidiary debt | (450 | ) | (601 | ) | |||
Repayments of MEHC senior and subordinated debt | (272 | ) | (122 | ) | |||
Net repayments of short-term debt | (715 | ) | (320 | ) | |||
Other, net | (58 | ) | (36 | ) | |||
Net cash flows from financing activities | 704 | (289 | ) | ||||
Effect of exchange rate changes | 5 | 1 | |||||
Net change in cash and cash equivalents | 1,574 | 436 | |||||
Cash and cash equivalents at beginning of period | 286 | 470 | |||||
Cash and cash equivalents at end of period | $ | 1,860 | $ | 906 |
The accompanying notes are an integral part of these consolidated financial statements.
7
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) | General |
MidAmerican Energy Holdings Company ("MEHC") is a holding company that owns subsidiaries principally engaged in energy businesses (collectively with its subsidiaries, the "Company"). MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The Company's operations are organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding, LLC ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), Northern Natural Gas Company ("Northern Natural Gas"), Kern River Gas Transmission Company ("Kern River"), Northern Powergrid Holdings Company ("Northern Powergrid Holdings") (which primarily consists of Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc), CalEnergy Philippines (which owns a majority interest in the Casecnan project in the Philippines), MidAmerican Renewables, LLC (which owns interests in independent power projects in the United States), and HomeServices of America, Inc. (collectively with its subsidiaries, "HomeServices"). Through these platforms, the Company owns and operates an electric utility company in the Western United States, an electric and natural gas utility company in the Midwestern United States, two interstate natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of independent power projects and the second largest residential real estate brokerage firm in the United States. Northern Natural Gas and Kern River have been aggregated in the reportable segment called MidAmerican Energy Pipeline Group, and CalEnergy Philippines and MidAmerican Renewables, LLC have been aggregated in the reportable segment called MidAmerican Renewables.
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 Consolidated Financial Statements as of September 30, 2012 and for the three- and nine-month periods ended September 30, 2012 and 2011. The results of operations for the three- and nine-month periods ended September 30, 2012 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 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 the Company's Annual Report on Form 10-K for the year ended December 31, 2011 describes the most significant accounting policies used in the preparation of the Consolidated Financial Statements. There have been no significant changes in the Company's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2012.
(2) | New Accounting Pronouncements |
In December 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2011-11, which amends FASB Accounting Standards Codification ("ASC") Topic 210, "Balance Sheet." The amendments in this guidance require an entity to provide quantitative disclosures about offsetting financial instruments and derivative instruments. Additionally, this guidance requires qualitative and quantitative disclosures about master netting agreements or similar agreements when the financial instruments and derivative instruments are not offset. This guidance is effective for fiscal years beginning on or after January 1, 2013, and for interim periods within those fiscal years. The Company is currently evaluating the impact of adopting this guidance on its disclosures included within Notes to Consolidated Financial Statements.
8
In June 2011, the FASB issued ASU No. 2011-05, which amends FASB ASC Topic 220, "Comprehensive Income." ASU No. 2011-05 provides an entity with the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. Regardless of the option chosen, this guidance also requires presentation of items on the face of the financial statements that are reclassified from other comprehensive income to net income. This guidance does not change the items that must be reported in other comprehensive income, when an item of other comprehensive income must be reclassified to net income or how tax effects of each item of other comprehensive income are presented. This guidance is effective for interim and annual reporting periods beginning after December 15, 2011. In December 2011, the FASB issued ASU No. 2011-12, which also amends FASB ASC Topic 220 to defer indefinitely the ASU No. 2011-05 requirement to present items on the face of the financial statements that are reclassified from other comprehensive income to net income. ASU No. 2011-12 is also effective for interim and annual reporting periods beginning after December 15, 2011. The Company adopted this guidance on January 1, 2012 and elected the two separate but consecutive statements option.
In May 2011, the FASB issued ASU No. 2011-04, which amends FASB ASC Topic 820, "Fair Value Measurements and Disclosures." The amendments in this guidance are not intended to result in a change in current accounting. ASU No. 2011-04 requires additional disclosures relating to fair value measurements categorized within Level 3 of the fair value hierarchy, including quantitative information about unobservable inputs, the valuation process used by the entity and the sensitivity of unobservable input measurements. Additionally, entities are required to disclose the level of the fair value hierarchy for assets and liabilities that are not measured at fair value in the balance sheet, but for which disclosure of the fair value is required. This guidance is effective for interim and annual reporting periods beginning after December 15, 2011. The Company adopted ASU No. 2011-04 on January 1, 2012. The adoption of this guidance did not have a material impact on the Company'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 | |||||||||
Depreciable | September 30, | December 31, | |||||||
Life | 2012 | 2011 | |||||||
Regulated assets: | |||||||||
Utility generation, distribution and transmission system | 5-80 years | $ | 41,813 | $ | 40,180 | ||||
Interstate pipeline assets | 3-80 years | 6,323 | 6,245 | ||||||
48,136 | 46,425 | ||||||||
Accumulated depreciation and amortization | (15,125 | ) | (14,390 | ) | |||||
Regulated assets, net | 33,011 | 32,035 | |||||||
Nonregulated assets: | |||||||||
Independent power plants | 5-30 years | 677 | 677 | ||||||
Other assets | 3-30 years | 452 | 429 | ||||||
1,129 | 1,106 | ||||||||
Accumulated depreciation and amortization | (575 | ) | (533 | ) | |||||
Nonregulated assets, net | 554 | 573 | |||||||
Net operating assets | 33,565 | 32,608 | |||||||
Construction work-in-progress | 2,639 | 1,559 | |||||||
Property, plant and equipment, net | $ | 36,204 | $ | 34,167 |
Construction work-in-progress includes $2.0 billion and $1.6 billion as of September 30, 2012 and December 31, 2011, respectively, related to the construction of regulated assets.
9
Through October 2012, the Company completed various acquisitions totaling $235 million. The purchase price for each acquisition was allocated to the assets acquired, which relate primarily to development and construction costs for the Topaz solar project ("Topaz Project") and the Bishop Hill II wind-powered generation project ("Bishop Hill Project"), and intangible franchise contracts and goodwill for a real estate brokerage franchise business and several real estate brokerage businesses. There were no material liabilities assumed.
In September 2012, MidAmerican Renewables, through wholly-owned subsidiaries, signed a definitive agreement, subject to conditions precedent, to acquire all of the equity interests in two project companies that own the 168-MW Alta Wind VII and the 132-MW Alta Wind IX wind-powered generation projects ("Alta Wind Projects"), located in California, which are expected to be placed in service in 2012. Once completed, the Alta Wind Projects will sell all of their generation to Southern California Edison pursuant to the terms of power purchase agreements that extend to 2035. These transactions are expected to close in 2012.
(4) | Fair Value Measurements |
The carrying value of the Company'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. The Company 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 the Company 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 the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data. |
The following table presents the Company'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, 2012 | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
Commodity derivatives | $ | 1 | $ | 82 | $ | 19 | $ | (69 | ) | $ | 33 | |||||||||
Money market mutual funds(2) | 865 | — | — | — | 865 | |||||||||||||||
Debt securities: | ||||||||||||||||||||
United States government obligations | 103 | — | — | — | 103 | |||||||||||||||
International government obligations | — | 1 | — | — | 1 | |||||||||||||||
Corporate obligations | — | 30 | — | — | 30 | |||||||||||||||
Municipal obligations | — | 6 | — | — | 6 | |||||||||||||||
Agency, asset and mortgage-backed obligations | — | 7 | — | — | 7 | |||||||||||||||
Auction rate securities | — | — | 38 | — | 38 | |||||||||||||||
Equity securities: | ||||||||||||||||||||
United States companies | 187 | — | — | — | 187 | |||||||||||||||
International companies | 394 | — | — | — | 394 | |||||||||||||||
Investment funds | 69 | — | — | — | 69 | |||||||||||||||
$ | 1,619 | $ | 126 | $ | 57 | $ | (69 | ) | $ | 1,733 | ||||||||||
Liabilities - commodity derivatives | $ | (11 | ) | $ | (360 | ) | $ | (7 | ) | $ | 147 | $ | (231 | ) |
10
Input Levels for Fair Value Measurements | ||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other(1) | Total | ||||||||||||||||
As of December 31, 2011 | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
Commodity derivatives | $ | 1 | $ | 166 | $ | 27 | $ | (147 | ) | $ | 47 | |||||||||
Money market mutual funds(2) | 164 | — | — | — | 164 | |||||||||||||||
Debt securities: | ||||||||||||||||||||
United States government obligations | 89 | — | — | — | 89 | |||||||||||||||
International government obligations | — | 1 | — | — | 1 | |||||||||||||||
Corporate obligations | — | 30 | — | — | 30 | |||||||||||||||
Municipal obligations | — | 12 | — | — | 12 | |||||||||||||||
Agency, asset and mortgage-backed obligations | — | 7 | — | — | 7 | |||||||||||||||
Auction rate securities | — | — | 35 | — | 35 | |||||||||||||||
Equity securities: | ||||||||||||||||||||
United States companies | 166 | — | — | — | 166 | |||||||||||||||
International companies | 489 | — | — | — | 489 | |||||||||||||||
Investment funds | 64 | — | — | — | 64 | |||||||||||||||
$ | 973 | $ | 216 | $ | 62 | $ | (147 | ) | $ | 1,104 | ||||||||||
Liabilities - commodity derivatives | $ | (37 | ) | $ | (598 | ) | $ | (4 | ) | $ | 303 | $ | (336 | ) |
(1) | Represents netting under master netting arrangements and a net cash collateral receivable of $78 million and $156 million as of September 30, 2012 and December 31, 2011, respectively. |
(2) | Amounts are included in cash and cash equivalents; current investments and restricted cash and investments; and noncurrent investments and restricted cash and investments 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 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 the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company 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 the Company. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company'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 due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company 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 5 for further discussion regarding the Company's risk management and hedging activities.
The Company's investments in money market mutual funds and debt and equity securities are accounted for as available-for-sale securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics. The fair value of the Company's investments in auction rate securities, where there is no current liquid market, is determined using pricing models based on available observable market data and the Company's judgment about the assumptions, including liquidity and nonperformance risks, which market participants would use when pricing the asset.
11
The following table reconciles the beginning and ending balances of the Company's assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
Three-Month Periods | Nine-Month Periods | ||||||||||||||
Ended September 30, | Ended September 30, | ||||||||||||||
Auction | Auction | ||||||||||||||
Commodity | Rate | Commodity | Rate | ||||||||||||
Derivatives | Securities | Derivatives | Securities | ||||||||||||
2012 | |||||||||||||||
Beginning balance | $ | 17 | $ | 36 | $ | 23 | $ | 35 | |||||||
Changes included in earnings(1) | (2 | ) | — | 7 | — | ||||||||||
Changes in fair value recognized in other comprehensive income | — | 2 | 3 | 4 | |||||||||||
Changes in fair value recognized in net regulatory assets | (3 | ) | — | — | — | ||||||||||
Sales | — | — | — | (1 | ) | ||||||||||
Settlements | — | — | (21 | ) | — | ||||||||||
Ending balance | $ | 12 | $ | 38 | $ | 12 | $ | 38 |
2011 | |||||||||||||||
Beginning balance | $ | (233 | ) | $ | 37 | $ | (331 | ) | $ | 50 | |||||
Changes included in earnings(1) | 6 | — | 10 | — | |||||||||||
Changes in fair value recognized in other comprehensive income | — | (2 | ) | — | — | ||||||||||
Changes in fair value recognized in net regulatory assets | 4 | — | 87 | — | |||||||||||
Sales | — | — | — | (15 | ) | ||||||||||
Settlements | 15 | — | 26 | — | |||||||||||
Transfers from Level 2 | 1 | — | 1 | — | |||||||||||
Ending balance | $ | (207 | ) | $ | 35 | $ | (207 | ) | $ | 35 |
(1) | Changes included in earnings are reported as operating revenue on the Consolidated Statements of Operations. For commodity derivatives held as of September 30, 2012 and 2011, net unrealized (losses) gains included in earnings for the three-month periods ended September 30, 2012 and 2011 totaled $(2) million and $4 million, respectively, and for the nine-month periods ended September 30, 2012 and 2011, totaled $3 million and $5 million, respectively. |
The Company's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of the Company'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 the Company'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 the Company's long-term debt (in millions):
As of September 30, 2012 | As of December 31, 2011 | ||||||||||||||
Carrying | Fair | Carrying | Fair | ||||||||||||
Value | Value | Value | Value | ||||||||||||
Long-term debt | $ | 20,956 | $ | 25,417 | $ | 19,072 | $ | 23,327 |
12
(5) | Risk Management and Hedging Activities |
The Company is exposed to the impact of market fluctuations in commodity prices, interest rates and foreign currency exchange rates. The Company is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk primarily through MEHC's ownership of the Utilities as they have an obligation to serve retail customer load in their regulated service territories. MidAmerican Energy also provides nonregulated retail electricity and natural gas services in competitive markets. The Utilities' 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, wholesale electricity that is purchased and sold, and natural gas supply for retail customers. 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. Additionally, the Company is exposed to foreign currency exchange rate risk from its business operations and investments in Great Britain. The Company does not engage in a material amount of proprietary trading activities.
Each of the Company's business platforms 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, the Company uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. The Company 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, the Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate the Company's exposure to interest rate risk. The Company does not hedge all of its commodity price, interest rate and foreign currency exchange rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in the Company's accounting policies related to derivatives. Refer to Note 4 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 the Company'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, 2012 | |||||||||||||||||||
Not designated as hedging contracts(1): | |||||||||||||||||||
Commodity assets | $ | 28 | $ | 8 | $ | 48 | $ | 8 | $ | 92 | |||||||||
Commodity liabilities | (7 | ) | (2 | ) | (206 | ) | (126 | ) | (341 | ) | |||||||||
Total | 21 | 6 | (158 | ) | (118 | ) | (249 | ) | |||||||||||
Designated as hedging contracts: | |||||||||||||||||||
Commodity assets | 6 | — | 3 | 1 | 10 | ||||||||||||||
Commodity liabilities | — | — | (22 | ) | (15 | ) | (37 | ) | |||||||||||
Total | 6 | — | (19 | ) | (14 | ) | (27 | ) | |||||||||||
Total derivatives | 27 | 6 | (177 | ) | (132 | ) | (276 | ) | |||||||||||
Cash collateral (payable) receivable | — | — | 71 | 7 | 78 | ||||||||||||||
Total derivatives - net basis | $ | 27 | $ | 6 | $ | (106 | ) | $ | (125 | ) | $ | (198 | ) |
13
Other | Other | Other | |||||||||||||||||
Current | Other | Current | Long-term | ||||||||||||||||
Assets | Assets | Liabilities | Liabilities | Total | |||||||||||||||
As of December 31, 2011 | |||||||||||||||||||
Not designated as hedging contracts(1): | |||||||||||||||||||
Commodity assets | $ | 93 | $ | 14 | $ | 73 | $ | 13 | $ | 193 | |||||||||
Commodity liabilities | (47 | ) | (5 | ) | (324 | ) | (216 | ) | (592 | ) | |||||||||
Total | 46 | 9 | (251 | ) | (203 | ) | (399 | ) | |||||||||||
Designated as hedging contracts: | |||||||||||||||||||
Commodity assets | — | — | 1 | — | 1 | ||||||||||||||
Commodity liabilities | (6 | ) | — | (24 | ) | (17 | ) | (47 | ) | ||||||||||
Total | (6 | ) | — | (23 | ) | (17 | ) | (46 | ) | ||||||||||
Total derivatives | 40 | 9 | (274 | ) | (220 | ) | (445 | ) | |||||||||||
Cash collateral (payable) receivable | (2 | ) | — | 114 | 44 | 156 | |||||||||||||
Total derivatives - net basis | $ | 38 | $ | 9 | $ | (160 | ) | $ | (176 | ) | $ | (289 | ) |
(1) | The Company's commodity derivatives not designated as hedging contracts are generally included in regulated rates, and as of September 30, 2012 and December 31, 2011, a net regulatory asset of $249 million and $400 million, respectively, was recorded related to the net derivative liability of $249 million and $399 million, respectively. |
Not Designated as Hedging Contracts
The following table reconciles the beginning and ending balances of the Company's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings (in millions):
Three-Month Periods | Nine-Month Periods | ||||||||||||||
Ended September 30, | Ended September 30, | ||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||
Beginning balance | $ | 357 | $ | 498 | $ | 400 | $ | 564 | |||||||
Changes in fair value recognized in net regulatory assets | (31 | ) | 81 | 42 | 19 | ||||||||||
Net gains (losses) reclassified to operating revenue | 10 | (6 | ) | 51 | 2 | ||||||||||
Net losses reclassified to cost of sales | (87 | ) | (56 | ) | (244 | ) | (68 | ) | |||||||
Ending balance | $ | 249 | $ | 517 | $ | 249 | $ | 517 |
Designated as Hedging Contracts
The Company uses derivative contracts accounted for as cash flow hedges to hedge electricity and natural gas commodity prices for delivery to nonregulated customers, spring operational sales, natural gas storage and other transactions.
14
The following table reconciles the beginning and ending balances of the Company's accumulated other comprehensive loss (pre-tax) and summarizes pre-tax gains and losses on derivative contracts designated and qualifying as cash flow hedges recognized in other comprehensive income ("OCI"), as well as amounts reclassified to earnings (in millions):
Three-Month Periods | Nine-Month Periods | ||||||||||||||
Ended September 30, | Ended September 30, | ||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||
Beginning balance(1) | $ | 49 | $ | 15 | $ | 46 | $ | 37 | |||||||
Changes in fair value recognized in OCI | (18 | ) | (12 | ) | 12 | (26 | ) | ||||||||
Net gains reclassified to operating revenue | — | 1 | — | 2 | |||||||||||
Net (losses) gains reclassified to cost of sales | (4 | ) | 3 | (31 | ) | (6 | ) | ||||||||
Ending balance(1) | $ | 27 | $ | 7 | $ | 27 | $ | 7 |
(1) | Certain derivative contracts, principally interest rate locks, have settled and the fair value at the date of settlement remains in accumulated other comprehensive income ("AOCI") and is recognized in earnings when the forecasted transactions impact earnings. |
Realized gains and losses on hedges and hedge ineffectiveness are recognized in income as operating revenue, cost of sales, operating expense or interest expense depending upon the nature of the item being hedged. For the three- and nine-month periods ended September 30, 2012 and 2011, hedge ineffectiveness was insignificant. As of September 30, 2012, the Company had cash flow hedges with expiration dates extending through May 2032 and $19 million of pre-tax net unrealized losses are forecasted to be reclassified from AOCI into earnings over the next twelve months as contracts settle.
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 | 2012 | 2011 | |||||
Electricity (sales) purchases | Megawatt hours | (2 | ) | 6 | |||
Natural gas purchases | Decatherms | 136 | 183 | ||||
Fuel purchases | Gallons | 4 | 19 |
Credit Risk
The Utilities extend unsecured credit to other utilities, energy marketing companies, financial institutions and other market participants in conjunction with their 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.
The Utilities analyze the financial condition of each significant wholesale counterparty before entering into any transactions, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on an ongoing basis. To mitigate exposure to the financial risks of wholesale counterparties, the Utilities enter into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed fees for delayed payments. If required, the Utilities exercise rights under these arrangements, including calling on the counterparty's credit support arrangement.
15
MidAmerican Energy also has potential indirect credit exposure to other market participants in the regional transmission organization ("RTO") markets where it actively participates, including the Midwest Independent Transmission System Operator, Inc. and the PJM Interconnection, L.L.C. In the event of a default by a RTO market participant on its market-related obligations, losses are allocated among all other market participants in proportion to each participant's share of overall market activity during the period of time the loss was incurred, diversifying MidAmerican Energy's exposure to credit losses from individual participants. Transactional activities of MidAmerican Energy and other participants in organized RTO markets are governed by credit policies specified in each respective RTO's governing tariff or related business practices. Credit policies of RTO's, which have been developed through extensive stakeholder participation, generally seek to minimize potential loss in the event of a market participant default without unnecessarily inhibiting access to the marketplace. MidAmerican Energy's share of historical losses from defaults by other RTO market participants has not been material.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale derivative contracts contain provisions that require MEHC's subsidiaries, principally the Utilities, to maintain specific credit ratings from one or more of the major credit rating agencies on their unsecured debt. 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 the subsidiary's creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2012, these subsidiaries' credit ratings from the three recognized credit rating agencies were investment grade.
The aggregate fair value of the Company's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $344 million and $571 million as of September 30, 2012 and December 31, 2011, respectively, for which the Company had posted collateral of $68 million and $125 million, respectively, in the form of cash deposits and letters of credit. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of September 30, 2012 and December 31, 2011, the Company would have been required to post $222 million and $332 million, respectively, of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
16
(6) | Investments and Restricted Cash and Investments |
Investments and restricted cash and investments consists of the following (in millions):
As of | |||||||
September 30, | December 31, | ||||||
2012 | 2011 | ||||||
Investments: | |||||||
BYD Company Limited common stock | $ | 392 | $ | 488 | |||
Rabbi trusts | 308 | 290 | |||||
Other | 105 | 99 | |||||
Total investments | 805 | 877 | |||||
Equity method investments: | |||||||
Electric Transmission Texas, LLC | 317 | 221 | |||||
CE Generation, LLC | 248 | 255 | |||||
Bridger Coal Company | 195 | 204 | |||||
Agua Caliente Solar, LLC | 62 | — | |||||
Other | 65 | 52 | |||||
Total equity method investments | 887 | 732 | |||||
Restricted cash and investments: | |||||||
Nuclear decommissioning trust funds | 338 | 308 | |||||
Other | 127 | 82 | |||||
Total restricted cash and investments | 465 | 390 | |||||
Total investments and restricted cash and investments | 2,157 | 1,999 | |||||
Less current portion | (81 | ) | (51 | ) | |||
Noncurrent portion | $ | 2,076 | $ | 1,948 |
Investments
MEHC's investment in BYD Company Limited common stock is accounted for as an available-for-sale security with changes in fair value recognized in AOCI. As of September 30, 2012 and December 31, 2011, the fair value of MEHC's investment in BYD Company Limited common stock was $392 million and $488 million, respectively, which resulted in a pre-tax unrealized gain of $160 million and $256 million as of September 30, 2012 and December 31, 2011, respectively.
Equity Method Investments
In January 2012, MEHC, through an indirect wholly-owned subsidiary, acquired from NRG Energy, Inc. a 49% equity interest in Agua Caliente Solar, LLC ("Agua Caliente"), the developer and owner of a solar project in Arizona. As of September 30, 2012, the equity investment is net of investment tax credits totaling $164 million.
17
(7) | Recent Financing Transactions |
Long-Term Debt
In January 2012, PacifiCorp issued $350 million of its 2.95% First Mortgage Bonds due February 2022 and $300 million of its 4.10% First Mortgage Bonds due February 2042. The net proceeds were used to repay short-term debt, fund capital expenditures and for general corporate purposes. In March 2012, PacifiCorp issued an additional $100 million of its 2.95% First Mortgage Bonds due February 2022. The net proceeds were used to redeem $84 million of tax-exempt bond obligations prior to scheduled maturity with a weighted average interest rate of 5.7%, repay short-term debt and for general corporate purposes.
In February 2012, Topaz Solar Farms, LLC ("Topaz") issued $850 million of the 5.75% Series A Senior Secured Notes. The principal of the notes amortize beginning September 2015 with a final maturity in September 2039. The net proceeds will be used to fund the costs and expenses related to the development, construction and financing of the Topaz Project. Any unused amounts will be invested or, in certain circumstances, loaned to MEHC. As of September 30, 2012, $421 million was loaned to MEHC.
In June 2012, MidAmerican Energy redeemed $275 million of its 5.125% Senior Notes due January 2013 at a redemption price determined in accordance with the terms of the indenture.
In July 2012, Northern Powergrid (Yorkshire) plc issued £150 million of its 4.375% Bonds due July 2032. The net proceeds will be used for general corporate purposes.
In August 2012, Northern Natural Gas issued $250 million of its 4.10% Senior Bonds due September 2042. The net proceeds were used to partially repay its $300 million, 5.375% Senior Notes due October 2012.
In August 2012, Bishop Hill issued $120 million of its 5.125% Senior Secured Fixed Rate Notes. The principal of the notes amortize beginning March 2013 with a final maturity in March 2032. The net proceeds will be used to fund the costs and expenses related to the development, construction and financing of the Bishop Hill Project.
In conjunction with the construction of wind-powered generating facilities in 2012, MidAmerican Energy has accrued as construction work-in-progress amounts it is not contractually obligated to pay until December 2015. The amounts ultimately payable are discounted at 1.43% and recognized upon delivery of the equipment as long-term debt. The discount is being amortized as interest expense over the period until payment is due using the effective interest method. As of September 30, 2012, $306 million of such debt from the 2012 wind-powered generation projects, net of associated discount, was outstanding.
Credit Facilities
In August 2012, Northern Powergrid Holdings replaced its existing £150 million unsecured credit facility expiring in March 2013 with a £150 million unsecured credit facility expiring in August 2017. The replacement credit facility has a variable interest rate based on the sterling London Interbank Offered Rate ("LIBOR") plus a spread that varies based on its credit ratings. This facility is for general corporate purposes. As of September 30, 2012, Northern Powergrid Holdings had no borrowings outstanding under this credit facility. The credit facility requires that Northern Powergrid Holdings' ratio of consolidated senior total net debt, including current maturities, to regulated asset value not exceed 0.8 to 1.0 at Northern Powergrid Holdings and 0.65 to 1.0 at Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc as of June 30 and December 31. Additionally, Northern Powergrid Holdings' interest coverage ratio shall not be less than 2.5 to 1.0.
In June 2012, MEHC entered into a $600 million senior unsecured credit facility expiring in June 2017. The credit facility has a variable interest rate based on LIBOR or a base rate, at MEHC's option, plus a spread that varies based on MEHC's credit ratings for its senior unsecured long-term debt securities. This facility is for general corporate purposes and also supports commercial paper and letters of credit for the benefit of certain subsidiaries and affiliates. As of September 30, 2012, MEHC had $140 million of commercial paper borrowings outstanding at an average rate of 0.4%. The credit facility requires that MEHC's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.70 to 1.0 as of the last day of each quarter. This facility, along with its existing $479 million senior unsecured credit facility expiring in July 2013, supports MEHC's $1 billion commercial paper program.
18
In June 2012, PacifiCorp replaced its existing $635 million unsecured credit facility expiring in October 2012 with a $600 million unsecured credit facility expiring in June 2017. The replacement credit facility has a variable interest rate based on LIBOR or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities. This facility is for general corporate purposes including supporting PacifiCorp's commercial paper program and provides for the issuance of letters of credit. As of September 30, 2012, PacifiCorp had no borrowings outstanding under this credit facility. The credit facility requires that PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.
In connection with its offering, Topaz entered into a letter of credit and reimbursement facility in an aggregate principal amount of $345 million. Letters of credit issued under the letter of credit facility will be used to (a) provide security under the power purchase agreement and large generator interconnection agreements, (b) fund the debt service reserve requirement and the operation and maintenance debt service reserve requirement, (c) provide security for remediation and mitigation liabilities, and (d) provide security in respect of conditional use permit sales tax obligations. As of September 30, 2012, Topaz had $56 million of letters of credit issued under this facility.
Pursuant to an equity funding and contribution agreement, MEHC has committed to provide Agua Caliente with funding for (a) base equity contributions of up to an aggregate amount of $303 million for the construction of the Agua Caliente Project, and (b) transmission upgrade costs. In January 2012, MEHC entered into a $303 million letter of credit facility related to its funding commitments. The equity funding and contribution agreement and the letter of credit commitment decreases as equity is contributed to the Agua Caliente Project. As of September 30, 2012, the balance of the commitment was $169 million.
(8) | Employee Benefit Plans |
Domestic Operations
Net periodic benefit cost for the domestic pension and other postretirement benefit plans included the following components (in millions):
Three-Month Periods | Nine-Month Periods | ||||||||||||||
Ended September 30, | Ended September 30, | ||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||
Pension: | |||||||||||||||
Service cost | $ | 6 | $ | 6 | $ | 19 | $ | 20 | |||||||
Interest cost | 24 | 26 | 72 | 78 | |||||||||||
Expected return on plan assets | (30 | ) | (29 | ) | (89 | ) | (88 | ) | |||||||
Net amortization | 10 | 6 | 29 | 15 | |||||||||||
Net periodic benefit cost | $ | 10 | $ | 9 | $ | 31 | $ | 25 | |||||||
Other postretirement: | |||||||||||||||
Service cost | $ | 3 | $ | 3 | $ | 8 | $ | 8 | |||||||
Interest cost | 9 | 10 | 27 | 31 | |||||||||||
Expected return on plan assets | (11 | ) | (12 | ) | (32 | ) | (33 | ) | |||||||
Net amortization | 1 | 4 | 1 | 12 | |||||||||||
Net periodic benefit cost | $ | 2 | $ | 5 | $ | 4 | $ | 18 |
Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $114 million and $9 million, respectively, during 2012. As of September 30, 2012, $111 million and $4 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.
19
Foreign Operations
Net periodic benefit cost for the United Kingdom pension plan included the following components (in millions):
Three-Month Periods | Nine-Month Periods | ||||||||||||||
Ended September 30, | Ended September 30, | ||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||
Service cost | $ | 5 | $ | 5 | $ | 15 | $ | 15 | |||||||
Interest cost | 21 | 24 | 64 | 70 | |||||||||||
Expected return on plan assets | (26 | ) | (29 | ) | (79 | ) | (87 | ) | |||||||
Net amortization | 11 | 9 | 33 | 27 | |||||||||||
Net periodic benefit cost | $ | 11 | $ | 9 | $ | 33 | $ | 25 |
Employer contributions to the United Kingdom pension plan are expected to be £50 million during 2012. As of September 30, 2012, £38 million, or $59 million, of contributions had been made to the United Kingdom pension plan.
(9) | Income Taxes |
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:
Three-Month Periods | Nine-Month Periods | ||||||||||
Ended September 30, | Ended September 30, | ||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||
Federal statutory income tax rate | 35 | % | 35 | % | 35 | % | 35 | % | |||
Federal and state income tax credits | (16 | ) | (13 | ) | (13 | ) | (11 | ) | |||
State income tax, net of federal income tax benefit | 2 | 2 | 2 | 2 | |||||||
Change in United Kingdom corporate income tax rate | (7 | ) | (9 | ) | (3 | ) | (3 | ) | |||
Income tax effect of foreign income | (3 | ) | (2 | ) | (2 | ) | (2 | ) | |||
Effects of ratemaking | (2 | ) | (1 | ) | (3 | ) | (1 | ) | |||
Other, net | — | 3 | (1 | ) | 1 | ||||||
Effective income tax rate | 9 | % | 15 | % | 15 | % | 21 | % |
Federal and state income tax credits primarily relate to production tax credits at the Utilities. The Utilities' wind-powered generating facilities are eligible for federal renewable electricity production tax credits for 10 years from the date the facilities were placed in service.
In July 2012, the Company recognized $38 million of deferred income tax benefits upon the enactment of a reduction in the United Kingdom corporate income tax rate from 25% to 24% effective April 1, 2012, and a further reduction to 23% effective April 1, 2013. In July 2011, the Company recognized $40 million of deferred income tax benefits upon the enactment of a reduction in the United Kingdom corporate income tax rate from 27% to 26% effective April 1, 2011, and a further reduction to 25% effective April 1, 2012.
Berkshire Hathaway includes the Company in its United States federal income tax return. As of September 30, 2012, the Company had income taxes payable to Berkshire Hathaway of $341 million and as of December 31, 2011, the Company had income taxes receivable from Berkshire Hathaway of $456 million.
20
(10) | Commitments and Contingencies |
Legal Matters
The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. The Company 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 MEHC'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 on two of its five claims. In May 2010, the Utah Supreme Court remanded the case back to the Third District Court for further consideration, which led to a trial that began in April 2012. On May 21, 2012, the jury reached a verdict in favor of the Plaintiff on both claims. The jury awarded the Plaintiff breach of contract damages of $18 million and unjust enrichment damages of $113 million against PacifiCorp; however, a final judgment has not been rendered on the verdict. On May 24, 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. On October 15, 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. PacifiCorp strongly disagrees with the verdict and will aggressively pursue available options in an effort to vacate or reduce the verdict, including, if necessary, appellate measures. If the judge grants either of PacifiCorp's post-trial motions, then the Plaintiff's motions for exemplary damages and attorneys' fees will be moot. If the judge does not grant either of PacifiCorp's post-trial motions, then the judge will set a schedule for PacifiCorp to respond to the Plaintiff's motions for exemplary damages and attorneys' fees. In the event the judge does not grant either of PacifiCorp's post-trial motions, PacifiCorp expects a decision on the Plaintiff's motions for exemplary damages and attorneys' fees in 2013. PacifiCorp believes there is meritorious basis for such post-trial motions and appeal. PacifiCorp has accrued its estimated liability as of September 30, 2012, and believes the ultimate outcome of the case will not be material to PacifiCorp's consolidated financial results; however this matter could have a material effect on PacifiCorp's consolidated financial results in the event of an unfavorable outcome. Any payment of damages will be at the end of the appeal process, which could take several years.
Environmental Laws and Regulations
The Company is subject to federal, state, local and foreign 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 the Company's current and future operations. The Company believes it is in material compliance with all applicable laws and regulations.
Hydroelectric Relicensing
PacifiCorp's Klamath hydroelectric system is currently operating under annual licenses with the Federal Energy Regulatory Commission ("FERC"). In February 2010, PacifiCorp, the United States Department of the Interior, the United States Department of Commerce, the State of California, the State of Oregon and various other governmental and non-governmental settlement parties signed the Klamath Hydroelectric Settlement Agreement ("KHSA"). Among other things, the KHSA provides that the United States Department of the Interior conduct scientific and engineering studies to assess whether removal of the Klamath hydroelectric system's mainstem dams is in the public interest and will advance restoration of the Klamath Basin's salmonid fisheries. If it is determined that dam removal should proceed, dam removal is expected to commence no earlier than 2020.
21
Under the KHSA, PacifiCorp and its customers are protected from uncapped dam removal costs and liabilities. For dam removal to occur, federal legislation consistent with the KHSA must be enacted to provide, among other things, protection for PacifiCorp from all liabilities associated with dam removal activities. If Congress does not enact legislation, then PacifiCorp will resume relicensing with the FERC. In November 2011, bills were introduced in both chambers of the United States Congress that, if passed, would enact the KHSA and a companion agreement that seeks to resolve other water-related conflicts and restore habitat in the Klamath basin.
In addition, the KHSA limits PacifiCorp's contribution to dam removal costs to no more than $200 million, of which up to $184 million would be collected from PacifiCorp's Oregon customers with the remainder to be collected from PacifiCorp's California customers. An additional $250 million for dam removal costs is expected to be raised through a California bond measure or other appropriate State of California financing mechanism. If dam removal costs exceed $200 million and if the State of California is unable to raise the additional funds necessary for dam removal costs, sufficient funds would need to be provided by an entity other than PacifiCorp in order for the KHSA and dam removal to proceed.
PacifiCorp has begun collection of surcharges from Oregon customers for their share of dam removal costs, as approved by the Oregon Public Utility Commission ("OPUC"), and is depositing the proceeds into trust accounts maintained by the OPUC. PacifiCorp has begun collection of surcharges from California customers for their share of dam removal costs, as approved by the California Public Utilities Commission ("CPUC"), and is depositing the proceeds into trust accounts maintained by the CPUC. PacifiCorp is authorized to collect the surcharges through 2019.
As of September 30, 2012, PacifiCorp's assets included $118 million of costs associated with the Klamath hydroelectric system's mainstem dams and the associated relicensing and settlement costs. PacifiCorp has received approvals from the OPUC, the CPUC and the Wyoming Public Service Commission to depreciate the Klamath hydroelectric system's mainstem dams and the associated relicensing and settlement costs through the expected dam removal date. The depreciation rate changes were effective January 1, 2011 and will allow for full depreciation of the assets by December 2019 for those jurisdictions. PacifiCorp filed for consistent ratemaking treatment in Idaho and Washington general rate cases, which were settled in January 2012 and March 2012, respectively, without a decision on this matter. As part of the September 2012 Utah general rate case order, the Utah Public Service Commission approved recovery of Utah's share of costs associated with the Klamath hydroelectric system's mainstem dams and the associated relicensing and settlement costs through December 31, 2022.
Guarantees
The Company has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on the Company's consolidated financial results.
(11) | Components of Accumulated Other Comprehensive Loss, Net |
The following table shows the change in accumulated other comprehensive loss attributable to MEHC shareholders by each component of other comprehensive income (loss), net of applicable income taxes, for the nine-month period ended September 30, 2012 (in millions):
Accumulated | ||||||||||||||||||||
Unrealized | Other | |||||||||||||||||||
Unrecognized | Foreign | Gains on | Unrealized | Comprehensive | ||||||||||||||||
Amounts on | Currency | Available- | Gains on | Loss Attributable | ||||||||||||||||
Retirement | Translation | For-Sale | Cash Flow | To MEHC | ||||||||||||||||
Benefits | Adjustment | Securities | Hedges | Shareholders, Net | ||||||||||||||||
Balance, December 31, 2011 | $ | (491 | ) | $ | (307 | ) | $ | 142 | $ | 15 | $ | (641 | ) | |||||||
Other comprehensive income (loss) | 6 | 113 | (51 | ) | 8 | 76 | ||||||||||||||
Balance, September 30, 2012 | $ | (485 | ) | $ | (194 | ) | $ | 91 | $ | 23 | $ | (565 | ) |
22
(12) | Segment Information |
Northern Natural Gas and Kern River have been aggregated in the reportable segment called MidAmerican Energy Pipeline Group, and CalEnergy Philippines and MidAmerican Renewables, LLC have been aggregated in the reportable segment called MidAmerican Renewables. Prior year amounts have been changed to conform to the current presentation. The Company's reportable segments with foreign operations include Northern Powergrid Holdings, whose business is principally in Great Britain, and MidAmerican Renewables, whose business includes operations in the Philippines. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company's reportable segments is shown below (in millions):
Three-Month Periods | Nine-Month Periods | ||||||||||||||
Ended September 30, | Ended September 30, | ||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||
Operating revenue: | |||||||||||||||
PacifiCorp | $ | 1,327 | $ | 1,198 | $ | 3,671 | $ | 3,408 | |||||||
MidAmerican Funding | 828 | 866 | 2,411 | 2,650 | |||||||||||
MidAmerican Energy Pipeline Group | 203 | 202 | 698 | 697 | |||||||||||
Northern Powergrid Holdings | 240 | 237 | 747 | 727 | |||||||||||
MidAmerican Renewables | 51 | 45 | 112 | 107 | |||||||||||
HomeServices | 372 | 285 | 970 | 764 | |||||||||||
MEHC and Other(1) | (13 | ) | (13 | ) | (46 | ) | (43 | ) | |||||||
Total operating revenue | $ | 3,008 | $ | 2,820 | $ | 8,563 | $ | 8,310 | |||||||
Depreciation and amortization: | |||||||||||||||
PacifiCorp | $ | 164 | $ | 154 | $ | 488 | $ | 465 | |||||||
MidAmerican Funding | 107 | 79 | 300 | 248 | |||||||||||
MidAmerican Energy Pipeline Group | 48 | 44 | 144 | 137 | |||||||||||
Northern Powergrid Holdings | 44 | 42 | 127 | 125 | |||||||||||
MidAmerican Renewables | 7 | 8 | 22 | 23 | |||||||||||
HomeServices | 4 | 3 | 14 | 9 | |||||||||||
MEHC and Other(1) | (3 | ) | (3 | ) | (9 | ) | (10 | ) | |||||||
Total depreciation and amortization | $ | 371 | $ | 327 | $ | 1,086 | $ | 997 | |||||||
Operating income: | |||||||||||||||
PacifiCorp | $ | 382 | $ | 320 | $ | 917 | $ | 858 | |||||||
MidAmerican Funding | 139 | 148 | 311 | 346 | |||||||||||
MidAmerican Energy Pipeline Group | 68 | 79 | 322 | 320 | |||||||||||
Northern Powergrid Holdings | 118 | 136 | 406 | 431 | |||||||||||
MidAmerican Renewables | 34 | 34 | 66 | 67 | |||||||||||
HomeServices | 25 | 18 | 49 | 25 | |||||||||||
MEHC and Other(1) | (9 | ) | (7 | ) | (30 | ) | (38 | ) | |||||||
Total operating income | 757 | 728 | 2,041 | 2,009 | |||||||||||
Interest expense | (298 | ) | (301 | ) | (884 | ) | (907 | ) | |||||||
Capitalized interest | 15 | 13 | 37 | 31 | |||||||||||
Interest and dividend income | 3 | 2 | 8 | 11 | |||||||||||
Other, net | 35 | 17 | 86 | 63 | |||||||||||
Total income before income tax expense and equity income | $ | 512 | $ | 459 | $ | 1,288 | $ | 1,207 |
23
Three-Month Periods | Nine-Month Periods | ||||||||||||||
Ended September 30, | Ended September 30, | ||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||
Interest expense: | |||||||||||||||
PacifiCorp | $ | 98 | $ | 106 | $ | 294 | $ | 309 | |||||||
MidAmerican Funding | 41 | 45 | 126 | 138 | |||||||||||
MidAmerican Energy Pipeline Group | 24 | 25 | 70 | 78 | |||||||||||
Northern Powergrid Holdings | 36 | 38 | 103 | 116 | |||||||||||
MidAmerican Renewables | 21 | 3 | 50 | 13 | |||||||||||
HomeServices | 1 | — | 1 | — | |||||||||||
MEHC and Other(1) | 77 | 84 | 240 | 253 | |||||||||||
Total interest expense | $ | 298 | $ | 301 | $ | 884 | $ | 907 |
As of | |||||||
September 30, | December 31, | ||||||
2012 | 2011 | ||||||
Total assets: | |||||||
PacifiCorp | $ | 22,813 | $ | 22,364 | |||
MidAmerican Funding | 13,105 | 12,430 | |||||
MidAmerican Energy Pipeline Group | 5,107 | 4,854 | |||||
Northern Powergrid Holdings | 6,314 | 5,690 | |||||
MidAmerican Renewables | 2,089 | 890 | |||||
HomeServices | 786 | 649 | |||||
MEHC and Other(1) | 896 | 841 | |||||
Total assets | $ | 51,110 | $ | 47,718 |
(1) | The remaining differences between the segment amounts and the consolidated amounts described as "MEHC and Other" relate principally to intersegment eliminations for operating revenue and, for the other items presented, to (a) corporate functions, including administrative costs, interest expense, corporate cash and investments and related interest income and (b) intersegment eliminations. |
The following table shows the change in the carrying amount of goodwill by reportable segment for the nine-month period ended September 30, 2012 (in millions):
MidAmerican | |||||||||||||||||||||||||||
Energy | Northern | ||||||||||||||||||||||||||
MidAmerican | Pipeline | Powergrid | MidAmerican | Home- | |||||||||||||||||||||||
PacifiCorp | Funding | Group | Holdings | Renewables | Services | Total | |||||||||||||||||||||
Balance, December 31, 2011 | $ | 1,126 | $ | 2,102 | $ | 205 | $ | 1,097 | $ | 71 | $ | 395 | $ | 4,996 | |||||||||||||
Foreign currency translation | — | — | — | 33 | — | — | 33 | ||||||||||||||||||||
Other | — | — | (20 | ) | — | — | 24 | 4 | |||||||||||||||||||
Balance, September 30, 2012 | $ | 1,126 | $ | 2,102 | $ | 185 | $ | 1,130 | $ | 71 | $ | 419 | $ | 5,033 |
24
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 the Company during the periods included herein. Explanations include management's best estimate of the impacts of weather, customer growth and other factors. This discussion should be read in conjunction with the Company's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q. The Company's actual results in the future could differ significantly from the historical results.
The Company's operations are organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding (which primarily consists of MidAmerican Energy), Northern Natural Gas, Kern River, Northern Powergrid Holdings (which primarily consists of Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc), CalEnergy Philippines (which owns a majority interest in the Casecnan project in the Philippines), MidAmerican Renewables, LLC (which owns interests in independent power projects in the United States), and HomeServices. Through these platforms, the Company owns and operates an electric utility company in the Western United States, an electric and natural gas utility company in the Midwestern United States, two interstate natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of independent power projects and the second largest residential real estate brokerage firm in the United States. Northern Natural Gas and Kern River have been aggregated in the reportable segment called MidAmerican Energy Pipeline Group, and CalEnergy Philippines and MidAmerican Renewables, LLC have been aggregated in the reportable segment called MidAmerican Renewables. The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies. The differences between the reportable segment amounts and the consolidated amounts, described as "MEHC and Other," relate principally to corporate functions, including administrative costs and intersegment eliminations.
Results of Operations for the Third Quarter and First Nine Months of 2012 and 2011
Overview
Net income attributable to MEHC shareholders for the three-month period ended September 30, 2012, was $488 million, an increase of $76 million, or 18%, compared to 2011. PacifiCorp's net income was $212 million for 2012, an increase of $42 million, or 25%, compared to 2011 as higher retail prices approved by regulators, higher margins from warmer temperatures and lower interest expense were partially offset by the net impact of the Utah rate case settlement in 2011 and higher depreciation and amortization. Net income at MidAmerican Funding was $136 million for 2012, an increase of $32 million, or 31%, compared to 2011 due to income tax benefits from higher production tax credits primarily from additional wind generation placed in service in late 2011 and the effects of ratemaking. Additionally, improvements in regulated electric margins from adjustment clauses and warmer temperatures were more than offset by higher costs associated with the wind assets placed in service. Net income at MidAmerican Energy Pipeline Group was $31 million for 2012, a decrease of $9 million, or 23%, compared to 2011 as higher revenue from Kern River's expansion projects, higher transportation revenue at Northern Natural Gas and a positive litigation settlement were more than offset by higher operating expense and depreciation and lower AFUDC associated with Kern River's expansion projects. Northern Powergrid Holdings' net income was $105 million for 2012, a decrease of $13 million, or 11%, compared to 2011 as higher distribution rates were more than offset by a favorable movement in regulatory provisions in 2011 and higher operating expense. MidAmerican Renewables' net income was $20 million for 2012, a decrease of $18 million, or 47%, compared to 2011 due to lower equity earnings at CE Generation from lower energy rates and higher interest expense related to the Topaz project financing, which was offset by higher equity earnings due to the acquisition of a 49% interest in Agua Caliente in January 2012. HomeServices' net income for 2012 was $18 million, an increase of $5 million, or 38%, compared to 2011 due to higher revenue and margins from higher closed units, partially offset by higher operating expenses. MEHC and Other net loss of $34 million improved $37 million for 2012 compared to 2011 due to the cessation of purchase price pension amortization in 2011, certain income tax benefits and lower interest expense.
25
Net income attributable to MEHC shareholders for the nine-month period ended September 30, 2012, was $1.145 billion, an increase of $166 million, or 17%, compared to 2011. PacifiCorp's net income was $493 million for 2012, an increase of $67 million, or 16%, compared to 2011 as higher retail prices approved by regulators, higher margins from warmer temperatures, lower interest expense and higher AFUDC were partially offset by higher energy costs, higher operating expense and higher depreciation and amortization. Net income at MidAmerican Funding was $284 million for 2012, an increase of $67 million, or 31%, compared to 2011 due to income tax benefits from higher production tax credits primarily from additional wind-powered generation placed in service in late 2011 and the effects of ratemaking. Additionally, improvements in regulated electric margins, from adjustment clauses and warmer temperatures, and lower interest expense were more than offset by higher costs associated with the wind assets placed in service and lower regulated gas margins. Net income at MidAmerican Energy Pipeline Group was $159 million for 2012, a decrease of $2 million, or 1%, compared to 2011 as higher revenue from Kern River's expansion projects, higher transportation and storage revenue at Northern Natural Gas and a positive litigation settlement were more than offset by higher operating expense and depreciation and lower AFUDC associated with Kern River's expansion projects. Northern Powergrid Holdings' net income was $270 million for 2012, a decrease of $8 million, or 3%, compared to 2011 as higher distribution rates and lower interest expense were more than offset by a favorable movement in regulatory provisions in 2011 and higher operating expense. MidAmerican Renewables' net income was $26 million for 2012, a decrease of $33 million, or 56% compared to 2011 primarily due to higher interest expense related to the Topaz project financing and lower equity earnings at CE Generation from lower energy rates, partially offset by higher equity earnings due to the acquisition of a 49% interest in Agua Caliente in January 2012. HomeServices' net income for 2012 was $38 million, an increase of $18 million, or 90%, compared to 2011 due to higher revenue and margins from higher closed units and average home sale prices, partially offset by higher operating expenses. MEHC and Other net loss of $125 million improved $57 million for 2012 compared to 2011 due to the cessation of purchase price pension amortization in 2011, lower interest expense, certain income tax benefits and higher equity income at ETT.
Reportable Segment Results
Operating revenue and operating income for the Company's reportable segments are summarized as follows (in millions):
Third Quarter | First Nine Months | ||||||||||||||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||||||||||||||
Operating revenue: | |||||||||||||||||||||||||||||
PacifiCorp | $ | 1,327 | $ | 1,198 | $ | 129 | 11 | % | $ | 3,671 | $ | 3,408 | $ | 263 | 8 | % | |||||||||||||
MidAmerican Funding | 828 | 866 | (38 | ) | (4 | ) | 2,411 | 2,650 | (239 | ) | (9 | ) | |||||||||||||||||
MidAmerican Energy Pipeline Group | 203 | 202 | 1 | — | 698 | 697 | 1 | — | |||||||||||||||||||||
Northern Powergrid Holdings | 240 | 237 | 3 | 1 | 747 | 727 | 20 | 3 | |||||||||||||||||||||
MidAmerican Renewables | 51 | 45 | 6 | 13 | 112 | 107 | 5 | 5 | |||||||||||||||||||||
HomeServices | 372 | 285 | 87 | 31 | 970 | 764 | 206 | 27 | |||||||||||||||||||||
MEHC and Other | (13 | ) | (13 | ) | — | — | (46 | ) | (43 | ) | (3 | ) | (7 | ) | |||||||||||||||
Total operating revenue | $ | 3,008 | $ | 2,820 | $ | 188 | 7 | $ | 8,563 | $ | 8,310 | $ | 253 | 3 |
Operating income: | |||||||||||||||||||||||||||||
PacifiCorp | $ | 382 | $ | 320 | $ | 62 | 19 | % | $ | 917 | $ | 858 | $ | 59 | 7 | % | |||||||||||||
MidAmerican Funding | 139 | 148 | (9 | ) | (6 | ) | 311 | 346 | (35 | ) | (10 | ) | |||||||||||||||||
MidAmerican Energy Pipeline Group | 68 | 79 | (11 | ) | (14 | ) | 322 | 320 | 2 | 1 | |||||||||||||||||||
Northern Powergrid Holdings | 118 | 136 | (18 | ) | (13 | ) | 406 | 431 | (25 | ) | (6 | ) | |||||||||||||||||
MidAmerican Renewables | 34 | 34 | — | — | 66 | 67 | (1 | ) | (1 | ) | |||||||||||||||||||
HomeServices | 25 | 18 | 7 | 39 | 49 | 25 | 24 | 96 | |||||||||||||||||||||
MEHC and Other | (9 | ) | (7 | ) | (2 | ) | (29 | ) | (30 | ) | (38 | ) | 8 | 21 | |||||||||||||||
Total operating income | $ | 757 | $ | 728 | $ | 29 | 4 | $ | 2,041 | $ | 2,009 | $ | 32 | 2 |
26
PacifiCorp
Operating revenue increased $129 million for the third quarter of 2012 compared to 2011 due to an increase in retail revenue of $105 million and higher renewable energy credit revenue of $42 million, partially offset by lower electric wholesale revenue of $22 million as a result of lower average prices and volumes. The increase in retail revenue was due to higher prices approved by regulators of $82 million and higher retail customer load totaling $23 million due to the impacts of hot weather in Utah, partially offset by lower industrial customer load in Wyoming and Oregon as certain large customers elected to self-generate their own power. The higher renewable energy credit revenue in 2012 was due to the Utah general rate case settlement in 2011 ("Utah general rate case settlement"), which resulted in a $30 million decrease to operating revenue in 2011. The Utah general rate case settlement provided for a $30 million credit to customers for the refund of renewable energy credit sales that substantially occurred prior to 2011 and that were credited to Utah customer's bills over the period from September 2011 through May 2012 (the "Utah renewable energy credit adjustment").
Operating income increased $62 million for the third quarter of 2012 compared to 2011 due to the higher operating revenue and lower operating expense of $4 million, partially offset by higher energy costs of $61 million and higher depreciation and amortization of $10 million due to higher plant in service. Energy costs increased due to lower deferral of incurred power costs of $54 million and higher net fuel costs of $8 million. The Utah general rate case settlement resulted in lower energy costs of $60 million recognized in 2011 and provided for the recovery of $60 million of previously incurred net power costs in excess of amounts included in base rates to be recovered from Utah customers over a three-year period beginning on June 1, 2012 (the "Utah net power cost recovery adjustment"). The $8 million of higher net fuel costs was due to higher unit coal costs and increased thermal generation, partially offset by lower unit natural gas costs.
Operating revenue increased $263 million for the first nine months of 2012 compared to 2011 due to an increase in retail revenue of $229 million, higher renewable energy credit revenue of $63 million, partially offset by lower electric wholesale revenue of $35 million on lower average prices. The increase in retail revenue was due to higher prices approved by regulators of $191 million and $38 million of higher retail customer load. The increase in customer load is due to the impacts of hot weather in Utah and higher irrigation customer load in Idaho, partially offset by lower industrial customer load in Wyoming and Oregon as certain large customers elected to self-generate their own power and lower residential customer load in Oregon. The Utah general rate case settlement resulted in $50 million of higher renewable energy credit revenue in 2012 as compared to 2011 due to the impact of the Utah renewable energy credit adjustment of $30 million recorded in 2011 and $20 million in amortization of the Utah renewable energy credit adjustment, which was offset in operating revenue through lower rates charged to retail customers.
Operating income increased $59 million for the first nine months of 2012 compared to 2011 due to the higher operating revenue, partially offset by higher energy costs of $156 million, higher operating expense of $24 million and higher depreciation and amortization of $23 million. Energy costs increased due to higher net fuel and purchased electricity costs of $84 million and the impact of the Utah general rate case settlement on deferred power costs of $67 million. The higher net fuel and purchased electricity costs were due to increased thermal generation, higher cost of purchased electricity and the higher unit cost of coal, partially offset by lower unit natural gas costs. The impact of the Utah general rate case settlement on deferred power costs was due to the Utah net power cost recovery adjustment of $60 million recorded in 2011 and $7 million in amortization of the Utah net power cost recovery adjustment, which was offset in operating income through higher rates charged to customers. Operating expense increased due to charges in 2012 related to litigation, damage claims, the impairment of certain pre-construction costs for environmental projects at a coal-fueled generating facility and higher property taxes due to higher plant in service, partially offset by lower thermal generating facility maintenance.
27
MidAmerican Funding
MidAmerican Funding's operating revenue and operating income are summarized as follows (in millions):
Third Quarter | First Nine Months | ||||||||||||||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||||||||||||||
Operating revenue: | |||||||||||||||||||||||||||||
Regulated electric | $ | 511 | $ | 487 | $ | 24 | 5 | % | $ | 1,295 | $ | 1,276 | $ | 19 | 1 | % | |||||||||||||
Regulated natural gas | 87 | 99 | (12 | ) | (12 | ) | 441 | 562 | (121 | ) | (22 | ) | |||||||||||||||||
Nonregulated and other | 230 | 280 | (50 | ) | (18 | ) | 675 | 812 | (137 | ) | (17 | ) | |||||||||||||||||
Total operating revenue | $ | 828 | $ | 866 | $ | (38 | ) | (4 | ) | $ | 2,411 | $ | 2,650 | $ | (239 | ) | (9 | ) | |||||||||||
Operating income: | |||||||||||||||||||||||||||||
Regulated electric | $ | 129 | $ | 133 | $ | (4 | ) | (3 | )% | $ | 243 | $ | 248 | $ | (5 | ) | (2 | )% | |||||||||||
Regulated natural gas | (3 | ) | (1 | ) | (2 | ) | * | 28 | 48 | (20 | ) | (42 | ) | ||||||||||||||||
Nonregulated and other | 13 | 16 | (3 | ) | (19 | ) | 40 | 50 | (10 | ) | (20 | ) | |||||||||||||||||
Total operating income | $ | 139 | $ | 148 | $ | (9 | ) | (6 | ) | $ | 311 | $ | 346 | $ | (35 | ) | (10 | ) |
* Not meaningful
Regulated electric operating revenue increased $24 million for the third quarter of 2012 compared to 2011 due to higher retail revenue of $28 million, partially offset by lower wholesale and other revenue of $4 million. Retail revenue increased due to new adjustment clauses in Iowa and Illinois totaling $17 million and a 2.5% increase in retail customer load as a result of abnormally hot weather in 2012 and customer growth. Wholesale and other revenue were lower as volumes decreased 7.0%.
Regulated electric operating income decreased $4 million for the third quarter of 2012 compared to 2011 as the higher revenue and lower energy costs of $11 million were more than offset by higher depreciation of $27 million and operating costs of $10 million due to additional wind-powered generation placed in service in late 2011 and higher revenue sharing of $7 million included in depreciation and amortization. Energy costs decreased due to lower purchased power prices and volumes, lower coal generation and the additional wind-powered generation.
Regulated natural gas operating revenue decreased $12 million for the third quarter of 2012 compared to 2011 due to a lower average per-unit cost of gas sold, resulting in lower cost of sales. Regulated natural gas operating income decreased $2 million for the third quarter of 2012 compared to 2011 due to higher operating expense.
Nonregulated and other operating revenue decreased $50 million for the third quarter of 2012 compared to 2011 due to lower electricity prices and volumes and lower natural gas prices, partially offset by higher natural gas volumes. Nonregulated and other operating income decreased $3 million for the third quarter of 2012 compared to 2011 due to lower electric margins.
Regulated electric operating revenue increased $19 million for the first nine months of 2012 compared to 2011 due to higher retail revenue of $37 million, partially offset by lower wholesale and other revenue of $18 million. Retail revenue increased due to new adjustment clauses in Iowa and Illinois totaling $30 million and a 0.5% increase in retail customer load as a result of abnormally hot weather. Wholesale and other revenue was lower due to an 8.7% decrease in average market prices.
Regulated operating income decreased $5 million for the first nine months of 2012 compared to 2011 as the higher revenue and lower energy costs of $38 million were more than offset by higher depreciation of $51 million and operating costs of $11 million due to additional wind-powered generation placed in service in late 2011 and higher revenue sharing of $16 million included in depreciation and amortization. Energy costs decreased due to lower purchased power prices and volumes, the additional wind-powered generation and lower coal generation.
Regulated natural gas operating revenue decreased $121 million for the first nine months of 2012 compared to 2011 due to a lower average per-unit cost of gas sold, resulting in lower cost of sales, and lower volumes from unseasonably warm weather. Regulated natural gas operating income decreased $20 million for the first nine months of 2012 compared to 2011 due to lower volume-related gas margins as a result of unseasonably warm winter and spring temperatures and other usage factors.
28
Nonregulated and other operating revenue decreased $137 million for the first nine months of 2012 compared to 2011 due to lower electricity and natural gas prices and volumes. Nonregulated and other operating income decreased $10 million for the first nine months of 2012 compared to 2011 due to lower electric margins.
MidAmerican Energy Pipeline Group
Operating revenue increased $1 million for the third quarter of 2012 compared to 2011 due to higher revenue from increased capacity from Kern River's expansion projects of $10 million and higher transportation revenue at Northern Natural Gas of $5 million due to higher Field Area volumes and rates, partially offset by lower sales of gas and condensate liquids totaling $9 million on lower volumes, which are offset in cost of sales. Operating income decreased $11 million for the third quarter of 2012 compared to 2011 as the higher revenue at Kern River and the higher transportation revenue at Northern Natural Gas were more than offset by higher operating expense and depreciation.
Operating revenue increased $1 million for the first nine months of 2012 compared to 2011 as higher revenue from Kern River's expansion projects of $27 million and higher Field Area transportation and storage rates of $5 million at Northern Natural Gas were partially offset by lower sales of gas and condensate liquids of $23 million on lower volumes, which are offset in cost of sales, and contract expirations with capacity sold at lower rates at Kern River. Operating income increased $2 million for the first nine months of 2012 compared to 2011 due to the higher revenue at Kern River and the higher Field Area transportation and storage rates at Northern Natural Gas, partially offset by higher operating expense and depreciation.
Northern Powergrid Holdings
Operating revenue increased $3 million for the third quarter of 2012 compared to 2011 due to higher distribution revenue of $5 million and higher contracting revenue of $3 million, partially offset by the stronger United States dollar totaling $5 million. Distribution revenue increased due to higher tariff rates of $17 million, partially offset by a favorable movement in regulatory provisions in 2011 of $9 million and lower units distributed. Operating income decreased $18 million for the third quarter of 2012 compared to 2011 as the higher distribution revenue was more than offset by higher pension expense of $11 million and higher distribution operating expense of $8 million.
Operating revenue increased $20 million for the first nine months of 2012 compared to 2011 due to higher distribution revenue of $36 million, partially offset by the stronger United States dollar totaling $17 million. Distribution revenue increased due to higher tariff rates of $67 million, partially offset by a favorable movement in regulatory provisions in 2011 of $29 million and lower units distributed. Operating income decreased $25 million for the first nine months of 2012 compared to 2011 as the higher distribution revenue was more than offset by higher pension expense of $33 million, higher distribution operating expense of $18 million and the stronger United States dollar of $9 million.
MidAmerican Renewables
Operating revenue increased $6 million for the third quarter of 2012 compared to 2011 and $5 million for first nine months of 2012 compared to 2011 due to higher variable energy fees earned in 2012 from higher rainfall at the Casecnan project. Operating income was flat for the third quarter and decreased $1 million for first nine months of 2012 compared to 2011 as the higher revenue was offset by higher project evaluation and acquisition costs.
HomeServices
Operating revenue increased $87 million for the third quarter of 2012 compared to 2011 due to an increase from existing businesses totaling $46 million, reflecting a 13.1% increase in closed brokerage units and a 2.7% increase in average home sale prices, and $41 million of revenue from acquired companies. Operating income increased $7 million for the third quarter of 2012 compared to 2011 due to the higher operating revenue, net of commissions, partially offset by higher operating expense at both acquired and existing businesses.
Operating revenue increased $206 million for the first nine months of 2012 compared to 2011 due to an increase from existing businesses totaling $124 million reflecting a 15.4% increase in closed brokerage units and $82 million of revenue from acquired companies. Operating income increased $24 million for the first nine months of 2012 compared to 2011 due to the higher operating revenue, net of commissions, partially offset by higher operating expense of $35 million at both acquired and existing businesses and higher depreciation and amortization at acquired businesses.
29
MEHC and Other
Operating loss increased $2 million for the third quarter of 2012 compared to 2011 as higher compensation expense was partially offset by the cessation of purchase price pension amortization in 2011.
Operating loss improved by $8 million for the first nine months of 2012 compared to 2011 due to the cessation of purchase price amortization in 2011, partially offset by higher compensation expense.
Consolidated Other Income and Expense Items
Interest Expense
Interest expense is summarized as follows (in millions):
Third Quarter | First Nine Months | ||||||||||||||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||||||||||||||
Subsidiary debt | $ | 220 | $ | 213 | $ | 7 | 3 | % | $ | 640 | $ | 638 | $ | 2 | — | % | |||||||||||||
MEHC senior debt and other | 78 | 81 | (3 | ) | (4 | ) | 244 | 246 | (2 | ) | (1 | ) | |||||||||||||||||
MEHC subordinated debt - Berkshire Hathaway | — | 3 | (3 | ) | (100 | ) | — | 12 | (12 | ) | (100 | ) | |||||||||||||||||
MEHC subordinated debt - other | — | 4 | (4 | ) | (100 | ) | — | 11 | (11 | ) | (100 | ) | |||||||||||||||||
Total interest expense | $ | 298 | $ | 301 | $ | (3 | ) | (1 | ) | $ | 884 | $ | 907 | $ | (23 | ) | (3 | ) |
Interest expense decreased $3 million for the third quarter of 2012 compared to 2011 and $23 million for the first nine months of 2012 compared to 2011 due to scheduled maturities and early principal repayments, partially offset by the debt issuances and refinancings at PacifiCorp ($400 million in May 2011, $650 million in January 2012 and $100 million in March 2012), MidAmerican Energy Pipeline Group ($200 million in April 2011 and $250 million in August 2012), Northern Powergrid Holdings (£150 million in July 2012) and MidAmerican Renewables ($850 million in February 2012 and $120 million in August 2012).
Capitalized Interest
Capitalized interest increased $2 million for the third quarter of 2012 compared to 2011 and $6 million for the first nine months of 2012 compared to 2011 due to higher construction in progress balances at Topaz and PacifiCorp, partially offset by lower construction in progress balances at MidAmerican Energy Pipeline Group and MidAmerican Energy.
Other, Net
Other, net increased $18 million for the third quarter of 2012 compared to 2011 and $23 million for the first nine months of 2012 compared to 2011 due to better investment performance and a positive litigation settlement at MidAmerican Energy Pipeline Group.
Income Tax Expense
Income tax expense decreased $21 million for the third quarter of 2012 compared to 2011 and the effective tax rates were 9% for the third quarter of 2012 and 15% for the third quarter of 2011. The decrease in the effective tax rate was due to $25 million of higher income tax benefits related to additional production tax credits at MidAmerican Energy primarily due to wind-powered generation placed in service in late 2011 and the effects of ratemaking.
Income tax expense decreased $67 million for the first nine months of 2012 compared to 2011 and the effective tax rates were 15% for the first nine months of 2012 and 21% for the first nine months of 2011. The decrease in the effective tax rate was due to $45 million of higher income tax benefits related to additional production tax credits at MidAmerican Energy primarily due to wind-powered generation placed in service in late 2011, the effects of ratemaking and the method change for repairs deductions.
30
In July 2012, the Company recognized $38 million of deferred income tax benefits upon the enactment of a reduction in the United Kingdom corporate income tax rate from 25% to 24% effective April 1, 2012, and a further reduction to 23% effective April 1, 2013. In July 2011, the Company recognized $40 million of deferred income tax benefits upon the enactment of a reduction in the United Kingdom corporate income tax rate from 27% to 26% effective April 1, 2011, and a further reduction to 25% effective April 1, 2012.
Equity Income
Equity income increased $2 million for the third quarter of 2012 compared to 2011 and $19 million for the first nine months of 2012 compared to 2011 due to the acquisition of a 49% interest in Agua Caliente in January 2012 and higher earnings at ETT due to continued investment, partially offset by lower earnings at CE Generation on lower energy rates at the Imperial Valley Projects. Equity income increased for the first nine months of 2012 compared to 2011 due to the reasons stated above, as well as higher earnings at HomeServices' mortgage joint venture due to higher refinancing activity.
Liquidity and Capital Resources
Each of MEHC's direct and indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy MEHC's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MEHC or affiliates thereof. The long-term debt of subsidiaries may include provisions that allow MEHC's subsidiaries to redeem it in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 17 of Notes to Consolidated Financial Statements in Item 8 of the Company's Annual Report on Form 10-K for further discussion regarding the limitation of distributions from MEHC's subsidiaries.
As of September 30, 2012, the Company's total net liquidity was $6.038 billion and the components are as follows (in millions):
Northern | |||||||||||||||||||||||
MidAmerican | Powergrid | ||||||||||||||||||||||
MEHC | PacifiCorp | Funding | Holdings | Other | Total | ||||||||||||||||||
Cash and cash equivalents | $ | 603 | $ | 175 | $ | 375 | $ | 164 | $ | 543 | $ | 1,860 | |||||||||||
Credit facilities(1) | 1,079 | 1,230 | 539 | 242 | 95 | 3,185 | |||||||||||||||||
Less: | |||||||||||||||||||||||
Short-term debt | (140 | ) | — | — | — | (38 | ) | (178 | ) | ||||||||||||||
Tax-exempt bond support and letters of credit | (32 | ) | (602 | ) | (195 | ) | — | — | (829 | ) | |||||||||||||
Net credit facilities | 907 | 628 | 344 | 242 | 57 | 2,178 | |||||||||||||||||
Net liquidity before Berkshire Equity Commitment | 1,510 | $ | 803 | $ | 719 | $ | 406 | $ | 600 | 4,038 | |||||||||||||
Berkshire Equity Commitment(2) | 2,000 | 2,000 | |||||||||||||||||||||
Total net liquidity | $ | 3,510 | $ | 6,038 | |||||||||||||||||||
Credit facilities: | |||||||||||||||||||||||
Maturity date | 2013, 2017 | 2013, 2017 | 2013 | 2017 | 2012, 2013 | ||||||||||||||||||
Largest single bank commitment as a % of total credit facilities(3) | 13 | % | 14 | % | 28 | % | 33 | % | 53 | % |
(1) | For further discussion regarding the Company's credit facilities, refer to Note 7 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q. |
(2) | MEHC has an Equity Commitment Agreement with Berkshire Hathaway (the "Berkshire Equity Commitment") pursuant to which Berkshire Hathaway has agreed to purchase up to $2.0 billion of MEHC's common equity upon any requests authorized from time to time by MEHC's Board of Directors. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC's debt obligations and (b) funding the general corporate purposes and capital requirements of MEHC's regulated subsidiaries. The Berkshire Equity Commitment expires on February 28, 2014. |
31
(3) | An inability of financial institutions to honor their commitments could adversely affect the Company's short-term liquidity and ability to meet long-term commitments. |
The above table does not include unused credit facilities and letters of credit for investments that are accounted for under the equity method.
Operating Activities
Net cash flows from operating activities for the nine-month periods ended September 30, 2012 and 2011 were $3.682 billion and $2.717 billion, respectively. The increase was primarily due to higher income tax receipts of $667 million from bonus depreciation, investment tax credits related to renewable projects and production tax credits from additional wind generation placed in service; improved operating results; lower interest payments; benefits from changes in collateral posted for derivative contracts; lower domestic employee benefit plan contributions; and other changes in working capital.
Investing Activities
Net cash flows from investing activities for the nine-month periods ended September 30, 2012 and 2011 were $(2.817) billion and $(1.993) billion, respectively. The change was primarily due to higher capital expenditures, the acquisitions of Topaz and Bishop Hill, and equity contributions to Agua Caliente.
Capital Expenditures
Capital expenditures, which exclude amounts for non-cash equity AFUDC and other non-cash items, by reportable segment for the nine-month periods ended September 30 are summarized as follows (in millions):
2012 | 2011 | ||||||
Capital expenditures: | |||||||
PacifiCorp | $ | 1,037 | $ | 1,069 | |||
MidAmerican Funding | 445 | 398 | |||||
MidAmerican Energy Pipeline Group | 112 | 218 | |||||
Northern Powergrid Holdings | 310 | 219 | |||||
MidAmerican Renewables | 439 | 1 | |||||
Other | 6 | 7 | |||||
Total capital expenditures | $ | 2,349 | $ | 1,912 |
The Company's capital expenditures relate primarily to the Utilities and consisted mainly of the following for the nine-month periods ended September 30:
2012:
• | Transmission system investments totaling $262 million, including construction costs for PacifiCorp's 100-mile high-voltage transmission line being built between the Mona substation in central Utah and the Oquirrh substation in the Salt Lake Valley. A 65-mile segment of the Mona-Oquirrh transmission project will be a single-circuit 500-kV transmission line, while the remaining 35-mile segment will be a double-circuit 345-kV transmission line. The transmission line is expected to be placed in service in 2013. |
• | Emissions control equipment on existing generating facilities totaling $196 million for installation or upgrade of sulfur dioxide scrubbers, low nitrogen oxide burners and particulate matter control systems. |
• | The development and construction of PacifiCorp's Lake Side 2 637-MW combined-cycle combustion turbine natural gas-fueled generating facility ("Lake Side 2") totaling $177 million, which is expected to be placed in service in 2014. |
• | The construction of MidAmerican Energy's 407 MW of wind-powered generating facilities totaling $121 million, excluding $306 million of costs for which payments are due in December 2015. MidAmerican Energy placed in service 214 MW during the third quarter of 2012, and the remaining 193 MW are expected to be placed in service during the fourth quarter of 2012. |
• | Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $726 million. |
32
2011:
• | The construction of MidAmerican Energy's 594 MW of wind-powered generating facilities totaling $182 million, excluding $376 million of costs for which payments are due in December 2013. The wind-powered generating facilities were placed in service in 2011. |
• | Emissions control equipment on existing generating facilities totaling $170 million for installation or upgrade of sulfur dioxide scrubbers, low nitrogen oxide burners and particulate matter control systems. |
• | Transmission system investments totaling $167 million, including permitting and right-of-way costs for PacifiCorp's Mona-Oquirrh substation and transmission project. |
• | The development and construction of Lake Side 2 totaling $123 million. |
• | Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $825 million. |
Additionally, capital expenditures for the nine-month period ended September 30, 2012 include costs related to MidAmerican Renewables totaling $439 million related to the Topaz and Bishop Hill Projects. Capital expenditures for the nine-month period ended September 30, 2011 include costs related to Kern River's expansion projects totaling $162 million. The remaining amounts are for ongoing investments in distribution and other infrastructure needed at the other platforms to serve existing and expected demand.
Financing Activities
Net cash flows from financing activities for the nine-month period ended September 30, 2012 was $704 million. Sources of cash totaled $2.199 billion related to proceeds from subsidiary debt. Uses of cash totaled $1.495 billion and consisted mainly of net repayments of short-term debt totaling $715 million, repayments of subsidiary debt totaling $450 million and repayments of MEHC senior and subordinated debt totaling $272 million. For the nine-month period ended September 30, 2012, subsidiary debt issuances included the following:
• | In January 2012, PacifiCorp issued $350 million of its 2.95% First Mortgage Bonds due February 1, 2022 and $300 million of its 4.10% First Mortgage Bonds due February 1, 2042. The net proceeds were used to repay short-term debt, fund capital expenditures and for general corporate purposes. In March 2012, PacifiCorp issued an additional $100 million of its 2.95% First Mortgage Bonds due February 1, 2022. The net proceeds were used to redeem $84 million of tax-exempt bond obligations prior to scheduled maturity with a weighted average interest rate of 5.7%, to repay short-term debt and for general corporate purposes. |
• | In February 2012, Topaz issued $850 million of the 5.75% Series A Senior Secured Notes. The principal of the notes amortize beginning September 2015 with a final maturity in September 2039. The net proceeds will be used to fund the costs and expenses related to the development, construction and financing of the Topaz Project. Any unused amounts will be invested or, in certain circumstances, loaned to MEHC. As of June 30, 2012, $421 million was loaned to MEHC. |
• | In July 2012, Northern Powergrid (Yorkshire) plc issued £150 million of its 4.375% Bonds due July 2032. The net proceeds will be used for general corporate purposes. |
• | In August 2012, Northern Natural Gas issued $250 million of its 4.10% Senior Bonds due September 2042. The net proceeds were used to partially repay its $300 million, 5.375% Senior Notes due October 2012. |
• | In August 2012, Bishop Hill issued $120 million of its 5.125% Senior Secured Fixed Rate Notes. The principal of the notes amortize beginning March 2013 with a final maturity in March 2032. The net proceeds will be used to fund the costs and expenses related to the development, construction and financing of the Bishop Hill Project. |
In conjunction with the construction of wind-powered generating facilities in 2012, MidAmerican Energy has accrued as construction work-in-progress amounts it is not contractually obligated to pay until December 2015. The amounts ultimately payable are discounted at 1.43% and recognized upon delivery of the equipment as long-term debt. The discount is being amortized as interest expense over the period until payment is due using the effective interest method. As of September 30, 2012, $306 million of such debt from the 2012 wind-powered generation projects, net of associated discount, was outstanding.
33
Net cash flows from financing activities for the nine-month period ended September 30, 2011 was $(289) million. Uses of cash totaled $1.079 billion and consisted mainly of $601 million for repayments of subsidiary debt, net repayments of short-term debt totaling $320 million and repayments of MEHC subordinated debt totaling $122 million. Sources of cash totaled $790 million related to proceeds from subsidiary debt.
Future Uses of Cash
The Company 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, the issuance of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which each subsidiary has access to external financing depends on a variety of factors, including its credit ratings, investors' judgment of risk and conditions in the overall capital market, including the condition of the utility industry and non-recourse project finance market, among other items. Additionally, MEHC has the Berkshire Equity Commitment pursuant to which Berkshire Hathaway has agreed to purchase up to $2.0 billion of MEHC's common equity upon any requests authorized from time to time by MEHC's Board of Directors. The Berkshire Equity Commitment expires on February 28, 2014 and may only be used for the purpose of (a) paying when due MEHC's debt obligations and (b) funding the general corporate purposes and capital requirements of MEHC's regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request in increments of at least $250 million pursuant to one or more drawings authorized by MEHC's Board of Directors. The funding of any such drawing will be made by means of a cash equity contribution to MEHC in exchange for additional shares of MEHC's common stock.
Capital Expenditures
The Company 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 rules and regulations, including environmental and nuclear; 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; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items, such as pollution-control technologies, replacement generation, nuclear decommissioning, hydroelectric relicensing, hydroelectric decommissioning and associated operating costs are generally incorporated into MEHC's energy subsidiaries' regulated retail rates.
Forecasted capital expenditures, which exclude amounts for non-cash equity AFUDC and other non-cash items, are approximately $3.3 billion for 2012 and consist mainly of large scale projects at the Utilities and MidAmerican Renewables, including the following:
• | $632 million for the Topaz Project, which is a 550-MW solar project in California that will be completed in 22 blocks through 2015, with an aggregate tested capacity of 586 MW. The Topaz Project expects to place 45 MW in service in 2012. |
• | $344 million for transmission system investments, including $262 million for the Energy Gateway Transmission Expansion Program, which includes construction costs for the Mona-Oquirrh transmission line. |
• | $264 million for emissions control equipment at the Utilities, which includes equipment to meet air quality and visibility targets, including the reduction of sulfur dioxide, nitrogen oxides and particulate matter emissions. This estimate includes the installation of new or the replacement of existing emissions control equipment at several of the Utilities' coal-fueled generating facilities. |
• | $230 million for development and construction of Lake Side 2, which is expected to be placed in service in 2014. |
• | $197 million for 407 MW (nominal ratings) of wind-powered generation at MidAmerican Energy, excluding approximately $400 million of payments deferred until December 2015. MidAmerican Energy placed in service 214 MW during the third quarter of 2012, and the remaining 193 MW are expected to be placed in service during the fourth quarter of 2012. |
• | $150 million of 81-MW wind-powered generation at the Bishop Hill Project in Illinois that is expected to be placed in service in 2012. In March 2012, MEHC, through a wholly-owned subsidiary, acquired the Bishop Hill Project from Invenergy Wind LLC. |
Remaining amounts are for ongoing investments in distribution, generation, mining and other infrastructure needed to serve existing and expected demand.
34
In September 2012, MidAmerican Renewables, through wholly-owned subsidiaries, signed a definitive agreement, subject to conditions precedent, to acquire all of the equity interests in two project companies that own the 168-MW Alta Wind VII and the 132-MW Alta Wind IX wind-powered generation projects ("Alta Wind Projects"), located in California, which are expected to be placed in service in 2012. Once completed, the Alta Wind Projects will sell all of their generation to Southern California Edison pursuant to the terms of power purchase agreements that extend to 2035. These transactions are expected to close in 2012.
Equity Investments
Agua Caliente, a company owned 51% by NRG Energy, Inc. and 49% by an indirect subsidiary of MEHC, is constructing the 290-MW Agua Caliente Project in Arizona that will be completed in 12 blocks through 2014. Pursuant to an equity funding and contribution agreement, MEHC has committed to provide Agua Caliente with funding for (a) base equity contributions of up to an aggregate amount of $303 million for the construction of the Agua Caliente Project and (b) transmission upgrade costs. MEHC expects to make equity contributions to Agua Caliente during 2012 of $279 million. The equity funding and contribution agreement and the letter of credit commitment decreases as equity is contributed to the Agua Caliente Project. As of September 30, 2012, the balance of the commitment was $169 million.
Contractual Obligations
As of September 30, 2012, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2011 other than the 2012 debt issuances previously discussed and MidAmerican Energy's redemption of $275 million of its 5.125% senior notes due January 2013. Additionally, refer to the "Capital Expenditures" discussion included in "Liquidity and Capital Resources."
In April 2012, MidAmerican Energy entered into a multi-year coal transportation agreement with BNSF Railway Company, an affiliate of the Company, for long-haul delivery of coal to MidAmerican Energy's generating facilities that are not "captive" to a single railroad. The new contract will provide delivery for the majority of the coal anticipated to be delivered to MidAmerican Energy-operated coal-fueled generating facilities beginning January 1, 2013. While prices for this rail service are significantly higher than those contained in MidAmerican Energy's legacy long-haul rail contract, which expires December 31, 2012, the BNSF Railway Company proposal was the lowest cost and best overall bid.
Regulatory Matters
MEHC's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2011.
PacifiCorp
Utah
In February 2012, PacifiCorp filed a general rate case with the UPSC requesting a rate increase of $172 million, or an average price increase of 10%. In July 2012, PacifiCorp filed rebuttal testimony that reduced the requested increase to $156 million, or an average price increase of 9%. In September 2012, the UPSC approved a multi-year settlement that provides for an annual increase of $100 million, or an average price increase of 6%, effective October 2012, to be followed by an additional annual increase of $54 million, or an average price increase of 3%, effective September 2013. As part of the general rate case settlement, PacifiCorp indicated that it anticipates retiring the 172-MW Carbon coal-fueled generating facility ("Carbon Facility") in early 2015. Refer to "Environmental Laws and Regulations" for a further discussion regarding the Carbon Facility. The settlement authorizes PacifiCorp to recover the remaining depreciation expense and decommissioning costs for the early retirement of the Carbon Facility through 2020, which is the end of the depreciation life previously used for setting rates in Utah.
In March 2012, PacifiCorp filed its first annual energy balancing account with the UPSC requesting: (a) $9 million for recovery of 70% of the net power costs in excess of amounts included in base rates for the period October 1, 2011 through December 31, 2011 and (b) collection of $20 million of excess net power costs representing the first annual installment of the $60 million of excess net power costs approved for recovery in the September 2011 general rate case settlement. Collection of the $20 million installment began in June 2012. The $9 million is under review and a schedule has been established to receive approval from the UPSC by early 2013 on the final amount to be recovered.
35
In March 2012, PacifiCorp filed with the UPSC to return $4 million to customers through the REC balancing account. The new rates were effective June 2012 on an interim basis until a final order is issued by the UPSC.
Oregon
In February 2012, PacifiCorp made its initial filing for the annual Transition Adjustment Mechanism with the OPUC for an annual increase of $10 million, or an average price increase of 1%, to recover the anticipated net power costs forecasted for calendar year 2013. In July 2012, PacifiCorp filed updated net power costs reducing the requested increase to $3 million, or an average price increase of less than 1%. The filing will be subject to updates through November 2012 and the new rates will be effective January 2013.
In March 2012, PacifiCorp filed a general rate case with the OPUC requesting an annual increase of $41 million, or an average price increase of 3%. In July 2012, a multiparty partial stipulation was filed with the OPUC resolving most components of the general rate case, including PacifiCorp's requests to include in rates the accelerated depreciation and decommissioning costs for the early retirement of the Carbon Facility. The stipulation provides for an annual increase of $24 million, or an average price increase of 2%. If the stipulation is approved by the OPUC, the new rates will be effective January 2013. The issues that were not settled in the stipulation include the prudence of PacifiCorp's investments in environmental controls at its thermal generating facilities, PacifiCorp's request for a power cost adjustment mechanism and PacifiCorp's proposal to add the Mona-Oquirrh transmission line to its rate base through a separate tariff rider when the line goes into service in 2013. A hearing on the issues not resolved through the stipulation was held in October 2012. Post-hearing briefs and oral arguments are scheduled for November 2012 with a decision from the OPUC expected in December 2012.
Wyoming
In December 2011, PacifiCorp filed a general rate case with the WPSC requesting an annual increase of $63 million, or an average price increase of 10%, for which the outcome is described below.
In March 2012, PacifiCorp made its first annual Wyoming energy cost adjustment mechanism ("ECAM") filing with the WPSC. The filing requested recovery of $29 million, or an average price increase of 5%, for deferred net power costs for the period December 1, 2010 to December 31, 2011. The new rates were effective May 2012 on an interim basis and were revised in July 2012 in anticipation of the general rate case stipulation described below.
In July 2012, the WPSC approved a stipulation that consolidated and resolved the December 2011 general rate case and the March 2012 ECAM filing. The stipulation resulted in a $50 million general rate increase that will be effective in two stages. The first increase of $32 million, or an average price increase of 5%, was effective in October 2012 and the second increase of $18 million, or an average price increase of 3%, will be effective in October 2013. The stipulation also resulted in a reduction of the ECAM surcharge rate increase from $29 million to $27 million and the increase will be collected over three years. The stipulation authorizes PacifiCorp to recover the remaining depreciation expense and decommissioning costs for the early retirement of the Carbon Facility through 2020, which is the end of the depreciation life previously used for setting rates in Wyoming. In addition, PacifiCorp agreed not to file another general rate case in Wyoming prior to March 2014 with the new rates to be effective no earlier than January 2015. PacifiCorp will continue to file its required annual ECAM filings.
In March 2012, PacifiCorp filed its first annual Wyoming REC and Sulfur Dioxide Revenue Adjustment Mechanism ("RRA") application with the WPSC. The RRA tracks the difference between PacifiCorp's actual revenues from the sale of RECs and sulfur dioxide allowances and the amounts credited to customers in current rates. The filing requested a $1 million reduction in the surcredit to $15 million. The new surcredit became effective in May 2012 on an interim basis. In September 2012, the WPSC approved the RRA on a permanent basis with no change to the previously approved interim rate.
In September 2011, PacifiCorp filed with the WPSC an application for a certificate of public convenience and necessity ("CPCN") for pollution control facilities at Naughton Unit No. 3 in Wyoming. In April 2012, PacifiCorp filed testimony modifying its original CPCN application to reflect its current plan to convert the Naughton Unit No. 3 to a natural gas-fueled unit as a result of PacifiCorp's current estimation that conversion is the least cost alternative for meeting air quality and visibility requirements and is in the best interest of customers. In May 2012, PacifiCorp filed a motion to withdraw the CPCN application, which was approved by the WPSC.
36
Washington
In May 2010, PacifiCorp filed a general rate case with the WUTC requesting an annual increase of $57 million, or an average price increase of 21%. In November 2010, the requested annual increase was reduced to $49 million, or an average price increase of 18%. In March 2011, the WUTC issued an order and clarification letter approving an annual increase of $33 million, or an average price increase of 12%, reduced in the first year by a customer bill credit of $5 million, or 2%, related to the sale of RECs expected during the twelve-month period ended March 31, 2012, as well as requiring PacifiCorp to submit additional information to the WUTC regarding the sales of RECs. The new rates were effective in April 2011. Although both PacifiCorp and the WUTC staff filed petitions for reconsideration of various items in the order, the WUTC denied the petitions for reconsideration. In May 2011, PacifiCorp submitted to the WUTC the additional information required by the March 2011 order regarding PacifiCorp's proceeds from sales of RECs for the period January 1, 2009 forward and a detailed proposal for a tracking mechanism for proceeds of RECs. Intervening parties and WUTC staff proposed that PacifiCorp refund to customers the amount of REC sales in excess of the amount included in base rates since January 1, 2009. Initial and reply briefs from all parties were filed in November 2011. Oral arguments were held before the WUTC in January 2012. In August 2012, the WUTC issued an order requiring PacifiCorp to credit to its customers all proceeds from the sale of RECs attributable to Washington that were booked on or after January 1, 2009, less any amounts already credited to customers. In September 2012, PacifiCorp filed a petition for reconsideration and a petition requesting a stay of the effectiveness of the order. In October 2012, PacifiCorp filed a reply to the intervening parties' and WUTC staff's answers to PacifiCorp's petitions. The WUTC indicated it will act on PacifiCorp's petitions by December 31, 2012. Also in October 2012, PacifiCorp submitted a compliance filing with the WUTC presenting Washington-allocated actual and projected REC sales proceeds from April 2011 through December 2012 and the amount of rate credits provided to customers for the same period.
In July 2011, PacifiCorp filed a general rate case with the WUTC requesting an annual increase of $13 million, or an average price increase of 4%, with an effective date no later than June 1, 2012. In February 2012, the parties to the proceeding filed a settlement agreement with the WUTC reflecting an annual increase of $5 million, or an average price increase of 2%. In March 2012, the WUTC approved the settlement agreement with an effective date of June 2012.
Idaho
In February 2012, PacifiCorp filed an ECAM application with the IPUC requesting recovery of $18 million in deferred net power costs with a $3 million increase to the current ECAM surcharge rate. In March 2012, the IPUC approved the new rates with an effective date of April 2012. In April 2012, Monsanto Company filed a motion for reconsideration of the IPUC order. As a result, the IPUC ordered a workshop to discuss certain aspects of PacifiCorp's ECAM application. In June 2012, the parties filed final comments with the IPUC supporting an increase to the current ECAM surcharge rate that will result in recovery of $18 million in deferred net power costs. In July 2012, the IPUC issued a final order approving the agreement reached by the parties.
MidAmerican Energy
On February 21, 2012, MidAmerican Energy filed an application with the IUB for an interim and final increase in Iowa retail electric rates in the form of two adjustment clauses to be added to customers' bills. The requested adjustment clauses and a modification to current revenue sharing provisions are consistent with a November 2011 settlement agreement between MidAmerican Energy and the Iowa Office of Consumer Advocate ("OCA"), in which the parties agreed to support the proposed changes. The adjustment clauses would recover anticipated increases in retail coal and coal transportation costs and environmental control expenditures subject to an aggregate maximum of $39 million, or 3.4%, for 2012 and an additional $37 million for an aggregate maximum of $76 million for 2013, or a 3.2% increase from 2012. The requested modification to the existing revenue sharing provisions provides for MidAmerican Energy to share with its customers 20% of revenue associated with Iowa electric returns on equity between 10% and 10.5%, 50% of revenue associated with Iowa electric returns on equity between 10.5% and 11.75%, 75% of revenue associated with Iowa electric returns on equity between 11.75% and 13.0% and 83.3% of revenue associated with Iowa electric returns on equity above 13.0%. Such shared amounts would reduce MidAmerican Energy's investment in the Walter Scott, Jr. Energy Center Unit 4. Pursuant to the settlement agreement, MidAmerican Energy is not precluded from seeking interim rate relief in 2013. MidAmerican Energy implemented the adjustment clauses on an interim basis in March 2012. On July 27, 2012, MidAmerican Energy, the OCA and a group of large industrial customers jointly filed a new settlement agreement with the IUB that resolved all issues surrounding the Iowa proceeding. This settlement agreement consolidated the two proposed adjustment clauses into a single clause with a fixed revenue increase of $39 million in 2012 and an additional $37 million in 2013. The new settlement agreement contained the same revenue sharing provisions as the November 2011 settlement agreement. On October 8, 2012, the IUB issued an order approving the July 27, 2012 settlement agreement.
37
Environmental Laws and Regulations
The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, RPS, 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 the Company'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 other state, local and international agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and the Company is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. The Company believes it is in material compliance with all applicable laws and regulations. Refer to "Liquidity and Capital Resources" for discussion of the Company's forecasted environmental-related capital expenditures. The discussion below contains material developments to those matters disclosed in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2011.
Clean Air Standards
National Ambient Air Quality Standards
In June 2012, the EPA released a proposal to strengthen the fine particulate matter National Ambient Air Quality Standards, reducing the standard from 15 micrograms per cubic meter to a range of 12 to 13 micrograms per cubic meter while taking comment on a standard of 11 micrograms per cubic meter. The EPA is also proposing a new, separate fine particulate matter standard of either 28 or 30 deciviews or measure of haze, aimed at improving visibility. The public comment period closed August 31, 2012. The EPA is required to finalize the proposal by December 14, 2012. Until the standards are final and attainment designations made, the Company cannot determine the potential impacts of the standards; however, any impacts are not anticipated to be significant.
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 on February 16, 2012, with an effective date of April 16, 2012, and requires that new and existing coal-fueled 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. While the final MATS continues to be reviewed by the Company, the Company 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 the Company's ability to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants. The Company 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. The Company is evaluating whether or not to close certain units. As a result of recent testing and evaluation, PacifiCorp currently anticipates that retiring the Carbon Facility in early 2015 will be the least-cost alternative to comply with the MATS and other environmental regulations. PacifiCorp continues to assess compliance alternatives and potential transmission system impacts that could otherwise impact PacifiCorp's ultimate decision with respect to the Carbon Facility, including timing of retirement and decommissioning. Incremental costs to install and maintain emissions control equipment at the Company'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 are pending against the MATS in the D.C. Circuit, which may have an impact on the Company's compliance obligations and the timing of those obligations.
38
Cross-State Air Pollution Rule
In August 2012, the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") vacated the Cross-State Air Pollution Rule ("CSAPR") in a 2-1 decision after it determined that the CSAPR exceeded the EPA's statutory authority. The CSAPR was promulgated by the EPA as the replacement rule for the Clean Air Interstate Rule after it was struck down by the D.C. Circuit in July 2008, and was designed to reduce interstate transport of emissions of ozone and fine particulate matter from downwind states in the eastern United States. In a petition filed in October 2012, the EPA sought a full review of the CSAPR ruling by the entire D.C. Circuit. Until such time as the challenges to the CSAPR are resolved or the EPA proposes and adopts a new rule, the Company will continue to operate in compliance with the Clean Air Interstate Rule, which has remained in effect since the D.C. Circuit stayed the CSAPR in December 2011.
Regional Haze
In May 2012, the EPA published in the Federal Register a proposal to partially approve and partially disapprove the Utah regional haze state implementation plan ("SIP"). The EPA's partial approval of the sulfur dioxide portion of the SIP is based on a sulfur dioxide milestone and backstop trading program to reduce emissions. The partial disapproval is based on the EPA's assertion that the Utah Department of Environmental Quality failed to conduct the appropriate five-factor best available retrofit technology analysis for nitrogen oxides and particulate matter. The EPA did not propose to issue a Federal Implementation Plan ("FIP"), but acknowledged the state's ongoing efforts to conduct the required analysis. The public comment period closed on the EPA's proposed action in July 2012 and the Company expects a final decision in the fourth quarter of 2012.
In May 2012, the EPA published in the Federal Register a proposal to approve the Wyoming regional haze SIP for sulfur dioxide. The Wyoming SIP utilizes the same trading program utilized by Utah. The EPA's public comment period closed in July 2012. In addition, the EPA published in the Federal Register a proposal to partially approve and partially disapprove the Wyoming regional haze SIP for nitrogen oxides and particulate matter and issue a FIP for those portions proposed to be disapproved. The EPA action proposed to accelerate the installation of selective catalytic reduction equipment at PacifiCorp's Jim Bridger Units 1 and 2 to 2017 from 2021 and 2022, but agreed to accept comment on maintaining the original schedule as the state proposed. In addition, the EPA proposed to reject the SIP for the Wyodak facility and Dave Johnston Unit 3 and require the installation of selective non-catalytic reduction equipment within five years, as well as requiring the installation of low-nitrogen oxides burners and overfire air systems at Dave Johnston Units 1 and 2. The EPA held public hearings on its proposed disapproval on June 26 and 28, 2012, and the written comment period closed August 3, 2012. Until the EPA takes final action on the SIP or FIP and the appropriate appeal period passes, the Company cannot fully determine the impacts of the EPA's proposal.
In July 2012, the EPA published in the Federal Register a proposal to partially approve and partially disapprove the Arizona regional haze SIP addressing, among others, the Cholla generating facility. PacifiCorp owns 100% of Cholla Unit 4. The Arizona SIP provided for low-nitrogen oxides burners, while the proposed FIP would require installation of selective catalytic reduction equipment within five years after final action. The written comment period closed September 18, 2012. On October 12, 2012, the State of Arizona provided notice of its intent to file a citizen suit under Section 304 of the Clean Air Act for failing to timely act on the SIP for regional haze and for bifurcating its decision on Arizona's state-wide plan into two parts. Until the EPA takes final action on the SIP or FIP or otherwise addresses the potential citizens' suit, the Company cannot fully determine the impacts of the EPA's proposal.
39
Climate Change
GHG New Source Performance Standards
Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. The EPA entered into a settlement agreement with a number of parties, including certain state governments and environmental groups, in December 2010 to promulgate emissions standards covering GHG. In April 2012, the EPA proposed new source performance standards for new fossil-fueled generating facilities that would limit emissions of carbon dioxide to 1,000 pounds per megawatt hour. The proposal exempts simple cycle combustion turbines from meeting the GHG standards. The public comment period closed in June 2012. The EPA indicated in the proposal that it does not have sufficient information to establish GHG new source performance standards for modified or reconstructed units and has not established a schedule for when these units, or other existing sources, will be regulated. Any new fossil-fueled generating facilities constructed by the Company will be required to meet the final GHG new source performance standards, which, if finalized as proposed, will preclude the construction of any coal-fueled generating facilities that do not have carbon capture and sequestration. Additionally, as proposed, it may be difficult even for combined cycle combustion turbines to meet the carbon dioxide emission standard under certain operating scenarios such as simple cycle or low-load operations on a sustained basis. Until any standards for existing, modified or reconstructed units are proposed and finalized, the impact on the Company's existing facilities cannot be determined.
GHG Litigation
In 2007, the United States District Court for the Southern District of Mississippi ("Southern District of Mississippi") dismissed the case of Ned Comer, et al. v. Murphy Oil USA, et al. ("Comer I"). Plaintiffs brought the putative class action lawsuit based on claims that the defendants' GHG emissions contributed to global warming that resulted in a rise in sea level and added to the ferocity of Hurricane Katrina, which caused damage to the plaintiffs' property. Plaintiffs petitioned for a rehearing before the full court of the United States Court for Appeals for the Fifth Circuit ("Fifth Circuit") in March 2010, but in May 2010, the Fifth Circuit dismissed the appeal for failure to have a quorum. The dismissal resulted in the Southern District of Mississippi's decision, holding that property owners did not have standing to sue for climate change and that climate change was a political question for the United States Congress, standing as good law. However, in May 2011, the Comer case was refiled ("Comer II") in the Southern District of Mississippi. In response to the defendants' motions to dismiss in Comer II, the Southern District of Mississippi, in March 2012, granted the motions, dismissing the suit with prejudice. Plaintiffs filed an appeal with the Fifth Circuit in April 2012. The Company was not a party in Comer I and is not a party in Comer II.
In September 2012, the United States Court of Appeals for the Ninth Circuit (“Ninth Circuit”) issued its opinion in Native Village of Kivalina v. ExxonMobil ("Kivalina"), affirming the United States District Court for the Northern District of California's dismissal of the plaintiffs' complaint. MEHC was a named defendant in the Kivalina case. The Ninth Circuit held that the Clean Air Act displaced the plaintiffs' federal common law claims. On October 4, 2012, the plaintiffs filed a petition for a full rehearing by the Ninth Circuit.
Collateral and Contingent Features
Debt of MEHC and debt and preferred securities of certain of its subsidiaries are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of the rated company'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.
MEHC and its subsidiaries have 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. The Company's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order to draw upon their availability but, under certain instances, must maintain sufficient covenant tests if ratings drop below a certain level. 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.
40
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain provisions that require certain of MEHC's subsidiaries, principally the Utilities, to maintain specific credit ratings on their unsecured debt from 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 the subsidiary's creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2012, these subsidiary's credit ratings from the three recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of September 30, 2012, the Company would have been required to post $537 million of additional collateral. The Company'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 5 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for a discussion of the Company's collateral requirements specific to the Company's derivative contracts.
In accordance with MEHC's equity commitment agreement related to Topaz, if MEHC does not maintain at least an investment grade credit rating from at least two of the three credit ratings agencies, MEHC's obligations under the equity commitment agreement would be supported by cash collateral or a letter of credit issued by a financial institution that meets certain minimum criteria specified in the financing documents. Upon reaching the final commercial operation date of the Topaz Project, MEHC will have no further obligation to make any equity contribution and any unused equity contribution obligations will be canceled.
In July 2010, the President signed into law the Dodd-Frank Reform Act. The Dodd-Frank Reform Act reshapes financial regulation in the United States by creating new regulators, regulating new markets and firms, and providing new enforcement powers to regulators. Virtually all major areas of the Dodd-Frank Reform Act are subject to extensive rulemaking proceedings being conducted both jointly and independently by multiple regulatory agencies, some of which have been completed and others that are expected to be finalized in late 2012 and 2013.
The Company is a party to derivative contracts, including over-the-counter derivative contracts. The Dodd-Frank Reform Act provides for extensive new regulation of over-the-counter derivative contracts and certain market participants, including imposition of mandatory clearing, exchange trading, capital, margin, reporting, recordkeeping, and business conduct requirements primarily for "swap dealers" and "major swap participants." The Dodd-Frank Reform Act provides certain exemptions from these requirements for commercial end-users when using derivatives to hedge or mitigate commercial risk of their businesses. While the Company generally does not enter into over-the-counter derivative contracts for purposes unrelated to hedging or mitigating commercial risk and does not anticipate that it will be considered a swap dealer or major swap participant, the outcome of remaining rulemaking proceedings cannot be predicted and, therefore, the impact of the Dodd-Frank Reform Act on the Company's consolidated financial results cannot be determined at this time.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting the Company, 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, impairment of long-lived assets and goodwill, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2011. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2011.
41
Item 3. | Quantitative and Qualitative Disclosures About Market Risk |
For quantitative and qualitative disclosures about market risk affecting the Company, see Item 7A of the Company's Annual Report on Form 10-K for the year ended December 31, 2011. The Company's exposure to market risk and its management of such risk has not changed materially since December 31, 2011. Refer to Note 5 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for disclosure of the Company's derivative positions as of September 30, 2012.
Item 4. | Controls and Procedures |
At the end of the period covered by this Quarterly Report on Form 10-Q, the Company carried out an evaluation, under the supervision and with the participation of the Company'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 the Company'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, the Company's management, including the Chief Executive Officer (principal executive officer) and the Chief Financial Officer (principal financial officer), concluded that the Company's disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company 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 the Company'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 the Company's internal control over financial reporting during the quarter ended September 30, 2012 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.
42
PART II
Item 1. | Legal Proceedings |
For a description of certain legal proceedings affecting the Company, refer to Note 10 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 the Company's risk factors from those disclosed in Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, 2011.
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 the Company's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Reform 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.
43
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.
MIDAMERICAN ENERGY HOLDINGS COMPANY | |
(Registrant) | |
Date: November 2, 2012 | /s/ Patrick J. Goodman |
Patrick J. Goodman | |
Executive Vice President and Chief Financial Officer | |
(principal financial and accounting officer) |
44
EXHIBIT INDEX
Exhibit No. | Description |
4.1 | Fiscal Agency Agreement, dated August 27, 2012, by and between Northern Natural Gas Company and The Bank of New York Mellon Trust Company, N.A., Fiscal Agent, relating to the $250,000,000 in principal amount of the 4.10% Senior Bonds due 2042. |
10.1 | £150,000,000 Facility Agreement, dated August 20, 2012, among Northern Powergrid Holdings Company, as Borrower, and Abbey National Treasury Services plc, Lloyds TSB Bank plc and The Royal Bank of Scotland plc, as Original Lenders. |
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 MidAmerican Energy Holdings Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, 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 Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail. |
45