NRG Energy 10-Q 2010
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the quarterly period ended: September 30, 2010
Commission File Number: 001-15891
NRG Energy, Inc.
(Exact name of registrant as specified in its charter)
(Registrants telephone number, including area code)
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 þ 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 þ 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. (Check one):
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No þ
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
Yes þ No o
As of November 1, 2010, there were 247,197,248 shares of common stock outstanding, par value $0.01 per share.
TABLE OF CONTENTS
CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION
This Quarterly Report on Form 10-Q of NRG Energy, Inc., or NRG or the Company, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. The words believes, projects, anticipates, plans, expects, intends, estimates and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause NRGs actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Risks Factors Related to NRG Energy, Inc. in Part I, Item 1A, of the Companys Annual Report on Form 10-K, for the year ended December 31, 2009, including the following:
Forward-looking statements speak only as of the date they were made, and NRG 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 review of factors that could cause NRGs actual results to differ materially from those contemplated in any forward-looking statements included in this Quarterly Report on Form 10-Q should not be construed as exhaustive.
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
The FASB has established the FASB Accounting Standards Codification, or ASC, as the source of authoritative U.S. GAAP. The FASB issues updates to the ASC through Accounting Standards Updates, or ASUs. The following ASC topics and ASUs are referenced in this report:
PART I FINANCIAL INFORMATION
ITEM 1 CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
See notes to condensed consolidated financial statements.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
See notes to condensed consolidated financial statements.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
See notes to condensed consolidated financial statements.
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 1 Basis of Presentation
NRG Energy, Inc., or NRG or the Company, is primarily a wholesale power generation company with a significant presence in major competitive power markets in the U.S., as well as a major retail electricity provider in the ERCOT (Texas) market. NRG is engaged in the ownership, development, construction and operation of power generation facilities, both conventional and renewable, the transacting in and trading of fuel and transportation services, the trading of energy, capacity and related products in the U.S. and select international markets, and supply of electricity and energy services to retail electricity customers in the Texas market.
The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SECs regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the Companys financial statements in its Annual Report on Form 10-K for the year ended December 31, 2009, or 2009 Form 10-K. Interim results are not necessarily indicative of results for a full year.
In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Companys consolidated financial position as of September 30, 2010, the results of operations for the three and nine months ended September 30, 2010, and 2009, and cash flows for the nine months ended September 30, 2010, and 2009. Certain prior-year amounts have been reclassified for comparative purposes.
Use of Estimates
The preparation of consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions. These estimates and assumptions impact the reported amount of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the consolidated financial statements. They also impact the reported amount of net earnings during the reporting period. Actual results could be different from these estimates.
Note 2 Summary of Significant Accounting Policies
Other Cash Flow Information
NRGs investing activities do not include capital expenditures of $215 million which were accrued and unpaid at September 30, 2010.
Recent Accounting Developments
ASU No. 2009-17 On January 1, 2010, the Company adopted the provisions of ASU No. 2009-17, Consolidations: Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities, or ASU 2009-17. This guidance amends ASC 810 by altering how a company determines when an entity that is insufficiently capitalized or not controlled through its voting interests should be consolidated. The previous ASC 810 guidance required a quantitative analysis of the economic risk/rewards of a Variable Interest Entity, or a VIE, to determine the primary beneficiary. ASU 2009-17 specifies that a qualitative analysis be performed, requiring the primary beneficiary to have both the power to direct the activities of a VIE that most significantly impact the entities economic performance, as well as either the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. The Companys adoption of ASU 2009-17 on January 1, 2010, did not have an impact on its results of operations, financial position or cash flows.
ASU No. 2010-10 In February 2010, the FASB issued ASU No. 2010-10, Consolidation (Topic 810): Amendments for Certain Investment Funds, or ASU 2010-10. The amendments to ASC 810 clarify that related parties should be considered when evaluating the criteria for determining whether a decision makers or service providers fee represents a variable interest. In addition, the amendments clarify that a quantitative calculation should not be the sole basis for evaluating whether a decision makers or service providers fee represents a variable interest. The Company adopted the provisions of ASU 2010-10 effective January 1, 2010, with no impact on its results of operations, financial position or cash flows.
Other effects of ASU 2009-17/ASU 2010-10 adoption NRG determined that one of its equity method investments was a VIE as of January 1, 2010, upon adoption of this new guidance. NRG owns a 50% interest in Sherbino I Wind Farm LLC, or Sherbino, a 150 MW wind farm operated as a joint venture with BP Wind Energy North America Inc. The Company has determined that Sherbino is a VIE, but the Company is not the primary beneficiary, under the amended guidance in ASU 2009-17 and ASU 2010-10. Therefore, NRG will continue to account for its investment in Sherbino under the equity method. NRGs maximum exposure to loss is limited to its equity investment, which is $100 million as of September 30, 2010.
Borrowings of an equity method investment In December 2008, Sherbino entered into a 15-year term loan facility which is non-recourse to NRG. As of September 30, 2010, the outstanding principal balance of the term loan facility was $131 million, and is secured by substantially all of Sherbinos assets and membership interests.
ASU No. 2010-09 In February 2010, the FASB issued ASU No. 2010-09, Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements, or ASU 2010-09. Under the amendments of ASU 2010-09, an entity that is an SEC filer is not required to disclose the date through which subsequent events have been evaluated. As this guidance provides only disclosure requirements, the adoption of ASU 2010-09 effective January 1, 2010, did not impact the Companys results of operations, financial position or cash flows.
Other The following accounting standards were adopted on January 1, 2010, with no impact on the Companys results of operations, financial position or cash flows:
Note 3 Comprehensive Income
The following table summarizes the components of the Companys comprehensive income/(loss), net of tax:
The following table summarizes the changes in the Companys accumulated other comprehensive income, net of tax:
Note 4 Business Acquisitions and Dispositions
Acquisitions Closed or Announced in 2010
The following acquisitions were announced during the third quarter of 2010:
Green Mountain On September 16, 2010, NRG agreed to acquire Green Mountain Energy Company, or Green Mountain, for $350 million in cash. Austin-based Green Mountain, a leading retail provider of clean energy products and services, has residential and commercial customers primarily in Texas, Oregon, and the New York metro region. Green Mountain also delivers renewable products and services to select utilities that are better for the environment, as well as providers in New York and New Jersey. Green Mountain, which will be managed and operated as a distinct retail business within NRG, offers cleaner electricity products from renewable sources and a variety of carbon offset products. NRG anticipates funding the transaction with cash on hand. The transaction, which is expected to close in November 2010, has received the required regulatory approvals, but remains subject to customary closing conditions.
Dynegy Plants On August 13, 2010, NRG signed a definitive agreement with an affiliate of The Blackstone Group L.P., or Blackstone, to purchase 3,884 MW of Dynegy Inc., or Dynegy, assets in California and Maine for $1.36 billion in cash. The Dynegy plants in California consist of 1,020 MW of combined cycle, 2,159 MW of steam turbine, and 165 MW of combustion turbine generating capacity, each gas-fired with the exception of an oil-fired combustion turbine. The Maine plant is a 540 MW gas-fired combined cycle facility. Out of the total California capacity to be acquired, 2,159 MW are under tolling agreements with 165 MW under an RMR agreement. The Maine plant dispatches into ISO-NE where it earns capacity revenues. The Company anticipates funding the acquisition with cash on hand. The acquisition is subject to the satisfaction of closing conditions, including the completion of Blackstones acquisition of Dynegy in a separately announced merger (which, itself, requires a vote by the shareholders of Dynegy), and the receipt of required government approvals. There are no assurances that the conditions to Blackstones acquisition of Dynegy will be satisfied or that Blackstones acquisition of Dynegy will be consummated on the terms agreed to, if at all.
Cottonwood On August 12, 2010, NRG agreed to acquire the Cottonwood Generating Station, a 1,279 MW combined cycle natural gas plant in the Entergy zone of east Texas, or Cottonwood, from Kelson Limited Partnership for $525 million in cash. The Company intends to fund the Cottonwood acquisition with cash on hand. The Cottonwood acquisition is expected to close by year end, subject to customary closing conditions and regulatory approvals.
The following acquisitions closed during the second quarter of 2010:
Northwind Phoenix On June 22, 2010, NRG, through its wholly-owned subsidiary, NRG Thermal LLC, or NRG Thermal, acquired Northwind Phoenix, LLC, or Northwind Phoenix, for a total purchase price of $100 million in cash, plus a payment for acquired working capital. Northwind Phoenix owns and operates a district cooling system that provides chilled water to commercial buildings in the Phoenix central business district. In addition, Northwind Phoenix maintains and operates Combined Heat and Power plants that provide chilled water, steam and electricity in metropolitan Tucson and to portions of Arizona State University campuses in Tempe and Mesa. The acquisition was financed by the issuance of $100 million in notes by NRG Thermal. See Note 8, Long-Term Debt to this Form 10-Q, for information related to the notes issued.
South Trent On June 14, 2010, NRG acquired South Trent Wind LLC, owner of the South Trent wind farm, or South Trent, a 101 MW wind farm near Sweetwater, Texas, for a total purchase price of $111 million. South Trent commenced operations in January 2009 and consists of 44 turbines producing up to 2.3 MW of power each. The project has a 20-year PPA, which commenced January 2009, for all generation from the site. In connection with the acquisition, NRG paid $32 million in cash and South Trent entered into a financing arrangement that includes a $79 million term loan. See Note 8, Long-Term Debt to this Form 10-Q, for information related to this financing arrangement.
2009 Acquisition of Reliant Energy
As discussed more fully in Note 3 Business Acquisitions, to the Companys 2009 Form 10-K, NRG acquired Reliant Energy on May 1, 2009, for total consideration of approximately $401 million. The following measurement period adjustments to the provisional amounts recorded as of December 31, 2009, attributable to refinement of the underlying appraisal assumptions, were recognized during the first quarter of 2010, the end of the measurement period: customer relationships decreased by $6 million and current and non-current liabilities increased by $6 million, resulting in no change to net assets acquired. The accounting for this business combination was completed on March 31, 2010.
Padoma On January 11, 2010, NRG sold its terrestrial wind development company, Padoma Wind Power LLC, or Padoma, to Enel North America, Inc., or Enel. NRG retained its existing ownership interest in its three Texas wind farms: Sherbino, Elbow Creek and Langford. In addition, NRG will maintain a strategic partnership with Enel to evaluate potential opportunities in renewable energy, including the opportunity to participate in wind projects currently in development. NRG recognized a gain on the sale of Padoma of $23 million, which was recorded as a component of operating income in the statement of operations.
MIBRAG On June 10, 2009, NRG sold its 50% ownership interest in Mibrag B.V. whose principal holding was MIBRAG. For its share, NRG received EUR 203 million ($284 million at an exchange rate of 1.40 U.S.$/EUR), net of transaction costs. During the nine months ended September 30, 2009, NRG recognized an after-tax gain of $128 million. Prior to completion of the sale, NRG continued to record its share of MIBRAGs operations to Equity in earnings of unconsolidated affiliates. In connection with the transaction, NRG entered into a foreign currency forward contract to hedge the impact of exchange rate fluctuations on the sale proceeds. For the nine months ended September 30, 2009, NRG recorded an exchange loss of $24 million on the contract within Other income/(expense), net.
Note 5 Fair Value of Financial Instruments
The estimated carrying values and fair values of NRGs recorded financial instruments are as follows:
Recurring Fair Value Measurements
The following table presents assets and liabilities measured and recorded at fair value on the Companys condensed consolidated balance sheet on a recurring basis and their level within the fair value hierarchy:
There have been no transfers during the three months and nine months ended September 30, 2010, between Levels 1 and 2. The following table reconciles the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements using significant unobservable inputs:
Realized and unrealized gains and losses included in earnings that are related to the energy derivatives are recorded in operating revenues and cost of operations.
In determining the fair value of NRGs Level 2 and 3 derivative contracts, NRG applies a credit reserve to reflect credit risk which is calculated based on credit default swaps. As of September 30, 2010, the credit reserve resulted in a $6 million decrease in fair value which is composed of a $3 million loss in OCI and a $3 million loss in operating revenue and cost of operations.
Concentration of Credit Risk
In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, to the Companys 2009 Form 10-K, the following item is a discussion of the concentration of credit risk for the Companys financial instruments. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply and retail customer credit risk through its retail load activities.
Counterparty Credit Risk
The Company monitors and manages counterparty credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits; (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty credit risk with a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at NRG to cover the credit risk of the counterparty until positions settle.
As of September 30, 2010, counterparty credit exposure to a significant portion of the Companys counterparties was $1.7 billion and NRG held collateral (cash and letters of credit) against those positions of $461 million, resulting in a net exposure of $1.2 billion. Counterparty credit exposure is discounted at the risk free rate. The following table highlights the counterparty credit quality and the net counterparty credit exposure by industry sector. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and Normal Purchase Normal Sale, or NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.
NRG has counterparty credit risk exposure to certain counterparties representing more than 10% of the total net exposure discussed above and the aggregate of such counterparties was $435 million. Approximately 79% of NRGs positions relating to this credit risk roll-off by the end of 2012. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Companys financial results or results of operations from nonperformance by any of NRGs counterparties.
Counterparty credit exposure described above excludes credit risk exposure under California tolling agreements, Northeast and South Central load obligations and a coal supply agreement, which are generally long-term. As external sources or observable market quotes are not available to estimate such exposure, the Company valued these contracts based on various techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of September 30, 2010, credit risk exposure to these counterparties is approximately $550 million. Many of these power contracts are with utilities or public power entities that have strong credit quality and specific public utility commission or other regulatory support. In the case of the coal supply agreement, NRG holds a lien against the underlying asset. These factors significantly reduce the risk of loss.
Retail Customer Credit Risk
NRG is exposed to retail credit risk through the Companys competitive electricity supply business, which serves C&I customers and the Mass market in Texas. Retail credit risk results when a customer fails to pay for services rendered. The losses may result from both nonpayment of customer accounts receivable and the loss of in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangements.
As of September 30, 2010, the Companys retail customer credit exposure to C&I customers was diversified across many customers and various industries, with a significant portion of the exposure with government entities.
NRG is also exposed to retail customer credit risk relating to its Mass customers, which results in a write-off of bad debt. During 2010, the Company continued to experience improved customer payment behavior, but current economic conditions may affect the ability of the Companys customers to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense.
This footnote should be read in conjunction with the complete description under Note 5, Fair Value of Financial Instruments, to the Companys 2009 Form 10-K.
Note 6 Nuclear Decommissioning Trust Fund
NRGs nuclear decommissioning trust fund assets, which are for its portion of the decommissioning of the South Texas Project, or STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. NRG accounts for the nuclear decommissioning trust fund in accordance with ASC-980 Regulated Operations, or ASC 980. Since the Company is in compliance with the Public Utility Commission of Texas, or PUCT, rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other than-temporary-impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear Decommissioning Trust Liability to the ratepayers and are not included in net income or accumulated other comprehensive income, consistent with regulatory treatment.
The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the trust funds as of September 30, 2010, and December 31, 2009, as well as information about the contractual maturities of those securities. The cost of securities sold is determined on the specific identification method.
The following tables summarize proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales:
Note 7 Accounting for Derivative Instruments and Hedging Activities
This footnote should be read in conjunction with the complete description under Note 6, Accounting for Derivative Instruments and Hedging Activities, to the Companys 2009 Form 10-K.
As of September 30, 2010, NRG had cash flow hedge energy-related derivative financial instruments extending through December 2013.
Interest Rate Swaps
NRG is exposed to changes in interest rates through the Companys issuance of variable and fixed rate debt. In order to manage the Companys interest rate risk, NRG enters into interest rate swap agreements. As of September 30, 2010, NRG had interest rate derivative instruments extending through June 2028, the majority of which had been designated as either cash flow or fair value hedges.
Volumetric Underlying Derivative Transactions
The following table summarizes the net notional volume buy/(sell) of NRGs open derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of September 30, 2010, and December 31, 2009. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.
Fair Value of Derivative Instruments
The following table summarizes the fair value within the derivative instrument valuation on the balance sheet:
Accumulated Other Comprehensive Income
The following table summarizes the effects of ASC 815 on NRGs Accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:
Amounts reclassified from Accumulated OCI into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to operating revenue for commodity contracts and interest expense for interest rate contracts.
The following table summarizes the amount of gain/(loss) resulting from fair value hedges reflected in interest income/(expense) for interest rate contracts:
Impact of Derivative Instruments on the Statement of Operations
In accordance with ASC 815, unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedge derivatives and ineffectiveness of hedge derivatives are reflected in current period earnings.
The following table summarizes the pre-tax effects of economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activity on NRGs statement of operations. These amounts are included within operating revenues and cost of operations.
Reliant Energys loss positions were acquired as of May 1, 2009, and valued using forward prices on that date. The roll-off amounts were offset by realized losses at the settled prices and are reflected in the cost of operations during the same period.
For the nine months ended September 30, 2010, the $129 million loss from economic hedge positions is the result of a decrease in value of forward purchases and sales of natural gas, electricity and fuel due to a decrease in forward power and gas prices.
For the nine months ended September 30, 2009, the $70 million gain from economic hedge positions includes a $217 million gain recognized in earnings from previously deferred amounts in Accumulated OCI as the Company discontinued cash flow hedge accounting for certain 2009 transactions in Texas and New York due to lower expected generation, a $29 million loss from discontinued normal purchase and sales for coal purchases and a $118 million loss in value of forward purchases and sales of electricity and fuel due to a decrease in forward power and gas prices.
Credit Risk Related Contingent Features
Certain of the Companys hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed adequate assurance under the agreements, or require the Company to post additional collateral if there was a one notch downgrade in the Companys credit rating. The collateral required for contracts that have adequate assurance clauses that are in a net liability position as of September 30, 2010, was $51 million. The collateral required for contracts with credit rating contingent features was $55 million. The Company is also a party to certain marginable agreements where NRG has a net liability position but the counterparty has not called for the collateral due, which is approximately $16 million as of September 30, 2010.
See Note 5, Fair Value of Financial Instruments, to this Form 10-Q for discussion regarding concentration of credit risk.
Note 8 Long-Term Debt
Senior Credit Facility
In March 2010, NRG made a repayment of approximately $229 million to its first lien lenders under the Term Loan Facility. This payment resulted from the mandatory annual offer of a portion of NRGs excess cash flow (as defined in the Senior Credit Facility) for 2009. The Company is contemplating making a prepayment on the 2011 mandatory offer related to 2010 in the fourth quarter of 2010.
Amendment and Extension of Maturity Dates
As of September 30, 2010, NRG had issued $850 million of letters of credit under the Funded Letter of Credit Facility, leaving $450 million available for future issuances. Under the Revolving Credit Facility as of September 30, 2010, NRG had issued a letter of credit of $36 million, leaving $839 million available.
Issuance of 2020 Senior Notes
On August 20, 2010, NRG issued $1.1 billion aggregate principal amount at par of 8.25% Senior Notes due 2020, or 2020 Senior Notes. The 2020 Senior Notes were issued under an Indenture, dated February 2, 2006, between NRG and Law Debenture Trust Company of New York, as trustee, as amended through Supplemental Indentures, which is discussed in Note 12 Debt and Capital Leases, in the Companys 2009 Form 10-K. The Indentures and the form of the notes provide, among other things, that the 2020 Senior Notes will be senior unsecured obligations of NRG.
The net proceeds of $1.086 billion are intended to be used for general corporate purposes, including, without limitation, working capital needs, investment in business initiatives and capital expenditures, and potentially to prepay or repurchase outstanding indebtedness of NRG and/or its subsidiaries or to fund recently announced acquisitions. Interest is payable semi-annually beginning on March 1, 2011, until their maturity date of September 1, 2020. As of September 30, 2010, $1.1 billion in principal was outstanding under the 2020 Senior Notes.
Prior to September 1, 2013, NRG may redeem up to 35% of the aggregate principal amount of the 2020 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 108.25% of the principal amount. Prior to September 1, 2015, NRG may redeem all or a portion of the 2020 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of (i) 1% of the principal amount of the note; or (ii) the excess of the principal amount of the note over the following: the present value of 104.125% of the note, plus interest payments due on the note from the date of redemption through September 1, 2015, discounted at a Treasury rate plus 0.50%. In addition, on or after September 1, 2015, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
Indian River Power LLC Tax-Exempt Bonds
On October 12, 2010, NRG executed a $190 million tax-exempt bond financing, or the Indian River bonds, through its wholly-owned subsidiary, Indian River Power LLC. The bonds were issued by the Delaware Economic Development Authority and will be used for construction of emission control equipment on the Indian River Generating Station in Millsboro, DE. The bonds were issued at a rate of 5.375%, have a maturity date of October 1, 2045, and are supported by an NRG guarantee. The proceeds received on October 12, 2010, were $66 million, and the remaining balance will be received over time as construction costs are paid.
Dunkirk Power LLC Tax-Exempt Bonds
On February 1, 2010, the Company fixed the rate on the Dunkirk bonds originally issued in April 2009, at 5.875%. In addition, the $59 million letter of credit issued by NRG in support of the bonds was cancelled and replaced with an NRG guarantee.
Debt Related to Capital Allocation Program
On March 3, 2010, the Company completed the early unwinding of the CSF I Debt by remitting a cash payment to Credit Suisse, or CS, of $242 million to settle the outstanding principal and interest, as compared to $249 million that would have been due at maturity in June 2010. As part of the unwind, CS returned to NRG 6,600,000 shares of NRG common stock borrowed under the Share Lending Agreement, or SLA, between the parties and released all 12,441,973 shares of NRG common stock held as collateral for the CSF I Debt. The 6,600,000 shares of NRG common stock were returned to treasury stock and will no longer be treated as outstanding for corporate law purposes. The Company has now settled all obligations related to the CSF I and II Debt entered into in 2006, as amended from time to time, as well as the SLA entered into in February 2009.
Blythe Credit Agreement
On June 24, 2010, NRG Solar Blythe LLC, or Blythe, entered into a credit agreement with a bank, or the Blythe Credit Agreement, for a $30 million term loan which has an interest rate of LIBOR plus an applicable margin which escalates 0.25% every three years and ranges from 2.5% at closing to 3.75% in year fifteen. The term loan matures in June 2028, amortizes based upon a predetermined schedule, and is secured by all of the assets of Blythe. The bank has also issued two letters of credit on behalf of Blythe totaling approximately $6.4 million. Blythe pays an availability fee of 100% of the applicable margin on these issued letters of credit.
Also related to the Blythe Credit Agreement, on June 25, 2010, Blythe entered into a fixed for floating interest rate swap for 75% of the outstanding term loan amount, intended to hedge the risks associated with floating interest rates. Blythe will pay its counterparty the equivalent of a 3.563% fixed interest payment on a predetermined notional value, and Blythe will receive quarterly the equivalent of a floating interest payment based on a three month LIBOR calculated on the same notional value. All interest rate swap payments by Blythe and its counterparty are made quarterly and the LIBOR is determined in advance of each interest period. The notional amount of the swap, which matures on June 25, 2028, is $22 million and amortizes in proportion to the loan.
South Trent Financing Agreement
On June 14, 2010, NRG completed the acquisition of South Trent, as discussed in Note 4, Business Acquisitions and Dispositions to this Form 10-Q. As part of the purchase price consideration, South Trent entered into the Amended and Restated Financing Agreement, or Financing Agreement, with a group of lenders, which matures on June 14, 2020. The Financing Agreement includes a $79 million term loan, as well as a $10 million letter of credit facility in support of the PPA, for which the full amount had been issued as of September 30, 2010. The Financing Agreement also provides for up to $8 million in additional letter of credit facilities, none of which are utilized as of September 30, 2010. The term loan accrues interest at LIBOR plus a margin based upon a grid, which is initially 2.50% and increases every two years by 12.5 basis points. The term loan amortizes quarterly based upon a predetermined schedule with the unamortized portion due at maturity.
Under the terms of the Financing Agreement, South Trent was required to enter into interest rate protection agreements that would fix the interest rate for a minimum of 75% of the outstanding principal amount. Accordingly, on June 14, 2010, South Trent entered into five interest rate swaps, intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, South Trent will pay its counterparty the equivalent of a 3.265% fixed interest payment on a predetermined notional value, and South Trent will receive the quarterly equivalent of a floating interest payment based on a three month LIBOR calculated on the same notional value. All interest rate swap payments by South Trent and its counterparties are made quarterly and the LIBOR is determined in advance of each interest period. The total notional amount of these swaps, which mature on June 14, 2020, is $59 million. The swaps amortize in proportion to the loan.
South Trent also entered into a series of forward-starting interest rate swaps that will become effective June 14, 2020, and are effective for eight years. The swaps are intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, South Trent will pay its counterparty the equivalent of a 4.95% fixed interest payment on a predetermined notional value, and receive the quarterly equivalent of a floating interest payment based on a three month LIBOR calculated on the same notional value. All interest rate swap payments by South Trent and its counterparties will be made quarterly and the LIBOR is determined in advance of each interest period. The total notional amount of these swaps, which will mature on June 14, 2028, is $21 million.
NRG Thermal Financing
On June 22, 2010, NRG Thermals largest subsidiary, NRG Energy Center Minneapolis LLC, or NRG Thermal Minneapolis, issued $100 million of 5.95% Series C notes due June 23, 2025, or the Series C Notes. The Series C Notes are secured by substantially all of the assets of NRG Energy Center Minneapolis. NRG Thermal has guaranteed the indebtedness and its guarantee is secured by a pledge of the equity interest in all of NRG Thermals subsidiaries. At the same time, NRG Thermal amended agreements for its other outstanding notes to conform to the covenants of the Series C Notes. The proceeds of the loan were used to finance the acquisition of Northwind Phoenix, as discussed in Note 4, Business Acquisitions and Dispositions to this Form 10-Q.
GenConn Energy LLC Related Financings
NRG Connecticut Peaking Development LLC, or NRG Connecticut Peaking, made funding requests under the equity bridge loan, or EBL, during the quarter. The EBL is backed by a letter of credit issued by NRG under its Funded Letter of Credit Facility equal to at least 104% of the amount outstanding. On September 29, 2010, the Devon project reached its commercial operations date, or COD, in accordance with the financing documents. Accordingly, NRG Connecticut Peaking repaid the $55 million portion of the EBL used to fund the Devon project, and converted $56 million of a promissory note from GenConn into equity. As of September 30, 2010, $61 million was outstanding under the EBL for the Middletown project and the remaining amounts will be drawn as necessary.
Borrowings of an equity method investment In April 2009, GenConn secured financing for 50% of the Devon and Middletown project construction costs through a seven-year term loan facility, and also entered into a five-year revolving working capital loan and letter of credit facility, which collectively with the term loan is referred to as the GenConn Facility. The aggregate credit amount secured under the GenConn Facility, which is non-recourse to NRG, is $291 million, including $48 million for the revolving facility. GenConn began to draw under the GenConn Facility to cover costs related to the Devon project in August 2009, and the Middletown project in June 2010. As of September 30, 2010, $164 million had been drawn.
As of September 30, 2010, NINA had $7 million outstanding under the TANE Facility. On June 1, 2010, NINA repaid $20 million outstanding under its revolving credit facility, and the facility was terminated.
Note 9 Changes in Capital Structure
The following table reflects the changes in NRGs common stock issued and outstanding:
2010 Capital Allocation Plan
As part of the Companys 2010 Capital Allocation Plan, the Company repurchased $50 million of NRGs common stock through open market purchases in the second quarter of 2010. On August 26, 2010, the Company entered into an accelerated share repurchase agreement, or ASR Agreement, with a financial institution to repurchase a total of $130 million of NRG common stock, based on a volume weighted average price less a specified discount. On August 27, 2010, under the ASR Agreement, the Company remitted $130 million to the financial institution, and received 3,208,292 shares of NRG common stock with a fair value of $65 million, with the remaining shares to be delivered at settlement. The ASR Agreement was accounted for as two separate transactions: a $65 million purchase of NRG common stock at cost; and a $65 million forward contract indexed to the Companys own stock. Both transactions were recorded as treasury stock on August 27, 2010. The ASR Agreement settled on October 22, 2010, and the Company received an additional 3,040,919 shares of NRG common stock. The shares repurchased under the ASR Agreement complete the Companys previously announced $180 million share buyback program for 2010.
Share Lending Agreements
As part of the CSF I Debt unwind on March 3, 2010, CS returned to NRG 6,600,000 shares of NRG common stock borrowed under the SLA between the parties. The 6,600,000 shares of NRG common stock were returned to treasury stock and will no longer be treated as outstanding for corporate law purposes. See Note 8, Long-Term Debt, to this Form 10-Q for more information.
4% Preferred Stock
As of January 21, 2010, the Company completed the redemption of all remaining outstanding shares of 4% Preferred Stock, with holders converting 154,029 Preferred Stock shares into 7,701,450 shares of common stock and the Company redeeming 28 Preferred Stock shares for $28 thousand in cash.
Note 10 Equity Compensation
Non-Qualified Stock Options, or NQSOs
The following table summarizes the Companys NQSO activity, and changes during the nine months then ended:
The weighted average grant date fair value of NQSOs granted for the nine months ended September 30, 2010, was $10.67.
Restricted Stock Units, or RSUs
The following table summarizes the Companys non-vested RSU awards, and changes during the nine months then ended:
Performance Units, or PUs
The following table summarizes the Companys non-vested PU awards, and changes during the nine months then ended:
In the nine months ended September 30, 2010, there were no performance unit payouts in accordance with the terms of the performance units.
Deferral Stock Units, or DSUs
The following table summarizes the Companys outstanding DSU awards, and changes during the nine months then ended:
On July 29, 2010, the Companys stockholders approved the Amended and Restated Long Term Incentive Plan, which included an increase in the shares authorized for issuance under the plan from 16 million shares to 22 million shares.
Note 11 Earnings Per Share
Basic earnings per share attributable to NRG common stockholders is computed by dividing net income attributable to NRG Energy Inc. adjusted for accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding.
Diluted earnings per share attributable to NRG common stockholders is computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period.
On March 3, 2010, as part of the CSF I Debt unwind, CS returned 6,600,000 shares of NRG common stock borrowed under the SLA between the parties. These shares had not been treated as outstanding for earnings per share purposes because CS was required to return all borrowed shares (or identical shares) upon termination of the SLA. See Note 8, Long-Term Debt, to this Form 10-Q, for more information on the SLA.
The reconciliation of basic earnings per share to diluted earnings per share attributable to NRG is as follows:
The following table summarizes NRGs outstanding equity instruments that were anti-dilutive and not included in the computation of the Companys diluted earnings per share:
Note 12 Segment Reporting
NRGs segment structure reflects the Companys core areas of operation, which are primarily Reliant Energy, the geographic regions of the Companys wholesale power generation, thermal and chilled water business, and corporate activities. Within NRGs wholesale power generation operations, there are distinct components with separate operating results and management structures for the following regions: Texas, Northeast, South Central, West and International.
Note 13 Income Taxes
Effective Tax Rate
The Companys income tax provision consisted of the following:
For the three months ended September 30, 2010, NRGs overall effective tax rate was lower than the statutory rate of 35% primarily due to the reduction in the valuation allowance resulting from the generation of capital gains during the quarter. For the three months ended September 30, 2009, NRGs effective tax rate was higher than the statutory rate of 35% primarily due to state and local income taxes and the U.S. taxation of foreign earnings.
For the nine months ended September 30, 2010, NRGs overall effective tax rate was higher than the statutory rate of 35% primarily due to the state and local income taxes and the U.S. taxation of foreign earnings. The rate was reduced due to the reduction in the valuation allowance resulting from the generation of overall capital gains during the year. For the nine months ended September 30, 2009, NRGs overall effective tax rate was higher than the statutory rate of 35% primarily due to an increase in the valuation allowance as a result of capital losses generated in the nine month period for which there were no projected capital gains or available tax planning strategies.
Uncertain tax benefits
As of September 30, 2010, NRG has recorded a $557 million non-current tax liability for uncertain tax benefits, primarily resulting from taxable earnings for the period for which there are no net operating losses available to offset for financial statement purposes. NRG has accrued interest related to these uncertain tax benefits of approximately $10 million for the nine months ended September 30, 2010, and has accrued approximately $36 million since adoption. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.
The examination by the Internal Revenue Service for the years 2004 through 2006 is currently in Joint Committee review and is not considered effectively settled in accordance with ASC 740. The Company anticipates conclusion of the audit by March 31, 2011. Upon effective settlement of the audit, the result may be a reduction of the liability for uncertain tax benefits. The Company continues to be under examination for various state jurisdictions for multiple years.
Tax Receivable and Payable
As of September 30, 2010, NRG recorded a current tax payable of $28 million that represents a tax liability due for domestic state taxes of $18 million, as well as foreign taxes payable of $10 million. In addition, as of September 30, 2010, NRG had a domestic tax receivable of $74 million for property tax refunds primarily due to the New York State Empire Zone program. On October 15, 2010, the Empire Zone Designation Board upheld the previous decertification of the Companys Oswego facility from participating in the Empire Zone program. This decertification is effective from January 1, 2008 and prevents the facility from further participation in certain tax benefits provided by this program and associated with property taxes paid. The Company is considering its avenues of appeal, but believes it has adequately reserved for the outcome of this decision.
Note 14 Benefit Plans and Other Postretirement Benefits
NRG Defined Benefit Plans
NRG sponsors and operates three defined benefit pension and other postretirement plans. The NRG Plan for Bargained Employees and the NRG Plan for Non-Bargained Employees are maintained solely for eligible legacy NRG participants. A third plan, the Texas Genco Retirement Plan, is maintained for participation solely by eligible employees. The total amount of employer contributions paid for the nine months ended September 30, 2010, was $15 million. NRG expects to make approximately $3 million in additional contributions for the remainder of 2010.
The net periodic pension cost related to all of the Companys defined benefit pension plans includes the following components:
The net periodic cost related to all of the Companys other postretirement benefits plans includes the following components:
STP Defined Benefit Plans
NRG has a 44% undivided ownership interest in South Texas Project, or STP. South Texas Project Nuclear Operating Company, or STPNOC, which operates and maintains STP, provides its employees a defined benefit pension plan as well as postretirement health and welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations. The total amount of employer contributions reimbursed to STPNOC for the nine months ended September 30, 2010, was $3 million.
The Company recognized net periodic costs related to its 44% interest in STP defined benefits as follows:
Note 15 Commitments and Contingencies
First and Second Lien Structure
NRG has granted first and second liens to certain counterparties on substantially all of the Companys assets to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Companys lien counterparties may have a claim on NRGs assets to the extent market prices exceed the hedged price. As of September 30, 2010, all hedges under the first and second liens were in-the-money on a counterparty aggregate basis.
Nuclear Innovation North America, LLC
CPS Settlement On March 1, 2010, an agreement was reached with CPS for NINA to acquire a controlling interest in the STP Units 3 and 4 Project through a settlement of litigation between the parties. As part of the agreement, NINA increased its ownership in the STP Units 3 and 4 Project from 50% to 92.375% and assumed full management control of the project. NRG also will pay $80 million to CPS, subject to the United States Department of Energys, or U.S. DOE, approval of a fully executed term sheet for a conditional U.S. DOE loan guarantee. The first $40 million would be promptly paid after acceptance of the guarantee with the remaining $40 million paid six months later. NRG also agreed to donate an additional $10 million, unconditionally, over four years in annual payments of $2.5 million to the Residential Energy Assistance Partnership, or REAP, in San Antonio. The first $2.5 million payment to REAP was made on March 17, 2010. In connection with the agreement, the Company capitalized $90 million to construction in progress within property, plant and equipment, and as of September 30, 2010, $87.5 million in liabilities remains on the condensed consolidated balance sheet for the obligations to CPS and REAP. As part of the agreement with CPS, all litigation was dismissed with prejudice.
NINA Investment and Option Agreement On May 10, 2010, NINA and TEPCO Nuclear Energy America LLC, or TNEA, a wholly-owned subsidiary of The Tokyo Electric Power Company of Japan, signed an Investment and Option Agreement whereby TNEA agreed to acquire up to a 20% interest in NINA Investments Holdings LLC, or Holdings, a wholly-owned subsidiary of NINA, which indirectly holds NINAs ownership interest in the STP Units 3 and 4 Project. TNEA will initially invest $155 million for a 10% share of Holdings, which includes a $30 million option premium payment to Holdings. This option, which expires approximately one year from the date of signing the Investment and Option Agreement, will enable TNEA to buy an additional 10% of Holdings for another payment of $125 million. Pursuant to the terms of the Agreement, the closing is contingent upon NINAs acceptance of a fully executed term sheet for a conditional U.S. DOE loan guarantee. Upon its initial investment, TNEA will hold a 9.238% interest in the STP Units 3 and 4 Project, diluting NINAs investment to 83.137% (75.2% for NRG). If TNEA exercises its option to increase its ownership of Holdings another 10%, it will own 18.475% of the STP Units 3 and 4 Project, diluting NINAs investment to 73.90% (66.8% for NRG).
U.S. DOE Loan Guarantee In early 2010, NRG announced that if the STP Units 3 and 4 Project did not receive a loan guarantee from the U.S. DOE in a timely fashion, it was the intention of the Company both to reduce substantially its commitment to fund on-going project expenditures as well as to reduce development spending on the project overall while the outcome of the loan guarantee was uncertain. When the loan guarantee was not received and Congress went into its summer recess, NRG, after consultation with its partners, dramatically reduced its ongoing equity contributions into NINA for project development, but did so in a manner that allowed the project to stay on its current schedule. Should NRG and its partners unanimously agree to withdraw support from the project, this would result in a reassessment of the probability of success of the project and an impairment and permanent write-down of some or all of the value of the capitalized assets for STP Units 3 and 4. Through September 30, 2010, NRG has made equity contributions of $315 million into NINA. NINA has capitalized $624 million of construction-in-progress, of which $157 million was funded by Toshiba equity contributions and the TANE Facility, and $162 million is an accounts payable balance that NINA intends to primarily fund in the fourth quarter with the TANE Facility upon completion of amendments to that credit facility. The likelihood of NINA receiving a loan guarantee is largely dependent upon additional appropriations for nuclear development by Congress or other means of properly securing the necessary funding for additional nuclear loan guarantee volume.
Set forth below is a description of the Companys material legal proceedings. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Companys liabilities and contingencies could be at amounts that are different from its currently recorded reserves and that such difference could be material.
In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In managements opinion, the disposition of these ordinary course matters will not materially adversely affect NRGs consolidated financial position, results of operations, or cash flows.
California Department of Water Resources
This matter concerns, among other contracts and other defendants, the California Department of Water Resources, or CDWR and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the Federal Energy Regulatory Commission, or FERC abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, the FERC rejected this complaint, denied rehearing, and the case was appealed to the U.S. Court of Appeals for the Ninth Circuit where oral argument was held on December 8, 2004. On December 19, 2006, the Ninth Circuit decided that in the FERCs review of the contracts at issue, the FERC could not rely on the Mobile-Sierra standard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. WCP and others sought review by the U.S. Supreme Court. WCPs appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008, the Supreme Court ruled: (i) that the Mobile-Sierra public interest standard of review applied to contracts made under a sellers market-based rate authority; (ii) that the public interest bar required to set aside a contract remains a very high one to overcome; and (iii) that the Mobile-Sierra presumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress. In this related case, the U.S. Supreme Court affirmed the Ninth Circuits decision agreeing that the case should be remanded to the FERC to clarify the FERCs 2003 reasoning regarding its rejection of the original complaint relating to the financial burdens under the contracts at issue and to alleged market manipulation at the time these contracts were formed. As a result, the U.S. Supreme Court then reversed and remanded the WCP CDWR case to the Ninth Circuit for treatment consistent with its June 26, 2008, decision in the related case. On October 20, 2008, the Ninth Circuit asked the parties in the remanded CDWR case, including WCP and the FERC, whether that Court should answer a question the U.S. Supreme Court did not address in its June 26, 2008, decision; whether the Mobile-Sierra doctrine applies to a third-party that was not a signatory to any of the wholesale power contracts, including the CDWR contract, at issue in that case. Without answering that reserved question, on December 4, 2008, the Ninth Circuit vacated its prior opinion and remanded the WCP CDWR case back to the FERC for proceedings consistent with the U.S. Supreme Courts June 26, 2008, decision. On December 15, 2008, WCP and the other seller-defendants filed with the FERC a Motion for Order Governing Proceedings on Remand. On January 14, 2009, the Public Utilities Commission of the State of California filed an Answer and Cross Motion for an Order Governing Procedures on Remand and on January 28, 2009, WCP and the other seller-defendants filed their reply.
At this time, while NRG cannot predict with certainty whether WCP will be required to make refunds for rates collected under the CDWR contract or estimate the range of any such possible refunds, a reconsideration of the CDWR contract by the FERC with a resulting order mandating significant refunds could have a material adverse impact on NRGs financial position, statement of operations, and statement of cash flows. As part of the 2006 acquisition of Dynegys 50% ownership interest in WCP, WCP and NRG assumed responsibility for any risk of loss arising from this case, unless any such loss was deemed to have resulted from certain acts of gross negligence or willful misconduct on the part of Dynegy, in which case any such loss would be shared equally between WCP and Dynegy.
On January 14, 2010, the U.S. Supreme Court issued its decision in an unrelated proceeding involving the Mobile-Sierra doctrine that will affect the standard of review applied to the CDWR contract on remand before the FERC. In NRG Power Marketing v. Maine Public Utilities Commission, the Supreme Court held that the Mobile-Sierra presumption regarding the reasonableness of contract rates does not depend on the identity of the complainant who seeks a FERC investigation/refund.
Louisiana Generating, LLC
On February 11, 2009, the U.S. Department of Justice, or U.S. DOJ, acting at the request of the U.S. Environmental Protection Agency, or U.S. EPA, commenced a lawsuit against Louisiana Generating, LLC, or LaGen, in federal district court in the Middle District of Louisiana alleging violations of the Clean Air Act, or CAA, at the Big Cajun II power plant. This is the same matter for which Notices of Violation, or NOVs, were issued to LaGen on February 15, 2005, and on December 8, 2006. Specifically, it is alleged that in the late 1990s, several years prior to NRGs acquisition of the Big Cajun II power plant from the Cajun Electric bankruptcy and several years prior to the NRG bankruptcy, modifications were made to Big Cajun II Units 1 and 2 by the prior owners without appropriate or adequate permits and without installing and employing the best available control technology, or BACT, to control emissions of nitrogen oxides and/or sulfur dioxides. The relief sought in the complaint includes a request for an injunction to: (i) preclude the operation of Units 1 and 2 except in accordance with the CAA; (ii) order the installation of BACT on Units 1 and 2 for each pollutant subject to regulation under the CAA; (iii) obtain all necessary permits for Units 1 and 2; (iv) order the surrender of emission allowances or credits; (v) conduct audits to determine if any additional modifications have been made which would require compliance with the CAAs Prevention of Significant Deterioration program; (vi) award to the Department of Justice its costs in prosecuting this litigation; and (vii) assess civil penalties of up to $27,500 per day for each CAA violation found to have occurred between January 31, 1997, and March 15, 2004, up to $32,500 for each CAA violation found to have occurred between March 15, 2004, and January 12, 2009, and up to $37,500 for each CAA violation found to have occurred after January 12, 2009.
On April 27, 2009, LaGen made several filings. LaGen filed an objection in the Cajun Electric Cooperative Power, Inc.s bankruptcy proceeding in the U.S. Bankruptcy Court for the Middle District of Louisiana to seek to prevent the bankruptcy from closing. LaGen also filed a complaint, or adversary proceeding, in the same bankruptcy proceeding, seeking a judgment that: (i) it did not assume liability from Cajun Electric for any claims or other liabilities under environmental laws with respect to Big Cajun II that arose, or are based on activities that were undertaken, prior to the closing date of the acquisition; (ii) it is not otherwise the successor to Cajun Electric with respect to environment liabilities arising prior to the acquisition; and (iii) Cajun Electric and/or the Bankruptcy Trustee are exclusively liable for any of the violations alleged in the February 11, 2009, lawsuit to the extent that such claims are determined to have merit. On April 15, 2010, the bankruptcy court signed an order granting LaGens stipulation of voluntary dismissal without prejudice of the adversary proceeding. The bankruptcy proceeding has since closed.
On June 8, 2009, the parties filed a joint status report in the U.S. DOJ lawsuit setting forth their views of the case and proposing a trial schedule. On April 28, 2010, the district court entered a Joint Case Management Order, in which the district court tentatively scheduled trial on a liability phase for mid-2011 and, if necessary, trial on the damages (remedy) phase for mid-2012. These dates are subject to change.
On August 24, 2009, LaGen filed a motion to dismiss this lawsuit, and on September 25, 2009, the U.S. DOJ filed its opposition to the motion. Thereafter, on February 18, 2010, the Louisiana Department of Environmental Quality, or LDEQ, filed a motion to intervene in the above lawsuit and a complaint against LaGen for alleged violations of Louisianas Prevention of Significant Deterioration, or PSD regulations and Louisianas Title V operating permit program. LDEQ seeks substantially similar relief to that requested by the U.S. DOJ. On February 19, 2010, the district court granted LDEQs motion to intervene. LDEQ is subject to the April 28, 2010 Joint Case Management Order in this matter. Also on April 26, 2010, LaGen filed a motion to dismiss the LDEQ complaint. On July 21, 2010, LaGen argued its motions to dismiss the U.S. DOJ and LDEQ complaints to the district court, while the U.S. DOJ and LDEQ argued in opposition to the motions. On August 20, 2010, the parties submitted proposed findings of fact and conclusions of law, and both parties have submitted additional briefing on emerging jurisprudence from other jurisdictions touching on the issues at stake in the U.S. DOJ lawsuit.
Dunkirk Construction Litigation
In 2005, NRG entered into a Consent Decree with the New York State Department of Environmental Conservation whereby it agreed to reduce certain emissions generated by its Huntley and Dunkirk power plants. Pursuant to the Consent Decree, on November 21, 2007, Clyde Bergemann EEC, or CBEEC, and NRG entered into a firm fixed price contract for the supply of equipment, material and services for six fabric filters for NRGs Dunkirk Electric Power Generating Station. Subsequent to contracting with NRG, CBEEC subcontracted with Hohl Industrial Services, Inc., or Hohl, to perform steel erection and equipment installation at Dunkirk.
On August 28, 2009, Hohl filed its original complaint against NRG, its subsidiary Dunkirk Power LLC, or Dunkirk Power, and CBEEC among others for claims of breach of contract, quantum meruit, unjust enrichment and foreclosure of mechanics liens. As part of CBEECs contractual obligation to NRG, CBEEC agreed to defend NRG, under a reservation of rights. CBEEC filed an answer to the above complaint on behalf of itself, NRG, and Dunkirk Power on October 5, 2009. On December 16, 2009, CBEEC filed a Motion for Summary Judgment on behalf of itself, NRG, and Dunkirk Power. On February 1, 2010, NRG and Dunkirk Power filed a Motion for Leave to file an Amended Answer with Cross-Claims against CBEEC. NRG asserted breach of contract claims seeking liquidated damages for the delays caused by CBEEC. NRG also retained its own counsel to represent its interest in the cross-claims and reserved its rights to seek reimbursement from CBEEC. On February 17, 2010, CBEEC filed an Amended Answer with Affirmative Defenses, Counterclaims and Cross-Claims against NRG, in which it sought $30 million alleging breach of contract, quantum meruit, unjust enrichment, and foreclosure of two mechanics liens, as a result of alleged delays caused by NRG and Dunkirk Power. On March 5, 2010, CBEEC and NRG resolved their disputed cross-claims. In April 2010, the other parties to this litigation settled their disputes. A final dismissal order is expected shortly.
Excess Mitigation Credits
From January 2002 to April 2005, CenterPoint Energy applied excess mitigation credits, or EMCs, to its monthly charges to retail electric providers as ordered by the PUCT. The PUCT imposed these credits to facilitate the transition to competition in Texas, which had the effect of lowering the retail electric providers monthly charges payable to CenterPoint Energy. As indicated in its Petition for Review filed with the Supreme Court of Texas on June 2, 2008, CenterPoint Energy has claimed that the portion of those EMCs credited to Reliant Energy Retail Services, LLC, or RERS, a retail electric provider and NRG subsidiary acquired from RRI, totaled $385 million for RERSs Price to Beat Customers. It is unclear what the actual number may be. Price to Beat was the rate RERS was required by state law to charge residential and small commercial customers that were transitioned to RERS from the incumbent integrated utility company commencing in 2002. In its original stranded cost case brought before the PUCT on March 31, 2004, CenterPoint Energy sought recovery of all EMCs that were credited to all retail electric providers, including RERS, and the PUCT ordered that relief in its Order on Rehearing in Docket No. 29526, on December 17, 2004. After an appeal to state district court, the court entered a final judgment on August 26, 2005, affirming the PUCTs order with regard to EMCs credited to RERS. Various parties filed appeals of that judgment with the Court of Appeals for the Third District of Texas with the first such appeal filed on the same date as the state district court judgment and the last such appeal filed on October 10, 2005. On April 17, 2008, the Court of Appeals for the Third District reversed the lower courts decision ruling that CenterPoint Energys stranded cost recovery should exclude only EMCs credited to RERS for its Price to Beat customers. On June 2, 2008, CenterPoint Energy filed a Petition for Review with the Supreme Court of Texas and on June 19, 2009, the Court agreed to consider the CenterPoint Energy appeal as well as two related petitions for review filed by other entities. Oral argument occurred on October 6, 2009.
In November 2008, CenterPoint Energy and Reliant Energy Inc., or REI, on behalf of itself and affiliates including RERS, agreed to suspend unexpired deadlines, if any, related to limitations periods that might exist for possible claims against REI and its affiliates if CenterPoint Energy is ultimately not allowed to include in its stranded cost calculation those EMCs previously credited to RERS. Regardless of the outcome of the Texas Supreme Court proceeding, NRG believes that any possible future CenterPoint Energy claim against RERS for EMCs credited to RERS would lack legal merit. No such claim has been filed.
Note 16 Regulatory Matters
NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRGs wholesale and retail businesses.
In addition to the regulatory proceedings noted below, NRG and its subsidiaries are a party to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In managements opinion, the disposition of these ordinary course matters will not materially adversely affect NRGs consolidated financial position, results of operations, or cash flows.
PJM On June 18, 2009, FERC denied rehearing of its order dated September 19, 2008, dismissing a complaint filed by the Maryland Public Service Commission, or MDPSC, together with other load interests, against PJM challenging the results of the Reliability Pricing Model, or RPM transition Base Residual Auctions for installed capacity, held between April 2007 and January 2008. The complaint had sought to replace the auction-determined results for installed capacity for the 2008/2009, 2009/2010, and 2010/2011 delivery years with administratively-determined prices. On August 14, 2009, the MDPSC and the New Jersey Board of Public Utilities filed an appeal of FERCs orders to the U.S. Court of Appeals for the Fourth Circuit, and a successful appeal could disrupt the auction-determined results and create a refund obligation for market participants. The case has been transferred to the U.S. Court of Appeals for the D.C. Circuit. Oral argument is scheduled for November 15, 2010.
Midwest ISO v. PJM On March 8, 2010, Midwest ISO filed a complaint against PJM seeking payments from PJM related to inter-market operations and settlements for congestion costs between the systems for the period from April 2005 to the present. If the Midwest ISOs allegations are true, PJM may have significant liability. If PJM makes any payments to the Midwest ISO related to these claims, PJM is expected to seek to recover the payments from entities that served load and held transmission congestion rights on PJM during the period in dispute, including NRG, which provided basic generation service and thus effectively served load. At this time, NRGs share of any payment by PJM is not expected to be material.
Retail (Replacement Reserve) On November 14, 2006, Constellation Energy Commodities Group, or Constellation, filed a complaint with the PUCT alleging that ERCOT misapplied the Replacement Reserve Settlement, or RPRS, Formula contained in the ERCOT protocols from April 10, 2006, through September 27, 2006. Specifically, Constellation disputed approximately $4 million in under-scheduling charges for capacity insufficiency asserting that ERCOT applied the wrong protocol. REPS, other market participants, ERCOT, and PUCT staff opposed Constellations complaint. On January 25, 2008, the PUCT entered an order finding that ERCOT correctly settled the capacity insufficiency charges for the disputed dates in accordance with ERCOT protocols and denied Constellations complaint. On April 9, 2008, Constellation appealed the PUCT order to the Civil District Court of Travis County, Texas and on June 19, 2009, the court issued a judgment reversing the PUCT order, finding that the ERCOT protocols were in irreconcilable conflict with each other. On July 20, 2009, REPS filed an appeal to the Third Court of Appeals in Travis County, Texas, thereby staying the effect of the trial courts decision. If all appeals are unsuccessful, on remand to the PUCT, it would determine the appropriate methodology for giving effect to the trial courts decision. It is not known at this time whether only Constellations under-scheduling charges, the under-scheduling charges of all other QSEs that disputed REPS charges for the same time frame, the entire market, or some other approach would be used for any resettlement. On October 6, 2010, the parties argued the appeal before the Court of Appeals for the Third District in Austin, Texas.
Under the PUCT ordered formula, Qualified Scheduling Entities, or QSEs, who under-scheduled capacity within any of ERCOTs four congestion zones were assessed under-scheduling charges which defrayed the costs incurred by ERCOT for RPRS that would otherwise be spread among all load-serving QSEs. Under the Courts decision, all RPRS costs would be assigned to all load-serving QSEs based upon their load ratio share without assessing any separate charge to those QSEs who under-scheduled capacity. If under-scheduling charges for capacity insufficient QSEs were not used to defray RPRS costs, REPSs share of the total RPRS costs allocated to QSEs would increase.
California On May 4, 2010, in Southern California Edison Company v. FERC, the U.S. Court of Appeals for the D.C. Circuit vacated FERCs acceptance of station power rules for the CAISO market, and remanded the case for further proceedings at FERC. On August 30, 2010, FERC issued an Order on Remand effectively disclaiming jurisdiction over how the states impose retail station power charges. Due to reservation-of-rights language in the California utilities state-jurisdictional station power tariffs, FERCs ruling effectively requires California generators to pay state-imposed retail charges back to the date of enrollment by the facilities in the CAISOs station period program (February 1, 2009 for the Companys Encina and El Segundo facilities; March 1, 2009 for the Companys Long Beach facility). Although requests for rehearing have been submitted, the Company has established an appropriate reserve.
Note 17 Environmental Matters
The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the U.S. If such laws and regulations become more stringent, or new laws, interpretations or compliance policies apply and NRGs facilities are not exempt from coverage, the Company could be required to make modifications to further reduce potential environmental impacts. In general, the effect of such future laws or regulations is expected to require the addition of pollution control equipment or the imposition of restrictions or additional costs on the Companys operations.
Environmental Capital Expenditures
Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures from 2010 through 2014 to meet NRGs environmental commitments will be approximately $0.9 billion and are primarily associated with controls on the Companys Big Cajun and Indian River facilities. These capital expenditures, in general, are related to installation of particulate, sulfur dioxide, or SO2, nitrogen oxide, or NOx, and mercury controls to comply with federal and state air quality rules and consent orders, as well as installation of Best Technology Available under a section of the Clean Water Act regulating cooling water intake structures, or Phase II 316(b) Rule. NRG continues to explore cost effective compliance alternatives. This estimate reflects anticipated schedules and controls related to the Clean Air Interstate Rule, or CAIR, the proposed Clean Air Transport Rule, or CATR, Maximum Achievable Control Technology, or MACT for mercury, and the Phase II 316(b) Rule which are under remand to the U.S. EPA, and, as such, the full impact on the scope and timing of environmental retrofits from any new or revised regulations cannot be determined at this time.
NRGs current contracts with the Companys rural electrical customers in the South Central region allow for recovery of a portion of the regions capital costs once in operation, along with a capital return incurred by complying with any change in law, including interest over the asset life of the required expenditures. The actual recoveries will depend, among other things, on the timing of the completion of the capital project and the remaining duration of the contracts.
In January 2006, NRGs Indian River Operations, Inc. received a letter of informal notification from Delaware Department of Natural Resources and Environmental Control, or DNREC, stating that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program. On February 4, 2008, DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself will require a further Remedial Investigation and Feasibility Study to determine the type and scope of any additional work required. Until the Remedial Investigation and Feasibility Study is completed, the Company is unable to predict the impact of any required remediation. On May 29, 2008, DNREC requested that NRGs Indian River Operations, Inc. participate in the development and performance of a Natural Resource Damage Assessment, or NRDA, at the Burton Island Old Ash Landfill. NRG is currently working with DNREC and other trustees to close out the assessment phase.
Pursuant to a consent order dated September 25, 2007, between NRG and DNREC, NRG agreed to operate the four units at the Indian River plant in a manner that would limit the emissions of NOx and SO2, and to mothball Units 1 and 2 on May 1, 2011, and May 1, 2010, respectively. In addition, Units 3 and 4, with a combined generating capacity of approximately 565 MW, could not operate beyond December 31, 2011, unless appropriate control technology was installed on each unit. Unit 2 was mothballed as planned on May 1, 2010. On July 21, 2010, the court approved an amended consent order, pursuant to which NRG will retire Unit 3 (155 MW) by December 31, 2013, thereby extending the operable period of the unit by two years without installing additional control technology. Units 1, 2 and 4 are not affected by the amended consent order.
South Central Region
On February 11, 2009, the U.S. DOJ acting at the request of the U.S. EPA commenced a lawsuit against LaGen in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. This is the same matter for which NOVs were issued to LaGen on February 15, 2005, and on December 8, 2006. Further discussion on this matter can be found in Note 15, Commitments and Contingencies, to this Form 10-Q, Louisiana Generating, LLC.
Note 18 Condensed Consolidating Financial Information
As of September 30, 2010, the Company had outstanding $1.2 billion of 7.25% Senior Notes due 2014, $2.4 billion of 7.375% Senior Notes due 2016, $1.1 billion of 7.375% Senior Notes due 2017, $700 million of 8.50% Senior Notes due 2019, and $1.1 billion of 8.25% Senior Notes due 2020. These notes are guaranteed by certain of NRGs current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries.
Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of September 30, 2010:
The non-guarantor subsidiaries include all of NRGs foreign subsidiaries and certain domestic subsidiaries. NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Companys ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRGs ability to receive funds from its subsidiaries. Except for NRG Bayou Cove, LLC, which is subject to certain restrictions under the Companys Peaker financing agreements, there are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. In addition, there may be restrictions for certain non-guarantor subsidiaries.
The following condensed consolidating financial information presents the financial information of NRG, the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under the Securities and Exchange Commissions Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.
In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended September 30, 2010
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Nine Months Ended September 30, 2010
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
September 30, 2010
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2010
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended September 30, 2009
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Nine Months Ended September 30, 2009
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2009
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2009
ITEM 2 MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
As you read this discussion and analysis, refer to the Companys Condensed Consolidated Statements of Operations to this Form 10-Q, which present the results of operations for the three and nine months ended September 30, 2010, and 2009. Also refer to NRGs Annual Report on Form 10-K for the year ended December 31, 2009, or 2009 Form 10-K, which includes detailed discussions of various items impacting the Companys business, results of operations and financial condition, including: Introduction and Overview section which provides a description of NRGs business segments; Strategy section; Business Environment section, including how regulation, weather, and other factors affect NRGs business; and Critical Accounting Policies and Estimates section.
The discussion and analysis below has been organized as follows:
Introduction and Overview
NRG Energy, Inc., or NRG or the Company, is primarily a wholesale power generation company with a significant presence in major competitive power markets in the U.S., as well as a major retail electricity provider in the ERCOT (Texas) market through Reliant Energy. NRG is engaged in the ownership, development, construction and operation of power generation facilities, both conventional and renewable, the transacting in and trading of fuel and transportation services, the trading of energy, capacity and related products in the U.S. and select international markets, and the supply of electricity and energy services to retail electricity customers in the Texas market.
As of September 30, 2010, NRG had a total global generation portfolio of 188 active operating fossil fuel and nuclear generation units, at 44 power generation plants, with an aggregate generation capacity of approximately 24,010 MW, and approximately 245 MW under construction which includes partner interests of 120 MW. In addition to its fossil fuel plant ownership, NRG has ownership interests in operating renewable facilities with an aggregate generation capacity of 465 MW, consisting of four wind farms representing an aggregate generation capacity of 445 MW and a 20 MW solar facility. Within the U.S., NRG has large and diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 23,005 MW of fossil fuel and nuclear generation capacity in 180 active generating units at 42 plants. The Companys power generation facilities are most heavily concentrated in Texas (approximately 11,440 MW, including 445 MW from four wind farms), the Northeast (approximately 6,910 MW), South Central (approximately 2,855 MW), and West (approximately 2,150 MW, including 20 MW from a solar facility) regions of the U.S., with approximately 115 MW of additional generation capacity from the Companys thermal assets. In addition, through certain foreign subsidiaries, NRG has investments in power generation projects located in Australia and Germany with approximately 1,005 MW of generation capacity.
NRGs principal domestic power plants consist of a mix of natural gas-, coal-, oil-fired, nuclear and renewable facilities, representing approximately 45%, 31%, 17%, 5% and 2% of the Companys total domestic generation capacity, respectively. In addition, 9% of NRGs domestic generating facilities have dual or multiple fuel capacity, which allows those plants to dispatch with the lowest cost fuel option.
NRGs domestic generation facilities consist of intermittent, baseload, intermediate and peaking power generation facilities, the ranking of which is referred to as the Merit Order, and include thermal energy production plants. The sale of capacity and power from baseload generation facilities accounts for the majority of the Companys revenues and provides a stable source of cash flow. In addition, NRGs generation portfolio provides the Company with opportunities to capture additional revenues by selling power during periods of peak demand, offering capacity or similar products to retail electric providers and others, and providing ancillary services to support system reliability.
Reliant Energy, the Companys retail electricity provider, arranges for the transmission and delivery of electricity to customers, bills customers, collects payments for electricity sold and maintains call centers to provide customer service. Based on metered locations, as of September 30, 2010, Reliant Energy had approximately 1.5 million customers.
Furthermore, NRG is focused on the development and investment in energy-related new businesses and new technologies where the benefits of such investments represent significant commercial opportunities and create a comparative advantage for the Company. These investments include low or no GHG emitting energy generating sources, such as nuclear, wind, solar thermal, photovoltaic, biomass, clean coal and gasification; the retrofit of post-combustion carbon capture technologies; and developments in the electric vehicle ecosystem.
NRGs Business Strategy
NRGs business strategy is intended to maximize shareholder value through the production and sale of safe, reliable and affordable power to its customers in the markets served by the Company, while aggressively positioning the Company to meet the markets increasing demand for sustainable and low carbon energy solutions. This dual strategy is designed to perfect the Companys core business of competitive power generation and establish the Company as a leading provider of sustainable energy solutions that promote national energy security, while utilizing the Companys retail business to complement and advance both initiatives.
The Companys core business is focused on: (i) top decile operating performance of its existing operating assets, (ii) optimal hedging of baseload and retail operations, while retaining optionality on the Companys gas fleet, (iii) repowering of power generation assets at existing sites and reducing environmental impacts, (iv) pursuit of selective acquisitions, joint ventures, divestitures and investments, and (v) engaging in a proactive capital allocation plan focused on achieving the regular return of capital to stockholders within the dictates of prudent balance sheet management.
In addition, the Company believes in promoting national energy security and that success in providing energy solutions that address sustainability and climate change concerns will not only reduce the carbon and capital intensity of the Company in the future, it also will reduce the real and perceived linkage between the Companys financial performance and prospects, and volatile commodity prices, particularly with respect to natural gas. The Companys initiatives in this area of future growth are focused on: (i) low carbon baseload primarily nuclear generation, (ii) renewables, with a concentration in solar and wind generation and development, (iii) fast start, high efficiency gas-fired capacity in the Companys core regions, (iv) electric vehicle ecosystems, and (v) smart grid services. The Companys advancements in each of these areas are driven by select acquisitions, joint ventures, and investments that are more fully described in the Companys 2009 Form 10-K, the Quarterly Reports on Form 10-Q for the quarters ended June 30, 2010, and March 31, 2010, and this Form 10-Q.
Environmental Regulatory Landscape
A number of regulations that could significantly impact the power generation industry are in development or under review by the U.S. EPA: CAIR/CATR, MACT, NAAQS revisions, coal combustion byproducts, and once-through cooling. While most of these regulations have been considered for some time, they are expected to gain clarity in 2010 through 2011. The timing and stringency of these regulations will provide a framework for the retrofit of existing fossil plants and deployment of new, cleaner technologies in the next decade. The Company has included capital to meet anticipated CAIR Phase I and II, proposed CATR, MACT standards for mercury, and the installation of Best Technology Available under the 316(b) Rule in the current estimated environmental capital expenditure. While the Company cannot predict the impact of future regulations and would likely face additional investments over time, these expenditures, combined with the Companys already existing air quality controls, use of Powder River Basin coal, closed cycle cooling, and dry ash handling systems position NRG well to meet more stringent requirements.
The U.S. EPA released the proposed CATR on July 6, 2010. This rule is designed to replace CAIR and address the findings of the U.S. Court of Appeals for the D.C. Circuit that initially vacated the rule. The rule is designed to bring 31 states and Washington, D.C. into attainment with PM 2.5 and ozone national ambient air quality standards through emission reductions in SO2 and NOx. Proposed implementation would be through a cap and trade program starting in 2012 with constrained trading between states in the CATR regions. In 2014, the SO2 cap would be further reduced in certain states. Under CATR, use of discounted Acid Rain SO2 allowances would be discontinued and replaced with a completely distinct CATR SO2 allowance program. Acid Rain allowances would still be required on a 1:1 basis under the Acid Rain Program. NRG continues to evaluate the proposed rule and any impact it has to emission markets and currently estimates that the proposed rule, if it becomes effective, could result in up to a $50 million future impairment of the Companys SO2 emission allowance, which is recorded as an intangible asset on the Companys balance sheet. NRGs planned environmental capital expenditures are consistent with reductions anticipated in the rule.
The New York State Department of Environmental Conservation finalized the NOx Reasonably Available Control Technology, or RACT, Rule on July 14, 2010. This rule identifies new NOx emission limits for major sources which must be met by July 1, 2014. Plants can comply or request an alternate RACT limit. All of NRGs facilities are able to meet the new standards with the exception of the Oswego plant, which will apply for an alternate limit.
On May 4, 2010, the U.S. EPA proposed two options for the regulation of coal combustion residue, commonly known as coal ash. Under the Proposals first regulatory option, the U.S. EPA would reverse its August 1993 and May 2000 Bevill Regulatory Determinations and list coal ash as a special waste subject to regulation under hazardous waste regulations. The second regulatory option would leave the Bevill Determination in place and regulate disposal of coal ash as non-hazardous. Under both options, an exemption for the beneficial use of coal ash would remain in place. Additionally, under both options, the U.S. EPA would establish dam safety requirements to address the structural integrity of surface impoundments. While it is not possible to predict the impact of this rule until it is final, as proposed it is not expected to have a material impact on NRGs operations, as all flyash disposal sites are dry landfills. However, should the U.S. EPA implement the hazardous waste option, NRG may incur significant costs due to loss of markets for beneficial reuse. Given the recent release of this proposed rule, NRG will continue to monitor developments and their respective impact on the Companys operations.
The California statewide 316(b) policy to mitigate once-through cooling was effective as of October 1, 2010. Options for power plants with once-through cooling include transitioning to a closed loop system, retirement or submitting an alternative plan that meets equivalent mitigation criteria. Specified compliance dates for NRGs El Segundo and Encina power plants are December 31, 2015, and December 31, 2017, respectively. NRG is analyzing compliance through a mix of alternative mitigation plans and repowering.
In June 2010, the U.S. EPA issued a Section 308 Information Collection Request to steam electric power generating plants across the industry, including 13 NRG facilities. The questionnaire focuses on water and wastewater discharges from power plants. The U.S. EPA indicated results will be used to develop new effluent guidelines for the industry.
Finalization of the Endangerment Finding, a rule addressing tailpipe limitations for light duty vehicles, and a final interpretation of the Johnson Memorandum set the stage for regulation of GHGs from stationary sources. On June 3, 2010, the U.S. EPA published the final rule tailoring the applicability criteria that determine which new and modified sources will become subject to permitting requirements for GHGs under the Prevention of Significant Deterioration, or PSD and Title V programs of the CAA. The rule raised applicability triggers to 75,000 or 100,000 tons per year CO2 equivalents, or CO2e, and implemented the requirements in two phases on January 2, 2011, or July 2, 2011. The immediate impact to NRGs new and modified facilities is not expected to be material; the Company will continue to evaluate the potential long-term impact as regulatory programs are implemented over time.
Climate Change Legislation
In 2009, in the course of producing approximately 71 million MWh of electricity, NRGs power plants emitted 59 million tonnes of CO2, of which 53 million tonnes were emitted in the U.S., 3 million tonnes in Germany and 3 million tonnes in Australia. During the same period, NRG emitted approximately 8 million tons of CO2 in the RGGI region. The impact from legislation or federal, regional or state regulation of GHGs on the Companys financial performance will depend on a number of factors, including the overall level of GHG reductions required under any such regulations, the price and availability of offsets, and the extent to which NRG would be entitled to receive CO2 emissions allowances without having to purchase them in an auction or on the open market. Thereafter, under any such legislation or regulation, the impact on NRG would depend on the Companys level of success in developing and deploying low and no carbon technologies such as those being pursued as discussed in the above.
Congress has been unable to come to an agreement on climate legislation during this session. Lack of legislation will prolong the uncertainty of the nature and timing of GHG requirements and their resulting impact on NRG.
As operators of power plants and participants in wholesale energy markets, certain NRG entities are subject to regulation by various federal and state government agencies. These include the U.S. Commodity Futures Trading Commission, or CFTC, FERC, U.S. Nuclear Regulatory Commission, or NRC, PUCT and other public utility commissions in certain states where NRGs generating or thermal assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO markets in which it participates. Certain of the Reliant Energy entities are competitive Retail Electric Providers, or REPs, and as such are subject to the rules and regulations of the PUCT governing REPs. NRG must also comply with the mandatory reliability requirements imposed by the North American Electric Reliability Corporation, or NERC, and the regional reliability councils in the regions where the Company operates. The operations of, and wholesale electric sales from, NRGs Texas region are not subject to rate regulation by the FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce.
Financial Reform On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which, among other things, aims to improve transparency and accountability in derivative markets. While the Dodd-Frank Act increases the CFTCs regulatory authority over over-the-counter derivatives, there is uncertainty on several issues related to market clearing, definitions of market participants, reporting, and capital requirements. While there are many details that remain to be addressed in CFTC rulemaking proceedings, at this time the Company does not anticipate any material impact on its current operations or collateral requirements. NRGs view is informed by a letter dated June 30, 2010, from Senate Banking Committee Chairman Dodd and Senate Agriculture Committee Chairman Lincoln clarifying that the legislative intent of the Dodd-Frank Act is not to impose margin requirements on end users that use swaps to hedge or mitigate commercial risks. Depending on the outcome of the pending and expected rulemakings, however, there could be impacts on the Companys future hedging strategy and collateral requirements.
New England On February 22, 2010, ISO-NE filed proposed amendments to its Forward Capacity Market, or FCM, design with FERC. A number of generators protested the ISO-NE filing, arguing that FERC should not accept the proposed amendments. On March 23, 2010, an association of generators filed a complaint alleging that the proposed FCM amendments are not just and reasonable due to market distortions such as out-of-market contracts, and thus would continue to under-compensate capacity suppliers in New England. On April 2, 2010, NRG and PSEG jointly filed a second complaint alleging that the existing FCM market fails to adequately establish zonal prices and thus does not adequately compensate suppliers for the locational value of their capacity. These complaints are seeking only prospective relief. Any changes to the FCM market in response to these complaints could benefit from the Companys existing New England assets in future FCM auctions. On April 23, 2010, FERC issued an order consolidating the proceedings. In its order, FERC accepted some of the ISO-NEs proposed changes, but also set several of the central issues for hearing and settlement processes.
New York On October 12, 2010, FERC approved new mitigation measures filed by the NYISO that apply when a unit in the rest-of-state region is dispatched out-of-merit for reliability. The Companys resources in the rest-of-state region are dispatched out-of-merit for reliability from time to time.
California On May 4, 2010, in Southern California Edison Company v. FERC, the U.S. Court of Appeals for the D.C. Circuit vacated FERCs acceptance of station power rules for the CAISO market, and remanded the case for further proceedings at FERC. On August 30, 2010, FERC issued an Order on Remand effectively disclaiming jurisdiction over how the states impose retail station power charges. As a result of FERCs decision, NRGs power plants may be prevented from netting their station power consumption against their sales on a monthly basis not only in California but also in other markets, which could require NRG to purchase station power at retail rates.
Changes in Accounting Standards
See Note 2, Summary of Significant Accounting Policies, to this Form 10-Q for a discussion of recent accounting developments.
Consolidated Results of Operations
The following table provides selected financial information for the Company:
Managements discussion of the results of operations for the three months ended September 30, 2010, and 2009:
Wholesale Power Generation
The following is a more detailed discussion of the energy and capacity revenues and generation cost of sales for NRGs wholesale power generation regions, adjusted to eliminate intersegment activity primarily with Reliant Energy.
The following is a detailed discussion of retail revenues and cost of sales for NRGs Reliant Energy business segment.
Mark-to-market activities include economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activities. Total net mark-to-market results decreased by $20 million during the three months ended September 30, 2010, compared to the same period in 2009.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region are as follows: