10-Q 1 a12-7167_110q.htm 10-Q

Table of Contents

 

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

 


 

FORM 10-Q

 

x      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended March 31, 2012

 

OR

 

o         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from                  to                   

 


 

Commission File Number: 1-16455

 

GenOn Energy, Inc.

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware

 

76-0655566

(State or Other Jurisdiction of Incorporation
or Organization)

 

(I.R.S. Employer Identification No.)

 

 

 

1000 Main Street,

 

 

Houston, Texas

 

77002

(Address of Principal Executive Offices)

 

(Zip Code)

 

(832) 357-3000

(Registrant’s 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.  x Yes  o No

 

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).  x Yes  o No

 

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

 

Large Accelerated Filer  x

 

Accelerated Filer  o

 

 

 

Non-accelerated Filer  o

 

Smaller reporting company  o

(Do not check if a smaller reporting company)

 

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  o Yes  x No

 

As of May 3, 2012, there were 772,866,179 shares of the registrant’s Common Stock, $0.001 par value per share, outstanding.

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

 

Glossary of Certain Defined Terms

ii

 

Cautionary Statement Regarding Forward-Looking Information

v

 

 

 

PART I

FINANCIAL INFORMATION

 

ITEM 1.

FINANCIAL STATEMENTS

1

 

Condensed Consolidated Statements of Operations (Unaudited) Three Months Ended March 31, 2012 and 2011

1

 

Condensed Consolidated Statements of Comprehensive Income (Loss) (Unaudited) Three Months Ended March 31, 2012 and 2011

2

 

Condensed Consolidated Balance Sheets (Unaudited) March 31, 2012 and December 31, 2011

3

 

Condensed Consolidated Statements of Cash Flows (Unaudited) Three Months Ended March 31, 2012 and 2011

4

 

Notes to Condensed Consolidated Financial Statements (Unaudited)

5

 

 

 

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

32

 

Overview

32

 

Expected Retirements, Mothballing or Long-Term Protective Layup of Generating Facilities

32

 

Hedging Activities

32

 

Dodd-Frank Act

33

 

Capital Expenditures and Capital Resources

33

 

Environmental Matters

34

 

Regulatory Matters

34

 

Commodity Prices and Generation Volumes

35

 

Results of Operations

35

 

Financial Condition

46

 

Liquidity and Capital Resources

46

 

Historical Cash Flows

49

 

Critical Accounting Estimates

50

 

Recently Adopted Accounting Guidance

50

 

 

 

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

51

 

Fair Value Measurements

51

 

Counterparty Credit Risk

52

 

Interest Rate Risk

53

 

Coal Agreement Risk

53

 

 

 

ITEM 4.

CONTROLS AND PROCEDURES

54

 

Effectiveness of Disclosure Controls and Procedures

54

 

Changes in Internal Control over Financial Reporting

54

 

 

 

PART II

OTHER INFORMATION

 

ITEM 1.

LEGAL PROCEEDINGS

55

ITEM 1A.

RISK FACTORS

55

ITEM 5.

OTHER INFORMATION

55

ITEM 6.

EXHIBITS

56

 

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Table of Contents

 

Glossary of Certain Defined Terms

 

ancillary services

 

services that ensure reliability and support the transmission of electricity from generation sites to customer loads. Such services include regulation service, reserves and voltage support.

 

 

 

Bankruptcy Court

 

United States Bankruptcy Court for the Northern District of Texas, Fort Worth Division.

 

 

 

baseload generating units

 

units designed to satisfy minimum baseload requirements of the system and produce electricity at an essentially constant rate and run continuously.

 

 

 

CAISO

 

California Independent System Operator.

 

 

 

capacity

 

amount of energy that could have been generated at continuous full-power operation during the period.

 

 

 

CenterPoint

 

CenterPoint Energy, Inc. and its subsidiaries, on and after August 31, 2002, and Reliant Energy, Incorporated and its subsidiaries, prior to August 31, 2002.

 

 

 

Clean Air Act

 

Federal Clean Air Act.

 

 

 

Clean Water Act

 

Federal Water Pollution Control Act.

 

 

 

CO2

 

carbon dioxide.

 

 

 

dark spread

 

the difference between power prices and the cost to generate electricity with coal.

 

 

 

deactivation

 

includes retirement, mothball and long-term protective layup. In each instance, the deactivated unit cannot be currently called upon to generate electricity.

 

 

 

Dodd-Frank Act

 

the Dodd-Frank Wall Street Reform and Consumer Protection Act.

 

 

 

EBITDA

 

earnings before interest, taxes, depreciation and amortization.

 

 

 

EPA

 

United States Environmental Protection Agency.

 

 

 

EPC

 

engineering, procurement and construction.

 

 

 

EPS

 

earnings per share.

 

 

 

Exchange Act

 

Securities Exchange Act of 1934, as amended.

 

 

 

FASB

 

Financial Accounting Standards Board.

 

 

 

FERC

 

Federal Energy Regulatory Commission.

 

 

 

GAAP

 

United States generally accepted accounting principles.

 

 

 

GenOn

 

GenOn Energy, Inc. (formerly known as RRI Energy, Inc.) and, except where the context indicates otherwise, its subsidiaries, after giving effect to the Merger.

 

 

 

GenOn Americas

 

GenOn Americas, Inc.

 

 

 

GenOn Americas Generation

 

GenOn Americas Generation, LLC.

 

 

 

GenOn credit facilities

 

senior secured term loan and revolving credit facility of GenOn and certain of its subsidiaries.

 

 

 

GenOn Energy Holdings

 

GenOn Energy Holdings, Inc. (formerly known as Mirant Corporation) and, except where the context indicates otherwise, its subsidiaries.

 

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GenOn Marsh Landing

 

GenOn Marsh Landing, LLC.

 

 

 

GenOn Mid-Atlantic

 

GenOn Mid-Atlantic, LLC and its subsidiaries, which include the baseload units at two generating facilities under operating leases.

 

 

 

GenOn North America

 

GenOn North America, LLC.

 

 

 

intermediate generating units

 

units designed to satisfy system requirements that are greater than baseload and less than peaking.

 

 

 

IRC

 

Internal Revenue Code of 1986, as amended.

 

 

 

IRC §

 

IRC section.

 

 

 

ISO

 

independent system operator.

 

 

 

ISO-NE

 

Independent System Operator-New England.

 

 

 

LIBOR

 

London InterBank Offered Rate.

 

 

 

long-term protective layup

 

a descriptive term for our plans with respect to the Shawville coal-fired units, including retiring the units from service in accordance with the PJM tariff, maintenance of the units in accordance with the lease requirements and continued payment of the lease rent. While the units are not decommissioned and reactivation remains a technical possibility, we do not expect to make any further investment in environmental controls for the units. Further, reactivation after the long-term protective layup would likely involve numerous new permits and substantial additional investment.

 

 

 

MADEP

 

Massachusetts’ Department of Environmental Protection.

 

 

 

MC Asset Recovery

 

MC Asset Recovery, LLC.

 

 

 

MDE

 

Maryland Department of the Environment.

 

 

 

Merger

 

the merger completed on December 3, 2010 pursuant to the Merger Agreement.

 

 

 

Merger Agreement

 

the agreement by and among Mirant Corporation, RRI Energy, Inc. and RRI Energy Holdings, Inc. dated as of April 11, 2010.

 

 

 

Mirant

 

GenOn Energy Holdings, Inc. (formerly known as Mirant Corporation) and, except where the context indicates otherwise, its subsidiaries.

 

 

 

Mirant Debtors

 

GenOn Energy Holdings, Inc. (formerly known as Mirant Corporation) and certain of its subsidiaries.

 

 

 

MISO

 

Midwest Independent Transmission System Operator.

 

 

 

mothballed

 

the unit has been removed from service and is unavailable for service, but has been laid up in a manner such that it can be brought back into service with an appropriate amount of notification, typically weeks or months.

 

 

 

MPSC

 

Maryland Public Service Commission.

 

 

 

MW

 

megawatt.

 

 

 

MWh

 

megawatt hour.

 

 

 

NAAQS

 

National Ambient Air Quality Standards.

 

 

 

net generating capacity

 

net summer capacity.

 

 

 

NJDEP

 

New Jersey Department of Environmental Protection.

 

 

 

NOL

 

net operating loss.

 

 

 

NOV

 

notice of violation.

 

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NOx

 

nitrogen oxides.

 

 

 

NPDES

 

national pollutant discharge elimination system.

 

 

 

NYISO

 

New York Independent System Operator.

 

 

 

NYMEX

 

New York Mercantile Exchange.

 

 

 

OCI

 

other comprehensive income.

 

 

 

OTC

 

over-the-counter.

 

 

 

PADEP

 

Pennsylvania Department of Environmental Protection.

 

 

 

peaking generating units

 

units designed to satisfy demand requirements during the periods of greatest or peak load on the system.

 

 

 

PEPCO

 

Potomac Electric Power Company.

 

 

 

PG&E

 

Pacific Gas & Electric Company.

 

 

 

PJM

 

PJM Interconnection, LLC.

 

 

 

Plan

 

the plan of reorganization that was approved in conjunction with Mirant Corporation’s emergence from bankruptcy protection on January 3, 2006.

 

 

 

PPA

 

power purchase agreement.

 

 

 

Protective Charter Amendment

 

the Certificate of Amendment to our Third Restated Certificate of Incorporation dated May 4, 2011.

 

 

 

REMA

 

GenOn REMA, LLC and its subsidiaries, which include three generating facilities under operating leases.

 

 

 

retirement

 

the unit has been removed from service and is unavailable for service and not expected to return to service in the future.

 

 

 

RMR

 

reliability-must-run.

 

 

 

ROC

 

Risk Oversight Committee.

 

 

 

RRI Energy

 

RRI Energy, Inc., which changed its name to GenOn Energy, Inc. in connection with the Merger.

 

 

 

RTO

 

regional transmission organization.

 

 

 

scrubbers

 

flue gas desulfurization emissions controls.

 

 

 

Securities Act

 

Securities Act of 1933, as amended.

 

 

 

SO2

 

sulfur dioxide.

 

 

 

Southern Company

 

The Southern Company.

 

 

 

spark spread

 

the difference between power prices and the cost to generate electricity with natural gas.

 

 

 

Stone & Webster

 

Stone & Webster, Inc.

 

 

 

SWD

 

surface water discharge.

 

 

 

total margin capture factor

 

the actual gross margin for a unit from energy, and contracted and capacity divided by the total gross margin from energy, and contracted and capacity that could have been earned by the unit.

 

 

 

VaR

 

value at risk.

 

 

 

VIE

 

variable interest entity.

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

 

In addition to historical information, the information presented in this report includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act.  These statements involve known and unknown risks and uncertainties and relate to our revenues, income, capital structure and other financial items, future events, our future financial performance or our projected business results and our view of economic and market conditions.  In some cases, one can identify forward-looking statements by words such as “may,” “will,” “should,” “could,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “expect,” “intend,” “seek,” “plan,” “think,” “anticipate,” “estimate,” “predict,” “target,” “potential” or “continue” or the negative of these terms or comparable words.

 

Forward-looking statements are only predictions.  Actual events or results may differ materially from any forward-looking statement as a result of various factors, which include:

 

·                  more stringent (or changes in the application of) environmental laws and regulations (including the cumulative effect of many such regulations) that restrict our ability or render it uneconomic to operate our assets, including regulations related to air emissions, disposal of ash and other byproducts, wastewater discharge and cooling water systems;

 

·                  changes in market conditions, including developments in the supply, demand, volume and pricing of electricity and other commodities such as coal and natural gas in the energy markets, including efforts to reduce demand for electricity and to encourage the development of renewable sources of electricity, and the extent and timing of the entry of additional competition in our markets;

 

·                  legislative and regulatory initiatives regarding deregulation, regulation or restructuring of the industry of generating, transmitting and distributing electricity (the electricity industry); changes in state, federal and other regulations affecting the electricity industry (including rate and other regulations); changes in tax laws and regulations to which we and our subsidiaries are subject; and changes in, or changes in the application of, other laws and regulations to which we and our subsidiaries and affiliates are or could become subject;

 

·                  conflicts between reliability needs and environmental rules, particularly with increasingly stringent environmental restrictions;

 

·                  price mitigation strategies employed by ISOs or RTOs that reduce our revenue and may result in a failure to compensate our generating units adequately for all of their costs;

 

·                  legal and political challenges to or changes in the rules used to calculate payments for capacity, energy and ancillary services or the establishment of bifurcated markets, incentives or other market design changes that give preferential treatment to new generating facilities over existing generating facilities;

 

·                  the failure of our generating facilities to perform as expected, including outages for unscheduled maintenance or repair;

 

·                  our failure to use new or advanced power generation technologies;

 

·                  strikes, union activity or labor unrest;

 

·                  our ability to develop or recruit capable leaders and our ability to retain or replace the services of key employees;

 

·                  weather and other natural phenomena, including hurricanes and earthquakes;

 

·                  our failure to provide a safe working environment for our employees and visitors thereby increasing our exposure to additional liability, loss of productive time, other costs and a damaged reputation;

 

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·                  hazards customary to the power generation industry, including those listed in this cautionary statement and elsewhere in this report, and the possibility that we may not have adequate insurance to cover losses resulting from such hazards or the inability of our insurers to provide agreed upon coverage;

 

·                  our ability to execute our plan in respect of our Marsh Landing generating facility, including obtaining and maintaining the governmental authorizations necessary for construction and operation of the generating facility and completing the construction of the generating facility by mid-2013;

 

·                  our relative lack of geographic diversification of revenue sources resulting in concentrated exposure to the PJM market;

 

·                  our ability to enter into intermediate and long-term contracts to sell power or to hedge economically our expected future generation of power, and to obtain adequate supplies and deliveries of fuel for our generating facilities, at our required specifications and on terms and prices acceptable to us;

 

·                  failure to obtain adequate supplies of fuels, including from curtailments of the transportation of fuels;

 

·                  the cost and availability of emissions allowances;

 

·                  the curtailment of operations and reduced prices for electricity resulting from transmission constraints;

 

·                  the potential of additional limitation or loss of our income tax NOLs as a result of an ownership change as defined in IRC Section 382;

 

·                  terrorist activities, cyberterrorism and inadequate cybersecurity, or the occurrence of a catastrophic loss and the possibility that we may not have adequate insurance to cover losses resulting from such hazards or the inability of our insurers to provide agreed upon coverage;

 

·                  deterioration in the financial condition of our counterparties, including financial counterparties, and the failure of such parties to pay amounts owed to us beyond collateral posted or to perform obligations or services due to us;

 

·                  poor economic and financial market conditions, including impacts on financial institutions and other current and potential counterparties, and negative impacts on liquidity in the power and fuel markets in which we hedge economically and transact;

 

·                  increased credit standards, margin requirements, market volatility or other market conditions that could increase our obligations to post collateral beyond amounts that are expected, including additional collateral costs associated with OTC hedging activities as a result of new or proposed laws, rules and regulations governing derivative financial instruments (such as the Dodd-Frank Act and related pending rulemaking proceedings);

 

·                  our inability to access effectively the OTC and exchange-based commodity markets or changes in commodity market conditions and liquidity, including as a result of new or proposed laws, rules and regulations governing derivative financial instruments (such as the Dodd-Frank Act and related pending rulemaking proceedings), which may affect our ability to engage in hedging and proprietary trading activities as expected, or may result in material losses from open positions;

 

·                  volatility in our gross margin as a result of changes in the fair value of our derivative financial instruments used in our hedging and proprietary trading activities and volatility in our cash flow from operations resulting from working capital requirements, including collateral, to support our hedging and proprietary trading activities;

 

·                  the disposition of pending or threatened litigation, including environmental litigation;

 

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·                  our ability to access contractors and equipment necessary to operate and maintain our generating facilities and to design, engineer, procure and construct capital improvements required or deemed advisable;

 

·                  the inability of our operating subsidiaries to generate sufficient cash to support our operations;

 

·                  the ability of lenders under our revolving credit facility and the Marsh Landing credit facility to perform their obligations;

 

·                  our consolidated indebtedness and the possibility that we or our subsidiaries may incur additional indebtedness in the future;

 

·                  restrictions on the ability of our subsidiaries to pay dividends, make distributions or otherwise transfer funds to us, including restrictions on GenOn Mid-Atlantic and REMA contained in their respective operating lease documents, which may affect our ability to access the cash flows of those subsidiaries to make debt service and other payments;

 

·                  our failure or inability to comply with provisions of our leases, loan agreements and debt, which may lead to a breach and, if not remedied, result in an event of default thereunder, which could result in such lessors, lenders and debt holders exercising remedies, limit access to needed liquidity and damage our reputation and relationships with financial institutions;

 

·                  covenants contained in our credit facilities, debt and leases that restrict our current and future operations, particularly our ability to respond to changes or take certain actions that may be in our long-term best interests; and

 

·                  our ability to borrow additional funds and access capital markets.

 

Many of these risks, uncertainties and assumptions are beyond our ability to control or predict.  All forward-looking statements contained herein are expressly qualified in their entirety by cautionary statements contained throughout this report.  Because of these risks, uncertainties and assumptions, you should not place undue reliance on these forward-looking statements.  Furthermore, forward-looking statements speak only as of the date they are made.  We undertake no obligation to update publicly or revise any forward-looking statements to reflect events or circumstances that may arise after the date of this report.

 

In addition to the discussion of certain risks in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the accompanying notes to GenOn’s interim financial statements, other factors that could affect our future performance are set forth in our 2011 Annual Report on Form 10-K.  Our filings and other important information are also available on our investor relations page at www.genon.com/investors.aspx.

 

Certain Terms

 

As used in this report, unless the context requires otherwise, “we,” “us,” “our” and “GenOn” refer to GenOn Energy, Inc. and its consolidated subsidiaries.

 

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PART I

FINANCIAL INFORMATION

 

ITEM 1.     FINANCIAL STATEMENTS

 

GENON ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

 

 

 

Three Months Ended March 31,

 

 

 

2012

 

2011

 

 

 

(in millions, except per share data)

 

 

 

 

 

 

 

Operating revenues (including unrealized gains (losses) of $143 and $(99), respectively)

 

$

721

 

$

814

 

Cost of fuel, electricity and other products (including unrealized (gains) losses of $43 and $(20), respectively)

 

278

 

401

 

Gross Margin (excluding depreciation and amortization)

 

443

 

413

 

Operating Expenses:

 

 

 

 

 

Operations and maintenance

 

308

 

305

 

Depreciation and amortization

 

88

 

86

 

Gain on sales of assets, net

 

(8

)

(1

)

Total operating expenses

 

388

 

390

 

Operating Income

 

55

 

23

 

Other Income (Expense), net:

 

 

 

 

 

Interest expense

 

(89

)

(109

)

Other, net

 

2

 

(22

)

Total other expense, net

 

(87

)

(131

)

Loss Before Income Taxes

 

(32

)

(108

)

Provision for income taxes

 

 

3

 

Net Loss

 

$

(32

)

$

(111

)

Basic and Diluted EPS:

 

 

 

 

 

Basic EPS

 

$

(0.04

)

$

(0.14

)

Diluted EPS

 

$

(0.04

)

$

(0.14

)

 

 

 

 

 

 

Weighted average shares outstanding

 

774

 

771

 

Effect of dilutive securities

 

 

 

Weighted average shares outstanding assuming dilution

 

774

 

771

 

 

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

 

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GENON ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

 

 

 

Three Months Ended March 31,

 

 

 

2012

 

2011

 

 

 

(in millions)

 

 

 

 

 

 

 

Net Loss

 

$

(32

)

$

(111

)

Other Comprehensive Income (Loss), net of reclassifications to net loss, net of tax of $0:

 

 

 

 

 

Pension and other postretirement benefitsactuarial losses, net

 

2

 

1

 

Pension and other postretirement benefitsprior service credit, net

 

(1

)

(1

)

Cash flow hedges—interest rate swaps

 

4

 

3

 

Available-for-sale securities

 

 

(1

)

Other Comprehensive Income

 

5

 

2

 

Comprehensive Loss

 

$

(27

)

$

(109

)

 

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

 

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GENON ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

 

 

 

March 31, 2012

 

December 31, 2011

 

 

 

(in millions)

 

ASSETS

 

 

 

 

 

Current Assets:

 

 

 

 

 

Cash and cash equivalents

 

$

1,705

 

$

1,668

 

Funds on deposit

 

427

 

422

 

Receivables, net

 

299

 

357

 

Derivative contract assets

 

1,231

 

999

 

Inventories

 

532

 

563

 

Prepaid rent and other expenses

 

158

 

167

 

Total current assets

 

4,352

 

4,176

 

Property, plant and equipment, gross

 

7,451

 

7,351

 

Accumulated depreciation and amortization

 

(1,219

)

(1,160

)

Property, Plant and Equipment, net

 

6,232

 

6,191

 

Noncurrent Assets:

 

 

 

 

 

Intangible assets, net

 

46

 

48

 

Derivative contract assets

 

820

 

733

 

Deferred income taxes

 

337

 

294

 

Prepaid rent

 

362

 

386

 

Other

 

438

 

441

 

Total noncurrent assets

 

2,003

 

1,902

 

Total Assets

 

$

12,587

 

$

12,269

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

Current portion of long-term debt

 

$

10

 

$

10

 

Accounts payable and accrued liabilities

 

881

 

790

 

Derivative contract liabilities

 

892

 

720

 

Deferred income taxes

 

337

 

294

 

Other

 

125

 

130

 

Total current liabilities

 

2,245

 

1,944

 

Noncurrent Liabilities:

 

 

 

 

 

Long-term debt, net of current portion

 

4,165

 

4,122

 

Derivative contract liabilities

 

177

 

131

 

Pension and postretirement obligations

 

255

 

259

 

Other

 

653

 

696

 

Total noncurrent liabilities

 

5,250

 

5,208

 

Commitments and Contingencies

 

 

 

 

 

Stockholders’ Equity:

 

 

 

 

 

Preferred stock, par value $.001 per share, authorized 125,000,000 shares, no shares issued at March 31, 2012 and December 31, 2011

 

 

 

Common stock, par value $.001 per share, authorized 2.0 billion shares, issued 772,487,968 shares and 771,692,734 shares at March 31, 2012 and December 31, 2011, respectively

 

1

 

1

 

Additional paid-in capital

 

7,451

 

7,449

 

Accumulated deficit

 

(2,195

)

(2,163

)

Accumulated other comprehensive loss

 

(165

)

(170

)

Total stockholders’ equity

 

5,092

 

5,117

 

Total Liabilities and Stockholders’ Equity

 

$

12,587

 

$

12,269

 

 

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

 

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GENON ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

 

 

 

Three Months Ended March 31,

 

 

 

2012

 

2011

 

 

 

(in millions)

 

Cash Flows from Operating Activities:

 

 

 

 

 

Net loss

 

$

(32

)

$

(111

)

Adjustments to reconcile net loss and changes in operating assets and liabilities to net cash provided by operating activities:

 

 

 

 

 

Depreciation and amortization

 

92

 

90

 

Amortization of acquired contracts

 

(8

)

(7

)

Gain on sales of assets, net

 

(8

)

(1

)

Net changes in derivative contracts

 

(100

)

79

 

Stock-based compensation expense

 

3

 

3

 

Excess materials and supplies inventory reserve

 

35

 

 

Lower of cost or market inventory adjustments

 

46

 

 

Loss on early extinguishment of debt.

 

 

24

 

Advance settlement of out-of-market contract obligation

 

(20

)

 

Other, net

 

2

 

 

Changes in operating assets and liabilities

 

57

 

141

 

Total adjustments

 

99

 

329

 

Net cash provided by operating activities

 

67

 

218

 

Cash Flows from Investing Activities:

 

 

 

 

 

Capital expenditures

 

(87

)

(98

)

Proceeds from the sales of assets

 

12

 

1

 

Restricted funds on deposit, net

 

2

 

1,020

 

Net cash provided by (used in) investing activities

 

(73

)

923

 

Cash Flows from Financing Activities:

 

 

 

 

 

Proceeds from long-term debt

 

45

 

 

Repayment of long-term debt

 

(2

)

(1,153

)

Net cash provided by (used in) financing activities

 

43

 

(1,153

)

Net Increase (Decrease) in Cash and Cash Equivalents

 

37

 

(12

)

Cash and Cash Equivalents, beginning of period

 

1,668

 

2,402

 

Cash and Cash Equivalents, end of period

 

$

1,705

 

$

2,390

 

 

 

 

 

 

 

Supplemental Disclosures:

 

 

 

 

 

Cash paid for interest, net of amounts capitalized

 

$

11

 

$

16

 

Cash refunds received for income taxes

 

$

2

 

$

5

 

 

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

 

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GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

1.  Description of Business and Accounting and Reporting Policies

 

Background

 

We are a wholesale generator with approximately 23,700 MW of net electric generating capacity located, in many cases, near major metropolitan load centers in the PJM, MISO, Northeast and Southeast regions, and California.  We also operate integrated asset management and proprietary trading operations.  See note 2 for a discussion of generating facilities in the Eastern PJM, Western PJM/MISO and California segments that we expect to deactivate between 2012 and 2015.

 

We were formed as a Delaware corporation in August 2000.  “We,” “us,” “our” and “GenOn” refer to GenOn Energy, Inc. and, except where the context indicates otherwise, its subsidiaries, after giving effect to the Merger.

 

Basis of Presentation

 

The consolidated interim financial statements and notes (interim financial statements) are unaudited, omit certain disclosures and should be read in conjunction with our audited consolidated financial statements and notes in our 2011 Annual Report on Form 10-K.  These interim financial statements have been prepared in accordance with GAAP from records maintained by us.  All significant intercompany accounts and transactions have been eliminated in consolidation.  The interim financial statements reflect all normal recurring adjustments necessary, in management’s opinion, to present fairly our financial position and results of operations for the reported periods.  Amounts reported for interim periods may not be indicative of a full year period because of seasonal fluctuations in demand for electricity and energy services, changes in commodity prices, and changes in regulations, timing of maintenance and other expenditures, dispositions, changes in interest expense and other factors.

 

At December 31, 2011 and March 31, 2012, substantially all of our subsidiaries are wholly-owned and located in the United States.  We do not consolidate five power generating facilities, which are under operating leases; a 50% equity investment in a cogeneration facility; and a VIE (MC Asset Recovery) for which we are not the primary beneficiary.  See note 10 for further discussion of MC Asset Recovery.

 

The preparation of interim financial statements in conformity with GAAP requires management to make various estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the interim financial statements and the reported amounts of revenues and expenses during the period.  Actual results could differ from those estimates.  Our significant estimates include:

 

·                  estimating the fair value of certain derivative contracts;

 

·                  estimating the inventory reserve;

 

·                  estimating future taxable income in evaluating the deferred tax asset valuation allowance;

 

·                  estimating the useful lives of long-lived assets;

 

·                  estimating future costs and the valuation of asset retirement obligations;

 

·                  estimating future cash flows in determining impairments of long-lived assets and definite-lived intangible assets;

 

·                  estimating the fair value and expected return on plan assets, discount rates and other actuarial assumptions used in estimating pension and other postretirement benefit plan liabilities; and

 

·                  estimating losses to be recorded for contingent liabilities.

 

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We evaluate events that occur after the balance sheet date but before the financial statements are issued for potential recognition or disclosure.  Based on the evaluation, we determined that there were no material subsequent events for recognition or disclosure other than those disclosed herein.

 

Our results of operations for the three months ended March 31, 2011 have been retroactively amended for the revisions to the provisional purchase price allocation in connection with the Merger.

 

We had disclosed in our 2011 Annual Report on Form 10-K that it was possible that RRI Energy had experienced an ownership change under the applicable tax rules as a result of the Merger.  Based on further inquiries, we do not think that RRI Energy experienced an ownership change as a result of the Merger or following the Merger through December 31, 2011.

 

Funds on Deposit

 

Funds on deposit are included in current and noncurrent assets in the consolidated balance sheets. Funds on deposit include the following:

 

 

 

March 31,

 

December 31,

 

 

 

2012

 

2011

 

 

 

(in millions)

 

 

 

 

 

 

 

Cash collateral posted — energy trading and marketing

 

$

171

 

$

185

 

Cash collateral posted — other operating activities(1) 

 

59

 

39

 

Cash collateral posted — surety bonds(2) 

 

34

 

34

 

GenOn Mid-Atlantic restricted cash(3) 

 

166

 

166

 

GenOn Marsh Landing development project cash collateral posted(4) 

 

114

 

131

 

Environmental compliance deposits(5) 

 

35

 

34

 

Other

 

14

 

16

 

Total current and noncurrent funds on deposit

 

593

 

605

 

Less: Current funds on deposit

 

427

 

422

 

Total noncurrent funds on deposit

 

$

166

 

$

183

 

 


(1)         Includes $32 million related to the Potomac River settlement.  See note 2.

(2)         Represents cash under surety bonds posted primarily with the Pennsylvania Department of Environmental Protection related to environmental obligations.

(3)         Represents cash reserved in respect of interlocutory liens related to the scrubber contract litigation.  See note 10.

(4)         Represents cash-collateralized letters of credit to support the Marsh Landing development project.

(5)         Represents deposits with the State of Pennsylvania to guarantee our obligations related to future closures of coal ash landfill sites and with the State of New Jersey to satisfy our obligations to remediate site contamination.  See note 10.

 

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Inventories

 

Inventories were comprised of the following:

 

 

 

March 31,
2012

 

December 31,
2011

 

 

 

(in millions)

 

 

 

 

 

 

 

Fuel inventory:

 

 

 

 

 

Coal

 

$

229

 

$

229

 

Fuel oil

 

102

 

108

 

Natural gas

 

 

1

 

Other

 

5

 

5

 

Materials and supplies(1) 

 

164

 

201

 

Purchased emissions allowances

 

32

 

19

 

Total inventories

 

$

532

 

$

563

 

 


(1)         Amount is net of an inventory reserve of $35 million and $0 at March 31, 2012 and December 31, 2011, respectively.  See note 2.

 

During the three months ended March 31, 2012 and 2011, we recorded $46 million and $0, respectively, for lower of average cost or market valuation adjustments in cost of fuel, electricity and other products.

 

Capitalization of Interest Cost

 

We incurred the following interest costs:

 

 

 

Three Months Ended March 31,

 

 

 

2012

 

2011

 

 

 

(in millions)

 

 

 

 

 

 

 

Total interest costs

 

$

96

 

$

111

 

Capitalized and included in property, plant and equipment, net

 

(7

)

(2

)

Interest expense

 

$

89

 

$

109

 

 

The amounts of capitalized interest above include interest accrued.  During the three months ended March 31, 2012 and 2011, cash paid for interest was $16 million and $17 million, respectively, of which $5 million and $1 million, respectively, were capitalized.

 

Guarantees and Indemnifications

 

We generally conduct business through various operating subsidiaries which enter into contracts as part of their business activities.  In certain instances, the contractual obligations of such subsidiaries are guaranteed by, or otherwise supported by, us or another of our subsidiaries, including by letters of credit issued under the GenOn credit facilities.  See note 4.

 

In addition, we, including our subsidiaries, enter into various contracts that include indemnification and guarantee provisions.  Examples of these contracts include financing and lease arrangements, purchase and sale agreements, agreements to purchase or sell commodities, construction agreements and agreements with vendors.  Although the primary obligation under such contracts is to pay money or render performance, such contracts may include obligations to indemnify the counterparty for damages arising from the breach thereof and, in certain instances, other existing or potential liabilities.  In many cases, our maximum potential liability cannot be estimated because some of the underlying agreements contain no limits on potential liability.

 

We have guaranteed some non-qualified benefits of CenterPoint’s existing retirees at September 20, 2002.  The estimated maximum potential amount of future payments under the guarantee is $56 million at March 31, 2012 and $4 million is recorded in the consolidated balance sheet for this item.

 

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Recently Adopted Accounting Guidance

 

Fair Value Measurement and Disclosure.  We adopted FASB accounting guidance for the quarter ended March 31, 2012 that requires disclosure of the following:

 

·                  quantitative information about the unobservable inputs used in a fair value measurement that is categorized within Level 3 of the fair value hierarchy;

 

·                  for those fair value measurements categorized within Level 3 of the fair value hierarchy, both the valuation processes used and the sensitivity of the fair value measurement to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any; and

 

·                  the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed.

 

See note 3 for these additional disclosures.

 

Comprehensive Income.  We adopted FASB accounting guidance for the quarter ended March 31, 2012 that requires companies to report the components of comprehensive income in either (a) a continuous statement of comprehensive income or (b) two separate but consecutive statements.  The guidance does not change the items that must be reported in comprehensive income.  See the consolidated statements of comprehensive loss and note 8.

 

New Accounting Guidance Not Yet Adopted at March 31, 2012

 

Balance Sheet Offsetting.  In December 2011, the FASB issued updated guidance to provide enhanced disclosures such that users of the financial statements will be able to better evaluate the effect or potential effect of netting arrangements in the balance sheet.  The guidance requires improved information about financial instruments and derivative instruments that are either offset according to specific guidance or subject to an enforceable master netting agreement or similar arrangement.  The disclosures will provide both net and gross information for these assets and liabilities.  Although we do not currently elect to offset assets and liabilities within the scope of the guidance, expanded disclosures will be required starting for the quarter ended March 31, 2013, along with retrospective presentation of prior periods.

 

2.  Expected Retirements, Mothballing or Long-Term Protective Layup of Generating Facilities

 

Facilities Announced in February and March 2012

 

We are subject to extensive environmental regulation by federal, state and local authorities under a variety of statutes, regulations and permits that address discharges into the air, water and soil; and the proper handling of solid, hazardous and toxic materials and waste.  Complying with increasingly stringent environmental requirements involves significant capital and operating expenses.  To the extent forecasted returns on investments necessary to comply with environmental regulations are insufficient for a particular facility, we plan to deactivate that facility.  In determining the forecasted returns on investments, we factor in forecasted energy and capacity prices, expected capital expenditures, operating costs, property taxes and other factors.  We currently expect to deactivate the following generating capacity, primarily coal-fired units, at the referenced times:  Niles unit 2 (108 MW) June 2012, Elrama units 1-3 (289 MW) mothball June 2012 and retire in March 2014, Portland (401 MW) January 2015, Avon Lake (732 MW) April 2015, New Castle (330 MW) April 2015, Titus (243 MW) April 2015, Shawville (597 MW) place in long-term protective layup in April 2015 and Glen Gardner (160 MW) May 2015.  We will operate Niles unit 1 (109 MW) and Elrama unit 4 (171 MW) under RMR arrangements until October 1, 2012 whereupon we expect to deactivate those two units in the same manner as the other units at those facilities.  While we continue to work with PJM to ensure that any reliability concerns that PJM may have regarding these deactivations are addressed, based on our discussions with PJM, we think that the units identified above for deactivation will be deactivated at the times referenced.

 

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Table of Contents

 

Potomac River Generating Facility

 

During 2011, we entered into an agreement with the City of Alexandria, Virginia to remove permanently from service our Potomac River generating facility. The agreement, which amends our Project Schedule and Agreement, dated July 2008 with the City of Alexandria, provides for the retirement of the Potomac River generating facility on October 1, 2012, subject to the receipt of all necessary consents and approvals.  PJM has determined that the retirement of the facility will not affect reliability.  We must now receive consent from PEPCO.  We will reverse $31 million of the previously recorded obligation under the 2008 agreement with the City of Alexandria upon the receipt of consent from PEPCO and we will recognize a reduction in operations and maintenance expense.  If the PEPCO consent has not been received by July 3, 2012, the Potomac River generating facility will be retired within 90 days after the receipt thereof.  Upon retirement of the Potomac River generating facility, all funds in the escrow account ($32 million) established under the July 2008 agreement shall be distributed to us, provided, that, if the retirement of the facility is after January 1, 2014, $750,000 of such funds shall be paid to the City of Alexandria.

 

Contra Costa Generating Facility

 

We entered into an agreement with PG&E in September 2009 for 674 MW at Contra Costa for the period from November 2011 through April 2013.  At the end of the agreement, and subject to any necessary regulatory approvals, we have agreed to retire the Contra Costa facility.

 

Expenses Related to Deactivations

 

In connection with our decision to deactivate the generating facilities, we are evaluating our materials and supplies inventory and have determined that we have excess inventory.  We established a reserve of $35 million (or $(0.04) per basic share) recorded to operations and maintenance expense during the three months ended March 31, 2012 relating to our excess inventory.  At March 31, 2012, the aggregate carrying value of property, plant and equipment and materials and supplies inventory for the ten generating facilities to be deactivated was $194 million and $26 million, respectively.  In addition, we expect to incur other costs in connection with the deactivations, such as severance and shutdown costs.

 

3.  Financial Instruments

 

Derivatives and Hedging Activities

 

In connection with the business of generating electricity, we are exposed to energy commodity price risk associated with the acquisition of fuel and emissions allowances needed to generate electricity, the price of electricity produced and sold, and the fair value of fuel inventories.  Through our asset management activities, we enter into a variety of exchange-traded and OTC energy and energy-related derivative financial instruments, such as forward contracts, futures contracts, option contracts and financial swap agreements to manage exposure to commodity price risks.  These contracts have varying terms and durations, which range from a few days to years, depending on the instrument.  Our proprietary trading activities also utilize similar derivative contracts in markets where we have a physical presence to attempt to generate incremental gross margin.  Our fuel oil management activities use derivative financial instruments to hedge economically the fair value of physical fuel oil inventories, optimize the approximately two million barrels of storage capacity that we own, and attempt to profit from market opportunities related to timing and/or differences in the pricing of various products.  The open positions in our trading activities comprising proprietary trading and fuel oil management activities expose us to risks associated with changes in energy commodity prices.

 

Derivative financial instruments are recorded in the consolidated balance sheets at fair value, except for derivative contracts that qualify for and for which we have elected the normal purchase or normal sale exceptions, which are not reflected in the consolidated balance sheet or results of operations prior to accrual of the settlement.  We present our derivative contract assets and liabilities on a gross basis (regardless of master netting arrangements with the same counterparty).  Cash collateral amounts are also presented on a gross basis.

 

If certain criteria are met, a derivative financial instrument may be designated as a fair value hedge or cash flow hedge.  In the fourth quarter of 2010, GenOn Marsh Landing entered into interest rate protection agreements

 

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(interest rate swaps) in connection with its project financing, which have been designated as cash flow hedges.  GenOn Marsh Landing entered into the interest rate swaps to reduce the risks with respect to the variability of the interest rates for the term loan.  With the exception of these interest rate swaps, we did not have any other derivative financial instruments designated as fair value or cash flow hedges for accounting purposes during the three months ended March 31, 2012 or 2011.

 

The changes in fair value of cash flow hedges are deferred in accumulated other comprehensive loss, net of tax, to the extent the contracts are, or have been, effective as hedges, until the forecasted transactions affect earnings.  We record immediately into earnings the ineffective portion of changes in fair value of cash flow hedges.

 

Derivative financial instruments designated as cash flow hedges must have a high correlation between price movements in the derivative and the hedged item.  If and when an acceptable level of correlation no longer exists, hedge accounting ceases and changes in fair value are recognized in our results of operations.  If it becomes probable that a forecasted transaction will not occur, we immediately recognize the related deferred gains or losses in our results of operations.  Changes in fair value of the associated hedging instrument are then recognized immediately in earnings for the remainder of the contract term unless a new hedging relationship is designated.

 

For our derivative financial instruments that have not been designated as cash flow hedges for accounting purposes, changes in such instruments’ fair values are recognized currently in earnings.  Our derivative financial instruments are categorized based on the business objective the instrument is expected to achieve:  asset management or trading, which includes proprietary trading and fuel oil management.  For asset management activities, changes in fair value and settlement of derivative financial instruments used to hedge electricity economically are reflected in operating revenue and changes in fair value and settlement of derivative financial instruments used to hedge fuel economically are reflected in cost of fuel, electricity and other products in the consolidated statements of operations.  Changes in the fair value and settlements of derivative financial instruments for proprietary trading and fuel oil management activities are recorded on a net basis as operating revenue in the consolidated statements of operations.

 

We also consider risks associated with interest rates, counterparty credit and our own non-performance risk when valuing derivative financial instruments.  The nominal value of the derivative contract assets and liabilities is discounted to account for time value using a LIBOR forward interest rate curve based on the tenor of the transactions being valued.

 

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Table of Contents

 

The following table presents the fair value of derivative financial instruments:

 

 

 

 

 

 

 

 

 

 

 

Net Derivative

 

 

 

Derivative Contract Assets

 

Derivative Contract Liabilities

 

Contract

 

 

 

Current

 

Long-Term

 

Current

 

Long-Term

 

Assets (Liabilities)

 

 

 

(in millions)

 

March 31, 2012

 

 

 

 

 

 

 

 

 

 

 

Commodity Contracts:

 

 

 

 

 

 

 

 

 

 

 

Asset management

 

$

694

 

$

811

 

$

(344

)

$

(139

)

$

1,022

 

Trading activities

 

537

 

9

 

(546

)

(10

)

(10

)

Total commodity contracts

 

1,231

 

820

 

(890

)

(149

)

1,012

 

Interest Rate Contracts

 

 

 

(2

)

(28

)

(30

)

Total derivatives

 

$

1,231

 

$

820

 

$

(892

)

$

(177

)

$

982

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2011

 

 

 

 

 

 

 

 

 

 

 

Commodity Contracts:

 

 

 

 

 

 

 

 

 

 

 

Asset management

 

$

538

 

$

730

 

$

(255

)

$

(97

)

$

916

 

Trading activities

 

461

 

3

 

(464

)

(3

)

(3

)

Total commodity contracts

 

999

 

733

 

(719

)

(100

)

913

 

Interest Rate Contracts

 

 

 

(1

)

(31

)

(32

)

Total derivatives

 

$

999

 

$

733

 

$

(720

)

$

(131

)

$

881

 

 

The following table presents the net gains (losses) for derivative financial instruments recognized in income in the consolidated statements of operations:

 

 

 

Three Months Ended March 31,

 

 

 

2012

 

2011

 

Derivatives Not Designated as Hedging Instruments

 

Operating
Revenues

 

Cost of Fuel,
Electricity and
Other Products

 

Operating
Revenues

 

Cost of Fuel,
Electricity and
Other Products

 

 

 

(in millions)

 

Asset Management Commodity Contracts:

 

 

 

 

 

 

 

 

 

Unrealized

 

$

150

 

$

(43

)

$

(75

)

$

20

 

Realized(1)(2)

 

184

 

(16

)

79

 

(43

)

Total asset management

 

$

334

 

$

(59

)

$

4

 

$

(23

)

 

 

 

 

 

 

 

 

 

 

Trading Commodity Contracts:

 

 

 

 

 

 

 

 

 

Unrealized

 

$

(7

)

$

 

$

(24

)

$

 

Realized(1)(2)

 

(5

)

 

6

 

 

Total trading

 

$

(12

)

$

 

$

(18

)

$

 

 

 

 

 

 

 

 

 

 

 

Total derivatives

 

$

322

 

$

(59

)

$

(14

)

$

(23

)

 


(1)         Represents the total cash settlements of derivative financial instruments during each reporting period (composed of the sum of the quarterly settlements) that existed at the beginning of each respective period.

(2)         Excludes settlement value of fuel contracts classified as inventory.

 

We recognized immaterial amounts in earnings on derivatives for the interest rate swaps classified as cash flow hedges for the three months ended March 31, 2012 and 2011.  These amounts represent the ineffective portion of the interest rate swaps and are recorded in interest expense.  The assessment of effectiveness excludes the default risk of the counterparties to these transactions and our own non-performance risk.  The effect of these valuation adjustments, which is recorded in interest expense, is a loss of $2 million and a loss of an immaterial amount during

 

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the three months ended March 31, 2012 and 2011, respectively.  At March 31, 2012, no cash flow hedges were discontinued and no amount was recognized in our results of operations as a result of discontinued cash flow hedges as all of the forecasted transactions (future interest payments) were deemed probable of occurring.

 

At March 31, 2012, the maximum length of time we are hedging our exposure to the variability in future cash flows that may result from changes in interest rates is 11 years.  Because a significant portion of the interest expense incurred by GenOn Marsh Landing during construction will be capitalized, amounts included in accumulated other comprehensive loss associated with construction period interest payments will be reclassified to property, plant and equipment and depreciated over the expected useful life of the Marsh Landing generating facility once it commences commercial operations in mid-2013.  Actual amounts reclassified into earnings could vary from the amounts currently recorded as a result of future changes in interest rates.  See note 8 for the effect of the cash flow hedges in comprehensive income/loss.

 

The following tables present the notional quantity on long (short) positions for derivative financial instruments:

 

 

 

Notional Volumes at March 31, 2012

 

Derivative Instruments

 

Derivative
Contract
Assets

 

Derivative
Contract
Liabilities

 

Net
Derivative
Contracts

 

 

 

(in millions)

 

Commodity Contracts (in equivalent MWh):

 

 

 

 

 

 

 

Power(1)

 

(119

)

63

 

(56

)

Natural gas

 

(7

)

9

 

2

 

Coal

 

1

 

12

 

13

 

Interest Rate Contracts (in dollars)(2)

 

 

475

 

475

 

 

 

 

Notional Volumes at December 31, 2011

 

Derivative Instruments

 

Derivative
Contract
Assets

 

Derivative
Contract
Liabilities

 

Net
Derivative
Contracts

 

 

 

(in millions)

 

Commodity Contracts (in equivalent MWh):

 

 

 

 

 

 

 

Power(1)

 

(130

)

73

 

(57

)

Natural gas

 

(8

)

10

 

2

 

Coal

 

3

 

12

 

15

 

Interest Rate Contracts (in dollars)(2)

 

 

475

 

475

 

 


(1)         Includes MWh equivalent of natural gas transactions used to hedge power economically.

(2)         Beginning in mid-2013, the notional amount will increase to $500 million.

 

Fair Value Measurements

 

Fair Value Hierarchy and Valuation Techniques.  We apply recurring fair value measurements to our financial assets and liabilities.  In estimating fair value, we generally use a market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation techniques.  The fair value measurement inputs we use vary from readily observable prices for exchange-traded instruments to price curves that cannot be validated through external pricing sources.  Based on the observability of the inputs used in the valuation techniques, the financial assets and liabilities carried at fair value in the financial statements are classified as follows:

 

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Level 1:                     Represents unadjusted quoted market prices in active markets for identical assets or liabilities that are accessible at the measurement date.  This category primarily includes natural gas and crude oil futures traded on the NYMEX and swaps cleared against NYMEX prices.  Interest bearing funds and trading securities are also valued using Level 1 inputs.

 

Level 2:                     Represents quoted market prices for similar assets or liabilities in active markets, quoted market prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data.  This category primarily includes non-exchange traded derivatives such as OTC forwards, swaps and options, and certain energy derivative instruments that are cleared and settled through exchanges.  This category also includes the interest rate swaps.

 

Level 3:                     Represents commodity derivative instruments whose fair value is estimated based on internally developed models and methodologies utilizing significant inputs that are generally less readily observable from market sources (such as implied volatilities and correlations).  The OTC, complex or structured derivative instruments that are transacted in less liquid markets with limited pricing information are included in Level 3.  Examples are coal contracts, power transmission congestion products, less liquid power and natural gas contracts, and options valued using internally developed inputs.

 

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy.  In such cases, the level in the fair value hierarchy within which the fair value measurement in its entirety falls must be determined based on the lowest level input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and consideration of factors specific to the asset or liability.

 

A significant amount of the fair value of our derivative contract assets and liabilities is based on observable quoted prices from exchanges and indicative quoted prices from independent brokers in active markets that regularly facilitate our transactions.  An active market is considered to have transactions with sufficient frequency and volume to provide pricing information on an ongoing basis.  We think that these prices represent the best available information for valuation purposes.  In determining the fair value of derivative contract assets and liabilities, we use third-party market pricing where available.  For transactions classified in Level 1 of the fair value hierarchy, we use the unadjusted published settled prices on the valuation date.  For transactions classified in Level 2 of the fair value hierarchy, we value these transactions using indicative quoted prices from independent brokers or other widely-accepted valuation methodologies.  Transactions are classified in Level 2 if substantially all (greater than 90%) of the fair value can be corroborated using observable market inputs such as transactable broker quotes.  In accordance with the exit price objective under the fair value measurements accounting guidance, the fair value of our derivative contract assets and liabilities is determined based on the net underlying position of the recorded derivative contract assets and liabilities using bid prices for assets and ask prices for liabilities.  The quotes we obtain from brokers are non-binding in nature, but are from brokers that typically transact in the market being quoted and are based on their knowledge of market transactions on the valuation date.  We typically obtain multiple broker quotes as of the valuation date that extend for the tenor of the underlying contracts for each delivery location.  The number of quotes that we can obtain depends on the relative liquidity of the delivery location on the valuation date.  If multiple broker quotes are received for a contract, we use an average of the quoted bid or ask prices.  If only one broker quote is received for a delivery location and it cannot be validated through other external sources, we will assign the quote to a lower level within the fair value hierarchy.  In some instances, we may combine broker quotes for a liquid delivery hub with broker quotes for the price spread between the liquid delivery hub and the delivery location under the contract.  We also may apply interpolation techniques to value monthly strips if broker quotes are only available on a seasonal or annual basis.  We perform validation procedures on the broker quotes at least monthly.  The validation procedures include reviewing the quotes for accuracy and comparing them to our internal price curves.  In certain instances, we may exclude from consideration a broker quote if it is a clear outlier and other quotes are obtained.  At March 31, 2012, we obtained broker quotes for 100% of our delivery locations classified in Level 2 of the fair value hierarchy.

 

Inactive markets are considered to be those markets with few transactions, noncurrent pricing or prices that vary over time or among market makers.  Our transactions in Level 3 of the fair value hierarchy may involve transactions whereby observable market data, such as broker quotes, are not available for substantially all of the

 

13



Table of Contents

 

tenor of the contract or we are only able to obtain indicative broker quotes that cannot be corroborated by observable market data.  In such cases, we may apply valuation techniques such as extrapolation and other quantitative methods to determine fair value.  Our techniques for fair value estimation include assumptions for market prices, including market price volatility and the volatility of the spread between multiple market prices.  Proprietary models may also be used to estimate the fair value of derivative contract assets and liabilities that may be structured or otherwise tailored.  The degree of estimation increases for longer duration contracts, contracts with multiple pricing features, option contracts and off-hub delivery points.  At March 31, 2012, the assets and liabilities classified as Level 3 in the fair value hierarchy represented 5% of total derivative contract assets and 14% of total derivative contract liabilities.

 

The fair value of our derivative contract assets and liabilities is also affected by assumptions as to time value, credit risk and non-performance risk.  The nominal value of derivatives is discounted to account for time value using a LIBOR forward interest rate curve based on the tenor of the transaction.  Derivative contract assets are reduced to reflect the estimated default risk of counterparties on their contractual obligations.  The counterparty default risk for our overall net position is measured based on published spreads on credit default swaps for counterparties, where available, or proxies based upon published spreads, applied to our current exposure and potential loss exposure from the financial commitments in our risk management portfolio.  The fair value of derivative contract liabilities is reduced to reflect the estimated risk of default on contractual obligations to counterparties and is measured based on published default rates of our debt, where available, or proxies based upon published spreads.  Credit risk and non-performance risk are calculated with consideration of our master netting agreements with counterparties and our exposure is reduced by cash collateral posted to us against these obligations.

 

Information about Sensitivity to Changes in Significant Unobservable Inputs.  The significant unobservable inputs used in the fair value measure of our commodity instruments categorized within Level 3 of the fair value hierarchy are estimates of future market volatility, estimates of forward congestion power price spreads and estimates of counterparty credit risk and our own non-performance risk.  These assumptions are generally independent of each other.  Volatility curves and power prices spreads are generally based on observable markets where available, or derived from historical prices and forward market prices from similar observable markets when not available.  Increases in the price or volatility of the spread on a long/short position in isolation would result in a higher/lower fair value measurement.  A change in the assumption used for the probability of default is accompanied by a directionally similar change in the adjustment to reflect the estimated default risk of counterparties on their contractual obligations, or the estimated risk of default on our own contractual obligations to counterparties.

 

Risk Management.  The Risk and Finance Oversight Committee of the Board of Directors is responsible for oversight of the risk management of our commercial activities and enterprise risk management.  In order to ensure proper daily oversight of our commercial risk controls, the Risk and Finance Oversight Committee has established the ROC with membership determined by the Chief Executive Officer.  The ROC is responsible for ensuring that the necessary policies, procedures and systems are in place to measure, monitor and report on the risks associated with our commercial activities.  The ROC is also responsible for safeguarding proprietary models against the negative impact of inadequate model control by providing oversight and control to model development, back-testing and verification, automation, security and revision control.  The ROC must approve new valuation models or fundamental modifications to existing models.  Model forecasts are back-tested annually and the results reviewed with the ROC.

 

Comprehensive, accurate and timely reporting and monitoring is essential to effectively manage market, credit and operational risks and to protect against large unanticipated losses.  A strong, effective reporting and monitoring function, which includes daily and weekly reporting, keeps the ROC and Chief Risk Officer informed of our activities.  The chair of the ROC reports to the Risk and Finance Oversight Committee on a quarterly basis, or more frequently, if events and circumstances dictate.

 

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Table of Contents

 

Fair Value of Derivative Instruments and Certain Other Assets.  The fair value measurements of financial assets and liabilities by class are as follows:

 

 

 

March 31, 2012

 

 

 

Level 1(1)

 

Level 2(1)(2)

 

Level 3

 

Total
Fair Value

 

 

 

(in millions)

 

Derivative contract assets:

 

 

 

 

 

 

 

 

 

Commodity Contracts

 

 

 

 

 

 

 

 

 

Asset Management:

 

 

 

 

 

 

 

 

 

Power

 

$

143

 

$

1,321

 

$

35

 

$

1,499

 

Fuel

 

 

1

 

5

 

6

 

Total Asset Management

 

143

 

1,322

 

40

 

1,505

 

Trading Activities

 

90

 

388

 

68

 

546

 

Total derivative contract assets

 

$

233

 

$

1,710

 

$

108

 

$

2,051

 

 

 

 

 

 

 

 

 

 

 

Derivative contract liabilities:

 

 

 

 

 

 

 

 

 

Commodity Contracts

 

 

 

 

 

 

 

 

 

Asset Management:

 

 

 

 

 

 

 

 

 

Power

 

$

69

 

$

276

 

$

1

 

$

346

 

Fuel

 

16

 

2

 

119

 

137

 

Total Asset Management

 

85

 

278

 

120

 

483

 

Trading Activities

 

110

 

422

 

24

 

556

 

Interest Rate Contracts

 

 

30

 

 

30

 

Total derivative contract liabilities

 

$

195

 

$

730

 

$

144

 

$

1,069

 

 

 

 

 

 

 

 

 

 

 

Interest-bearing funds(3)

 

$

1,994

 

$

 

$

 

$

1,994

 

Other assets(4)

 

$

21

 

$

 

$

 

$

21

 

 


(1)         Transfers between Level 1 and Level 2 are recognized as of the end of the reporting period.  There were no transfers during the three months ended March 31, 2012.

(2)         Option contracts comprised 2% of net derivative contract assets.

(3)         Represents investments in money market funds and is included in cash and cash equivalents, funds on deposit and other noncurrent assets in the consolidated balance sheet.  We had $1.655 billion of interest-bearing funds included in cash and cash equivalents, $200 million included in funds on deposit and $139 million included in other noncurrent assets.

(4)         Relates to mutual funds held in a rabbi trust for non-qualified deferred compensation plans for some key and highly compensated employees.

 

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Table of Contents

 

 

 

December 31, 2011

 

 

 

Level 1(1)

 

Level 2(1)(2)

 

Level 3

 

Total
Fair Value

 

 

 

(in millions)

 

Derivative contract assets:

 

 

 

 

 

 

 

 

 

Commodity Contracts

 

 

 

 

 

 

 

 

 

Asset Management:

 

 

 

 

 

 

 

 

 

Power

 

$

102

 

$

1,136

 

$

19

 

$

1,257

 

Fuel

 

2

 

 

9

 

11

 

Total Asset Management

 

104

 

1,136

 

28

 

1,268

 

Trading Activities

 

124

 

302

 

38

 

464

 

Total derivative contract assets

 

$

228

 

$

1,438

 

$

66

 

$

1,732

 

 

 

 

 

 

 

 

 

 

 

Derivative contract liabilities:

 

 

 

 

 

 

 

 

 

Commodity Contracts

 

 

 

 

 

 

 

 

 

Asset Management:

 

 

 

 

 

 

 

 

 

Power

 

$

45

 

$

206

 

$

2

 

$

253

 

Fuel

 

19

 

1

 

79

 

99

 

Total Asset Management

 

64

 

207

 

81

 

352

 

Trading Activities

 

142

 

309

 

16

 

467

 

Interest Rate Contracts

 

 

32

 

 

32

 

Total derivative contract liabilities

 

$

206

 

$

548

 

$

97

 

$

851

 

 

 

 

 

 

 

 

 

 

 

Interest-bearing funds(3)

 

$

1,985

 

$

 

$

 

$

1,985

 

Other assets(4)

 

$

20

 

$

 

$

 

$

20

 

 


(1)         Transfers between Level 1 and Level 2 are recognized as of the end of the reporting period.  There were no significant transfers during 2011.

(2)         Option contracts comprised 1% of net derivative contract assets.

(3)         Represents investments in money market funds and is included in cash and cash equivalents, funds on deposit and other noncurrent assets in the consolidated balance sheet.  We had $1.626 billion of interest-bearing funds included in cash and cash equivalents, $202 million included in funds on deposit and $157 million included in other noncurrent assets.

(4)         Relates to mutual funds held in a rabbi trust for non-qualified deferred compensation plans for some key and highly compensated employees.

 

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Table of Contents

 

The following is a reconciliation of changes (comprised of the sum of the quarterly changes) in fair value of net commodity derivative contract assets and liabilities classified as Level 3 during the three months ended March 31, 2012 and 2011:

 

 

 

Net Derivatives Contracts (Level 3)

 

 

 

Asset
Management

 

Trading
Activities

 

Total

 

 

 

(in millions)

 

 

 

 

 

 

 

 

 

Balance, January 1, 2012 (net asset (liability))

 

$

(53

)

$

22

 

$

(31

)

Total gains (losses) realized/unrealized:

 

 

 

 

 

 

 

Included in earnings (1)

 

(40

)

29

 

(11

)

Purchases(2)

 

 

 

 

Issuances(2) 

 

 

 

 

Settlements(3)

 

13

 

(7

)

6

 

Transfers into Level 3(4)

 

 

 

 

Transfers out of Level 3(4)

 

 

 

 

Balance, March 31, 2012 (net asset (liability))

 

$

(80

)

$

44

 

$

(36

)

 

 

 

 

 

 

 

 

Balance, January 1, 2011 (net asset (liability))

 

$

(70

)

$

2

 

$

(68

)

Total gains (losses) realized/unrealized:

 

 

 

 

 

 

 

Included in earnings (1)

 

23

 

1

 

24

 

Purchases(2)

 

 

 

 

Issuances(2) 

 

 

 

 

Settlements(3)

 

(4

)

 

(4

)

Transfers into Level 3(4)

 

 

 

 

Transfers out of Level 3(4)

 

 

 

 

Balance, March 31, 2011 (net asset (liability))

 

$

(51

)

$

3

 

$

(48

)

 


(1)         Represents the fair value, as of the end of each reporting period, of Level 3 contracts entered into during each reporting period and the gains and losses attributable to Level 3 contracts that existed as of the beginning of each reporting period and were still held at the end of each reporting period.

(2)         Contracts entered into during each reporting period are reported with other changes in fair value.

(3)         Represents the reversal of previously recognized unrealized gains and losses from settlement of contracts during each reporting period.

(4)        Denotes the total contracts that existed at the beginning of each reporting period and were still held at the end of each reporting period that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during each reporting period.  Amounts reflect fair value as of the end of each reporting period.

 

The following table presents the amounts included in income related to derivative contract assets and liabilities classified as Level 3:

 

 

 

Three Months Ended March 31,

 

 

 

2012

 

2011

 

 

 

Operating
Revenues

 

Cost of
Fuel,
Electricity
and Other
Products

 

Total

 

Operating
Revenues

 

Cost of
Fuel,
Electricity
and Other
Products

 

Total

 

 

 

(in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gains (losses) included in income

 

$

39

 

$

(44

)

$

(5

)

$

4

 

$

16

 

$

20

 

Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at March 31

 

$

38

 

$

(43

)

$

(5

)

$

4

 

$

15

 

$

19

 

 

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Table of Contents

 

Information about Sensitivity to Changes in Significant Unobservable Inputs.  The following table presents the range of sensitivity of unobservable inputs used in fair value measurements categorized within Level 3 of the fair value hierarchy:

 

 

 

Quantitative Information about Level 3 Fair Value Measurements

 

 

 

Net Fair Value at
March 31, 2012

 

Valuation
Techniques

 

Unobservable Input

 

Range (Weighted
Average)
(1)

 

 

 

(in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Power swaps

 

$

6

 

Internal model

 

Market price

 

3% to (3)%

(2)

Spread options

 

$

8

 

Internal model

 

Volatility

 

35% to (28)%

(3)

Credit valuation adjustment

 

$

(1

)

Internal model

 

Counterparty credit risk

 

20% to (20)%

(4)

Credit valuation adjustment

 

$

3

 

Internal model

 

Own credit risk

 

20% to (20)%

(4)

 


(1)         Excludes immaterial unobservable inputs related to power transmission congestion products and premiums on physical gas transactions.

(2)         Represents the range of the market curves used in the valuation analysis that we think market participants might use when pricing the contracts.

(3)         Represents the range of the volatility curves used in the valuation analysis that we think market participants might use when pricing the contracts.

(4)         Represents the range of the credit default swap spread curves used in the valuation analysis that we think market participants might use when pricing the contracts.

 

At March 31, 2012, net fair value of $63 million of power transactions and $(115) million of fuel transactions classified as Level 3 were priced based on unadjusted indicative broker quotes that cannot be corroborated by observable market data.  Quantitative information is excluded for these fair value measurements.

 

Counterparty Credit Concentration Risk

 

We are exposed to the default risk of the counterparties with which we transact.  We manage our credit risk by entering into master netting agreements and requiring counterparties to post cash collateral or other credit enhancements based on the net exposure and the credit standing of the counterparty.  We also have non-collateralized power hedges entered into by GenOn Mid-Atlantic.  These transactions are senior unsecured obligations of GenOn Mid-Atlantic and the counterparties and do not require either party to post cash collateral for initial margin and, except as described in the next sentence, changes in power or natural gas prices.  Beginning in April 2012, certain agreements entered into by GenOn Mid-Atlantic were amended to provide for the counterparty thereto to post collateral to secure credit exposure above the agreed threshold as a result of changes in power or natural gas prices.  Our credit valuation adjustment on derivative contract assets was $24 million and $48 million at March 31, 2012 and December 31, 2011, respectively.

 

At March 31, 2012 and December 31, 2011, $3 million and $4 million, respectively, of cash collateral posted by counterparties under master netting agreements were included in accounts payable and accrued liabilities in the consolidated balance sheets.

 

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Table of Contents

 

We monitor counterparty credit concentration risk on both an individual basis and a group counterparty basis.  The following tables highlight the credit quality and the balance sheet settlement exposures related to these activities:

 

 

 

March 31, 2012

 

Credit Rating Equivalent

 

Gross Exposure
Before
Collateral
(1)

 

Net Exposure
Before
Collateral
(2)

 

Collateral(3)

 

Exposure Net
of Collateral

 

% of Net
Exposure

 

 

 

(dollars in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

Clearing and Exchange

 

$

906

 

$

298

 

$

298

 

$

 

 

Investment Grade:

 

 

 

 

 

 

 

 

 

 

 

Financial institutions

 

902

 

858

 

 

858

 

78

%

Energy companies

 

511

 

211

 

1

 

210

 

19

%

Non-investment Grade:

 

 

 

 

 

 

 

 

 

 

 

Energy companies

 

12

 

7

 

3

 

4

 

 

No External Ratings:

 

 

 

 

 

 

 

 

 

 

 

Internally-rated investment grade

 

23

 

22

 

 

22

 

2

%

Internally-rated non-investment grade

 

9

 

9

 

 

9

 

1

%

Total

 

$

2,363

 

$

1,405

 

$

302

 

$

1,103

 

100

%

 

 

 

December 31, 2011

 

Credit Rating Equivalent

 

Gross Exposure
Before
Collateral
(1)

 

Net Exposure
Before
Collateral
(2)

 

Collateral(3)

 

Exposure Net
of Collateral

 

% of Net
Exposure

 

 

 

(dollars in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

Clearing and Exchange

 

$

724

 

$

223

 

$

223

 

$

 

 

Investment Grade:

 

 

 

 

 

 

 

 

 

 

 

Financial institutions

 

860

 

817

 

 

817

 

78

%

Energy companies

 

421

 

195

 

3

 

192

 

18

%

Non-investment Grade:

 

 

 

 

 

 

 

 

 

 

 

Energy companies

 

13

 

5

 

1

 

4

 

 

No External Ratings:

 

 

 

 

 

 

 

 

 

 

 

Internally-rated investment grade

 

18

 

18

 

 

18

 

2

%

Internally-rated non-investment grade

 

15

 

15

 

 

15

 

2

%

Total

 

$

2,051

 

$

1,273

 

$

227

 

$

1,046

 

100

%

 


(1)         Gross exposure before collateral represents credit exposure, including both realized and unrealized transactions, before (a) applying the terms of master netting agreements with counterparties and (b) netting of transactions with clearing brokers and exchanges.  The table excludes amounts related to contracts classified as normal purchases/normal sales and non-derivative contractual commitments that are not recorded at fair value in the consolidated balance sheets, except for any related accounts receivable.  Such contractual commitments contain credit and economic risk if a counterparty does not perform.  Non-performance could have a material adverse effect on our future results of operations, financial condition and cash flows.

(2)         Net exposure before collateral represents the credit exposure, including both realized and unrealized transactions, after applying the terms of master netting agreements and the netting of transactions with clearing brokers and exchanges.

(3)         Collateral includes cash and letters of credit received from counterparties.

 

We had credit exposure to two investment grade counterparties at March 31, 2012 and December 31, 2011, each representing an exposure of more than 10% of total credit exposure, net of collateral and totaling $669 million and $664 million at March 31, 2012 and December 31, 2011, respectively.  In April 2012, certain agreements entered into by GenOn Mid-Atlantic were amended to provide for the counterparty thereto to post collateral to secure credit exposure above the agreed threshold as a result of changes in power or natural gas prices, including one of the counterparties referenced in the preceding sentence.  At April 27, 2012, the total credit exposure, net of collateral, of the referenced counterparty was $201 million compared to $429 million at March 31, 2012.

 

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Table of Contents

 

GenOn Credit Risk

 

Our standard industry contracts contain credit-risk-related contingent features such as ratings-related thresholds whereby we would be required to post additional cash collateral or letters of credit as a result of a credit event, including a downgrade.  Additionally, some of our contracts contain adequate assurance language, which is generally subjective in nature that could require us to post additional cash collateral or letters of credit as a result of a credit event, including a downgrade.  However, as a result of our current credit rating, we are typically required to post collateral in the normal course of business to offset either substantially or completely the net liability positions, after applying the terms of master netting agreements.  At March 31, 2012, the fair value of financial instruments with credit-risk-related contingent features in a net liability position was $11 million for which we had posted collateral of $9 million, including cash and letters of credit.

 

At March 31, 2012 and December 31, 2011, we had $104 million and $86 million, respectively, of cash collateral posted with counterparties under master netting agreements that was included in funds on deposit in the consolidated balance sheets.

 

Fair Values of Other Financial Instruments

 

The fair values of certain funds on deposit, accounts receivable, notes and other receivables, and accounts payable and accrued liabilities approximate their carrying amounts.

 

The carrying amounts and fair values of debt are as follows:

 

 

 

Carrying
Amount

 

Level 1

 

Level 2(1)

 

Level 3(2)

 

Total Fair Value

 

 

 

(in millions)

 

March 31, 2012

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

Long and short-term debt

 

$

4,175

 

$

 

$

3,746

 

$

139

 

$

3,885

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2011

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

$

4,132

 

$

 

$

3,969

 

$

97

 

$

4,066

 

Long and short-term debt

 

 

 

 

 

 

 

 

 

 

 

 


(1)         The fair value of long and short-term debt is estimated using broker quotes for instruments that are publicly traded.

(2)         The fair value of long and short-term debt is estimated based on the income approach valuation technique for non-publicly traded debt using current interest rates for similar instruments with equivalent credit quality.

 

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Table of Contents

 

4.  Long-Term Debt

 

Outstanding debt was as follows:

 

 

 

March 31, 2012

 

December 31, 2011

 

 

 

Weighted
Average
Stated
Interest
Rate (1)

 

Long-term

 

Current

 

Weighted
Average
Stated
Interest
Rate (1)

 

Long-term

 

Current

 

 

 

(in millions, except interest rates)

 

Facilities, Bonds and Notes:

 

 

 

 

 

 

 

 

 

 

 

 

 

GenOn:

 

 

 

 

 

 

 

 

 

 

 

 

 

Senior unsecured notes, due 2014

 

7.625%

 

$

575

 

$

 

7.625

%

$

575

 

$

 

Senior unsecured notes, due 2017

 

7.875

 

725

 

 

7.875

 

725

 

 

Senior secured term loan, due 2017(2) 

 

6.00

 

683

 

7

 

6.00

 

684

 

7

 

Senior unsecured notes, due 2018

 

9.50

 

675

 

 

9.50

 

675

 

 

Senior unsecured notes, due 2020

 

9.875

 

550

 

 

9.875

 

550

 

 

Unamortized debt discounts

 

 

 

(24

)

(2

)

 

 

(24

)

(2

)

GenOn Americas Generation:

 

 

 

 

 

 

 

 

 

 

 

 

 

Senior unsecured notes, due 2021

 

8.50

 

450

 

 

8.50

 

450

 

 

Senior unsecured notes, due 2031

 

9.125

 

400

 

 

9.125

 

400

 

 

Unamortized debt discounts

 

 

 

(2

)

 

 

 

(2

)

 

GenOn Marsh Landing: