UNITED STATES
SECURITIES AND EXCHANGE
COMMISSION
Washington, D.C.
20549
Form 10-K
|
|
|
þ
|
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
|
|
|
For the fiscal year ended
December 31,
2010
|
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:
333-63240
GenOn
Americas Generation, LLC
(Exact
Name of Registrant as Specified in Its Charter)
51-0390520
(I.R.S. Employer Identification
No.)
Commission File Number:
333-61668
GenOn
Mid-Atlantic, LLC
(Exact Name of Registrant as
Specified in Its Charter)
|
|
|
Delaware
(State or Other Jurisdiction
of
Incorporation or Organization of All Registrants)
|
|
58-2574140
(I.R.S. Employer
Identification No.)
|
|
|
|
1000 Main Street,
Houston, Texas 77002
(Address of Principal
Executive Offices,
Including Zip Code, of All Registrants)
|
|
(832) 357-3000
(Registrants telephone
number,
including area code)
|
None
Securities registered pursuant to Section 12(b) of the Act
None
Securities registered pursuant to Section 12(g) of the Act
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined by Rule 405 of the Securities
Act.
|
|
|
|
|
GenOn Americas Generation, LLC
|
|
|
o Yes þ No
|
|
GenOn Mid-Atlantic, LLC
|
|
|
o Yes þ No
|
|
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act.
|
|
|
|
|
GenOn Americas Generation, LLC
|
|
|
þ Yes o No
|
|
GenOn Mid-Atlantic, LLC
|
|
|
þ Yes o No
|
|
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.
(As a voluntary filer not subject to filing requirements, the
registrant nevertheless filed all reports which would have been
required to be filed by Section 15(d) of the Exchange Act
during the preceding 12 months had the registrant been
required to file reports pursuant to Section 15(d) of the
Securities Exchange Act of 1934 solely as a result of having
registered debt securities under the Securities Act of 1933.)
|
|
|
|
|
GenOn Americas Generation, LLC
|
|
|
o Yes o No
|
|
GenOn Mid-Atlantic, LLC
|
|
|
o 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).
|
|
|
|
|
GenOn Americas Generation, LLC
|
|
|
o Yes o No
|
|
GenOn Mid-Atlantic, LLC
|
|
|
o Yes o No
|
|
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(§ 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of the registrants
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-K
or any amendment to this
Form 10-K.
|
|
|
GenOn Americas Generation, LLC
|
|
þ
|
GenOn Mid-Atlantic, LLC
|
|
þ
|
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
|
|
Accelerated filer
|
|
Non-accelerated filer
|
|
Smaller reporting company
|
|
GenOn Americas Generation, LLC
|
|
o
|
|
o
|
|
þ
|
|
o
|
GenOn Mid-Atlantic, LLC
|
|
o
|
|
o
|
|
þ
|
|
o
|
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Act).
|
|
|
|
|
GenOn Americas Generation, LLC
|
|
|
o Yes þ No
|
|
GenOn Mid-Atlantic, LLC
|
|
|
o Yes þ No
|
|
All of the registrants outstanding membership interests
are held by its parent and there are no membership interest held
by nonaffiliates.
|
|
|
Registrant
|
|
Parent
|
|
GenOn Americas Generation, LLC
|
|
GenOn Americas, Inc.
|
GenOn Mid-Atlantic, LLC
|
|
GenOn North America, LLC
|
This combined
Form 10-K
is separately filed by GenOn Americas Generation, LLC and GenOn
Mid-Atlantic, LLC. Information contained in this combined
Form 10-K
relating to GenOn Americas Generation, LLC and GenOn
Mid-Atlantic, LLC is filed by such registrant on its own behalf
and each registrant makes no representation as to information
relating to registrants other than itself.
We have not incorporated by reference any information into this
Form 10-K
from any annual report to securities holders, proxy statement or
prospectus filed pursuant to 424(b) or (c) of the
Securities Act.
NOTE: WHEREAS GENON AMERICAS GENERATION, LLC AND GENON
MID-ATLANTIC, LLC MEET THE CONDITIONS SET FORTH IN GENERAL
INSTRUCTION I(1)(a) AND (b) OF
FORM 10-K,
THIS COMBINED
FORM 10-K
IS BEING FILED WITH THE REDUCED DISCLOSURE FORMAT PURSUANT TO
GENERAL INSTRUCTION I(2).
GLOSSARY
OF CERTAIN DEFINED TERMS
|
|
|
AB 32 |
|
Californias Global Warming Solutions Act. |
|
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. |
|
Administrative Services Agreement |
|
Management, personnel and services agreement with GenOn Energy
Services, effective January 3, 2006. |
|
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. |
|
CAIR |
|
Clean Air Interstate Rule. |
|
CAISO |
|
California Independent System Operator. |
|
CAMR |
|
Clean Air Mercury Rule. |
|
capacity |
|
Energy that could have been generated at continuous full-power
operation during the period. |
|
CARB |
|
California Air Resources Board. |
|
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. |
|
CERCLA |
|
Federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980. |
|
CFTC |
|
Commodity Futures Trading Commission. |
|
Clean Air Act |
|
Federal Clean Air Act. |
|
Clean Water Act |
|
Federal Water Pollution Control Act. |
|
Climate Protection Act |
|
Massachusetts Global Warming Solutions Act. |
|
CO2 |
|
Carbon dioxide. |
|
Companies |
|
GenOn Americas Generation, LLC, GenOn Mid-Atlantic, LLC and
their subsidiaries. |
|
D.C. Circuit |
|
The United States Court of Appeals for the District of Columbia
Circuit. |
|
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. |
|
Exchange Act |
|
Securities Exchange Act of 1934, as amended. |
|
Exchange Ratio |
|
Right of Mirant Corporation stockholders to receive
2.835 shares of common stock of RRI Energy, Inc. in the
Merger. |
|
FASB |
|
Financial Accounting Standards Board. |
ii
GLOSSARY
OF CERTAIN DEFINED TERMS
(Continued)
|
|
|
FCM |
|
Forward Capacity Market administered by ISO-NE to procure
capacity resources to meet forecasted demand and reserve
requirements. |
|
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. (formerly known as Mirant Americas, Inc.). |
|
GenOn Americas Generation |
|
GenOn Americas Generation, LLC (formerly known as Mirant
Americas Generation, LLC). |
|
GenOn Bowline |
|
GenOn Bowline, LLC (formerly known as Mirant Bowline, LLC). |
|
GenOn California North |
|
GenOn California North, LLC (formerly known as Mirant
California, LLC). |
|
GenOn Canal |
|
GenOn Canal, LLC (formerly known as Mirant Canal, LLC). |
|
GenOn Chalk Point |
|
GenOn Chalk Point, LLC (formerly known as Mirant Chalk Point,
LLC). |
|
GenOn Delta |
|
GenOn Delta, LLC (formerly known as Mirant Delta, LLC). |
|
GenOn Energy Holdings |
|
GenOn Energy Holdings, Inc. (formerly known as Mirant
Corporation) and, except where the context indicates otherwise,
its subsidiaries. |
|
GenOn Energy Management |
|
GenOn Energy Management, LLC (formerly known as Mirant Energy
Trading, LLC). |
|
GenOn Energy Services |
|
GenOn Energy Services, LLC (formerly known as Mirant Services,
LLC). |
|
GenOn Escrow |
|
GenOn Escrow Corp. |
|
GenOn Kendall |
|
GenOn Kendall, LLC (formerly known as Mirant Kendall, LLC). |
|
GenOn Lovett |
|
GenOn Lovett, LLC, owner of the former Lovett generating
facility, which was shut down on April 19, 2008, and has
been demolished (formerly known as Mirant Lovett, LLC). |
|
GenOn Marsh Landing |
|
GenOn Marsh Landing, LLC (formerly known as Mirant Marsh
Landing, LLC). |
|
GenOn MD Ash Management |
|
GenOn MD Ash Management, LLC (formerly known as Mirant MD Ash
Management, LLC). |
|
GenOn Mid-Atlantic |
|
GenOn Mid-Atlantic, LLC (formerly known as Mirant Mid-Atlantic,
LLC) and, except where the context indicates otherwise, its
subsidiaries. |
|
GenOn North America |
|
GenOn North America, LLC (formerly known as Mirant North
America, LLC). |
iii
GLOSSARY
OF CERTAIN DEFINED TERMS
(Continued)
|
|
|
GenOn Potomac River |
|
GenOn Potomac River, LLC (formerly known as Mirant Potomac
River, LLC). |
|
GenOn Potrero |
|
GenOn Potrero, LLC (formerly known as Mirant Potrero, LLC). |
|
HAP |
|
Hazardous Air Pollutant. |
|
Hudson Valley Gas |
|
Hudson Valley Gas Corporation. |
|
IBEW |
|
International Brotherhood of Electrical Workers. |
|
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. |
|
ISO |
|
Independent system operator. |
|
ISO-NE |
|
Independent System Operator-New England. |
|
LIBOR |
|
London InterBank Offered Rate. |
|
LTSA |
|
Long-term service agreement. |
|
MACT |
|
Maximum achievable control technology. |
|
MADEP |
|
Massachusetts Department of Environmental Protection. |
|
MAEEA |
|
Massachusetts Executive Office of Energy and Environmental
Affairs. |
|
Maryland Act |
|
Greenhouse Gas Reduction Act of 2009. |
|
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. |
|
MW |
|
Megawatt. |
|
MWh |
|
Megawatt hour. |
|
NAAQS |
|
National ambient air quality standard. |
|
NERC |
|
North American Electric Reliability Council. |
|
net capacity factor |
|
Actual net production of electricity as a percentage of net
generating capacity to produce electricity. |
|
net generating capacity |
|
Net summer capacity. |
|
NOL |
|
Net operating loss. |
|
NOV |
|
Notice of violation. |
|
NOx |
|
Nitrogen oxides. |
iv
GLOSSARY
OF CERTAIN DEFINED TERMS
(Continued)
|
|
|
NPCC |
|
Northeast Power Coordinating Council. |
|
NPDES |
|
National pollutant discharge elimination system. |
|
NYISO |
|
New York Independent System Operator. |
|
NYMEX |
|
New York Mercantile Exchange. |
|
OTC |
|
Over-the-counter. |
|
Ozone Season |
|
The period between May 1 and September 30 of each year. |
|
peaking generating units |
|
Units designed to satisfy demand requirements during the periods
of greatest or peak load on the system. |
|
PG&E |
|
Pacific Gas & Electric Company. |
|
PJM |
|
PJM Interconnection, LLC. |
|
Plan |
|
The plan of reorganization that was approved in conjunction with
Mirant Corporations and the Companies emergence from
bankruptcy protection on January 3, 2006. |
|
Power Sale, Fuel Supply and Services Agreement |
|
Power sale, fuel supply and services agreement with Mirant
Americas Energy Marketing, LP. effective January 3, 2006.
As of February 1, 2006, the agreement was transferred to
GenOn Energy Management. |
|
PPA |
|
Power purchase agreement. |
|
PUHCA |
|
Public Utility Holding Company Act of 2005. |
|
reserve margin |
|
Excess capacity over peak demand. |
|
RFC |
|
Reliability First Corporation. |
|
RGGI |
|
Regional Greenhouse Gas Initiative. |
|
RMR |
|
Reliability-must-run. |
|
RPM |
|
Model utilized by PJM to meet load serving entities
forecasted capacity obligations through a forward-looking
commitment of capacity resources. |
|
RRI Energy |
|
RRI Energy, Inc., which changed its name to GenOn Energy, Inc.
in connection with the Merger. |
|
RTO |
|
Regional Transmission Organization. |
|
SCR |
|
Selective catalytic reduction emissions controls. |
|
scrubbers |
|
Flue gas desulfurization emissions controls. |
|
SEC |
|
United States Securities and Exchange Commission. |
|
Securities Act |
|
Securities Act of 1933, as amended. |
|
SEMA |
|
Southeastern Massachusetts zone within ISO-NE. |
|
SO2 |
|
Sulfur dioxide. |
v
GLOSSARY
OF CERTAIN DEFINED TERMS
(Continued)
|
|
|
spark spread |
|
The difference between the price received for electricity
generated compared to the market price of the natural gas
required to produce the electricity. |
|
SWD |
|
Surface water discharge. |
|
Transport Rule |
|
The EPAs Proposed Federal Implementation Plan To Reduce
Interstate Transport of Fine Particulate Matter and Ozone, which
would replace the CAIR. |
|
UWUA |
|
Utility Workers Union of America. |
|
VaR |
|
Value at risk. |
|
Virginia DEQ |
|
Virginia Department of Environmental Quality. |
|
WCI |
|
Western Climate Initiative. |
|
WECC |
|
Western Electric Coordinating Council. |
vi
CAUTIONARY
STATEMENT REGARDING FORWARD-LOOKING INFORMATION
In addition to historical information, the information presented
in this combined
Form 10-K
includes forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933 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
terminology 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 other
comparable terminology.
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:
|
|
|
|
|
our ability to integrate successfully the businesses following
the Merger or realize cost savings and any other synergies as a
result of the Merger;
|
|
|
|
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 supply and delivery
of fuel for our generating facilities, at our required
specifications and on terms and prices acceptable to us;
|
|
|
|
failure to obtain adequate fuel supply, including from
curtailments of the transportation of natural gas;
|
|
|
|
changes in market conditions, including developments in the
supply, demand, volume and pricing of electricity and other
commodities 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;
|
|
|
|
deterioration in the financial condition of our counterparties,
including affiliates, and the failure of such parties to pay
amounts owed to us or to perform obligations or services due to
us beyond collateral posted;
|
|
|
|
the failure of our generating facilities to perform as expected,
including outages for unscheduled maintenance or repair;
|
|
|
|
hazards customary to the power generation industry 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 failure to utilize new or advancements in 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;
|
|
|
|
the cost and availability of emissions allowances;
|
|
|
|
the curtailment of operations and reduced prices for electricity
resulting from transmission constraints;
|
|
|
|
the ability of GenOn Americas Generation to execute the business
plan in northern California, including entering into new tolling
arrangements for its existing generating facilities;
|
|
|
|
our lack of geographic diversification of revenue sources
resulting in concentrated exposure to the PJM market;
|
|
|
|
war, terrorist activities, cyberterrorism and inadequate
cybersecurity, or the occurrence of a catastrophic loss;
|
vii
|
|
|
|
|
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;
|
|
|
|
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 regulations), which may affect
our ability to engage in asset management and, for GenOn
Americas Generation, proprietary trading and fuel oil management
activities as expected, or may result in material gains or
losses from open positions;
|
|
|
|
volatility in our gross margin as a result of our accounting for
derivative financial instruments used in our asset management
and GenOn Americas Generations proprietary trading and
fuel oil management activities and volatility in our cash flow
from operations resulting from working capital requirements,
including collateral, to support our asset management and GenOn
Americas Generations proprietary trading and fuel oil
management activities;
|
|
|
|
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, environmental and other laws and regulations
to which we and our subsidiaries and affiliates are or could
become subject;
|
|
|
|
more stringent environmental laws and regulations (including the
cumulative effect of many such regulations) and the disposition
of environmental litigation that restrict our ability or render
it uneconomic to operate our assets, including regulations and
litigation related to air emissions;
|
|
|
|
increased regulation that limits our access to adequate water
supplies and landfill options needed to support power generation
or that increases the costs of cooling water and handling,
transporting and disposing of ash and other byproducts;
|
|
|
|
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 exiting generating facilities;
|
|
|
|
the disposition of pending or threatened litigation, including
environmental litigation;
|
|
|
|
the inability of GenOn Americas Generations operating
subsidiaries to generate sufficient cash to support their
operations;
|
|
|
|
the ability of lenders under GenOns revolving credit
facility to perform their obligations;
|
|
|
|
GenOn Americas Generations consolidated indebtedness and
the possibility that GenOn Americas Generation or its
subsidiaries may incur additional indebtedness in the future;
|
|
|
|
restrictions on the ability of GenOn Americas Generations
subsidiaries to pay dividends, make distributions or otherwise
transfer funds to GenOn Americas Generation, including
restrictions on
|
viii
|
|
|
|
|
GenOn Mid-Atlantic contained in its operating lease documents,
which may affect GenOn Americas Generations ability to
access the cash flows of those subsidiaries to make debt service
and other payments;
|
|
|
|
|
|
failure to comply with provisions of GenOn Mid-Atlantics
operating leases, GenOn Americas Generations debt and
affiliates loan agreements and debt 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 affiliates 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 and our affiliates 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 attributable to us or persons acting on our behalf
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.
Factors
that Could Affect Future Performance
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. Our filings and
other important information are also available on our investor
relations page at www.genon.com/investors.aspx.
In addition to the discussion of certain risks in Item 7,
Managements Discussion and Analysis of Financial
Condition and Results of Operations and the accompanying
combined notes to GenOn Americas Generation, LLCs and
GenOn Mid-Atlantic, LLCs consolidated financial
statements, other factors that could affect our future
performance are set forth in Item 1A. Risk
Factors.
Certain
Terms
As used in this report, unless the context requires otherwise,
we, us, our, and the
Companies refer to GenOn Americas Generation, LLC,
GenOn Mid-Atlantic, LLC and their subsidiaries. In addition, as
used in this report, unless the context requires otherwise,
GenOn Americas Generation refers to GenOn Americas
Generation, LLC and its subsidiaries and GenOn
Mid-Atlantic refers to GenOn Mid-Atlantic, LLC and its
subsidiaries.
ix
PART I
Merger of
Mirant and RRI Energy
On December 3, 2010, Mirant and RRI Energy completed their
Merger. Mirant merged with a wholly-owned subsidiary of RRI
Energy, with Mirant surviving the Merger as a wholly-owned
subsidiary of RRI Energy. In connection with the all-stock,
tax-free Merger, RRI Energy changed its name to GenOn Energy,
Inc., Mirant stockholders received a fixed ratio of
2.835 shares of GenOn common stock for each share of Mirant
common stock, and Mirant changed its name to GenOn Energy
Holdings.
Pursuant to the Plan for Mirant and certain of its subsidiaries,
on January 3, 2006, Mirant emerged from bankruptcy and
acquired substantially all of the assets of the old Mirant
Corporation. The Plan provides that new Mirant (now named GenOn
Energy Holdings) has no successor liability for any unassumed
obligations of the old Mirant Corporation. The old corporation
was then renamed and transferred to a trust, which is not
affiliated with GenOn Energy Holdings. For further information
about our corporate history, revenues, suppliers, business
segments and Mirants bankruptcy, see notes 1, 8 and 9
to our consolidated financial statements and Selected
Financial Data in Item 6 of this
Form 10-K.
Overview
GenOn Americas Generation provides energy, capacity, ancillary
and other energy services to wholesale customers in competitive
energy markets in the United States through ownership and
operation of, and contracting for, power generation capacity.
GenOn Americas Generation is a wholesale generator with
approximately 9,724 MW of net electric generating capacity
in the Eastern PJM and Northeast regions and in northern
California, including 5,204 MW with GenOn Mid-Atlantic in
the Eastern PJM region. GenOn Americas Generation also operates
integrated asset management and energy marketing organizations,
including proprietary trading operations. GenOn Americas
Generations customers are principally ISOs, RTOs and
investor-owned utilities. GenOn Americas Generations
generating portfolio is diversified across fossil fuel and
technology types, operating characteristics and several regional
power markets and serves customers primarily located near major
metropolitan load centers.
At December 31, 2010, GenOn Americas Generations
generating capacity was 52% in PJM, 23% in CAISO, and 25% in
NYISO and ISO-NE. GenOn Mid-Atlantics generating
facilities serve the PJM markets. GenOn Americas
Generations net generating capacity is 30% baseload, 58%
intermediate and 12% peaking. GenOn Mid-Atlantics net
generating capacity is 53% baseload, 27% intermediate and 20%
peaking capacity. Our coal facilities generally dispatch as
baseload, although some dispatch as intermediate capacity, and
our gas, oil and dual fuel plants primarily dispatch as
intermediate
and/or
peaking capacity.
GenOn Americas Generation and GenOn Mid-Atlantic are Delaware
limited liability companies and indirect wholly-owned
subsidiaries of GenOn. GenOn Mid-Atlantic is an indirect
wholly-owned subsidiary of GenOn Americas Generation.
1
The chart below is a summary representation of the
Companies organizational structure and is not a complete
organizational chart of GenOn.
|
|
(1) |
GenOn Power Generation, LLCs subsidiaries include former
RRI Energy generating facilities acquired as a result of the
Merger.
|
Strategy
Our goal is to create long-term stockholder value across a broad
range of commodity price environments. We intend to achieve this
goal by:
Successfully integrating the companies and achieving cost
savings targets. GenOn expects to achieve
approximately $150 million in annual cost savings through
reductions in corporate overhead and support costs. GenOn
expects cost savings to result from consolidations in several
areas, including headquarters, IT systems and corporate
functions such as accounting, human resources and finance.
Starting in January 2012, GenOn expects to achieve the full
$150 million of annual cost savings. GenOn has estimated
the total merger-related costs at approximately
$215 million.
Continued operating and commercial
expertise. We have substantial experience in the
management, operation and optimization of a portfolio of diverse
generating facilities. Drawing on the best practices of Mirant
and RRI Energy, we intend to operate our generating facilities
safely and efficiently and in an environmentally responsible
manner to achieve optimal availability and performance to
maximize cash flow.
Transacting to reduce variability in realized gross
margin. We intend to develop and execute
appropriate hedging strategies to manage risks associated with
the volatility in the price at which we sell power and in the
prices of fuel, emissions allowances and other inputs required
to produce such power. This includes hedging over multiple years
to reduce the variability in realized gross margin from our
expected generation. In addition, we expect to continue to sell
capacity either bilaterally or through periodic auction
processes.
Investing capital prudently. Our capital
investment decisions are focused on achieving an appropriate
return on investment. Capital investments include participating
in the development or acquisition of new facilities, the
maintenance of our existing facilities for long-term
availability and improved commercial availability, and
investments in our existing facilities to improve their
competitive position.
2
Maintaining appropriate liquidity and capital
structure. Through disciplined balance sheet
management and maintaining adequate liquidity, we expect to be
able to operate across a broad range of commodity price
environments.
Business
Segments (GenOn Americas Generation)
We have five operating segments: Eastern PJM, Northeast,
California, Energy Marketing and Other Operations.
The Eastern PJM segment consists of four generating facilities
located in Maryland and Virginia, near Washington, D.C.
The Northeast segment consists of three generating facilities
located in Massachusetts and one generating facility located in
New York. For 2008, the Northeast segment included the Lovett
generating facility in New York, which was shut down on
April 19, 2008 and demolished in 2009.
The California segment consists of three generating facilities
located in or near the City of San Francisco.
The Energy Marketing segment consists of GenOn Americas
Generations proprietary trading and fuel oil management
activities.
The Other Operations segment includes parent company adjustments
for affiliate transactions.
The table below summarizes selected financial information of our
operations by business segment for 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
Business Segments
|
|
Revenues
|
|
|
Gross
Margin(1)
|
|
|
Income (Loss)
|
|
|
|
(dollars in millions)
|
|
|
Eastern PJM
|
|
$
|
1,704
|
(2)
|
|
|
81
|
%
|
|
$
|
1,006
|
|
|
|
80
|
%
|
|
$
|
(778
|
)
|
|
|
416
|
%
|
Northeast
|
|
|
234
|
|
|
|
11
|
%
|
|
|
97
|
|
|
|
8
|
%
|
|
|
(33
|
)
|
|
|
18
|
%
|
California
|
|
|
144
|
|
|
|
7
|
%
|
|
|
121
|
|
|
|
10
|
%
|
|
|
26
|
|
|
|
(14
|
)%
|
Energy Marketing
|
|
|
1,868
|
|
|
|
89
|
%
|
|
|
27
|
|
|
|
2
|
%
|
|
|
16
|
|
|
|
(9
|
)%
|
Other Operations
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
(34
|
)
|
|
|
18
|
%
|
Eliminations
|
|
|
(1,845
|
)
|
|
|
(88
|
)%
|
|
|
|
|
|
|
|
%
|
|
|
616
|
|
|
|
(329
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,105
|
|
|
|
100
|
%
|
|
$
|
1,251
|
|
|
|
100
|
%
|
|
$
|
(187
|
)
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gross margin excludes depreciation and amortization. |
|
(2) |
|
For 2010, we recorded $1.3 billion in revenues from a
single counterparty (PJM) which represented 63% of our
consolidated revenues. The revenues generated from this
counterparty are included primarily in our Eastern PJM segment. |
Eliminations for revenues and gross margin are primarily related
to intercompany sales of emissions allowances, intercompany
revenues and cost of fuel. Eliminations for operating
income/loss also include a $616 million impairment loss
related to goodwill recorded at our GenOn Mid-Atlantic
subsidiary on its standalone balance sheet. The goodwill
impairment loss and related goodwill balance are eliminated upon
consolidation at GenOn North America and are not reflected on
the consolidated balance sheet of GenOn Americas Generation. For
selected financial information about our business segments, see
note 8 to our consolidated financial statements.
3
Eastern
PJM Segment
We own or lease four generating facilities in the Eastern PJM
segment with total net generating capacity of 5,204 MW. Our
Eastern PJM segment had a combined 2010 net capacity factor
of 34%. The following table presents the details of our Eastern
PJM generating facilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
Generating
|
|
|
|
Primary
|
|
|
|
|
|
|
|
|
Capacity
|
|
|
|
Fuel
|
|
|
|
|
|
NERC
|
Facility
|
|
(MW)(1)
|
|
Holding
|
|
Type
|
|
Dispatch Type
|
|
Location
|
|
Region
|
|
Chalk Point
|
|
2,401
|
|
Own
|
|
Coal/Dual/Oil
|
|
Baseload/
Intermediate/
Peaking
|
|
Maryland
|
|
RFC
|
Dickerson
|
|
844
|
|
Own/
Lease(2)
|
|
Coal/Dual/Oil
|
|
Baseload/Peaking
|
|
Maryland
|
|
RFC
|
Morgantown
|
|
1,477
|
|
Own/
Lease(2)
|
|
Coal/Oil
|
|
Baseload/Peaking
|
|
Maryland
|
|
RFC
|
Potomac River
|
|
482
|
|
Own
|
|
Coal
|
|
Baseload/
Intermediate
|
|
Virginia
|
|
RFC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Eastern PJM
|
|
5,204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Total MW amounts reflect net summer capacity. |
|
(2) |
|
We lease a 100% interest in the Dickerson and Morgantown
baseload units through facility lease agreements expiring in
2029 and 2034, respectively. We own 307 MW and 248 MW
of peaking capacity at the Dickerson and Morgantown generating
facilities, respectively. |
We completed the installation of scrubbers at our Chalk Point,
Dickerson and Morgantown coal-fired units in the fourth quarter
of 2009. We previously installed SCR systems at the Morgantown
coal-fired units and one of the Chalk Point coal-fired units and
a selective auto catalytic reduction system at the other Chalk
Point coal-fired unit. In addition, we installed selective
non-catalytic reduction systems at the three Dickerson
coal-fired units. These controls are capable of reducing
emissions of
SO2,
NOx
and mercury by approximately 98%, 90% and 80%, respectively, for
three of our largest coal-fired units in Maryland.
We reviewed our Chalk Point, Dickerson, Morgantown and Potomac
River generating facilities for impairment as a result of our
annual assessment of the goodwill recorded at GenOn Mid-Atlantic
on its standalone balance sheet, which is eliminated upon
consolidation at GenOn North America. Upon completion of the
assessment, we determined that none of the GenOn Mid-Atlantic
generating facilities was impaired at October 31, 2010.
In December 2010, PJM published an updated load forecast, which
depicted a decrease in the expected demand from prior
projections because of lower economic growth expectations. As a
result of the load forecast, our current expectation is that
there will be a decrease in the clearing prices for future
capacity auctions in certain years. The decrease in projected
capacity revenue caused us to update our October 2010 impairment
review of GenOn Mid-Atlantics long-lived assets. Upon
completion of our assessment, which was based on the accounting
guidance related to the impairment of long-lived assets, we
determined that the Dickerson and Potomac River generating
facilities were impaired at December 31, 2010, as the
carrying value exceeded the updated December 2010 undiscounted
cash flows. GenOn Americas Generation recorded fourth quarter
impairment losses of $523 million and $42 million on
the consolidated statement of operations to reduce the carrying
values of the Dickerson and Potomac River generating facilities,
respectively, to their estimated fair values. GenOn Mid-Atlantic
recorded fourth quarter impairment losses of $497 million
and $40 million on the consolidated statement of operations
to reduce the carrying values of the Dickerson and Potomac River
generating facilities, respectively, to their estimated fair
values. In addition, as a result of the full impairment of the
Potomac River generating facility, we recorded $32 million
in operations and maintenance expense and corresponding
liabilities associated with our commitment to reduce particulate
emissions at our Potomac River generating facility as part of
the agreement with the City of Alexandria,
4
Virginia. The planned capital investment would not be recovered
in future periods based on the current projected cash flows of
the Potomac River generating facility. We also have
$32 million included in funds on deposit and other
noncurrent assets in the consolidated balance sheets, which
represents the remaining balance placed in escrow as a result of
the agreement with the City of Alexandria. See note 3(d) to
our consolidated financial statements for further information
related to our GenOn Mid-Atlantic impairment analyses.
Northeast
Segment (GenOn Americas Generation)
We own four generating facilities in the Northeast segment with
total net generating capacity of 2,535 MW. Our Northeast
segment had a combined 2010 net capacity factor of 9%. The
following table presents the details of our Northeast generating
facilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
Generating
|
|
|
|
Primary
|
|
|
|
|
|
|
|
|
Capacity
|
|
|
|
Fuel
|
|
|
|
|
|
NERC
|
Facility
|
|
(MW)(1)
|
|
Holding
|
|
Type
|
|
Dispatch Type
|
|
Location
|
|
Region
|
|
Bowline
|
|
1,139
|
|
Own
|
|
Dual
|
|
Intermediate
|
|
New York
|
|
NPCC
|
Canal
|
|
1,126
|
|
Own
|
|
Dual/Oil
|
|
Intermediate
|
|
Massachusetts
|
|
NPCC
|
Kendall
|
|
256
|
|
Own
|
|
Natural
Gas/Oil/Dual
|
|
Baseload/
Peaking
|
|
Massachusetts
|
|
NPCC
|
Marthas Vineyard
|
|
14
|
|
Own
|
|
Oil
|
|
Peaking
|
|
Massachusetts
|
|
NPCC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Northeast
|
|
2,535
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Total MW amounts reflect net summer capacity. |
During the second quarter of 2010, the NYISO issued its annual
peak load and energy forecast in its Load and Capacity Data
report (the Gold Book). The Gold Book reports projected
electricity supply and demand for the New York control area for
the next ten years. The most recent Gold Book projects a
significant decrease in future electricity demand as a result of
current economic conditions and the expected future effects of
demand-side management programs in New York. The expected
reduction in future demand as a result of demand-side management
programs is being driven primarily by an energy efficiency
program being instituted within the State of New York that will
seek to achieve a 15% reduction from 2007 energy volumes by
2015. As a result of the projections in the Gold Book, we
evaluated the Bowline generating facility for impairment in the
second quarter of 2010. The sum of the probability weighted
undiscounted cash flows for the Bowline generating facility
exceeded the carrying value. As a result, we did not record an
impairment loss for the Bowline generating facility during the
second quarter of 2010.
GenOn Bowline has challenged its property tax assessment for the
2009 and 2010 tax years. Although the assessment for the 2010
tax year was reduced significantly from the assessment received
in 2009, the assessment continues to exceed significantly the
estimated fair value of the generating facility.
In the fourth quarter of 2010, we identified certain operational
issues that reduced the available capacity of the Bowline
generating facility. We are in the process of evaluating
long-term solutions for the generating facility, but our current
expectation is that the reduction in available capacity could
extend through 2012. In the fourth quarter of 2010, we again
evaluated the Bowline generating facility for impairment because
of the expected extended reduction in available capacity
together with the pending property tax litigation and the effect
of supply and demand assumptions in the NYISOs Gold Book.
The sum of the probability weighted undiscounted cash flows for
the Bowline generating facility exceeded the carrying value. As
a result, we did not record an impairment loss for the Bowline
generating facility during 2010. See note 3(d) to our
consolidated financial statements for further information
related to our impairment analysis of the Bowline generating
facility.
ISO-NE previously had determined that, at times, it was
necessary for the Canal generating facility to operate to meet
local reliability criteria for SEMA when it is not economic for
the Canal generating facility to operate based upon prevailing
market prices. When the Canal generating facility operates to
meet local
5
reliability criteria, we are compensated at the price we bid
into the ISO-NE, pursuant to ISO-NE market rules, rather than at
the market price.
During 2009, NSTAR Electric Company completed planned upgrades
to the SEMA transmission system. These upgrades have reduced the
need for the Canal generating facility to operate and caused a
reduction in energy gross margin compared to historical levels.
The final phase of these transmission upgrades was completed in
the third quarter of 2009 and as a result, the capacity factor
for the Canal generating facility dropped as compared to 2008.
With the completion of the transmission upgrades and because of
the Canal generating facilitys high fuel costs relative to
other generation in the northeast market, we expect that the
future revenues of the Canal generating facility will be
principally capacity revenue from the ISO-NE forward capacity
market.
The Kendall generating facility, which is a cogeneration
facility, has long-term agreements under which it sells steam.
Pursuant to a consent decree, we discontinued operation of units
4 and 5 at our Lovett generating facility in New York in May
2007 and April 2008, respectively. In addition, we discontinued
operation of unit 3 at the Lovett generating facility in May
2007 because it was uneconomic to operate the unit. We completed
the demolition of the Lovett generating facility in 2009.
California
Segment (GenOn Americas Generation)
We own three generating facilities in northern California with
total net generating capacity of 2,347 MW. Our California
segment generating facilities had a combined 2010 net
capacity factor of 3%. The following table presents the details
of our California generating facilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Generating
|
|
|
|
|
Primary
|
|
|
|
|
|
|
|
|
Capacity
|
|
|
|
|
Fuel
|
|
|
|
|
|
NERC
|
Facility
|
|
(MW)(1)
|
|
|
Holding
|
|
Type
|
|
Dispatch Type
|
|
Location
|
|
Region
|
|
Contra Costa
|
|
|
674
|
|
|
Own
|
|
Natural gas
|
|
Intermediate
|
|
California
|
|
WECC
|
Pittsburg
|
|
|
1,311
|
|
|
Own
|
|
Natural gas
|
|
Intermediate
|
|
California
|
|
WECC
|
Potrero(2)
|
|
|
362
|
|
|
Own
|
|
Natural gas/Oil
|
|
Intermediate/
Peaking
|
|
California
|
|
WECC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total California
|
|
|
1,985
|
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Total MW amounts reflect net summer capacity. |
|
(2) |
|
We shut down the Potrero facility on February 28, 2011. The
total net generating capacity for the California segment per the
table excludes the Potrero. See below for further discussion. |
In the third quarter of 2009, GenOn Potrero executed a
settlement agreement with the City and County of
San Francisco in which it agreed to shut down the Potrero
generating facility when it is no longer needed for reliability,
as determined by the CAISO. That settlement agreement became
effective in November 2009. In December 2010, the CAISO provided
GenOn Potrero with the requisite notice of termination of the
RMR agreement. On January 19, 2011, at the request of GenOn
Potrero, the FERC approved changes to GenOn Potreros RMR
agreement to allow the CAISO to terminate the RMR agreement
effective February 28, 2011. On February 28, 2011, the
Potrero facility was shut down.
Our existing generating facilities in northern California depend
almost entirely on payments they receive to operate in support
of system reliability. The energy, capacity and ancillary
services markets, as currently constituted, will not support the
capital expenditures necessary to repower or reconstruct our
facilities. In order to obtain the necessary capital support for
repowering or reconstructing our facilities, we would need to
obtain contracts with creditworthy buyers. Absent that, our
existing generating facilities in northern California will be
commercially viable only as long as they have contracts for
their capacity.
6
Energy
Marketing Segment (GenOn Americas Generation)
Our Energy Marketing segment includes our proprietary trading
and fuel oil management activities. This activity includes the
purchase and sale of electricity, fuel and emissions allowances,
sometimes through financial derivatives.
Using our fundamental understanding of the markets in which we
operate, we support our commercial asset management activities
as well as engage in proprietary trading when we identify
opportunities. We engage in fuel oil management activities to
hedge economically the fair value of our physical fuel oil
inventories, optimize the approximately three million barrels of
storage capacity that we own or lease, as well as attempt to
profit from market opportunities related to timing
and/or
differences in the pricing of various products.
Proprietary trading and fuel oil management activities together
will typically comprise less than 10% of our realized gross
margin. All of our commercial activities are governed by a
comprehensive risk management policy, which includes limits on
the size of volumetric positions and VaR for our proprietary
trading and fuel oil management activities. For 2010, our
combined average daily VaR for proprietary trading and fuel oil
management activities was $2 million.
Asset
Management
We provide energy, capacity, ancillary and other energy services
to wholesale customers in competitive energy markets in the
United States, including ISOs and RTOs, power aggregators,
retail providers, electric-cooperative utilities, other power
generating companies and load serving entities. Our commercial
operations consist primarily of dispatching electricity, hedging
the generation and sale of electricity, selling capacity,
procuring and managing fuel and providing logistical support for
the operation of our facilities (for example, by procuring
transportation for coal and natural gas).
Our strategy is to enter into economic hedgesforward sales
of electricity and forward purchases of fuel and emissions
allowancesto manage the risks associated with volatility
in prices for electricity, fuel and emissions allowances and to
achieve more predictable financial results. In addition, given
the high correlation between natural gas prices and electricity
prices in many of the markets in which we operate, we enter into
forward sales of natural gas to hedge economically our exposure
to changes in the price of electricity. We procure our hedges in
OTC transactions or on exchanges where electricity, fuel and
emissions allowances are broadly traded, or through specific
transactions with buyers and sellers, using futures, forwards,
swaps and options. Our hedges cover various periods, including
several years. See Managements Discussion and
Analysis of Financial Condition and Results of Operations
in Item 7 of this
Form 10-K
for our aggregate hedge levels based on expected generation for
2011 to 2015. In addition, see Item 1A, Risk
FactorsRisks Related to Economic and Financial Market
ConditionsGreater regulation of energy contracts for
a discussion of the risks of implementation of the Dodd-Frank
Act on our ability to hedge economically our generation,
including potentially reducing liquidity in the energy and
commodity markets and, if we are required to clear such
transactions on exchanges or meet other requirements, by
significantly increasing the collateral costs associated with
such activities.
We sell capacity either bilaterally or through periodic auction
processes in each ISO and RTO market in which we participate.
GenOn Americas Generations capacity sales primarily occur
through the PJM RPM and ISO-NE FCM auctions, but also in CAISO,
NYISO and other markets where we enter into agreements with
counterparties. GenOn Mid-Atlantics capacity sales occur
through the PJM RPM auctions. We expect that a substantial
portion of our PJM capacity will continue to be sold in PJM up
to three years in advance. Revenue from these capacity sales is
determined by market rules designed to ensure regional
reliability, encourage competition and reduce energy price
volatility. These capacity sales provide an important source of
predictable revenues for us over the contracted periods. At
January 31, 2011, GenOn Americas Generations total
projected contracted capacity and PPA revenues for which prices
have been set for 2011 through 2014 are $1.3 billion. At
January 31, 2011, GenOn Mid-Atlantics total projected
contracted capacity revenues for which prices have been set for
2011 through 2014 are $881 million.
7
Power
We hedge economically a substantial portion of our Eastern PJM
coal-fired baseload generation and certain of our other
generation. We generally do not hedge our intermediate and
peaking units for tenors greater than 12 months. A
significant portion of our hedges are financial swap
transactions between GenOn Mid-Atlantic and financial
counterparties that are senior unsecured obligations of such
parties and do not require either party to post cash collateral
either for initial margin or for securing exposure as a result
of changes in power or natural gas prices.
Although standard industry OTC transactions make up a
substantial portion of our economic hedge portfolio, at times we
sell non-standard, structured products to customers.
GenOn Americas Generations California generating
facilities operate under contracts for their capacity or energy.
GenOn Delta has entered into agreements with PG&E to
provide electricity from our natural gas-fired units in service
at Contra Costa and Pittsburg. With respect to Contra Costa
units 6 and 7, GenOn Delta is providing 674 MW of capacity
to PG&E for 2011 under a multi-year tolling agreement into
which we entered in 2006. GenOn Delta entered into a new
agreement with PG&E on September 2, 2009 for the
674 MW at Contra Costa units 6 and 7 for the period from
November 2011 through April 2013. At the end of the agreement,
and subject to any necessary regulatory approval, GenOn Delta
has agreed to retire Contra Costa units 6 and 7, which began
operations in 1964, in furtherance of state and federal policies
to retire aging power plants that utilize once-through cooling
technology. In addition, GenOn Delta entered into an agreement
with PG&E on October 28, 2010 for 1,159 MW of
capacity from Pittsburg units 5, 6 and 7 for three years
commencing January 1, 2011, with options for PG&E to
extend the agreement for each of 2014 and 2015. Under the
respective agreements, GenOn Delta will receive monthly capacity
payments with bonuses
and/or
penalties based on heat rate and availability.
Fuel
We enter into contracts of varying terms to secure appropriate
quantities of fuel that meet the varying specifications of our
generating facilities. For our coal-fired generating facilities,
we purchase most of our coal from a small number of suppliers
under contracts with terms of varying lengths, some of which
extend to 2013. See Quantitative and Qualitative
Disclosures About Market Risk in Item 7A of this
Form 10-K
for discussion of our coal agreement risk. For our oil-fired
units, we typically purchase fuel from a small number of
suppliers either in the spot market or under contracts with
terms of varying lengths. For our natural gas-fired facilities,
in addition to purchasing natural gas, we arrange for and
schedule its transportation through pipelines. We sell excess
fuel supplies to third parties.
We receive coal at our generating facilities primarily by rail.
In addition, we can receive coal by barge at our Morgantown
generating facility, which completed construction of a barge
unloader in 2008 that enables us to receive coal from domestic
and international sources. We have a coal blending facility at
our Morgantown generating facility that allows for greater
flexibility of coal supply by allowing various coal qualities to
be blended while also meeting emissions targets. We monitor coal
supply and delivery logistics carefully and, despite occasional
interruptions of planned deliveries, to date we have managed to
avoid any significant detrimental effects on our operations.
Because of the risk of disruptions in our coal supply, we strive
to maintain adequate targeted levels of coal inventories at our
coal-fired facilities. Interruptions to planned or contracted
deliveries can result from a variety of factors, including
operational issues of coal suppliers, lack of, or constraints
in, coal transportation (including rail system and river system
disruptions) and adverse weather conditions.
Emissions
Our commercial operations manage the acquisition and use of
emissions allowances for our generating facilities. Our
generating facilities in Maryland and GenOn Americas
Generations generating facilities in Massachusetts and New
York are subject to the RGGI, a multi-state
cap-and-trade
program to reduce
CO2
emissions from units of 25 MW or greater. The RGGI became
effective on January 1, 2009. To comply, we are required to
purchase allowances, either through periodic auctions or open
market transactions, to offset our
8
CO2
emissions. In 2010 and 2009, GenOn Americas Generation
recognized approximately $34 million and $45 million,
respectively, in cost of fuel, electricity and other products as
a result of its compliance with the RGGI and GenOn Mid-Atlantic
recognized approximately $32 million and $41 million,
respectively, in cost of fuel, electricity and other products as
a result of its compliance with the RGGI.
In May 2010, the Montgomery County Council imposed a levy on
major emitters of
CO2
in Montgomery County, Maryland which we estimate will impose on
the Dickerson generating facility of GenOn Mid-Atlantic an
additional $10 million to $15 million per year in
levies owed to Montgomery County. During 2010, we recognized
$8 million in levies in operations and maintenance expense.
See note 9 to our consolidated financial statements for
further discussion of the action filed against Montgomery County
in the United States District Court for the District of Maryland
by GenOn Mid-Atlantic.
Coal
Combustion Byproducts
Existing state and federal rules require the proper management
and disposal of wastes and other materials. We produce
byproducts from our coal-fired generating units, including ash
and gypsum. We actively manage the current and planned
disposition of each of these byproducts. All of our ash disposal
facilities are dry landfills. Our disposal plan for ash includes
land filling at our existing ash management facilities,
purchasing and permitting additional disposal sites, using third
parties to handle and dispose of the ash, and constructing an
ash beneficiation facility at our Morgantown site to make the
ash more suitable for sale to third parties for the production
of concrete as well as other beneficial uses. We commenced
construction of the ash beneficiation facility in February 2011
and expect to complete it in 2012. Our disposal plan for gypsum
includes disposing of it in approved landfills and selling it to
third parties for use in the production of drywall. Currently,
we expect to spend approximately $100 million over the next
five years for ash landfill expansions, closures and for
building an ash beneficiation facility.
There is increased focus on the regulation of coal combustion
products and, if the manner in which they are regulated changes,
we may be required to change our management practices for these
byproducts
and/or incur
additional costs.
Competitive
Environment
The power generating industry is capital intensive and highly
competitive. Our competitors include regulated utilities,
merchant energy companies, financial institutions and other
companies. For a discussion of competitive factors see
Item 1A, Risk Factors. Coal-fired, natural
gas-fired, nuclear and hydroelectric generation currently
account for approximately 45%, 24%, 20% and 6%, respectively, of
the electricity produced in the United States. Other energy
sources account for the remaining 5% of electricity produced.
Wholesale power generation is highly fragmented compared to
other commodity industries. There is wide variation in terms of
the capabilities, resources, nature and identity of the
companies with which we compete. Our competitive advantages
include the following:
|
|
|
|
|
Reliability of our future cash flows. Our
large coal generating fleet is exposed to the relationship
between the cost of production and the price of the power
produced. This relationship, commonly referred to as the
dark spread, fluctuates with the cost of coal and
the price of power. We hedge economically a substantial portion
of our Eastern PJM coal-fired baseload generation and certain of
our other generation. We hedge our output at varying levels
several years in advance because the price of electricity is
volatile. In addition, we enter into contracts to hedge
economically our future needs of coal, which is our primary fuel.
|
|
|
|
Locational advantages. Many of GenOn Americas
Generations generating facilities are located in or near
metropolitan areas, including Boston, New York City,
San Francisco and Washington, D.C. GenOn
Mid-Atlantics generating facilities are located near
Washington, D.C. The supply-demand balance in some of these
markets is forecasted to become constrained, though at a slower
rate than forecasted before the economic downturn, and
increasingly dependent on power imported from other regions to
|
9
|
|
|
|
|
sustain reliability. Although transmission projects are planned
in these markets to bring capacity from neighboring regions, the
timing of these projects is subject to delays and uncertainty.
|
|
|
|
|
|
Room to expand at our existing sites. We have
sufficient room and infrastructure at many of our existing sites
to increase significantly our generating capacity when market
rules and conditions warrant. In addition to reduced costs for
developing new generation at existing sites because of our
ownership of the land and our ownership of
and/or
access to infrastructure, regulators frequently prefer that new
generation be added at existing sites (brownfield development)
rather than at new sites (greenfield development). We continue
to consider these and other investment opportunities.
|
Given the substantial time required to permit and construct new
power plants, the process to add generating capacity must begin
years in advance of anticipated growth in demand. A number of
ISOs and RTOs, including those in markets in which we operate,
have implemented capacity markets as a way to encourage
construction of additional generation when market conditions
warrant. Over the last several years, very little new generation
has been constructed as a result of the economic downturn in
recent years and programs to reduce the demand for electricity
which have resulted in a decrease in the rate at which the
long-term demand for electricity is forecasted to grow. Also,
the costs to construct new generating facilities have been
rising, and there is substantial environmental opposition to
building either coal-fired or nuclear plants.
In some markets, state regulators have proposed initiatives to
provide long-term contracts for new generating capacity. In
December 2010, the Maryland Public Service Commission sought
comments on a possible request for proposals for new generating
facilities. The draft request for proposals would require any
such new generation to bid into the capacity markets in a manner
that would ensure clearing in the market. The draft request
provides for project submittals on July 29, 2011. We filed
comments on the draft request for proposals on January 28,
2011, noting there is no need for additional capacity at this
time. If the request for proposals is issued as currently
drafted, it could have a negative effect on capacity prices in
PJM in future years.
On January 28, 2011, New Jersey enacted legislation which
requires the Board of Public Utilities to implement a Long-Term
Capacity Agreement Pilot Program providing for new generating
capacity in the state. The new generating capacity would be
required to participate and be accepted as a capacity resource
in the PJM capacity market. If the New Jersey agreement for new
capacity is implemented as required by the statute, it could
have a negative effect on capacity prices in PJM in future
years. On February 1, 2011, a group of which we are a
member initiated a proceeding at the FERC seeking changes in the
PJM tariff to prevent interference with the capacity markets
from efforts such as the New Jersey legislation and the Maryland
request for proposals. On February 9, 2011, we joined a
group of companies that filed suit in the U.S. District
Court for New Jersey asking the court to declare the New Jersey
legislation unconstitutional.
In addition, as a result of initiatives at both the federal and
state level, new construction of renewable resources, including
solar and wind, has occurred or is planned.
There are proposed upgrades to the transmission systems in some
of the markets in which we operate that could mitigate the need
for existing marginal generating capacity and for additional
generating capacity. To the extent that these upgrades are
completed, prices for electricity and capacity could be lower in
some of our markets than they might otherwise be.
The prices for power and natural gas remain low compared to
several years ago. The energy gross margin from our generating
facilities is negatively affected by these price levels. For
that portion of the volumes of generation that we have hedged,
we are generally economically neutral to subsequent changes in
commodity prices because our realized gross margin will reflect
the contractual prices of our power and fuel contracts. We
continue to add economic hedges, including to maintain projected
levels of cash flows from operations for future periods to help
support continued compliance with the covenants in GenOn
Mid-Atlantics operating lease agreements. We have
implemented seasonal operating models at some of our facilities
to address the effect of depressed power and commodity prices on
the margins earned at these facilities.
Concern over climate change and air emissions have led to
significant legislative and regulatory efforts at the state and
federal level. The costs of compliance with such efforts could
affect our ability to compete in the
10
markets in which we operate, especially with our coal-fired
generating facilities. See Environmental
Regulation later in the section for further discussion.
Seasonality
For information on the effect of seasonality on our business,
see Risk Factors in Item 1A of this
Form 10-K.
Regulatory
Environment
The electricity industry is regulated extensively at the
federal, state and local levels. At the federal level, the FERC
has exclusive jurisdiction under the Federal Power Act over
sales of electricity at wholesale and the transmission of
electricity in interstate commerce. Each of our subsidiaries
that owns or leases a generating facility selling at wholesale
or that markets electricity at wholesale is a public
utility subject to the FERCs jurisdiction under the
Federal Power Act. These subsidiaries must comply with certain
FERC reporting requirements and FERC-approved market rules and
they are subject to FERC oversight of mergers and acquisitions,
the disposition of facilities under the FERCs jurisdiction
and the issuance of securities.
The FERC has authorized our subsidiaries that are public
utilities under the Federal Power Act to sell wholesale energy,
capacity and certain ancillary services at market-based rates.
The majority of the output of the generating facilities owned by
our subsidiaries is sold pursuant to this market-based rate
authorization, although the GenOn Americas Generations
Potrero station sold its output under a cost-based RMR agreement
through February 2011 for which separate rate authorization was
granted by the FERC. The FERC could revoke or limit our
market-based rate authority if it determined that we possess
insufficiently mitigated market power in a regional electricity
market. Under the Natural Gas Act, GenOn Americas
Generations subsidiary, GenOn Energy Management, that
sells natural gas for resale is deemed by the FERC to have
blanket certificate authority to undertake these sales at
market-based rates.
The FERC requires that our public utility subsidiaries with
market-based rate authority and our subsidiary with blanket
certificate authority adhere to general rules against market
manipulation as well as certain market behavior rules and codes
of conduct. If any of our subsidiaries were found to have
engaged in market manipulation, the FERC has the authority to
impose a civil penalty of up to $1 million per day per
violation. In addition to the civil penalties, if any of our
subsidiaries were to engage in market manipulation or violate
the market behavior rules or codes of conduct, the FERC could
require a disgorgement of profits or revoke the
subsidiarys market-based rate authority or blanket
certificate authority. If the FERC were to revoke market-based
rate authority, our affected public utility subsidiary would
have to file a cost-based rate schedule for all or some of its
sales of electricity at wholesale.
In 2006, the FERC certified the NERC as the national energy
reliability organization. The NERC is now responsible for the
development and enforcement of mandatory reliability standards
for the electric power system. Each of our subsidiaries selling
electricity at wholesale is responsible for complying with the
reliability standards in the region in which it operates. The
NERC has the ability to assess financial penalties for
non-compliance with the reliability standards, which penalties
can, depending on the nature of the non-compliance, be
significant. In addition to complying with the NERC standards,
each of our entities selling electricity at wholesale must
comply with the reliability standards of the regional
reliability council for the NERC region in which its sales occur.
The vast majority of our facilities operate in markets
administered by ISOs and RTOs. In areas where ISOs or RTOs
control the regional transmission systems, market participants
have access to broader geographic markets than in regions
without ISOs and RTOs. ISOs and RTOs operate day-ahead and
real-time energy and ancillary services markets, typically
governed by FERC-approved tariffs and market rules. Some ISOs
and RTOs also operate capacity markets. Changes to the
applicable tariffs and market rules may be requested by the ISO
or RTO, or by other interested persons, including market
participants and state regulatory agencies, and such proposed
changes, if approved by the FERC, could have a significant
effect on our operations and financial results. Although
participation in ISOs and RTOs by public utilities that own
transmission has been,
11
and is expected to continue to be, voluntary, the majority of
such public utilities in California, Maryland, Massachusetts,
New York, and Virginia have joined the applicable ISO and RTO.
Our subsidiaries owning generating facilities have made such
filings, and received such orders, as are necessary to obtain
exempt wholesale generator status under the PUHCA and the
FERCs regulations thereunder. Provided all of our
subsidiaries owning or leasing generating facilities continue to
be exempt wholesale generators, or are qualifying facilities
under the Public Utility Regulatory Policies Act of 1978, we and
our intermediate holding companies owning direct or indirect
interests in those subsidiaries will remain exempt from the
accounting, record retention or reporting requirements that
PUHCA imposes on holding companies.
State and local regulatory authorities historically have
overseen the distribution and sale of electricity at retail to
the ultimate end user, as well as the siting, permitting and
construction of generating and transmission facilities. Our
existing generating facilities are subject to a variety of state
and local regulations, including regulations regarding the
environment, health and safety and maintenance and expansion of
the facilities.
We hedge economically a substantial portion of our Eastern PJM
coal-fired baseload generation and certain of our other
generation. A significant portion of such hedges are financial
swap transactions between GenOn Mid-Atlantic and financial
counterparties that are senior unsecured obligations of such
parties and do not require either party to post cash collateral
either for initial margin or for securing exposure as a result
of changes in power or natural gas prices. The Dodd-Frank Act,
which was enacted in July 2010 in response to the global
financial crisis, increases the regulation of transactions
involving OTC derivative financial instruments. The statute
provides that standardized swap transactions between dealers and
large market participants will have to be cleared and traded on
an exchange or electronic platform. Although the provisions and
legislative history of the Dodd-Frank Act provide strong
evidence that market participants, such as GenOn Americas
Generation and GenOn Mid-Atlantic, which utilize OTC derivative
financial instruments to hedge economically commercial risks are
not to be subject to these clearing and exchange-trading
requirements, it is uncertain what the final implementing
regulations to be issued by the CFTC and SEC will provide. The
effect of the Dodd-Frank Act on our business depends in large
measure on pending CFTC and SEC rulemaking proceedings and, in
particular, the final definitions for the key terms Swap
Dealer and Major Swap Participant in the
Dodd-Frank Act. The CFTC and SEC issued a proposed rulemaking to
set final definitions for the terms Swap Dealer and
Major Swap Participant, among others. Entities
defined as Swap Dealers and Major Swap Participants will face
costly requirements for clearing and posting margin, as well as
additional requirements for reporting and business conduct. As
proposed, the Swap Dealer definition in particular is ambiguous,
subjective and could be broad enough to encompass some energy
companies. Such regulations could materially affect our ability
to hedge economically our generation by reducing liquidity in
the energy and commodity markets and, if we were required to
clear such transactions on exchanges or meet other requirements,
by significantly increasing the collateral costs associated with
such activities. See Item 1A, Risk FactorsRisks
Related to Economic and Financial Market ConditionsGreater
regulation of energy contracts for additional information.
Under the Dodd-Frank Act, the CFTC now has the authority to set
position limits not only on contracts listed by designated
contract markets but also for swap contracts that perform or
affect a significant price discovery function. As a result of
the significant amendments to the Commodity Exchange Act by the
Dodd-Frank Act, the CFTC withdrew, in August 2010, the January
2010 notice of proposed rulemaking in which it proposed to adopt
all-months-combined, single (non-spot) month and spot-month
position limits for exchange-listed natural gas, crude oil,
heating oil and gasoline futures and options contracts. The CFTC
plans to issue a notice of rulemaking proposing position limits
for regulated exempt commodity contracts, including energy
commodity contracts, in early 2011.
In addition to the upcoming position limit rulemakings under the
Dodd-Frank Act, the CFTC has designated and put into effect
position limits for certain electricity and natural gas
contracts designated as significant price discovery contracts,
including contracts based on CAISO and PJM West Hub locational
marginal pricing that GenOn Americas Generation trades on the
Intercontinental Exchange, Inc. Designations
12
put into effect to date have not had a material effect on our
business. We continue to monitor the rulemaking proceeding on
the remaining contracts.
PJM Region. Our Eastern PJM generating
facilities sell electricity into the markets operated by PJM. We
have access to the PJM transmission system pursuant to
PJMs Open Access Transmission Tariff. PJM operates the PJM
Interchange Energy Market, which is the regions spot
market for wholesale electricity, provides ancillary services
for its transmission customers, performs transmission planning
for the region and economically dispatches generating
facilities. PJM administers day-ahead and real-time single
clearing price markets and calculates electricity prices based
on a locational marginal pricing model. A locational marginal
pricing model determines a price for energy at each node in a
particular zone taking into account the limitations and losses
on transmission of electricity into the zone, resulting in a
higher zonal price when less expensive energy cannot be imported
from another zone. Generation owners in PJM are subject to
mitigation, which limits the prices that they may receive under
certain specified conditions.
Load-serving entities within PJM are required to have adequate
sources of generating capacity. Our generating facilities
located in the Eastern PJM region that sell electricity into the
PJM market participate in the RPM forward capacity market. The
PJM RPM capacity auctions are designed to provide forward prices
for capacity that ensure that adequate resources are in place to
meet the regions demand requirements. PJM has conducted
seven RPM capacity auctions and we began receiving payments in
June 2007 as a result of the first auction. Certain market
participants have challenged the results of the RPM auctions
that set capacity payments under the RPM provisions of
PJMs tariff for the twelve month periods beginning
June 1, 2008, June 1, 2009 and June 1, 2010. The
FERC rejected those challenges and its orders were affirmed by
the D.C. Circuit. See Complaint Challenging Capacity
Rates Under the RPM Provisions of PJMs Tariff in
note 9 to our consolidated financial statements for a
discussion of the challenges.
Since 2008, annual auctions have been conducted to procure
capacity three years prior to each delivery period. The first
annual auction took place in May 2008, for the provision of
capacity from June 1, 2011 to May 31, 2012. PJM
continues to revise elements of the RPM provisions of its
tariff, both pursuant to those provisions and on its own
volition or at the request of its stakeholders. These revisions
must be filed with and approved by the FERC, and we, either
individually or as part of a group, are actively involved at the
FERC to protect our interests. See Competitive
Environment for our involvement at the FERC.
Northeast Region (GenOn Americas
Generation). Our Bowline generating facility
participates in a market administered by the NYISO. The NYISO
provides statewide transmission service under a single tariff
and interfaces with neighboring market control areas. To account
for transmission congestion and losses, the NYISO calculates
energy prices using a locational marginal pricing model. The
NYISO also administers a spot market for energy, as well as
markets for installed capacity and services that are ancillary
to transmission service. The NYISOs locational capacity
market utilizes a demand curve mechanism to determine monthly
capacity prices to be paid to suppliers for three capacity
zones: New York City, Long Island and Rest of State. Our
facility is located in the Rest of State capacity zone.
Our Canal, Kendall and Marthas Vineyard generating
facilities participate in a market administered by ISO-NE. GenOn
Energy Management is a member of the New England Power Pool,
which is a voluntary association of electric utilities and other
market participants in Connecticut, Maine, Massachusetts,
New Hampshire, Rhode Island and Vermont, and which
functions as an advisory organization to ISO-NE. As the RTO for
the New England region, ISO-NE is responsible for the operation
of transmission systems and for the administration and
settlement of the wholesale electric energy, capacity and
ancillary services markets. ISO-NE utilizes a locational
marginal pricing model similar to the model used in PJM and
NYISO.
On March 6, 2006, a settlement proposal was filed with the
FERC among ISO-NE and multiple market participants for the FCM
under which annual capacity auctions would be conducted for
supply three years in advance of provision. The settlement
provided for a four-year transition period during which capacity
suppliers receive a set price for their capacity commencing on
December 1, 2006, with price escalators through
May 31, 2010. Beginning December 1, 2006, our
generating facilities began receiving capacity revenues under
the FCM transition period. On June 1, 2010, our generating
facilities began receiving capacity revenues based upon the
auction results.
13
California (GenOn Americas Generation). Our
California generating facilities are located inside the
CAISOs control area. On April 1, 2009, the CAISO
implemented its Market Redesign and Technology Update (MRTU).
MRTUs key components include locational marginal pricing
of energy similar to the RTO/ISO markets in the east, a
day-ahead market in addition to the existing real-time market, a
more effective congestion management system and an increase in
the existing bid caps. The CAISO also schedules transmission
transactions and arranges for necessary ancillary services. Most
sales in California are pursuant to bilateral contracts, but a
significant percentage of electrical energy is sold in the
day-ahead and real-time market. The CAISO does not operate a
wholesale capacity market.
Environmental
Regulation
Our business is subject to extensive environmental regulation by
federal, state and local authorities. We must comply with
applicable laws and regulations, and obtain and comply with the
terms of government issued permits. These requirements relate to
a broad range of our activities, including the discharge of
materials into the air, water and soil; the proper handling of
solid, hazardous and toxic materials and waste; noise and safety
and health standards applicable to the workplace. Some of these
requirements are under revision or in dispute, and some new
requirements are pending or under consideration. Our costs of
complying with environmental laws and permits are substantial,
including significant environmental capital expenditures. See
Item 7, Managements Discussion and Analysis of
Financial Condition and Results of OperationsCapital
Expenditures and Capital Resources for additional
information.
Air
Emissions Regulations
The Clean Air Act and similar state laws impose significant
environmental requirements on our generating facilities. The
Clean Air Act mandates a broad range of requirements concerning
air quality, air emissions, operating practices and pollution
control equipment. Under the Clean Air Act, the EPA sets NAAQS
for pollutants thought to be harmful to public health and the
environment, including
SO2,
NOx
ozone, and fine particulate matter (PM2.5). Most of our
facilities are located in or near areas that are classified by
the EPA as not achieving certain NAAQS (non-attainment areas).
The relevant NAAQS have become more stringent and we expect that
trend to continue. As a result of such classification and the
manner in which regulators seek to achieve the NAAQS, our
operations generally are subject to more stringent air pollution
requirements than those applicable to facilities located
elsewhere. The states are generally free to impose requirements
that are more stringent than those imposed by the federal
government. We expect increased regulation at both the federal
and state levels of our air emissions. We maintain a
comprehensive compliance strategy to address these continuing
and new requirements. Complying with increasingly stringent
NAAQS may require us to install and operate additional emissions
control equipment at some of our facilities if we decide to
continue to operate such facilities. Such costs could be
material. Significant air regulatory programs to which we are
subject are described below.
Clean Air Interstate Rule. In 2005, the EPA
promulgated the CAIR, which established in the eastern United
States
SO2
and
NOx
cap-and-trade
programs applicable directly to states and indirectly to
generating facilities. The
NOx
cap-and-trade
program has two components, an annual program and an Ozone
Season program. The CAIR
SO2
cap-and-trade
program builds off the existing acid rain
cap-and-trade
program but requires generating facilities to surrender twice as
many allowances to cover emissions from 2010 through 2014 and
approximately three times as many allowances starting in 2015.
Maryland, New York and Virginia are subject to the CAIRs
SO2
trading program and both its
NOx
trading programs. Massachusetts is subject only to the
CAIRs Ozone Season
NOx
trading program. These
cap-and-trade
programs were to be implemented in two phases, with the first
phase going into effect in 2009 for
NOx
and 2010 for
SO2
and more stringent caps going into effect in 2015. Various
parties challenged the EPAs adoption of the CAIR, and on
July 11, 2008, the D.C. Circuit in State of North
Carolina v. Environmental Protection Agency issued an
opinion that would have vacated the CAIR. Various parties filed
requests for rehearing with the D.C. Circuit and on
December 23, 2008, the D.C. Circuit issued a second opinion
in which it granted rehearing only to the extent that it
remanded the case to the EPA without vacating the CAIR.
Accordingly, the CAIR will remain effective until it is replaced
by a rule consistent with the D.C. Circuits opinions. The
states in which GenOn Americas Generation operates that are
subject to CAIR (i.e., Maryland, Massachusetts, New York and
14
Virginia) and two states in which GenOn Mid-Atlantic operates
that are subject to CAIR (i.e., Maryland and Virginia) have
promulgated regulations implementing the federal CAIR.
The EPA has stated that it expects to finalize the regulations
to replace the CAIR in 2011, and on August 2, 2010, the EPA
proposed a rule (the Transport Rule) to replace the CAIR. The
EPA has sought comment on the proposed Transport Rule as well as
several alternatives. If finalized, the CAIR replacement
proposal and each of the alternatives would impose more
stringent emission reductions than were required under the CAIR.
The EPAs proposed replacement rule would establish an
emissions budget for each of thirty-one eastern and midwestern
states and the District of Columbia, and would allow only
limited interstate trading. For
SO2,
generating facilities in a region comprised of Georgia,
Illinois, Indiana, Iowa, Kentucky, Michigan, Missouri, New York,
North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West
Virginia and Wisconsin would be subject to a more stringent cap
on
SO2
emissions than the other states subject to the rule, and would
not be allowed to use emissions allowances from sources in a
separate region comprised of Alabama, Connecticut, Delaware, the
District of Columbia, Florida, Kansas, Louisiana, Maryland,
Massachusetts, Minnesota, Nebraska, New Jersey and South
Carolina. For both
SO2
and
NOx,
interstate trading of emissions allowances would be allowed only
to the extent that the total number of emissions allowances used
within a particular state did not exceed the states
budgeted allowances plus a variability limit
intended to account for the variability of emissions because of
changes in demand for electricity, timing of maintenance
activities and unit outages. If total emissions allowances used
within a state in a year exceed the annual budget plus the
variability limit, then owners of generating facilities in that
state that are deemed responsible for the states
exceedance would be required to surrender additional allowances.
The two alternatives on which the EPA sought comment would
further restrict trading. Under the first alternative, only
intrastate trading of allowances would be allowed. The second
alternative would establish an emissions limit for each
generating facility, with some averaging allowed. In January
2011, the EPA also sought comment on two additional methods of
allocating allowances. Finally, the EPA has also stated that it
may issue a subsequent, more stringent rule if it concludes that
recent or planned revisions to the particulate matter and ozone
NAAQS make necessary more stringent limits on
SO2
and
NOx
emissions from electric generating facilities. We continue to
monitor developments related to the EPAs proposed options
to replace the existing CAIR.
The effect on our business of these pending regulations and
whether we elect to install additional controls is uncertain and
depends on the content and timing of the regulations, the
expected effect of the regulations on wholesale power prices and
allowance prices, as well as the cost of controls, profitability
of our generating facilities, market conditions at the time and
the likelihood of
CO2
regulation. We may choose to retire certain of our units rather
than install additional controls.
The costs associated with more stringent environmental air
quality requirements may result in coal-fired generating
facilities, including some of ours, being retired. Although
conditions may change, under current and forecasted market
conditions, installations of additional scrubbers would not be
economic at most of our unscrubbed coal-fired facilities. Any
such retirements could contribute to improving supply and demand
fundamentals for the remaining fleet. Any resulting increased
demand for gas could increase the spread between gas and coal
prices, which would also benefit the remaining coal-fired
generating facilities.
Maryland Healthy Air Act. The Maryland Healthy
Air Act was enacted in April 2006 and requires reductions in
SO2,
NOx
and mercury emissions from large coal-fired power facilities.
The state law also required Maryland to join the RGGI, which is
discussed below. The Maryland Healthy Air Act and the
regulations adopted by MDE to implement that act impose limits
for (a) emissions of
NOx
in 2009 with further reductions in 2012 (including sublimits
during the Ozone Season) and (b) emissions of
SO2
in 2010 with further reductions in 2013. The Maryland Healthy
Air Act also imposes restrictions on emissions of mercury
beginning in 2010 with further reductions in 2013. The Maryland
Healthy Air Act imposes fixed limits and owners of power
facilities may not exceed these fixed limits by purchasing
emissions allowances to comply.
We installed scrubbers at our Chalk Point, Dickerson and
Morgantown coal-fired units. In addition, we installed SCR
systems at the Morgantown coal-fired units and one of the Chalk
Point coal-fired units and a selective auto catalytic reduction
system at the other Chalk Point coal-fired unit. We also
installed selective
15
non-catalytic reduction systems at the three Dickerson
coal-fired units. These controls are capable of reducing
emissions of
SO2,
NOx
and mercury by approximately 98%, 90% and 80%, respectively, for
three of our largest coal-fired units. The control equipment we
have installed allows our Maryland generating facilities to
comply with (a) the first phase of the CAIR without having
to purchase emissions allowances and (b) all of the
requirements of the Maryland Healthy Air Act.
In 2009, we had planned outages to complete the installation of
the scrubbers. During those outages, we also performed
significant maintenance activities. We expect to invest
$1.674 billion in capital expenditures to comply with the
requirements for
SO2,
NOx
and mercury emissions under the Maryland Healthy Air Act. At
December 31, 2010, we had invested $1.519 billion of
the $1.674 billion. In July 2007, GenOn Mid-Atlantic and
its subsidiary, GenOn Chalk Point, entered into an agreement
with Stone & Webster, Inc. for EPC services relating
to the installation of the scrubbers described above. The cost
under the agreement was approximately $1.1 billion and is a
part of the $1.674 billion described above. See note 9
to our consolidated financial statements under Scrubber
Contract Litigation for further discussion.
HAPs Regulations. In 2005, the EPA issued the
CAMR, which would have limited total annual mercury emissions
from coal-fired power plants across the United States through a
two-phased
cap-and-trade
program. In February 2008, the D.C. Circuit vacated the CAMR and
the EPAs decision not to regulate coal- and oil-fired
electric utility steam generating units under section 112
of the Clean Air Act, which requires the EPA to develop MACT
standards for controlling emissions of all HAPs, including
mercury. The EPA and a group representing electricity generators
sought review of the D.C. Circuits decision by the United
States Supreme Court. In February 2009, the EPA filed to
withdraw its petition for review, stating that it intends to
promulgate alternative regulations for electricity generators
under section 112 of the Clean Air Act, and the United
States Supreme Court subsequently denied the petition for
review. As a result of the D.C. Circuit decision, coal-fired and
oil-fired generating facilities are now subject to regulation
under the section of the Clean Air Act that generally requires
the EPA to develop MACT standards to control HAPs, including
mercury, from each covered facility. Although the EPA has
announced that it will develop MACT standards for mercury and
other HAPs, it has not yet promulgated such standards. The MACT
standards may require us to install and operate additional
emissions control equipment at some of our facilities, the cost
of which may be material. The EPA has collected emissions data,
which will be used to develop such standards. Our Maryland
coal-fired units already are subject to mercury limits under the
Maryland Healthy Air Act, as described above. Many of our
coal-fired units will emit less mercury as a result of the
SO2
and
NOx
controls that have been installed.
New Source Review Enforcement Initiative. The
EPA and various states are investigating compliance of
coal-fired electric generating facilities with the
pre-construction permitting requirements of the Clean Air Act
known as new source review. In the past decade, the
EPA has made information requests for our Chalk Point,
Dickerson, Morgantown and Potomac River generating facilities.
We are corresponding or have corresponded with the EPA regarding
all of these requests. If a violation is determined to have
occurred at any of the facilities, our subsidiary owning or
leasing the facilities may be responsible for the cost of
purchasing and installing emissions control equipment, the cost
of which may be material. Several of our generating facilities
already have installed a variety of emissions control equipment.
If such a violation is determined to have occurred after our
subsidiaries acquired or leased the facilities or, if occurring
prior to the acquisition or lease, is determined to constitute a
continuing violation, our subsidiary owning or leasing the
facility at issue could also be subject to fines and penalties
by the state or federal government for the period after its
acquisition or lease of the facility, the cost of which may be
material, although applicable bankruptcy law may bar such
liability for the Chalk Point, Dickerson, Morgantown and Potomac
River generating facilities for periods prior to January 3,
2006, when the Plan became effective.
Regulation of Greenhouse Gases, including the
RGGI. Concern over climate change has led to
significant legislative and regulatory efforts at the state and
federal level to limit greenhouse gas emissions, especially
CO2.
One such effort is the RGGI, a multi-state initiative in the
Eastern PJM and Northeast outlining a
cap-and-trade
program to reduce
CO2
emissions from electric generating units with capacity of
25 MW or greater. The RGGI program calls for signatory
states, which include Maryland, Massachusetts and New York, to
stabilize
CO2emissions
to an established baseline from 2009 through 2014, followed by a
2.5% reduction each year from 2015 through 2018. Each of these
three states has promulgated regulations
16
implementing the RGGI. Complying with the RGGI could have a
material adverse effect upon our operations and our operating
costs, depending upon the availability and cost of emissions
allowances and the extent to which such costs may be offset by
higher market prices to recover increases in operating costs
caused by the RGGI. As contemplated in a memorandum of
understanding among the participating states, Regional
Greenhouse Gas Initiative, Inc. is comprehensively reviewing the
program, which may cause the participating states to change the
manner in which the program is administered and may increase our
cost to comply.
During 2010, GenOn Americas Generation produced approximately
17.3 million tons of
CO2
at its Maryland, Massachusetts and New York generating
facilities for a total cost of $34 million under the RGGI,
including 16.2 million tons of
CO2
(for a total cost of $32 million) at GenOn
Mid-Atlantics Maryland generating facilities. In 2011,
GenOn Americas Generation expects to produce approximately
15.6 million tons of
CO2
at its Maryland, Massachusetts and New York generating
facilities, including approximately 14.8 million tons at
GenOn Mid-Atlantics Maryland generating facilities. The
RGGI regulations required those facilities to obtain allowances
to emit
CO2
beginning in 2009. Annual allowances generally were not granted
to existing sources of such emissions. Instead, allowances have
been made available for such facilities by purchase through
periodic auctions conducted quarterly or through subsequent
purchase from a party that holds allowances sold through a
quarterly auction.
The tenth auction of allowances by the RGGI states was held on
December 1, 2010. The clearing price for the approximately
24.8 million allowances sold in the auction allocated for
use beginning in the first control period
(2009-2011)
was $1.86 per ton. The clearing price for the approximately
1.2 million allowances sold in the auction allocated for
use beginning in the second control period
(2012-2014)
was $1.86 per ton. The allowances sold in this auction may be
used for compliance in any of the RGGI states. Further auctions
will occur quarterly, with the next auction scheduled for March
2011.
In California, emissions of greenhouse gases are governed by
Californias Global Warming Solutions Act (AB 32), which
requires that statewide greenhouse gas emissions be reduced to
1990 levels by 2020. In December 2008, the CARB approved a
Scoping Plan for implementing AB 32. The Scoping Plan requires
that the CARB adopt a
cap-and-trade
regulation by January 2011 and that the cap and trade program
begin in 2012. The CARBs schedule for developing
regulations to implement AB 32 is being coordinated with the
schedule of the WCI for development of a regional
cap-and-trade
program for greenhouse gas emissions. Through the WCI,
California is working with other western states and Canadian
provinces to coordinate and implement a regional
cap-and-trade
program. In October 2010, the CARB released its proposed
cap-and-trade
regulation for public comment, which the CARB approved in
December 2010. GenOn Americas Generations California
generating facilities will be required to comply beginning in
2012. The recently adopted
cap-and-trade
regulation and any other plans, rules and programs approved to
implement AB 32, could adversely affect the costs of operating
the facilities.
In August 2008, Massachusetts adopted the Climate Protection
Act, which establishes a program to reduce greenhouse gas
emissions significantly over the next 40 years. Under the
Climate Protection Act, the MADEP has established a reporting
and verification system for statewide greenhouse gas emissions,
including emissions from generating facilities producing all
electricity consumed in Massachusetts, and determined the
states greenhouse gas emissions level in 1990. Under the
Climate Change Act, the MAEEA is to establish statewide
greenhouse gas emissions limits effective beginning in 2020 that
will reduce such emissions from the 1990 levels by a range of
10% to 25% beginning in 2020, with the reduction increasing to
80% below 1990 levels by 2050. In setting these limits, the
MAEEA is to consider the potential costs and benefits of various
reduction measures, including emissions limits for electric
generating facilities, and may consider the use of market-based
compliance mechanisms. A violation of the emissions limits
established under the Climate Protection Act may result in a
civil penalty of up to $25,000 per day. Implementation of the
Climate Protection Act could have a material adverse effect on
how GenOn Americas Generation operates its Massachusetts
generating facilities and the costs of operating those
facilities. On December 29, 2010, the MAEEA established a
limit for 2020 that is 25% less than the 1990 level.
In April 2009, the Maryland General Assembly passed the Maryland
Act, which became effective in October 2009. The Maryland Act
requires a reduction in greenhouse gas emissions in Maryland by
25% from
17
2006 levels by 2020. However, this provision of the Maryland Act
is only in effect through 2016 unless a subsequent statutory
enactment extends its effective period. The Maryland Act
requires the MDE to develop a proposed implementation plan to
achieve these reductions by the end of 2011 and to adopt a final
plan by the end of 2012.
In light of the United States Supreme Court ruling in
Massachusetts v. EPA that greenhouse gases fit
within the Clean Air Acts definition of air
pollutant, the EPA has proposed and promulgated
regulations regarding the emission of greenhouse gases. In
September 2009, the EPA promulgated a rule that requires owners
of facilities in many sectors of the economy, including power
generation, to report annually to the EPA the quantity and
source of greenhouse gas emissions released from those
facilities. In addition to this reporting requirement, the EPA
has promulgated several rules that address greenhouse gas
emissions. In December 2009, under a portion of the Clean Air
Act that regulates vehicles, the EPA determined that elevated
concentrations of greenhouse gases in the atmosphere endanger
the publics health and welfare through their contribution
to climate change (Endangerment Finding). In April 2010, the EPA
finalized a rule to regulate greenhouse gases from vehicles
beginning in model year 2012. In April 2010, the EPA also issued
its Reconsideration of Interpretation of Regulations that
Determine Pollutants Covered by Clean Air Act Permitting
Programs, which addresses the scope of pollutants subject
to certain permitting requirements under the Clean Air Act as
well as when such requirements become effective. The EPA has
stated that, because of the vehicle rule, emissions of
greenhouse gases from new stationary sources such as power
plants and from major modifications to such sources are subject
to certain Clean Air Act permitting requirements as of January
2011. These permitting requirements will require such sources to
use best available control technology to limit their
greenhouse gases. We expect various parties to seek judicial
review of these regulations and that the legal challenges to
these regulations will not be resolved for several years. The
additional substantive requirements under the Clean Air Act that
may apply or may come to apply to stationary sources such as
power plants are not clear at this time.
In December 2010, the EPA announced that it was starting the
process of developing regulations under the New Source
Performance Standard section of the Clean Air Act that would
affect new and existing fossil-fueled generating facilities. The
EPA expects to propose regulations by July 2011 and to finalize
such regulations by May 2012.
In addition to the state and regional regulatory matters
described above, various bills have been proposed in Congress to
govern
CO2
emissions from generating facilities. Current proposals include
a
cap-and-trade
system that would require us to purchase allowances for some or
all of the
CO2
emitted by our generating facilities. If
CO2
regulation becomes more stringent, we expect the demand for gas
and/or
renewable sources of electricity will increase over time.
Although we expect that market prices for electricity would
increase following such regulation and would allow us to recover
a portion of the cost of these allowances, we cannot predict
with any certainty the actual increases in costs such regulation
could impose upon us or our ability to recover such cost
increases through higher market rates for electricity, and such
regulation could have a material adverse effect on our
consolidated statements of operations, financial position and
cash flows. It is possible that Congress will take action to
regulate greenhouse gas emissions within the next several years.
The form and timing of any final legislation will be influenced
by political and economic factors and is uncertain at this time.
Implementation of a
CO2
cap-and-trade
program in addition to other emission control requirements could
increase the likelihood of coal-fired generating facility
retirements. During 2010, GenOn Americas Generation produced
approximately 18.8 million tons of
CO2
at its generating facilities (including approximately
17.3 million tons at GenOn Mid-Atlantics generating
facilities). GenOn Americas Generation expects to produce
approximately 16.3 million total tons of
CO2
at its generating facilities (including approximately
15.5 million total tons at GenOn Mid-Atlantics
generating facilities) in 2011.
Water
Regulations
We are required under the Clean Water Act to comply with intake
and discharge requirements, requirements for technological
controls and operating practices. To discharge water, we
generally need permits required by the Clean Water Act. Such
permits typically are subject to review every five years. As
with air quality regulations, federal and state water
regulations are expected to impose additional and more stringent
18
requirements or limitations in the future. This is particularly
the case for regulatory requirements governing cooling water
intake structures, which are subject to regulation under
section 316(b) of the Clean Water Act (the 316
(b) regulations). A 2007 decision by the United States
Court of Appeals for the Second Circuit (the Second Circuit) in
Riverkeeper Inc. et al, v. EPA, in which the court
remanded to the EPA for reconsideration numerous provisions of
the EPAs section 316(b) regulations for existing
power plants, has created substantial uncertainty about exactly
what technologies or other measures will be needed to satisfy
section 316(b) requirements in the future and when any new
requirements will be imposed. Following that ruling by the
Second Circuit, the EPA in 2007 suspended its 316(b) regulations
for existing power plants. Various parties sought review of the
Second Circuits decision by the United States Supreme
Court, and it granted those requests with respect to whether the
EPA could permissibly weigh costs versus benefits in determining
what requirements to impose. On April 1, 2009, the Supreme
Court reversed the Second Circuit, ruling that the EPA had
permissibly relied on cost-benefit analysis in setting standards
for cooling water intake structures for existing power plants
and authorizing site-specific variances. The Supreme
Courts ruling did not alter other aspects of the Second
Circuits decision. Significant uncertainty remains
regarding the effect of the Supreme Courts decision on the
EPAs 316(b) regulations for existing power plants and what
technologies or other measures will be needed to satisfy
section 316(b) regulations. The EPA also is in the process
of updating its technology-based regulations regarding
discharges from power plants. The EPA has collected information
from numerous power plants to inform this rulemaking. The new
standards have not yet been proposed. Accordingly, we cannot
predict their effect on our business.
Once-Through Cooling (GenOn Americas
Generation). In October 2010, the California
State Water Resources Control Boards (State Water
Boards) Policy on the Use of Coastal and Estuarine Waters
for Power Plant Cooling (Once-Through Cooling Policy) became
effective. Compliance options for GenOn Americas
Generations affected generating units include
transitioning to a closed-cycle cooling system, retiring, or
submitting an alternative plan that meets equivalent mitigation
criteria. The specified compliance date for GenOn Americas
Generations Pittsburg and Contra Costa generating
facilities is December 31, 2017. We will shut down the
Contra Costa generating facility in April 2013, subject to
regulatory approval. We are analyzing compliance options for the
remaining affected generating units, and for certain of GenOn
Americas Generations California generating facilities the
Once-Through Cooling Policy could have a material adverse effect
on how it operates those facilities and the costs of operating
those facilities. In October 2010, GenOn Americas Generation and
several other companies jointly filed a lawsuit in California
superior court challenging the State Water Boards issuance
of the Once-Through Cooling Policy on various procedural and
substantive grounds. The lawsuit seeks a writ directing the
State Water Board to vacate and set aside approval of the
Once-Through Cooling Policy.
Endangered Species Acts (GenOn Americas
Generation). GenOn Deltas use of water from
the Sacramento-San Joaquin Delta at its Contra Costa and
Pittsburg generating facilities potentially affects certain fish
species protected under the federal Endangered Species Act and
the California Endangered Species Act. GenOn Delta therefore
must maintain authorization under both statutes to engage in
operations that could result in a take of (i.e., cause harm to)
fish of the protected species. In January and February 2006,
GenOn Delta received correspondence from the United States Fish
and Wildlife Service and the U.S. Army Corps of Engineers
expressing the view that the federal Endangered Species Act take
authorization for the Contra Costa and Pittsburg generating
facilities was no longer in effect as a result of changed
circumstances. GenOn Delta disagreed with the agencies
characterization of its take authorization as no longer being in
effect. In October 2007, GenOn Delta received correspondence
from the United States Fish and Wildlife Service, the National
Marine Fisheries Service and the Army Corps of Engineers
clarifying that GenOn Delta continued to be authorized to take
four species of fish protected under the federal Endangered
Species Act. The agencies have initiated a process that will
review the environmental effects of GenOn Deltas water
usage, including effects on the protected species of fish. That
process could lead to changes in the manner in which GenOn Delta
can use river water for the operation of the Contra Costa and
Pittsburg generating facilities. As discussed further in
note 3(d) to our consolidated financial statements, we plan
to shut down the Contra Costa generating facility in April 2013.
19
By letter dated September 27, 2007, the Coalition for a
Sustainable Delta, four water districts, and an individual (the
Delta Noticing Parties) provided notice to GenOn and GenOn Delta
of their intent to file suit alleging that GenOn Delta has
violated, and continues to violate, the federal Endangered
Species Act through the operation of its Contra Costa and
Pittsburg generating facilities. The Delta Noticing Parties
contend that the facilities use of water drawn from the
Sacramento-San Joaquin Delta for cooling purposes results
in harm to four species of fish listed as endangered species.
The Delta Noticing Parties assert that GenOn Deltas
authorizations to take (i.e., cause harm to) those species, a
biological opinion and incidental take statement issued by the
National Marine Fisheries Service on October 17, 2002, for
three of the fish species and a biological opinion and
incidental take statement issued by the United States Fish and
Wildlife Service on November 4, 2002, for the fourth fish
species, have been violated by GenOn Delta and no longer apply
to permit the effects on the four fish species caused by the
operation of the Contra Costa and Pittsburg generating
facilities. Following receipt of these letters, GenOn Delta
received in October 2007 the correspondence noted above from the
United States Fish and Wildlife Service, the National Marine
Fisheries Service and the United States Army Corps of
Engineers (the Corps) clarifying GenOn Deltas continuing
right to take the four species of fish. In a subsequent letter,
the Coalition for a Sustainable Delta also alleged violations of
the National Environmental Policy Act and the California
Endangered Species Act associated with the operation of GenOn
Deltas generating facilities. On May 14, 2009, the
Coalition for a Sustainable Delta, Kern County Water Agency and
an individual sent a new notice of intent to sue to the Corps
alleging that the Corps had violated the federal Endangered
Species Act by issuing permits related to the operation of GenOn
Deltas Contra Costa and Pittsburg generating facilities
without ensuring that conservation measures would be implemented
to minimize and mitigate the harm to the four endangered fish
species and their habitat allegedly resulting from such
operation. GenOn Delta disputes the allegations made by the
Delta Noticing Parties and those made in the May 14, 2009
notice.
On February 11, 2010, GenOn Delta entered into a settlement
agreement with the Delta Noticing Parties, the parties to the
May 14, 2009 notice of intent to sue, and the Corps. The
settlement agreement provides for the Delta Noticing Parties and
the parties to the May 14, 2009 notice of intent to sue to
withdraw the two notices of intent to sue and to release all
claims described in those notices. The settlement agreement
obligated GenOn Delta to seek approval from the Corps, the
United States Fish and Wildlife Service, and the National Marine
Fisheries Service to amend its plan then in effect for
monitoring entrainment and impingement of aquatic species caused
by the operation of its generating facilities to increase
monitoring during periods the facilities are operating, and
those approvals have been obtained. The settlement agreement
requires the Corps to use its best efforts to conclude ongoing
consultations with the United States Fish and Wildlife Service
and the National Marine Fisheries Service regarding the
environmental effects of GenOn Deltas water usage in a
timely manner and allows the Delta Noticing Parties and the
parties to the May 14, 2009 notice of intent to sue to
issue new notices of intent to sue if such consultations are not
completed by October 31, 2011.
In November 2009, GenOn Delta signed a second amendment to a
Memorandum of Agreement with the California Department of Fish
and Game. The amendment requires GenOn Delta to prepare a
planning and feasibility study for potential habitat restoration
projects and extends by 16 months to March 1, 2011,
the deadline for submitting an application for a new permit
authorizing GenOn Delta to take the protected fish species
affected by the operation of its facilities. The amendment
extends GenOn Deltas existing authorization for take of
fish species protected under the California Endangered Species
Act until the California Department of Fish and Game completes
its consideration of the application for the new permit.
Potrero National Pollution Discharge Elimination System
Permit (GenOn Americas Generation). On
June 8, 2006, Bayview-Hunters Point Community Advocates and
Communities for a Better Environment filed a petition
challenging the issuance of the NPDES permit for our Potrero
generating facility. On February 8, 2007, Bayview-Hunters
Point Community Advocates and Communities for a Better
Environment filed another petition with a request to amend their
initial petition. On March 21, 2007, the California State
Water Resources Control Board notified the parties that
petitioners requested that as of March 19, 2007, the two
petitions be moved from active status to abeyance. Those
petitions currently remain in abeyance. Additionally, on
June 15, 2007, Bayview-Hunters Point Community Advocates
and Communities for a Better Environment and San Francisco
Baykeeper filed a third petition requesting that the NPDES
permits for Potrero and GenOn
20
Deltas Pittsburg generating facility be reopened. The
State Water Resources Control Board denied that petition on
November 27, 2007. As discussed further in notes 3 and
10 to our consolidated financial statements, the CAISO has
determined that the Potrero generating facility is no longer
needed for reliability and, accordingly, we shut it down on
February 28, 2011.
Kendall NPDES and Surface Water Discharge Permit (GenOn
Americas Generation). On September 26, 2006,
the EPA issued to GenOn Kendall an NPDES renewal permit for the
Kendall cogeneration facility. The same permit was concurrently
issued by the MADEP as a state SWD permit, and was accompanied
by MADEPs earlier issued water quality certificate under
section 401 of the Clean Water Act. These permits sought to
impose new temperature limits at various points in the Charles
River, an extensive temperature, water quality and biological
monitoring program and a requirement to develop and install a
barrier net system to reduce fish impingement and entrainment.
The provisions regulating the thermal discharge could have
caused substantial curtailments of the operations of the Kendall
generating facility. GenOn Kendall appealed the permits in three
proceedings: (a) appeal of the NPDES permit to the
EPAs Environmental Appeals Board; (b) appeal of the
SWD permit to the MADEP; and (c) appeal of the water
quality certification to the MADEP. The effect of the permits
was stayed pending the outcome of these appeals. On
March 6, 2008, the EPA and the MADEP issued a draft permit
modification to address the 316(b) provisions of the permit that
would have required modifications to the intake structure for
the Kendall generating facility to add fine and coarse mesh
barrier exclusion technologies and to install a mechanism to
sweep organisms away from the intake structure through an
induced water flow. On May 1, 2008, GenOn Kendall submitted
comments on the draft permit modification objecting to the new
requirements. On December 19, 2008, the EPA and the MADEP
issued final permit modifications to address the 316
(b) regulations. Those final permit modifications did not
substantially modify the requirements proposed in the draft
modifications, and on February 2, 2009, GenOn Kendall filed
an appeal of those modifications.
In October 2010, GenOn Kendall submitted a permit modification
request to the EPA and MADEP that requested modification of the
2006 permits (as previously modified in 2008) to reflect
revised permit terms agreed upon among GenOn Kendall, the EPA
and MADEP as part of a settlement of the permit renewal
proceedings pending before EPA and MADEP. The settlement
contemplates that an additional steam pipeline will be installed
across the Charles River under the Longfellow Bridge to allow
GenOn Kendall to make additional steam sales to Trigen-Boston
Energy Corporation in Boston and that GenOn Kendall will install
a back pressure steam turbine and air cooled condenser at the
Kendall generating facility. This new pipeline and equipment
once operational, would allow GenOn Kendall to reduce
significantly its use of water from the Charles River. On
October 25, 2010, EPA and MADEP issued the proposed revised
permits (the 2010 Kendall Permits) as draft permit modifications
for public comment. On December 17, 2010, the EPA and MADEP
issued final permits that became effective on February 1,
2011. The 2010 Kendall Permits will limit GenOn Kendall to
drawing no more than 3.2 million gallons of water per day
from the river under normal operations, impose temperature
limits similar to the 2006 permits, and require monitoring of
temperatures at various points in the river when the Kendall
generating facility is discharging water to the river. The 2010
Kendall Permits do not require the installation of barrier nets
or modifications to the intake structure at the facility.
Because river water will no longer be used for once-through
cooling under normal operations once the new pipeline and
equipment have been installed, GenOn Kendall expects the 2010
Kendall Permits to impose significantly less risk that
operations of the facility would have to be curtailed to
maintain compliance with the temperature limits. As part of its
settlement with the EPA and MADEP, the EPA and MADEP issued
administrative orders that defer application of the new limit on
the amount of river water used by the Kendall cogenerating
facility and the new temperature limits imposed by the 2010
Kendall Permits until installation has been completed of the new
pipeline, the back pressure steam turbine, and the air cooled
condenser, which is not expected to occur until 2015.
Canal NPDES and SWD Permit (GenOn Americas
Generation). On August 1, 2008, the EPA
issued to GenOn Canal an NPDES renewal permit for the Canal
generating facility. The same permit was concurrently issued by
MADEP as a state SWD Permit, and was accompanied by MADEPs
earlier water quality certificate under section 401 of the
Clean Water Act. The new permit imposes a requirement on GenOn
Canal to install closed cycle cooling or an alternative
technology that will reduce the entrainment of marine organisms
by the
21
Canal generating facility to levels equivalent to what would be
achieved by closed cycle cooling. GenOn Canal appealed the NPDES
permit to the EPAs Environmental Appeals Board and
appealed the surface water discharge and the water quality
certificate to the MADEP. On December 4, 2008, the EPA
requested a stay to the appeal proceedings and withdrew
provisions related to the closed cycle cooling requirements. The
EPA has re-noticed these provisions as draft conditions for
additional public comment. GenOn Canal filed comments on
January 29, 2009, stating that installing closed cycle
cooling at the Canal generating facility was not justified and
that without some cost-recovery mechanism the cost would make
continued operation of the facility uneconomic. While the
appeals of the renewal permit are pending, the effect of any
contested permit provisions is stayed and the Canal generating
facility will continue to operate under its current NPDES
permit. We are unable to predict the outcome of this proceeding.
NPDES and State Pollutant Discharge Elimination System Permit
Renewals. In addition to the various NPDES
proceedings described above, proceedings are currently pending
for renewal of the NPDES or state pollutant discharge
elimination system permits at many of our generating facilities
and ash disposal sites. In general, the EPA and the state
agencies responsible for implementing the provisions of the
Clean Water Act applicable to the intake of water and discharge
of effluent by electric generating facilities have been making
the requirements imposed upon such facilities more stringent
over time. With respect to each of these permit renewal
proceedings, the permit renewal proceeding could take years to
resolve and the agency or agencies involved could impose
requirements upon the entity owning the facility that require
significant capital expenditures, limit the times at which the
facility can operate, or increase operations and maintenance
costs materially.
Byproducts,
Wastes, Hazardous Materials and Contamination
Our facilities are subject to laws and regulations governing
waste management. The federal Resource Conservation and Recovery
Act of 1976 (and many analogous state laws) contains
comprehensive requirements for the handling of solid and
hazardous wastes. The generation of electricity produces
non-hazardous and hazardous materials, and we incur substantial
costs to store and dispose of waste materials. The EPA and the
states in which we operate coal-fired units may develop new
regulations that impose additional requirements on facilities
that store or dispose of materials remaining after the
combustion of fossil fuels, including coal ash. If so, we may be
required to change our current waste management practices at
some facilities and incur additional costs.
In June 2010, the EPA proposed two alternatives for regulating
byproducts of coal combustion (e.g., ash and gypsum) under the
federal Resource Conservation and Recovery Act of 1976. Under
the first proposal, these byproducts would be regulated as solid
wastes. Under the second proposal, these byproducts would be
regulated as special wastes in a manner similar to
the regulation of hazardous waste with an exception for
beneficial reuse of these byproducts. The second alternative
would impose significantly more stringent requirements on and
increase materially the cost of disposal of coal combustion
byproducts.
GenOn Americas Generations Contra Costa, Pittsburg and
Potrero generating facilities have areas of soil and groundwater
contamination. In 1998, prior to GenOn Americas
Generations acquisition of those facilities from
PG&E, consultants for PG&E conducted soil and
groundwater investigations at those facilities which revealed
contamination. The consultants conducting the investigation
estimated the aggregate cleanup costs at those facilities could
be as much as $60 million. Pursuant to the terms of the
Purchase and Sale Agreement with PG&E, PG&E has
responsibility for the containment or capping of all soil and
groundwater contamination and the disposition of up to 60,000
cubic yards of contaminated soil from the Potrero generating
facility and the remediation of any groundwater or solid
contamination identified by PG&Es consultants in 1998
at the Contra Costa and Pittsburg generating facilities, before
those facilities were purchased in 1999 by GenOn Americas
Generations subsidiaries. Pursuant to GenOn Americas
Generations requests, PG&E has disposed of 807 cubic
yards of contaminated soil from the Potrero generating facility.
GenOn Americas Generation is not aware of soil or groundwater
conditions at its Contra Costa, Pittsburg and Potrero generating
facilities for which it expects remediation costs to be material
that are not the responsibility of other parties.
22
In 2008, GenOn Americas Generation closed and then demolished
the Lovett generating facility in New York. Pursuant to an
agreement with the New York State Department of Environmental
Conservation in 2009, GenOn Americas Generation assessed the
environmental condition of the property. GenOn Americas
Generation does not yet know what, if any, remediation will be
required for the Lovett property.
Other. As a result of their age, many of our
plants contain significant amounts of asbestos insulation, other
asbestos containing materials, as well as lead-based paint. We
think we properly manage and dispose of such materials in
compliance with state and federal rules. See note 3(e) to
our consolidated financial statements.
Additionally, CERCLA, also known as the Superfund law,
establishes a federal framework for dealing with the cleanup of
contaminated sites. Many states have enacted similar state
superfund statutes as well as other laws imposing obligations to
investigate and clean up contamination. We do not think we have
any material liabilities or obligations under CERCLA or similar
state laws. These laws impose clean up and restoration liability
on owners and operators of plants from or at which there has
been a release or threatened release of hazardous substances,
together with those who have transported or arranged for the
disposal of those substances.
Employees
GenOn Energy Services, an indirect subsidiary of GenOn, provides
our personnel pursuant to services agreements. At
February 11, 2011, approximately 1,146 GenOn Energy
Services employees worked at GenOn Americas Generations
facilities, of which approximately 753 worked at GenOn
Mid-Atlantic facilities. The following details the employees
subject to collective bargaining agreements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Contract
|
|
|
|
|
|
Employees
|
|
|
Expiration
|
|
Union
|
|
Location
|
|
Covered
|
|
|
Date
|
|
|
Eastern PJM Region
|
|
|
|
|
|
|
|
|
|
|
IBEW Local
1900(1)
|
|
Maryland and Virginia
|
|
|
489
|
|
|
|
6/1/2015
|
|
Northeast Region
|
|
|
|
|
|
|
|
|
|
|
IBEW Local
503(2)
|
|
New York
|
|
|
30
|
|
|
|
4/30/2013
|
|
UWUA Local 369
|
|
Cambridge, Massachusetts
|
|
|
30
|
|
|
|
2/28/2013
|
|
UWUA Local
369(3)
|
|
Sandwich, Massachusetts
|
|
|
26
|
|
|
|
5/31/2011
|
|
California
|
|
|
|
|
|
|
|
|
|
|
IBEW Local
1245(4)
|
|
California
|
|
|
112
|
|
|
|
10/31/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
Total GenOn Americas Generation
|
|
|
|
|
687
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
During the second quarter of 2010, GenOn entered into a new
collective bargaining agreement with its employees represented
by IBEW Local 1900. The previous collective bargaining agreement
expired on June 1, 2010. As part of the new agreement,
GenOn is required to provide additional retirement contributions
through the defined contribution plan currently sponsored by
GenOn Energy Services, increases in pay and other benefits. In
addition, the new agreement provides for a change to the
postretirement healthcare benefit plan covering Mid-Atlantic
union employees to eliminate employer-provided healthcare
subsidies through a gradual phase-out. |
|
(2) |
|
In August 2010, GenOn entered into a new collective bargaining
agreement with its employees represented by IBEW Local 503. The
previous collective bargaining agreement expired on June 1,
2008. After reaching impasse in its negotiations with the union,
GenOn imposed terms effective January 28, 2009, under which
the employees worked without disruption. The new agreement is
substantially the same as the imposed contract. |
|
(3) |
|
In June 2009, the UWUA Local 480 representing the employees at
the Canal generating facility in Sandwich, Massachusetts, merged
with the UWUA Local 369. The UWUA Local 369 also represents
GenOn |
23
|
|
|
|
|
Americas Generations employees at the Kendall generating
facility in a separate bargaining unit and each facility is
covered by its own collective bargaining agreement. |
|
(4) |
|
As a result of the shut down of GenOn Americas Generations
Potrero generating facility, GenOn will be downsizing its
bargaining unit workforce consistent with an agreement
negotiated with Local 1245. |
To mitigate and reduce the risk of disruption during labor
negotiations, we engage in contingency planning for operation of
our generating facilities to the extent possible during an
adverse collective action by one or more of our unions.
Available
Information
GenOns principal offices are at 1000 Main Street, Houston,
Texas 77002
(832-357-7000).
The following information is available free of charge on our
website
(http://www.genon.com):
|
|
|
|
|
The corporate governance guidelines and standing board committee
charters for GenOn;
|
|
|
|
Our annual reports on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K
and amendments to these reports; and
|
|
|
|
The code of ethics and business conduct for GenOn.
|
You can request a free copy of these documents by contacting our
investor relations department. It is our intention to disclose
amendments to, or waivers from, GenOns code of ethics and
business conduct on our website. No information on our website
is incorporated by reference into this
Form 10-K.
In addition, our annual, quarterly and current reports are
available on the SECs website at
(http://www.sec.gov)
or at its public reference room: 100 F Street, NE,
Room 1580, Washington, D.C. 20549
(1-800-SEC-0330).
We are subject to the following factors that could affect our
future performance and results of operations. Also, see
Cautionary Statement Regarding Forward-Looking
Information on page vii, Business in
Item 1 and Managements Discussion and Analysis
of Financial Condition and Results of Operations in
Item 7 of this
Form 10-K.
Risks
Related to the Operation of our Business
The
merger that created GenOn may not achieve its intended results,
and we may be unable to integrate successfully Mirants and
RRI Energys operations.
Achieving the anticipated benefits of the merger that created
GenOn depends on whether the businesses of RRI Energy and Mirant
can be integrated in an efficient and effective manner.
Integration of the two companies could take longer than
anticipated and could result in the loss of valuable employees,
the disruption of our ongoing businesses, processes and systems
or inconsistencies in standards, controls, procedures,
practices, policies and compensation arrangements, any of which
could adversely affect our ability to achieve the anticipated
benefits of the merger. We may have difficulty addressing
possible differences in corporate cultures and management
philosophies. Many of our employees are in new positions
following the merger and are required to comply with policies
that are new to them, including policies related to risk
management. The integration process is subject to a number of
uncertainties, and no assurance can be given that the
anticipated benefits will be realized or, if realized, the
timing of their realization. Failure to achieve these
anticipated benefits could result in increased costs or
decreases in the amount of expected revenues and could adversely
affect our future business, financial condition, operating
results and prospects.
24
Our
revenues are unpredictable because most of our generating
facilities operate without long-term power sales agreements, and
our revenues and results of operations depend on market and
competitive forces that are beyond our control.
We provide energy, capacity, ancillary and other energy services
from our generating facilities into competitive power markets
either on a short-term fixed price basis or through power sales
agreements. Our revenues from selling capacity are a significant
part of our overall revenues. We are not guaranteed recovery of
our costs or any return on our capital investments through
mandated rates. The market for wholesale electric energy and
energy services reflects various market conditions beyond our
control, including the balance of supply and demand, our
competitors marginal and long-term costs of production,
and the effect of market regulation. The price at which we can
sell our output may fluctuate on a
day-to-day
basis, and our ability to transact may be affected by the
overall liquidity in the markets in which we operate. These
markets remain subject to regulations that limit our ability to
raise prices during periods of shortage to the degree that would
occur in a fully deregulated market, which may limit our ability
to recover costs and an adequate return on our investment. In
addition, unlike most other commodities, electric energy can be
stored only on a very limited basis and generally must be
produced at the time of use. As a result, the wholesale power
markets are subject to substantial price fluctuations over
relatively short periods of time and can be unpredictable. For
further discussion, see BusinessCompetitive
Environment. Our revenues and results of operations are
influenced by factors that are beyond our control, including:
|
|
|
|
|
the failure of market regulators to develop and maintain
efficient mechanisms to compensate merchant generators for the
value of providing capacity needed to meet demand;
|
|
|
|
actions by regulators, ISOs, RTOs and other bodies that may
artificially modify supply and demand levels and prevent
capacity and energy prices from rising to the level necessary
for recovery of our costs, our investment and an adequate return
on our investment;
|
|
|
|
legal and political challenges to or changes in the rules used
to calculate capacity payments in the markets in which we
operate or the establishment of bifurcated markets, incentives,
other market design changes or bidding requirements that give
preferential treatment to new generating facilities over
existing generating facilities or otherwise reduce capacity
payments to existing generating facilities;
|
|
|
|
the ability of wholesale purchasers of power to make timely
payment for energy or capacity, which may be adversely affected
by factors such as retail rate caps, refusals by regulators to
allow utilities to recover fully their wholesale power costs and
investments through rates, catastrophic losses and losses from
investments by utilities in unregulated businesses;
|
|
|
|
increases in prevailing market prices for fuel oil, coal,
natural gas and emissions allowances that may not be reflected
in prices we receive for sales of energy;
|
|
|
|
increases in electricity supply as a result of actions of our
current competitors or new market entrants, including the
development of new generating facilities or alternative energy
sources that may be able to produce electricity less expensively
than our generating facilities and improvements in transmission
that allow additional supply to reach our markets;
|
|
|
|
increases in 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 OTC regulations adopted
pursuant to the Dodd-Frank Act;
|
|
|
|
decreases in energy consumption resulting from demand-side
management programs such as automated demand response, which may
alter the amount and timing of consumer energy use;
|
|
|
|
the competitive advantages of certain competitors, including
continued operation of older power facilities in strategic
locations after recovery of historic capital costs from
ratepayers;
|
25
|
|
|
|
|
existing or future regulation of our markets by the FERC, ISOs
and RTOs, including any price limitations and other mechanisms
to address some of the price volatility or illiquidity in these
markets or the physical stability of the system;
|
|
|
|
regulatory policies of state agencies that affect the
willingness of our customers to enter into long-term contracts
generally, and contracts for capacity in particular;
|
|
|
|
changes in the rate of growth in electricity usage as a result
of such factors as national and regional economic conditions and
implementation of conservation programs;
|
|
|
|
seasonal variations in energy and natural gas prices, and
capacity payments; and
|
|
|
|
seasonal fluctuations in weather, in particular abnormal weather
conditions.
|
Some
of our existing generating facilities may have a limited life
unless we make significant capital expenditures to increase
their commercial and environmental performance which may not be
justified under current market rules and conditions. (GenOn
Americas Generation)
Our existing generating facilities in northern California depend
almost entirely on payments in support of system reliability.
The energy market, as currently constituted, will not justify
the capital expenditures necessary to repower or reconstruct
these facilities to make them commercially viable in a merchant
market and to meet future environmental requirements. If a
commercially reasonable capacity market were to be instituted by
the CAISO or we could obtain a contract with a creditworthy
buyer, it is possible that we could justify investing the
necessary capital to repower or reconstruct these facilities.
Absent that, our existing generating facilities in northern
California will be commercially viable only as long as they are
necessary for reliability. As discussed further in
note 3(d) to our consolidated financial statements, we plan
to shut down the Contra Costa generating facility in April 2013
and we shut down the Potrero generating facility on
February 28, 2011.
Our generating facilities face lower levels of profitability
under current and forecasted market conditions and some of our
generating facilities may not justify the capital expenditures
to make them commercially viable
and/or to
meet possible environmental requirements.
Changes
in the wholesale energy market or in our facility operations
could result in impairments.
If our outlook for the wholesale energy market changes
negatively, or if our ongoing evaluation of our business results
in decisions to mothball, retire or dispose of facilities, we
could have impairment charges related to our fixed assets. These
evaluations involve significant judgments about the future.
Actual future market prices, project costs and other factors
could be materially different from our current estimates.
Furthermore, increasing environmental regulatory requirements
could result in facilities being removed from service or
derated. See Managements Discussion and Analysis of
Financial Condition and Results of OperationsBusiness
Overview in Item 7 of this
Form 10-K
and note 3 to our consolidated financial statements.
We are
exposed to the risk of fuel and fuel transportation cost
increases and volatility and interruption in fuel supply because
our generating facilities generally do not have long-term
agreements for the supply of natural gas, coal and oil and rely
on other parties for transportation.
Although we purchase fuel based on our expected fuel
requirements, we still face the risks of supply interruptions
and fuel price volatility. Our cost of fuel may not reflect
changes in energy and fuel prices in part because we must
pre-purchase inventories of coal and oil for reliability and
dispatch requirements, and thus the price of fuel may have been
determined at an earlier date than the price of energy generated
from it. The price we can obtain from the sale of energy may not
rise at the same rate, or may not rise at all, to match a rise
in fuel costs. This may have a material adverse effect on our
financial performance. The volatility of fuel prices could
adversely affect our financial results and operations.
26
For our coal-fired generating facilities, we purchase most of
our coal from a small number of suppliers under contracts with
terms of varying lengths, some of which extend to 2013. There is
risk that our coal suppliers may not provide the contractual
quantities on the dates specified within the agreements, or the
deliveries may be carried over to future periods. If our coal
suppliers do not perform in accordance with the agreements, we
may have to procure coal in the market to meet our needs, or
power in the market to meet our obligations. In addition,
generally our coal suppliers do not have investment grade credit
ratings nor do they post collateral with us and, accordingly, we
may have limited ability to collect damages in the event of
default by such suppliers. Non-performance or default risk by
our coal suppliers could have a material adverse effect on our
future results of operations, financial condition and cash
flows. For a discussion of our coal supplier concentration risk,
see note 1 to our consolidated financial statements in this
Form 10-K.
For our oil-fired generating facilities, we typically purchase
fuel from a limited number of suppliers under contracts with
terms of varying lengths. If our oil suppliers do not perform in
accordance with the agreements, we may have to procure oil in
the market to meet our needs, or power in the market to meet our
obligations. For our gas-fired generating facilities, any
curtailments or interruptions on transporting pipelines could
result in curtailment of our operations or increased fuel supply
costs.
Operation
of our generating facilities involves risks that may have a
material adverse effect on our cash flows and results of
operations.
The operation of our generating facilities involves various
operating risks, including, but not limited to:
|
|
|
|
|
the output and efficiency levels at which those generating
facilities perform;
|
|
|
|
interruptions in fuel supply and quality of available fuel;
|
|
|
|
disruptions in the delivery of electricity;
|
|
|
|
adverse zoning;
|
|
|
|
breakdowns or equipment failures (whether a result of age or
otherwise);
|
|
|
|
violations of our permit requirements or changes in the terms
of, or revocation of, permits;
|
|
|
|
releases of pollutants and hazardous substances to air, soil,
surface water or groundwater;
|
|
|
|
ability to transport and dispose of coal ash at reasonable
prices;
|
|
|
|
curtailments or other interruptions in natural gas supply;
|
|
|
|
shortages of equipment or spare parts;
|
|
|
|
labor disputes, including strikes, work stoppages and slowdowns;
|
|
|
|
the aging workforce at certain of our facilities;
|
|
|
|
operator errors;
|
|
|
|
curtailment of operations because of transmission constraints;
|
|
|
|
failures in the electricity transmission system which may cause
large energy blackouts;
|
|
|
|
implementation of unproven technologies in connection with
environmental improvements; and
|
|
|
|
catastrophic events such as fires, explosions, floods,
earthquakes, hurricanes or other similar occurrences.
|
A decrease in, or the elimination of, the revenues generated by
our facilities or an increase in the costs of operating them
could materially affect our cash flows and results of
operations, including cash flows available to us to make
payments on our debt or our other obligations.
27
We are
exposed to possible losses that may occur from the failure of a
counterparty to perform according to the terms of a contractual
arrangement with us, particularly in connection with our
non-collateralized power hedges between GenOn Mid-Atlantic and
financial institutions.
We are exposed to possible losses from the failure of a
counterparty to perform according to the terms of a contractual
arrangement with us, particularly in connection with our
non-collateralized power hedges between GenOn Mid-Atlantic and
financial institutions. Non collateralized power hedges
represent 59% of the net notional power position for GenOn
Americas Generation and 60% of the net notional power position
for GenOn Mid-Atlantic at December 31, 2010. Such hedges
are senior unsecured obligations of GenOn Mid-Atlantic and the
counterparties, and do not require either party to post cash
collateral for initial margin or for securing exposure as a
result of changes in power or natural gas prices. Deterioration
in the financial condition of our counterparties and any
resulting failure to pay amounts owed to us or to perform
obligations or services owed to us beyond collateral posted
could have a negative effect on our business and financial
condition.
We are
subject to adverse developments in the regions in which we
operate, especially the PJM market.
At December 31, 2010, GenOn Americas Generations
generating capacity was 52% in PJM, 23% in CAISO, and 25% in
NYISO and ISO-NE. All of GenOn Mid-Atlantics generating
facilities serve the PJM market. Adverse developments in these
regions, especially in the PJM market (where most of our
revenues are derived), may adversely affect our results of
operations or financial condition. The effect of such adverse
regional developments may be greater on us than on our more
diversified competitors.
Competition
in wholesale power markets may have a material adverse effect on
our financial condition, results of operations and cash
flows.
We compete with non-utility generators, regulated utilities, and
other energy service companies in the sale of our products and
services, as well as in the procurement of fuel and transmission
services. We compete primarily on the basis of price and
service. Regulated utilities in the wholesale markets generally
enjoy a lower cost of capital than we do and often are able to
recover fixed costs through regulated retail rates, including,
in many cases, the costs of generation, allowing them to build,
buy and upgrade generating facilities without relying
exclusively on market-clearing prices to recover their
investments. The competitive advantages of such participants
could adversely affect our ability to compete effectively and
could have an adverse effect on the revenues generated by our
facilities.
Changes
in technology may significantly affect our generating business
by making our generating facilities less
competitive.
We generate electricity using fossil fuels at large central
facilities. This method results in economies of scale and lower
costs than newer technologies such as fuel cells, microturbines,
windmills and photovoltaic solar cells. It is possible that
advances in those technologies, or governmental incentives for
renewable energies, will reduce their costs to levels that are
equal to or below that of most central station electricity
production, which could have a material adverse effect on our
results of operations.
The
expected decommissioning and/or site remediation obligations of
certain of our generating facilities may negatively affect our
cash flows.
Some of our generating facilities and related properties are
subject to decommissioning
and/or site
remediation obligations that may require material expenditures.
Furthermore, laws and regulations may change to impose material
additional decommissioning and remediation obligations on us in
the future. If we are required to make material expenditures to
decommission or remediate one or more of our facilities, such
obligations will affect our cash flows and may adversely affect
our ability to make payments on our obligations.
28
Terrorist
attacks, future wars or risk of war may adversely affect our
results of operations, our ability to raise capital or our
future growth.
As power generators, we face heightened risk of an act of
terrorism, either a direct act against one of our generating
facilities or an act against the transmission and distribution
infrastructure that is used to transport our power, which would
cause an inability to operate as a result of systemic damage.
Further, we rely on information technology networks and systems
to operate our generating facilities, engage in asset management
activities, and process, transmit and store electronic
information. Security breaches of this information technology
infrastructure, including cyber-attacks and cyber terrorism,
could lead to system disruptions, generating facility shutdowns
or unauthorized disclosure of confidential information. If such
an attack or security breach were to occur, our business,
results of operations and financial condition could be
materially adversely affected. In addition, such an attack could
affect our ability to service our indebtedness, our ability to
raise capital and our future growth opportunities.
Our
operations are subject to hazards customary to the power
generating industry. We may not have adequate insurance to cover
all of these hazards.
Power generation involves hazardous activities, including
acquiring, transporting and unloading fuel, operating large
pieces of high-speed rotating equipment and delivering
electricity to transmission and distribution systems. In
addition to natural risks (such as earthquake, flood, storm
surge, lightning, hurricane, tornado and wind), hazards (such as
fire, explosion, collapse and machinery failure) are inherent
risks in our operations. These hazards can cause significant
injury to personnel or loss of life, severe damage to and
destruction of property, plant and equipment, contamination of,
or damage to, the environment and suspension of operations. The
occurrence of any one of these events may result in our being
named as a defendant in lawsuits asserting claims for
substantial damages, environmental cleanup costs, personal
injury and fines
and/or
penalties. We maintain an amount of insurance protection that we
consider adequate, but we cannot assure that our insurance will
be sufficient or effective under all circumstances and against
all hazards or liabilities to which we may be subject. A hazard
or liability for which we are not fully insured could have a
material adverse effect on our financial results and our
financial condition.
Lawsuits,
regulatory proceedings and tax proceedings could adversely
affect our future financial results.
From time to time, we are named as a party to, or our property
is the subject of, lawsuits, regulatory proceedings or tax
proceedings. We are currently involved in various proceedings
which involve highly subjective matters with complex factual and
legal questions. Their outcome is uncertain. Any claim that is
successfully asserted against us could require significant
expenditures by us and could have a material adverse effect on
our results of operations. Even if we prevail, any proceedings
could be costly and time-consuming, could divert the attention
of our management and key personnel from our business operations
and could result in adverse changes in our insurance costs,
which could adversely affect our financial condition, results of
operations or cash flows. See notes 5, 9 and 10 to our
consolidated financial statements.
If we
acquire or develop additional facilities, dispose of existing
facilities or combine with other businesses, we may incur
additional costs and risks.
We may seek to purchase or develop additional facilities,
dispose of existing facilities, or combine with other
businesses. There is no assurance that these efforts will be
successful. In addition, these activities involve risks and
challenges, including identifying suitable opportunities,
obtaining required regulatory and other approvals, integrating
acquired or combined operations with our own, and increasing
expenses and working capital requirements. Furthermore, in any
sale, we may be required to indemnify a purchaser against
liabilities. To finance future acquisitions, we may be required
to issue additional equity securities or incur additional debt.
Obtaining such additional financing is dependent on numerous
factors, including general economic and capital market
conditions, credit availability from financial institutions, the
covenants in our debt agreements, and our financial performance,
cash flow and credit ratings. We cannot make any assurances that
we would be able to obtain such additional financing on
commercially reasonable terms or at all.
29
Risks
Related to Economic and Financial Market Conditions
The
failure of the lenders under GenOns undrawn credit
facilities to perform could have a material adverse effect on
our liquidity and results of operations. We are exposed to
systemic risk of the financial markets and institutions and the
risk of non-performance of the individual lenders under
GenOns undrawn credit facilities.
Maintaining sufficient liquidity in our business for maintenance
and operating expenditures, capital expenditures and collateral
is crucial in order to mitigate the risk of future financial
distress to us. Accordingly, GenOn maintains a revolving credit
facility to manage its expected liquidity needs and
contingencies as described in more detail in this
Form 10-K.
The failure of the lenders to perform under the GenOn revolving
credit facility could have a material adverse effect on our
results of operations. In the event that financial institutions
are unwilling or unable to renew GenOns existing revolving
credit facility or enter into new revolving credit facilities,
our ability to hedge economically our assets or GenOn Americas
Generations ability to engage in proprietary trading could
also be impaired.
As
financial institutions consolidate and operate under more
restrictive capital constraints and regulations, there could be
less liquidity in the energy and commodity markets, which could
have a negative effect on our ability to hedge economically and
transact with creditworthy counterparties.
We hedge economically a substantial portion of our Eastern PJM
coal-fired baseload generation and certain of our other
generation. A significant portion of our hedges are financial
swap transactions between GenOn Mid-Atlantic and financial
counterparties that are senior unsecured obligations of such
parties and do not require either party to post cash collateral,
either for initial margin or for securing exposure as a result
of changes in power or natural gas prices. In recent years,
global financial institutions have been active participants in
these energy and commodity markets. As such financial
institutions consolidate and operate under more restrictive
capital constraints and regulations, there could be less
liquidity in the energy and commodity markets, which could have
a negative effect on our ability to hedge economically and
transact with creditworthy counterparties.
The
Dodd-Frank Act could materially affect our business, including
greater regulation of energy contracts and OTC derivative
financial instruments, which could materially affect our ability
to hedge economically our generation.
The Dodd-Frank Act, which was enacted in July 2010 in response
to the global financial crisis, increases the regulation of
transactions involving OTC derivative financial instruments. The
statute provides that standardized swap transactions between
dealers and large market participants will have to be cleared
and traded on an exchange or electronic platform. Although the
provisions and legislative history of the Dodd-Frank Act provide
strong evidence that market participants, such as the Companies,
which utilize OTC derivative financial instruments to hedge
commercial risks are not to be subject to these clearing and
exchange-trading requirements, it is uncertain what the final
implementing regulations to be issued by the CFTC and SEC will
provide. The effect of the Dodd-Frank Act on our business
depends in large measure on pending CFTC and SEC rulemaking
proceedings and, in particular, the final definitions for the
key terms Swap Dealer and Major Swap
Participant in the Dodd-Frank Act. The CFTC and SEC issued
a proposed rulemaking to set final definitions for the terms
Swap Dealer and Major Swap Participant,
among others. Entities defined as Swap Dealers and Major Swap
Participants will face costly requirements for clearing and
posting margin, as well as additional requirements for reporting
and business conduct. As proposed, the Swap Dealer definition in
particular is ambiguous, subjective and could be broad enough to
encompass some energy companies. If applied to our hedging
activity, such regulations could materially affect our ability
to hedge economically our generation by reducing liquidity in
the energy and commodity markets and, if we are required to
clear such transactions on exchanges or meet other requirements,
by significantly increasing the collateral costs associated with
such activities.
30
Changes
in commodity prices may negatively affect our financial results
by increasing the cost of producing power or lowering the price
at which we are able to sell our power.
Our generating business is subject to changes in power prices
and fuel and emissions costs, and these commodity prices are
influenced by many factors outside our control, including
weather, seasonal variation in supply and demand, market
liquidity, transmission and transportation inefficiencies,
availability of competitively priced alternative energy sources,
demand for energy commodities, production of natural gas, coal
and crude oil, natural disasters, wars, embargoes and other
catastrophic events, and federal, state and environmental
regulation and legislation. In addition, significant
fluctuations in the price of natural gas may cause significant
fluctuations in the price of electricity. Significant
fluctuations in commodity prices may affect our financial
results and financial position by increasing the cost of
producing power and decreasing the amounts we receive from the
sale of power.
Our
asset management activities will not fully protect us from
fluctuations in commodity prices.
We engage in asset management activities related to sales of
electricity and purchases of fuel. The income and losses from
these activities are recorded as operating revenues and fuel
costs. We may use forward contracts and other derivative
financial instruments to manage market risk and exposure to
volatility in prices of electricity, coal, natural gas,
emissions and oil. We cannot provide assurance that these
strategies will be successful in managing our price risks, or
that they will not result in net losses to us as a result of
future volatility in electricity, fuel and emissions markets.
Actual power prices and fuel costs may differ from our
expectations.
Our asset management activities include natural gas derivative
financial instruments that we use to hedge economically power
prices for our baseload generation. The effectiveness of these
hedges is dependent upon the correlation between power and
natural gas prices in the markets where we operate. If those
prices are not sufficiently correlated, our financial results
and financial position could be adversely affected. See
note 2 to our consolidated financial statements and
Quantitative and Qualitative Disclosures About Market
Risk in Item 7A of this
Form 10-K.
Additionally, we expect to have an open position in the market,
within our established guidelines, resulting from GenOn Americas
Generations proprietary trading and fuel oil management
activities. To the extent open positions exist, fluctuating
commodity prices can affect our financial results and financial
position, either favorably or unfavorably. As a result of these
and other factors, we cannot predict the outcome that risk
management decisions may have on our business, operating results
or financial position. Although management devotes considerable
attention to these issues, their outcome is uncertain.
Our
policies and procedures cannot eliminate the risks associated
with our hedging and GenOn Americas Generations
proprietary trading activity.
The risk management procedures we have in place may not always
be followed or may not always work as planned. If any of our
employees were able to violate our system of internal controls,
including our risk management policy, and engage in unauthorized
hedging and related activities, it could result in significant
penalties and financial losses. In addition, risk management
tools and metrics such as value at risk, gross margin at risk,
and stress testing are partially based on historic price
movements. If price movements significantly or persistently
deviate from historical behavior, risk limits may not fully
protect us from significant losses.
The
accounting treatment of our asset management and GenOn Americas
Generations proprietary trading and fuel oil management
activities may increase the volatility of our quarterly and
annual financial results.
We engage in asset management activities to hedge economically
our exposure to market risk with respect to:
(a) electricity sales from our generating facilities,
(b) fuel used by those facilities and (c) emissions
allowances. We generally attempt to balance our fixed-price
purchases and sales commitments in terms of contract volumes and
the timing of performance and delivery obligations through the
use of financial and
31
physical derivative financial instruments. GenOn Americas
Generation also uses derivative financial instruments with
respect to its limited proprietary trading and fuel oil
management activities, through which it attempts to achieve
incremental returns by transacting where it has specific market
expertise. Derivatives from our asset management and GenOn
Americas Generations proprietary trading and fuel oil
management activities are recorded on our balance sheet at fair
value pursuant to the accounting guidance for derivative
financial instruments. None of our derivatives recorded at fair
value are designated as a hedge under this guidance, and changes
in their fair values currently are recognized in earnings as
unrealized gains or losses. As a result, our GAAP financial
resultsincluding gross margin, operating income and
balance sheet ratioswill, at times, be volatile and
subject to fluctuations in value primarily because of changes in
forward electricity and fuel prices. See note 2 to our
consolidated financial statements.
Risks
Related to Governmental Regulation and Laws
Our
costs of compliance with environmental laws are significant and
can affect our future operations and financial
results.
We are subject to extensive and evolving environmental
regulations, particularly in regard to our coal- and oil-fired
facilities. Failure to comply with environmental requirements
could require us to shut down or reduce production at our
facilities or create liabilities. We incur significant costs in
complying with these regulations and, if we fail to comply,
could incur significant penalties. Our cost estimates for
environmental compliance are based on existing regulations or
our view of reasonably likely regulations, and our assessment of
the costs of labor and materials and the state of evolving
technologies. Our decision to make these investments is often
subject to future market conditions. Changes to the preceding
factors, new or revised environmental regulations, litigation
and new legislation
and/or
regulations, as well as other factors, could cause our actual
costs to vary outside the range of our estimates, further
constrain our operations, increase our environmental compliance
costs and/or
make it uneconomical to operate some of our facilities.
Environmental laws, particularly with respect to air emissions,
disposal of ash, wastewater discharge and cooling water systems,
are generally becoming more stringent, which may require us to
make additional facility upgrades or restrict our operations.
We are required to surrender emission allowances equal to
emissions of specific substances to operate our facilities.
Surrender requirements may require purchase of allowances, which
may be unavailable or only available at costs that would make it
uneconomical to operate our facilities.
Federal, state and regional initiatives to regulate greenhouse
gas emissions could have a material impact on our financial
performance and condition. The actual impact will depend on a
number of factors, including the overall level of greenhouse gas
reductions required under any such regulations, the final form
of the regulations or legislation, and the price and
availability of emission allowances if allowances are a part of
the final regulatory framework. See
BusinessEnvironmental Matters in Item 1,
Managements Discussion and Analysis of Financial
Condition and Results of OperationsBusiness Overview
in Item 7 of this
Form 10-K
and note 9 to our consolidated financial statements.
Certain environmental laws, including the Comprehensive
Environmental Response, Compensation and Liability Act of 1980
and comparable state laws, impose strict and, in many
circumstances, joint and several liability for costs of
remediating contamination. Some of our facilities have areas
with known soil
and/or
groundwater contamination. Releases of hazardous substances at
our generating facilities, or at locations where we dispose of
(or in the past disposed of) hazardous substances and other
waste, could require us to spend significant sums to remediate
contamination, regardless of whether we caused such
contamination. The discovery of significant contamination at our
generating facilities, at disposal sites we currently use or
have used, or at other locations for which we may be liable, or
the failure or inability of parties contractually responsible to
us for contamination to respond when claims or obligations
regarding such contamination arise, could have a material
adverse effect on our financial performance and condition.
32
Our
coal-fired generating units produce certain byproducts that
involve extensive handling and disposal costs and are subject to
government regulation. Changes in these regulations, or their
administration, by legislatures, state and federal regulatory
agencies, or other bodies may affect the costs of handling and
disposing of these byproducts.
As a result of the coal combustion process, we produce
significant quantities of ash at our coal-fired generating units
that must be disposed of at sites permitted to handle ash. For
most of our ash disposal, we use our own ash management
facilities, which are all dry landfills to dispose of the ash;
however, one of our landfills in Maryland has reached design
capacity and we expect that another one of our sites in Maryland
may reach full capacity in the next few years. As a result, we
have a plan to develop new ash management facilities and also
commenced construction in February 2011 of a facility that is
designed to prepare our ash from certain of our Maryland
facilities for beneficial uses. However, the costs associated
with purchasing new land and permitting the land to allow for
ash disposal could be material, and the amount of time needed to
obtain permits for the land could extend beyond the expected
timeline. Likewise, the ongoing construction of a facility to
prepare our ash for beneficial use may be delayed, cost more
than expected or not operate as expected; or the ash may not be
marketed and sold as expected. Additionally, costs associated
with third-party ash handling and disposal are material and
could have an adverse effect on our financial performance and
condition.
We also produce gypsum as a byproduct of the
SO2
scrubbing process at our coal-fired generating facilities, which
is sold to third parties for use in drywall production. Should
our ability to sell such gypsum to third parties be restricted
as a result of the lack of demand or otherwise, our gypsum
disposal costs could rise materially.
The EPA has proposed two alternatives for regulating byproducts
such as ash and gypsum. One of these alternatives would regulate
these byproducts as special wastes in a manner
similar to the regulation of hazardous wastes. If these
byproducts are regulated as special wastes, the cost of
disposing of these byproducts would increase materially and may
limit our ability to recycle them for beneficial use. The EPA
expects to finalize this rule in late 2011.
Our
business is subject to complex government regulations. Changes
in these regulations, or their administration, by legislatures,
state and federal regulatory agencies, or other bodies may
affect the prices at which we are able to sell the electricity
we produce, the costs of operating our generating facilities or
our ability to operate our facilities.
We are subject to regulation by the FERC regarding the rates,
terms and conditions of wholesale sales of electric capacity,
energy and ancillary services and other matters, including
mergers and acquisitions, the disposition of facilities under
the FERCs jurisdiction and the issuance of securities, as
well as by state agencies regarding physical aspects of our
generating facilities. The majority of our generation is sold at
market prices under market-based rate authority granted by the
FERC. If certain conditions are not met, the FERC has the
authority to withhold or rescind market-based rate authority and
require sales to be made based on
cost-of-service
rates. A loss of our market-based rate authority could have a
materially negative impact on our generating business.
Even when market-based rate authority has been granted, the FERC
may impose various forms of market mitigation measures,
including price caps and operating restrictions, when it
determines that potential market power might exist and that the
public interest requires such potential market power to be
mitigated. In addition to direct regulation by the FERC, most of
our facilities are subject to rules and terms of participation
imposed and administered by various ISOs and RTOs. Although
these entities are themselves ultimately regulated by the FERC,
they can impose rules, restrictions and terms of service that
are quasi-regulatory in nature and can have a material adverse
impact on our business. For example, ISOs and RTOs may impose
bidding and scheduling rules, both to curb the potential
exercise of market power and to ensure market functions. Such
actions may materially affect our ability to sell and the price
we receive for our energy, capacity and ancillary services.
33
To conduct our business, we must obtain and periodically renew
licenses, permits and approvals for our facilities. These
licenses, permits and approvals can be in addition to any
required environmental permits. No assurance can be provided
that we will be able to obtain and comply with all necessary
licenses, permits and approvals for these facilities. If we
cannot comply with all applicable regulations, our business,
results of operations and financial condition could be adversely
affected.
We cannot predict whether the federal or state legislatures will
adopt legislation relating to the restructuring of the energy
industry. There are proposals in many jurisdictions that would
either roll back or advance the movement toward competitive
markets for the supply of electricity, at both the wholesale and
retail levels. In addition, any future legislation favoring
large, vertically integrated utilities and a concentration of
ownership of such utilities could affect our ability to compete
successfully, and our business and results of operations could
be adversely affected. Similarly, any regulations or laws that
favor new generation over existing generation could adversely
affect our business and results of operations.
Risks
Related to Level of Indebtedness
Our
substantial indebtedness and operating lease obligations could
adversely affect our ability to raise additional capital to fund
our operations, limit our ability to react to changes in the
economy or our industry and prevent us from meeting or
refinancing our obligations.
At December 31, 2010, GenOn Americas Generations
consolidated indebtedness was $2.3 billion and GenOn
Mid-Atlantics consolidated debt was $22 million. In
addition, the present value of lease payments under the GenOn
Mid-Atlantic operating leases was approximately
$927 million (assuming a 10% discount rate) and the
termination value of the GenOn Mid-Atlantic operating leases was
$1.4 billion.
Our substantial indebtedness and operating lease obligations
could have important consequences for our liquidity, results of
operations, financial position and prospects, including our
ability to grow in accordance with our strategy. These
consequences include the following:
|
|
|
|
|
they may limit our ability to obtain additional debt or equity
financing for working capital, capital expenditures, debt
service requirements, acquisitions and general corporate or
other purposes;
|
|
|
|
a substantial portion of our cash flows from operations must be
dedicated to the payment of rent and principal and interest on
our indebtedness and will not be available for other purposes,
including our working capital, capital expenditures and other
general purposes;
|
|
|
|
the debt service requirements of our indebtedness could make it
difficult for us to satisfy or refinance our financial
obligations;
|
|
|
|
they may limit our flexibility in planning for and reacting to
changes in our industry;
|
|
|
|
they may place us at a competitive disadvantage compared to
other, less leveraged competitors; and
|
|
|
|
we may be more vulnerable in a downturn in general economic
conditions or in our business and we may be unable to carry out
capital expenditures that are important to our long-term growth
or necessary to comply with environmental regulations.
|
GenOn
Americas Generation and its subsidiaries that are holding
companies may not have access to sufficient cash to meet their
obligations if their subsidiaries, in particular GenOn
Mid-Atlantic, are unable to make distributions.
GenOn Americas Generation and certain of its subsidiaries are
holding companies and, as a result, GenOn Americas Generation is
dependent upon dividends, distributions and other payments from
its operating subsidiaries to generate the funds necessary to
meet its obligations. In particular, a substantial portion of
the cash from our operations is generated by GenOn Mid-Atlantic.
GenOn Mid-Atlantics ability to pay dividends and make
distributions is restricted under the terms of its operating
leases. Under its operating leases, GenOn Mid-Atlantic is not
permitted to make any distributions and other restricted
payments unless: (a) it satisfies the fixed charge coverage
ratio for the most recently ended period of four fiscal
quarters; (b) it is projected to
34
satisfy the fixed charge coverage ratio for each of the two
following periods of four fiscal quarters, commencing with the
fiscal quarter in which such payment is proposed to be made; and
(c) no significant lease default or event of default has
occurred and is continuing. In the event of a default under the
operating leases or if the restricted payment tests are not
satisfied, GenOn Mid-Atlantic would not be able to distribute
cash. At December 31, 2010, GenOn Mid-Atlantic satisfied
the restricted payments test.
We may
be unable to generate sufficient cash to service our debt and to
post required amounts of cash collateral necessary to hedge
economically market risk. (GenOn Americas
Generation)
Our ability to pay principal and interest on our debt depends on
our future operating performance. If our cash flows and capital
resources are insufficient to allow us to make scheduled
payments on our debt, we may have to reduce or delay capital
expenditures, sell assets, seek additional capital, restructure
or refinance. There can be no assurance that the terms of our
debt will allow these alternative measures, that the financial
markets will be available to us on acceptable terms or that such
measures would satisfy our scheduled debt service obligations.
If we do not comply with the payment and other material
covenants under our debt agreements, we could be required to
repay our debt immediately.
We seek to manage the risks associated with the volatility in
the price at which we sell power produced by our generating
facilities and in the prices of fuel, emissions allowances and
other inputs required to produce such power by entering into
hedging transactions. These asset management activities may
require us to post collateral either in the form of cash or
letters of credit. At December 31, 2010, we had
approximately $120 million of posted cash collateral and
GenOn had $195 million of letters of credit outstanding
under its revolving credit facility on our behalf primarily to
support our asset management activities, trading activities,
rent reserve requirements and other commercial arrangements. See
note 7 to our consolidated financial statements for further
information on our posted cash collateral and letters of credit.
Although we seek to structure transactions in a way that reduces
our potential liquidity needs for collateral, we may be unable
to execute our hedging strategy successfully if we are unable to
post the amount of collateral required to enter into and support
hedging contracts.
We are an active participant in energy exchange and clearing
markets. These markets require a per-contract initial margin to
be posted, regardless of the credit quality of the participant.
The initial margins are determined by the exchanges through the
use of proprietary models that rely on a variety of inputs and
factors, including market conditions. We have limited notice of
any changes to the margin rates. Consequently, we are exposed to
changes in the per unit margin rates required by the exchanges
and could be required to post additional collateral on short
notice.
|
|
Item 1B.
|
Unresolved
Staff Comments.
|
None.
Our generating facilities are described under
BusinessBusiness Segments in Item 1 of
this
Form 10-K.
We own or lease oil and gas pipelines that serve our generating
facilities. We think that our properties are adequate for our
present needs. We have satisfactory title, rights and possession
to our owned facilities, subject to exceptions, which, in our
opinion, would not have a material adverse effect on the use or
value of the facilities.
|
|
Item 3.
|
Legal
Proceedings.
|
See note 9 to our consolidated financial statements for
discussion of the material legal proceedings to which we are a
party.
|
|
Item 4.
|
Removed
and Reserved by the SEC.
|
35
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities.
|
GenOn Americas Generation and GenOn Mid-Atlantic are indirect
wholly-owned subsidiaries of GenOn. Our membership interests are
not publicly traded. All of GenOn Americas Generations
membership interests are held by its parent, GenOn Americas. For
2010 and 2009, GenOn Americas Generation made cash distributions
to GenOn Americas of $222 million and $115 million,
respectively. See Item 7, Managements
Discussion and AnalysisLiquidity and Capital
Resources for additional information. All of GenOn
Mid-Atlantics membership interests are held by its parent,
GenOn North America. For 2010 and 2009, GenOn Mid-Atlantic made
cash distributions to GenOn North America of $350 million
and $125 million, respectively. We have no equity
compensation plans under which we issue our membership interests.
|
|
Item 6.
|
Selected
Financial Data.
|
The following discussion should be read in conjunction with our
consolidated financial statements and the notes thereto, which
are in this
Form 10-K.
The following tables present our selected consolidated financial
information, which is derived from our consolidated financial
statements.
GenOn
Americas Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in millions)
|
|
|
Statements of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
2,105
|
|
|
$
|
2,309
|
|
|
$
|
3,188
|
|
|
$
|
2,041
|
|
|
$
|
3,257
|
|
Income (loss) from continuing operations
|
|
|
(396
|
)
|
|
|
476
|
|
|
|
1,198
|
|
|
|
(68
|
)
|
|
|
1,197
|
|
Net income (loss)
|
|
$
|
(396
|
)
|
|
$
|
476
|
|
|
$
|
1,198
|
|
|
$
|
(60
|
)
|
|
$
|
1,200
|
|
Our Statement of Operations Data for each year reflects the
volatility caused by unrealized gains and losses related to
derivative financial instruments used to hedge economically
electricity and fuel. Changes in the fair value and settlements
of derivative financial instruments used to hedge economically
electricity are reflected in operating revenue and changes in
the fair value and settlements of derivative financial
instruments used to hedge economically fuel 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. See note 2 to our consolidated financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in millions)
|
|
|
Unrealized gains (losses) included in operating revenues
|
|
$
|
72
|
|
|
$
|
(2
|
)
|
|
$
|
840
|
|
|
$
|
(652
|
)
|
|
$
|
711
|
|
Unrealized (gains) losses included in cost of fuel, electricity
and other products
|
|
|
89
|
|
|
|
(49
|
)
|
|
|
54
|
|
|
|
(28
|
)
|
|
|
102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(17
|
)
|
|
$
|
47
|
|
|
$
|
786
|
|
|
$
|
(624
|
)
|
|
$
|
609
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For 2010, net loss reflects the following:
|
|
|
|
|
$565 million of impairment losses related to our Dickerson
and Potomac River generating facilities. See note 3(d) to
our consolidated financial statements for further information on
these impairments.
|
|
|
|
$9 million in write-off of unamortized debt issuance costs.
See note 4 to our consolidated financial statements for
further information on the debt transactions.
|
For 2009, net income reflects the following:
|
|
|
|
|
$221 million of impairment losses related to our Potomac
River generating facility and intangible assets related to our
Potrero and Contra Costa generating facilities. See
note 3(d) to our consolidated financial statements for
further information on these impairments.
|
36
For 2007, net loss reflects the following:
|
|
|
|
|
$175 million impairment loss related to our Lovett
generating facility.
|
For 2006, net income reflects the following:
|
|
|
|
|
$120 million impairment loss related to suspended
construction at our Bowline generating facility; and
|
|
|
|
$244 million gain from a New York property tax settlement.
|
The consolidated Balance Sheet Data at December 31, 2006
segregates pre-petition liabilities subject to compromise from
those liabilities that were not subject to compromise.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in millions)
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
7,813
|
|
|
$
|
7,517
|
|
|
$
|
8,552
|
|
|
$
|
5,936
|
|
|
$
|
7,177
|
|
Current portion of long-term debt
|
|
|
1,389
|
|
|
|
74
|
|
|
|
45
|
|
|
|
141
|
|
|
|
141
|
|
Long-term debt, net of current portion
|
|
|
866
|
|
|
|
2,556
|
|
|
|
2,630
|
|
|
|
2,952
|
|
|
|
3,131
|
|
Liabilities subject to compromise
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
|
|
Members equity
|
|
$
|
3,585
|
|
|
$
|
2,829
|
|
|
$
|
2,384
|
|
|
$
|
1,169
|
|
|
$
|
1,644
|
|
The amounts for 2010 reflect the debt transactions related to
GenOn North America in connection with the Merger. For
additional information on the GenOn North America debt
transactions, see note 4 to our consolidated financial
statements.
In 2010, we reclassified the principal balance of our senior
notes due in May 2011 from long-term debt to current portion of
long-term debt.
In 2005, we recorded the effects of the Plan. As a result,
liabilities subject to compromise at December 31, 2006,
only reflect the liabilities of our New York entities that
remained in bankruptcy at that time. Total assets for all
periods reflect our election in 2008 to discontinue the net
presentation of assets subject to master netting agreements upon
adoption of the accounting guidance for offsetting amounts
related to certain contracts.
GenOn
Mid-Atlantic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in millions)
|
|
|
Statements of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
1,704
|
|
|
$
|
1,778
|
|
|
$
|
2,279
|
|
|
$
|
1,133
|
|
|
$
|
1,901
|
|
Net income (loss)
|
|
$
|
(781
|
)
|
|
$
|
344
|
|
|
$
|
1,217
|
|
|
$
|
169
|
|
|
$
|
922
|
|
Our Statement of Operations Data for each year reflects the
volatility caused by unrealized gains and losses related to
derivative financial instruments used to hedge economically
electricity and fuel. Changes in the fair value and settlements
of derivative financial instruments used to hedge economically
electricity are reflected in operating revenue and changes in
the fair value and settlements of derivative financial
instruments used to hedge economically fuel are reflected in
cost of fuel, electricity and other products in the consolidated
statements of operations. See note 2 to our consolidated
financial statements for additional information.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in millions)
|
|
|
Unrealized gains (losses) included in operating revenues
|
|
$
|
80
|
|
|
$
|
136
|
|
|
$
|
685
|
|
|
$
|
(474
|
)
|
|
$
|
519
|
|
Unrealized (gains) losses included in cost of fuel, electricity
and other products
|
|
|
73
|
|
|
|
(8
|
)
|
|
|
9
|
|
|
|
5
|
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
7
|
|
|
$
|
144
|
|
|
$
|
676
|
|
|
$
|
(479
|
)
|
|
$
|
484
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37
For 2010, net loss reflects the following before taxes:
|
|
|
|
|
$1.153 billion of impairment losses related to our
Dickerson and Potomac River generating facilities and goodwill
recorded at the GenOn Mid-Atlantic registrant on its standalone
balance sheet. The goodwill impairment loss and related goodwill
balance are eliminated upon consolidation at GenOn North America
and are not reflected on the consolidated balance sheet of GenOn
Americas Generation. See note 3(d) to our consolidated
financial statements for further information on these
impairments.
|
For 2009, net income reflects the following:
|
|
|
|
|
$385 million of impairment losses related to our Potomac
River generating facility and goodwill recorded at the GenOn
Mid-Atlantic registrant on its standalone balance sheet. See
note 3(d) to our consolidated financial statements for
further information on these impairments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in millions)
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
4,626
|
|
|
$
|
5,807
|
|
|
$
|
5,620
|
|
|
$
|
4,008
|
|
|
$
|
3,947
|
|
Current portion of long-term debt
|
|
|
4
|
|
|
|
4
|
|
|
|
3
|
|
|
|
3
|
|
|
|
3
|
|
Long-term debt, net of current portion
|
|
|
18
|
|
|
|
21
|
|
|
|
25
|
|
|
|
27
|
|
|
|
31
|
|
Members equity
|
|
$
|
3,900
|
|
|
$
|
4,886
|
|
|
$
|
4,583
|
|
|
$
|
3,407
|
|
|
$
|
3,292
|
|
Total assets for all periods reflect our election in 2008 to
discontinue the net presentation of assets subject to master
netting agreements upon adoption of the accounting guidance for
offsetting amounts related to certain contracts.
38
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations.
|
A. GenOn
Americas Generation
This section is intended to provide the reader with information
that will assist in understanding GenOn Americas
Generations financial statements, the changes in those
financial statements from year to year and the primary factors
contributing to those changes. The following discussion should
be read in conjunction with GenOn Americas Generations
consolidated financial statements and the notes accompanying
those financial statements.
Merger of
Mirant and RRI Energy
On December 3, 2010, Mirant and RRI Energy completed their
Merger. Mirant merged with a wholly-owned subsidiary of RRI
Energy, with Mirant surviving the Merger as a wholly-owned
subsidiary of RRI Energy. In connection with the all-stock,
tax-free Merger, RRI Energy changed its name to GenOn Energy,
Inc., Mirant stockholders received a fixed ratio of
2.835 shares of GenOn common stock for each share of Mirant
common stock, and Mirant changed its name to GenOn Energy
Holdings.
Our
Business
With approximately 9,724 MW of electric generating
capacity, we operate across various fuel (natural gas, coal and
oil) and technology types, operating characteristics and
regional power markets. At December 31, 2010, our
generating capacity was 52% in PJM, 23% in CAISO and 25% in
NYISO and ISO-NE.
We provide energy, capacity, ancillary and other energy services
to wholesale customers in competitive energy markets in the
United States, including ISOs and RTOs, power aggregators,
retail providers, electric-cooperative utilities, other power
generating companies and load serving entities. Our commercial
operations consist primarily of dispatching electricity, hedging
the generation and sale of electricity, procuring and managing
fuel and providing logistical support for the operation of our
facilities (e.g., by procuring transportation for coal and
natural gas), as well as our proprietary trading operations.
We typically sell the electricity we produce into the wholesale
market at prices in effect at the time we produce it (spot
price). We use dispatch models to assist in making daily bidding
decisions regarding the quantity and price of the power we offer
to generate from our facilities and sell into the markets. We
bid the energy from our generating facilities into the
hour-ahead or day-ahead energy market and sell ancillary
services through the ISO and RTO markets. We work with the ISOs
and RTOs in real time to ensure that our generating facilities
are dispatched economically to meet the reliability needs of the
market.
Spot prices for electricity are volatile, as are prices for fuel
and emissions allowances. In order to reduce the risk of price
volatility and achieve more predictable financial results, we
have historically entered into economic hedgesforward
sales of electricity and forward purchases of fuel and emissions
allowances to permit us to produce and sell the
electricityto manage the risks associated with such
volatility. In addition, given the high correlation between
natural gas prices and electricity prices in the markets in
which we operate, we have entered into forward sales of natural
gas to hedge economically exposure to changes in the price of
electricity. We procure hedges in OTC transactions or on
exchanges where electricity, fuel and emissions allowances are
broadly traded, or through specific transactions with buyers and
sellers, using futures, forwards, swaps and options.
We sell capacity either bilaterally or through periodic auctions
in each ISO and RTO market in which we participate. These
capacity sales provide an important source of predictable
revenues for us over the contracted period. At January 31,
2011, total projected contracted capacity and PPA revenues for
which prices have been set for 2011 through 2014 are
$1.3 billion.
In addition to the activities described above, we buy and sell
some electricity, fuel and emissions allowances, sometimes
through financial derivatives, as part of our proprietary
trading and fuel oil management activities. We engage in
proprietary trading to gain information about the markets in
which we operate to support our asset management and to take
advantage of selected opportunities that we identify. We enter
into
39
fuel oil management activities to hedge economically the fair
value of our physical fuel oil inventories, optimize the
approximately three million barrels of storage capacity that we
own or lease, as well as attempt to profit from market
opportunities related to timing
and/or
differences in the pricing of various products. Proprietary
trading and fuel oil management activities together will
typically comprise less than 10% of our realized gross margin.
All of our commercial activities are governed by a comprehensive
risk management policy, which includes limits on the size of
volumetric positions and VaR for our proprietary trading and
fuel oil management activities. For 2010, the combined average
daily VaR for proprietary trading and fuel oil management
activities was $2 million.
Hedging
Activities
We hedge economically a substantial portion of our Eastern PJM
coal-fired baseload generation and certain of our other
generation. We generally do not hedge our intermediate and
peaking units for tenors greater than 12 months. We hedge
economically using products which we expect to be effective to
mitigate the price risk of our generation. However, as a result
of market liquidity limitations, our hedges often are not an
exact match for the generation being hedged, and, we then have
some risks resulting from price differentials for different
delivery points and for implied differences in heat rates when
we hedge economically power using natural gas. Currently, a
significant portion of our hedges are financial swap
transactions between GenOn Mid-Atlantic and financial
counterparties that are senior unsecured obligations of such
parties and do not require either party to post cash collateral
either for initial margin or for securing exposure as a result
of changes in power or natural gas prices. At January 31,
2011, our aggregate hedge levels based on expected generation
for each year were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011(1)
|
|
2012
|
|
2013
|
|
2014
|
|
2015
|
|
Power
|
|
|
91
|
%
|
|
|
78
|
%
|
|
|
37
|
%
|
|
|
35
|
%
|
|
|
|
%
|
Fuel
|
|
|
89
|
%
|
|
|
77
|
%
|
|
|
51
|
%
|
|
|
|
%
|
|
|
|
%
|
|
|
|
(1) |
|
Percentages represent the period from February through
December 2011. |
See Item 1A, Risk FactorsRisks Related to
Economic and Financial Market Conditions for a discussion
of:
|
|
|
|
|
the risks of consolidation of financial institutions and more
restrictive capital constraints and regulation, which could have
a negative effect on our ability to hedge economically with
creditworthy counterparties; and
|
|
|
|
the risks of implementation of the Dodd-Frank Act on our ability
to hedge economically our generation, including potentially
reducing liquidity in the energy and commodity markets and, if
we are required to clear such transactions on exchanges or meet
other requirements, by significantly increasing the collateral
costs associated with such activities.
|
Capital
Expenditures and Capital Resources
For 2010, we invested $247 million for capital
expenditures, excluding capitalized interest, of which
$114 million related to compliance with the Maryland
Healthy Air Act. At December 31, 2010, we have invested
$1.519 billion of the $1.674 billion that was budgeted
for capital expenditures related to compliance with the Maryland
Healthy Air Act. As the final part of our compliance with the
Maryland Healthy Air Act, we placed four scrubbers in service at
our Maryland facilities in the fourth quarter of 2009.
Provisions in the construction contracts for the scrubbers
provide for certain payments to be made after final completion
of the project. The current budget of $1.674 billion
continues to represent our best estimate of the total capital
expenditures for compliance with the Maryland Healthy Air Act.
See note 9 to our consolidated financial statements for
further discussion of scrubber contract litigation.
For 2010, our capitalized interest was $5 million compared
to $72 million for 2009. The decrease in capitalized
interest from 2009 is a result of placing our scrubbers in
service at our Maryland facilities in the fourth quarter of 2009.
40
The following table details the expected timing of payments for
our estimated capital expenditures, excluding capitalized
interest, for 2011 and 2012:
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
2012
|
|
|
|
(in millions)
|
|
|
Maryland Healthy Air Act
|
|
$
|
155
|
|
|
$
|
|
|
Other environmental
|
|
|
7
|
|
|
|
9
|
|
Maintenance
|
|
|
52
|
|
|
|
40
|
|
Other construction
|
|
|
52
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
266
|
|
|
$
|
53
|
|
|
|
|
|
|
|
|
|
|
We expect that available cash and future cash flows from
operations will be sufficient to fund these capital expenditures.
Environmental
Matters
We make decisions to invest capital for environmental controls
based on relatively certain regulations and the expected
economic returns on the capital. As discussed in Part 1 of
this
Form 10-K
under BusinessRegulatory
EnvironmentEnvironmental Regulation, the effect on
our business of pending EPA regulations to replace the CAIR and
whether we elect to install additional controls are uncertain
and depend on the content and timing of the regulations, the
expected effect of the regulations on wholesale power prices and
allowance prices, as well as the cost of controls, profitability
of our generating facilities, market conditions at the time and
the likelihood of
CO2
regulation. The EPA has stated that it expects to finalize the
regulations to replace the CAIR in 2011. We may choose to retire
certain of our units rather than install additional controls.
The costs associated with more stringent environmental air
quality requirements may result in coal-fired generating
facilities, including some of ours, being retired. Although
conditions may change, under current and forecasted market
conditions, installations of additional scrubbers would not be
economic at most of our unscrubbed coal-fired facilities. Any
such retirements could contribute to improving supply and demand
fundamentals for the remaining fleet. Any resulting increased
demand for gas could increase the spread between gas and coal
prices, which would also benefit the remaining coal-fired
generating facilities.
Furthermore, federal, state-specific or regional regulatory
initiatives to stimulate
CO2
emission reductions in our industry are being considered. The
effect on our business of these matters is uncertain and depends
on the form and content of resulting regulations, if any,
including their effect on (a) wholesale electricity and
emissions allowance prices and (b) other existing
regulations such as the RGGI.
If
CO2
regulation becomes more stringent, we expect that the demand for
gas and/or
renewable sources of electricity will increase over time.
Although we expect that market prices for electricity would
increase following such regulation and would allow us to recover
a portion of the resulting costs, we cannot predict with any
certainty the actual increases in costs such regulation could
impose upon us or our ability to recover such cost increases
through higher market rates for electricity. It is possible that
Congress will take action to regulate greenhouse gas emissions
within the next several years. The form and timing of any final
legislation will be influenced by political and economic factors
and are uncertain at this time. Implementation of a
CO2
cap-and-trade
program in addition to other emission control requirements could
increase the likelihood of coal-fired generating facility
retirements.
Given the uncertainty related to these environmental matters, we
cannot predict their actual outcome or ultimate effect on our
business, and such matters could result in a material adverse
effect on our results of operations, financial position and cash
flows. See BusinessRegulatory
EnvironmentEnvironmental Regulation and Risk
FactorsRisks Related to Governmental Regulation and
Laws in Items 1 and 1A, respectively, of this
Form 10-K
and note 9 to our consolidated financial statements for
further discussion.
41
Commodity
Prices
The prices for power and natural gas remain low compared to
several years ago. The energy gross margin from our generating
facilities is negatively affected by these price levels. For
that portion of the volumes of generation that we have hedged,
we are generally economically neutral to subsequent changes in
commodity prices because our realized gross margin will reflect
the contractual prices of our power and fuel contracts. We
continue to add economic hedges, including to maintain projected
levels of cash flows from operations for future periods to help
support continued compliance with the covenants in our debt and
lease agreements.
California
Development Activities
Contra
Costa Toll Extension
On September 2, 2009, GenOn Delta entered into an agreement
with PG&E for the 674 MW of Contra Costa units 6 and 7
for the period from November 2011 through April 2013. At the end
of the agreement, and subject to any necessary regulatory
approval, GenOn Delta has agreed to retire Contra Costa units 6
and 7, which began operations in 1964, in furtherance of state
and federal policies to retire aging power plants that utilize
once-through cooling technology.
Pittsburg
Toll Extension
On October 28, 2010, GenOn Delta entered into an agreement
with PG&E for 1,159 MW of capacity from Pittsburg
units 5, 6 and 7 for three years commencing January 1,
2011, with options for PG&E to extend the agreement for
each of 2014 and 2015. Under the agreement, GenOn Delta will
receive monthly capacity payments with bonuses
and/or
penalties based on heat rate and availability.
Potrero
Settlement
On August 13, 2009, GenOn Potrero entered into a settlement
agreement (Potrero Settlement) with the City and County of
San Francisco. Among other things, the Potrero Settlement
obligates GenOn Potrero to close permanently each of the
remaining units of the Potrero generating facility at the end of
the year in which the CAISO determines that such unit is no
longer needed to maintain the reliable operation of the
electricity system. In December 2010, the CAISO provided GenOn
Potrero with the requisite notice of termination of the RMR
agreement. On January 19, 2011, at the request of GenOn
Potrero, the FERC approved changes to GenOn Potreros RMR
agreement to allow the CAISO to terminate the RMR agreement
effective February 28, 2011. On February 28, 2011, the
Potrero facility was shut down. See note 10 to our
consolidated financial statements for further discussion of the
Potrero Settlement.
IBEW
Local 1900 Collective Bargaining Agreement
During the second quarter of 2010, GenOn Energy Services entered
into a new collective bargaining agreement with our employees
represented by IBEW Local 1900 (located in Maryland and
Virginia). The previous collective bargaining agreement expired
on June 1, 2010. The new agreement has a five-year term
expiring on June 1, 2015. As part of the new agreement,
GenOn Energy Services is required to provide additional
retirement contributions through the defined contribution plan
currently sponsored by GenOn Energy Services, increases in pay
and other benefits. In addition, the agreement provides for a
change to the postretirement healthcare benefit plan covering
IBEW Local 1900 union employees to eliminate employer-provided
healthcare subsidies through a gradual phase-out. We will
reimburse GenOn Energy Services for the costs associated with
providing the benefits through the Administrative Services
Agreement. See note 6 to our consolidated financial
statements for additional information on the arrangements with
related parties.
Results
of Operations
Non-GAAP Performance Measures. The
following discussion includes the non-GAAP financial measures
realized gross margin and unrealized gross margin to reflect how
we manage our business. In our discussion of the results of our
reportable segments, we include the components of realized gross
margin, which are
42
energy, contracted and capacity, and realized value of hedges.
Management generally evaluates our operating results excluding
the impact of unrealized gains and losses. When viewed with our
GAAP financial results, these non-GAAP financial measures may
provide a more complete understanding of factors and trends
affecting our business. Realized gross margin represents our
gross margin (excluding depreciation and amortization) less
unrealized gains and losses on derivative financial instruments.
Conversely, unrealized gross margin represents our unrealized
gains and losses on derivative financial instruments. None of
our derivative financial instruments recorded at fair value is
designated as a hedge and changes in their fair values are
recognized currently in income as unrealized gains or losses. As
a result, our financial results are, at times, volatile and
subject to fluctuations in value primarily because of changes in
forward electricity and fuel prices. Realized gross margin,
together with its components energy, contracted and capacity and
realized value of hedges, provide a measure of performance that
eliminates the volatility reflected in unrealized gross margin,
which is created by significant shifts in market values between
periods. However, these non-GAAP financial measures may not be
comparable to similarly titled non-GAAP financial measures used
by other companies. We use these non-GAAP financial measures in
communications with investors, analysts, rating agencies, banks
and other parties. We think these non-GAAP financial measures
provide meaningful representations of our consolidated operating
performance and are useful to us and others in facilitating the
analysis of our results of operations from one period to
another. We encourage our investors to review our consolidated
financial statements and other publicly filed reports in their
entirety and not to rely on a single financial measure.
2010
Compared to 2009
Consolidated
Financial Performance
We reported net loss of $396 million and net income of
$476 million for 2010 and 2009, respectively. The change in
net income/loss is detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2010
|
|
|
2009
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
|
Realized gross margin
|
|
$
|
1,268
|
|
|
$
|
1,552
|
|
|
$
|
(284
|
)
|
Unrealized gross margin
|
|
|
(17
|
)
|
|
|
47
|
|
|
|
(64
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross margin (excluding depreciation and amortization)
|
|
|
1,251
|
|
|
|
1,599
|
|
|
|
(348
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenancenonaffiliate
|
|
|
390
|
|
|
|
355
|
|
|
|
35
|
|
Operations and maintenanceaffiliate
|
|
|
293
|
|
|
|
290
|
|
|
|
3
|
|
Depreciation and amortization
|
|
|
199
|
|
|
|
142
|
|
|
|
57
|
|
Impairment losses
|
|
|
565
|
|
|
|
221
|
|
|
|
344
|
|
Gain on sales of assets, net
|
|
|
(9
|
)
|
|
|
(22
|
)
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
1,438
|
|
|
|
986
|
|
|
|
452
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(187
|
)
|
|
|
613
|
|
|
|
(800
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other expense, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
200
|
|
|
|
136
|
|
|
|
64
|
|
Other, net
|
|
|
9
|
|
|
|
1
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense, net
|
|
|
209
|
|
|
|
137
|
|
|
|
72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(396
|
)
|
|
$
|
476
|
|
|
$
|
(872
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Gross Margin. For 2010, our realized
gross margin decrease of $284 million was principally a
result of the following:
|
|
|
|
|
a decrease of $337 million in realized value of hedges. In
2010 and 2009, realized value of hedges was $292 million
and $629 million, respectively, which reflects the amount
by which the settlement value
|
43
|
|
|
|
|
of power contracts exceeded market prices for power, offset in
part by the amount by which contract prices for fuel exceeded
market prices for fuel; and
|
|
|
|
|
|
a decrease of $25 million in contracted and capacity
primarily as a result of a decrease in capacity prices in
Eastern PJM, offset in part by an increase in ancillary services
revenue and additional megawatts of capacity sold in Eastern
PJM; partially offset by
|
|
|
|
an increase of $78 million in energy, primarily as a result
of an increase in energy in Eastern PJM because of an increase
in the average settlement price for power, a decrease in the
cost of emissions allowances and higher generation volumes,
offset in part by a decrease in realized gross margin from
proprietary trading and fuel oil management activities in Energy
Marketing and an increase in the average price of fuel.
|
Unrealized Gross Margin. Our unrealized gross
margin for both periods reflects the following:
|
|
|
|
|
unrealized losses of $17 million in 2010, which included
$387 million associated with the reversal of previously
recognized unrealized gains from power and fuel contracts that
settled during the period, substantially offset by a
$370 million net increase in the value of hedge and
proprietary trading contracts for future periods. The increase
in value was primarily related to decreases in forward power and
natural gas prices, offset in part by the recognition of many of
our coal agreements at fair value beginning in the second
quarter of 2010; and
|
|
|
|
unrealized gains of $47 million in 2009, which included a
$686 million net increase in the value of hedge and trading
contracts for future periods primarily related to decreases in
forward power and natural gas prices, substantially offset by
$639 million associated with the reversal of previously
recognized unrealized gains from power and fuel contracts that
settled during the period.
|
Operating Expenses. Our operating expenses
increase of $452 million was primarily a result of the
following:
|
|
|
|
|
an increase of $344 million in impairment losses. In 2010,
we recognized $565 million in impairment losses related to
our Dickerson and Potomac River generating facilities. In 2009,
we recognized $221 million in impairment losses related to
our Potomac River generating facility and intangible assets
related to our Potrero and Contra Costa generating facilities.
See note 3(d) to our consolidated financial statements for
additional information related to our impairment reviews;
|
|
|
|
an increase of $57 million in depreciation and amortization
expense primarily as a result of the scrubbers at our Maryland
generating facilities that were placed in service in December
2009;
|
|
|
|
an increase of $38 million in operations and maintenance
expense primarily related to the following:
|
|
|
|
|
|
an increase of $32 million related to the recognition of a
liability associated with our commitment to reduce particulate
emissions at our Potomac River generating facility as a part of
the agreement with the City of Alexandria, Virginia because the
planned capital investment would not be recovered in future
periods based on the current projected cash flows for the
Potomac River generating facility and the full impairment of the
facility in 2010. See note 3(d) to our consolidated
financial statements for additional information related to our
impairment reviews; and
|
|
|
|
an increase of $27 million primarily as a result of an
increase in costs related to the operation of the scrubbers at
our Maryland generating facilities and the Montgomery County,
Maryland
CO2
levy imposed on our Dickerson generating facility beginning in
May 2010, offset in part by a decrease in planned maintenance
costs in 2010 compared to 2009; offset in part by
|
|
|
|
a decrease of $18 million primarily related to lower
property taxes because of a lower assessed value for the Lovett
generating facility which was demolished in 2009 and a decrease
in shutdown costs associated with this generating
facility; and
|
|
|
|
|
|
a decrease of $13 million in gain on sales of assets
primarily related to emissions allowances sold to third parties
in 2009.
|
44
Interest Expense, Net. Interest expense, net
increase of $64 million was primarily a result lower
capitalized interest because of the scrubbers at our Maryland
generating facilities that were placed in service in December
2009.
Other, Net. Other, net increase of
$8 million was primarily a result of a $9 million
write-off of unamortized debt issuance costs related to the
GenOn North America senior secured term loan that was repaid in
2010.
Segments
The following discussion of our performance is organized by
reportable segment, which is consistent with the way we manage
our business. We previously had four reportable segments:
Mid-Atlantic, Northeast, California and Other Operations. In the
fourth quarter of 2010, in conjunction with the Merger, we began
reporting in five segments: Eastern PJM, Northeast, California,
Energy Marketing and Other Operations. We reclassified amounts
for 2009 and 2008 to conform to the current segment presentation.
In the tables below, the Eastern PJM segment consists of four
generating facilities located in Maryland and Virginia. The
Northeast segment consists of four generating facilities located
in Massachusetts and New York. The California segment consists
of three generating facilities located in northern California.
The Energy Marketing segment consists of proprietary trading and
fuel oil management activities. Other Operations consists of
parent company adjustments for affiliate transactions and other
activities that cannot be specifically identified to another
segment. In the following tables, eliminations are primarily
related to intercompany sales of emissions allowances.
Gross
Margin Overview
The following tables detail realized and unrealized gross margin
for 2010 and 2009, by operating segments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
|
Eastern
|
|
|
|
|
|
|
|
|
Energy
|
|
|
|
|
|
|
|
|
|
PJM
|
|
|
Northeast
|
|
|
California
|
|
|
Marketing
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
(in millions)
|
|
|
Energy
|
|
$
|
384
|
|
|
$
|
19
|
|
|
$
|
|
|
|
$
|
32
|
|
|
$
|
|
|
|
$
|
435
|
|
Contracted and capacity
|
|
|
335
|
|
|
|
85
|
|
|
|
121
|
|
|
|
|
|
|
|
|
|
|
|
541
|
|
Realized value of hedges
|
|
|
280
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized gross margin
|
|
|
999
|
|
|
|
116
|
|
|
|
121
|
|
|
|
32
|
|
|
|
|
|
|
|
1,268
|
|
Unrealized gross margin
|
|
|
7
|
|
|
|
(19
|
)
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
(17
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross
margin(1)
|
|
$
|
1,006
|
|
|
$
|
97
|
|
|
$
|
121
|
|
|
$
|
27
|
|
|
$
|
|
|
|
$
|
1,251
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
Eastern
|
|
|
|
|
|
|
|
|
Energy
|
|
|
|
|
|
|
|
|
|
PJM
|
|
|
Northeast
|
|
|
California
|
|
|
Marketing
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
Energy
|
|
$
|
170
|
|
|
$
|
23
|
|
|
$
|
|
|
|
$
|
167
|
|
|
$
|
(3
|
)
|
|
$
|
357
|
|
Contracted and capacity
|
|
|
351
|
|
|
|
93
|
|
|
|
122
|
|
|
|
|
|
|
|
|
|
|
|
566
|
|
Realized value of hedges
|
|
|
586
|
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized gross margin
|
|
|
1,107
|
|
|
|
159
|
|
|
|
122
|
|
|
|
167
|
|
|
|
(3
|
)
|
|
|
1,552
|
|
Unrealized gross margin
|
|
|
144
|
|
|
|
16
|
|
|
|
|
|
|
|
(113
|
)
|
|
|
|
|
|
|
47
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross
margin(1)
|
|
$
|
1,251
|
|
|
$
|
175
|
|
|
$
|
122
|
|
|
$
|
54
|
|
|
$
|
(3
|
)
|
|
$
|
1,599
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gross margin excludes depreciation and amortization. |
45
Energy represents gross margin from the generation of
electricity, fuel sales and purchases at market prices, fuel
handling, steam sales and our proprietary trading and fuel oil
management activities.
Contracted and capacity represents gross margin received from
capacity sold in ISO and RTO administered capacity markets,
through RMR contracts(for 2010 and 2009), through PPAs and
tolling agreements and from ancillary services.
Realized value of hedges represents the actual margin upon the
settlement of our power and fuel hedging contracts and the
difference between market prices and contract costs for fuel.
Power hedging contracts include sales of both power and natural
gas used to hedge power prices, as well as hedges to capture the
incremental value related to the geographic location of our
physical assets.
Unrealized gross margin represents the net unrealized gain or
loss on our derivative contracts, including the reversal of
unrealized gains and losses recognized in prior periods and
changes in value for future periods.
Operating
Statistics
The following table summarizes net capacity factor by segment
for 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2010
|
|
|
2009
|
|
|
(Decrease)
|
|
|
Eastern PJM
|
|
|
34
|
%
|
|
|
30
|
%
|
|
|
4
|
%
|
Northeast
|
|
|
9
|
%
|
|
|
10
|
%
|
|
|
(1
|
)%
|
California
|
|
|
3
|
%
|
|
|
5
|
%
|
|
|
(2
|
)%
|
Energy Marketing
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Other Operations
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Total
|
|
|
20
|
%
|
|
|
19
|
%
|
|
|
1
|
%
|
The following table summarizes power generation volumes by
segment for 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
Increase/
|
|
|
|
2010
|
|
|
2009
|
|
|
(Decrease)
|
|
|
(Decrease)
|
|
|
|
(in gigawatt hours)
|
|
|
Eastern PJM:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Baseload
|
|
|
14,271
|
|
|
|
13,500
|
|
|
|
771
|
|
|
|
6
|
%
|
Intermediate
|
|
|
1,120
|
|
|
|
363
|
|
|
|
757
|
|
|
|
209
|
%
|
Peaking
|
|
|
218
|
|
|
|
92
|
|
|
|
126
|
|
|
|
137
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Eastern PJM
|
|
|
15,609
|
|
|
|
13,955
|
|
|
|
1,654
|
|
|
|
12
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Baseload
|
|
|
1,485
|
|
|
|
1,425
|
|
|
|
60
|
|
|
|
4
|
%
|
Intermediate
|
|
|
395
|
|
|
|
673
|
|
|
|
(278
|
)
|
|
|
(41
|
)%
|
Peaking
|
|
|
7
|
|
|
|
3
|
|
|
|
4
|
|
|
|
133
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Northeast
|
|
|
1,887
|
|
|
|
2,101
|
|
|
|
(214
|
)
|
|
|
(10
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intermediate
|
|
|
519
|
|
|
|
1,050
|
|
|
|
(531
|
)
|
|
|
(51
|
)%
|
Peaking(1)
|
|
|
(1
|
)
|
|
|
4
|
|
|
|
(5
|
)
|
|
|
(125
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total California
|
|
|
518
|
|
|
|
1,054
|
|
|
|
(536
|
)
|
|
|
(51
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
18,014
|
|
|
|
17,110
|
|
|
|
904
|
|
|
|
5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Negative amounts denote net energy used by the generating
facility. |
46
The total increase in power generation volumes for 2010, as
compared to 2009, is primarily the result of the following:
Eastern PJM. An increase in our generation
volumes primarily as a result of higher power prices resulting
from an increase in demand because of higher average
temperatures and a decrease in outages in 2010 compared to 2009.
Northeast. A decrease in our Northeast
intermediate generation as a result of transmission upgrades in
2009 which reduced the demand for the oil-fired intermediate
units at our Canal generating facility and unplanned outages in
2010, partially offset by increases in generation volumes in our
baseload and peaking units.
California. The decrease in our intermediate
generation volumes is primarily the result of the TransBay Cable
becoming operational during the fourth quarter of 2010, which
reduced the demand for our natural gas-fired Potrero generating
unit. See note 10 for further information on the Potrero
Settlement.
Eastern
PJM
Our Eastern PJM segment includes four generating facilities with
total net generating capacity of 5,204 MW. The following
table summarizes the results of operations of our Eastern PJM
segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2010
|
|
|
2009
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
|
Gross Margin:
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
$
|
384
|
|
|
$
|
170
|
|
|
$
|
214
|
|
Contracted and capacity
|
|
|
335
|
|
|
|
351
|
|
|
|
(16
|
)
|
Realized value of hedges
|
|
|
280
|
|
|
|
586
|
|
|
|
(306
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized gross margin
|
|
|
999
|
|
|
|
1,107
|
|
|
|
(108
|
)
|
Unrealized gross margin
|
|
|
7
|
|
|
|
144
|
|
|
|
(137
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross margin (excluding depreciation and amortization)
|
|
|
1,006
|
|
|
|
1,251
|
|
|
|
(245
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenance
|
|
|
493
|
|
|
|
434
|
|
|
|
59
|
|
Depreciation and amortization
|
|
|
141
|
|
|
|
98
|
|
|
|
43
|
|
Impairment losses
|
|
|
1,153
|
|
|
|
385
|
|
|
|
768
|
|
Gain on sales of assets, net
|
|
|
(3
|
)
|
|
|
(14
|
)
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
1,784
|
|
|
|
903
|
|
|
|
881
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
(778
|
)
|
|
$
|
348
|
|
|
$
|
(1,126
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
Margin
The decrease of $108 million in realized gross margin was
principally a result of the following:
|
|
|
|
|
a decrease of $306 million in realized value of hedges. In
2010 and 2009, realized value of hedges was $280 million
and $586 million, respectively, which reflects the amount
by which the settlement value of power contracts exceeded market
prices for power, partially offset by the amount by which
contract prices for coal exceeded market prices for
coal; and
|
|
|
|
a decrease of $16 million in contracted and capacity
primarily related to lower average capacity prices, offset in
part by an increase in ancillary services revenue and additional
megawatts of capacity sold in 2010; partially offset by
|
47
|
|
|
|
|
an increase of $214 million in energy, primarily as a
result of an increase in the average settlement price for power,
a decrease in the cost of emissions allowances and higher
generation volumes, offset in part by an increase in the average
price of fuel.
|
Our unrealized gross margin for both periods reflects the
following:
|
|
|
|
|
unrealized gains of $7 million in 2010, which included a
$326 million net increase in the value of hedge contracts
for future periods primarily related to decreases in forward
power and natural gas prices, offset in part by the recognition
of many of our coal agreements at fair value beginning in the
second quarter of 2010. The increase in value was substantially
offset by $319 million associated with the reversal of
previously recognized unrealized gains from power and fuel
contracts that settled during the period; and
|
|
|
|
unrealized gains of $144 million in 2009, which included a
$633 million net increase in the value of hedge contracts
for future periods primarily related to decreases in forward
power and natural gas prices, partially offset by
$489 million associated with the reversal of previously
recognized unrealized gains from power and fuel contracts that
settled during the period.
|
Operating
Expenses
The increase of $881 million was primarily a result of the
following:
|
|
|
|
|
an increase of $768 million in impairment losses. In 2010,
we recognized $1.2 billion in impairment losses, including
$616 million related to the write-off of goodwill recorded
at GenOn Mid-Atlantic on its standalone balance sheet and
$537 million related to our Dickerson and Potomac River
generating facilities. In 2009, we recognized $385 million
in impairment losses, including $202 million related to our
Potomac River generating facility and $183 million related
to goodwill recorded at our GenOn Mid-Atlantic registrant on its
standalone balance sheet. The goodwill does not exist at GenOn
Americas Generations consolidated balance sheet. As such,
the goodwill impairment loss and related goodwill balance are
eliminated upon consolidation at GenOn North America. See
note 3(d) to our consolidated financial statements for
additional information related to our impairment reviews;
|
|
|
|
an increase of $43 million in depreciation and amortization
expense primarily as a result of the scrubbers at our Maryland
generating facilities that were placed in service in December
2009, offset in part by a decrease in the carrying value of the
Potomac River generating facility as a result of the impairment
charge taken in the fourth quarter of 2009;
|
|
|
|
an increase of $32 million related to the recognition of a
liability associated with our commitment to reduce particulate
emissions at our Potomac River generating facility as part of
the agreement with the City of Alexandria, Virginia because the
planned capital investment would not be recovered in future
periods based on the current projected cash flows for the
Potomac River generating facility and the full impairment of the
facility in 2010. See note 3(d) to our consolidated
financial statements for additional information related to our
impairment reviews;
|
|
|
|
an increase of $27 million in operations and maintenance
expense primarily as a result of an increase in costs related to
the operation of the scrubbers at our Maryland generating
facilities and the Montgomery County, Maryland
CO2
levy imposed on our Dickerson generating facility beginning in
May 2010, offset in part by a decrease in planned maintenance
costs in 2010 compared to 2009; and
|
|
|
|
a decrease of $11 million in gain on sales of assets
primarily related to emissions allowances sold to third parties
in 2009.
|
48
Northeast
Our Northeast segment is consists of four generating facilities
with total net generating capacity of 2,535 MW. The
following table summarizes the results of operations of our
Northeast segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2010
|
|
|
2009
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
|
Gross Margin:
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
$
|
19
|
|
|
$
|
23
|
|
|
$
|
(4
|
)
|
Contracted and capacity
|
|
|
85
|
|
|
|
93
|
|
|
|
(8
|
)
|
Realized value of hedges
|
|
|
12
|
|
|
|
43
|
|
|
|
(31
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized gross margin
|
|
|
116
|
|
|
|
159
|
|
|
|
(43
|
)
|
Unrealized gross margin
|
|
|
(19
|
)
|
|
|
16
|
|
|
|
(35
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross margin (excluding depreciation and amortization)
|
|
|
97
|
|
|
|
175
|
|
|
|
(78
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenance
|
|
|
108
|
|
|
|
126
|
|
|
|
(18
|
)
|
Depreciation and amortization
|
|
|
23
|
|
|
|
18
|
|
|
|
5
|
|
Gain on sales of assets, net
|
|
|
(1
|
)
|
|
|
(4
|
)
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
130
|
|
|
|
140
|
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
(33
|
)
|
|
$
|
35
|
|
|
$
|
(68
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
Margin
The decrease of $43 million in realized gross margin was
principally a result of the following:
|
|
|
|
|
a decrease of $31 million in realized value of hedges. In
2010 and 2009, realized value of hedges was $12 million and
$43 million, respectively, which reflects the amount by
which the settlement value of power contracts exceeded market
prices for power, partially offset by the amount by which
contract prices for fuel exceeded market prices for fuel;
|
|
|
|
a decrease of $8 million in contracted and capacity
primarily related to decreases in capacity prices and megawatts
of capacity sold; and
|
|
|
|
a decrease of $4 million in energy primarily as a result of
a decrease in generation volumes from our oil-fired intermediate
units at our Canal generating facility as a result of
transmission upgrades in 2009, a decrease in the average
settlement price for power and unplanned outages in 2010, offset
in part by an increase in generation volumes at our Bowline
generating facility.
|
Our unrealized gross margin for both periods reflects the
following:
|
|
|
|
|
unrealized losses of $19 million in 2010 as a result of the
reversal of previously recognized unrealized gains from power
and fuel contracts that settled during the period; and
|
|
|
|
unrealized gains of $16 million in 2009, which included a
$65 million net increase in the value of hedge contracts
for future periods primarily related to decreases in forward
power and fuel prices, partially offset by $49 million
associated with the reversal of previously recognized unrealized
gains from power and fuel contracts that settled during the
period.
|
49
Operating
Expenses
The decrease of $10 million in operating expenses was
principally the result of the following:
|
|
|
|
|
a decrease of $18 million primarily related to lower
property taxes because of a lower assessed value for the Lovett
generating facility which was demolished in 2009 and a decrease
in shutdown costs associated with this generating facility;
partially offset by
|
|
|
|
an increase of $5 million in depreciation and amortization
expense primarily as a result of revisions to the useful lives
of our assets as a result of a depreciation study completed in
the first quarter of 2010; and
|
|
|
|
a decrease of $3 million in gain on sales of assets
primarily related to emissions allowances sold to third parties
in 2009.
|
California
Our California segment consists of three generating facilities
with total net generating capacity of 2,347 MW. The
following table summarizes the results of operations of our
California segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2010
|
|
|
2009
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
|
Gross Margin:
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Contracted and capacity
|
|
|
121
|
|
|
|
122
|
|
|
|
(1
|
)
|
Realized value of hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized gross margin
|
|
|
121
|
|
|
|
122
|
|
|
|
(1
|
)
|
Unrealized gross margin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross margin (excluding depreciation and amortization)
|
|
|
121
|
|
|
|
122
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenance
|
|
|
72
|
|
|
|
74
|
|
|
|
(2
|
)
|
Depreciation and amortization
|
|
|
28
|
|
|
|
22
|
|
|
|
6
|
|
Impairment losses
|
|
|
|
|
|
|
14
|
|
|
|
(14
|
)
|
Gain on sales of assets, net
|
|
|
(5
|
)
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
95
|
|
|
|
110
|
|
|
|
(15
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
26
|
|
|
$
|
12
|
|
|
$
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
Margin
Our natural gas-fired units in service at Contra Costa and
Pittsburg operate under tolling agreements with PG&E for
100% of the capacity from these units, and our Potrero units
were subject to RMR arrangements in 2010 and 2009. Therefore,
our gross margin generally is not affected by changes in power
generation volumes from these facilities.
Operating
Expenses
The decrease of $15 million in operating expenses was
principally a result of the following:
|
|
|
|
|
a decrease of $14 million of impairment losses related to
our Potrero and Contra Costa generating facilities during 2009.
See note 3(d) to our consolidated financial statements for
additional information related to our impairments; and
|
50
|
|
|
|
|
a increase of $5 million in gain on sales of assets
primarily related to land and emissions reduction credits sold
to GenOn Marsh Landing. See note 6 to our consolidated
financial statements for additional information related to the
sales of land and emissions reduction credits; partially offset
by
|
|
|
|
an increase of $6 million in depreciation expense primarily
as a result of a decrease in the useful life of our Potrero
generating facility because of the settlement with the City and
County of San Francisco executed in the third quarter of
2009. See note 10 to our consolidated financial statements
for additional information on the GenOn Potrero settlement with
the City and County of San Francisco.
|
Energy
Marketing
Our Energy Marketing segment consists of proprietary trading and
fuel oil management activities. The following table summarizes
the results of operations of our Energy Marketing segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2010
|
|
|
2009
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
|
Gross Margin:
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
$
|
32
|
|
|
$
|
167
|
|
|
$
|
(135
|
)
|
Contracted and capacity
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized value of hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized gross margin
|
|
|
32
|
|
|
|
167
|
|
|
|
(135
|
)
|
Unrealized gross margin
|
|
|
(5
|
)
|
|
|
(113
|
)
|
|
|
108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross margin (excluding depreciation and amortization)
|
|
|
27
|
|
|
|
54
|
|
|
|
(27
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenance
|
|
|
10
|
|
|
|
11
|
|
|
|
(1
|
)
|
Depreciation and amortization
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
11
|
|
|
|
12
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
16
|
|
|
$
|
42
|
|
|
$
|
(26
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
Margin
The decrease of $135 million in realized gross margin was
principally a result of a $77 million decrease from
proprietary trading activities and a $58 million decrease
from our fuel oil management activities. The decrease in the
contribution from proprietary trading was primarily a result of
a decrease in the realized value associated with power positions
in 2010 as compared to 2009. The decrease in the contribution
from fuel oil management was a result of lower gross margin on
positions used to hedge economically the fair value of our
physical fuel oil inventory.
Our unrealized gross margin for both periods reflects the
following:
|
|
|
|
|
unrealized losses of $5 million in 2010, which included
$50 million associated with the reversal of previously
recognized unrealized gains from power and fuel contracts that
settled during the period, substantially offset by a
$45 million net increase in the value of contracts for
future periods; and
|
|
|
|
unrealized losses of $113 million in 2009, which included
$101 million associated with the reversal of previously
recognized unrealized gains from power and fuel contracts that
settled during the period and a $12 million net decrease in
the value of contracts for future periods.
|
51
Other
Operations
Other Operations includes parent company adjustments for
affiliate transactions and other activities that cannot be
specifically identified to another segment. The following table
summarizes the results of operations of our Other Operations
segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2010
|
|
|
2009
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$
|
6
|
|
|
$
|
3
|
|
|
$
|
3
|
|
Impairment losses
|
|
|
28
|
|
|
|
5
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
34
|
|
|
|
8
|
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
$
|
(34
|
)
|
|
$
|
(8
|
)
|
|
$
|
(26
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Expenses
Our operating expense increase of $26 million was primarily
a result of the following:
|
|
|
|
|
an increase of $23 million in impairment losses. In 2010,
we recognized $28 million in impairment losses for
capitalized interest recorded at GenOn North America related to
our Dickerson and Potomac River generating facilities. In 2009,
we recognized $5 million in impairment losses recognized
for capitalized interest recorded at GenOn North America related
to the Potomac River generating facility; and
|
|
|
|
an increase of $3 million in depreciation and amortization
expense primarily as a result of the depreciation of interest
capitalized at GenOn North America related to the scrubbers at
our Maryland generating facilities that were placed in service
in December 2009.
|
52
2009
Compared to 2008
Consolidated
Financial Performance
We reported net income of $476 million and
$1.2 billion for 2009 and 2008, respectively. The change in
net income is detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
|
Realized gross margin
|
|
$
|
1,552
|
|
|
$
|
1,343
|
|
|
$
|
209
|
|
Unrealized gross margin
|
|
|
47
|
|
|
|
786
|
|
|
|
(739
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross margin (excluding depreciation and amortization)
|
|
|
1,599
|
|
|
|
2,129
|
|
|
|
(530
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenancenonaffiliate
|
|
|
355
|
|
|
|
372
|
|
|
|
(17
|
)
|
Operations and maintenanceaffiliate
|
|
|
290
|
|
|
|
285
|
|
|
|
5
|
|
Depreciation and amortization
|
|
|
142
|
|
|
|
136
|
|
|
|
6
|
|
Impairment losses
|
|
|
221
|
|
|
|
|
|
|
|
221
|
|
Gain on sales of assets, net
|
|
|
(22
|
)
|
|
|
(38
|
)
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
986
|
|
|
|
755
|
|
|
|
231
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
613
|
|
|
|
1,374
|
|
|
|
(761
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other expense, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
136
|
|
|
|
173
|
|
|
|
(37
|
)
|
Other, net
|
|
|
1
|
|
|
|
3
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense, net
|
|
|
137
|
|
|
|
176
|
|
|
|
(39
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
476
|
|
|
$
|
1,198
|
|
|
$
|
(722
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Gross Margin. For 2009, our realized
gross margin increase of $209 million was principally a
result of the following:
|
|
|
|
|
an increase of $422 million in realized value of hedges. In
2009, realized value of hedges was $629 million, which
reflects the amount by which the settlement value of power
contracts exceeded market prices for power, partially offset by
the amount by which contract prices for fuel exceeded market
prices for fuel. In 2008, realized value of hedges was
$207 million, which reflects the amount by which market
prices for fuel exceeded contract prices for fuel, partially
offset by the amount by which market prices for power exceeded
the settlement value of power contracts; and
|
|
|
|
an increase of $13 million in contracted and capacity
primarily related to higher capacity prices in 2009; partially
offset by
|
|
|
|
a decrease of $226 million in energy, primarily as a result
of a decrease in power prices, an increase in the cost of
emissions allowances, including $45 million to comply with
the RGGI in 2009, and lower generation volumes. The lower
generation volumes were a result of lower demand and decreases
in natural gas prices, which at times made it uneconomic for
certain of our coal-fired units to generate. The decreases in
energy gross margin were partially offset by a decrease in the
price of fuel.
|
Unrealized Gross Margin. Our unrealized gross
margin for both periods reflects the following:
|
|
|
|
|
unrealized gains of $47 million in 2009, which included a
$686 million net increase in the value of hedge and trading
contracts for future periods primarily related to decreases in
forward power and natural gas prices, partially offset by
$639 million associated with the reversal of previously
recognized unrealized gains from power and fuel contracts that
settled during the period; and
|
53
|
|
|
|
|
unrealized gains of $786 million in 2008, which included a
$460 million net increase in the value of hedge contracts
for future periods primarily related to decreases in forward
power and natural gas prices and $326 million associated with
the reversal of previously recognized unrealized losses from
power and fuel contracts that settled during the period.
|
Operating Expenses. Our operating expenses
increase of $231 million was primarily a result of the
following:
|
|
|
|
|
an increase of $221 million of impairment losses related to
our Potomac River generating facility and intangible assets
related to our Potrero and Contra Costa generating facilities
during 2009. See note 3(d) to our consolidated financial
statements for additional information related to our
impairments; and
|
|
|
|
a decrease of $16 million in gain on sales of assets, net
in 2009; partially offset by
|
|
|
|
a decrease of $12 million in operations and maintenance
expense. The decrease in operations and maintenance expense was
primarily a result of the shutdown of the Lovett generating
facility in April 2008 and a decrease in maintenance costs
associated with planned outages at our Mid-Atlantic generating
facilities during 2009 compared to 2008.
|
Interest Expense, Net. Interest expense, net
decreased $37 million and reflects lower interest expense
in 2009 because of lower outstanding debt and higher interest
capitalized on projects under construction, partially offset by
lower interest income as a result of lower interest rates on
invested cash and lower average cash balances in 2009 compared
to the same period in 2008.
Segments
The following discussion of our performance is organized by
reportable segment, which is consistent with the way we manage
our business. We previously had four reportable segments:
Mid-Atlantic, Northeast, California and Other Operations. In the
fourth quarter of 2010, in conjunction with the Merger, we began
reporting in five segments: Eastern PJM, Northeast, California,
Energy Marketing and Other Operations. We reclassified amounts
for 2009 and 2008 to conform to the current segment presentation.
In the tables below, the Eastern PJM segment consists of four
generating facilities located in Maryland and Virginia. The
Northeast segment consists of four generating facilities located
in Massachusetts and New York. For the year ended
December 31, 2008, the Northeast segment also included the
Lovett generating facility, which was shut down on
April 19, 2008. The California segment consists of three
generating facilities located in northern California. The Energy
Marketing segment consists of proprietary trading and fuel oil
management activities. Other Operations includes parent company
adjustments for affiliate transactions and other activities that
cannot be specifically identified to another segment. In the
following tables, eliminations are primarily related to
intercompany sales of emissions allowances.
Gross
Margin Overview
The following tables detail realized and unrealized gross margin
for 2009 and 2008, by operating segments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
Eastern
|
|
|
|
|
|
|
|
|
Energy
|
|
|
|
|
|
|
|
|
|
PJM
|
|
|
Northeast
|
|
|
California
|
|
|
Marketing
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
Energy
|
|
$
|
170
|
|
|
$
|
23
|
|
|
$
|
|
|
|
$
|
167
|
|
|
$
|
(3
|
)
|
|
$
|
357
|
|
Contracted and capacity
|
|
|
351
|
|
|
|
93
|
|
|
|
122
|
|
|
|
|
|
|
|
|
|
|
|
566
|
|
Realized value of hedges
|
|
|
586
|
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized gross margin
|
|
|
1,107
|
|
|
|
159
|
|
|
|
122
|
|
|
|
167
|
|
|
|
(3
|
)
|
|
|
1,552
|
|
Unrealized gross margin
|
|
|
144
|
|
|
|
16
|
|
|
|
|
|
|
|
(113
|
)
|
|
|
|
|
|
|
47
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross
margin(1)
|
|
$
|
1,251
|
|
|
$
|
175
|
|
|
$
|
122
|
|
|
$
|
54
|
|
|
$
|
(3
|
)
|
|
$
|
1,599
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
Eastern
|
|
|
|
|
|
|
|
|
Energy
|
|
|
|
|
|
|
|
|
|
PJM
|
|
|
Northeast
|
|
|
California
|
|
|
Marketing
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
Energy
|
|
$
|
517
|
|
|
$
|
73
|
|
|
$
|
4
|
|
|
$
|
(17
|
)
|
|
$
|
6
|
|
|
$
|
583
|
|
Contracted and capacity
|
|
|
340
|
|
|
|
90
|
|
|
|
123
|
|
|
|
|
|
|
|
|
|
|
|
553
|
|
Realized value of hedges
|
|
|
181
|
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
207
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized gross margin
|
|
|
1,038
|
|
|
|
189
|
|
|
|
127
|
|
|
|
(17
|
)
|
|
|
6
|
|
|
|
1,343
|
|
Unrealized gross margin
|
|
|
676
|
|
|
|
(10
|
)
|
|
|
|
|
|
|
120
|
|
|
|
|
|
|
|
786
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross
margin(1)
|
|
$
|
1,714
|
|
|
$
|
179
|
|
|
$
|
127
|
|
|
$
|
103
|
|
|
$
|
6
|
|
|
$
|
2,129
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gross margin excludes depreciation and amortization. |
Energy represents gross margin from the generation of
electricity, fuel sales and purchases at market prices, fuel
handling, steam sales and our proprietary trading and fuel oil
management activities.
Contracted and capacity represents gross margin received from
capacity sold in ISO and RTO administered capacity markets,
through RMR contracts (for 2009 and 2008), through tolling
agreements and from ancillary services.
Realized value of hedges represents the actual margin upon the
settlement of our power and fuel hedging contracts and the
difference between market prices and contract costs for fuel.
Power hedging contracts include sales of both power and natural
gas used to hedge power prices as well as hedges to capture the
incremental value related to the geographic location of our
physical assets.
Unrealized gross margin represents the net unrealized gain or
loss on our derivative contracts, including the reversal of
unrealized gains and losses recognized in prior periods and
changes in value for future periods.
Operating
Statistics
The following table summarizes net capacity factor by segment
for 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
Eastern PJM
|
|
|
30
|
%
|
|
|
33
|
%
|
|
|
(3
|
)%
|
Northeast
|
|
|
10
|
%
|
|
|
13
|
%
|
|
|
(3
|
)%
|
California
|
|
|
5
|
%
|
|
|
4
|
%
|
|
|
1
|
%
|
Energy Marketing
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Other Operations
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Total
|
|
|
19
|
%
|
|
|
21
|
%
|
|
|
(2
|
)%
|
55
The following table summarizes power generation volumes by
segment for 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
Increase/
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
(Decrease)
|
|
|
|
(in gigawatt hours)
|
|
|
Eastern PJM:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Baseload
|
|
|
13,500
|
|
|
|
14,350
|
|
|
|
(850
|
)
|
|
|
(6
|
)%
|
Intermediate
|
|
|
363
|
|
|
|
489
|
|
|
|
(126
|
)
|
|
|
(26
|
)%
|
Peaking
|
|
|
92
|
|
|
|
160
|
|
|
|
(68
|
)
|
|
|
(43
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Eastern PJM
|
|
|
13,955
|
|
|
|
14,999
|
|
|
|
(1,044
|
)
|
|
|
(7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Baseload
|
|
|
1,425
|
|
|
|
1,131
|
|
|
|
294
|
|
|
|
26
|
%
|
Intermediate
|
|
|
673
|
|
|
|
1,919
|
|
|
|
(1,246
|
)
|
|
|
(65
|
)%
|
Peaking
|
|
|
3
|
|
|
|
5
|
|
|
|
(2
|
)
|
|
|
(40
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Northeast
|
|
|
2,101
|
|
|
|
3,055
|
|
|
|
(954
|
)
|
|
|
(31
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intermediate
|
|
|
1,050
|
|
|
|
868
|
|
|
|
182
|
|
|
|
21
|
%
|
Peaking
|
|
|
4
|
|
|
|
21
|
|
|
|
(17
|
)
|
|
|
(81
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total California
|
|
|
1,054
|
|
|
|
889
|
|
|
|
165
|
|
|
|
19
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
17,110
|
|
|
|
18,943
|
|
|
|
(1,833
|
)
|
|
|
(10
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The total decrease in power generation volumes for 2009, as
compared to 2008, is primarily the result of the following:
Eastern PJM. A decrease in our Eastern PJM
baseload generation as a result of a decrease in demand in 2009
compared to 2008 and a decrease in natural gas prices, which at
times made it uneconomic for certain of our coal-fired units to
generate.
Northeast. A decrease in our Northeast
intermediate generation as a result of transmission upgrades in
2009, which reduced the demand for certain of our intermediate
units, partially offset by an increase in our Northeast baseload
generation as a result of an increase in market spark spreads.
California. All of our California generating
facilities operate under tolling agreements or are subject to
RMR arrangements. Our natural gas-fired units in service at
Contra Costa and Pittsburg operate under tolling agreements with
PG&E for 100% of the capacity from these units and our
Potrero units were subject to RMR arrangements in 2009 and 2008.
Therefore, changes in power generation volumes from those
generating facilities, which can be caused by weather, planned
outages or other factors, generally did not affect our gross
margin.
56
Eastern
PJM
Our Eastern PJM segment includes four generating facilities with
total net generating capacity of 5,204 MW. The following
table summarizes the results of operations of our Eastern PJM
segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Gross Margin:
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
$
|
170
|
|
|
$
|
517
|
|
|
$
|
(347
|
)
|
Contracted and capacity
|
|
|
351
|
|
|
|
340
|
|
|
|
11
|
|
Realized value of hedges
|
|
|
586
|
|
|
|
181
|
|
|
|
405
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized gross margin
|
|
|
1,107
|
|
|
|
1,038
|
|
|
|
69
|
|
Unrealized gross margin
|
|
|
144
|
|
|
|
676
|
|
|
|
(532
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross margin (excluding depreciation and amortization)
|
|
|
1,251
|
|
|
|
1,714
|
|
|
|
(463
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenance
|
|
|
434
|
|
|
|
412
|
|
|
|
22
|
|
Depreciation and amortization
|
|
|
98
|
|
|
|
92
|
|
|
|
6
|
|
Impairment losses
|
|
|
385
|
|
|
|
|
|
|
|
385
|
|
Gain on sales of assets, net
|
|
|
(14
|
)
|
|
|
(8
|
)
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
903
|
|
|
|
496
|
|
|
|
407
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
348
|
|
|
$
|
1,218
|
|
|
$
|
(870
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
Margin
The increase of $69 million in realized gross margin was
principally a result of the following:
|
|
|
|
|
an increase of $405 million in realized value of hedges. In
2009, realized value of hedges was $586 million, which
reflects the amount by which the settlement value of power
contracts exceeded market prices for power, partially offset by
the amount by which contract prices for coal that we purchased
under long-term agreements exceeded market prices for coal. In
2008, realized value of hedges was $181 million, which
reflects the amount by which market prices for coal exceeded
contract prices for coal that we purchased under long-term
agreements, partially offset by the amount by which market
prices for power exceeded the settlement value of power
contracts; and
|
|
|
|
an increase of $11 million in contracted and capacity
primarily related to higher capacity prices in 2009; partially
offset by
|
|
|
|
a decrease of $347 million in energy, primarily as a result
of a decrease in power prices, an increase in the cost of
emissions allowances, including $41 million to comply with
the RGGI in 2009, and lower generation volumes. The lower
generation volumes were a result of lower demand and decreases
in natural gas prices, which at times made it uneconomic for
certain of our coal-fired units to generate. These decreases
were partially offset by a decrease in the price of coal.
|
Our unrealized gross margin for both periods reflects the
following:
|
|
|
|
|
unrealized gains of $144 million in 2009, which included a
$633 million net increase in the value of hedge contracts
for future periods primarily related to decreases in forward
power and natural gas prices, partially offset by
$489 million associated with the reversal of previously
recognized unrealized gains from power and fuel contracts that
settled during the period; and
|
|
|
|
unrealized gains of $676 million in 2008, which included a
$399 million net increase in the value of hedge contracts
for future periods primarily related to decreases in forward
power and natural gas
|
57
|
|
|
|
|
prices and $277 million associated with the reversal of
previously recognized unrealized losses from power and fuel
contracts that settled during the period.
|
Operating
Expenses
The increase of $407 million in operating expenses was
primarily a result of the following:
|
|
|
|
|
an increase of $385 million in impairment losses recognized
in the fourth quarter of 2009, including $202 million
related to our Potomac River generating facility and
$183 million related to goodwill recorded at our GenOn
Mid-Atlantic registrant on its standalone balance sheet. The
goodwill does not exist at GenOn Americas Generations
consolidated balance sheet. As such, the goodwill impairment
loss and related goodwill balance are eliminated upon
consolidation at GenOn North America. See note 3(d) to our
consolidated financial statements for additional information
related to our impairment of the Potomac River generating
facility and GenOn Mid-Atlantics impairment of its
goodwill;
|
|
|
|
an increase of $22 million in operations and maintenance
expense primarily as a result of higher labor costs related to
increased staffing levels in preparation for the operation of
our scrubbers and an increase in Maryland property taxes, offset
in part by a decrease in maintenance costs associated with a
decrease in planned outages; and
|
|
|
|
an increase of $6 million in depreciation and amortization
expense primarily related to pollution control equipment for
NOx
emissions that was placed in service in 2008 as part of our
compliance with the Maryland Healthy Air Act; partially offset by
|
|
|
|
an increase of $6 million in gain on sales of assets
primarily related to emissions allowances sold to third parties.
|
Northeast
Our Northeast segment consists of four generating facilities
with total net generating capacity of 2,535 MW. The
following table summarizes the results of operations of our
Northeast segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Gross Margin:
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
$
|
23
|
|
|
$
|
73
|
|
|
$
|
(50
|
)
|
Contracted and capacity
|
|
|
93
|
|
|
|
90
|
|
|
|
3
|
|
Realized value of hedges
|
|
|
43
|
|
|
|
26
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized gross margin
|
|
|
159
|
|
|
|
189
|
|
|
|
(30
|
)
|
Unrealized gross margin
|
|
|
16
|
|
|
|
(10
|
)
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross margin (excluding depreciation and amortization)
|
|
|
175
|
|
|
|
179
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenance
|
|
|
126
|
|
|
|
167
|
|
|
|
(41
|
)
|
Depreciation and amortization
|
|
|
18
|
|
|
|
19
|
|
|
|
(1
|
)
|
Gain on sales of assets, net
|
|
|
(4
|
)
|
|
|
(30
|
)
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
140
|
|
|
|
156
|
|
|
|
(16
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
35
|
|
|
$
|
23
|
|
|
$
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
58
Gross
Margin
The decrease of $30 million in realized gross margin was
principally a result of the following:
|
|
|
|
|
a decrease of $50 million in energy, primarily as a result
of a 31% decrease in generation volumes because of transmission
upgrades which reduced the need for the Canal generating
facility to operate, a decrease in power prices, an increase in
the cost of emissions allowances, including $4 million to
comply with the RGGI in 2009 and the shutdown of the Lovett
generating facility in 2008 offset in part by lower fuel costs;
partially offset by
|
|
|
|
an increase of $17 million in realized value of hedges. In
2009, realized value of hedges was $43 million, which
reflects the amount by which the settlement value of power
contracts exceeded market prices for power, partially offset by
the amount by which contract prices for fuel exceeded market
prices for fuel. In 2008, realized value of hedges was
$26 million, which reflects the amount by which market
prices for fuel exceeded contract prices for fuel and the amount
by which the settlement value of power contracts exceeded market
prices for power.
|
Our unrealized gross margin for both periods reflects the
following:
|
|
|
|
|
unrealized gains of $16 million in 2009, which included a
$65 million net increase in the value of hedge contracts
for future periods primarily related to decreases in forward
power and fuel prices, partially offset by $49 million
associated with the reversal of previously recognized unrealized
gains from power and fuel contracts that settled during the
period; and
|
|
|
|
unrealized losses of $10 million in 2008, which included
$6 million associated with the reversal of previously
recognized unrealized gains from power and fuel contracts that
settled during the period and a $4 million net decrease in
the value of hedge contracts for future periods primarily
related to increases in forward power and fuel prices.
|
Operating
Expenses
The decrease of $16 million in operating expenses was
principally the result of the following:
|
|
|
|
|
a decrease of $41 million in operations and maintenance
expense primarily related to the shutdown of the Lovett
generating facility in April 2008 and lower maintenance expense
as a result of planned outages at the Canal generating facility
in 2008, partially offset by
|
|
|
|
a decrease of $26 million in gain on sales of assets
primarily related to emissions allowances sold to third parties.
|
59
California
Our California segment consists of three generating facilities
with total net generating capacity of 2,347 MW. The
following table summarizes the results of operations of our
California segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Gross Margin:
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
$
|
|
|
|
$
|
4
|
|
|
$
|
(4
|
)
|
Contracted and capacity
|
|
|
122
|
|
|
|
123
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized gross margin
|
|
|
122
|
|
|
|
127
|
|
|
|
(5
|
)
|
Unrealized gross margin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross margin (excluding depreciation and amortization)
|
|
|
122
|
|
|
|
127
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenance
|
|
|
74
|
|
|
|
68
|
|
|
|
6
|
|
Depreciation and amortization
|
|
|
22
|
|
|
|
23
|
|
|
|
(1
|
)
|
Impairment losses
|
|
|
14
|
|
|
|
|
|
|
|
14
|
|
Gain on sales of assets, net
|
|
|
|
|
|
|
(7
|
)
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
110
|
|
|
|
84
|
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
12
|
|
|
$
|
43
|
|
|
$
|
(31
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Expenses
The increase of $26 million in operating expenses was
principally a result of the following:
|
|
|
|
|
an impairment loss of $14 million on intangible assets
related to our Potrero and Contra Costa generating facilities
during 2009. See note 3(d) to our consolidated financial
statements for additional information related to our impairment
reviews; and
|
|
|
|
a decrease of $7 million in gain on sales of assets
primarily related to emissions allowances sold to third parties.
|
Energy
Marketing
Our Energy Marketing segment consists of proprietary trading and
fuel oil management activities. The following table summarizes
the results of operations of our Energy Marketing segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Gross Margin:
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
$
|
167
|
|
|
$
|
(17
|
)
|
|
$
|
184
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized gross margin
|
|
|
167
|
|
|
|
(17
|
)
|
|
|
184
|
|
Unrealized gross margin
|
|
|
(113
|
)
|
|
|
120
|
|
|
|
(233
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross margin (excluding depreciation and amortization)
|
|
|
54
|
|
|
|
103
|
|
|
|
(49
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenance
|
|
|
11
|
|
|
|
10
|
|
|
|
1
|
|
Depreciation and amortization
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
12
|
|
|
|
11
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
42
|
|
|
$
|
92
|
|
|
$
|
(50
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60
Gross
Margin
The increase of $184 million in realized gross margin was
principally a result of the following:
|
|
|
|
|
an increase of $184 million in energy primarily as a result
of $112 million increase from our fuel oil management
activities and a $72 million increase from proprietary
trading activities. The increase from our fuel oil management
activities includes a $25 million gain from the sale of
excess fuel oil in 2009 and a $37 million lower of cost or
market fuel oil inventory adjustment recognized in the fourth
quarter of 2008. The increase in gross margin from proprietary
trading activities was a result of higher realized value
associated with power positions in 2009 as compared to 2008.
|
Our unrealized gross margin for both periods reflects the
following:
|
|
|
|
|
unrealized losses of $113 million in 2009, which included
$101 million associated with the reversal of previously
recognized unrealized gains from power and fuel contracts that
settled during the period and a $12 million net decrease in
the value of contracts for future periods; and
|
|
|
|
unrealized gains of $120 million in 2008, which included a
$65 million net increase in the value of contracts for
future periods and $55 million associated with the reversal
of previously recognized unrealized losses from power and fuel
contracts that settled during the period.
|
Other
Operations
Other Operations includes parent company adjustments for
affiliate transactions and other activities that cannot be
specifically identified to another segment. The following table
summarizes the results of operations of our Other Operations
segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$
|
3
|
|
|
$
|
1
|
|
|
$
|
2
|
|
Impairment losses
|
|
|
5
|
|
|
|
|
|
|
|
5
|
|
Gain on sales of assets, net
|
|
|
|
|
|
|
(1
|
)
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
8
|
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
$
|
(8
|
)
|
|
$
|
|
|
|
$
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Expenses
The increase of $8 million in operating expenses was
primarily the result of a $5 million increase in impairment
losses recognized in the fourth quarter of 2009 for capitalized
interest recorded at GenOn North America related to the Potomac
River generating facility.
Financial
Condition
Liquidity
and Capital Resources
Management thinks that our liquidity position and cash flows
from operations will be adequate to fund operating, maintenance
and capital expenditures, to fund debt service and to meet other
liquidity requirements. Management regularly monitors our
ability to fund our operating, financing and investing
activities. See note 4 to our consolidated financial
statements for additional discussion of our debt.
Debt
Financing Transactions Related to the Merger
GenOn entered into new senior secured credit facilities
comprised of a $788 million five-year senior secured
revolving credit facility and a $700 million seven-year
senior secured term loan (the GenOn credit
61
facilities). The funding of the term loan facility and the
availability of borrowings and letters of credit under the
revolving credit facility were subject to the closing of the
Merger and the satisfaction of the conditions precedent thereto.
In addition, GenOn Escrow, a wholly-owned subsidiary of GenOn,
issued senior notes in an aggregate principal amount of
$1.225 billion. Upon issuance, the proceeds of the notes
(which were issued at a discount), together with additional
funds, were deposited into a segregated escrow account pending
completion of the Merger. Upon completion of the Merger, GenOn
Escrow merged with and into GenOn which assumed all of GenOn
Escrows obligations under the notes and the related
indenture and the funds held in escrow were released to GenOn.
The proceeds of the new GenOn credit facilities and senior notes
were used, in part, to redeem the GenOn North America senior
notes, repay and terminate the GenOn North America term loan and
replace the GenOn North America revolving credit facility.
The GenOn credit facilities, and the subsidiary guarantees
thereof, are senior secured obligations of GenOn and certain of
its existing and future direct and indirect subsidiaries,
excluding GenOn Americas Generation; provided, however, that
certain of GenOn Americas Generations subsidiaries (other
than GenOn Mid-Atlantic and GenOn Energy Management and their
subsidiaries) guarantee the GenOn credit facilities to the
extent permitted under the indenture for the senior notes of
GenOn Americas Generation.
Sources
of Funds and Capital Structure
Maintaining sufficient liquidity in our business is crucial in
order to mitigate the risk of future financial distress to us.
Accordingly, we plan on a prospective basis for the expected
liquidity requirements of our business considering the factors
listed below:
|
|
|
|
|
expected expenditures with respect to maintenance activities and
capital improvements, and related outages;
|
|
|
|
expected collateral postings in support of our business;
|
|
|
|
effects of market price volatility on the amount of collateral
postings for hedge transactions and risk management transactions;
|
|
|
|
effects of market price volatility on fuel pre-payment
requirements;
|
|
|
|
seasonal and intra-month working capital requirements;
|
|
|
|
debt service obligations; and
|
|
|
|
costs associated with litigation, regulatory and tax proceedings.
|
The principal sources of our liquidity are expected to be:
(a) existing cash on hand and expected cash flows from the
operations of our subsidiaries, (b) at its discretion,
letters of credit issued under GenOns senior secured
revolving credit facility, and (c) at its discretion,
additional capital contributions from GenOn.
Our operating cash flows may be affected by, among other things:
(a) demand for electricity; (b) the difference between
the cost of fuel used to generate electricity and the market
value of the electricity generated; (c) commodity prices
(including prices for electricity, emissions allowances, natural
gas, coal and oil); (d) operations and maintenance expenses
in the ordinary course; (e) planned and unplanned outages;
(f) terms with trade creditors; and (g) cash
requirements for capital expenditures relating to certain
facilities (including those necessary to comply with
environmental regulations).
The table below sets forth total cash and cash equivalents of
GenOn Americas Generation and its subsidiaries at
December 31, 2010 (in millions):
|
|
|
|
|
Cash and Cash Equivalents:
|
|
|
|
|
GenOn Americas Generation (excluding GenOn Mid-Atlantic)
|
|
$
|
312
|
|
GenOn Mid-Atlantic
|
|
|
202
|
|
|
|
|
|
|
Total cash and cash equivalents
|
|
$
|
514
|
|
|
|
|
|
|
62
We consider all short-term investments with an original maturity
of three months or less to be cash equivalents. At
December 31, 2010, except for amounts held in bank accounts
to cover upcoming payables, all of our cash and cash equivalents
were invested in AAA-rated United States Treasury money market
funds.
GenOn Americas Generation is a holding company. The chart below
is a summary representation of our capital structure and is not
a complete corporate organizational chart.
|
|
|
(1) |
|
At December 31, 2010, the present value of lease payments
under the GenOn Mid-Atlantic operating leases was approximately
$927 million (assuming a 10% discount rate) and the
termination value of the GenOn Mid-Atlantic operating leases was
$1.4 billion. |
Except for existing cash on hand, GenOn Americas Generation is a
holding company that is dependent on the distributions and
dividends of its subsidiaries for liquidity and, at its
discretion, additional capital contributions from GenOn. In
particular, a substantial portion of cash from its operations is
generated by GenOn Mid-Atlantic.
GenOn Mid-Atlantics ability to pay dividends and make
distributions is restricted under the terms of its operating
leases. Under the operating leases, GenOn Mid-Atlantic is not
permitted to make any distributions and other restricted
payments unless: (a) it satisfies the fixed charge coverage
ratio for the most recently ended period of four fiscal
quarters; (b) it is projected to satisfy the fixed charge
coverage ratio for each of the two following periods of four
fiscal quarters, commencing with the fiscal quarter in which
such payment is proposed to be made; and (c) no significant
lease default or event of default has occurred and is
continuing. In the event of a default under the operating leases
or if the restricted payment tests are not satisfied, GenOn
Mid-Atlantic would not be able to distribute cash. At
December 31, 2010, GenOn Mid-Atlantic satisfied the
restricted payments test.
Pursuant to the terms of its lease documents, GenOn Mid-Atlantic
is restricted from, among other actions, (a) encumbering
assets, (b) entering into business combinations or
divesting assets, (c) entering into transactions with
affiliates on other than an arms length basis or
(d) materially changing its business. Therefore, at
December 31, 2010, all of GenOn Mid-Atlantics net
assets (excluding cash) were deemed restricted for purposes of
Rule 4-08(e)(3)(ii)
of
Regulation S-X.
The amounts of the deemed restricted net assets were as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2010
|
|
2009
|
|
|
(in millions)
|
|
GenOn Mid-Atlantic
|
|
$
|
3,698
|
|
|
$
|
4,761
|
|
Our ability to pay our obligations is dependent on the receipt
of dividends from GenOn North America, capital contributions or
intercompany loans from GenOn and our ability to refinance all
or a portion of those
63
obligations as they become due. Although we continue to evaluate
our refinancing options, we expect to maintain adequate
liquidity to retire our $535 million of senior notes that
come due in May 2011.
Uses of
Funds
Our requirements for liquidity and capital resources, other than
for the
day-to-day
operation of our generating facilities, are significantly
influenced by the following items: (a) capital
expenditures, (b) debt service, (c) payments under the
GenOn Mid-Atlantic operating leases, and (d) collateral
required for our asset management and proprietary trading and
fuel oil management activities.
Capital Expenditures. Our capital
expenditures, excluding capitalized interest, during 2010, were
$247 million. Our estimated capital expenditures, excluding
capitalized interest, for 2011 and 2012 are $266 million
and $53 million, respectively. See Item 1,
Business for further discussion of our capital
expenditures.
Debt Service. At December 31, 2010, we
had $2.3 billion of long-term debt ($1.4 billion of
which was classified as current) with expected interest payments
of $91 million for 2011. See note 4 to our
consolidated financial statements.
GenOn Mid-Atlantic Operating Leases. GenOn
Mid-Atlantic leases a 100% interest in both the Dickerson and
Morgantown baseload units and associated property through 2029
and 2034, respectively. GenOn Mid-Atlantic has an option to
extend the leases. Any extensions of the respective leases would
be for less than 75% of the economic useful life of the
facility, as measured from the beginning of the original lease
term through the end of the proposed remaining lease term. We
are accounting for these leases as operating leases. Although
there is variability in the scheduled payment amounts over the
lease term, we recognize rent expense for these leases on a
straight-line basis in accordance with GAAP. Rent expense under
the GenOn Mid-Atlantic leases was $96 million for each of
2010, 2009 and 2008. The scheduled payment amounts for the GenOn
Mid-Atlantic leases are $134 million and $132 million
for 2011 and 2012, respectively. At December 31, 2010, the
total notional minimum lease payments for the remaining term of
the leases aggregated $1.7 billion and the aggregate
termination value for the leases was approximately
$1.4 billion and generally decreases over time. In
addition, the present value of lease payments at
December 31, 2010 was approximately $927 million
(assuming a 10% discount rate). GenOn provides letters of credit
in support of GenOn Mid-Atlantics lease obligations in an
aggregate amount equal to the greatest of the next six months
scheduled rent payments, 50% of the next 12 months
scheduled rent payments or $75 million.
Cash Collateral and Letters of Credit. In
order to sell power and purchase fuel in the forward markets and
perform other energy trading and marketing activities, we often
are required to provide credit support to our counterparties or
make deposits with brokers. In addition, we often are required
to provide cash collateral or letters of credit as credit
support for various contractual and other obligations incurred
in connection with our commercial and operating activities,
including obligations in respect of transmission and
interconnection access, participation in power pools, rent
reserves, power purchases and sales, fuel and emission purchases
and sales, construction and equipment purchases and other
operating activities. Credit support includes cash collateral,
letters of credit, surety bonds and financial guarantees. In the
event that we default, the counterparty can draw on a letter of
credit or apply cash collateral held to satisfy the existing
amounts outstanding under an open contract. At December 31,
2010, we had $120 million of posted cash collateral and
GenOn had $195 million of letters of credit outstanding
under its revolving credit facility on our behalf primarily to
support our asset management activities, trading activities,
rent reserve requirements and other commercial arrangements.
Upon the completion of the Merger, the outstanding letters of
credit under the GenOn North America senior secured
revolving credit facility were transferred to the GenOn senior
secured revolving credit facility. Our liquidity requirements
are highly dependent on the level of our hedging activities,
forward prices for energy, emissions allowances and fuel,
commodity market volatility, credit terms with third parties and
regulation of energy contracts. See Item 1,
Business for our discussion on the Dodd-Frank Act.
See note 4 to our consolidated financial statements.
64
The following table summarizes cash collateral posted with
counterparties and brokers, letters of credit issued and surety
bonds provided:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
Cash collateral postedenergy trading and marketing
|
|
$
|
80
|
|
|
$
|
41
|
|
Cash collateral postedother operating activities
|
|
|
40
|
|
|
|
42
|
|
Letters of creditenergy trading and
marketing(1)
|
|
|
63
|
|
|
|
51
|
|
Letters of creditrent
reserves(1)
|
|
|
101
|
|
|
|
101
|
|
Letters of creditother operating
activities(1)
|
|
|
31
|
|
|
|
47
|
|
Surety bonds
|
|
|
7
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
322
|
|
|
$
|
283
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
At December 31, 2010, represents letters of credit posted
by GenOn for the benefit of GenOn Americas Generation. |
Debt
Obligations, Off-Balance Sheet Arrangements and Contractual
Obligations
Our debt obligations, off-balance sheet arrangements and
contractual obligations at December 31, 2010, are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt Obligations, Off-Balance Sheet Arrangements and
Contractual Obligations by Year
|
|
|
|
|
|
|
Less than
|
|
|
One to
|
|
|
Three to
|
|
|
More than
|
|
|
|
Total
|
|
|
One Year
|
|
|
Three Years
|
|
|
Five Years
|
|
|
Five Years
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
3,430
|
|
|
$
|
1,480
|
|
|
$
|
160
|
|
|
$
|
160
|
|
|
$
|
1,630
|
|
GenOn Mid-Atlantic operating leases
|
|
|
1,730
|
|
|
|
134
|
|
|
|
270
|
|
|
|
241
|
|
|
|
1,085
|
|
Other operating leases
|
|
|
39
|
|
|
|
5
|
|
|
|
7
|
|
|
|
8
|
|
|
|
19
|
|
Fuel commitments
|
|
|
914
|
|
|
|
371
|
|
|
|
543
|
|
|
|
|
|
|
|
|
|
Maryland Healthy Air Act
|
|
|
155
|
|
|
|
155
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
287
|
|
|
|
137
|
|
|
|
55
|
|
|
|
27
|
|
|
|
68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total payments
|
|
$
|
6,555
|
|
|
$
|
2,282
|
|
|
$
|
1,035
|
|
|
$
|
436
|
|
|
$
|
2,802
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our contractual obligations table does not include our
derivative obligations reported at fair value (other than fuel
supply commitments), which are discussed in note 2 to our
consolidated financial statements and asset retirement
obligations which are discussed in note 3 to our
consolidated financial statements.
Long-term debt includes the current portion of long-term debt
and long-term debt on our consolidated balance sheets, which are
discussed in note 4 to our consolidated financial
statements. Long-term debt also includes estimated interest on
debt. These amounts do not include unamortized debt discounts.
GenOn Mid-Atlantic operating leases relate to our minimum lease
payments associated with our off-balance sheet leases of the
Dickerson and Morgantown baseload units. In addition, we have
commitments under other operating leases with various terms and
expiration dates.
Fuel commitments primarily relate to coal agreements.
Maryland Healthy Air Act commitments reflect the remaining
expected payments for capital expenditures to comply with the
limitations for
SO2,
NOx
and mercury emissions under the Maryland Healthy Air Act. We
completed the installation of the remaining pollution control
equipment related to compliance with the Maryland Healthy Air
Act in the fourth quarter of 2009. However, provisions in our
construction contracts provide that certain payments be made
after final completion of the project.
65
Other primarily represents the open purchase orders less
invoices received related to general procurement of products and
services purchased in the ordinary course of business. These
include construction, maintenance and labor activities at our
generating facilities. Other also includes fuel transportation
agreements, limestone supply and transportation agreements, our
LTSA associated with the maintenances of a turbine at our
Kendall generating facility and miscellaneous noncurrent
liabilities.
Historical
Cash Flows
2010
Compared to 2009
Operating Activities. The changes in our
operating cash flows are detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2010
|
|
|
2009
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
|
Operating income (loss)
|
|
$
|
(187
|
)
|
|
$
|
613
|
|
|
$
|
(800
|
)
|
Non-cash items(1)
|
|
|
844
|
|
|
|
336
|
|
|
|
508
|
|
Receivables and accounts payable and accrued liabilities, net
|
|
|
17
|
|
|
|
23
|
|
|
|
(6
|
)
|
Funds on deposit
|
|
|
87
|
|
|
|
26
|
|
|
|
61
|
|
Inventories
|
|
|
(76
|
)
|
|
|
(35
|
)
|
|
|
(41
|
)
|
Interest payments, net of amounts capitalized
|
|
|
(185
|
)
|
|
|
(124
|
)
|
|
|
(61
|
)
|
Prepaid rent
|
|
|
(44
|
)
|
|
|
(46
|
)
|
|
|
2
|
|
Other, net
|
|
|
(12
|
)
|
|
|
(27
|
)
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
444
|
|
|
$
|
766
|
|
|
$
|
(322
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
See our consolidated statements of cash flows for additional
information. |
Our cash provided by operating activities is affected by
seasonality, changes in energy prices and fluctuations in our
working capital requirements. Net cash provided by operating
activities decreased by $322 million during 2010, compared
to 2009, primarily as a result of the following:
|
|
|
|
|
Realized gross margin. A decrease in cash
provided of $294 million in 2010, compared to 2009,
excluding a decrease in non-cash lower of cost or market fuel
inventory adjustments of $10 million. See Results of
Operations in this Item 7 for additional discussion
of our performance in 2010 compared to 2009;
|
|
|
|
Interest payments, net of amounts
capitalized. An increase in cash used of
$61 million primarily as a result of a decrease in
capitalized interest (which is included in investing activities);
|
|
|
|
Inventory. An increase in cash used of
$41 million primarily as a result of higher prices and
purchases of a larger volume of fuel oil;
|
|
|
|
Operating expenses. An increase in cash used
for operations and maintenance expense of $7 million,
primarily as a result of costs related to the operation of our
scrubbers in 2010, offset in part by a decrease in shutdown
costs associated with the demolished Lovett generating facility
and a decrease in outage costs. See Results of
Operations in this Item 7 for additional discussion
of our performance in 2010 compared to 2009; and
|
|
|
|
Other operating assets and liabilities. An
increase in cash used of $2 million related to changes in
other operating assets and liabilities.
|
The increases in cash used in and decrease in cash provided by
operating activities were partially offset by the following:
|
|
|
|
|
Funds on deposit. An increase in cash provided
of $61 million. We received $87 million in collateral
from our counterparties in 2010 compared to $26 million
returned from our counterparties in 2009; and
|
66
|
|
|
|
|
Property taxes. A decrease in cash used of
$22 million primarily related to the timing of property tax
payments and lower property taxes assessed on the value of the
Lovett generating facility which was demolished in 2009.
|
Investing Activities. The changes in our
investing cash flows are detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2010
|
|
|
2009
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
|
Capital expenditures
|
|
$
|
(252
|
)
|
|
$
|
(666
|
)
|
|
$
|
414
|
(1)
|
Proceeds from the sales of assets
|
|
|
8
|
|
|
|
25
|
|
|
|
(17
|
)(2)
|
Restricted deposit payments and other
|
|
|
(866
|
)
|
|
|
1
|
|
|
|
(867
|
)(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
$
|
(1,110
|
)
|
|
$
|
(640
|
)
|
|
$
|
(470
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Primarily related to placing scrubbers for our Maryland
generating facilities in service during the fourth quarter of
2009 as part of our compliance with the Maryland Healthy Air Act. |
|
(2) |
|
Primarily related to sales of emissions allowances in 2009 as
compared to 2010. |
|
(3) |
|
Primarily related to funds deposited with the Trustee to pay the
GenOn North America senior notes, which were redeemed on
January 3, 2011. |
Financing Activities. The changes in our
financing cash flows are detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2010
|
|
|
2009
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
|
Redemption of preferred stock in affiliate
|
|
$
|
295
|
|
|
$
|
84
|
|
|
$
|
211
|
(1)
|
Repayments of long-term debtnonaffiliate
|
|
|
(376
|
)
|
|
|
(45
|
)
|
|
|
(331
|
)(2)
|
Capital contributions
|
|
|
1,079
|
|
|
|
|
|
|
|
1,079
|
(3)
|
Distributions to member
|
|
|
(222
|
)
|
|
|
(115
|
)
|
|
|
(107
|
)(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
$
|
776
|
|
|
$
|
(76
|
)
|
|
$
|
852
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes $295 million related to the final redemptions of
Series B preferred stock held by us and Series A
preferred stock held by GenOn Mid-Atlantic (see note 6 to
our consolidated financial statements for further discussion) |
|
(2) |
|
Includes $373 million related to the repayment of the GenOn
North America senior secured term loan (see note 4 to our
consolidated financial statements for further discussion). |
|
(3) |
|
Includes $1.079 billion related to contributions from GenOn
Americas primarily for the repayment of the GenOn North America
senior secured notes and senior secured credit facility. |
|
(4) |
|
Includes $222 million related to distributions to our
member during 2010 compared to $115 million during 2009. |
67
2009
Compared to 2008
Operating Activities. The changes in our
operating cash flows are detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Operating income
|
|
$
|
613
|
|
|
$
|
1,374
|
|
|
$
|
(761
|
)
|
Non-cash
items(1)
|
|
|
336
|
|
|
|
(604
|
)
|
|
|
940
|
|
Receivables and accounts payable and accrued liabilities, net
|
|
|
23
|
|
|
|
32
|
|
|
|
(9
|
)
|
Funds on deposit
|
|
|
26
|
|
|
|
109
|
|
|
|
(83
|
)
|
Inventories
|
|
|
(35
|
)
|
|
|
47
|
|
|
|
(82
|
)
|
Interest payments, net of amounts capitalized
|
|
|
(124
|
)
|
|
|
(175
|
)
|
|
|
51
|
|
Interest income
|
|
|
1
|
|
|
|
16
|
|
|
|
(15
|
)
|
Prepaid rent
|
|
|
(46
|
)
|
|
|
(24
|
)
|
|
|
(22
|
)
|
Other, net
|
|
|
(28
|
)
|
|
|
(15
|
)
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities of continuing
operations
|
|
|
766
|
|
|
|
760
|
|
|
|
6
|
|
Net cash provided by operating activities of discontinued
operations
|
|
|
|
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
766
|
|
|
$
|
761
|
|
|
$
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
See our consolidated statements of cash flows for additional
information. |
Continuing
Operations
Our cash provided by operating activities is affected by
seasonality, changes in energy prices and fluctuations in our
working capital requirements. Net cash provided by operating
activities from continuing operations increased $6 million
during 2009, compared to 2008, primarily as a result of the
following:
|
|
|
|
|
Realized gross margin. An increase in cash
provided of $176 million in 2009, compared to 2008,
excluding a decrease in non-cash lower of cost or market fuel
inventory adjustments of $33 million. See Results of
Operations for additional discussion of our performance in
2009 compared to 2008; and
|
|
|
|
Interest payments, net of amounts
capitalized. A decrease in cash used of
$51 million primarily as a result of lower outstanding debt
and higher interest capitalized on projects under construction.
|
The increase in cash provided by and decrease in cash used in
operating activities were partially offset by the following:
|
|
|
|
|
Funds on deposit. A decrease in cash provided
of $83 million. During 2009, we had net cash collateral
returned to us of $26 million. During 2008, we had net cash
collateral returned to us of $109 million primarily related
to the cash collateral account to support issuance of letters of
credit under the GenOn North America senior secured term loan;
|
|
|
|
Inventories. An increase in cash used of
$82 million as a result of higher inventory levels of coal
and fuel oil, partially offset by lower market prices in 2009 as
compared to 2008;
|
|
|
|
Prepaid rent. An increase in cash used for our
GenOn Mid-Atlantic operating leases as the scheduled rent
payments were higher by $22 million during 2009 than during
2008;
|
|
|
|
Interest income. A decrease in cash provided
of $15 million primarily as a result of lower interest
rates on invested cash, as well as lower average cash balances;
|
|
|
|
Receivables and accounts payable and accrued liabilities,
net. A decrease in cash provided of
$9 million primarily related to an increase in cash used of
$111 million as a result of $43 million collateral
returned to counterparties during 2009 as compared to
$68 million received from counterparties during 2008,
partially offset by a decrease in cash used of $102 million
during 2009 primarily
|
68
|
|
|
|
|
related to (a) a decrease in power prices in 2009 compared
to 2008 and (b) the implementation in June 2009 of weekly
settlements with PJM (in lieu of monthly settlements) which
reduced the amount of outstanding receivables for the PJM
markets; and
|
|
|
|
|
|
Other operating assets and liabilities. An
increase in cash used of $10 million related to changes in
other operating assets and liabilities.
|
Discontinued
Operations
In 2008, net cash provided by operating activities from
discontinued operations was a result of final working capital
adjustments related to the 2007 dispositions of the Zeeland and
Bosque natural gas-fired generating facilities and Mirant
NY-Gen, LLC.
Investing Activities. The changes in our
investing cash flows are detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Capital expenditures
|
|
$
|
(666
|
)
|
|
$
|
(720
|
)
|
|
$
|
54
|
(1)
|
Proceeds from the sales of assets
|
|
|
25
|
|
|
|
40
|
|
|
|
(15
|
)(2)
|
Restricted deposit payments and other
|
|
|
1
|
|
|
|
(34
|
)
|
|
|
35
|
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities of continuing operations
|
|
|
(640
|
)
|
|
|
(714
|
)
|
|
|
74
|
|
Net cash provided by investing activities of discontinued
operations
|
|
|
|
|
|
|
18
|
|
|
|
(18
|
)(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
$
|
(640
|
)
|
|
$
|
(696
|
)
|
|
$
|
56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Primarily related to our environmental capital expenditures for
our Maryland generating facilities related to our compliance
with the Maryland Healthy Air Act. |
|
(2) |
|
Primarily related to sales of emissions allowances to third
parties. |
|
(3) |
|
Related to $34 million placed in an escrow account in
September 2008, to satisfy the conditions of Potomac
Rivers agreement with the City of Alexandria, Virginia.
See note 10 to our consolidated financial statements for
additional information on Potomac Rivers agreement with
the City of Alexandria, Virginia. |
|
(4) |
|
Primarily as a result of $16 million related to insurance
recoveries for repairs of the Swinging Bridge generating
facility. |
Financing Activities. The changes in our
financing cash flows are detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Redemption of preferred stock in affiliate
|
|
$
|
84
|
|
|
$
|
31
|
|
|
$
|
53
|
(1)
|
Repayments and purchases of long-term debt
|
|
|
(45
|
)
|
|
|
(419
|
)
|
|
|
374
|
(2)
|
Repayment of note payableaffiliate, net
|
|
|
|
|
|
|
(6
|
)
|
|
|
6
|
|
Capital contributions
|
|
|
|
|
|
|
282
|
|
|
|
(282
|
)(3)
|
Distributions to member
|
|
|
(115
|
)
|
|
|
(297
|
)
|
|
|
182
|
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities
|
|
$
|
(76
|
)
|
|
$
|
(409
|
)
|
|
$
|
333
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Related to the redemption of Series A preferred stock held
by GenOn Mid-Atlantic (see note 6 to our consolidated
financial statements for further discussion). |
|
(2) |
|
Includes $276 million for the 2008 purchase and retirement
of GenOn Americas Generation senior notes due in 2011. |
|
(3) |
|
Includes $282 million as a result of contributions from
GenOn Americas primarily for the purchase of our bonds in 2008. |
|
(4) |
|
Related to distributions of $115 million to our member
during 2009 compared to $297 million during 2008. |
69
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations.
|
B. GenOn
Mid-Atlantic
This section is intended to provide the reader with information
that will assist in understanding GenOn Mid-Atlantics
financial statements, the changes in those financial statements
from year to year and the primary factors contributing to those
changes. The following discussion should be read in conjunction
with GenOn Mid-Atlantics consolidated financial statements
and the notes accompanying those financial statements.
Merger of
Mirant and RRI Energy
Refer to Merger of Mirant and RRI Energy above for
GenOn Americas Generation.
Our
Business
With approximately 5,204 MW of electric generating capacity
in the PJM market, we operate across various fuel (natural gas,
coal and oil) and technology types, and operating
characteristics. We provide energy, capacity, ancillary and
other energy services to wholesale customers in the PJM market.
GenOn Americas Generations commercial operations provides
us with services that consist primarily of dispatching
electricity, hedging the generation and sale of electricity,
procuring and managing fuel and providing logistical support for
the operation of our facilities (e.g., by procuring
transportation for coal and natural gas).
We typically sell the electricity we produce into the wholesale
market at prices in effect at the time we produce it (spot
price). We use dispatch models to assist in making daily bidding
decisions regarding the quantity and price of the power we offer
to generate from our facilities and sell into the markets. We
bid the energy from our generating facilities into the
hour-ahead or day-ahead energy market and sell ancillary
services through the PJM market. We work with the PJM market in
real time to ensure that our generating facilities are
dispatched economically to meet the reliability needs of the
market.
We sell capacity either bilaterally or through periodic auctions
in the PJM. These capacity sales provide an important source of
predictable revenues for us over the contracted period. At
January 31, 2011, total projected contracted capacity
revenues for which prices had been set for 2011 through 2014 are
$881 million.
Hedging
Activities
Spot prices for electricity are volatile, as are prices for fuel
and emissions allowances. We use derivative financial
instruments, such as commodity forwards, futures, options and
swaps, to manage our exposure to fluctuations in electric energy
and fuel commodity prices. In addition, we hedge economically a
substantial portion of our PJM coal-fired baseload generation.
We generally do not hedge our intermediate and peaking units for
tenors greater than 12 months. We hedge economically using
products which we expect to be effective to mitigate the price
risk of our generation, including natural gas. However, as a
result of market liquidity limitations, our hedges often are not
an exact match for the generation being hedged, and, we then
have some risks resulting from price differentials for different
delivery points and for implied differences in heat rates when
we hedge economically power using natural gas. Although some of
our hedges are executed through our affiliate, GenOn Energy
Management, a majority of our hedges are financial swap
transactions with financial counterparties that are senior
unsecured obligations of such parties and do not require either
party to post cash collateral either for initial margin or for
securing exposure as a result of changes in power or natural gas
prices. At January 31, 2011, our aggregate hedge levels
based on expected generation for each year were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011(1)
|
|
2012
|
|
2013
|
|
2014
|
|
2015
|
|
Power
|
|
|
89
|
%
|
|
|
78
|
%
|
|
|
40
|
%
|
|
|
38
|
%
|
|
|
|
%
|
Fuel
|
|
|
88
|
%
|
|
|
79
|
%
|
|
|
55
|
%
|
|
|
|
%
|
|
|
|
%
|
|
|
|
(1) |
|
Percentages represent the period from February through
December 2011. |
70
See Item 1A, Risk FactorsRisks Related to
Economic and Financial Market Conditions for a discussion
of:
|
|
|
|
|
the risks of consolidation of financial institutions and more
restrictive capital constraints and regulation, which could have
a negative effect on our ability to hedge economically with
creditworthy counterparties; and
|
|
|
|
the risks of implementation of the Dodd-Frank Act on our ability
to hedge economically our generation, including potentially
reducing liquidity in the energy and commodity markets and, if
we are required to clear such transactions on exchanges or meet
other requirements, by significantly increasing the collateral
costs associated with such activities.
|
Capital
Expenditures and Capital Resources
For 2010, we invested $233 million for capital
expenditures, of which $114 million related to compliance
with the Maryland Healthy Air Act. At December 31, 2010, we
have invested $1.519 billion of the $1.674 billion
that was budgeted for capital expenditures related to compliance
with the Maryland Healthy Air Act. As the final part of our
compliance with the Maryland Healthy Air Act, we placed four
scrubbers in service at our Maryland facilities in the fourth
quarter of 2009. Provisions in the construction contracts for
the scrubbers provide for certain payments to be made after
final completion of the project. The current budget of
$1.674 billion continues to represent our best estimate of
the total capital expenditures for compliance with the Maryland
Healthy Air Act. See note 9 to our consolidated financial
statements for further discussion of scrubber contract
litigation.
The following table details the expected timing of payments for
our estimated capital expenditures for 2011 and 2012:
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
2012
|
|
|
|
(in millions)
|
|
|
Maryland Healthy Air Act
|
|
$
|
155
|
|
|
$
|
|
|
Other environmental
|
|
|
7
|
|
|
|
5
|
|
Maintenance
|
|
|
44
|
|
|
|
34
|
|
Other construction
|
|
|
52
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
258
|
|
|
$
|
43
|
|
|
|
|
|
|
|
|
|
|
We expect that available cash and future cash flows from
operations will be sufficient to fund these capital expenditures.
Environmental
Matters
Refer to Environmental Matters above for GenOn
Americas Generation.
Commodity
Prices
Refer to Commodity Prices above for GenOn Americas
Generation.
IBEW
Local 1900 Collective Bargaining Agreement
Refer to IBEW Local 1900 Collective Bargaining
Agreement above for GenOn Americas Generation.
71
Results
of Operations
Non-GAAP Performance Measures. The
following discussion includes the non-GAAP financial measures
realized gross margin and unrealized gross margin to reflect how
we manage our business. In our discussion of the results of our
reportable segments, we include the components of realized gross
margin, which are energy, contracted and capacity and realized
value of hedges. Management generally evaluates our operating
results excluding the impact of unrealized gains and losses.
When viewed with our GAAP financial results, these non-GAAP
financial measures may provide a more complete understanding of
factors and trends affecting our business. Realized gross margin
represents our gross margin (excluding depreciation and
amortization) less unrealized gains and losses on derivative
financial instruments. Conversely, unrealized gross margin
represents our unrealized gains and losses on derivative
financial instruments. None of our derivative financial
instruments recorded at fair value is designated as a hedge and
changes in their fair values are recognized currently in income
as unrealized gains or losses. As a result, our financial
results are, at times, volatile and subject to fluctuations in
value primarily because of changes in forward electricity and
fuel prices. Realized gross margin, together with its components
energy, contracted and capacity and realized value of hedges,
provide a measure of performance that eliminates the volatility
reflected in unrealized gross margin, which is created by
significant shifts in market values between periods. However,
these non-GAAP financial measures may not be comparable to
similarly titled non-GAAP financial measures used by other
companies. We use these non-GAAP financial measures in
communications with investors, analysts, rating agencies, banks
and other parties. We think these non-GAAP financial measures
provide meaningful representations of our consolidated operating
performance and are useful to us and others in facilitating the
analysis of our results of operations from one period to
another. We encourage our investors to review our consolidated
financial statements and other publicly filed reports in their
entirety and not to rely on a single financial measure.
72
2010
Compared to 2009
Consolidated
Financial Performance
We reported net loss of $781 million and net income of
$344 million for 2010 and 2009, respectively. The change in
net income/loss is detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2010
|
|
|
2009
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
|
Realized gross margin
|
|
$
|
999
|
|
|
$
|
1,107
|
|
|
$
|
(108
|
)
|
Unrealized gross margin
|
|
|
7
|
|
|
|
144
|
|
|
|
(137
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross margin (excluding depreciation and amortization)
|
|
|
1,006
|
|
|
|
1,251
|
|
|
|
(245
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenancenonaffiliate
|
|
|
299
|
|
|
|
245
|
|
|
|
54
|
|
Operations and maintenanceaffiliate
|
|
|
194
|
|
|
|
189
|
|
|
|
5
|
|
Depreciation and amortization
|
|
|
141
|
|
|
|
98
|
|
|
|
43
|
|
Impairment losses
|
|
|
1,153
|
|
|
|
385
|
|
|
|
768
|
|
Gain on sales of assets, netaffiliate
|
|
|
(3
|
)
|
|
|
(14
|
)
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
1,784
|
|
|
|
903
|
|
|
|
881
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(778
|
)
|
|
|
348
|
|
|
|
(1,126
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other expense, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
3
|
|
|
|
3
|
|
|
|
|
|
Other, net
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense, net
|
|
|
4
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(782
|
)
|
|
|
344
|
|
|
|
(1,126
|
)
|
Benefit for income taxes
|
|
|
(1
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(781
|
)
|
|
$
|
344
|
|
|
$
|
(1,125
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refer to Eastern PJM in Results of
OperationsGenOn Americas Generation above for our
realized and unrealized gross margin and operating expenses,
additional related details and variance explanations.
Segment
Refer to Eastern PJM in SegmentsGenOn
Americas Generation above for details on the Eastern PJM
segment.
Operating
Statistics
Our net capacity factor was 34% during 2010, compared to 30%
during 2009. Our power generation volumes during 2010 (in
gigawatt hours) was 15,609 compared to 13,955 during 2009. See
Operating Statistics in Results of
OperationsGenOn Americas Generation above for
additional details on net capacity factor and power generation
volumes.
Gross
Margin
Refer to Eastern PJM in Results of
OperationsGenOn Americas Generation above for our
realized and unrealized gross margin, additional related details
and variance explanations.
73
Operating
Expenses
Refer to Eastern PJM in Results of
OperationsGenOn Americas Generation above for our
operating expenses variance explanations.
2009
Compared to 2008
Consolidated
Financial Performance
We reported net income of $344 million and
$1.217 billion for 2009 and 2008, respectively. The change
in net income is detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
|
Realized gross margin
|
|
$
|
1,107
|
|
|
$
|
1,038
|
|
|
$
|
69
|
|
Unrealized gross margin
|
|
|
144
|
|
|
|
676
|
|
|
|
(532
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross margin (excluding depreciation and amortization)
|
|
|
1,251
|
|
|
|
1,714
|
|
|
|
(463
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenancenonaffiliate
|
|
|
245
|
|
|
|
239
|
|
|
|
6
|
|
Operations and maintenanceaffiliate
|
|
|
189
|
|
|
|
173
|
|
|
|
16
|
|
Depreciation and amortization
|
|
|
98
|
|
|
|
92
|
|
|
|
6
|
|
Impairment losses
|
|
|
385
|
|
|
|
|
|
|
|
385
|
|
Gain on sales of assets, netaffiliate
|
|
|
(14
|
)
|
|
|
(8
|
)
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
903
|
|
|
|
496
|
|
|
|
407
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
348
|
|
|
|
1,218
|
|
|
|
(870
|
)
|
Other expense, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
3
|
|
|
|
|
|
|
|
3
|
|
Other, net
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense, net
|
|
|
4
|
|
|
|
1
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
344
|
|
|
$
|
1,217
|
|
|
$
|
(873
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refer to Eastern PJM in Results of
OperationsGenOn Americas Generation above for our
realized and unrealized gross margin and operating expenses,
additional related details and variance explanations.
Segment
Refer to Eastern PJM in SegmentsGenOn
Americas Generation above for details on the Eastern PJM
segment.
Operating
Statistics
Our net capacity factor was 30% during 2009, compared to 33%
during 2008. Our power generation volumes during 2009 (in
gigawatt hours) was 13,955 compared to 14,999 during 2008. See
Operating Statistics in Results of
OperationsGenOn Americas Generation above for
additional details on net capacity factor and power generation
volumes.
Gross
Margin
Refer to Eastern PJM in Results of
OperationsGenOn Americas Generation above for our
realized and unrealized gross margin, additional related details
and variance explanations.
74
Operating
Expenses
Refer to Eastern PJM in Results of
OperationsGenOn Americas Generation above for our
operating expenses variance explanations.
Financial
Condition
Liquidity
and Capital Resources
Management thinks that our liquidity position and cash flows
from operations will be adequate to fund operating, maintenance
capital expenditures, and to service our operating leases and to
meet other liquidity requirements. Management regularly monitors
our ability to fund our operating, financing and investing
activities.
Sources
of Funds
Maintaining sufficient liquidity in our business is crucial in
order to mitigate the risk of future financial distress to us.
Accordingly, we plan on a prospective basis for the expected
liquidity requirements of our business considering the factors
listed below:
|
|
|
|
|
expected expenditures with respect to maintenance activities and
capital improvements, and related outages;
|
|
|
|
expected collateral postings in support of our business;
|
|
|
|
effects of market price volatility on the amount of collateral
postings for hedge transactions and risk management transactions;
|
|
|
|
effects of market price volatility on fuel pre-payment
requirements; and
|
|
|
|
seasonal and intra-month working capital requirements.
|
The principal sources of our liquidity are expected to be:
(a) existing cash on hand and expected cash flows from our
operations and the operations of our subsidiaries, (b) at
its discretion, capital contributions or advances from GenOn
North America and (c) at its discretion, letters of credit
issued under GenOns senior secured revolving credit
facility.
Our operating cash flows may be affected by, among other things:
(a) demand for electricity; (b) the difference between
the cost of fuel used to generate electricity and the market
value of the electricity generated; (c) commodity prices
(including prices for electricity, emissions allowances, natural
gas, coal and oil); (d) operations and maintenance expenses
in the ordinary course; (e) planned and unplanned outages;
(f) terms with trade creditors; and (g) cash
requirements for capital expenditures relating to certain
facilities (including those necessary to comply with
environmental regulations).
We consider all short-term investments with an original maturity
of three months or less to be cash equivalents. At
December 31, 2010, except for amounts held in bank accounts
to cover upcoming payables, all of our cash and cash equivalents
were invested in AAA-rated United States Treasury money market
funds.
At December 31, 2010, we had $202 million of cash,
which amount was available under the operating leases for
distribution to GenOn North America.
Under the operating leases, we are subject to a covenant that
restricts our right to make distributions. Our ability to
satisfy the criteria set by that covenant in the future could be
impaired by factors which negatively affect the performance of
our power generating facilities, including interruptions in
operations or curtailment of operations to comply with
environmental restrictions.
75
Uses of
Funds
Our requirements for liquidity and capital resources, other than
for the
day-to-day
operation of our generating facilities, are significantly
influenced by capital expenditures and payments under our
operating leases.
Capital Expenditures. Our capital expenditures
during 2010 were $233 million. Our estimated capital
expenditures for 2011 and 2012 are $258 million and
$43 million, respectively. See Item 1,
Business for further discussion of our capital
expenditures.
Operating Leases. We lease 100% interest in
both the Dickerson and Morgantown baseload units and associated
property through 2029 and 2034, respectively, and have an option
to extend the leases. Any extensions of the respective leases
would be for less than 75% of the economic useful life of the
facility, as measured from the beginning of the original lease
term through the end of the proposed remaining lease term. We
are accounting for these leases as operating leases. Although
there is variability in the scheduled payment amounts over the
lease term, we recognize rent expense for these leases on a
straight-line basis in accordance with GAAP. Rent expense under
our leases was $96 million for each of 2010, 2009 and 2008.
The scheduled payment amounts for our leases are
$134 million and $132 million for 2011 and 2012,
respectively. At December 31, 2010, the total notional
minimum lease payments for the remaining term of the leases
aggregated $1.7 billion and the aggregate termination value
for the leases was approximately $1.4 billion and generally
decreases over time. In addition, the present value of lease
payments at December 31, 2010 was approximately
$927 million (assuming a 10% discount rate). GenOn provides
letters of credit in support of our lease obligations in an
aggregate amount equal to the greatest of the next six months
scheduled rent payments, 50% of the next 12 months
scheduled rent payments or $75 million.
Debt
Obligations, Off-Balance Sheet Arrangements and Contractual
Obligations
Our debt obligations, off-balance sheet arrangements and
contractual obligations at December 31, 2010, are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt Obligations, Off-Balance Sheet Arrangements and
|
|
|
|
Contractual Obligations by Year
|
|
|
|
|
|
|
Less than
|
|
|
One to
|
|
|
Three to
|
|
|
More than
|
|
|
|
Total
|
|
|
One Year
|
|
|
Three Years
|
|
|
Five Years
|
|
|
Five Years
|
|
|
|
(in millions)
|
|
|
Long-term debt
|
|
$
|
27
|
|
|
$
|
6
|
|
|
$
|
10
|
|
|
$
|
11
|
|
|
$
|
|
|
Generating units operating leases
|
|
|
1,730
|
|
|
|
134
|
|
|
|
270
|
|
|
|
241
|
|
|
|
1,085
|
|
Other operating leases
|
|
|
37
|
|
|
|
5
|
|
|
|
7
|
|
|
|
7
|
|
|
|
18
|
|
Fuel commitments
|
|
|
914
|
|
|
|
371
|
|
|
|
543
|
|
|
|
|
|
|
|
|
|
Maryland Healthy Air Act
|
|
|
155
|
|
|
|
155
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
222
|
|
|
|
123
|
|
|
|
47
|
|
|
|
24
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total payments
|
|
$
|
3,085
|
|
|
$
|
794
|
|
|
$
|
877
|
|
|
$
|
283
|
|
|
$
|
1,131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our contractual obligations table does not include our
derivative obligations reported at fair value (other than fuel
supply commitments), which are discussed in note 2 to our
consolidated financial statements and asset retirement
obligations which are discussed in note 3 to our
consolidated financial statements.
Long-term debt consists of a capital lease by GenOn Chalk Point
and is reflected in the current portion of long-term debt and
long-term debt on our consolidated balance sheets, which are
discussed in note 4 to our consolidated financial
statements. Long-term debt also includes estimated interest on
the capital lease.
Generating units operating leases relate to our minimum lease
payments associated with our off-balance sheet leases of the
Dickerson and Morgantown baseload units. In addition, we have
commitments under other operating leases with various terms and
expiration dates.
Fuel commitments primarily relate to coal agreements.
76
Maryland Healthy Air Act commitments reflect the remaining
expected payments for capital expenditures to comply with the
limitations for
SO2,
NOx
and mercury emissions under the Maryland Healthy Air Act. We
completed the installation of the remaining pollution control
equipment related to compliance with the Maryland Healthy Air
Act in the fourth quarter of 2009. However, provisions in our
construction contracts provide that certain payments be made
after final completion of the project.
Other primarily represents the open purchase orders less
invoices received related to general procurement of products and
services purchased in the ordinary course of business. These
include construction, maintenance and labor activities at our
generating facilities. Other also includes fuel transportation
agreements and limestone supply and transportation agreements,
entered into on our behalf by our affiliate, GenOn Energy
Management.
Historical
Cash Flows
2010
Compared to 2009
Operating Activities. The changes in our
operating cash flows are detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2010
|
|
|
2009
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
|
Operating income (loss)
|
|
$
|
(778
|
)
|
|
$
|
348
|
|
|
$
|
(1,126
|
)
|
Non-cash items(1)
|
|
|
1,329
|
|
|
|
354
|
|
|
|
975
|
|
Receivables and accounts payable, net
|
|
|
12
|
|
|
|
(5
|
)
|
|
|
17
|
|
Inventories
|
|
|
(18
|
)
|
|
|
(17
|
)
|
|
|
(1
|
)
|
Interest payments
|
|
|
(2
|
)
|
|
|
(2
|
)
|
|
|
|
|
Prepaid rent
|
|
|
(44
|
)
|
|
|
(46
|
)
|
|
|
2
|
|
Other, net
|
|
|
14
|
|
|
|
(25
|
)
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
513
|
|
|
$
|
607
|
|
|
$
|
(94
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
See our consolidated statements of cash flows for additional
information. |
Our cash provided by operating activities is affected by
seasonality, changes in energy prices and fluctuations in our
working capital requirements. Net cash provided by operating
activities decreased by $94 million during 2010, compared
to 2009, primarily as a result of the following:
|
|
|
|
|
Realized gross margin. A decrease in cash
provided of $124 million in 2010, compared to 2009,
excluding a decrease in non-cash lower of cost or market fuel
inventory adjustments of $16 million. See Results of
Operations in this Item 7 for additional discussion
of our performance in 2010 compared to 2009; and
|
|
|
|
Operating expenses. An increase in cash used
for operations and maintenance expense of $26 million,
primarily as a result of costs related to the operation of our
scrubbers in 2010. See Results of Operations in this
Item 7 for additional discussion of our performance in 2010
compared to 2009.
|
The decrease in cash provided by and increase in cash used in
operating activities were partially offset by the following:
|
|
|
|
|
Property taxes. A decrease in cash used of
$27 million primarily related to the timing of property tax
payments;
|
|
|
|
Receivables and accounts payable, net. An
increase in cash provided of $17 million primarily related
to settlements of our non-collateralized power hedges; and
|
|
|
|
Other operating assets and liabilities. A
decrease in cash used of $12 million related to changes in
other operating assets and liabilities.
|
77
Investing Activities. The changes in our
investing cash flows are detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2010
|
|
|
2009
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
|
Capital expenditures
|
|
$
|
(233
|
)
|
|
$
|
(578
|
)
|
|
$
|
345
|
(1)
|
Proceeds from the sales of assets
|
|
|
4
|
|
|
|
14
|
|
|
|
(10
|
)(2)
|
Restricted deposit payments and other
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
$
|
(228
|
)
|
|
$
|
(563
|
)
|
|
$
|
335
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Primarily related to placing our scrubbers in service during the
fourth quarter of 2009 as part of our compliance with the
Maryland Healthy Air Act. |
|
(2) |
|
Primarily related to sales of emissions allowances in 2009 as
compared to 2010. |
Financing Activities. The changes in our
financing cash flows are detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2010
|
|
|
2009
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
|
Redemption of preferred stock in affiliate
|
|
$
|
145
|
|
|
$
|
84
|
|
|
$
|
61
|
(1)
|
Repayment of long-term debtnonaffiliate
|
|
|
(3
|
)
|
|
|
(3
|
)
|
|
|
|
|
Distributions to member
|
|
|
(350
|
)
|
|
|
(125
|
)
|
|
|
(225
|
)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities
|
|
$
|
(208
|
)
|
|
$
|
(44
|
)
|
|
$
|
(164
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Related to the redemption of our Series A preferred stock
of GenOn Americas (see note 6 to our consolidated financial
statements for further discussion). |
|
(2) |
|
Related to distributions of $350 million to our member
during 2010 compared to $125 million during 2009. |
2009
Compared to 2008
Operating Activities. The changes in our
operating cash flows are detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
|
Operating income
|
|
$
|
348
|
|
|
$
|
1,218
|
|
|
$
|
(870
|
)
|
Non-cash
items(1)
|
|
|
354
|
|
|
|
(578
|
)
|
|
|
932
|
|
Receivables and accounts payable, net
|
|
|
(5
|
)
|
|
|
(9
|
)
|
|
|
4
|
|
Funds on deposit
|
|
|
|
|
|
|
2
|
|
|
|
(2
|
)
|
Inventories
|
|
|
(17
|
)
|
|
|
(23
|
)
|
|
|
6
|
|
Interest payments
|
|
|
(2
|
)
|
|
|
(2
|
)
|
|
|
|
|
Interest income
|
|
|
|
|
|
|
3
|
|
|
|
(3
|
)
|
Prepaid rent
|
|
|
(46
|
)
|
|
|
(24
|
)
|
|
|
(22
|
)
|
Other, net
|
|
|
(25
|
)
|
|
|
10
|
|
|
|
(35
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
607
|
|
|
$
|
597
|
|
|
$
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
See our consolidated statements of cash flows for additional
information. |
78
Our cash provided by operating activities is affected by
seasonality, changes in energy prices and fluctuations in our
working capital requirements. Net cash provided by operating
activities increased by $10 million during 2009 compared to
2008, primarily as a result of the following:
|
|
|
|
|
Realized gross margin. An increase in cash
provided of $84 million in 2009, compared to 2008,
excluding an increase in non-cash lower of cost or market fuel
inventory adjustments of $15 million. See Results of
Operations in this item 7 for additional discussion
of our performance in 2009 compared to 2008; partially offset by
|
|
|
|
Other operating assets and liabilities. An
increase in cash used of $30 million related to changes in
other operating assets and liabilities, of which approximately
$19 million related to the timing of property tax payments
in 2009 compared to 2008 and approximately $10 million
related to option premiums received during 2008 compared to 2009;
|
|
|
|
Prepaid rent. An increase in cash used of
$22 million as a result of scheduled rent payments for our
leveraged leases were higher during 2009 than during
2008; and
|
|
|
|
Operating expense. An increase in cash used
related to higher operations and maintenance expense of
$22 million. See Results of Operations for
additional discussion of our performance during 2009 compared to
2008.
|
Investing Activities. The changes in our
investing cash flows are detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Increase
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Capital expenditures
|
|
$
|
(578
|
)
|
|
$
|
(641
|
)
|
|
$
|
63
|
(1)
|
Proceeds from the sales of assets
|
|
|
14
|
|
|
|
8
|
|
|
|
6
|
(2)
|
Restricted deposit payments and other
|
|
|
1
|
|
|
|
(34
|
)
|
|
|
35
|
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
$
|
(563
|
)
|
|
$
|
(667
|
)
|
|
$
|
104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Primarily related to our environmental capital expenditures
related to our compliance with the Maryland Healthy Air Act. |
|
(2) |
|
Primarily related to sales of emissions allowances to third
parties. |
|
(3) |
|
Related to $34 million placed in an escrow account in
September 2008, to satisfy the conditions of Potomac
Rivers agreement with the City of Alexandria, Virginia.
See note 10 to our consolidated financial statements for
additional information on Potomac Rivers agreement with
the City of Alexandria, Virginia. |
Financing Activities. The changes in our
financing cash flows are detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Redemption of preferred stock in affiliate
|
|
$
|
84
|
|
|
$
|
31
|
|
|
$
|
53
|
(1)
|
Repayment of long-term debtnonaffiliate
|
|
|
(3
|
)
|
|
|
(2
|
)
|
|
|
(1
|
)
|
Capital contributions
|
|
|
|
|
|
|
250
|
|
|
|
(250
|
)(2)
|
Distributions to member
|
|
|
(125
|
)
|
|
|
(325
|
)
|
|
|
200
|
(3)
|
Other
|
|
|
|
|
|
|
(1
|
)
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities
|
|
$
|
(44
|
)
|
|
$
|
(47
|
)
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Related to the redemption of our Series A preferred stock
of GenOn Americas (see note 6 to our consolidated financial
statements for further discussion). |
|
(2) |
|
Includes $250 million as a result of capital contributions
received from GenOn North America. |
|
(3) |
|
Related to distributions of $125 million to our member
during 2009 compared to $325 million during 2008. |
79
Critical
Accounting Estimates
The accounting policies described below are considered critical
to obtaining an understanding of our consolidated financial
statements because their application requires significant
estimates and judgments by management in preparing our
consolidated financial statements. Managements estimates
and judgments are inherently uncertain and may differ
significantly from actual results achieved. Management considers
an accounting estimate to be critical if the following
conditions apply:
|
|
|
|
|
the estimate requires significant assumptions; and
|
|
|
|
changes in the estimate could have a material effect on our
consolidated results of operations or financial
condition; or
|
|
|
|
if different estimates that could have been selected had been
used, there could be a material effect on our consolidated
results of operations or financial condition.
|
We have discussed the selection and application of these
accounting estimates with the Audit Committee of the Board of
Directors and our independent registered public accounting firm.
It is managements view that the current assumptions and
other considerations used to estimate amounts reflected in our
consolidated financial statements are appropriate. However,
actual results can differ significantly from those estimates
under different assumptions and conditions. The sections below
contain information about our most critical accounting
estimates, as well as the effects of hypothetical changes in the
material assumptions used to develop the estimates.
Revenue
Recognition and Accounting for Energy Trading and Marketing
Activities
Nature of Estimates Required. Accounting
standards require an accrual model to be used to account for our
revenues from the sale of energy, capacity and ancillary
services. We recognize revenue when it has been earned and
collection is probable as a result of electricity delivered or
capacity available to customers pursuant to contractual
commitments that specify volume, price and delivery
requirements. Sales of energy primarily are based on economic
dispatch, or they may be as-ordered by an ISO or
RTO, based on member participation agreements, but without an
underlying contractual commitment. ISO and RTO revenues and
revenues for sales of energy based on economic dispatch are
recorded on the basis of MWh delivered, at the relevant
day-ahead or real-time prices. Sales that have been delivered
but not billed by period end are estimated.
The accrual model is also used to account for our revenues from
the sales of natural gas. These sales are sold at market-based
prices through third party contracts. Sales that have been
delivered but not billed by period end are estimated.
Accounting standards require a fair value model to be used to
measure fair value on a recurring basis for derivative energy
contracts that are used to manage our exposure to commodity
price risk or that are used in GenOn Americas Generations
proprietary trading and fuel oil management activities. We use a
variety of derivative financial instruments, such as futures,
forwards, swaps and option contracts, in the management of our
business. Such derivative financial instruments have varying
terms and durations, or tenors, which range from a few days to a
number of years, depending on the instrument.
Derivative financial instruments are recorded in our
consolidated financial statements at fair value as either
derivative contract assets or derivative contract liabilities,
with changes in fair value recognized currently in income unless
they qualify for a scope exception pursuant to the accounting
guidance. Management considers fair value techniques and
valuation adjustments related to credit and liquidity to be
critical accounting estimates. These estimates are considered
significant because they are highly susceptible to change from
period to period and are dependent on many subjective factors.
Transactions that are not accounted for using the fair value
model under the accounting guidance for derivative financial
instruments are either not derivatives or qualify for the scope
exception and are accounted for under accrual accounting. We
recognize immediately in income inception gains and losses for
transactions at other than the bid price or ask price.
80
Key Assumptions and Approach Used. In
determining 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 and
over-the-counter
instruments (Level 1 or Level 2) to price curves
that cannot be validated through external pricing sources
(Level 3). Note 2 to our consolidated financial
statements explains the fair value hierarchy. For most delivery
locations and tenors where we have positions, we receive
multiple independent broker price 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 our assets and ask prices for
liabilities. If no active market exists, we estimate the fair
value of certain derivative financial instruments using price
extrapolation, interpolation and other quantitative methods. We
have not identified any distressed market conditions that would
alter our valuation techniques at December 31, 2010. Fair
value estimates involve uncertainties and matters of significant
judgment. Our techniques for fair value estimation include
assumptions for market prices, correlation and volatility. The
degree of estimation increases for longer duration contracts,
contracts with multiple pricing features, option contracts and
off-hub delivery points. GenOn Americas Generations assets
and liabilities classified as Level 3 in the fair value
hierarchy represent approximately 2% of its total assets and 8%
of its total liabilities measured at fair value at
December 31, 2010. GenOn Mid-Atlantics assets and
liabilities classified as Level 3 in the fair value
hierarchy represent approximately 3% of its total assets and 29%
of its total liabilities measured at fair value at
December 31, 2010.
The fair value of derivative contract assets and liabilities in
our consolidated balance sheets is also affected by our
assumptions as to time value, credit risk and non-performance
risk. The nominal value of the contracts is discounted using a
forward interest rate curve based on LIBOR. In addition, the
fair value of our derivative contract assets is reduced to
reflect the estimated default risk of counterparties on their
contractual obligations to us. The default risk of our
counterparties for a significant portion of our overall net
position is measured based on published spreads on credit
default swaps. The fair value of our derivative contract
liabilities is reduced to reflect our estimated risk of default
on our contractual obligations to counterparties and is measured
based on published default rates of our debt. The credit risk
reflected in the fair value of our derivative contract assets
and the non-performance risk reflected in the fair value of our
derivative contract liabilities 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.
Effect if Different Assumptions Used. The
amounts recorded as revenue or cost of fuel, electricity and
other products change as estimates are revised to reflect actual
results and changes in market conditions or other factors, many
of which are beyond our control. Because we use derivative
financial instruments and have not elected cash flow or fair
value hedge accounting for the majority of our derivative
financial instruments, certain components of our financial
statements, including gross margin, operating income and balance
sheet ratios, are at times volatile and subject to fluctuations
in value primarily as a result of changes in forward energy and
fuel prices. Significant negative changes in fair value could
require us to post additional collateral either in the form of
cash or letters of credit. Because the fair value measurements
of our material assets and liabilities are based on observable
market information, there is not a significant range of values
around the fair value estimate. For our derivative financial
instruments that are measured at fair value using quantitative
pricing models, a significant change in estimate could affect
our results of operations and cash flows at the time contracts
are ultimately settled. The estimated fair value of GenOn
Americas Generations derivative contract assets and
liabilities was a net asset of $679 million at
December 31, 2010. A 10% change in electricity and fuel
prices would result in approximately a $150 million change
in the fair value of its net asset at December 31, 2010.
The estimated fair value of GenOn Mid-Atlantics derivative
contract assets and liabilities was a net asset of
$677 million at December 31, 2010. A 10% change in
electricity and fuel prices would result in approximately a
$141 million change in the fair value of its net asset at
December 31, 2010. See Item 7A. Quantitative and
Qualitative Disclosures About Market Risk for further
sensitivities in our assumptions used to calculate fair value.
See note 2 to our consolidated financial statements for
further information on derivative financial instruments related
to energy trading and marketing activities.
81
Long-Lived
Assets
Estimated
Useful Lives
Nature of Estimates Required. The estimated
useful lives of our long-lived assets are used to compute
depreciation expense, determine the carrying value of asset
retirement obligations and estimate expected future cash flows
attributable to an asset for the purposes of impairment testing.
Estimated useful lives are based, in part, on the assumption
that we provide an appropriate level of capital expenditures
while the assets are still in operation. Without these continued
capital expenditures, the useful lives of these assets could
decrease significantly.
Key Assumptions and Approach Used. Estimated
useful lives are the mechanism by which we allocate the cost of
long-lived assets over the assets service period. We
perform depreciation studies periodically to update changes in
estimated useful lives. The actual useful life of an asset could
be affected by changes in estimated or actual commodity prices,
environmental regulations, various legal factors, competitive
forces and our liquidity and ability to sustain required
maintenance expenditures and satisfy asset retirement
obligations. We use composite depreciation for groups of similar
assets and establish an average useful life for each group of
related assets. In accordance with the accounting guidance
related to evaluating long-lived assets for impairment, we cease
depreciation on long-lived assets classified as held for sale.
Also, we may revise the remaining useful life of an asset held
and used subject to impairment testing. See note 3 to our
consolidated financial statements for additional information
related to our property, plant and equipment.
We completed a depreciation study in the first quarter of 2010
that resulted in a change to the estimated useful lives of our
long-lived assets. The change in useful lives resulted in an
increase of approximately $2 million in depreciation and
amortization expense for GenOn Americas Generation, and a
decrease of approximately $3 million for GenOn Mid-Atlantic
during 2010. In addition, the change in useful lives also
resulted in an increase of $9 million in GenOn Americas
Generations asset retirement obligations and
$1 million in GenOn Mid-Atlantics asset retirement
obligations and a corresponding increase of $9 million in
GenOn Americas Generations property, plant and equipment,
net and $1 million in GenOn Mid-Atlantics property,
plant and equipment, net at December 31, 2010.
Effect if Different Assumptions Used. The
determination of estimated useful lives is dependent on
subjective factors such as expected market conditions, commodity
prices and anticipated capital expenditures. Since composite
depreciation rates are used, the actual useful life of a
particular asset may differ materially from the useful life
estimated for the related group of assets. A 10% increase in the
weighted average useful lives of GenOn Americas
Generations facilities would result in a $21 million
decrease in its annual depreciation expense. A 10% increase in
the weighted average useful lives of GenOn Mid-Atlantics
facilities would result in a $13 million decrease in its
annual depreciation expense. A 10% decrease in the weighted
average useful lives of GenOn Americas Generations
facilities would result in a $25 million increase in its
annual depreciation expense. A 10% decrease in the weighted
average useful lives of GenOn Mid-Atlantics facilities
would result in a $16 million increase in its annual
depreciation expense. In the event the useful lives of
significant assets were found to be shorter than originally
estimated, depreciation expense may increase, liabilities
recognized for future asset retirement obligations may be
insufficient and impairments in the carrying value of tangible
and intangible assets may result.
Asset
Retirement Obligations
Nature of Estimates Required. We account for
asset retirement obligations under the accounting guidance for
asset retirement obligations and conditional asset retirements.
This guidance requires an entity to recognize the fair value of
a liability for conditional and unconditional asset retirement
obligations in the period in which they are incurred. Retirement
obligations associated with long-lived assets included within
the scope of the accounting guidance are those obligations for
which a requirement exists under enacted laws, statutes and
written or oral contracts, including obligations arising under
the doctrine of promissory estoppel. Asset retirement
obligations are estimated using the estimated current cost to
satisfy the retirement obligation, increased for inflation
through the expected period of retirement and discounted back to
present value at our credit-adjusted risk free rate. GenOn
Americas Generation has identified certain asset retirement
obligations
82
within its power generating operations and has a noncurrent
liability of $54 million recorded at December 31,
2010. GenOn Mid-Atlantic has identified certain retirement
obligations with its power generating operations and has a
noncurrent liability of $18 million recorded at
December 31, 2010. These asset retirement obligations are
primarily related to asbestos abatement at some of our
generating facilities, the removal of oil storage tanks,
equipment on leased property and environmental obligations
related to the closing of ash disposal sites.
During 2010, a third-party consulting firm completed a study on
behalf of GenOn to determine the extent of asbestos present at
certain of our generating facilities. The consulting firm also
provided GenOn with cost estimates for the removal of the
asbestos. As a result, we revised the cost estimates associated
with our asset retirement obligations for asbestos removal at
all of our generating facilities.
Key Assumptions and Approach Used. The fair
value of liabilities associated with the initial recognition of
asset retirement obligations is estimated by applying a present
value calculation to current engineering cost estimates of
satisfying the obligations. Significant inputs to the present
value calculation include current cost estimates, estimated
asset retirement dates and appropriate discount rates. Where
appropriate, multiple cost
and/or
retirement scenarios have been probability weighted.
Effect if Different Assumptions Used. We
update liabilities associated with asset retirement obligations
as significant assumptions change or as relevant new information
becomes available.
Goodwill
(GenOn Mid-Atlantic)
Nature of Estimates Required. We evaluate our
goodwill for impairment at least annually and periodically if
indicators of impairment are present in accordance with the
accounting guidance related to goodwill and other intangible
assets. The results of our impairment testing may be affected by
a significant adverse change in the extent or manner in which a
reporting units assets are being used, a significant
adverse change in legal factors or in the business climate that
could affect the value of a reporting unit, as well as other
economic or operational analyses. If the carrying amount of the
reporting unit is not recoverable, an impairment charge is
recorded. The amount of the impairment charge, if impairment
exists, is calculated as the difference between the fair value
of the reporting unit goodwill and its carrying value. For this
test, our business constitutes a single reporting unit. We
perform our annual assessment of goodwill at October 31 and
whenever contrary evidence exists as to the recoverability of
goodwill.
Key Assumptions and Approach Used. The
accounting estimates related to determining the fair value of
goodwill require management to make assumptions about cost of
capital, future revenues, operating costs, capital expenditures
and forward commodity prices over the life of the assets as well
as evaluating observable market data. Our assumptions about
future revenues, costs and forward prices require significant
judgment because such factors have fluctuated in the past and
will continue to do so in the future.
2010 and
2009
We performed our annual test for goodwill impairment effective
October 31, 2010 and 2009. The test was based upon the most
recent business plans and market data from independent sources
available at the respective testing dates. We utilized multiple
valuation approaches in arriving at a fair value of our
reporting unit for purposes of the test, including an income
approach involving discounted cash flows and a market approach
involving trading multiples of peer companies. The transaction
method was not utilized in either year because there were no
comparable recent transactions, specifically no transactions for
baseload coal-fired generating facilities in the PJM market. In
addition to the market approaches listed above, we also
performed reconciliations of the fair value of the Mid-Atlantic
reporting unit to the market capitalization of Mirant on the
testing dates, adjusted for a control premium, as a
reasonableness check for the other approaches. The
reconciliations resulted in values that were consistent with the
valuation approaches. For both 2010 and 2009, we assigned a 50%
weighting to the income approach and a 50% weighting to the
market approach to determine the fair value of the reporting
unit. However, a change in the relative weightings between the
income and market approach would have an immaterial effect on
the outcome of the goodwill impairment
83
analyses. The annual evaluations of goodwill during 2010 and
2009 indicated that the carrying value of the reporting unit
exceeded the fair value, requiring the second step of the
goodwill analysis to be performed.
Based on the results of the step one goodwill impairment
analyses, we tested our long-lived assets for impairment under
the accounting guidance related to impairment of long-lived
assets. The long-lived assets must be first tested for
impairment before completion of the step two test for goodwill.
During 2010, we determined that no impairment of our long-lived
assets was required as the undiscounted cash flows exceeded the
carrying value for each generating facility. For 2009, we
determined that the Potomac River generating facility was
impaired, as the carrying value exceeded the undiscounted cash
flows. We recorded an impairment loss of $202 million on
our consolidated statement of operations to reduce the carrying
value of the Potomac River generating facility to its estimated
fair value. We determined that none of our other long-lived
assets was impaired at October 31, 2009. See note 3 to
our consolidated financial statements contained elsewhere in
this report for additional information related to our property,
plant and equipment.
We then performed the second step of the goodwill impairment
test, which requires an allocation of the fair value as the
purchase price in a hypothetical acquisition of the reporting
unit. The fair value of the reporting unit was compared to the
fair value of the tangible and intangible assets and the
remaining value was the implied goodwill. During 2010, as a
result of this analysis, we recorded an impairment loss of
$616 million on our consolidated statement of operations to
reduce the carrying value of goodwill to its implied fair value,
which was zero. For 2009, we recorded an impairment loss of
$183 million on our consolidated statement of operations to
reduce the carrying value of goodwill to its implied fair value.
Our assessments of goodwill for 2010 and 2009 included
assumptions about the following:
|
|
|
|
|
electricity, fuel and emissions prices;
|
|
|
|
capacity payments under the RPM provisions of PJMs tariff;
|
|
|
|
costs of
CO2
allowances under a potential federal
cap-and-trade
program and other environmental regulations;
|
|
|
|
timing of announced transmission projects;
|
|
|
|
timing and extent of generating capacity additions and
retirements; and
|
|
|
|
future capital expenditure requirements for the generating
facility.
|
Our assumptions related to future electricity and fuel prices
were based on observable market prices to the extent available
and long-term prices derived from proprietary fundamental market
modeling. Our long-term capacity prices were based on the
assumption that the PJM RPM capacity market would continue to be
consistent with the current structure. We also assumed that a
federal
CO2
cap-and-trade
program would be instituted later this decade. There are several
transmission projects currently planned in the Mid-Atlantic
region, including the Trans-Allegheny Interstate Line (TrAIL),
Mid-Atlantic Power Pathway transmission line (MAPP) and the
Potomac-Appalachian transmission line (PATH). Our assumptions
regarding the timing of these projects were based on the current
status of permitting and construction of each project. Our
assumptions regarding electricity demand were based on forecasts
from PJM and assumptions for generating capacity additions and
retirements included publicly-announced projects, which take
into account renewable sources of electricity. In addition, the
assumptions exclude general corporate overhead allocations, but
include overhead allocations from GenOn Energy Management under
the assumption that a market participant would utilize a trading
company to manage the procurement of fuel and the sale of
electricity. Our assumptions for determining the fair value of
the Dickerson generating facility included scenarios related to
the success of challenging the legality of the Montgomery
County, Maryland
CO2
levy.
Our estimates of future cash flows did not include contracts
entered into to hedge economically the expected generation of
our generating facilities. The cash flows related to these
contracts were excluded because they were not directly
attributable to our generating facilities.
84
The following chart details our assumptions used in the goodwill
impairment analyses:
|
|
|
|
|
|
|
|
|
|
|
October 2010
|
|
|
October 2009
|
|
|
Income Approach Assumptions:
|
|
|
|
|
|
|
|
|
EBITDA multiple for terminal value calculation
|
|
|
8.0
|
|
|
|
8.0
|
|
Market Approach Assumptions:
|
|
|
|
|
|
|
|
|
EBITDA multiple for public company
approach(1)
|
|
|
8.0
|
|
|
|
6.5
|
|
Valuation Approach Weightings:
|
|
|
|
|
|
|
|
|
Income approach
|
|
|
50
|
%
|
|
|
50
|
%
|
Market approach
|
|
|
50
|
%
|
|
|
50
|
%
|
|
|
|
(1) |
|
Changed primarily as a result of changes in trading multiples of
peer companies common stock. |
Asset
Impairments
Nature of Estimates Required. We evaluate our
long-lived assets, including intangible assets, for impairment
in accordance with applicable accounting guidance. The amount of
an impairment charge is calculated as the excess of the
assets carrying value over its fair value, which generally
represents the discounted expected future cash flows
attributable to the asset, or in the case of an asset we expect
to sell, at its fair value less costs to sell.
The accounting guidance related to impairments of long-lived
assets requires management to recognize an impairment charge if
the sum of the undiscounted expected future cash flows from a
long-lived asset or definite-lived intangible asset is less than
the carrying value of that asset. We evaluate our long-lived
assets (property, plant and equipment) and definite-lived
intangible assets for impairment whenever indicators of
impairment exist or when we commit to sell the asset. These
evaluations of long-lived assets and definite-lived intangible
assets may result from significant decreases in the market price
of an asset, a significant adverse change in the extent or
manner in which an asset is being used or in its physical
condition, a significant adverse change in legal factors or in
the business climate that could affect the value of an asset, as
well as other economic or operational analyses. If the carrying
amount is not recoverable, an impairment charge is recorded.
The prices for power and natural gas remain low compared to
several years ago. The energy gross margin from our baseload
coal units is negatively affected by these price levels.
Additionally, the current weak economic conditions and various
demand-response programs have resulted in a decrease in the
forecasted gross margin of our generating facilities. On an
ongoing basis, we evaluate our long-lived assets for indications
of impairment; however, given the remaining useful lives for
many of our generating facilities, the total undiscounted cash
flows for these generating facilities are more significantly
affected by the long-term view of supply and demand than by the
short term fluctuations in energy prices and demand. As such, we
typically do not consider short term decreases in either energy
prices or demand to cause an impairment evaluation. Our current
expectation is that there will be a recovery in gross margins
over time as a result of declining reserve margins in the
markets in which we operate such that companies constructing new
generating facilities can earn a reasonable rate of return on
their investment. This implies that gross margins and therefore
cash flows in the future will be better than they are currently
because market prices will need to rise high enough to provide
an incentive for new generating facilities to be built and the
entire market will realize the benefit of those higher gross
margins.
Key Assumptions and Approach Used. The
impairment evaluation is a two-step process, the first of which
involves comparing the undiscounted cash flows to the carrying
value of the asset. If the carrying value exceeds the
undiscounted cash flows, the fair value of the asset must be
calculated on a discounted basis. The fair value of an asset is
the price that would be received from a sale of the asset in an
orderly transaction between market participants at the
measurement date. Quoted market prices in active markets are the
best evidence of fair value and are used as the basis for the
measurement, when available. In the absence of quoted prices for
identical or similar assets, fair value is estimated using
various internal and external valuation methods. These methods
include discounted cash flow analyses and reviewing available
information on
85
comparable transactions. The determination of fair value
requires management to apply judgment in estimating future
capacity and energy prices, environmental and maintenance
expenditures and other cash flows. Our estimates of the fair
value of the assets include significant assumptions about the
timing of future cash flows, remaining useful lives and the
selection of a discount rate that represents the estimated
weighted average cost of capital consistent with the risk
inherent in future cash flows.
Our long-lived asset impairment assessments typically include
assumptions about the following:
|
|
|
|
|
electricity, fuel and capacity prices;
|
|
|
|
costs related to compliance with environmental regulations;
|
|
|
|
timing of announced transmission projects;
|
|
|
|
timing and extent of generating capacity additions and
retirements; and
|
|
|
|
future capital expenditure requirements related to the
generating facilities.
|
2010
GenOn Mid-Atlantic Generating FacilitiesGenOn
Mid-Atlantic has goodwill recorded on its standalone balance
sheet, which is eliminated upon consolidation at GenOn North
America. In accordance with accounting guidance for goodwill and
other intangible assets, we are required to test the goodwill
balance at least annually. We performed the goodwill assessment
at October 31, 2010, which, by policy, is our annual
testing date. In conducting step one of the goodwill impairment
analysis, we noted that the carrying value of its net assets
exceeded the calculated fair value, indicating that step two of
the goodwill impairment analysis was required. Based on the
results of the step one goodwill impairment analysis, we tested
our long-lived assets for impairment under the accounting
guidance related to impairment of long-lived assets before
completion of the step two test for goodwill.
Upon completion of the assessment, we determined that none of
the GenOn Mid-Atlantic generating facilities were impaired at
October 31, 2010.
In December 2010, PJM published an updated load forecast, which
depicted a decrease in the expected demand from prior
projections because of lower economic growth expectations. As a
result of the load forecast, our current expectation is that
there will be a decrease in the clearing prices for future
capacity auctions in certain years. The decrease in projected
capacity revenue caused us to update our October 2010 impairment
review of our long-lived assets. The sum of the updated December
2010 undiscounted cash flows for the Chalk Point and Morgantown
generating facilities exceeded their carrying values, which
represented approximately 47% and 35% of Mirant Americas
Generations total property, plant and equipment, net and
approximately 55% and 40% of Mirant Mid-Atlantics total
property, plant and equipment, net at December 31, 2010.
However, we determined that the Dickerson and Potomac River
generating facilities were impaired at December 31, 2010,
as the carrying values exceeded the updated December 2010
undiscounted cash flows. GenOn Americas Generation recorded
fourth quarter impairment losses of $523 million and
$42 million on the consolidated statement of operations to
reduce the carrying values of the Dickerson and Potomac River
generating facilities, respectively, to their estimated fair
values. GenOn Mid-Atlantic recorded fourth quarter impairment
losses of $497 million and $40 million on the
consolidated statement of operations to reduce the carrying
values of the Dickerson and Potomac River generating facilities,
respectively, to their estimated fair values. In addition, as a
result of the full impairment of the Potomac River generating
facility, we recorded $32 million in operations and
maintenance expense and corresponding liabilities associated
with our commitment to reduce particulate emissions at our
Potomac River generating facility as part of the agreement with
the City of Alexandria, Virginia. The planned capital investment
would not be recovered in future periods based on the current
projected cash flows of the Potomac River generating facility.
Our assumptions related to future electricity and fuel prices
were based on observable market prices to the extent available
and long-term prices derived from proprietary fundamental market
modeling. The long-term capacity prices were based on the
assumption that the PJM RPM capacity market would continue to be
consistent with the current structure. For the Dickerson
generating facility, the total
CO2
costs under the levy were determined by applying the cost of
CO2
emissions to the expected generation forecasts. Our estimate of
future cash flows related to the Dickerson generating facility
involved considering scenarios related to the
86
Montgomery County levy. The scenarios are related to the success
of the legal challenges to the law. We also assumed that a
federal
CO2
cap-and-trade
program would be instituted later this decade which would
supplant all pre-existing
CO2
programs, including the Montgomery County levy. In addition, our
assumptions included costs associated with compliance of other
environmental regulations. There are several transmission
projects currently planned in the Mid-Atlantic region, including
the Trans-Allegheny Interstate Line (TrAIL), Mid-Atlantic Power
Pathway transmission line (MAPP) and the Potomac-Appalachian
transmission line (PATH). The assumptions regarding the timing
of these projects were based on the current status of permitting
and construction of each project. The assumptions regarding
electricity demand were based on forecasts from PJM and
assumptions for generating capacity additions and retirements
included publicly-announced projects, which take into account
renewable sources of electricity. Capital expenditures include
the remaining contract retention payments for the completion of
the Maryland Healthy Air Act pollution control equipment for our
Maryland generating facilities. For our Potomac River generating
facility, the cash flows also include the remaining
$32 million that GenOn Potomac River committed to spend to
reduce particulate emissions as part of the agreement with the
City of Alexandria, Virginia.
The estimates and assumptions used in the impairment analyses of
the GenOn Mid-Atlantic generating facilities are subject to a
high degree of uncertainty, and changes in these assumptions
could affect the amount of the impairment loss or result in
additional future impairment losses. A decrease in projected
electricity prices or an increase in coal prices would decrease
the future cash flows of the GenOn Mid-Atlantic generating
facilities. Additionally, decreases in the projected demand or
changes to the structure of the PJM RPM capacity market could
negatively affect the future capacity prices the facilities will
earn. The assumptions include the development of a potential
federal
cap-and-trade
program for
CO2
emissions. If we are not compensated for the costs of complying
with a federal
CO2
program through allocated
CO2
allowances, increased electricity and capacity prices or
decreased coal prices, the cash flows of the GenOn Mid-Atlantic
generating facilities would be negatively affected. In addition,
if pre-existing
CO2
emission programs such as the RGGI and the Montgomery County
levy are allowed to remain in effect under a federal
CO2
program, the cash flows of the GenOn Mid-Atlantic generating
facilities would be negatively affected. If the planned
transmission projects are completed earlier than assumed, this
could negatively affect the cash flows of the facilities. Also,
changes in assumptions regarding generating capacity additions
and retirements in the PJM region could affect the cash flows,
depending on the timing and extent of additions and retirements.
The assumptions include only those capital expenditures needed
to keep the plants operational through their estimated remaining
useful lives. However, changes in laws or regulations could
require additional capital investments beyond amounts forecasted
to keep the plants operational.
The estimates of future cash flows did not include contracts
entered into to hedge economically the expected generation of
GenOn Mid-Atlantics generating facilities. The cash flows
related to these contracts were excluded because they were not
directly attributable to each of the generating facilities.
For purposes of impairment testing, a long-lived asset or assets
must be grouped at the lowest level of independent identifiable
cash flows. Each generating facility was determined to be its
own group, which included the leasehold improvements for the
leased generating units at the Dickerson and Morgantown
generating facilities. See note 3(d) to our consolidated
financial statements for further information related to our
impairment analyses.
Dickerson Generating FacilityWe also reviewed our
Dickerson generating facility for impairment in the second
quarter of 2010 upon the enactment of the
CO2
levy by the Montgomery County Council. Upon completion of the
assessment, we determined that the Dickerson generating facility
was not impaired in the second quarter of 2010.
Bowline Generating Facility (GenOn Americas
Generation)During the second quarter of 2010, the
NYISO issued its annual peak load and energy forecast in its
Gold Book. The Gold Book reports projected electricity supply
and demand for the New York control area for the next ten years.
The most recent Gold Book projects a significant decrease in
future electricity demand as a result of current economic
conditions and the expected future effects of demand-side
management programs in New York. The expected reduction in
future demand as a result of demand-side management programs is
being driven primarily by an energy efficiency program being
instituted within the State of New York that will seek to
achieve a 15% reduction
87
from 2007 energy volumes by 2015. As a result of the projections
in the Gold Book, GenOn Americas Generation evaluated the
Bowline generating facility for impairment in the second quarter
of 2010. The sum of the probability weighted undiscounted cash
flows for the Bowline generating facility exceeded the carrying
value. As a result, GenOn Americas Generation did not record an
impairment loss for the Bowline generating facility during the
second quarter of 2010.
GenOn Bowline has challenged its property tax assessment for the
2009 and 2010 tax years. Although the assessment for the 2010
tax year was reduced significantly from the assessment received
in 2009, the assessment continues to exceed significantly the
estimated fair value of the generating facility.
In the fourth quarter of 2010, GenOn Americas Generation
identified certain operational issues that reduced the available
capacity of the Bowline generating facility. GenOn Americas
Generation is in the process of evaluating long-term solutions
for the generating facility, but its current expectation is that
the reduction in available capacity could extend through 2012.
In the fourth quarter of 2010, we again evaluated the Bowline
generating facility for impairment because of the expected
extended reduction in available capacity together with the
pending property tax litigation and the effect of supply and
demand assumptions in the NYISOs Gold Book. The sum of the
probability weighted undiscounted cash flows for the Bowline
generating facility exceeded the carrying value. Therefore,
GenOn Americas Generation did not record an impairment loss for
the Bowline generating facility during 2010. The carrying value
of the Bowline generating facility represented approximately 5%
of our total property, plant and equipment, net at
December 31, 2010. See note 3(d) to our consolidated
financial statements for further information related to our
impairment analysis of the Bowline generating facility.
Emissions AllowancesIn August 2010, the EPA
proposed a replacement for the CAIR. The market prices for
SO2
and
NOx
emissions allowances declined as a result of the proposed rule.
Our historical accounting policy has been to include emissions
allowances in our asset groupings when evaluating long-lived
assets for impairment. However, to the extent the final EPA rule
significantly modifies or ends the current
cap-and-trade
program, we may evaluate whether our
SO2
and
NOx
emissions allowances included in property, plant and equipment
and intangible assets should be evaluated separately from the
underlying generating facilities. The carrying value of the
SO2
and
NOx
emissions allowances included in property, plant and equipment
and intangible assets at December 31, 2010 was
approximately $146 million at GenOn Americas Generation and
approximately $85 million at GenOn Mid-Atlantic. See
Environmental Matters for further information on the
EPAs proposed replacement of the CAIR.
2009
Potrero Generating FacilityIn the third quarter of
2009, GenOn Potrero executed a settlement agreement with the
City and County of San Francisco in which it agreed to shut
down the Potrero generating facility when it is no longer needed
for reliability, as determined by the CAISO. That settlement
agreement became effective in November 2009. In December 2010,
the CAISO provided GenOn Potrero with the requisite notice of
termination of the RMR agreement. On January 19, 2011, at
the request of GenOn Potrero, the FERC approved changes to GenOn
Potreros RMR agreement to allow the CAISO to terminate the
RMR agreement effective February 28, 2011. On
February 28, 2011, the Potrero facility was shut down. The
Potrero generating facility was fully depreciated at
December 31, 2010.
The asset group for GenOn Potrero included intangible assets
recorded at GenOn California North related to trading rights and
development rights. As a result of certain terms included in the
settlement agreement, GenOn Americas Generation separately
evaluated the trading and development rights associated with the
Potrero generating facility for impairment and determined that
both of these intangible assets were fully impaired as of
September 30, 2009. Accordingly, GenOn Americas Generation
recognized an impairment loss of $9 million on its
consolidated statement of operations to write off the carrying
value of the intangible assets related to the Potrero generating
facility. See note 3(d) to GenOn Americas Generations
consolidated financial statements for further information
related to our impairment analysis of the Potrero generating
facility and related intangible assets.
88
Contra Costa Generating FacilityOn
September 2, 2009, GenOn Delta entered into an agreement
with PG&E for the 674 MW at Contra Costa units 6 and 7
for the period from November 2011 through April 2013. At the end
of the agreement, and subject to any necessary regulatory
approval, GenOn Delta has agreed to retire Contra Costa units 6
and 7, which began operations in 1964, in furtherance of state
and federal policies to retire aging power plants that utilize
once-through cooling technology. GenOn Americas Generation
evaluated the trading rights related to GenOn Deltas
Contra Costa generating facility for impairment during the third
quarter of 2009 as a result of the retirement provisions in the
tolling agreement. Because the Contra Costa generating facility
is under contract with PG&E through the expected shutdown
date, GenOn Americas Generation determined the intangible asset
was fully impaired as of September 30, 2009. GenOn Americas
Generation recorded an impairment loss of $5 million on its
consolidated statement of operations to write off the carrying
value of the trading rights related to the Contra Costa
generating facility.
Canal Generating FacilityGenOn Americas
Generations 1,126 MW Canal generating facility is
located in the lower SEMA load zone in the ISO-NE control area.
ISO-NE previously has determined that, at times, it is necessary
for the Canal generating facility to operate to meet local
reliability criteria for SEMA when it is not economic for the
Canal generating facility to operate based upon prevailing
market prices. When the Canal generating facility operates to
meet local reliability criteria, GenOn Americas Generation is
compensated at the price they bid into the ISO-NE, pursuant to
ISO-NE market rules, rather than at the market price.
During 2009, NSTAR Electric Company completed planned upgrades
to the SEMA transmission system. These upgrades are expected to
reduce the need for the Canal generating facility to operate and
caused a reduction in energy gross margin compared to historical
levels. The final phase of these transmission upgrades was
completed in the third quarter of 2009. With the completion of
the transmission upgrades, GenOn Americas Generation expects
that the future revenues of the Canal generating facility will
be principally capacity revenue from ISO-NE forward capacity
market. GenOn Americas Generations current projections
indicate that the undiscounted cash flows exceed the carrying
value of the facility at December 31, 2009. As a result,
GenOn Americas Generation did not record an impairment charge
because of the transmission upgrades. GenOn Americas Generation
continues to monitor developments related to its Canal
generating facility, including the NPDES and SWD Permit. See
Item 1. BusinessEnvironmental Regulation
for further information related to the NPDES and SWD Permit for
the Canal generating facility. The carrying value of the Canal
generating facility represented approximately 6% of GenOn
Americas Generations total property, plant and equipment,
net at December 31, 2010.
GenOn Mid-Atlantic Generating FacilitiesWe have
goodwill recorded at the GenOn Mid-Atlantic registrant on its
standalone balance sheet, which is eliminated upon consolidation
at GenOn North America. In accordance with accounting guidance
for goodwill and other intangible assets, we are required to
test the goodwill balance at GenOn Mid-Atlantic at least
annually. We performed the goodwill assessment at
October 31, 2009, which, by policy, is our annual testing
date. In conducting step one of the goodwill impairment analysis
for GenOn Mid-Atlantic, we noted that the carrying value of its
net assets exceeded the calculated fair value of GenOn
Mid-Atlantic, indicating that step two of the goodwill
impairment analysis was required. Based on the results of the
step one goodwill impairment analysis, we tested GenOn
Mid-Atlantics long-lived assets for impairment under the
accounting guidance related to impairment of long-lived assets
before completion of the step two test for goodwill. During
2009, the continued decline in average natural gas prices caused
power prices to decline in the Eastern PJM region. Additionally,
weak economic conditions and various demand-response programs
have resulted in a decrease in the forecasted gross margin of
the GenOn Mid-Atlantic generating facilities.
Upon completion of our assessment, which was based on the
accounting guidance related to the impairment of long-lived
assets, we determined that the Potomac River generating facility
was impaired, as the carrying value exceeded the undiscounted
cash flows. GenOn Americas Generation recorded an impairment
loss of $207 million on its consolidated statement of
operations to reduce the carrying value of the Potomac River
generating facility to its estimated fair value. In performing
our impairment assessment, we noted that the undiscounted cash
flows for other GenOn Mid-Atlantic generating facilities also
decreased significantly from the prior year. We determined that
no other GenOn Mid-Atlantic long-lived assets were impaired at
October 31, 2009.
89
2008
GenOn Mid-Atlantic Generating FacilitiesWe
performed the goodwill assessment for GenOn Mid-Atlantic at
October 31, 2008, which, by policy, is our annual testing
date. In conducting step one of the goodwill impairment analysis
for GenOn Mid-Atlantic, we noted that the carrying value of its
net assets exceeded the calculated fair value of GenOn
Mid-Atlantic, indicating that step two of the goodwill
impairment analysis was required. Based on the results of the
step one goodwill impairment analysis, we tested GenOn
Mid-Atlantics long-lived assets for impairment under the
accounting guidance related to impairment of long-lived assets
before completion of the step two test for goodwill. Upon
completion of our assessment, which was based on the accounting
guidance related to the impairment of long-lived assets, we
determined that no further analysis of the long-lived assets was
needed at December 31, 2008.
Effect if Different Assumptions Used. The
estimates and assumptions used to determine whether an
impairment exists are subject to a high degree of uncertainty.
The estimated fair value of an asset would change if different
estimates and assumptions were used in our applied valuation
techniques, including estimated undiscounted cash flows,
discount rates and remaining useful lives for assets held and
used. If actual results are not consistent with the assumptions
used in estimating future cash flows and asset fair values, we
may be exposed to additional losses that could be material to
our results of operations.
See note 3 (d) to our consolidated financial
statements for additional information on impairments.
Loss
Contingencies
Nature of Estimates Required. We record loss
contingencies when it is probable that a liability has been
incurred and the amount can be reasonably estimated. We consider
loss contingency estimates to be critical accounting estimates
because they entail significant judgment regarding probabilities
and ranges of exposure, and the ultimate outcome of the
proceedings is unknown and could have a material adverse effect
on our results of operations, financial condition and cash
flows. We currently have loss contingencies related to
litigation, environmental matters, tax matters and others.
Key Assumptions and Approach Used. The
determination of a loss contingency requires significant
judgment as to the expected outcome of each contingency in
future periods. In making the determination as to potential
losses and probability of loss, we consider all available
positive and negative evidence including the expected outcome of
potential litigation. We record our best estimate of a loss, or
the low end of our range if no estimate is better than another
estimate within a range of estimates, when the loss is
considered probable. As additional information becomes
available, we reassess the potential liability related to the
contingency and revise our estimates. In our evaluation of legal
matters, management holds discussions with applicable legal
counsel and relies on analysis of case law and legal precedents.
Effect if Different Assumptions
Used. Revisions in our estimates of potential
liabilities could materially affect our results of operations
and the ultimate resolution may be materially different from the
estimates that we make.
See notes 7, 9 and 10 to our consolidated financial
statements for additional information on our loss contingencies.
Litigation
We are currently involved in legal proceedings. We estimate the
range of liability through discussions with applicable legal
counsel and analysis of case law and legal precedents. We record
our best estimate of a loss, or the low end of our range if no
estimate is better than another estimate within a range of
estimates, when the loss is considered probable and can be
reasonably estimated. As additional information becomes
available, we reassess the potential liability related to our
pending litigation and revise our estimates. Revisions in our
estimates of the potential liability could materially affect our
results of operations and the ultimate resolution may be
materially different from the estimates that we make.
90
See note 9 to our consolidated financial statements for
further information related to our legal proceedings.
Recently
Adopted Accounting Guidance
See note 1 to our consolidated financial statements for
further information related to our recently adopted accounting
guidance.
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosures About Market Risk.
|
Fair
Value Measurements
We are exposed to market risk, primarily associated with
commodity prices. We also consider risks associated with
interest rates and credit when valuing our derivative financial
instruments.
GenOn
Americas Generation
The estimated net fair value of our derivative contract assets
and liabilities was a net asset of $679 million and
$702 million at December 31, 2010 and 2009,
respectively. The following tables provide a summary of the
factors affecting the change in fair value of the derivative
contract asset and liability accounts for 2009 and 2010,
respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts
|
|
|
|
Asset
|
|
|
Trading
|
|
|
|
|
|
|
Management
|
|
|
Activities
|
|
|
Total
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Fair value of portfolio of assets and liabilities at
January 1, 2009
|
|
$
|
549
|
|
|
$
|
106
|
|
|
$
|
655
|
|
Gains (losses) recognized in the period, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
New contracts and other changes in fair
value(1)
|
|
|
20
|
|
|
|
(150
|
)
|
|
|
(130
|
)
|
Roll off of previous
values(2)
|
|
|
(539
|
)
|
|
|
(100
|
)
|
|
|
(639
|
)
|
Purchases, issuances and
settlements(3)
|
|
|
671
|
|
|
|
145
|
|
|
|
816
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of portfolio of assets and liabilities at
December 31, 2009
|
|
|
701
|
|
|
|
1
|
|
|
|
702
|
|
Gains (losses) recognized in the period, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
New contracts and other changes in fair
value(1)
|
|
|
171
|
|
|
|
66
|
|
|
|
237
|
|
Roll off of previous
values(2)
|
|
|
(338
|
)
|
|
|
(49
|
)
|
|
|
(387
|
)
|
Purchases, issuances and
settlements(3)
|
|
|
150
|
|
|
|
(23
|
)
|
|
|
127
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of portfolio of assets and liabilities at
December 31, 2010
|
|
$
|
684
|
|
|
$
|
(5
|
)
|
|
$
|
679
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The fair value, as of the end of each quarterly reporting
period, of contracts entered into during each quarterly
reporting period and the gains or losses attributable to
contracts that existed as of the beginning of each quarterly
reporting period and were still held at the end of each
quarterly reporting period. |
|
(2) |
|
The fair value, as of the beginning of each quarterly reporting
period, of contracts that settled during each quarterly
reporting period. |
|
(3) |
|
Denotes cash settlements during each quarterly reporting period
of contracts that existed at the beginning of each quarterly
reporting period. |
91
GenOn
Mid-Atlantic
The estimated net fair value of our derivative contract assets
and liabilities was a net asset of $677 million and
$670 million at December 31, 2010 and 2009,
respectively. The following tables provide a summary of the
factors affecting the change in fair value of the derivative
contract asset and liability accounts for 2009 and 2010,
respectively:
|
|
|
|
|
|
|
Asset
|
|
|
|
Management
|
|
|
|
(in millions)
|
|
|
Fair value of portfolio of assets and liabilities at
January 1, 2009
|
|
$
|
526
|
|
Gains (losses) recognized in the period, net:
|
|
|
|
|
New contracts and other changes in fair
value(1)
|
|
|
(15
|
)
|
Roll off of previous
values(2)
|
|
|
(489
|
)
|
Purchases, issuances and
settlements(3)
|
|
|
648
|
|
|
|
|
|
|
Fair value of portfolio of assets and liabilities at
December 31, 2009
|
|
|
670
|
|
Gains (losses) recognized in the period, net:
|
|
|
|
|
New contracts and other changes in fair
value(1)
|
|
|
154
|
|
Roll off of previous
values(2)
|
|
|
(319
|
)
|
Purchases, issuances and
settlements(3)
|
|
|
172
|
|
|
|
|
|
|
Fair value of portfolio of assets and liabilities at
December 31, 2010
|
|
$
|
677
|
|
|
|
|
|
|
|
|
|
(1) |
|
The fair value, as of the end of each quarterly reporting
period, of contracts entered into during each quarterly
reporting period and the gains or losses attributable to
contracts that existed as of the beginning of each quarterly
reporting period and were still held at the end of each
quarterly reporting period. |
|
(2) |
|
The fair value, as of the beginning of each quarterly reporting
period, of contracts that settled during each quarterly
reporting period. |
|
(3) |
|
Denotes cash settlements during each quarterly reporting period
of contracts that existed at the beginning of each quarterly
reporting period |
In May 2010, we concluded that we could no longer assert that
physical delivery is probable for many of our coal agreements.
The conclusion was based on expected generation levels, changes
observed in the coal markets and substantial progress in the
construction of a coal blending facility at the Morgantown
generating facility that will allow for greater flexibility of
our coal supply. Because we can no longer assert that physical
delivery of coal from these agreements is probable, we are
required to apply fair value accounting for these contracts in
the current period and prospectively. The fair value of these
derivative contracts is included in the tables above.
We did not elect the fair value option for any financial
instruments under the accounting guidance. However, we do
transact using derivative financial instruments which are
required to be recorded at fair value in our consolidated
balance sheets under the accounting guidance related to
derivative financial instruments.
92
GenOn
Americas Generation
At December 31, 2010, the estimated net fair value of our
derivative contract assets and liabilities are (asset
(liability)):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 and
|
|
|
Total fair
|
|
Sources of Fair Value
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
thereafter
|
|
|
value
|
|
|
|
(in millions)
|
|
|
Asset Management:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices actively quoted (Level 1)
|
|
$
|
(19
|
)
|
|
$
|
(6
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(25
|
)
|
Prices provided by other external sources (Level 2)
|
|
|
218
|
|
|
|
184
|
|
|
|
184
|
|
|
|
191
|
|
|
|
|
|
|
|
|
|
|
|
777
|
|
Prices based on models and other valuation methods (Level 3)
|
|
|
(36
|
)
|
|
|
(36
|
)
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(68
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total asset management
|
|
$
|
163
|
|
|
$
|
142
|
|
|
$
|
188
|
|
|
$
|
191
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
684
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trading Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices actively quoted (Level 1)
|
|
$
|
3
|
|
|
$
|
(6
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(3
|
)
|
Prices provided by other external sources (Level 2)
|
|
|
(8
|
)
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
Prices based on models and other valuation methods (Level 3)
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total trading activities
|
|
$
|
(3
|
)
|
|
$
|
(2
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GenOn
Mid-Atlantic
At December 31, 2010, the estimated net fair value of our
derivative contract assets and liabilities are (asset
(liability)):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 and
|
|
|
Total fair
|
|
Sources of Fair Value
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
thereafter
|
|
|
value
|
|
|
|
(in millions)
|
|
|
Asset Management:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices actively quoted (Level 1)
|
|
$
|
(9
|
)
|
|
$
|
(2
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(11
|
)
|
Prices provided by other external sources (Level 2
|
|
|
203
|
|
|
|
179
|
|
|
|
184
|
|
|
|
191
|
|
|
|
|
|
|
|
|
|
|
|
757
|
|
Prices based on models and other valuation methods (Level 3)
|
|
|
(36
|
)
|
|
|
(37
|
)
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(69
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total asset management
|
|
$
|
158
|
|
|
$
|
140
|
|
|
$
|
188
|
|
|
$
|
191
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
677
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair values shown in the table above are subject to
significant changes as a result of fluctuating commodity forward
market prices, volatility and credit risk. For further
discussion of how we determine these fair values, see
note 2 to our consolidated financial statements and
Managements Discussion and Analysis of Financial
Condition and Results of Operations under GenOn Americas
Generation, and GenOn Mid-Atlantic, respectively,Recently
Adopted Accounting Guidance and Critical Accounting
EstimatesCritical Accounting Estimates in
Item 7 of this
Form 10-K.
Commodity
Price Risk
In connection with our 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 our fuel inventories. A portion of our fuel
requirements is purchased in the spot market and a portion of
the electricity we produce is sold in the spot market. In
addition,
93
the open positions in GenOn Americas Generations
proprietary trading and fuel oil management activities expose it
to risks associated with changes in energy commodity prices.
As a result, our financial performance varies depending on
changes in the prices of energy and energy-related commodities.
See Item 7, Critical Accounting Estimates for a
discussion of the accounting treatment for asset management,
proprietary trading and fuel oil management activities.
The financial performance of our business of generating
electricity is influenced by the difference between the variable
cost of converting a fuel, such as natural gas, coal or oil,
into electricity, and the variable revenue we receive from the
sale of that electricity. The difference between the cost of a
specific fuel used to generate one MWh of electricity and the
market value of the electricity generated is commonly referred
to as the conversion spread. Absent the effects of
our derivative contract activities, the operating margins that
we realize are equal to the difference between the aggregate
conversion spread and the cost of operating the facilities that
produce the electricity sold.
Conversion spreads are dependent on a variety of factors that
influence the cost of fuel and the sales price of the
electricity generated over the longer term, including conversion
spreads of other generating facilities in the regions in which
we operate, facility outages, weather and general economic
conditions. As a result of these influences, the cost of fuel
and electricity prices do not always change in the same
magnitude or direction, which results in conversion spreads for
a particular generating facility widening or narrowing (or
becoming negative) over any given period.
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 our exposure to commodity price risks. These contracts
have varying terms and durations which range from a few days to
years, depending on the instrument. GenOn Americas
Generations proprietary trading activities also utilize
similar derivative contracts in markets where we have a physical
presence to attempt to generate incremental gross margin. GenOn
Americas Generations fuel oil management activities use
derivative financial instruments to hedge economically the fair
value of physical fuel oil inventories, optimize the
approximately three million barrels of storage capacity that it
owns or leases, as well as attempt to profit from market
opportunities related to timing
and/or
differences in the pricing of various products.
Derivative energy contracts that are required to be reflected at
fair value are presented as derivative contract assets and
liabilities in the consolidated balance sheets. The net changes
in their fair market values are recognized in income in the
period of change. The determination of fair value considers
various factors, including closing exchange or OTC market price
quotations, time value, credit quality, liquidity and volatility
factors underlying options. See Item 7, Critical
Accounting Estimates for the accounting treatment of asset
management, proprietary trading and fuel oil management
activities.
Counterparty
Credit Risk
The valuation of our derivative contract assets is affected by
the default risk of the counterparties with which we transact.
We recognized a reserve, which is reflected as a reduction of
our derivative contract assets, related to counterparty credit
risk of $19 million and $13 million at
December 31, 2010 and 2009, respectively.
In accordance with the fair value measurements accounting
guidance, we calculate the credit reserve through consideration
of observable market inputs, when available. We calculate our
credit reserve using published spreads, where available, or
proxies based upon published spreads, on credit default swaps
for our counterparties applied to our current exposure and
potential loss exposure from the financial commitments in our
risk management portfolio. We do not, however, transact in
credit default swaps or any other credit derivative. Potential
loss exposure is calculated as our current exposure plus a
calculated VaR over the remaining life of the contracts.
Our non-collateralized power hedges entered into by GenOn
Mid-Atlantic with financial institutions, which represent 59% of
the net notional power position for GenOn Americas Generation
and 60% of the net
94
notional power position for GenOn Mid-Atlantic at
December 31, 2010, are senior unsecured obligations of
GenOn Mid-Atlantic and the counterparties, and do not require
either party to post cash collateral for initial margin or for
securing exposure as a result of changes in power or natural gas
prices. Our coal contracts included in derivative contract
assets and liabilities in the consolidated balance sheets also
do not require either party to post cash collateral for initial
margin or for securing exposure as a result of changes in coal
prices. An increase of 10% in the spread of credit default swaps
of our trading partners would result in an increase of
$2 million in our credit reserve at December 31, 2010.
Once we have delivered a physical commodity or agreed to
financial settlement terms, we are subject to collection risk.
Collection risk is similar to credit risk and collection risk is
accounted for when we establish our provision for uncollectible
accounts. We manage this risk using the same techniques and
processes used in credit risk discussed above.
We also monitor counterparty credit concentration risk on both
an individual basis and a group counterparty basis. See
note 2(c) to our consolidated financial statements for
further discussion of our counterparty credit concentration risk.
GenOn
Americas Generation and GenOn Mid-Atlantic Credit
Risk
In valuing our derivative contract liabilities, we apply a
valuation adjustment for our non-performance, which is based on
the probability of our default. Our methodology incorporates
published spreads on our credit default swaps, where available,
or proxies based upon published spreads. An increase of 10% in
the spread of our credit default swap rate would have an
immaterial effect on our consolidated statement of operations
for 2010.
Broker
Quotes
The fair value of our derivative contract assets and liabilities
is based largely on observable quoted prices from exchanges and
unadjusted indicative quoted prices from independent brokers in
active markets who 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 our derivative contract assets and liabilities, we
use third-party market pricing where available. Note 2 to
our consolidated financial statements explains the fair value
hierarchy. Our transactions in Level 1 of the fair value
hierarchy primarily consist of natural gas and crude oil futures
traded on the NYMEX and swaps cleared against NYMEX prices. For
these transactions, we use the unadjusted published settled
prices on the valuation date. Our transactions in Level 2
of the fair value hierarchy primarily include
non-exchange-traded derivatives such as OTC forwards, swaps and
options, and certain energy derivative instruments that are
cleared and settled through exchanges. 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 our assets
and ask prices for liabilities. The quotes that 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 on the valuation date
for each delivery location that extend for the tenor of our
underlying contracts. 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 on a monthly basis.
95
The validation procedures include reviewing the quotes for
accuracy and comparing them to our internal price curves. In
certain instances, we may discard a broker quote if it is a
clear outlier and multiple other quotes are obtained. At
December 31, 2010, 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 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. Proprietary models
may also be used to determine the fair value of certain of our
derivative contract assets and liabilities that may be
structured or otherwise tailored. Our techniques for fair value
estimation include assumptions for market prices, correlation
and volatility. The degree of estimation increases for longer
duration contracts, contracts with multiple pricing features,
option contracts and off-hub delivery points. At
December 31, 2010, GenOn Americas Generations assets
and liabilities classified as Level 3 in the fair value
hierarchy represented approximately 2% of its total assets and
8% of its total liabilities measured at fair value. At
December 31, 2010, GenOn Mid-Atlantics assets and
liabilities classified as Level 3 in the fair value
hierarchy represented approximately 3% of its total assets and
29% of its total liabilities measured at fair value. See
note 2 to our consolidated financial statements for further
explanation of the fair value hierarchy.
Value
at Risk
Our risk management policy limits our trading to certain
products and contains limits and restrictions related to our
asset management, proprietary trading and fuel oil management
activities.
We manage the price risk associated with asset management
activities through a variety of methods. Our risk management
policy requires that asset management activities are restricted
to only those activities that are risk-reducing. We ensure
compliance with this restriction at the transactional level by
testing each individual transaction executed relative to the
overall asset position.
We also use VaR to measure the market price risk of our energy
asset portfolio as a result of potential changes in market
prices. VaR is a statistical model that provides an estimate of
potential loss. We calculate VaR based on the parametric
variance/covariance approach, utilizing a 95% confidence
interval and a
one-day
holding period on a rolling
24-month
forward looking period. Additionally, we estimate correlation
based on historical commodity price changes. Volatilities are
based on a combination of historical price changes and implied
market rates.
VaR is calculated quarterly on an asset management portfolio
comprised of
mark-to-market
and non
mark-to-market
energy assets and liabilities, including generating facilities
and bilateral physical and financial transactions. Asset
management VaR levels are substantially reduced as a result of
our decision to actively hedge economically in the forward
markets the commodity price risk related to the expected
generation and fuel usage of our generating facilities. See
Item 1, BusinessAsset Management for
discussion of our hedging strategies.
GenOn
Americas Generation
The following table summarizes year-end, average, high and low
VaR for our asset management portfolio:
|
|
|
|
|
|
|
|
|
Asset Management VaR
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
Year-end
|
|
$
|
6
|
|
|
$
|
11
|
|
Average
|
|
$
|
6
|
|
|
$
|
12
|
|
High
|
|
$
|
6
|
|
|
$
|
13
|
|
Low
|
|
$
|
5
|
|
|
$
|
11
|
|
96
GenOn Americas Generation calculates VaR daily on portfolios
consisting of
mark-to-market
and non
mark-to-market
bilateral physical and financial transactions related to our
proprietary trading activities and fuel oil management
operations.
The following table summarizes year-end, average, high and low
VaR for our proprietary trading and fuel oil management
activities:
|
|
|
|
|
|
|
|
|
Proprietary Trading and Fuel Oil Management VaR
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
Year-end
|
|
$
|
2
|
|
|
$
|
2
|
|
Average
|
|
$
|
2
|
|
|
$
|
2
|
|
High
|
|
$
|
3
|
|
|
$
|
4
|
|
Low
|
|
$
|
1
|
|
|
$
|
1
|
|
GenOn
Mid-Atlantic
The following table summarizes year-end, average, high and low
VaR for our asset management portfolio:
|
|
|
|
|
|
|
|
|
Asset Management VaR
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
Year-end
|
|
$
|
6
|
|
|
$
|
10
|
|
Average
|
|
$
|
6
|
|
|
$
|
11
|
|
High
|
|
$
|
6
|
|
|
$
|
12
|
|
Low
|
|
$
|
5
|
|
|
$
|
10
|
|
Because of inherent limitations of statistical measures such as
VaR and the seasonality of changes in market prices, the VaR
calculation may not reflect the full extent of our commodity
price risk exposure on our cash flows and liquidity.
Additionally, actual changes in the fair value of
mark-to-market
energy assets and liabilities could differ from the calculated
VaR, and such changes could have a material effect on our
financial results.
Interest
Rate Risk
Fair
Value Measurement
We are also subject to interest rate risk when discounting to
account for time value in determining the fair value of our
derivative contract assets and liabilities. The nominal value of
our derivative contract assets and liabilities is discounted
using a LIBOR forward interest rate curve based on the tenor of
our transactions. It is estimated that a one percentage point
change in market interest rates would result in a change of
$20 million to GenOn Americas Generations derivative
contract assets and a change of $7 million to GenOn
Americas Generations derivative contract liabilities at
December 31, 2010. It is estimated that a one percent in
market interest rates would result in a change of
$19 million to GenOn Mid-Atlantics derivative
contract assets and a change of $6 million to GenOn
Mid-Atlantics derivative contract liabilities at
December 31, 2010.
Coal
Agreement Risk
Our coal supply comes primarily from the Northern Appalachian
and Central Appalachian coal regions. GenOn Americas Generation
enters into contracts of varying tenors on behalf of GenOn
Mid-Atlantic to secure appropriate quantities of fuel that meet
the varying specifications of GenOn Mid-Atlantics
generating facilities. For our coal-fired generating facilities,
we purchase most of our coal from a small number of suppliers
under contracts with terms of varying lengths, some of which
extend to 2013. We had exposure to two counterparties at
December 31, 2010, and exposure to three counterparties at
December 31, 2009, that each represented an exposure of
more than 10% of our total coal commitments, by volume, for the
respective succeeding year, and in aggregate represented
approximately 60% and 61% of our total coal commitments at
97
December 31, 2010 and 2009, respectively. At
December 31, 2010, one counterparty represented an exposure
of 39% of these total coal commitments, by volume.
In addition, we have non-performance risk associated with our
coal agreements. There is risk that our coal suppliers may not
provide the contractual quantities on the dates specified within
the agreements or the deliveries may be carried over to future
periods. If our coal suppliers do not perform in accordance with
the agreements, we may have to procure coal in the market to
meet our needs, or power in the market to meet our obligations.
In addition, generally our coal suppliers do not have investment
grade credit ratings nor do they post collateral with us and,
accordingly, we may have limited ability to collect damages in
the event of default by such suppliers. We seek to mitigate this
risk through diversification of coal suppliers, to the extent
possible, and through guarantees. Despite this, there can be no
assurance that these efforts will be successful in mitigating
credit risk from coal suppliers. Non-performance or default risk
by our coal suppliers could have a material adverse effect on
our future results of operations, financial condition and cash
flows. See note 2(c) to our consolidated financial
statements for further explanation of these agreements and our
credit concentration tables.
Certain of our coal contracts are not required to be recorded at
fair value under the accounting guidance for derivative
financial instruments. As such, these contracts are not included
in derivative contract assets and liabilities in the
consolidated balance sheets. These contracts contain pricing
terms that are favorable compared to forward market prices at
December 31, 2010, and are projected to provide a
$62 million benefit to our realized value of hedges through
2013 as the coal is utilized in the production of electricity.
|
|
Item 8.
|
Financial
Statements and Supplementary Data.
|
The financial statements and schedules are listed in
Part IV, Item 15 of this
Form 10-K.
|
|
Item 9.
|
Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosure.
|
None.
|
|
Item 9A.
|
Controls
and Procedures.
|
Effectiveness
of Disclosure Controls and Procedures
As required by Exchange Act
Rule 13a-15(b),
our management, including our Principal Executive Officer and
our Principal Financial Officer, conducted an assessment of the
effectiveness of the design and operation of our disclosure
controls and procedures (as defined by
Rules 13a-15(e)
and
15d-15(e)
under the Exchange Act), as of December 31, 2010. Based
upon this assessment, our management concluded that, as of
December 31, 2010, the design and operation of these
disclosure controls and procedures were effective.
Managements
Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining
adequate internal control over financial reporting (as defined
by
Rules 13a-15(f)
under the Exchange Act). The Companies internal control
framework and processes have been designed to provide reasonable
assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in
accordance with United States generally accepted accounting
principles. Internal control over financial reporting includes
those processes and procedures that:
|
|
|
|
|
pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and
dispositions of the assets of the Companies;
|
|
|
|
provide reasonable assurance that transactions are recorded
properly to allow for the preparation of financial statements,
in accordance with generally accepted accounting principles, and
that receipts and expenditures of the Companies are being made
only in accordance with authorizations of management and
directors of the Companies (or persons performing the equivalent
functions);
|
98
|
|
|
|
|
provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of
the Companies assets that could have a material effect on
the consolidated financial statements; and
|
|
|
|
provide reasonable assurance as to the detection of fraud.
|
Under the supervision and with the participation of our
management, including our Principal Executive Officer and our
Principal Financial Officer, we carried out an assessment of the
effectiveness of our internal control over financial reporting
as of December 31, 2010. In conducting our assessment,
management utilized the criteria set forth by the Committee of
Sponsoring Organizations of the Treadway Commission in
Internal ControlIntegrated Framework. Based on this
assessment, management concluded that our internal control over
financial reporting was effective as of December 31, 2010.
Changes
in Internal Control over Financial Reporting
There have been no changes in the Companies internal
control over financial reporting that have occurred during the
quarter ended December 31, 2010, that have materially
affected or are reasonably likely to materially affect the
Companies internal control over financial reporting.
|
|
Item 9B.
|
Other
Information.
|
None.
99
PART III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance.
|
|
|
Item 11.
|
Executive
Compensation.
|
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.
|
|
|
Item 13.
|
Certain
Relationships and Related Transactions and Director
Independence.
|
Each of Items 10 through 13 have been omitted from this
report pursuant to the reduced disclosure format permitted by
General Instruction I to
Form 10-K.
|
|
Item 14.
|
Principal
Accountant Fees and Services.
|
KPMG LLP conducts an integrated audit of GenOn and its
subsidiaries. As such, GenOn Americas Generation and GenOn
Mid-Atlantic do not separately arrange for audit services. A
significant portion of the fees for professional audit services
and other services rendered by KPMG LLP were allocated to the
Companies through the Administrative Services Agreement with
GenOn Energy Services as described in note 6
Related Party Arrangements and Transactions. Prior to the
Merger, the Mirant Audit Committee pre-approved all audit
services and permissible non-audit services provided by the
independent auditor. As provided in the GenOn Audit Committee
Charter, the GenOn Audit Committee pre-approved all audit
services and permissible non-audit services provided by the
independent auditor from the time of the Merger and for the
remainder of the fiscal year 2010.
The following table shows the aggregate fees related to the
audit and other services provided by KPMG LLP (in thousands) for
fiscal years ended December 31, 2010 and 2009. Amounts in
the table for periods prior to the consummation of the Merger on
December 3, 2010 reflect amounts paid by Mirant to KPMG LLP.
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
Audit
Fees(1)
|
|
$
|
5,867
|
|
|
$
|
5,504
|
|
Audit-Related
Fees(2)
|
|
|
754
|
|
|
|
|
|
Tax
Fees(3)
|
|
|
|
|
|
|
|
|
All Other
Fees(4)
|
|
|
|
|
|
|
251
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
6,621
|
|
|
$
|
5,755
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes fees and expenses related to the audit of GenOns
consolidated annual financial statements and the effectiveness
of GenOns internal controls over financial reporting. This
category also includes the review of financial statements
included in Mirants Quarterly Reports on
Form 10-Q,
the audits of various subsidiary financial statements required
by statute or regulation, and services that are normally
provided by the independent auditors in connection with
regulatory filings or engagements, consultations provided on
audit and accounting matters that arose during, or as a result
of, the audits or the reviews of interim financial statements,
and the preparation of any written communications on internal
control matters. |
|
(2) |
|
Consists of accounting consulting, assurance and related
services that are reasonably related to the performance of the
audit or review of our financial statements, which during 2010
related to the Merger, and are not reported above under
Audit Fees. |
|
(3) |
|
Consists of professional services rendered for general tax
consulting services. |
|
(4) |
|
Consists of fees for services provided by KPMG LLP, other than
fees for the services listed in the other categories. The fees
disclosed include services related to an International Financial
Reporting Standards (IFRS) readiness assessment project. |
100
PART IV
|
|
Item 15.
|
Exhibits
and Financial Statement Schedules.
|
(a) 1. Financial Statements
|
|
|
|
|
Report of Independent Registered Public Accounting Firm
|
|
|
F-1
|
|
GenOn Americas Generation, LLC
|
|
|
|
|
Consolidated Statements of Operations
|
|
|
F-3
|
|
Consolidated Balance Sheets
|
|
|
F-4
|
|
Consolidated Statements of Members Equity
|
|
|
F-5
|
|
Consolidated Statements of Cash Flows
|
|
|
F-6
|
|
GenOn Mid-Atlantic, LLC
|
|
|
|
|
Consolidated Statements of Operations
|
|
|
F-7
|
|
Consolidated Balance Sheets
|
|
|
F-8
|
|
Consolidated Statements of Members Equity
|
|
|
F-9
|
|
Consolidated Statements of Cash Flows
|
|
|
F-10
|
|
Combined Notes to the Consolidated Financial Statements
|
|
|
F-11
|
|
2. Financial Statement Schedules
|
|
|
|
|
Report of Independent Registered Public Accounting Firm
|
|
|
F-78
|
|
GenOn Americas Generation, LLC
|
|
|
|
|
Schedule ICondensed Statements of Operations (Parent)
|
|
|
F-80
|
|
Schedule ICondensed Balance Sheets (Parent)
|
|
|
F-81
|
|
Schedule ICondensed Statements of Cash Flows (Parent)
|
|
|
F-82
|
|
Schedule INotes to Registrants Condensed Financial
Statements (Parent)
|
|
|
F-83
|
|
Schedule IIValuation and Qualifying Accounts
|
|
|
F-85
|
|
3. Exhibits
|
|
|
|
|
Exhibits
|
|
|
|
|
GenOn Americas Generation, LLC
|
|
|
F-86
|
|
GenOn Mid-Atlantic, LLC
|
|
|
F-88
|
|
101
Report of
Independent Registered Public Accounting Firm
The Member
GenOn Americas Generation, LLC:
We have audited the accompanying consolidated balance sheets of
GenOn Americas Generation, LLC (a wholly-owned subsidiary of
GenOn Energy, Inc.) and subsidiaries (the Company) as of
December 31, 2010 and 2009, and the related consolidated
statements of operations, members equity and cash flows
for each of the years in the three-year period ended
December 31, 2010. These consolidated financial statements
are the responsibility of the Companys management. Our
responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes consideration
of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Companys internal control over
financial reporting. Accordingly, we express no such opinion. An
audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of GenOn Americas Generation, LLC and subsidiaries as
of December 31, 2010 and 2009, and the results of their
operations and their cash flows for each of the years in the
three-year period ended December 31, 2010, in conformity
with U.S. generally accepted accounting principles.
Houston, Texas
March 1, 2011
F-1
Report of
Independent Registered Public Accounting Firm
The Member
GenOn Mid-Atlantic, LLC:
We have audited the accompanying consolidated balance sheets of
GenOn Mid-Atlantic, LLC (a wholly-owned subsidiary of GenOn
Energy, Inc.) and subsidiaries (the Company) as of
December 31, 2010 and 2009, and the related consolidated
statements of operations, members equity and cash flows
for each of the years in the three-year period ended
December 31, 2010. These consolidated financial statements
are the responsibility of the Companys management. Our
responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes consideration
of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Companys internal control over
financial reporting. Accordingly, we express no such opinion. An
audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of GenOn Mid-Atlantic, LLC and subsidiaries as of
December 31, 2010 and 2009, and the results of their
operations and their cash flows for each of the years in the
three-year period ended December 31, 2010, in conformity
with U.S. generally accepted accounting principles.
Houston, Texas
March 1, 2011
F-2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
Operating revenuesnonaffiliate (including unrealized gains
(losses) of $69 million, $(2) million and
$840 million, respectively)
|
|
$
|
2,102
|
|
|
$
|
2,309
|
|
|
$
|
3,188
|
|
Operating revenuesaffiliate (including unrealized gains of
$3 million, $0 million and $0 million,
respectively)
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
2,105
|
|
|
|
2,309
|
|
|
|
3,188
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of fuel, electricity and other productsnonaffiliate
(including unrealized (gains) losses of $89 million,
$(49) million and $54 million, respectively)
|
|
|
846
|
|
|
|
701
|
|
|
|
1,053
|
|
Cost of fuel, electricity and other productsaffiliate
(including unrealized (gains) losses of $0, $0 and $0,
respectively)
|
|
|
8
|
|
|
|
9
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of fuel, electricity and other products
|
|
|
854
|
|
|
|
710
|
|
|
|
1,059
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin (excluding depreciation and amortization)
|
|
|
1,251
|
|
|
|
1,599
|
|
|
|
2,129
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenancenonaffiliate
|
|
|
390
|
|
|
|
355
|
|
|
|
372
|
|
Operations and maintenanceaffiliate
|
|
|
293
|
|
|
|
290
|
|
|
|
285
|
|
Depreciation and amortization
|
|
|
199
|
|
|
|
142
|
|
|
|
136
|
|
Impairment losses
|
|
|
565
|
|
|
|
221
|
|
|
|
|
|
Gain on sales of assets, net
|
|
|
(9
|
)
|
|
|
(22
|
)
|
|
|
(38
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
1,438
|
|
|
|
986
|
|
|
|
755
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
|
|
(187
|
)
|
|
|
613
|
|
|
|
1,374
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Expense (Income), net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
200
|
|
|
|
137
|
|
|
|
189
|
|
Interest income
|
|
|
|
|
|
|
(1
|
)
|
|
|
(16
|
)
|
Other, net
|
|
|
9
|
|
|
|
1
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense, net
|
|
|
209
|
|
|
|
137
|
|
|
|
176
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
|
$
|
(396
|
)
|
|
$
|
476
|
|
|
$
|
1,198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying combined notes are an integral part of these
consolidated financial statements
F-3
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
ASSETS
|
Current Assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
514
|
|
|
$
|
404
|
|
Funds on deposit
|
|
|
949
|
|
|
|
180
|
|
Receivablesnonaffiliate
|
|
|
363
|
|
|
|
401
|
|
Receivablesaffiliate
|
|
|
4
|
|
|
|
|
|
Derivative contract assetsnonaffiliate
|
|
|
1,288
|
|
|
|
1,416
|
|
Derivative contract assets affiliate
|
|
|
5
|
|
|
|
|
|
Inventories
|
|
|
295
|
|
|
|
241
|
|
Prepaid expenses
|
|
|
124
|
|
|
|
134
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
3,542
|
|
|
|
2,776
|
|
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment, net
|
|
|
3,077
|
|
|
|
3,606
|
|
|
|
|
|
|
|
|
|
|
Noncurrent Assets:
|
|
|
|
|
|
|
|
|
Intangible assets, net
|
|
|
101
|
|
|
|
171
|
|
Derivative contract assetsnonaffiliate
|
|
|
689
|
|
|
|
599
|
|
Derivative contract assetsaffiliate
|
|
|
3
|
|
|
|
|
|
Prepaid rent
|
|
|
348
|
|
|
|
304
|
|
Debt issuance costs, net
|
|
|
12
|
|
|
|
29
|
|
Other
|
|
|
41
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent assets
|
|
|
1,194
|
|
|
|
1,135
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
7,813
|
|
|
$
|
7,517
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS EQUITY
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
Current portion of long-term debt
|
|
$
|
1,389
|
|
|
$
|
74
|
|
Accounts payable and accrued liabilities
|
|
|
527
|
|
|
|
646
|
|
Payableaffiliate
|
|
|
42
|
|
|
|
42
|
|
Derivative contract liabilitiesnonaffiliate
|
|
|
1,130
|
|
|
|
1,150
|
|
Derivative contract liabilitiesaffiliate
|
|
|
3
|
|
|
|
|
|
Other
|
|
|
8
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
3,099
|
|
|
|
1,920
|
|
|
|
|
|
|
|
|
|
|
Noncurrent Liabilities:
|
|
|
|
|
|
|
|
|
Long-term debt, net of current portion
|
|
|
866
|
|
|
|
2,556
|
|
Derivative contract liabilities
|
|
|
173
|
|
|
|
163
|
|
Other
|
|
|
90
|
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent liabilities
|
|
|
1,129
|
|
|
|
2,768
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
Members Equity:
|
|
|
|
|
|
|
|
|
Members interest
|
|
|
3,585
|
|
|
|
3,109
|
|
Preferred stock in affiliate
|
|
|
|
|
|
|
(280
|
)
|
|
|
|
|
|
|
|
|
|
Total members equity
|
|
|
3,585
|
|
|
|
2,829
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Members Equity
|
|
$
|
7,813
|
|
|
$
|
7,517
|
|
|
|
|
|
|
|
|
|
|
The accompanying combined notes are an integral part of these
consolidated financial statements
F-4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
|
|
|
Total
|
|
|
|
Members
|
|
|
Stock in
|
|
|
Members
|
|
|
|
Interest
|
|
|
Affiliate
|
|
|
Equity
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Balance, December 31, 2007
|
|
$
|
1,524
|
|
|
$
|
(355
|
)
|
|
$
|
1,169
|
|
Net income
|
|
|
1,198
|
|
|
|
|
|
|
|
1,198
|
|
Amortization of discount on preferred stock in affiliate
|
|
|
21
|
|
|
|
(21
|
)
|
|
|
|
|
Redemption of preferred stock in affiliate
|
|
|
|
|
|
|
31
|
|
|
|
31
|
|
Distributions to member
|
|
|
(297
|
)
|
|
|
|
|
|
|
(297
|
)
|
Capital contributions
|
|
|
282
|
|
|
|
|
|
|
|
282
|
|
Adoption of accounting guidance related to fair value measurement
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
2,729
|
|
|
|
(345
|
)
|
|
|
2,384
|
|
Net income
|
|
|
476
|
|
|
|
|
|
|
|
476
|
|
Amortization of discount on preferred stock in affiliate
|
|
|
19
|
|
|
|
(19
|
)
|
|
|
|
|
Redemption of preferred stock in affiliate
|
|
|
|
|
|
|
84
|
|
|
|
84
|
|
Distribution to member
|
|
|
(115
|
)
|
|
|
|
|
|
|
(115
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
3,109
|
|
|
|
(280
|
)
|
|
|
2,829
|
|
Net loss
|
|
|
(396
|
)
|
|
|
|
|
|
|
(396
|
)
|
Amortization of discount on preferred stock in affiliate
|
|
|
15
|
|
|
|
(15
|
)
|
|
|
|
|
Redemption of preferred stock in affiliate
|
|
|
|
|
|
|
295
|
|
|
|
295
|
|
Distribution to member
|
|
|
(222
|
)
|
|
|
|
|
|
|
(222
|
)
|
Capital contributions
|
|
|
1,079
|
|
|
|
|
|
|
|
1,079
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2010
|
|
$
|
3,585
|
|
|
$
|
|
|
|
$
|
3,585
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying combined notes are an integral part of these
consolidated financial statements
F-5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Cash Flows from Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(396
|
)
|
|
$
|
476
|
|
|
$
|
1,198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to reconcile net income (loss) and changes in other
operating assets and liabilities to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
207
|
|
|
|
152
|
|
|
|
146
|
|
Impairment losses
|
|
|
565
|
|
|
|
221
|
|
|
|
|
|
Gain on sales of assets, net
|
|
|
(9
|
)
|
|
|
(22
|
)
|
|
|
(38
|
)
|
Net changes in derivative contracts
|
|
|
17
|
|
|
|
(47
|
)
|
|
|
(786
|
)
|
Lower of cost or market inventory adjustments
|
|
|
22
|
|
|
|
32
|
|
|
|
65
|
|
Potomac River settlement obligation
|
|
|
32
|
|
|
|
|
|
|
|
|
|
Other, net
|
|
|
10
|
|
|
|
|
|
|
|
9
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivablesnonaffiliate
|
|
|
38
|
|
|
|
342
|
|
|
|
(218
|
)
|
Receivablesaffiliate
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
Funds on deposit
|
|
|
87
|
|
|
|
26
|
|
|
|
109
|
|
Prepaid rent
|
|
|
(44
|
)
|
|
|
(46
|
)
|
|
|
(24
|
)
|
Inventories
|
|
|
(76
|
)
|
|
|
(35
|
)
|
|
|
47
|
|
Other assets
|
|
|
5
|
|
|
|
(10
|
)
|
|
|
7
|
|
Accounts payable and accrued liabilities
|
|
|
(18
|
)
|
|
|
(326
|
)
|
|
|
249
|
|
Payableaffiliate
|
|
|
|
|
|
|
8
|
|
|
|
1
|
|
Taxes accruednonaffiliate
|
|
|
5
|
|
|
|
(7
|
)
|
|
|
2
|
|
Other liabilities
|
|
|
1
|
|
|
|
2
|
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total adjustments
|
|
|
840
|
|
|
|
290
|
|
|
|
(438
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities of continuing
operations
|
|
|
444
|
|
|
|
766
|
|
|
|
760
|
|
Net cash provided by operating activities of discontinued
operations
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
444
|
|
|
|
766
|
|
|
|
761
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(252
|
)
|
|
|
(666
|
)
|
|
|
(720
|
)
|
Proceeds from the sales of assets
|
|
|
8
|
|
|
|
25
|
|
|
|
40
|
|
Restricted deposit payments and other
|
|
|
(866
|
)
|
|
|
1
|
|
|
|
(34
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities of continuing operations
|
|
|
(1,110
|
)
|
|
|
(640
|
)
|
|
|
(714
|
)
|
Net cash provided by investing activities of discontinued
operations
|
|
|
|
|
|
|
|
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(1,110
|
)
|
|
|
(640
|
)
|
|
|
(696
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Redemption of preferred stock in affiliate
|
|
|
295
|
|
|
|
84
|
|
|
|
31
|
|
Repayments of long-term debt
|
|
|
(376
|
)
|
|
|
(45
|
)
|
|
|
(419
|
)
|
Repayment of note payableaffiliate, net
|
|
|
|
|
|
|
|
|
|
|
(6
|
)
|
Capital contributions
|
|
|
1,079
|
|
|
|
|
|
|
|
282
|
|
Distributions to member
|
|
|
(222
|
)
|
|
|
(115
|
)
|
|
|
(297
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
776
|
|
|
|
(76
|
)
|
|
|
(409
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents
|
|
|
110
|
|
|
|
50
|
|
|
|
(344
|
)
|
Cash and Cash Equivalents, beginning of year
|
|
|
404
|
|
|
|
354
|
|
|
|
698
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents, end of year
|
|
$
|
514
|
|
|
$
|
404
|
|
|
$
|
354
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Cash Flow Disclosures:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest, net of amounts capitalized
|
|
$
|
185
|
|
|
$
|
124
|
|
|
$
|
175
|
|
The accompanying combined notes are an integral part of these
consolidated financial statements
F-6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Operating revenuesnonaffiliate (including unrealized gains
of $123 million, $137 million and $525 million,
respectively)
|
|
$
|
347
|
|
|
$
|
401
|
|
|
$
|
492
|
|
Operating revenuesaffiliate (including unrealized gains
(losses) of $(43) million, $(1) million and
$160 million, respectively)
|
|
|
1,357
|
|
|
|
1,377
|
|
|
|
1,787
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
1,704
|
|
|
|
1,778
|
|
|
|
2,279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of fuel, electricity and other productsnonaffiliate
(including unrealized (gains) losses of $0, $0 and $0,
respectively)
|
|
|
18
|
|
|
|
17
|
|
|
|
20
|
|
Cost of fuel, electricity and other productsaffiliate
(including unrealized (gains) losses of $73 million,
$(8) million and $9 million, respectively)
|
|
|
680
|
|
|
|
510
|
|
|
|
545
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of fuel, electricity and other products
|
|
|
698
|
|
|
|
527
|
|
|
|
565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin (excluding depreciation and amortization)
|
|
|
1,006
|
|
|
|
1,251
|
|
|
|
1,714
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenancenonaffiliate
|
|
|
299
|
|
|
|
245
|
|
|
|
239
|
|
Operations and maintenanceaffiliate
|
|
|
194
|
|
|
|
189
|
|
|
|
173
|
|
Depreciation and amortization
|
|
|
141
|
|
|
|
98
|
|
|
|
92
|
|
Impairment losses
|
|
|
1,153
|
|
|
|
385
|
|
|
|
|
|
Gain on sales of assets, netaffiliate
|
|
|
(3
|
)
|
|
|
(14
|
)
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
1,784
|
|
|
|
903
|
|
|
|
496
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
|
|
(778
|
)
|
|
|
348
|
|
|
|
1,218
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Expense (Income), net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
3
|
|
|
|
3
|
|
|
|
3
|
|
Interest income
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
Other, net
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense, net
|
|
|
4
|
|
|
|
4
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before Income Taxes
|
|
|
(782
|
)
|
|
|
344
|
|
|
|
1,217
|
|
Benefit for income taxes
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
|
$
|
(781
|
)
|
|
$
|
344
|
|
|
$
|
1,217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying combined notes are an integral part of these
consolidated financial statements
F-7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
ASSETS
|
Current Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
202
|
|
|
$
|
125
|
|
|
|
|
|
Funds on deposit
|
|
|
2
|
|
|
|
14
|
|
|
|
|
|
Receivablesnonaffiliate
|
|
|
21
|
|
|
|
27
|
|
|
|
|
|
Receivablesaffiliate
|
|
|
169
|
|
|
|
187
|
|
|
|
|
|
Derivative contract assetsnonaffiliate
|
|
|
162
|
|
|
|
155
|
|
|
|
|
|
Derivative contract assetsaffiliate
|
|
|
245
|
|
|
|
464
|
|
|
|
|
|
Inventories
|
|
|
122
|
|
|
|
117
|
|
|
|
|
|
Prepaid rent
|
|
|
96
|
|
|
|
96
|
|
|
|
|
|
Other
|
|
|
11
|
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,030
|
|
|
|
1,203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment, net
|
|
|
2,533
|
|
|
|
3,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill, net
|
|
|
|
|
|
|
616
|
|
|
|
|
|
Other intangible assets, net
|
|
|
71
|
|
|
|
138
|
|
|
|
|
|
Derivative contract assetsnonaffiliate
|
|
|
516
|
|
|
|
399
|
|
|
|
|
|
Derivative contract assetsaffiliate
|
|
|
97
|
|
|
|
127
|
|
|
|
|
|
Prepaid rent
|
|
|
348
|
|
|
|
304
|
|
|
|
|
|
Other
|
|
|
31
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent assets
|
|
|
1,063
|
|
|
|
1,604
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
4,626
|
|
|
$
|
5,807
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS EQUITY
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt
|
|
$
|
4
|
|
|
$
|
4
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
|
63
|
|
|
|
168
|
|
|
|
|
|
Payableaffiliate
|
|
|
106
|
|
|
|
123
|
|
|
|
|
|
Derivative contract liabilitiesnonaffiliate
|
|
|
18
|
|
|
|
4
|
|
|
|
|
|
Derivative contract liabilitiesaffiliate
|
|
|
231
|
|
|
|
374
|
|
|
|
|
|
Contract retention liability
|
|
|
132
|
|
|
|
112
|
|
|
|
|
|
Other
|
|
|
8
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
562
|
|
|
|
787
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, net of current portion
|
|
|
18
|
|
|
|
21
|
|
|
|
|
|
Derivative contract liabilitiesnonaffiliate
|
|
|
|
|
|
|
13
|
|
|
|
|
|
Derivative contract liabilitiesaffiliate
|
|
|
94
|
|
|
|
84
|
|
|
|
|
|
Other
|
|
|
52
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent liabilities
|
|
|
164
|
|
|
|
134
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
Members Equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Members interest
|
|
|
3,900
|
|
|
|
5,024
|
|
|
|
|
|
Preferred stock in affiliate
|
|
|
|
|
|
|
(138
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total members equity
|
|
|
3,900
|
|
|
|
4,886
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Members Equity
|
|
$
|
4,626
|
|
|
$
|
5,807
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying combined notes are an integral part of these
consolidated financial statements
F-8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
|
|
|
Total
|
|
|
|
Members
|
|
|
Stock in
|
|
|
Members
|
|
|
|
Interest
|
|
|
Affiliate
|
|
|
Equity
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Balance, December 31, 2007
|
|
$
|
3,636
|
|
|
$
|
(229
|
)
|
|
$
|
3,407
|
|
Net income
|
|
|
1,217
|
|
|
|
|
|
|
|
1,217
|
|
Amortization of discount on preferred stock in affiliate
|
|
|
13
|
|
|
|
(13
|
)
|
|
|
|
|
Redemption of preferred stock in affiliate
|
|
|
|
|
|
|
31
|
|
|
|
31
|
|
Distributions to member
|
|
|
(325
|
)
|
|
|
|
|
|
|
(325
|
)
|
Capital contributions
|
|
|
250
|
|
|
|
|
|
|
|
250
|
|
Adoption of accounting guidance related to fair value measurement
|
|
|
3
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
4,794
|
|
|
|
(211
|
)
|
|
|
4,583
|
|
Net income
|
|
|
344
|
|
|
|
|
|
|
|
344
|
|
Amortization of discount on preferred stock in affiliate
|
|
|
11
|
|
|
|
(11
|
)
|
|
|
|
|
Redemption of preferred stock in affiliate
|
|
|
|
|
|
|
84
|
|
|
|
84
|
|
Distribution to member
|
|
|
(125
|
)
|
|
|
|
|
|
|
(125
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
5,024
|
|
|
|
(138
|
)
|
|
|
4,886
|
|
Net loss
|
|
|
(781
|
)
|
|
|
|
|
|
|
(781
|
)
|
Amortization of discount on preferred stock in affiliate
|
|
|
7
|
|
|
|
(7
|
)
|
|
|
|
|
Redemption of preferred stock in affiliate
|
|
|
|
|
|
|
145
|
|
|
|
145
|
|
Distribution to member
|
|
|
(350
|
)
|
|
|
|
|
|
|
(350
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2010
|
|
$
|
3,900
|
|
|
$
|
|
|
|
$
|
3,900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying combined notes are an integral part of these
consolidated financial statements
F-9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Cash Flows from Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(781
|
)
|
|
$
|
344
|
|
|
$
|
1,217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to reconcile net income (loss) and changes in other
operating assets and liabilities to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
141
|
|
|
|
98
|
|
|
|
92
|
|
Impairment losses
|
|
|
1,153
|
|
|
|
385
|
|
|
|
|
|
Gain on sales of assets, net
|
|
|
(3
|
)
|
|
|
(14
|
)
|
|
|
(8
|
)
|
Net changes in derivative contracts
|
|
|
(7
|
)
|
|
|
(144
|
)
|
|
|
(676
|
)
|
Lower of cost or market inventory adjustments
|
|
|
13
|
|
|
|
29
|
|
|
|
14
|
|
Potomac River settlement obligation
|
|
|
32
|
|
|
|
|
|
|
|
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonaffiliate accounts receivable, net
|
|
|
6
|
|
|
|
(11
|
)
|
|
|
(7
|
)
|
Affiliate accounts receivable, net
|
|
|
18
|
|
|
|
24
|
|
|
|
(69
|
)
|
Funds on deposit
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Prepaid rent
|
|
|
(44
|
)
|
|
|
(46
|
)
|
|
|
(24
|
)
|
Inventories
|
|
|
(18
|
)
|
|
|
(17
|
)
|
|
|
(23
|
)
|
Other assets
|
|
|
6
|
|
|
|
(9
|
)
|
|
|
1
|
|
Accounts payable and accrued liabilities
|
|
|
6
|
|
|
|
|
|
|
|
(1
|
)
|
Payableaffiliate
|
|
|
(17
|
)
|
|
|
(19
|
)
|
|
|
66
|
|
Taxes accruednonaffiliate
|
|
|
6
|
|
|
|
(7
|
)
|
|
|
2
|
|
Other liabilities
|
|
|
2
|
|
|
|
(6
|
)
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total adjustments
|
|
|
1,294
|
|
|
|
263
|
|
|
|
(620
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
513
|
|
|
|
607
|
|
|
|
597
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(233
|
)
|
|
|
(578
|
)
|
|
|
(641
|
)
|
Proceeds from the sales of assets
|
|
|
4
|
|
|
|
14
|
|
|
|
8
|
|
Restricted deposit payments and other
|
|
|
1
|
|
|
|
1
|
|
|
|
(34
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(228
|
)
|
|
|
(563
|
)
|
|
|
(667
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Redemption of preferred stock in affiliate
|
|
|
145
|
|
|
|
84
|
|
|
|
31
|
|
Repayment of long-term debt
|
|
|
(3
|
)
|
|
|
(3
|
)
|
|
|
(2
|
)
|
Capital contributions
|
|
|
|
|
|
|
|
|
|
|
250
|
|
Distributions to member
|
|
|
(350
|
)
|
|
|
(125
|
)
|
|
|
(325
|
)
|
Other
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities
|
|
|
(208
|
)
|
|
|
(44
|
)
|
|
|
(47
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents
|
|
|
77
|
|
|
|
|
|
|
|
(117
|
)
|
Cash and Cash Equivalents, beginning of year
|
|
|
125
|
|
|
|
125
|
|
|
|
242
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents, end of year
|
|
$
|
202
|
|
|
$
|
125
|
|
|
$
|
125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Cash Flow Disclosures:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
2
|
|
The accompanying combined notes are an integral part of these
consolidated financial statements
F-10
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31,
2010, 2009 and 2008
|
|
1.
|
Description
of Business and Accounting and Reporting Policies
|
Background
GenOn Americas Generation provides energy, capacity, ancillary
and other energy services to wholesale customers in competitive
energy markets in the United States through ownership and
operation of, and contracting for, power generation capacity.
GenOn Americas Generation is a wholesale generator with
approximately 9,724 MW of net electric generating capacity
in the Eastern PJM and Northeast regions and northern
California. GenOn Americas Generation also operates integrated
asset management and energy marketing organizations, including
proprietary trading operations.
GenOn Mid-Atlantic operates and owns or leases 5,204 MW of
net electric generating capacity in the Washington, D.C.
area. GenOn Mid-Atlantics electric generating capacity is
part of the 9,724 MW of net electric generating capacity of
GenOn Americas Generation. GenOn Mid-Atlantics generating
facilities serve the Eastern PJM markets. The PJM ISO operates
the largest centrally dispatched control area in the
United States.
GenOn Americas Generation and GenOn Mid-Atlantic are Delaware
limited liability companies and indirect wholly-owned
subsidiaries of GenOn. GenOn Mid-Atlantic is a wholly-owned
subsidiary of GenOn North America and an indirect wholly-owned
subsidiary of GenOn Americas Generation. The chart below is a
summary representation of the Companies organizational
structure and is not a complete organizational chart of GenOn.
|
|
|
(1) |
|
GenOn Power Generation, LLCs subsidiaries include former
RRI Energy generating facilities acquired as a result of the
Merger. |
GenOn, a Delaware corporation, was formed in August 2000 by
CenterPoint (then known as Reliant Energy, Incorporated) in
connection with the planned separation of its regulated and
unregulated operations. CenterPoint transferred substantially
all of its unregulated businesses, including the name Reliant
Energy, to
F-11
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
the company now named GenOn Energy, Inc. In May 2001, Reliant
Energy (then known as Reliant Resources, Inc.) became a publicly
traded company and in September 2002, CenterPoint distributed
its remaining ownership of Reliant Energys common stock to
its stockholders. RRI Energy changed its name from Reliant
Energy, Inc. effective May 2, 2009 in connection with the
sale of its retail business. GenOn changed its name from RRI
Energy, Inc. effective December 3, 2010.
GenOn Americas Generation and GenOn Mid-Atlantic have a number
of service agreements for labor and administrative services with
GenOn Energy Services. GenOn Energy Management provides services
to certain operating subsidiaries of GenOn Americas, outside of
GenOn Americas Generation, which includes the bidding and
dispatch of the generating units, fuel procurement and the
execution of contracts, including economic hedges, to reduce
price risk. See note 6 for further discussion of
arrangements with these related parties.
Merger
of Mirant and RRI Energy
On December 3, 2010, Mirant and RRI Energy completed the
Merger contemplated by the Merger Agreement. Upon completion of
the Merger, RRI Energy Holdings, Inc. (Merger Sub), a direct and
wholly-owned subsidiary of RRI Energy merged with and into
Mirant, with Mirant continuing as the surviving corporation and
a wholly-owned subsidiary of RRI Energy. Each of Mirant and RRI
Energy received legal opinions that the Merger qualified as a
tax-free reorganization under the IRC. Accordingly, none of RRI
Energy, Merger Sub, Mirant or any of the Mirant stockholders
will recognize any gain or loss in the transaction, except that
Mirant stockholders will recognize a gain or loss with respect
to cash received in lieu of fractional shares of RRI Energy
common stock. Upon the closing of the Merger, each issued and
outstanding share of Mirant common stock, including grants of
restricted common stock, automatically converted into
2.835 shares of common stock of RRI Energy based on the
Exchange Ratio. Additionally, upon the closing of the Merger,
RRI Energy was renamed GenOn. Mirant stock options and other
equity awards converted upon completion of the Merger into stock
options and equity awards with respect to GenOn common stock,
after giving effect to the Exchange Ratio. At the close of the
Merger, former Mirant stockholders owned approximately 54% of
the equity of the combined company and former RRI Energy
stockholders owned approximately 46% of the equity of the
combined company. See note 4 for additional information on
the related debt transactions.
Basis
of Presentation
The consolidated financial statements of the Companies and their
wholly-owned subsidiaries have been prepared in accordance with
GAAP. The consolidated financial statements have been prepared
from records maintained by the Companies and their subsidiaries.
All significant intercompany accounts and transactions have been
eliminated in consolidation.
At December 31, 2010, substantially all of the
Companies subsidiaries are wholly-owned and located in the
United States. Certain prior period amounts have been
reclassified to conform to the current year financial statement
presentation.
Use of
Estimates
The preparation of consolidated 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 consolidated financial statements
and the reported amounts
F-12
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
of revenues and expenses during the period. Actual results could
differ from those estimates. The Companies significant
estimates include:
|
|
|
|
|
determining the fair value of certain derivative contracts;
|
|
|
|
estimating the useful lives of long-lived assets;
|
|
|
|
determining the value of asset retirement obligations;
|
|
|
|
estimating future cash flows in determining impairments of
long-lived assets, definite-lived intangible assets and goodwill
(GenOn Mid-Atlantic); and
|
|
|
|
estimating losses to be recorded for contingent liabilities.
|
The Companies evaluate events that occur after their balance
sheet date but before their financial statements are issued for
potential recognition or disclosure. Based on their evaluations,
the Companies determined that there were no material subsequent
events for recognition or disclosure other than those disclosed
herein.
Revenue
Recognition
GenOn
Americas Generation
GenOn Americas Generation recognizes revenue when earned and
collection is probable. GenOn Americas Generation earns revenue
from the following sources: (a) power generation revenues,
(b) contracted and capacity revenues, (c) fuel sales
and proprietary trading revenues and (d) power hedging
revenues.
Power Generation Revenues. GenOn Americas
Generation recognizes revenue from the sale of electricity from
its generating facilities. Sales of energy primarily are based
on economic dispatch, or as-ordered by an ISO or
RTO, based on member participation agreements, but without an
underlying contractual commitment. ISO and RTO revenues and
revenues from sales of energy based on economic-dispatch are
recorded on the basis of MWh delivered, at the relevant
day-ahead or real-time prices. Additionally, GenOn Americas
Generation includes revenue from the sale of steam in power
generation revenues.
Contracted and Capacity Revenues. GenOn
Americas Generation recognizes revenue received from providing
ancillary services and revenue received from an ISO or RTO based
on auction results or negotiated contract prices for making
installed generation capacity available to meet system
reliability requirements. In addition, when a long-term electric
power agreement conveys to the buyer of the electric power the
right to control the generating capacity of GenOn Americas
Generations facility, that agreement is evaluated to
determine if it is a lease of the generating facility rather
than a sale of electric power. Operating lease revenue for GenOn
Americas Generations generating facilities is normally
recorded as capacity revenue.
Fuel Sales and Proprietary Trading
Revenues. GenOn Americas Generation recognizes
revenue from the sale of fuel oil and natural gas and revenues
associated with fuel oil management and proprietary trading
activities.
Power Hedging Revenues. GenOn Americas
Generation recognizes revenue from contracts which include both
the sale of power and natural gas used to hedge power prices as
well as hedges to capture the incremental value related to the
geographic location of its physical assets.
F-13
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table reflects GenOn Americas Generations
revenues by type:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
Power generation revenues
|
|
$
|
1,122
|
|
|
$
|
805
|
|
|
$
|
1,841
|
|
Contracted and capacity revenues
|
|
|
560
|
|
|
|
592
|
|
|
|
612
|
|
Fuel sales and proprietary trading revenues
|
|
|
29
|
|
|
|
67
|
|
|
|
90
|
|
Power hedging revenues
|
|
|
394
|
|
|
|
845
|
|
|
|
645
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
2,105
|
|
|
$
|
2,309
|
|
|
$
|
3,188
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In accordance with accounting guidance related to derivative
financial instruments, physical transactions, or revenues from
the sale of generated electricity to ISOs and RTOs, are recorded
on a gross basis in the consolidated statements of operations.
Financial transactions, or the buying and selling of energy for
trading purposes, are recorded on a net basis in the
consolidated statements of operations.
GenOn
Mid-Atlantic
GenOn Mid-Atlantic recognizes revenue from the sale of energy
when earned and collection is probable. GenOn Mid-Atlantic
recognizes affiliate and nonaffiliate revenue when electric
power is delivered to an affiliate or to a customer pursuant to
contractual commitments that specify volume, price and delivery
requirements. GenOn Mid-Atlantic earns revenue from the
following sources: (a) power generation revenues,
(b) contracted and capacity revenues and (c) power
hedging revenues, as defined above.
The following table reflects GenOn Mid-Atlantics revenues
by type:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
Power generation revenues
|
|
$
|
990
|
|
|
$
|
659
|
|
|
$
|
1,370
|
|
Contracted and capacity revenues
|
|
|
335
|
|
|
|
349
|
|
|
|
340
|
|
Power hedging revenues
|
|
|
379
|
|
|
|
770
|
|
|
|
569
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
1,704
|
|
|
$
|
1,778
|
|
|
$
|
2,279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of Fuel, Electricity and Other Products
Cost of fuel, electricity and other products on the
Companies consolidated statements of operations include
the costs of goods produced and sold through the combustion
process, including the costs associated with handling and
disposal of ash, natural gas transportation and services
rendered during a reporting period. Cost of fuel, electricity
and other products also includes purchased emissions allowances
for
CO2,
SO2
and
NOx
and the settlements of and changes in fair value of derivative
financial instruments used to hedge fuel economically.
Additionally, cost of fuel, electricity and other products
includes lower of cost or market inventory adjustments. Cost of
fuel, electricity and other products excludes depreciation and
amortization. Gross margin is total operating revenues less cost
of fuel, electricity and other products.
Derivatives
and Hedging Activities
In connection with the business of generating electricity, the
Companies 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. In addition, the
open positions in GenOn Americas Generations trading
activities comprised of proprietary trading and fuel oil
management
F-14
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
activities, expose it to risks associated with changes in energy
commodity prices. The Companies, through their asset management
activities, 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.
GenOn Americas Generations proprietary trading activities
also utilize similar derivative contracts in markets where it
has a physical presence to attempt to generate incremental gross
margin. GenOn Americas Generations fuel oil management
activities use derivative financial instruments to hedge
economically the fair value of its physical fuel oil
inventories, optimize the approximately three million barrels of
storage capacity that it owns or leases, as well as attempt to
profit from market opportunities related to timing
and/or
differences in the pricing of various products.
Derivative financial instruments are recorded in the
consolidated balance sheets at fair value, except for derivative
contracts that qualify for the normal purchase or normal sale
exceptions, which are not in the consolidated balance sheets or
results of operations prior to settlement based on accrual
accounting treatment. The Companies present their 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. The
Companies did not have any derivative financial instruments that
they had designated as fair value or cash flow hedges for
accounting purposes during 2010, 2009 or 2008.
Because the Companies derivative financial instruments
have not been designated as hedges for accounting purposes,
changes in such instruments fair values are recognized
currently in earnings. The Companies derivative financial
instruments are categorized based on the business objective the
instrument is expected to achieve: asset management or trading,
which includes GenOn Americas Generations 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 GenOn Americas Generations
proprietary trading and fuel oil management activities are
recorded on a net basis as operating revenue in the consolidated
statements of operations.
In May 2010, the Companies concluded that they could no longer
assert that physical delivery is probable for many of their coal
agreements. The conclusion was based on expected generation
levels, changes observed in the coal markets and the completion
of the Companies coal blending facility at their
Morgantown generating facility that allows for greater
flexibility of the Companies coal supply. Because the
Companies can no longer assert that physical delivery of coal
from these agreements is probable, they do not qualify for the
normal purchase exception and the Companies are required to
apply fair value accounting for these contracts in the current
period and prospectively.
The Companies also consider risks associated with interest
rates, counterparty credit and their own non-performance risk
when valuing their 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 Companies
transactions being valued. See note 2 for discussion on
fair value measurements and note 2 for further discussion
of the Companies credit policies.
F-15
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Concentration
of Revenues
During 2010, GenOn Americas Generation had $1.3 billion in
revenues from PJM, which represented 63% of consolidated
revenues. The revenues generated from this counterparty are
included in the Eastern PJM and Energy Marketing segments.
During 2009, GenOn Americas Generation had $1.0 billion in
revenues from PJM, which represented 43% of consolidated
revenues. The revenues generated from this counterparty are
primarily included in the Eastern PJM segment. Additionally,
during 2009 GenOn Americas Generation had $332 million in
revenues from another counterparty, which represented 14% of
consolidated revenues. The revenues generated from this
counterparty are included in the Eastern PJM, Energy Marketing
and Northeast segments. During 2008, GenOn Americas Generation
had $1.5 billion in revenues from PJM, which represented
48% of consolidated revenues. The revenues generated from this
counterparty are primarily included in the Eastern PJM segment.
Additionally, during 2008 GenOn Americas Generation had
$470 million in revenues from another counterparty, which
represented 15% of consolidated revenues. The revenues generated
from this counterparty are primarily included in the Northeast
segment.
During 2010, GenOn Mid-Atlantic had $1.3 billion in
revenues from PJM, which represented 78% of consolidated
revenues. During 2009, GenOn Mid-Atlantic had $1.0 billion
in revenues from PJM, which represented 56% of consolidated
revenues. Additionally, during 2009 GenOn Mid-Atlantic had
$191 million in revenues from another counterparty, which
represented 11% of consolidated revenues. During 2008, GenOn
Mid-Atlantic had $1.5 billion in revenues from PJM, which
represented 67% of consolidated revenues.
Coal
Supplier Concentration Risk
The Companies coal supply comes primarily from the
Northern Appalachian and Central Appalachian coal regions. GenOn
Americas Generation enters into contracts of varying tenors on
behalf of GenOn Mid-Atlantic to secure appropriate quantities of
fuel that meet the varying specifications of GenOn
Mid-Atlantics generating facilities. For the coal-fired
generating facilities, GenOn Americas Generation purchases most
of its coal from a small number of suppliers under contracts
with terms of varying lengths, some of which extend to 2013. The
Companies had exposure to two counterparties at
December 31, 2010, and exposure to three counterparties at
December 31, 2009, that each represented an exposure of
more than 10% of the total coal commitments, by volume, for the
respective succeeding year, and in aggregate represented
approximately 60% and 61% of the Companies total coal
commitments at December 31, 2010 and 2009, respectively. At
December 31, 2010, one counterparty represented an exposure
of 39% of these total coal commitments, by volume.
Concentration
of Labor Subject to Collective Bargaining
Agreements
Under the Companies services agreement with GenOn Energy
Services, an indirect wholly-owned subsidiary of GenOn, GenOn
Energy Services provides the Companies personnel. At
December 31, 2010, approximately 57% of GenOn Americas
Generations total employees are subject to collective
bargaining agreements. Of those employees subject to collective
bargaining agreements, 69% are represented by IBEW Local 1900 in
the Eastern PJM segment. At December 31, 2010,
approximately 62% of GenOn Mid-Atlantics total employees
are subject to collective bargaining agreements and are
represented by IBEW Local 1900. Less than five percent of GenOn
Americas Generations employees are subject to collective
bargaining agreements that will expire in 2011. GenOn Americas
Generation intends to negotiate the renewal of these agreements
and does not anticipate any disruptions to GenOn Americas
Generations operations.
F-16
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Cash
and Cash Equivalents
GenOn Americas Generation and GenOn Mid-Atlantic consider all
short-term investments with an original maturity of three months
or less to be cash equivalents. At December 31, 2010,
except for amounts held in bank accounts to cover current
payables, all of the Companies cash and cash equivalents
were invested in AAA-rated United States Treasury money market
funds.
Restricted
Cash
Restricted cash is included in current and noncurrent assets as
funds on deposit and other noncurrent assets, respectively, in
the consolidated balance sheets. Restricted cash includes the
following:
GenOn
Americas Generation
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
Funds deposited with the trustee to discharge the GenOn North
America senior notes, due
2013(1)
|
|
$
|
866
|
|
|
$
|
|
|
Cash collateral
posted(2)
|
|
|
120
|
|
|
|
83
|
|
GenOn North America
deposits(3)
|
|
|
|
|
|
|
124
|
|
|
|
|
|
|
|
|
|
|
Total current and noncurrent funds on deposit
|
|
|
986
|
|
|
|
207
|
|
Less: Current funds on deposit
|
|
|
949
|
|
|
|
180
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent funds on deposit
|
|
$
|
37
|
|
|
$
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
See note 4. |
|
(2) |
|
Represents cash collateral posted for energy trading and
marketing and other operating activities; includes
$32 million related to the Potomac River Settlement, see
notes 3(d) and 10. |
|
(3) |
|
Represents deposits posted under GenOn North America senior
secured term loans to support the issuance of letters of credit.
These amounts were returned in 2010 as a result of the repayment
of the GenOn North America senior secured term loans. |
GenOn
Mid-Atlantic
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
Cash collateral
posted(1)
|
|
$
|
32
|
|
|
$
|
33
|
|
|
|
|
|
|
|
|
|
|
Total current and noncurrent funds on deposit
|
|
|
32
|
|
|
|
33
|
|
Less: Current funds on deposit
|
|
|
2
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent funds on deposit
|
|
$
|
30
|
|
|
$
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents amount related to the Potomac River Settlement, see
notes 3(d) and 10. |
Inventories
Inventories consist primarily of materials and supplies, fuel
oil, coal and purchased emissions allowances. Inventory is
generally stated at the lower of cost or market value and is
expensed on a weighted average cost
F-17
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
basis. Fuel inventory is removed from the inventory account as
it is used in the generation of electricity or sold to third
parties, including sales related to GenOn Americas
Generations fuel oil management activities. Materials and
supplies are removed from the inventory account when they are
used for repairs, maintenance or capital projects. Purchased
emissions allowances are removed from inventory and charged to
cost of fuel, electricity and other products in the
Companies consolidated statements of operations as they
are utilized for emissions volumes.
Inventories were comprised of the following:
GenOn
Americas Generation
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
Fuel inventory:
|
|
|
|
|
|
|
|
|
Fuel oil
|
|
$
|
136
|
|
|
$
|
99
|
|
Coal
|
|
|
52
|
|
|
|
52
|
|
Other
|
|
|
1
|
|
|
|
1
|
|
Materials and supplies
|
|
|
72
|
|
|
|
66
|
|
Purchased emissions allowances
|
|
|
34
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
Total inventories
|
|
$
|
295
|
|
|
$
|
241
|
|
|
|
|
|
|
|
|
|
|
During 2010, 2009 and 2008, GenOn Americas Generation recorded
$22 million, $32 million and $65 million,
respectively, for lower of average cost or market valuation
adjustments in cost of fuel, electricity and other products.
GenOn
Mid-Atlantic
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
Fuel inventory:
|
|
|
|
|
|
|
|
|
Fuel oil
|
|
$
|
20
|
|
|
$
|
20
|
|
Coal
|
|
|
52
|
|
|
|
52
|
|
Other
|
|
|
1
|
|
|
|
1
|
|
Materials and supplies
|
|
|
49
|
|
|
|
43
|
|
Purchased emissions allowances
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
Total inventories
|
|
$
|
122
|
|
|
$
|
117
|
|
|
|
|
|
|
|
|
|
|
During 2010, 2009 and 2008, GenOn Mid-Atlantic recorded
$13 million, $29 million and $14 million,
respectively, for lower of average cost or market valuation
adjustments in cost of fuel, electricity and other products.
Granted
Emissions Allowances
Included in property, plant and equipment are:
(a) emissions allowances granted by the EPA that were
projected to be required to offset physical emissions and
(b) emissions allowances granted by the EPA that were
projected to be in excess of those required to offset physical
emissions related to generating facilities
F-18
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
owned by the Companies. These emissions allowances were recorded
at fair value at the date of the acquisition of the facility and
are depreciated on a straight-line basis over the estimated
useful life of the respective generating facility and are
charged to depreciation and amortization expense in the
consolidated statements of operations.
Included in other intangible assets are emissions allowances
related to the Dickerson and Morgantown baseload units leased by
the Companies. Emissions allowances related to leased units are
recorded at fair value at the commencement of the lease. These
emissions allowances are amortized on a straight-line basis over
the term of the lease for leased units, and are charged to
depreciation and amortization expense in the consolidated
statements of operations.
Property,
Plant and Equipment
Property, plant and equipment are recorded at cost, which
includes materials, labor, associated payroll-related and
overhead costs and the cost of financing construction. The cost
of routine maintenance and repairs, such as inspections and
corrosion removal, and the replacement of minor items of
property are charged to expense as incurred. Certain
expenditures incurred during a major maintenance outage of a
generating facility are capitalized, including the replacement
of major component parts and labor and overhead incurred to
install the parts. Depreciation of the recorded cost of
depreciable property, plant and equipment is determined using
primarily composite rates. Leasehold improvements are
depreciated over the shorter of the expected life of the related
equipment or the lease term. Upon the retirement or sale of
property, plant and equipment, the cost of such assets and the
related accumulated depreciation are removed from the
consolidated balance sheets. No gain or loss is recognized for
ordinary retirements in the normal course of business since the
composite depreciation rates used by the Companies take into
account the effect of interim retirements.
Impairment
of Long-Lived Assets
GenOn Americas Generation and GenOn Mid-Atlantic evaluate
long-lived assets, such as property, plant and equipment and
purchased intangible assets subject to amortization, for
impairment whenever events or changes in circumstances indicate
that the carrying amount of the asset may not be recoverable.
Such evaluations are performed in accordance with the accounting
guidance related to evaluating long-lived assets for impairment.
Recoverability of assets to be held and used is measured by a
comparison of the carrying amount of an asset to the estimated
undiscounted future cash flows expected to be generated by the
asset. If the carrying amount of an asset exceeds its estimated
undiscounted future cash flows, an impairment charge is
recognized as the amount by which the carrying amount of the
asset exceeds its fair value. See note 3(d) for further
discussion of assets reviewed for impairment.
Capitalization
of Interest Cost (GenOn Americas Generation)
GenOn Americas Generation capitalizes interest on projects
during their construction period. GenOn Americas Generation
determines which debt instruments represent a reasonable measure
of the cost of financing construction in terms of interest costs
incurred that otherwise could have been avoided. These debt
instruments and associated interest costs are included in the
calculation of the weighted average interest rate used for
determining the capitalization rate. Once a project is placed in
service, capitalized interest, as a component of the total cost
of the construction, is depreciated over the estimated useful
life of the asset constructed.
F-19
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
During 2010, 2009 and 2008, GenOn Americas Generation incurred
the following interest costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
Total interest costs
|
|
$
|
205
|
|
|
$
|
209
|
|
|
$
|
237
|
|
Capitalized and included in property, plant and equipment, net
|
|
|
(5
|
)
|
|
|
(72
|
)
|
|
|
(48
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
$
|
200
|
|
|
$
|
137
|
|
|
$
|
189
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The amounts of capitalized interest above include interest
accrued. During 2010, 2009 and 2008, cash paid for interest was
$190 million, $192 million and $223 million,
respectively, of which $5 million, $68 million and
$48 million, respectively, were capitalized.
Environmental
Costs
GenOn Americas Generation and GenOn Mid-Atlantic expense
environmental expenditures related to existing conditions that
do not have future economic benefit. GenOn Americas Generation
and GenOn Mid-Atlantic capitalize environmental expenditures for
which there is a future economic benefit. GenOn Americas
Generation and GenOn Mid-Atlantic record liabilities for
expected future costs, on an undiscounted basis, related to
environmental assessments and /or remediation when they are
probable and can be reasonably estimated.
Operating
Leases
GenOn Americas Generation and GenOn Mid-Atlantic lease various
assets under non-cancelable leasing arrangements, including
generating facilities, office space and other equipment. The
rent expense associated with leases that qualify as operating
leases is recognized on a straight-line basis over the lease
term within operations and maintenance expensenonaffiliate
in the consolidated statements of operations. The
Companies most significant operating leases are GenOn
Mid-Atlantics leases of the Dickerson and Morgantown
baseload units. See note 7 for further discussion on these
leases.
Intangible
Assets
Intangible assets relate primarily to trading rights,
development rights, and emissions allowances. Intangible assets
with definite useful lives are amortized on a straight-line
basis to their estimated residual values over their respective
useful lives ranging up to 40 years.
Goodwill
(GenOn Mid-Atlantic)
Goodwill represents the excess of costs over the fair value of
assets of businesses acquired. Goodwill acquired in a purchase
business combination is not amortized, but instead tested for
impairment at least annually. A goodwill impairment occurs when
the fair value of a reporting unit is less than its carrying
value including goodwill. The amount of the impairment charge,
if an impairment exists, is calculated as the difference between
the implied fair value of the reporting unit goodwill and its
carrying value. GenOn Mid-Atlantic performs an annual assessment
of goodwill at October 31 and whenever contrary evidence exists
as to the recoverability of goodwill. The fair value of the
reporting unit is calculated using income and market approaches
and underlying assumptions based on the best information
available. See note 3 for further discussion.
F-20
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Debt
Issuance Costs (GenOn Americas Generation)
Debt issuance costs are capitalized and amortized as interest
expense under the effective interest method over the term of the
related debt. Changes in debt issuance costs are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
Balance, January 1
|
|
$
|
29
|
|
|
$
|
38
|
|
|
$
|
49
|
|
Amortized
|
|
|
(8
|
)
|
|
|
(9
|
)
|
|
|
(10
|
)
|
Accelerated
amortization/write-offs(1)(2)
|
|
|
(9
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31
|
|
$
|
12
|
|
|
$
|
29
|
|
|
$
|
38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
See note 4. |
|
(2) |
|
Amounts are considered a portion of the net carrying value of
the related debt and are expensed when accelerated as a
component of debt extinguishments. |
Income
Taxes and Deferred Tax Asset Valuation Allowance
GenOn
Americas Generation
GenOn Americas Generation and most of its subsidiaries are
limited liability companies that are treated as branches of
GenOn Americas for income tax purposes. As a result, GenOn
Americas and GenOn have direct liability for the majority of the
federal and state income taxes relating to GenOn Americas
Generations operations. Some of GenOn Americas
Generations subsidiaries, Hudson Valley Gas and GenOn
Special Procurement, Inc. exist as regarded corporate entities
for income tax purposes. GenOn Kendall, which had previously
existed as a regarded entity, has been converted to a
disregarded entity. For the subsidiaries that continue to exist
as corporate regarded entities, GenOn Americas Generation
allocates current and deferred income taxes to each corporate
regarded entity as if such entity were a single taxpayer
utilizing the asset and liability method to account for income
taxes. To the extent GenOn Americas Generation provides tax
expense or benefit, any related tax payable or receivable to
GenOn is reclassified to equity in the same period since GenOn
Americas Generation does not have a tax sharing agreement with
GenOn.
Deferred tax assets and liabilities are recognized for the
regarded corporate entities for the future tax consequences
attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their
respective tax bases and operating loss and tax credit
carryforwards. When necessary, deferred tax assets are reduced
by a valuation allowance to reflect the amount that is estimated
to be recoverable. In assessing the recoverability of the
deferred tax assets, GenOn Americas Generation considers whether
it is likely that some portion or all of the deferred tax assets
will be realized. Deferred tax assets and liabilities are
measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are
expected to be recovered or settled. The effect on deferred tax
assets and liabilities of a change in tax rates is recognized in
income in the period that includes the enactment date.
The determination of a valuation allowance requires significant
judgment as to the generation of taxable income during future
periods in which those temporary differences are deductible. In
making this determination, management considers all available
positive and negative evidence affecting specific deferred tax
assets, including GenOn Americas Generations past and
anticipated future performance, the reversal of deferred tax
liabilities and the implementation of tax planning strategies.
Additionally, GenOn Americas Generation has not recognized any
tax benefits relating to tax uncertainties arising in the
ordinary course of business that are less than or subject to the
measurement threshold of the
F-21
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
more-likely-than-not standard prescribed under the accounting
guidance for accounting for uncertainty of income taxes. These
unrecognized tax benefits may be either a tax liability or an
adjustment to their NOLs based on the specific facts of each tax
uncertainty. GenOn Americas Generation periodically assesses its
tax uncertainties based on the latest information available. The
amount of the unrecognized tax benefit requires management to
make significant assumptions about the expected outcomes of
certain tax positions included in their filed or yet to be filed
tax returns.
GenOn
Mid-Atlantic
GenOn Mid-Atlantic and its subsidiaries are limited liability
companies that are treated as branches of GenOn Americas for
income tax purposes. As such, GenOn and GenOn Americas have
direct liability for the majority of the federal and state
income taxes relating to its operations.
Fair
Value of Financial Instruments
The accounting guidance related to the disclosure about fair
value of financial instruments requires the disclosure of the
fair value of all financial instruments that are not otherwise
recorded at fair value in the financial statements. At
December 31, 2010 and 2009, financial instruments recorded
at contractual amounts that approximate fair value include
certain funds on deposit, receivables from affiliate and
nonaffiliate, accounts payable and accrued liabilities,
payableaffiliate and notes payableaffiliate. The
fair values of such items are not materially sensitive to shifts
in market interest rates because of the short term to maturity
of these instruments. The fair value of the Companies
long-term debt is estimated using quoted market prices when
available. See note 2 for further discussion.
Recently
Adopted Accounting Guidance
In December 2007, the FASB issued revised guidance related to
accounting for business combinations. This guidance requires an
acquirer of a business to recognize the assets acquired, the
liabilities assumed and any noncontrolling interest in the
acquiree at their acquisition-date fair values. The guidance
also requires disclosure of information necessary for investors
and other users to evaluate and understand the nature and
financial effect of the business combination. Additionally, the
guidance requires that acquisition-related costs be expensed as
incurred. The provisions of this guidance became effective for
acquisitions completed on or after January 1, 2009;
however, the income tax considerations included in the guidance
were effective as of that date for all acquisitions, regardless
of the acquisition date. The Companies adopted this accounting
guidance on January 1, 2009, and the adoption had no effect
on the Companies consolidated statements of operations,
financial position or cash flows.
On February 12, 2008, the FASB issued guidance related to
fair value measurements, which deferred the effective date of
fair value measurements for one year for certain nonfinancial
assets and liabilities, with the exception of those nonfinancial
assets and liabilities that are recognized or disclosed on a
recurring basis (at least annually). The Companies
non-recurring nonfinancial assets and liabilities that could be
measured at fair value in the Companies consolidated
financial statements include long-lived asset impairments and
the initial recognition of asset retirement obligations. The
Companies adopted the guidance related to fair value
measurements for non-recurring nonfinancial assets and
liabilities on January 1, 2009, and the adoption had no
effect on the Companies consolidated statements of
operations, financial position or cash flows. The Companies
incorporated the recognition and disclosure provisions related
to fair value measurements for non-recurring nonfinancial assets
and liabilities when applicable. See note 2 for these
disclosures.
On March 19, 2008, the FASB issued guidance that enhances
the required disclosures for derivative instruments. The
Companies utilize derivative financial instruments to manage
their exposure to commodity
F-22
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
price risks and for GenOn Americas Generations proprietary
trading and fuel oil management activities. The Companies
adopted this guidance on January 1, 2009. See note 2
for these disclosures.
On April 9, 2009, the FASB issued guidance that requires
disclosures about the fair value of financial instruments that
are not otherwise recorded at fair value in the interim
financial statements. The Companies adopted this accounting
guidance for their disclosures of the fair value of financial
instruments for the quarter ended June 30, 2009, and the
adoption had no effect on the Companies consolidated
statements of operations, financial position or cash flows. See
Fair Values of Other Financial Instruments in
note 2 for these disclosures.
On April 9, 2009, the FASB issued guidance which provides
additional direction on determining whether a market for a
financial asset is not active and a transaction is not
distressed for fair value measurements. Under distressed market
conditions, the Companies need to weigh all available evidence
in determining whether a transaction occurred in an orderly
market. This guidance requires additional judgment by the
Companies when determining the fair value of derivative
contracts in the current economic environment. The Companies
adopted this accounting guidance for their fair value
measurements for the quarter ended June 30, 2009, and the
adoption did not have a material effect on the Companies
consolidated statements of operations, financial position or
cash flows.
On July 1, 2009, the FASB issued guidance which codified
all authoritative nongovernmental GAAP into a single source. The
codified guidance supersedes all existing accounting standards,
but does not change the contents of those standards. The
Companies adopted this accounting guidance for the quarter ended
September 30, 2009, and the Companies changed their
references to accounting literature to conform to the codified
source of authoritative nongovernmental GAAP.
On August 27, 2009, the FASB issued updated guidance for
measuring the fair value of liabilities. The guidance clarifies
that a quoted price for the identical liability in an active
market is the best evidence of fair value for that liability,
and in the absence of a quoted market price, the liability may
be measured at fair value at the amount that the Companies would
receive as proceeds if they were to issue that liability at the
measurement date. The Companies adopted this accounting guidance
for their fair value measurements of liabilities for the quarter
ended September 30, 2009, and the adoption did not have a
material effect on the Companies consolidated statements
of operations, financial position or cash flows.
On January 21, 2010, the FASB issued guidance that enhances
the disclosures for fair value measurements. The guidance
requires the Companies to disclose separately the amount of
significant transfers between Level 1 and Level 2 of
the fair value hierarchy, the reasons for the significant
transfers, the valuation techniques and inputs used and the
classes of assets and liabilities accounted for at fair value on
a recurring basis. The Companies adopted this accounting
guidance for the quarter ended March 31, 2010. See
note 2 for additional information on fair value
measurements.
On February 25, 2010, the FASB issued guidance that amends
its requirement for public companies to disclose the date
through which the Companies have evaluated subsequent events and
whether that date represents the date the financial statements
were issued or were available to be issued. The Companies
adopted the subsequent event disclosure requirements for the
quarter ended March 31, 2010, and the adoption had no
effect on the Companies consolidated statements of
operations, financial positions or cash flows. The Companies
continue to evaluate subsequent events through the date when the
financial statements are issued.
New
Accounting Guidance Not Yet Adopted at December 31,
2010
On January 21, 2010, the FASB issued guidance that requires
a reconciliation for Level 3 fair value measurements,
including presenting separately the amounts of purchases,
issuances and settlements on a gross
F-23
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
basis. The Companies currently disclose the amounts of
purchases, issuances and settlements on a net basis within their
roll forward of Level 3 fair value measurements in
note 2. The Companies will present these disclosures in
their
Form 10-Q
for the quarter ended March 31, 2011.
|
|
(a)
|
Derivatives
and Hedging Activities.
|
The Companies use derivative financial instruments to manage
operational or market constraints, to increase the return on
their generation assets and to generate incremental gross margin.
GenOn
Americas Generation
The following table presents the fair value of GenOn Americas
Generations derivative financial instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Derivative
|
|
|
|
Derivative Contract Assets
|
|
|
Derivative Contract Liabilities
|
|
|
Contract
|
|
|
|
Current
|
|
|
Long-Term
|
|
|
Current
|
|
|
Long-Term
|
|
|
Assets (Liabilities)
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset management
|
|
$
|
442
|
|
|
$
|
623
|
|
|
$
|
(279
|
)
|
|
$
|
(102
|
)
|
|
$
|
684
|
|
Trading activities
|
|
|
851
|
|
|
|
69
|
|
|
|
(854
|
)
|
|
|
(71
|
)
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
$
|
1,293
|
|
|
$
|
692
|
|
|
$
|
(1,133
|
)
|
|
$
|
(173
|
)
|
|
$
|
679
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset management
|
|
$
|
669
|
|
|
$
|
535
|
|
|
$
|
(404
|
)
|
|
$
|
(99
|
)
|
|
$
|
701
|
|
Trading activities
|
|
|
747
|
|
|
|
64
|
|
|
|
(746
|
)
|
|
|
(64
|
)
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
$
|
1,416
|
|
|
$
|
599
|
|
|
$
|
(1,150
|
)
|
|
$
|
(163
|
)
|
|
$
|
702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-24
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table presents the net gains (losses) for
derivative financial instruments recognized in income in the
consolidated statements of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
|
|
|
|
Cost of Fuel,
|
|
|
|
|
|
Cost of Fuel,
|
|
|
|
|
|
|
Electricity and
|
|
|
|
|
|
Electricity and
|
|
Derivatives Not Designated as Hedging Instrument
|
|
Revenues
|
|
|
Other Products
|
|
|
Revenues
|
|
|
Other Products
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Asset Management Commodity Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
|
|
$
|
77
|
|
|
$
|
(89
|
)
|
|
$
|
111
|
|
|
$
|
49
|
|
Realized(1)
|
|
|
318
|
|
|
|
(168
|
)
|
|
|
745
|
|
|
|
(74
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total asset management
|
|
$
|
395
|
|
|
$
|
(257
|
)
|
|
$
|
856
|
|
|
$
|
(25
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trading Commodity Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
|
|
$
|
(5
|
)
|
|
$
|
|
|
|
$
|
(113
|
)
|
|
$
|
|
|
Realized(1)
|
|
|
(23
|
)
|
|
|
|
|
|
|
145
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total trading
|
|
$
|
(28
|
)
|
|
$
|
|
|
|
$
|
32
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
$
|
367
|
|
|
$
|
(257
|
)
|
|
$
|
888
|
|
|
$
|
(25
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents the total cash settlements of derivative financial
instruments during each quarterly reporting period that existed
at the beginning of each respective period. |
The following tables present the notional quantity on long
(short) positions for derivative financial instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional Volumes at December 31, 2010
|
|
|
|
Derivative
|
|
|
Derivative
|
|
|
Net
|
|
|
|
Contract
|
|
|
Contract
|
|
|
Derivative
|
|
Derivative Instrument
|
|
Assets
|
|
|
Liabilities
|
|
|
Contracts
|
|
|
|
(in millions)
|
|
|
Commodity Contracts (in equivalent MWh):
|
|
|
|
|
|
|
|
|
|
|
|
|
Power(1)
|
|
|
(23
|
)
|
|
|
(15
|
)
|
|
|
(38
|
)
|
Natural gas
|
|
|
(28
|
)
|
|
|
29
|
|
|
|
1
|
|
Fuel oil
|
|
|
2
|
|
|
|
(3
|
)
|
|
|
(1
|
)
|
Coal
|
|
|
9
|
|
|
|
7
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional Volumes at December 31, 2009
|
|
|
|
Derivative
|
|
|
Derivative
|
|
|
Net
|
|
|
|
Contract
|
|
|
Contract
|
|
|
Derivative
|
|
Derivative Instrument
|
|
Assets
|
|
|
Liabilities
|
|
|
Contracts
|
|
|
|
(in millions)
|
|
|
Commodity Contracts (in equivalent MWh):
|
|
|
|
|
|
|
|
|
|
|
|
|
Power(1)
|
|
|
(82
|
)
|
|
|
38
|
|
|
|
(44
|
)
|
Natural gas
|
|
|
(32
|
)
|
|
|
32
|
|
|
|
|
|
Fuel oil
|
|
|
3
|
|
|
|
(4
|
)
|
|
|
(1
|
)
|
Coal
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
(1) |
|
Includes MWh equivalent of natural gas transactions used to
hedge power economically. |
F-25
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
GenOn
Mid-Atlantic
The following table presents the fair value of GenOn
Mid-Atlantics derivative financial instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Derivative
|
|
|
|
Derivative Contract Assets
|
|
|
Derivative Contract Liabilities
|
|
|
Contract
|
|
|
|
Current
|
|
|
Long-Term
|
|
|
Current
|
|
|
Long-Term
|
|
|
Assets (Liabilities)
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset managementnonaffiliate
|
|
$
|
162
|
|
|
$
|
516
|
|
|
$
|
(18
|
)
|
|
$
|
|
|
|
$
|
660
|
|
Asset managementaffiliate
|
|
|
245
|
|
|
|
97
|
|
|
|
(231
|
)
|
|
|
(94
|
)
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
$
|
407
|
|
|
$
|
613
|
|
|
$
|
(249
|
)
|
|
$
|
(94
|
)
|
|
$
|
677
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset managementnonaffiliate
|
|
$
|
155
|
|
|
$
|
399
|
|
|
$
|
(4
|
)
|
|
$
|
(13
|
)
|
|
$
|
537
|
|
Asset managementaffiliate
|
|
|
464
|
|
|
|
127
|
|
|
|
(374
|
)
|
|
|
(84
|
)
|
|
|
133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
$
|
619
|
|
|
$
|
526
|
|
|
$
|
(378
|
)
|
|
$
|
(97
|
)
|
|
$
|
670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents the net gains (losses) for
derivative financial instruments recognized in income in the
consolidated statements of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
|
|
|
|
Cost of Fuel,
|
|
|
|
|
|
Cost of Fuel,
|
|
|
|
|
|
|
Electricity and
|
|
|
|
|
|
Electricity and
|
|
Derivatives Not Designated as Hedging Instrument
|
|
Revenues
|
|
|
Other Products
|
|
|
Revenues
|
|
|
Other Products
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Asset Management Commodity Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
|
|
$
|
80
|
|
|
$
|
(73
|
)
|
|
$
|
136
|
|
|
$
|
8
|
|
Realized(1)
|
|
|
300
|
|
|
|
(128
|
)
|
|
|
644
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total asset management
|
|
$
|
380
|
|
|
$
|
(201
|
)
|
|
$
|
780
|
|
|
$
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents the total cash settlements of derivative financial
instruments during each quarterly reporting period that existed
at the beginning of each respective period. |
The following tables present the notional quantity on long
(short) positions for derivative financial instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional Volumes at December 31, 2010
|
|
|
Derivative
|
|
Derivative
|
|
Net
|
|
|
Contract
|
|
Contract
|
|
Derivative
|
Derivative Instrument
|
|
Assets
|
|
Liabilities
|
|
Contracts
|
|
|
(in millions)
|
|
Commodity Contracts (in equivalent MWh):
|
|
|
|
|
|
|
|
|
|
|
|
|
Power(1)
|
|
|
(40
|
)
|
|
|
4
|
|
|
|
(36
|
)
|
Coal
|
|
|
6
|
|
|
|
10
|
|
|
|
16
|
|
F-26
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional Volumes at December 31, 2009
|
|
|
Derivative
|
|
Derivative
|
|
Net
|
|
|
Contract
|
|
Contract
|
|
Derivative
|
Derivative Instrument
|
|
Assets
|
|
Liabilities
|
|
Contracts
|
|
|
(in millions)
|
|
Commodity Contracts (in equivalent MWh):
|
|
|
|
|
|
|
|
|
|
|
|
|
Power(1)
|
|
|
(79
|
)
|
|
|
34
|
|
|
|
(45
|
)
|
Coal
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
|
|
|
(1) |
|
Includes MWh equivalent of natural gas transactions used to
hedge power economically. |
|
|
(b)
|
Fair
Value Measurements.
|
Fair Value Hierarchy and Valuation
Techniques. The Companies apply recurring fair
value measurements to their financial assets and liabilities. In
determining fair value, the Companies 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 the Companies 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 Companies financial assets and
liabilities carried at fair value in the consolidated financial
statements are classified as follows:
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. The
Companies interest bearing funds 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.
Level 3: This category includes the
Companies energy 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 Companies 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, congestion products,
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. The Companies 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.
The fair value of the Companies derivative contract assets
and liabilities is based largely on observable quoted prices
from exchanges and unadjusted indicative quoted prices from
independent brokers in active markets who regularly facilitate
the Companies transactions. An active market is considered
to have transactions with sufficient frequency and volume to
provide pricing information on an ongoing basis. The Companies
think that these prices represent the best available information
for valuation purposes. In
F-27
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
determining the fair value of its derivative contract assets and
liabilities, the Companies use third-party market pricing where
available. For transactions classified in Level 1 of the
fair value hierarchy, the Companies use the unadjusted published
settled prices on the valuation date. For transactions
classified in Level 2 of the fair value hierarchy, the
Companies 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 the Companies 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 that the Companies 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. The
Companies typically obtain multiple broker quotes on the
valuation date for each delivery location that extend for the
tenor of their underlying contracts. The number of quotes that
the Companies can obtain depends on the relative liquidity of
the delivery location on the valuation date. If multiple broker
quotes are received for a contract, the Companies 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, the Companies will assign the
quote to a lower level within the fair value hierarchy. In some
instances, the Companies 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. The Companies also may apply interpolation techniques
to value monthly strips if broker quotes are only available on a
seasonal or annual basis. The Companies perform validation
procedures on the broker quotes at least on a monthly basis. The
validation procedures include reviewing the quotes for accuracy
and comparing them to the Companies internal price curves.
In certain instances, the Companies may discard a broker quote
if it is a clear outlier and multiple other quotes are obtained.
At December 31, 2010, the Companies obtained broker quotes
for 100% of their 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. The Companies 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 tenor of
the contract or the Companies are only able to obtain indicative
broker quotes that cannot be corroborated by observable market
data. In such cases, the Companies may apply valuation
techniques such as extrapolation and other quantitative methods
to determine fair value. Proprietary models may also be used to
determine the fair value of the Companies derivative
contract assets and liabilities that may be structured or
otherwise tailored. The Companies techniques for fair
value estimation include assumptions for market prices,
correlation and volatility. The degree of estimation increases
for longer duration contracts, contracts with multiple pricing
features, option contracts and off-hub delivery points. At
December 31, 2010, GenOn Americas Generations assets
and liabilities classified as Level 3 in the fair value
hierarchy represented approximately 2% of its total assets and
8% of its total liabilities measured at fair value. At
December 31, 2010, GenOn Mid-Atlantics assets and
liabilities classified as Level 3 in the fair value
hierarchy represented approximately 3% of its total assets and
29% of its total liabilities measured at fair value.
The fair value of the Companies derivative contract assets
and liabilities is also affected by assumptions as to time
value, credit risk and non-performance risk. The nominal value
of the Companies 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 to the Companies. The
counterparty default risk for the Companies overall net
position is measured based on published spreads on credit
default swaps for its counterparties, where available, or
proxies based upon published spreads, applied to its current
exposure and potential loss exposure from the
F-28
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
financial commitments in the Companies risk management
portfolio. The fair value of the Companies derivative
contract liabilities is reduced to reflect the estimated risk of
default on its contractual obligations to counterparties and is
measured based on published default rates of the Companies
debt, where available, or proxies based upon published spreads.
Credit risk and non-performance risk are calculated with
consideration of the Companies master netting agreements
with counterparties and their exposure is reduced by cash
collateral posted to the Companies against these obligations.
See note 3 for discussion of GenOn Americas
Generations and GenOn Mid-Atlantics fair value
measurements for non-financial assets.
GenOn
Americas Generation
Fair Value of Derivative Instruments and Certain Other
Assets. The fair value measurements of GenOn
Americas Generations financial assets and liabilities by
class are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Level
1(1)
|
|
|
Level
2(1)(2)
|
|
|
Level 3
|
|
|
Fair Value
|
|
|
|
(in millions)
|
|
|
Derivative contract assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Management:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
$
|
1
|
|
|
$
|
1,022
|
|
|
$
|
2
|
|
|
$
|
1,025
|
|
Fuel
|
|
|
4
|
|
|
|
3
|
|
|
|
33
|
|
|
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Asset Management
|
|
|
5
|
|
|
|
1,025
|
|
|
|
35
|
|
|
|
1,065
|
|
Trading Activities
|
|
|
530
|
|
|
|
385
|
|
|
|
5
|
|
|
|
920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative contract assets
|
|
$
|
535
|
|
|
$
|
1,410
|
|
|
$
|
40
|
|
|
$
|
1,985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contract liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Management:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
$
|
12
|
|
|
$
|
248
|
|
|
$
|
4
|
|
|
$
|
264
|
|
Fuel
|
|
|
18
|
|
|
|
|
|
|
|
99
|
|
|
|
117
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Asset Management
|
|
|
30
|
|
|
|
248
|
|
|
|
103
|
|
|
|
381
|
|
Trading Activities
|
|
|
533
|
|
|
|
389
|
|
|
|
3
|
|
|
|
925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative contract liabilities
|
|
$
|
563
|
|
|
$
|
637
|
|
|
$
|
106
|
|
|
$
|
1,306
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest-bearing
funds(3)
|
|
$
|
547
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
547
|
|
|
|
|
(1) |
|
Transfers between Level 1 and Level 2 are recognized
as of the end of the reporting period. There were no significant
transfers during 2010. |
|
(2) |
|
Option contracts comprised approximately 1% of GenOn Americas
Generations net derivative contract assets. |
|
(3) |
|
Represent investments in money market funds and are included in
cash and cash equivalents, funds on deposit and other noncurrent
assets in the consolidated balance sheet. GenOn Americas
Generation had $508 million of interest-bearing funds
included in cash and cash equivalents, $2 million included
in funds on deposit and $37 million included in other
noncurrent assets. |
F-29
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Fair Value
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Derivative contract assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Management:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
$
|
2
|
|
|
$
|
1,162
|
|
|
$
|
14
|
|
|
$
|
1,178
|
|
Fuel
|
|
|
11
|
|
|
|
8
|
|
|
|
7
|
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Asset Management
|
|
|
13
|
|
|
|
1,170
|
|
|
|
21
|
|
|
|
1,204
|
|
Trading Activities
|
|
|
374
|
|
|
|
415
|
|
|
|
22
|
|
|
|
811
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative contract assets
|
|
$
|
387
|
|
|
$
|
1,585
|
|
|
$
|
43
|
|
|
$
|
2,015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contract liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Management:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
$
|
11
|
|
|
$
|
475
|
|
|
$
|
2
|
|
|
$
|
488
|
|
Fuel
|
|
|
14
|
|
|
|
1
|
|
|
|
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Asset Management
|
|
|
25
|
|
|
|
476
|
|
|
|
2
|
|
|
|
503
|
|
Trading Activities
|
|
|
368
|
|
|
|
433
|
|
|
|
9
|
|
|
|
810
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative contract liabilities
|
|
$
|
393
|
|
|
$
|
909
|
|
|
$
|
11
|
|
|
$
|
1,313
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest-bearing
funds(1)
|
|
$
|
564
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
564
|
|
|
|
|
(1) |
|
Represent investments in money market funds and are included in
cash and cash equivalents, funds on deposit and other noncurrent
assets in the consolidated balance sheet. GenOn Americas
Generation had $400 million of interest-bearing funds
included in cash and cash equivalents, $137 million
included in funds on deposit and $27 million included in
other noncurrent assets. |
F-30
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following is a reconciliation of changes in fair value of
net commodity derivative contract assets and liabilities
classified as Level 3 during 2009 and 2010, respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Derivatives Contracts (Level 3)
|
|
|
|
Asset
|
|
|
|
|
|
|
|
|
|
Management
|
|
|
Trading
|
|
|
Total
|
|
|
|
(in millions)
|
|
|
Balance, January 1, 2009 (net asset (liability))
|
|
$
|
24
|
|
|
$
|
22
|
|
|
$
|
46
|
|
Total gains (losses) realized/unrealized:
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in
earnings(1)
|
|
|
(58
|
)
|
|
|
(62
|
)
|
|
|
(120
|
)
|
Purchases, issuances and settlements
(net)(2)
|
|
|
54
|
|
|
|
53
|
|
|
|
107
|
|
Transfers in and out of
Level 3(3)
|
|
|
(1
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009 (net asset (liability))
|
|
|
19
|
|
|
|
13
|
|
|
|
32
|
|
Total gains (losses) realized/unrealized:
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in
earnings(1)
|
|
|
17
|
|
|
|
(49
|
)
|
|
|
(32
|
)
|
Purchases, issuances and settlements
(net)(2)
|
|
|
(142
|
)
|
|
|
39
|
|
|
|
(103
|
)
|
Transfers in and out of
Level 3(3)
|
|
|
38
|
|
|
|
(1
|
)
|
|
|
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2010 (net asset (liability))
|
|
$
|
(68
|
)
|
|
$
|
2
|
|
|
$
|
(66
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Reflects the total gains or losses on contracts included in
Level 3 at the beginning of each quarterly reporting period
and at the end of each quarterly reporting period, and contracts
entered into during each quarterly reporting period that remain
at the end of each quarterly reporting period. Also reflects
GenOn Americas Generations coal agreements that were
initially recognized at fair value in the second quarter of 2010. |
|
(2) |
|
Represents the total cash settlements of contracts during each
quarterly reporting period that existed at the beginning of each
quarterly reporting period. |
|
(3) |
|
Denotes the total contracts that existed at the beginning of
each quarterly reporting period and were still held at the end
of each quarterly 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 quarterly
reporting period. Amounts reflect fair value as of the end of
each quarterly reporting period. |
The following table presents the amounts included in income
related to derivative contract assets and liabilities classified
as Level 3:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
2009
|
|
|
|
|
Cost of Fuel,
|
|
|
|
|
|
Cost of Fuel,
|
|
|
|
|
|
|
Electricity
|
|
|
|
|
|
Electricity
|
|
|
|
|
Operating
|
|
and Other
|
|
|
|
Operating
|
|
and Other
|
|
|
|
|
Revenues
|
|
Products
|
|
Total
|
|
Revenues
|
|
Products
|
|
Total
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Gains (losses) included in income
|
|
$
|
(24
|
)
|
|
$
|
(74
|
)
|
|
$
|
(98
|
)
|
|
$
|
(22
|
)
|
|
$
|
8
|
|
|
$
|
(14
|
)
|
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 December 31
|
|
$
|
(1
|
)
|
|
$
|
(67
|
)
|
|
$
|
(68
|
)
|
|
$
|
7
|
|
|
$
|
7
|
|
|
$
|
14
|
|
F-31
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
GenOn
Mid-Atlantic
Fair Value of Derivative Instruments and Certain Other
Assets. The fair value measurements of GenOn
Mid-Atlantics financial assets and liabilities by class
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Level
1(1)
|
|
|
Level
2(1)(2)
|
|
|
Level 3
|
|
|
Fair Value
|
|
|
|
(in millions)
|
|
|
Derivative contract assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Management:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
$
|
1
|
|
|
$
|
986
|
|
|
$
|
|
|
|
$
|
987
|
|
Fuel
|
|
|
|
|
|
|
2
|
|
|
|
31
|
|
|
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative contract assets
|
|
$
|
1
|
|
|
$
|
988
|
|
|
$
|
31
|
|
|
$
|
1,020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contract liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Management:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
$
|
12
|
|
|
$
|
231
|
|
|
$
|
1
|
|
|
$
|
244
|
|
Fuel
|
|
|
|
|
|
|
|
|
|
|
99
|
|
|
|
99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative contract liabilities
|
|
$
|
12
|
|
|
$
|
231
|
|
|
$
|
100
|
|
|
$
|
343
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest-bearing
funds(3)
|
|
$
|
234
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
234
|
|
|
|
|
(1) |
|
Transfers between Level 1 and Level 2 are recognized
as of the end of the reporting period. There were no significant
transfers during 2010. |
|
(2) |
|
Option contracts comprised less than 1% of GenOn
Mid-Atlantics net derivative contract assets. |
|
(3) |
|
Represent investments in money market funds and are included in
cash and cash equivalents, funds on deposit and other noncurrent
assets in the consolidated balance sheet. GenOn Mid-Atlantic had
$202 million of interest-bearing funds included in cash and
cash equivalents, $2 million included in funds on deposit
and $30 million included in other noncurrent assets. |
F-32
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Fair Value
|
|
|
|
(in millions)
|
|
|
Derivative contract assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Management:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
$
|
2
|
|
|
$
|
1,130
|
|
|
$
|
6
|
|
|
$
|
1,138
|
|
Fuel
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative contract assets
|
|
$
|
2
|
|
|
$
|
1,130
|
|
|
$
|
13
|
|
|
$
|
1,145
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contract liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Management:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
$
|
11
|
|
|
$
|
463
|
|
|
$
|
|
|
|
$
|
474
|
|
Fuel
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative contract liabilities
|
|
$
|
11
|
|
|
$
|
464
|
|
|
$
|
|
|
|
$
|
475
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest-bearing
funds(1)
|
|
$
|
158
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
158
|
|
|
|
|
(1) |
|
Represent investments in money market funds and are included in
cash and cash equivalents, funds on deposit and other noncurrent
assets in the consolidated balance sheet. GenOn Americas
Generation had $125 million of interest-bearing funds
included in cash and cash equivalents, $14 million included
in funds on deposit and $19 million included in other
noncurrent assets. |
The following is a reconciliation of changes in fair value of
net commodity derivative contract assets and liabilities
classified as Level 3 during 2009 and 2010, respectively:
|
|
|
|
|
|
|
Asset
|
|
|
|
Management
|
|
|
|
(in millions)
|
|
|
Balance, January 1, 2009 (net asset (liability))
|
|
$
|
|
|
Total gains (losses) realized/unrealized:
|
|
|
|
|
Included in
earnings(1)
|
|
|
10
|
|
Purchases, issuances and settlements
(net)(2)
|
|
|
4
|
|
Transfers in and out of
Level 3(3)
|
|
|
(1
|
)
|
|
|
|
|
|
Balance, December 31, 2009 (net asset (liability))
|
|
|
13
|
|
Total gains (losses) realized/unrealized:
|
|
|
|
|
Included in
earnings(1)
|
|
|
6
|
|
Purchases, issuances and settlements
(net)(2)
|
|
|
(126
|
)
|
Transfers in and out of
Level 3(3)
|
|
|
38
|
|
|
|
|
|
|
Balance, December 31, 2010 (net asset (liability))
|
|
$
|
(69
|
)
|
|
|
|
|
|
|
|
|
(1) |
|
Reflects the total gains or losses on contracts included in
Level 3 at the beginning of each quarterly reporting period
and at the end of each quarterly reporting period, and contracts
entered into during each |
F-33
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
quarterly reporting period that remain at the end of each
quarterly reporting period. Also reflects GenOn
Mid-Atlantics coal agreements that were initially
recognized at fair value in the second quarter of 2010. |
|
(2) |
|
Represents the total cash settlements of contracts during each
quarterly reporting period that existed at the beginning of each
quarterly reporting period. |
|
(3) |
|
Denotes the total contracts that existed at the beginning of
each quarterly reporting period and were still held at the end
of each quarterly 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 quarterly
reporting period. Amounts reflect fair value as of the end of
each quarterly reporting period. |
The following table presents the amounts included in income
related to derivative contract assets and liabilities classified
as Level 3:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
|
|
|
|
Cost of
|
|
|
|
|
|
|
|
|
Cost of
|
|
|
|
|
|
|
|
|
|
Fuel,
|
|
|
|
|
|
|
|
|
Fuel,
|
|
|
|
|
|
|
|
|
|
Electricity
|
|
|
|
|
|
|
|
|
Electricity
|
|
|
|
|
|
|
Operating
|
|
|
and Other
|
|
|
|
|
|
Operating
|
|
|
and Other
|
|
|
|
|
|
|
Revenues
|
|
|
Products
|
|
|
Total
|
|
|
Revenues
|
|
|
Products
|
|
|
Total
|
|
|
|
(in millions)
|
|
|
Gains (losses) included in income
|
|
$
|
(7
|
)
|
|
$
|
(75
|
)
|
|
$
|
(82
|
)
|
|
$
|
6
|
|
|
$
|
7
|
|
|
$
|
13
|
|
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 December 31
|
|
$
|
(7
|
)
|
|
$
|
(68
|
)
|
|
$
|
(75
|
)
|
|
$
|
6
|
|
|
$
|
7
|
|
|
$
|
13
|
|
|
|
(c)
|
Counterparty
Credit Concentration Risk.
|
The Companies are exposed to the default risk of the
counterparties with which the Companies transact. The Companies
manage their 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. The Companies 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 or for securing exposure as a result of changes in power
or natural gas prices. The Companies credit reserve on
their derivative contract assets was $19 million and
$13 million at December 31, 2010 and 2009,
respectively.
At December 31, 2010 and 2009, approximately
$3 million and $12 million, respectively, of cash
collateral posted to GenOn Americas Generation by counterparties
under master netting agreements was included in accounts payable
and accrued liabilities on GenOn Americas Generations
consolidated balance sheets.
F-34
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Companies also 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:
GenOn
Americas Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
Exposure
|
|
|
Exposure
|
|
|
|
|
|
Exposure
|
|
|
%
|
|
|
|
Before
|
|
|
Before
|
|
|
|
|
|
Net of
|
|
|
of Net
|
|
Credit Rating Equivalent
|
|
Collateral(1)
|
|
|
Collateral(2)
|
|
|
Collateral(3)
|
|
|
Collateral
|
|
|
Exposure
|
|
|
|
(dollars in millions)
|
|
|
Clearing and Exchange
|
|
$
|
987
|
|
|
$
|
39
|
|
|
$
|
39
|
|
|
$
|
|
|
|
|
|
|
Investment Grade:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial institutions
|
|
|
806
|
|
|
|
707
|
|
|
|
|
|
|
|
707
|
|
|
|
78
|
%
|
Energy companies
|
|
|
337
|
|
|
|
130
|
|
|
|
2
|
|
|
|
128
|
|
|
|
14
|
%
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-investment Grade:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial institutions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy companies
|
|
|
15
|
|
|
|
15
|
|
|
|
|
|
|
|
15
|
|
|
|
2
|
%
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
No External Ratings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Internally-rated investment grade
|
|
|
34
|
|
|
|
27
|
|
|
|
|
|
|
|
27
|
|
|
|
3
|
%
|
Internally-rated non-investment grade
|
|
|
26
|
|
|
|
26
|
|
|
|
|
|
|
|
26
|
|
|
|
3
|
%
|
Not internally rated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,205
|
|
|
$
|
944
|
|
|
$
|
41
|
|
|
$
|
903
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-35
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
Exposure
|
|
|
Exposure
|
|
|
|
|
|
Exposure
|
|
|
%
|
|
|
|
Before
|
|
|
Before
|
|
|
|
|
|
Net of
|
|
|
of Net
|
|
Credit Rating Equivalent
|
|
Collateral(1)
|
|
|
Collateral(2)
|
|
|
Collateral(3)
|
|
|
Collateral
|
|
|
Exposure
|
|
|
|
(dollars in millions)
|
|
|
Clearing and Exchange
|
|
$
|
790
|
|
|
$
|
96
|
|
|
$
|
96
|
|
|
$
|
|
|
|
|
|
|
Investment Grade:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial institutions
|
|
|
997
|
|
|
|
646
|
|
|
|
12
|
|
|
|
634
|
|
|
|
81
|
%
|
Energy companies
|
|
|
497
|
|
|
|
125
|
|
|
|
13
|
|
|
|
112
|
|
|
|
14
|
%
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-investment Grade:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial institutions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy companies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
No External Ratings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Internally-rated investment grade
|
|
|
34
|
|
|
|
27
|
|
|
|
|
|
|
|
27
|
|
|
|
4
|
%
|
Internally-rated non-investment grade
|
|
|
8
|
|
|
|
8
|
|
|
|
|
|
|
|
8
|
|
|
|
1
|
%
|
Not internally rated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,326
|
|
|
$
|
902
|
|
|
$
|
121
|
|
|
$
|
781
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gross exposure before collateral represents credit exposure,
including 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
the 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. |
|
(3) |
|
Collateral includes cash and letters of credit received from
counterparties. |
F-36
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
GenOn
Mid-Atlantic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
Exposure
|
|
|
Exposure
|
|
|
|
|
|
Exposure
|
|
|
%
|
|
|
|
Before
|
|
|
Before
|
|
|
|
|
|
Net of
|
|
|
of Net
|
|
Credit Rating Equivalent
|
|
Collateral(1),(4)
|
|
|
Collateral(2)
|
|
|
Collateral(3)
|
|
|
Collateral
|
|
|
Exposure
|
|
|
|
|
|
|
(dollars in millions)
|
|
|
|
|
|
|
|
|
Clearing and Exchange
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
Investment Grade:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial institutions
|
|
|
714
|
|
|
|
695
|
|
|
|
|
|
|
|
695
|
|
|
|
95
|
%
|
Energy companies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-investment Grade:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial institutions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy companies
|
|
|
13
|
|
|
|
13
|
|
|
|
|
|
|
|
13
|
|
|
|
2
|
%
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
No External Ratings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Internally-rated investment grade
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Internally-rated non-investment grade
|
|
|
25
|
|
|
|
25
|
|
|
|
|
|
|
|
25
|
|
|
|
3
|
%
|
Not internally rated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
752
|
|
|
$
|
733
|
|
|
$
|
|
|
|
$
|
733
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
Exposure
|
|
|
Exposure
|
|
|
|
|
|
Exposure
|
|
|
|
|
|
|
Before
|
|
|
Before
|
|
|
|
|
|
Net of
|
|
|
% of Net
|
|
Credit Rating Equivalent
|
|
Collateral(1),(4)
|
|
|
Collateral(2)
|
|
|
Collateral(3)
|
|
|
Collateral
|
|
|
Exposure
|
|
|
|
(dollars in millions)
|
|
|
Clearing and Exchange
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
Investment Grade:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial institutions
|
|
|
595
|
|
|
|
578
|
|
|
|
|
|
|
|
578
|
|
|
|
99
|
%
|
Energy companies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-investment Grade:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial institutions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy companies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
No External Ratings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Internally-rated investment grade
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Internally-rated non-investment grade
|
|
|
8
|
|
|
|
8
|
|
|
|
|
|
|
|
8
|
|
|
|
1
|
%
|
Not internally rated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
603
|
|
|
$
|
586
|
|
|
$
|
|
|
|
$
|
586
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-37
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(1) |
|
Gross exposure before collateral represents credit exposure,
including 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
the 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. |
|
(3) |
|
Collateral includes cash and letters of credit received from
counterparties. |
|
(4) |
|
Amounts do not include exposures with affiliates or exposures
incurred by GenOn Mid-Atlantic in connection with transactions
entered into with external counterparties by affiliates on its
behalf, with the exception of coal purchases. |
GenOn Americas Generation had credit exposure to two investment
grade counterparties at December 31, 2010 and credit
exposure to three investment grade counterparties at
December 31, 2009, each representing an exposure of more
than 10% of total credit exposure, net of collateral and
totaling $568 million and $495 million at
December 31, 2010 and 2009, respectively.
GenOn Mid-Atlantic had credit exposure to three investment grade
counterparties each representing an exposure of more than 10% of
total credit exposure, net of collateral and totaling
$653 million and $481 million at December 31,
2010 and 2009, respectively.
|
|
(d)
|
GenOn
Americas Generation and GenOn Mid-Atlantic Credit
Risk.
|
The Companies standard industry contracts contain
credit-risk-related contingent features such as ratings-related
thresholds whereby the Companies 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 the
Companies contracts contain adequate assurance language,
which is generally subjective in nature, but would most likely
require the Companies to post additional cash collateral or
letters of credit as a result of a credit event, including a
downgrade. However, as a result of the Companies current
credit ratings, the Companies are typically required to post
collateral in the normal course of business to offset either
substantially or completely their net liability positions, after
applying the terms of master netting agreements. At
December 31, 2010, the fair value of GenOn Americas
Generations financial instruments with credit-risk-related
contingent features in a net liability position was
$10 million for which GenOn Americas Generation posted
collateral of $7 million, including cash and letters of
credit. At December 31, 2010, GenOn Mid-Atlantic did not
have any financial instruments with credit-risk-related
contingent features in a net liability position.
In addition, at December 31, 2010 and 2009, GenOn Americas
Generation had $1 million and $25 million,
respectively, of cash collateral posted with counterparties
under master netting agreements that was included in funds on
deposit on the consolidated balance sheets.
|
|
(e)
|
Fair
Values of Other Financial Instruments (GenOn Americas
Generation).
|
The fair values of certain funds on deposit, accounts receivable
and accounts payable and accrued liabilities approximate their
carrying amounts.
F-38
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The carrying amounts and fair values of GenOn Americas
Generations financial instruments are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
Carrying
|
|
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
|
Amount
|
|
|
Fair Value
|
|
|
Amount
|
|
|
Value
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long and short-term
debt(1)
|
|
$
|
2,255
|
|
|
$
|
2,272
|
|
|
$
|
2,630
|
|
|
$
|
2,558
|
|
|
|
|
(1) |
|
The fair value of GenOn Americas Generations long- and
short-term debt is estimated using quoted market prices, when
available. |
|
|
(a)
|
Property,
Plant and Equipment, Net.
|
Property, plant and equipment, net consisted of the following:
GenOn
Americas Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
Depreciable
|
|
|
|
2010
|
|
|
2009
|
|
|
Lives
(years)(1)
|
|
|
|
(in millions)
|
|
|
|
|
|
Production
|
|
$
|
2,695
|
|
|
$
|
2,688
|
|
|
|
11 to 54
|
|
Leasehold improvements on leased generating facilities
|
|
|
1,056
|
|
|
|
1,329
|
|
|
|
5 to 34
|
|
Construction work in progress
|
|
|
65
|
|
|
|
216
|
|
|
|
|
|
Other
|
|
|
129
|
|
|
|
130
|
|
|
|
2 to 12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
3,945
|
|
|
|
4,363
|
|
|
|
|
|
Accumulated depreciation and amortization
|
|
|
(868
|
)
|
|
|
(757
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment, net
|
|
$
|
3,077
|
|
|
$
|
3,606
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
GenOn Americas Generation completed a depreciation study in the
first quarter of 2010 for the generating facilities that
resulted in a change to the estimated useful lives of its
long-lived assets. The change in useful lives resulted in an
increase of approximately $2 million in depreciation and
amortization expense during 2010. |
F-39
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
GenOn
Mid-Atlantic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciable
|
|
|
|
December 31,
|
|
|
Lives
|
|
|
|
2010
|
|
|
2009
|
|
|
(years)(1)
|
|
|
|
(in millions)
|
|
|
|
|
|
Production
|
|
$
|
1,885
|
|
|
$
|
1,871
|
|
|
|
11 to 54
|
|
Leasehold improvements on leased generating facilities
|
|
|
1,056
|
|
|
|
1,329
|
|
|
|
5 to 34
|
|
Construction work in progress
|
|
|
56
|
|
|
|
203
|
|
|
|
|
|
Other
|
|
|
49
|
|
|
|
50
|
|
|
|
2 to 10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
3,046
|
|
|
|
3,453
|
|
|
|
|
|
Accumulated depreciation and amortization
|
|
|
(513
|
)
|
|
|
(453
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment, net
|
|
$
|
2,533
|
|
|
$
|
3,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
GenOn Mid-Atlantic completed a depreciation study in the first
quarter of 2010 for the generating facilities that resulted in a
change to the estimated useful lives of its long-lived assets.
The change in useful lives resulted in a decrease of
approximately $3 million in depreciation and amortization
expense during 2010. |
Depreciation of the recorded cost of property, plant and
equipment is recognized on a straight-line basis over the
estimated useful lives of the assets. Emissions allowances
purchased in acquisitions prior to the Merger related to owned
facilities are included in production assets above, and are
depreciated on a straight-line basis over the average life of
the related generating facilities.
Depreciation expense was as follows:
GenOn
Americas Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
(in millions)
|
|
Depreciation expense
|
|
$
|
190
|
|
|
$
|
134
|
|
|
$
|
128
|
|
GenOn
Mid-Atlantic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
(in millions)
|
|
Depreciation expense
|
|
$
|
135
|
|
|
$
|
92
|
|
|
$
|
86
|
|
F-40
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(b)
|
Intangible
Assets, Net.
|
GenOn
Americas Generation
The following is a summary of intangible assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
December 31, 2009
|
|
|
|
Weighted Average
|
|
|
Gross Carrying
|
|
|
Accumulated
|
|
|
Gross Carrying
|
|
|
Accumulated
|
|
|
|
Amortization Lives
|
|
|
Amount
|
|
|
Amortization
|
|
|
Amount
|
|
|
Amortization
|
|
|
|
(in millions)
|
|
|
Trading rights
|
|
|
16 years
|
|
|
$
|
15
|
|
|
$
|
(6
|
)
|
|
$
|
15
|
|
|
$
|
(4
|
)
|
Development rights
|
|
|
33 years
|
|
|
|
13
|
|
|
|
(2
|
)
|
|
|
54
|
|
|
|
(12
|
)
|
Emissions allowances
|
|
|
32 years
|
|
|
|
107
|
|
|
|
(28
|
)
|
|
|
149
|
|
|
|
(39
|
)
|
Other intangibles
|
|
|
23 years
|
|
|
|
4
|
|
|
|
(2
|
)
|
|
|
12
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total intangible assets
|
|
|
|
|
|
$
|
139
|
|
|
$
|
(38
|
)
|
|
$
|
230
|
|
|
$
|
(59
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GenOn
Mid-Atlantic
The following is a summary of intangible assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
December 31, 2009
|
|
|
|
Weighted Average
|
|
|
Gross Carrying
|
|
|
Accumulated
|
|
|
Gross Carrying
|
|
|
Accumulated
|
|
|
|
Amortization Lives
|
|
|
Amount
|
|
|
Amortization
|
|
|
Amount
|
|
|
Amortization
|
|
|
|
(in millions)
|
|
|
Development rights
|
|
|
30 years
|
|
|
$
|
6
|
|
|
$
|
|
|
|
$
|
47
|
|
|
$
|
(11
|
)
|
Emissions allowances
|
|
|
34 years
|
|
|
|
89
|
|
|
|
(26
|
)
|
|
|
131
|
|
|
|
(37
|
)
|
Other intangibles
|
|
|
23 years
|
|
|
|
4
|
|
|
|
(2
|
)
|
|
|
12
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total intangible assets
|
|
|
|
|
|
$
|
99
|
|
|
$
|
(28
|
)
|
|
$
|
190
|
|
|
$
|
(52
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trading rights are intangible assets recognized in connection
with asset purchases that represent GenOn Americas
Generations ability to generate additional cash flows by
incorporating GenOn Americas Generations trading
activities with the acquired generating facilities. See below
for information on the 2009 impairment of the trading rights
related to the Potrero and Contra Costa generating facilities.
Development rights represent the right to expand capacity at
certain acquired generating facilities. The existing
infrastructure, including storage facilities, transmission
interconnections and fuel delivery systems and contractual
rights acquired by the Companies, provide the opportunity to
expand or repower certain generating facilities. See below for
information on the 2010 impairment of the development rights
related to the Dickerson generating facility and the 2009
impairment of the development rights related to the Potrero
generating facility.
Emissions allowances primarily represent allowances granted for
the leasehold baseload units at the Dickerson and Morgantown
generating facilities. See below for information on the 2010
impairment of emissions allowances related to the Dickerson
generating facility.
GenOn
Americas Generation
Amortization expense was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
(in millions)
|
|
Amortization expense
|
|
$
|
9
|
|
|
$
|
8
|
|
|
$
|
8
|
|
F-41
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
GenOn
Mid-Atlantic
Amortization expense was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
Amortization expense
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
6
|
|
GenOn
Americas Generation
Assuming no future acquisitions, dispositions or impairments of
intangible assets, amortization expense is estimated to be
approximately the following for each of the next five years (in
millions):
|
|
|
|
|
2011
|
|
$
|
6
|
|
2012
|
|
|
6
|
|
2013
|
|
|
6
|
|
2014
|
|
|
6
|
|
2015
|
|
|
4
|
|
GenOn
Mid-Atlantic
Assuming no future acquisitions, dispositions or impairments of
intangible assets, amortization expense is estimated to be
approximately the following for each of the next five years (in
millions):
|
|
|
|
|
2011
|
|
$
|
3
|
|
2012
|
|
|
3
|
|
2013
|
|
|
3
|
|
2014
|
|
|
3
|
|
2015
|
|
|
3
|
|
|
|
(c)
|
Goodwill,
Net (GenOn Mid-Atlantic).
|
GenOn Mid-Atlantic evaluates its goodwill for impairment at
least annually and periodically if indicators of impairment are
present in accordance with the accounting guidance related to
goodwill and other intangible assets. The results of GenOn
Mid-Atlantics impairment testing may be affected by a
significant adverse change in the extent or manner in which a
reporting units assets are being used, a significant
adverse change in legal factors or in the business climate that
could affect the value of a reporting unit, as well as other
economic or operational analyses. If the carrying amount of the
reporting unit is not recoverable, an impairment charge is
recorded. The amount of the impairment charge, if impairment
exists, is calculated as the difference between the fair value
of the reporting unit goodwill and its carrying value. For this
test, GenOn Mid-Atlantics business constitutes a single
reporting unit. GenOn Mid-Atlantic performs its annual
assessment of goodwill at October 31 and whenever contrary
evidence exists as to the recoverability of goodwill.
GenOn Mid-Atlantic performed its annual test for goodwill
impairment effective October 31, 2010 and 2009, based upon
GenOn Mid-Atlantics most recent business plan and market
data from independent sources available at the respective
testing dates. GenOn Mid-Atlantic utilized multiple valuation
approaches in arriving at a fair value of GenOn
Mid-Atlantics reporting unit for purposes of the test,
including an income approach involving discounted cash flows and
a market approach involving trading multiples of peer companies.
The transaction method was not utilized in either year because
there were no comparable recent transactions, specifically no
transactions for baseload coal-fired generating facilities in
the PJM market. In addition to the market approaches listed
above, GenOn Mid-Atlantic also performed a reconciliation of the
fair value of the
F-42
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Mid-Atlantic reporting unit to the market capitalization of
Mirant on the testing dates, adjusted for a control premium, as
a reasonableness check for the valuation approaches. The
reconciliations resulted in values that were consistent with the
other approaches. For 2010 and 2009, GenOn Mid-Atlantic assigned
a 50% weighting to the income approach and a 50% weighting to
the market approach to determine the fair value of the reporting
unit. However, a change in the relative weightings between the
income and market approach would have an immaterial effect on
the outcome of the goodwill impairment analyses. The annual
evaluations of goodwill for 2010 and 2009 indicated that the
carrying value of the reporting unit exceeded the fair value,
requiring the second step of the goodwill analysis to be
performed.
GenOn Mid-Atlantic then performed the second step of the
goodwill impairment test, which requires an allocation of the
fair value as the purchase price in a hypothetical acquisition
of the reporting unit. The fair value of the reporting unit was
compared to the fair value of the tangible and intangible assets
and the remaining value was the implied goodwill. For 2010, as a
result of this analysis, GenOn Mid-Atlantic recorded an
impairment loss of $616 million on its consolidated
statement of operations to reduce the carrying value of goodwill
to its implied fair value, which was zero. For 2009, GenOn
Mid-Atlantic recorded an impairment loss of $183 million on
its consolidated statement of operations to reduce the carrying
value of goodwill to its implied fair value.
GenOn Mid-Atlantics assessment of goodwill for 2010 and
2009 included assumptions about the following:
|
|
|
|
|
electricity, fuel and emissions prices;
|
|
|
|
capacity payments under the RPM provisions of PJMs tariff;
|
|
|
|
costs related to the Montgomery County
CO2
emissions levy (Dickerson generating facility);
|
|
|
|
costs of
CO2
allowances under a potential federal
cap-and-trade
program and other environmental regulations;
|
|
|
|
timing of announced transmission projects;
|
|
|
|
timing and extent of generating capacity additions and
retirements; and
|
|
|
|
future capital expenditure requirements related to the
generating facilities.
|
GenOn Mid-Atlantics assumptions related to future
electricity and fuel prices were based on observable market
prices to the extent available and long-term prices derived from
proprietary fundamental market modeling. GenOn
Mid-Atlantics long-term capacity prices were based on the
assumption that the PJM RPM capacity market would continue
consistent with the current structure. For the Dickerson
generating facility, the total
CO2
costs under the levy were determined by applying the cost of
CO2
emissions to the expected generation forecasts. GenOn
Mid-Atlantics estimate of future cash flows related to the
Dickerson generating facility involved considering scenarios
related to the Montgomery County levy. The scenarios are related
to the success of the legal challenges to the law. GenOn
Mid-Atlantic also assumed for all of its generating facilities
that a federal
CO2
cap-and-trade
program would be instituted later this decade which would
supplant all pre-existing
CO2
programs, including the Montgomery County levy. In addition, the
assumptions included costs associated with compliance of other
environmental regulations. There are several transmission
projects currently planned in the Mid-Atlantic region, including
the Trans-Allegheny Interstate Line (TrAIL), Mid-Atlantic Power
Pathway transmission line (MAPP) and the Potomac-Appalachian
transmission line (PATH). GenOn Mid-Atlantics assumptions
regarding the timing of these projects were based on the current
status of permitting and construction of each project. The
assumptions regarding electricity demand were based on forecasts
from PJM and assumptions for generating capacity additions and
retirements included publicly-announced projects, which take
into account renewable sources of electricity. Capital
expenditures include the
F-43
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
remaining contract retention payments for the completion of the
Maryland Healthy Air Act pollution control equipment for the
Maryland generating facilities. For the Potomac River generating
facility, the cash flows also include the remaining
$32 million that GenOn Potomac River committed to spend to
reduce particulate emissions as part of the agreement with the
City of Alexandria, Virginia. In addition, the assumptions
exclude general corporate overhead allocations, but include
overhead allocations from GenOn Energy Management under the
assumption that a market participant would utilize a trading
company to manage the procurement of fuel and the sale of
electricity. See note 9 for further details of the
Montgomery County
CO2
levy.
GenOn Mid-Atlantics estimates of future cash flows did not
include contracts entered into to hedge economically the
expected generation of Mid-Atlantic generating facilities. The
cash flows related to these contracts were excluded because they
were not directly attributable to the generating facilities.
The following summarizes the changes in the carrying amount of
goodwill during 2010, 2009 and 2008, respectively (in millions):
|
|
|
|
|
Balance, January 1, 2008
|
|
$
|
799
|
|
Impairment loss
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
799
|
|
Impairment loss
|
|
|
(183
|
)
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
616
|
|
Impairment loss
|
|
|
(616
|
)
|
|
|
|
|
|
Balance, December 31, 2010
|
|
$
|
|
|
|
|
|
|
|
The following tables set forth by level within the fair value
hierarchy GenOn Mid-Atlantics goodwill that was accounted
for at fair value on a non-recurring basis. GenOn
Mid-Atlantics goodwill that was measured at fair value as
a result of an impairment during the current period was
categorized in Level 3 at December 31, 2010 and 2009:
GenOn
Mid-Atlantic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value at December 31, 2010
|
|
|
|
|
|
|
Quoted Prices
|
|
|
Significant
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
in Active
|
|
|
Other
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Markets for
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
|
|
Loss
|
|
|
|
Identical Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
|
|
|
Included in
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Total
|
|
|
Earnings
|
|
|
|
(in millions)
|
|
|
GenOn Mid-Atlantic
goodwill(1)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
616
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
616
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value at December 31, 2009
|
|
|
|
|
|
|
Quoted Prices
|
|
|
Significant
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
in Active
|
|
|
Other
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Markets for
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
|
|
Loss
|
|
|
|
Identical Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
|
|
|
Included in
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Total
|
|
|
Earnings
|
|
|
|
(in millions)
|
|
|
GenOn Mid-Atlantic
goodwill(1)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
616
|
|
|
$
|
616
|
|
|
$
|
183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
|
|
|
$
|
616
|
|
|
$
|
616
|
|
|
$
|
183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-44
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(1) |
|
Goodwill is recorded at GenOn Mid-Atlantic on its standalone
balance sheet. The goodwill does not exist at GenOn Americas
Generations balance sheets. As such, the goodwill
impairment loss and related goodwill balance are eliminated upon
consolidation at GenOn North America. |
|
|
(d)
|
Impairments
on Assets Held and Used.
|
2010
GenOn
Mid-Atlantic Generating Facilities
Background
As described above, the Companies have goodwill recorded at the
GenOn Mid-Atlantic registrant on its standalone balance sheet,
which is eliminated upon consolidation at GenOn North America.
In accordance with accounting guidance for goodwill and other
intangible assets, the Companies are required to test the
goodwill balance at GenOn Mid-Atlantic at least annually. The
Companies performed the goodwill assessment at October 31,
2010, which, by policy, is the annual testing date. In
conducting step one of the goodwill impairment analysis for
GenOn Mid-Atlantic, the Companies noted that the carrying value
of its net assets exceeded the calculated fair value of GenOn
Mid-Atlantic, indicating that step two of the goodwill
impairment analysis was required. Based on the results of the
step one goodwill impairment analysis, the Companies tested
GenOn Mid-Atlantics long-lived assets for impairment under
the accounting guidance related to impairment of long-lived
assets before completion of the step two test for goodwill. Upon
completion of the assessment, the Companies determined that none
of the GenOn Mid-Atlantic generating facilities was impaired at
October 31, 2010.
In December 2010, PJM published an updated load forecast, which
depicted a decrease in the expected demand from price
projections because of lower economic growth expectations. As a
result of the load forecast, the Companies current
expectation is that there will be a decrease in the clearing
prices for future capacity auctions in certain years. The
decrease in projected capacity revenue caused the Companies to
update their October 2010 impairment review of GenOn
Mid-Atlantics long-lived assets. Upon completion of the
assessment, which was based on the accounting guidance related
to the impairment of long-lived assets, the Companies determined
that the Dickerson and Potomac River generating facilities were
impaired at December 31, 2010, as the carrying value
exceeded the updated December 2010 undiscounted cash flows. The
Companies determined that no other GenOn Mid-Atlantic long-lived
assets were impaired at December 31, 2010.
Asset
Grouping
For purposes of impairment testing, a long-lived asset or assets
must be grouped at the lowest level of identifiable cash flows.
Each of the GenOn Mid-Atlantic generating facilities is viewed
as an individual asset group. The asset groups also include
construction
work-in-process,
capitalized interest recorded at GenOn North America related to
the generating facilities and related intangible assets,
including development rights and emissions allowances.
Assumptions
and Results
The assumptions for the long-lived asset impairment analysis
were consistent with those used in the goodwill impairment
analysis of GenOn Mid-Atlantic described above.
GenOn Americas Generation recorded fourth quarter impairment
losses of $523 million and $42 million on the
consolidated statement of operations to reduce the carrying
values of the Dickerson and Potomac River
F-45
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
generating facilities, respectively, to their estimated fair
values. GenOn Mid-Atlantic recorded fourth quarter impairment
losses of $497 million and $40 million on the
consolidated statement of operations to reduce the carrying
values of the Dickerson and Potomac River generating facilities,
respectively, to their estimated fair values. In addition, as a
result of the impairment of the Potomac River generating
facility, the Companies recorded $32 million in operations
and maintenance expense and corresponding liabilities associated
with GenOn Mid-Atlantics commitment to reduce particulate
emissions as part of the agreement with the City of Alexandria,
Virginia. The planned capital investment would not be recovered
in future periods based on the current projected cash flows of
the Potomac River generating facility.
The following table sets forth by level within the fair value
hierarchy the Companies assets that were accounted for at
fair value on a non-recurring basis. All of the Companies
assets that were measured at fair value as a result of
impairment losses recorded during the current period were
categorized in Level 3 at December 31, 2010:
GenOn
Americas Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value at December 31, 2010
|
|
|
|
|
|
|
Quoted Prices
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
|
|
|
in Active
|
|
|
Significant
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Markets for
|
|
|
Other
|
|
|
Unobservable
|
|
|
|
|
|
Loss
|
|
|
|
|
|
|
Identical Assets
|
|
|
Observable Inputs
|
|
|
Inputs
|
|
|
|
|
|
Included in
|
|
|
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Total
|
|
|
Earnings
|
|
|
|
|
|
|
(in millions)
|
|
|
Dickerson generating facility
|
|
$
|
|
|
|
$
|
|
|
|
$
|
91
|
|
|
$
|
91
|
|
|
$
|
463
|
|
|
|
|
|
Dickerson intangible assets
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
|
8
|
|
|
|
60
|
|
|
|
|
|
Potomac River generating
facility(1)
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
1
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
|
|
|
$
|
100
|
|
|
$
|
100
|
|
|
$
|
565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The remaining carrying value represents the fair value of the
related
SO2
and
NOx
emissions allowances included in property, plant and equipment,
net. |
GenOn
Mid-Atlantic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value at December 31, 2010
|
|
|
|
|
|
|
Quoted Prices
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
|
|
|
in Active
|
|
|
Significant
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Markets for
|
|
|
Other
|
|
|
Unobservable
|
|
|
|
|
|
Loss
|
|
|
|
|
|
|
Identical Assets
|
|
|
Observable Inputs
|
|
|
Inputs
|
|
|
|
|
|
Included in
|
|
|
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Total
|
|
|
Earnings
|
|
|
|
|
|
|
(in millions)
|
|
|
Dickerson generating facility
|
|
$
|
|
|
|
$
|
|
|
|
$
|
86
|
|
|
$
|
86
|
|
|
$
|
437
|
|
|
|
|
|
Dickerson intangible assets
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
|
8
|
|
|
|
60
|
|
|
|
|
|
Potomac River generating
facility(1)
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
1
|
|
|
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
|
|
|
$
|
95
|
|
|
$
|
95
|
|
|
$
|
537
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The remaining carrying value represents the fair value of the
related
SO2
and
NOx
emissions allowances included in property, plant and equipment,
net. |
F-46
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Dickerson
Generating Facility
Background
The Companies also reviewed the Dickerson generating facility
for impairment in the second quarter of 2010 upon the enactment
of the
CO2
levy by the Montgomery County Council. Upon completion of the
assessment, the Companies determined that the Dickerson
generating facility was not impaired in the second quarter of
2010.
Bowline
Generating Facility (GenOn Americas Generation)
Background
During the second quarter of 2010, the NYISO issued its annual
peak load and energy forecast in its Load and Capacity Data
report (the Gold Book). The Gold Book reports projected
electricity supply and demand for the New York control area for
the next ten years. The most recent Gold Book projects a
significant decrease in future electricity demand as a result of
current economic conditions and the expected future effects of
demand-side management programs in New York. The expected
reduction in future demand as a result of demand-side management
programs is being driven primarily by an energy efficiency
program being instituted within the State of New York that will
seek to achieve a 15% reduction from 2007 energy volumes by
2015. As a result of the projections in the Gold Book, GenOn
Americas Generation evaluated the Bowline generating facility
for impairment in the second quarter of 2010. The sum of the
probability weighted undiscounted cash flows for the Bowline
generating facility exceeded the carrying value. As a result,
GenOn Americas Generation did not record an impairment loss for
the Bowline generating facility during the second quarter of
2010.
GenOn Bowline has challenged its property tax assessment for the
2009 and 2010 tax years. Although the assessment for the 2010
tax year was reduced significantly from the assessment received
in 2009, the assessment continues to exceed significantly the
estimated fair value of the generating facility.
In the fourth quarter of 2010, GenOn Americas Generation
identified certain operational issues that reduced the available
capacity of the Bowline generating facility. GenOn Americas
Generation is in the process of evaluating long-term solutions
for the generating facility, but its current expectation is that
the reduction in available capacity could extend through 2012.
In the fourth quarter of 2010, GenOn Americas Generation again
evaluated the Bowline generating facility for impairment because
of the expected extended reduction in available capacity
together with the pending property tax litigation and the effect
of supply and demand assumptions in the NYISOs Gold Book.
Asset
Grouping
For purposes of impairment testing, a long-lived asset or assets
must be grouped at the lowest level of identifiable cash flows.
GenOn Americas Generation included its Hudson Valley Gas
subsidiary in the impairment analysis as the sole function of
the pipeline operated by Hudson Valley Gas is to supply gas to
the Bowline generating facility.
Assumptions
and Results
GenOn Americas Generations assessment for recoverability
of the Bowline generating facility under the accounting guidance
related to the impairment of a long-lived asset involved
developing cash flow projections for the future expected
operations of the Bowline generating facility, including
scenarios related to the outcome of the ongoing property tax
litigation. The cash flow projections included capacity and
energy
F-47
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
revenue forecasts based on supply and demand assumptions from
the NYISOs Gold Book and proprietary fundamental modeling.
The sum of the probability weighted undiscounted cash flows for
the Bowline generating facility exceeded the carrying value. As
a result, GenOn Americas Generation did not record an impairment
loss for the Bowline generating facility during 2010. The
carrying value of the Bowline generating facility represented
approximately 5% of GenOn Americas Generations total
property, plant and equipment, net at December 31, 2010.
Emissions
Allowances
In August 2010, the EPA proposed a replacement for the CAIR. The
market prices for
SO2
and
NOx
emissions allowances declined as a result of the proposed rule.
The Companies historical accounting policies have been to
include emissions allowances in their asset groupings when
evaluating long-lived assets for impairment. However, to the
extent the final EPA rule significantly modifies or ends the
current
cap-and-trade
program, the Companies may evaluate whether the their
SO2
and
NOx
emissions allowances included in property, plant and equipment
and intangible assets should be evaluated separately from the
underlying generating facilities. The carrying value of the
SO2
and
NOx
emissions allowances included in GenOn Americas
Generations property, plant and equipment and intangible
assets at December 31, 2010 was $146 million. The
carrying value of the
SO2
and
NOx
emissions allowances included in GenOn Mid-Atlantics
property, plant and equipment and intangible assets at
December 31, 2010 was $85 million. See
Environmental Matters in note 9 for further
information on the EPAs proposed replacement of the CAIR.
2009
Potrero
Generating Facility (GenOn Americas Generation)
Background
In the third quarter of 2009, GenOn Potrero executed a
settlement agreement with the City and County of
San Francisco in which it agreed to shut down the Potrero
generating facility when it is no longer needed for reliability,
as determined by the CAISO. That settlement agreement became
effective in November 2009. As a result of the settlement
agreement, GenOn Americas Generation evaluated the Potrero
generating facility for impairment during the third quarter of
2009. In December 2010, the CAISO provided GenOn Potrero with
the requisite notice of termination of the RMR agreement. On
January 19, 2011, at the request of GenOn Potrero, the FERC
approved changes to GenOn Potreros RMR agreement to allow
the CAISO to terminate the RMR agreement effective
February 28, 2011. On February 28, 2011, the Potrero
facility was shut down. See note 10 for further discussion
of the settlement agreement with the City and County of
San Francisco.
Asset
Grouping
For purposes of impairment testing, a long-lived asset or assets
must be grouped at the lowest level of identifiable cash flows.
All of the units at GenOn Potrero are viewed as a single asset
group. Additionally, the asset group includes intangible assets
recorded at GenOn California North for trading and development
rights related to GenOn Potrero.
Assumptions
and Results
GenOn Americas Generation evaluated the Potrero generating
facility for impairment during the third quarter of 2009. GenOn
Americas Generations assessment of GenOn Potrero under the
accounting guidance
F-48
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
related to the impairment of a long-lived asset involved
developing scenarios for the future expected operations of the
Potrero generating facility.
GenOn Americas Generation determined that the tangible assets
for the Potrero generating facility were not impaired because
the weighted average sum of the undiscounted cash flows exceeded
the carrying value of the tangible assets in the third quarter
of 2009. The Potrero generating facility was fully depreciated
at December 31, 2010.
As a result of certain terms included in the settlement
agreement, GenOn Americas Generation separately evaluated the
trading and development rights associated with the Potrero
generating facility for impairment and determined that both of
these intangible assets were fully impaired as of
September 30, 2009. Accordingly, GenOn Americas Generation
recognized an impairment loss of $9 million on the
consolidated statement of operations to write off the carrying
value of the intangible assets related to the Potrero generating
facility. This impairment loss is included in the results of
GenOn Americas Generations California segment for 2009.
Contra
Costa Generating Facility (GenOn Americas
Generation)
Background
On September 2, 2009, GenOn Delta entered into an agreement
with PG&E for the 674 MW Contra Costa units 6 and 7
for the period from November 2011 through April 2013. At the end
of the agreement, and subject to any necessary regulatory
approval, GenOn Delta has agreed to retire Contra Costa units 6
and 7, which began operations in 1964, in furtherance of state
and federal policies to retire aging generating facilities that
utilize once-through cooling technology. The agreement to retire
these units did not significantly affect the remaining useful
life of the Contra Costa generating facility. The GenOn Delta
agreement became effective on September 30, 2010.
Assumptions
and Results
GenOn Americas Generation evaluated the intangible asset of
trading rights related to its Contra Costa generating facility
for impairment during the third quarter of 2009 as a result of
the shutdown provisions in the tolling agreement. Because the
Contra Costa generating facility is under contract with
PG&E through its expected shutdown date of April 2013,
GenOn Americas Generation determined the intangible asset was
fully impaired as of September 30, 2009. GenOn Americas
Generation recorded an impairment loss of $5 million on the
consolidated statement of operations to write off the carrying
value of the trading rights related to the Contra Costa
generating facility. This impairment loss is included in the
results of GenOn Americas Generations California segment
for 2009.
GenOn
Mid-Atlantic Generating Facilities
Background
As described above, the Companies have goodwill recorded at the
GenOn Mid-Atlantic registrant on its standalone balance sheet,
which is eliminated upon consolidation at GenOn North America.
In accordance with accounting guidance for goodwill and other
intangible assets, the Companies are required to test the
goodwill balance at GenOn Mid-Atlantic at least annually. The
Companies performed the goodwill assessment at October 31,
2009, which, by policy, is the annual testing date. In
conducting step one of the goodwill impairment analysis for
GenOn Mid-Atlantic, the Companies noted that the carrying value
of its net assets exceeded the calculated fair value of GenOn
Mid-Atlantic, indicating that step two of the goodwill
impairment analysis was required. Based on the results of the
step one goodwill impairment analysis, the Companies tested
GenOn Mid-Atlantics long-lived assets for impairment under
the accounting guidance related to impairment
F-49
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
of long-lived assets before completion of the step two test for
goodwill. During 2009, the continued decline in average natural
gas prices caused power prices to decline in the Eastern PJM
region. Additionally, weak economic conditions and various
demand-response programs have resulted in a decrease in the
forecasted gross margin of the GenOn Mid-Atlantic generating
facilities.
Upon completion of the Companies assessment, which was based on
the accounting guidance related to the impairment of long-lived
assets, the Companies determined that the Potomac River
generating facility was impaired, as the carrying value exceeded
the undiscounted cash flows. In performing the impairment
assessment, the Companies noted that the undiscounted cash flows
for other GenOn Mid-Atlantic generating facilities also
decreased significantly from the prior year. The Companies
determined that no other GenOn Mid-Atlantic long-lived assets
were impaired at October 31, 2009.
As a result of the assessment, GenOn Americas Generation
recorded an impairment loss of $207 million in the fourth
quarter of 2009 to reduce the carrying value of the Potomac
River generating facility to its estimated fair value. GenOn
Mid-Atlantic recorded an impairment loss of $202 million to
reduce the carrying value of the Potomac River generating
facility to its estimated fair value.
The following tables set forth by level within the fair value
hierarchy the Companies assets and GenOn Americas
Generations intangible assets that were accounted for at
fair value on a non-recurring basis. All of the Companies
assets and GenOn Americas Generations intangible assets
that were measured at fair value as a result of impairment
losses recorded during the current period were categorized in
Level 3 at December 31, 2009:
GenOn
Americas Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value at December 31, 2009
|
|
|
|
Quoted Prices
|
|
|
Significant
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
in Active
|
|
|
Other
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Markets for
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
|
|
Loss
|
|
|
|
Identical Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
|
|
|
Included in
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Total
|
|
|
Earnings
|
|
|
|
(in millions)
|
|
|
Potomac River generating facility
|
|
$
|
|
|
|
$
|
|
|
|
$
|
37
|
|
|
$
|
37
|
|
|
$
|
207
|
|
Potrero intangible assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
Contra Costa intangible assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
|
|
|
$
|
37
|
|
|
$
|
37
|
|
|
$
|
221
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GenOn
Mid-Atlantic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value at December 31, 2009
|
|
|
|
Quoted Prices
|
|
|
Significant
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
in Active
|
|
|
Other
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Markets for
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
|
|
Loss
|
|
|
|
Identical Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
|
|
|
Included in
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Total
|
|
|
Earnings
|
|
|
|
(in millions)
|
|
|
Potomac River generating facility
|
|
$
|
|
|
|
$
|
|
|
|
$
|
37
|
|
|
$
|
37
|
|
|
$
|
202
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
|
|
|
$
|
37
|
|
|
$
|
37
|
|
|
$
|
202
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-50
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(e)
|
Asset
Retirement Obligations.
|
Upon initial recognition of a liability for an asset retirement
obligation or a conditional asset retirement obligation, an
entity shall capitalize an asset retirement cost by increasing
the carrying amount of the related long-lived asset by the same
amount as the liability. Over time, the liability is accreted to
its present value each period and the capitalized cost is
depreciated over the useful life of the related asset.
Retirement obligations associated with long-lived assets
included within the scope of accounting guidance are those for
which a legal obligation exists under enacted laws, statutes and
written or oral contracts, including obligations arising under
the doctrine of promissory estoppel.
The Companies identified certain asset retirement obligations
within their power generating facilities. These asset retirement
obligations are primarily related to asbestos abatement in
facilities on owned or leased property and other environmental
obligations related to ash disposal sites. In addition, the
asset retirement obligations also relate to environmental
obligations for fuel storage facilities, wastewater treatment
facilities and pipelines. See note 9 for further discussion
of the Companies ash disposal facilities.
Asbestos abatement is the most significant type of asset
retirement obligation identified for recognition in connection
with the Companies policy related to accounting for
conditional asset retirements. The EPA has regulations in place
governing the removal of asbestos. Because of the nature of
asbestos, it can be difficult to ascertain the extent of
contamination in older facilities unless substantial renovation
or demolition takes place. Therefore, the Companies incorporated
certain assumptions based on the relative age and size of their
facilities to estimate the current cost for asbestos abatement.
The actual abatement cost could differ from the estimates used
to measure the asset retirement obligation. As a result, these
amounts will be subject to revision when actual abatement
activities are undertaken.
During 2010, a third-party consulting firm completed a study on
behalf of GenOn to determine the extent of asbestos present at
all of GenOn Americas Generations and GenOn
Mid-Atlantics generating facilities. The consulting firm
also provided the Companies with cost estimates for the removal
of the asbestos. As a result, GenOn Americas Generation and
GenOn Mid-Atlantic revised the cost estimates associated with
its asset retirement obligations for asbestos removal at all of
their generating facilities.
The following tables set forth the balances of the asset
retirement obligations and the additions, revisions in estimated
cash flows and accretion of the asset retirement obligations.
The asset retirement obligations are included in other
noncurrent liabilities in the consolidated balance sheets:
GenOn
Americas Generation
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
Beginning balance January 1
|
|
$
|
43
|
|
|
$
|
40
|
|
Revisions in estimated cash flows
|
|
|
7
|
|
|
|
|
|
Accretion expense
|
|
|
4
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
Ending balance December 31
|
|
$
|
54
|
|
|
$
|
43
|
|
|
|
|
|
|
|
|
|
|
F-51
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
GenOn
Mid-Atlantic
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
Beginning balance January 1
|
|
$
|
13
|
|
|
$
|
12
|
|
Revisions in estimated cash flows
|
|
|
4
|
|
|
|
|
|
Accretion expense
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
Ending balance December 31
|
|
$
|
18
|
|
|
$
|
13
|
|
|
|
|
|
|
|
|
|
|
Outstanding debt was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
December 31, 2009
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
|
|
|
Stated
|
|
|
|
|
|
|
|
|
Stated
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
|
|
|
|
|
|
|
Interest
|
|
|
|
|
|
|
|
|
|
|
|
|
Rate(1)
|
|
|
Long-Term
|
|
|
Current
|
|
|
Rate(1)
|
|
|
Long-Term
|
|
|
Current
|
|
|
|
|
|
|
(in millions, except interest rates)
|
|
|
Facilities, Bonds and Notes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GenOn Americas Generation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior unsecured notes, due 2011
|
|
|
8.30
|
%
|
|
$
|
|
|
|
$
|
535
|
|
|
|
8.30
|
%
|
|
$
|
535
|
|
|
$
|
|
|
|
|
|
|
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, net
|
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
GenOn North America:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior secured term loan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.13
|
|
|
|
303
|
|
|
|
70
|
|
|
|
|
|
Senior notes, due
2013(2)
|
|
|
7.375
|
|
|
|
|
|
|
|
850
|
|
|
|
7.375
|
|
|
|
850
|
|
|
|
|
|
|
|
|
|
GenOn Mid-Atlantic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GenOn Chalk Point capital lease, due 2011 to 2015
|
|
|
8.19
|
|
|
|
18
|
|
|
|
4
|
|
|
|
8.19
|
|
|
|
21
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
$
|
866
|
|
|
$
|
1,389
|
|
|
|
|
|
|
$
|
2,556
|
|
|
$
|
74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The weighted average stated interest rates are at
December 31, 2010 and 2009. |
|
(2) |
|
These notes were discharged at the closing of the Merger on
December 3, 2010 and were redeemed on January 3, 2011
at a call price of 101.844% of the principal amount. |
F-52
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
GenOn
Americas Generation
Debt maturities for the principal amounts at December 31,
2010 are (in millions):
|
|
|
|
|
2011
|
|
$
|
1,389
|
(1)
|
2012
|
|
|
4
|
|
2013
|
|
|
4
|
|
2014
|
|
|
5
|
|
2015
|
|
|
5
|
|
2016 and thereafter
|
|
|
850
|
|
|
|
|
|
|
Total
|
|
$
|
2,257
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes $850 million of GenOn North America senior notes
redeemed on January 3, 2011. |
|
|
(b)
|
Debt
Financing Transactions Related to the Merger.
|
GenOn entered into new senior secured credit facilities
comprised of a $788 million five-year senior secured
revolving credit facility and a $700 million seven-year
senior secured term loan (the GenOn credit facilities). The
funding of the term loan facility and the availability of
borrowings and letters of credit under the revolving credit
facility were subject to the closing of the Merger and the
satisfaction of the conditions precedent thereto. In addition,
GenOn Escrow, a wholly-owned subsidiary of GenOn, issued senior
notes in an aggregate principal amount of $1.225 billion.
Upon issuance, the proceeds of the notes (which were issued at a
discount), together with additional funds, were deposited into a
segregated escrow account pending completion of the Merger. Upon
completion of the Merger, GenOn Escrow merged with and into
GenOn which assumed all of GenOn Escrows obligations under
the notes and the related indenture and the funds held in escrow
were released to GenOn. The proceeds of the new GenOn credit
facilities and senior notes were used, in part, to redeem the
GenOn North America senior notes, repay and terminate the GenOn
North America term loan and replace the GenOn North America
revolving credit facility.
The GenOn credit facilities, and the subsidiary guarantees
thereof, are the senior secured obligations of GenOn and certain
of its existing and future direct and indirect subsidiaries,
excluding GenOn Americas Generation; provided, however, that
certain of GenOn Americas Generations subsidiaries (other
than GenOn Mid-Atlantic and GenOn Energy Management and their
subsidiaries) guarantee the GenOn credit facilities to the
extent permitted under the indenture for the senior notes of
GenOn Americas Generation.
GenOn
North America Senior Secured Credit Facilities
Upon closing of the Merger, GenOn North America repaid the
outstanding senior secured credit facility (entered into in
2006) of $305 million plus accrued and unpaid interest
through the date of repayment. The total payment was
$305 million and a $9 million loss on extinguishment
of debt was recognized in other, net in the consolidated
statement of operations. Letters of credit in the amount of
$197 million outstanding under the GenOn North America
credit facilities were transferred to the GenOn revolving credit
facility and $124 million of the cash collateral previously
posted to support these letters of credit was released to fund a
portion of the Merger closing costs.
GenOn
North America Senior Notes Due 2013
Upon closing of the Merger, the senior secured notes due 2013 of
GenOn North America (issued in 2005) were discharged
following the deposit with the trustee of funds sufficient to
pay the redemption price
F-53
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
thereof, plus accrued interest to the date of redemption. The
amount of funds on deposit with the trustee was
$866 million at December 31, 2010 and is recorded as
restricted cash, included in funds on deposit on the
consolidated balance sheet.
On January 3, 2011, the senior secured notes were redeemed
at the call price of 101.844% of the principal amount plus
accrued and unpaid interest through the date of redemption. The
total payment on the date of redemption was $866 million
and a $23 million loss on extinguishment of debt was
recognized in 2011, which includes a $16 million premium
and $7 million of unamortized debt issuance costs.
|
|
(c)
|
Debt
and Capital Leases.
|
GenOn
Americas Generation Senior Notes
The senior notes due 2011, 2021 and 2031 are senior unsecured
obligations of GenOn Americas Generation having no recourse to
any subsidiary or affiliate of GenOn Americas Generation. The
principal balance of the GenOn Americas Generation senior notes
due in May 2011 is included in current portion of long-term debt
at December 31, 2010. During 2008, GenOn Americas
Generation purchased and retired $276 million of senior
notes due in 2011.
Capital
Leases
Outstanding debt includes a capital lease by GenOn Chalk Point.
At December 31, 2010 and 2009, the current portion of the
long-term debt under this capital lease was $4 million. The
amount outstanding under the capital lease at December 31,
2010, which matures in 2015, is $22 million with an 8.19%
annual interest rate. This lease is for an 84 MW peaking
electric power generating facility. Depreciation expense related
to this lease was $2 million during 2010, 2009 and 2008.
The annual principal payments under this lease are
$4 million in 2011, 2012 and 2013, and $5 million in
2014 and 2015. The gross amount of assets under the capital
lease, recorded in property, plant and equipment, net, was
$24 million at December 31, 2010 and 2009. The related
accumulated depreciation was $16 million and
$15 million at December 31, 2010 and 2009,
respectively.
The principal sources of liquidity for the Companies are
expected to be: (a) existing cash on hand and expected cash
flows from their operations and the operations of their
subsidiaries, (b) at its discretion, letters of credit
issued under the GenOn revolving credit facility on behalf of
the Companies and (c) at its discretion, capital
contributions from GenOn.
GenOn Americas Generation and certain of its subsidiaries are
holding companies and, as a result, GenOn Americas Generation
and such subsidiaries are dependent upon dividends,
distributions and other payments from their respective
subsidiaries to generate the funds necessary to meet their
obligations. In particular, a substantial portion of the cash
from GenOn Americas Generations operations is generated by
GenOn Mid-Atlantic. GenOn Mid-Atlantics ability to pay
dividends and make distributions is restricted under the terms
of its operating leases. Under the operating leases, GenOn
Mid-Atlantic is not permitted to make any distributions and
other restricted payments unless: (a) it satisfies the
fixed charge coverage ratio for the most recently ended period
of four fiscal quarters; (b) it is projected to satisfy the
fixed charge coverage ratio for each of the two following
periods of four fiscal quarters, commencing with the fiscal
quarter in which such payment is proposed to be made; and
(c) no significant lease default or event of default has
occurred and is continuing. In the event of a default under the
operating leases or if the restricted payment tests are not
satisfied, GenOn Mid-Atlantic would not be able to distribute
cash. At December 31, 2010, GenOn Mid-Atlantic satisfied
the restricted payments test.
F-54
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Pursuant to the terms of its lease document, GenOn Mid-Atlantic
is restricted from, among other actions, (a) encumbering
assets, (b) entering into business combinations or
divesting assets, (c) incurring additional debt,
(d) entering into transactions with affiliates on other
than an arms length basis or (e) materially changing
their business. Therefore, at December 31, 2010, all of
GenOn Mid-Atlantics net assets (excluding cash) were
deemed restricted for purposes of
Rule 4-08(e)(3)(iii)
of
Regulation S-X.
The amounts of restricted net assets were as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2010
|
|
2009
|
|
|
(in millions)
|
|
GenOn Mid-Atlantic
|
|
$
|
3,698
|
|
|
$
|
4,761
|
|
The ability of GenOn Americas Generation to pay its obligations
is dependent on the receipt of dividends from GenOn North
America, capital contributions or intercompany loans from GenOn
and its ability to refinance all or a portion of those
obligations as they become due. Although GenOn Americas
Generation continues to evaluate its refinancing options, GenOn
Americas Generation expects to maintain adequate liquidity to
retire its senior notes that come due in May 2011.
As described above, GenOn Mid-Atlantic has restrictions on its
ability to pay dividends or make intercompany loans and advances
under its operating lease agreements. At December 31, 2010,
GenOn North America had $290 million of cash, of which
$202 million was held by GenOn Mid-Atlantic. In addition,
GenOn Mid-Atlantic met the tests under the operating lease
documentation permitting it to make distributions to GenOn North
America at December 31, 2010.
Income
Tax Disclosures (GenOn Americas Generation)
GenOn Americas Generation and most of its subsidiaries are
limited liability companies that are treated as branches of
GenOn Americas for income tax purposes. As a result, GenOn
Americas and GenOn have direct liability for the majority of the
United States federal and state income taxes relating to GenOn
Americas Generations operations. Some of GenOn Americas
Generations subsidiaries, Hudson Valley Gas and GenOn
Special Procurement, Inc., exist as regarded corporate entities
for income tax purposes. GenOn Kendall, which had previously
existed as a regarded entity, has been converted to a
disregarded entity. For these subsidiaries that continue to
exist as corporate regarded entities, GenOn Americas Generation
allocates current and deferred income taxes to each corporate
regarded entity as if such entity were a single taxpayer
utilizing the asset and liability method to account for income
taxes. To the extent GenOn Americas Generation provides tax
expense or benefit, any related tax payable or receivable to
GenOn is reclassified to equity in the same period because GenOn
Americas Generation does not have a tax sharing agreement with
GenOn.
As a result of the Merger, each of Mirant and RRI Energy has
separately determined whether or not each had experienced an
ownership change as defined in the IRC. IRC Section (IRC §)
382 provides, in general, that an ownership change occurs when
there is a greater than 50-percentage point increase in
ownership of a companys stock by new or existing
stockholders who own (or are deemed to own under IRC
§ 382) 5% or more of the loss companys
stock over a three year testing period. IRC § 382
limits the amount of pre-merger NOLs that can be used during any
post-ownership change year to offset taxable income. Mirant
experienced an ownership change within the meaning
of IRC § 382. The annual limitation on the amount of
taxable income that can be offset by Mirants pre-merger
NOLs has been redetermined as of the date of the Merger. GenOn
Americas Generations annual limitation on the amount of
taxable income that can be offset by its pre-merger NOLs has
also been redetermined as a consequence of the Mirant ownership
change as a result of the
F-55
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Merger. GenOn Americas Generation has reduced the amount of its
pre-merger NOLs available to offset post-merger taxable income
based on the expected limits determined in accordance with IRC
§ 382.
Details of GenOn Americas Generations income tax provision
(benefit) are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
Current benefit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
State
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
Deferred provision:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
1
|
|
|
|
|
|
|
|
|
|
State
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total provision (benefit) for income taxes
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A reconciliation of GenOn Americas Generations expected
federal statutory income tax provision to the effective income
tax provision adjusted for permanent and other items during
2010, 2009 and 2008, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
United States federal statutory income tax provision (benefit)
|
|
$
|
(139
|
)
|
|
$
|
167
|
|
|
$
|
419
|
|
State and local income taxes, net of federal income taxes
|
|
|
12
|
|
|
|
1
|
|
|
|
2
|
|
LLC income not subject to federal taxation
|
|
|
136
|
|
|
|
(166
|
)
|
|
|
(420
|
)
|
Change in deferred tax asset valuation allowance
|
|
|
(105
|
)
|
|
|
(2
|
)
|
|
|
(1
|
)
|
Conversion of GenOn Kendall to disregarded entity
|
|
|
58
|
|
|
|
|
|
|
|
|
|
Merger related write off of NOLs
|
|
|
38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax provision
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GenOn Kendall, which had previously existed as a taxable entity,
has been converted to a disregarded entity and will be treated
as a branch of GenOn Americas for income tax purposes. As a
result of this conversion, GenOn Kendalls net deferred tax
assets of $58 million and corresponding valuation allowance
were written off.
F-56
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The tax effects of GenOn Americas Generations temporary
differences between the carrying amounts of assets and
liabilities in the consolidated financial statements and its tax
bases which give rise to deferred tax assets and liabilities for
continuing operations are as follows:
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
Deferred Tax Assets:
|
|
|
|
|
|
|
|
|
Property and intangible assets
|
|
$
|
|
|
|
$
|
65
|
|
Loss carry forwards
|
|
|
2
|
|
|
|
41
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
2
|
|
|
|
106
|
|
Valuation allowance
|
|
|
|
|
|
|
(105
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
|
2
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
Deferred Tax Liabilities:
|
|
|
|
|
|
|
|
|
Property and intangible assets
|
|
|
(3
|
)
|
|
|
|
|
Derivative contracts
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liabilities
|
|
|
(3
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred taxes
|
|
$
|
(1
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2010, GenOn Americas Generation had
$4 million of NOL carry forwards for federal income tax
purposes expiring from 2023 to 2030 and $5 million of NOL
carry forwards for state income tax purposes. The federal NOL
carry forward is available to offset future federal income tax.
The guidance related to accounting for income taxes requires
that a valuation allowance be established when it is
more-likely-than-not that all or a portion of a deferred tax
asset will not be realized. The ultimate realization of deferred
tax assets is dependent upon the generation of future taxable
income during the periods in which those temporary differences
are deductible. In making this determination, management
considers all available positive and negative evidence affecting
specific deferred tax assets, including GenOn Americas
Generations past and anticipated future performance, the
reversal of deferred tax liabilities and the implementation of
tax planning strategies.
Objective positive evidence is necessary to support a conclusion
that a valuation allowance is not needed for all or a portion of
deferred tax assets when significant negative evidence exists.
GenOn Americas Generation evaluates this position quarterly and
makes its judgment based on the facts and circumstances at that
time.
At December 31, 2009, GenOn Americas Generations
deferred tax assets reduced by the valuation allowance are
completely offset by their deferred tax liabilities. In 2010,
2009 and 2008, GenOn Americas Generation recognized changes in
its valuation allowance of $(105) million,
$(2) million and $(1) million, respectively, related
to its net deferred tax assets.
Tax
Uncertainties
The recognition of contingent losses for tax uncertainties
requires management to make significant assumptions about the
expected outcomes of certain tax contingencies. Under the
accounting guidance, the Companies must reflect in their income
tax provision the full benefit of all positions that will be
taken in the their income tax returns, except to the extent that
such positions are uncertain and fall below the benefit
recognition requirements. In the event that the Companies
determine that a tax position meets the uncertainty criteria, an
additional liability or an adjustment to their NOLs, determined
under the measurement criteria, will
F-57
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
result. The Companies periodically reassess the tax positions in
their tax returns for open years based on the latest information
available and determine whether any portion of the tax benefits
reflected should be treated as unrecognized.
Both the federal and state NOL carry forwards from any closed
year are subject to examination until the year that such NOL
carry forwards are utilized and that utilization year is closed
for audit. The Companies tax provision continues to
include an immaterial amount related to the accrual for any
penalties and interest subsequent to its adoption of the
accounting guidance related to accounting for uncertainty in
income taxes.
Pro
Forma Income Tax Disclosures
GenOn
Americas Generation
GenOn Americas Generation is not subject to income taxes except
for those subsidiaries of GenOn Americas Generation that are
separate taxpayers. GenOn Americas and GenOn are otherwise
directly responsible for income taxes related to GenOn Americas
Generations operations.
The following reflects a pro forma disclosure of the income tax
provision that would be reported if GenOn Americas Generation
were to be allocated income taxes attributable to its
operations. Pro forma income tax provision attributable to
income before tax would consist of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
Current income tax provision:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
7
|
|
|
$
|
10
|
|
|
$
|
2
|
|
State
|
|
|
2
|
|
|
|
5
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes
|
|
$
|
9
|
|
|
$
|
15
|
|
|
$
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents the pro forma reconciliation of
GenOn Americas Generations federal statutory income tax
provision for continuing operations adjusted for reorganization
items to the pro forma effective tax provision:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
United States federal statutory income tax provision (benefit)
|
|
$
|
(139
|
)
|
|
$
|
167
|
|
|
$
|
419
|
|
State and local income taxes, net of federal income taxes
|
|
|
42
|
|
|
|
26
|
|
|
|
63
|
|
Change in deferred tax asset valuation allowance
|
|
|
55
|
|
|
|
(167
|
)
|
|
|
(479
|
)
|
Merger related write off of NOLs
|
|
|
61
|
|
|
|
|
|
|
|
|
|
Effect of IRC §382(1)(6) and §382(1)(5)
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
Excess tax deductions related to bankruptcy transactions
|
|
|
|
|
|
|
(3
|
)
|
|
|
|
|
Other, net
|
|
|
(10
|
)
|
|
|
(8
|
)
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax provision
|
|
$
|
9
|
|
|
$
|
15
|
|
|
$
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-58
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The tax effects of temporary differences between the carrying
amounts of assets and liabilities in the consolidated balance
sheets and their respective tax bases which give rise to the pro
forma deferred tax assets and liabilities would be as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
Deferred Tax Assets:
|
|
|
|
|
|
|
|
|
Reserves
|
|
$
|
14
|
|
|
$
|
10
|
|
Loss carry forwards
|
|
|
228
|
|
|
|
359
|
|
Property and intangible assets
|
|
|
238
|
|
|
|
83
|
|
Other, net
|
|
|
42
|
|
|
|
54
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
522
|
|
|
|
506
|
|
Valuation allowance
|
|
|
(253
|
)
|
|
|
(198
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
|
269
|
|
|
|
308
|
|
|
|
|
|
|
|
|
|
|
Deferred Tax Liabilities:
|
|
|
|
|
|
|
|
|
Derivative contract assets and liabilities
|
|
|
(268
|
)
|
|
|
(281
|
)
|
Other, net
|
|
|
(1
|
)
|
|
|
(27
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liabilities
|
|
|
(269
|
)
|
|
|
(308
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred taxes
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2010, a portion of GenOn Americas
Generations pro forma NOLs (approximately
$11 million) is attributable to excess tax deductions
primarily related to bankruptcy transactions. The recognition of
pro forma tax benefit of these excess tax deductions, either
through realization or reduction of the pro forma valuation
allowance, would be an increase to pro forma members
interest. These pro forma NOLs will be the last utilized for
financial reporting purposes.
As a result of the Merger, each of Mirant and RRI Energy has
separately determined whether or not each had experienced an
ownership change as defined in the IRC. IRC § 382
provides, in general, that an ownership change occurs when there
is a greater than 50-percentage point increase in ownership of a
companys stock by new or existing stockholders who own (or
are deemed to own under IRC § 382) 5% or more of
the loss companys stock over a three year testing period.
IRC § 382 limits the amount of pre-merger NOLs that
can be used during any post-ownership change year to offset
taxable income. Mirant experienced an ownership
change within the meaning of IRC § 382. The
annual limitation on the amount of taxable income that can be
offset by Mirants pre-merger NOLs has been redetermined as
of the date of the Merger. GenOn Americas Generations
annual limitation on the amount of taxable income that can be
offset by its pre-merger NOLs has also been redetermined as a
consequence of the Mirant ownership change as a result of the
Merger. GenOn Americas Generation has reduced the amount of its
proforma NOLs available to offset post-merger taxable income
based on the expected limits determined in accordance with IRC
§ 382.
GenOn Americas Generation has not provided a pro forma deferred
tax liability with respect to its investment in the GenOn
Americas Preferred Stock discussed in note 6 since the
underlying transaction is disregarded for income tax purposes.
F-59
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
GenOn
Mid-Atlantic
GenOn Mid-Atlantic and its subsidiaries are limited liability
companies and are not subject to United States federal or
state income taxes. As such, GenOn Mid-Atlantic is treated as
though it were a branch or division of GenOn Americas
Generations parent, GenOn Americas, for income tax
purposes, and not as a separate taxpayer. GenOn Americas and
GenOn are directly responsible for income taxes related to GenOn
Mid-Atlantics operations.
The following reflects a pro forma disclosure of the income tax
provision that would be reported if GenOn Mid-Atlantic was to be
allocated income taxes attributable to its operations. Pro forma
income tax provision attributable to income before tax would
consist of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
Current provision:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
108
|
|
|
$
|
182
|
|
|
$
|
173
|
|
State
|
|
|
21
|
|
|
|
40
|
|
|
|
41
|
|
Deferred provision (benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(159
|
)
|
|
|
(9
|
)
|
|
|
219
|
|
State
|
|
|
(39
|
)
|
|
|
(7
|
)
|
|
|
52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income taxes provision (benefit)
|
|
$
|
(69
|
)
|
|
$
|
206
|
|
|
$
|
485
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents the pro forma reconciliation of
GenOn Mid-Atlantics federal statutory income tax provision
for continuing operations adjusted for reorganization items to
the pro forma effective tax provision:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
United States federal statutory income tax provision (benefit)
|
|
$
|
(274
|
)
|
|
$
|
121
|
|
|
$
|
426
|
|
State and local income taxes, net
|
|
|
(11
|
)
|
|
|
21
|
|
|
|
61
|
|
Effect of IRC §382(1)(6)
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
Impairment of non-deductible goodwill
|
|
|
216
|
|
|
|
64
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax provision (benefit)
|
|
$
|
(69
|
)
|
|
$
|
206
|
|
|
$
|
485
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-60
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The tax effects of temporary differences between the carrying
amounts of assets and liabilities in the consolidated balance
sheets and their respective tax bases which give rise to the pro
forma deferred tax assets and liabilities would be as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
Deferred Tax Assets:
|
|
|
|
|
|
|
|
|
Property and intangible assets
|
|
$
|
26
|
|
|
$
|
|
|
Other, net
|
|
|
21
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
|
47
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
Deferred Tax Liabilities:
|
|
|
|
|
|
|
|
|
Property and intangible assets
|
|
|
|
|
|
|
(142
|
)
|
Derivative contracts
|
|
|
(266
|
)
|
|
|
(265
|
)
|
Other, net
|
|
|
|
|
|
|
(15
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liabilities
|
|
|
(266
|
)
|
|
|
(422
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred taxes
|
|
$
|
(219
|
)
|
|
$
|
(417
|
)
|
|
|
|
|
|
|
|
|
|
Pro
Forma Tax Uncertainties
The pro forma unrecognized tax benefit for all of the Companies
is an insignificant amount and would not materially affect the
Companies pro forma effective tax rate if it were
recognized. The Companies pro forma tax provisions include
an immaterial amount related to the accrual for any penalties
and interest subsequent to their adoption of the accounting
guidance related to accounting for uncertainty in income taxes.
|
|
6.
|
Related
Party Arrangements and Transactions
|
Administrative
Services Agreement with GenOn Energy Services
GenOn Energy Services provides the Companies with various
management, personnel and other services as set forth in the
Administrative Services Agreement. The Companies reimburse GenOn
Energy Services for amounts equal to GenOn Energy Services
costs of providing such services.
The total costs incurred by the Companies under the
Administrative Services Agreement with GenOn Energy Services
have been included in the Companies consolidated
statements of operations as follows:
GenOn
Americas Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
Cost of fuel, electricity and other productsaffiliate
|
|
$
|
8
|
|
|
$
|
9
|
|
|
$
|
6
|
|
Operations and maintenance expenseaffiliate
|
|
|
163
|
|
|
|
155
|
|
|
|
147
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
171
|
|
|
$
|
164
|
|
|
$
|
153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-61
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
GenOn
Mid-Atlantic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
Cost of fuel, electricity and other productsaffiliate
|
|
$
|
8
|
|
|
$
|
8
|
|
|
$
|
7
|
|
Operations and maintenance expenseaffiliate
|
|
|
98
|
|
|
|
84
|
|
|
|
78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
106
|
|
|
$
|
92
|
|
|
$
|
85
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Services
Provided by GenOn Energy Management
GenOn
Americas Generation
As a result of the Merger, GenOn Energy Management provides
services to certain of GenOns indirect operating
subsidiaries through Power, Fuel Supply and Services Agreements.
The services include the bidding and dispatch of the generating
units, fuel procurement and the execution of contracts,
including economic hedges, to reduce price risk. Amounts due
from and to GenOns indirect operating subsidiaries are
recorded as accounts receivableaffiliate or net
payableaffiliate, as appropriate.
GenOn
Mid-Atlantic
GenOn Mid-Atlantic receives services from GenOn Energy
Management which include the bidding and dispatch of the
generating units, fuel procurement and the execution of
contracts, including economic hedges, to reduce price risk.
Amounts due to and from GenOn Energy Management under the Power
Sale, Fuel Supply and Services Agreement are recorded as a net
payableaffiliate or accounts receivableaffiliate, as
appropriate. Substantially all energy marketing overhead
expenses are allocated to GenOns operating subsidiaries.
During, 2010, 2009 and 2008, GenOn Mid-Atlantic incurred
$13 million, $14 million and $15 million,
respectively, of energy marketing overhead expense. These costs
are included in operations and maintenance
expenseaffiliate in GenOn Mid-Atlantics consolidated
statements of operations.
Power
Sales and Fuel Supply Arrangement with GenOn Energy Management
(GenOn Mid-Atlantic)
GenOn Mid-Atlantic operates under a Power Sale, Fuel Supply and
Services Agreement with GenOn Energy Management. Amounts due to
GenOn Energy Management for fuel purchases and due from GenOn
Energy Management for power and capacity sales are recorded as a
payableaffiliate or accounts receivableaffiliate in
GenOn Mid-Atlantics consolidated balance sheets.
Under the Power Sale, Fuel Supply and Services Agreement, GenOn
Energy Management resells GenOn Mid-Atlantics energy
products in the PJM spot and forward markets and to other third
parties. GenOn Mid-Atlantic is paid the amount received by GenOn
Energy Management for such capacity and energy. GenOn
Mid-Atlantic has counterparty credit risk in the event that
GenOn Energy Management is unable to collect amounts owed from
third parties for the resale of GenOn Mid-Atlantics energy
products.
Services
Agreement with GenOn Marsh Landing (GenOn Americas
Generation)
During 2010, GenOn Energy Management entered into a services
agreement with GenOn Marsh Landing that includes the bidding and
dispatch of the GenOn Marsh Landing generating units, fuel
procurement and the execution of contracts to reduce price risk,
except to the extent that GenOn Marsh Landing contracts directly
with third-parties, including the PPA with PG&E. As
reimbursement for such services, GenOn Marsh Landing has agreed
to pay GenOn Energy Management the allocated cost to GenOn
Energy Management of providing such services.
F-62
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Administration
Arrangements with GenOn Energy Services
Prior to the completion of the Merger, substantially all of
GenOns corporate overhead costs were allocated to its
operating subsidiaries based on an average of each operating
subsidiaries gross margin, labor costs and net property,
plant and equipment relative to all operating subsidiaries. For
periods subsequent to the completion of the Merger, GenOns
corporate overhead costs are allocated based on each operating
subsidiaries planned operating expenses relative to all
operating subsidiaries. Management has concluded that this
method of allocating overhead costs is reasonable. During 2010,
2009 and 2008, the Companies incurred the following in costs
under these arrangements, which are included in operations and
maintenance expense affiliate in the Companies
consolidated statements of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
(in millions)
|
|
GenOn Americas Generation
|
|
$
|
130
|
|
|
$
|
135
|
|
|
$
|
138
|
|
GenOn Mid-Atlantic
|
|
$
|
83
|
|
|
$
|
91
|
|
|
$
|
80
|
|
These allocations and charges are not necessarily indicative of
what would have been incurred had the Companies been an
unaffiliated entity.
Sales
Agreements with GenOn Marsh Landing (GenOn Americas
Generation)
In October 2010, GenOn Delta entered into an agreement for the
sale of the land for the Marsh Landing planned generating
facility site to GenOn Marsh Landing for consideration of
approximately $3 million based on a third-party appraisal.
In connection with the closing of the sale of the land for the
Marsh Landing generating facility site, GenOn Delta and GenOn
Marsh Landing will enter into related agreements including a
shared facilities and services agreement, easement agreements
and an assignment of certain water rights to GenOn Marsh
Landing. On December 2, 2010, GenOn Marsh Landing and GenOn
Delta closed on the transfer of the site. In connection with the
transaction, GenOn Delta recognized a gain of $3 million,
which is included in gain on sales of assets, net in GenOn
Americas Generations consolidated statement of operations.
In October 2010, GenOn California North entered into an
agreement for the sale of certain emission reduction credits to
GenOn Marsh Landing. In connection with the transaction, GenOn
California North recognized a gain of $2 million, which is
included in gain on sales of assets, net in GenOn Americas
Generations consolidated statement of operations.
Purchased
Emissions Allowances (GenOn Mid-Atlantic)
In the first quarter of 2009, GenOn Energy Management began
maintaining on behalf of GenOn Mid-Atlantic an inventory of
certain purchased emissions allowances. The emissions allowances
are sold by GenOn Energy Management to GenOn Mid-Atlantic as
they are needed for operations. GenOn Mid-Atlantic purchases
emissions allowances from GenOn Energy Management at GenOn
Energy Managements original cost to purchase the
allowances. For allowances that have been purchased by GenOn
Energy Management from a GenOn affiliate, the price paid by
GenOn Energy Management is determined by market indices.
Emissions allowances purchased from GenOn Energy Management that
were utilized in 2010, 2009 and 2008, were $32 million,
$45 million and $8 million, respectively, and are
recorded in cost of fuel, electricity and other
productsaffiliate in GenOn Mid-Atlantics
consolidated statements of operations. Amounts expensed as a
result of writing down emissions allowances to the lower of cost
or market were $2 million during 2008, and were recorded in
cost of fuel, electricity and other productsaffiliate in
GenOn Mid-Atlantics consolidated statements of operations.
F-63
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Preferred
Shares in GenOn Americas
Series A
Pursuant to the Plan, GenOn Americas was required to make
capital contributions to GenOn Mid-Atlantic for the purpose of
funding future environmental capital expenditures. These capital
contributions were made in the form of mandatorily redeemable
Series A preferred shares, and are reflected as preferred
stock in affiliate in the consolidated balance sheet at
December 31, 2009. In 2010 and 2009, GenOn Americas was
required to and did redeem $95 million and
$84 million, respectively, in preferred stock held by GenOn
Mid-Atlantic.
The final redemption for the Series A preferred shares was
scheduled in 2011 at a specified redemption amount of
$50 million. As a result of the Merger, GenOn Americas
redeemed the remaining $50 million of Series A
preferred shares held by GenOn Mid-Atlantic.
At December 31, 2009, the Series A preferred shares
were recorded at a fair value of $138 million as a
component of equity in the Companies consolidated balance
sheets. The fair value was determined using a discounted cash
flow method based on the specified redemption amounts using a
6.21% discount rate. During 2010 and 2009, the Companies
recorded $7 million and $11 million, respectively, in
preferred stock in affiliate and members interest in the
consolidated balance sheets related to the amortization of the
discount on the preferred stock in GenOn Americas.
Series B
(GenOn Americas Generation)
In December 2005, GenOn Americas issued mandatorily redeemable
Series B preferred shares to GenOn Americas Generation for
the purpose of supporting the refinancing of $850 million
of GenOn Americas Generation senior notes due in 2011. The
Series B preferred shares had a mandatory redemption date
of April 1, 2011, for the liquidation preference amount of
$150 million. At any time after June 30, 2010, GenOn
Americas Generation had the right to put the Series B
preferred shares to GenOn at the liquidation preference amount.
As a result of the Merger, GenOn Americas redeemed the remaining
$150 million of Series B preferred shares held by
GenOn Americas Generation.
At December 31, 2009, the Series B preferred shares
were recorded at a fair value of $142 million as a
component of equity in GenOn Americas Generations
consolidated balance sheets. The fair value was determined using
a discounted cash flow method based on the expected redemption
date and the liquidation preference amount using a 6.21%
discount rate. During both 2010 and 2009, GenOn Americas
Generation recorded $8 million in preferred stock in
affiliate and members interest in the consolidated balance
sheets related to the amortization of the discount on the
preferred stock in GenOn Americas.
|
|
7.
|
Commitments
and Contingencies
|
The Companies have made firm commitments to buy materials and
services in connection with their ongoing operations and have
provided cash collateral or financial guarantees relative to
some of their investments.
F-64
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In addition to debt and other obligations in the consolidated
balance sheets, the Companies have the following annual
commitments under various agreements at December 31, 2010,
related to their operations:
GenOn
Americas Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-Balance Sheet Arrangements and
|
|
|
|
Contractual Obligations by Year
|
|
|
|
Total
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
>5 Years
|
|
|
|
(in millions)
|
|
|
GenOn Mid-Atlantic operating leases
|
|
$
|
1,730
|
|
|
$
|
134
|
|
|
$
|
132
|
|
|
$
|
138
|
|
|
$
|
131
|
|
|
$
|
110
|
|
|
$
|
1,085
|
|
Other operating leases
|
|
|
39
|
|
|
|
5
|
|
|
|
3
|
|
|
|
4
|
|
|
|
4
|
|
|
|
4
|
|
|
|
19
|
|
Fuel commitments
|
|
|
914
|
|
|
|
371
|
|
|
|
334
|
|
|
|
209
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maryland Healthy Air Act
|
|
|
155
|
|
|
|
155
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
287
|
|
|
|
137
|
|
|
|
36
|
|
|
|
19
|
|
|
|
13
|
|
|
|
14
|
|
|
|
68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total commitments
|
|
$
|
3,125
|
|
|
$
|
802
|
|
|
$
|
505
|
|
|
$
|
370
|
|
|
$
|
148
|
|
|
$
|
128
|
|
|
$
|
1,172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GenOn
Mid-Atlantic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-Balance Sheet Arrangements and
|
|
|
|
Contractual Obligations by Year
|
|
|
|
Total
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
>5 Years
|
|
|
|
(in millions)
|
|
|
Generating units operating leases
|
|
$
|
1,730
|
|
|
$
|
134
|
|
|
$
|
132
|
|
|
$
|
138
|
|
|
$
|
131
|
|
|
$
|
110
|
|
|
$
|
1,085
|
|
Other operating leases
|
|
|
37
|
|
|
|
5
|
|
|
|
3
|
|
|
|
4
|
|
|
|
4
|
|
|
|
3
|
|
|
|
18
|
|
Fuel commitments
|
|
|
914
|
|
|
|
371
|
|
|
|
334
|
|
|
|
209
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maryland Healthy Air Act
|
|
|
155
|
|
|
|
155
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
222
|
|
|
|
123
|
|
|
|
34
|
|
|
|
13
|
|
|
|
12
|
|
|
|
12
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total commitments
|
|
$
|
3,058
|
|
|
$
|
788
|
|
|
$
|
503
|
|
|
$
|
364
|
|
|
$
|
147
|
|
|
$
|
125
|
|
|
$
|
1,131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companies contractual obligations tables do not
include the derivative obligations reported at fair value (other
than fuel supply commitments), which are discussed in
note 2 and the asset retirement obligations, which are
discussed in note 3(e).
GenOn
Mid-Atlantic Operating Leases
GenOn Mid-Atlantic leases a 100% interest in both the Dickerson
and Morgantown baseload units and associated property through
2029 and 2034, respectively. GenOn Mid-Atlantic has an option to
extend the leases. Any extensions of the respective leases would
be for less than 75% of the economic useful life of the
facility, as measured from the beginning of the original lease
term through the end of the proposed remaining lease term. The
Companies are accounting for these leases as operating leases
and recognize rent expense on a straight-line basis. Rent
expense totaled $96 million during 2010, 2009 and 2008, and
is included in operations and maintenance expense in the
consolidated statements of operations. At December 31, 2010
and 2009, the Companies have paid $444 million and
$400 million, respectively, of lease payments in excess of
rent expense recognized, which is recorded in prepaid rent and
prepaid expenses on the consolidated balance sheets. Of these
amounts, $96 million is included in prepaid expenses on the
Companies consolidated balance sheets at December 31,
2010 and 2009.
F-65
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At December 31, 2010, the total notional minimum lease
payments for the remaining terms of the leases aggregated
$1.7 billion and the aggregate termination value for the
leases was $1.4 billion, which generally decreases over
time. GenOn Mid-Atlantic leases the Dickerson and the Morgantown
baseload units from third party owner lessors. These owner
lessors each own the undivided interests in these baseload
generating facilities. The subsidiaries of the institutional
investors who hold the membership interests in the owner lessors
are called owner participants. Equity funding by the owner
participants plus transaction expenses paid by the owner
participants totaled $299 million. The issuance and sale of
pass through certificates raised the remaining $1.2 billion
needed for the owner lessors to acquire the undivided interests.
The pass through certificates are not direct obligations of
GenOn Mid-Atlantic. Each pass through certificate represents a
fractional undivided interest in one of three pass through
trusts formed pursuant to three separate pass through trust
agreements between GenOn Mid-Atlantic and United States Bank
National Association (as successor in interest to State Street
Bank and Trust Company of Connecticut, National
Association), as pass through trustee. The property of the pass
through trusts consists of lessor notes. The lessor notes issued
by an owner lessor are secured by that owner lessors
undivided interest in the lease facilities and its rights under
the related lease and other financing documents. For
restrictions under these leases, see note 4.
Other
Operating Leases
The Companies have commitments under other operating leases with
various terms and expiration dates. GenOn Americas
Generations rent expense totaled $6 million,
$6 million and $5 million during 2010, 2009 and 2008,
respectively, related to these operating leases. GenOn
Mid-Atlantics rent expense totaled $6 million,
$5 million and $4 million during 2010, 2009 and 2008,
respectively, related to these operating leases.
Fuel
Commitments
The Companies have commitments under coal agreements of various
quantities and durations. At December 31, 2010, the maximum
remaining term under any individual fuel supply contract is
three years.
Maryland
Healthy Air Act
Maryland Healthy Air Act commitments reflect the remaining
expected payments for capital expenditures to comply with the
limitations for
SO2,
NOx
and mercury emissions under the Maryland Healthy Air Act. The
Companies completed the installation of the remaining pollution
control equipment related to compliance with the Maryland
Healthy Air Act in the fourth quarter of 2009. However,
provisions in the Companies construction contracts provide
that certain payments be made after final completion of the
project. See note 9 under Scrubber Contract
Litigation for further discussion.
Other
Other primarily represents the open purchase orders less
invoices received related to general procurement of products and
services purchased in the ordinary course of business. These
include construction, maintenance and labor activities at the
Companies generating facilities. Other also includes fuel
transportation agreements and limestone supply and
transportation agreements entered into by GenOn Energy
Management for GenOn Mid-Atlantic, GenOn Americas
Generations LTSA associated with the maintenance of a
turbine at its Kendall generating facility and miscellaneous
noncurrent liabilities.
F-66
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In order to sell power and purchase fuel in the forward markets
and perform other energy trading and marketing activities, GenOn
Americas Generation often is required to provide trade credit
support to its counterparties or make deposits with brokers. In
addition, GenOn Americas Generation often is required to provide
cash collateral for access to the transmission grid to
participate in power pools and for other operating activities.
In the event of default by the Companies, the counterparty can
apply cash collateral held to satisfy the existing amounts
outstanding under an open contract.
The following is a summary of cash collateral posted with
counterparties:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
Cash collateral postedenergy trading and marketing
|
|
$
|
80
|
|
|
$
|
41
|
|
Cash collateral postedother operating activities
|
|
|
40
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
120
|
|
|
$
|
83
|
|
|
|
|
|
|
|
|
|
|
|
|
(c)
|
Guarantees
(GenOn Americas Generation).
|
GenOn generally conducts its business through various
intermediate holding companies, including GenOn Americas
Generation, and various operating subsidiaries, which enter into
contracts as a routine part of their business activities. In
certain instances, the contractual obligations of such
subsidiaries are guaranteed by, or otherwise supported by, GenOn
or another of its subsidiaries, including by letters of credit
issued under the GenOn credit facilities.
In addition, GenOn Americas Generation and its subsidiaries
enter into various contracts that include indemnification and
guarantee provisions. Examples of these contracts include
financing and lease arrangements, purchase and sale agreements,
including for commodities, construction agreements and
agreements with vendors. Although the primary obligation of
GenOn Americas Generation or a subsidiary 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 GenOn Americas
Generations maximum potential liability cannot be
estimated because some of the underlying agreements contain no
limits on potential liability.
Upon issuance or modification of a guarantee, GenOn Americas
Generation determines if the obligation is subject to initial
recognition and measurement of a liability
and/or
disclosure of the nature and terms of the guarantee. Generally,
guarantees of the performance of a third party are subject to
the recognition and measurement, as well as the disclosure
provisions, of the accounting guidance related to guarantees.
Such guarantees must initially be recorded at fair value, as
determined in accordance with the accounting guidance. GenOn
Americas Generation did not have any guarantees at
December 31, 2010, that met the recognition requirements of
the accounting guidance.
Alternatively, guarantees between and on behalf of entities
under common control are subject only to the disclosure
provisions of the accounting guidance related to
guarantors accounting and disclosure requirements for
guarantees. GenOn Americas Generation must disclose information
as to the term of the guarantee and the maximum potential amount
of future gross payments (undiscounted) under the guarantee,
even if the likelihood of a claim is remote.
F-67
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Letters
of Credit and Surety Bonds
In December 2010, the GenOn North America letters of credit
issued under the senior secured revolving credit facility were
transferred to GenOn upon completion of the Merger. GenOn has
issued letters of credit in support of the obligations of the
Companies to perform under commodity agreements, financing or
lease arrangements and other commercial agreements.
At December 31, 2010 and 2009, GenOn Americas Generation
had obligations outstanding under surety bonds of
$7 million and $1 million, respectively.
Following is a summary of letters of credit issued and surety
bonds provided:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
Letters of creditenergy trading and
marketing(1)
|
|
$
|
63
|
|
|
$
|
51
|
|
Letters of creditrent
reserves(1)
|
|
|
101
|
|
|
|
101
|
|
Letters of creditother operating
activities(1)
|
|
|
31
|
|
|
|
47
|
|
Surety bonds
|
|
|
7
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
202
|
|
|
$
|
200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
At December 31, 2010, represents letters of credit posted
by GenOn for the benefit of GenOn Americas Generation. |
Purchase
and Sale Guarantees and Indemnifications
In connection with the purchase or sale of an asset or a
business by the Companies through a subsidiary, the Companies
are typically required to provide certain assurances to the
counterparties for the performance of the obligations of such a
subsidiary under the purchase or sale agreements. Such
assurances may take the form of a guarantee issued by the
Companies or a subsidiary on behalf of the obligor subsidiary.
The scope of such guarantees would typically include any
indemnity obligations owed to such counterparty. Although the
terms thereof vary in the scope, exclusions, thresholds and
applicable limits, the indemnity obligations of a seller
typically include liabilities incurred as a result of a breach
of a purchase and sale agreement, including the sellers
representations or warranties, unpaid and unreserved tax
liabilities and specified retained liabilities, if any. These
obligations generally have a term of 12 months from the
closing date and are intended to protect the buyer against
breaches of the agreement or risks that are difficult to predict
or estimate at the time of the transaction. In most cases, the
contract limits the liability of the seller. Although the
primary indemnity periods under the agreements for the sales of
the GenOn Americas six U.S. natural gas-fired
generating facilities have elapsed without any claims being
made, the Companies continues to have indefinite indemnity
obligations in respect of certain representations and covenants
that are typically not subject to lapse. No claims have been
made in respect thereof and the Companies do not expect that it
will be required to make any material payments under these
guarantee and indemnity provisions.
Commercial
Purchase and Sales Arrangements
In connection with the purchase and sale of fuel, emissions
allowances and energy to and from third parties with respect to
the operation of the Companies generating facilities, the
Companies may be required to guarantee a portion of the
obligations of certain of their subsidiaries. These obligations
may include liquidated damages payments or other unscheduled
payments. The majority of the current guarantees are set to
expire before the end of 2011, although the obligations of the
issuer will remain in effect until all the
F-68
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
liabilities created under the guarantee have been satisfied or
no longer exist. At December 31, 2010, a GenOn Americas
Generation subsidiary was contingently obligated for a total of
$46 million under such arrangements. In addition, GenOn was
contingently obligated for a total of $54 million under
such guarantees issued on behalf of GenOn Americas Generation
subsidiaries. The Companies do not expect that they will be
required to make any material payments under these guarantees.
Other
Guarantees and Indemnifications
The Companies debt agreements typically indemnify against
liabilities that arise from the preparation, entry into,
administration or enforcement of the agreement.
The Companies have issued guarantees in conjunction with certain
performance agreements and commodity and derivative contracts
and other contracts that provide financial assurance to third
parties on behalf of a subsidiary or an unconsolidated third
party. The guarantees on behalf of subsidiaries are entered into
primarily to support or enhance the creditworthiness otherwise
attributed to a subsidiary on a stand-alone basis, thereby
facilitating the extension of sufficient credit to accomplish
the relevant subsidiarys intended commercial purposes.
At December 31, 2010, a GenOn Americas Generation
subsidiary had issued $63 million of guarantees of
obligations that its subsidiaries may incur in connection with
construction agreements. In addition, GenOn Energy Holdings had
issued $22 million of guarantees on behalf of a GenOn
Americas Generation subsidiary related to settlement agreement
obligations. The Companies do not expect that they will be
required to make any material payments under these guarantees.
GenOn Americas Generation, through its subsidiaries,
participates in several power pools with RTOs. The rules of
these RTOs require that each participant indemnify the pool for
defaults by other members. Usually, the amount indemnified is
based upon the activity of the participant relative to the total
activity of the pool and the amount of the default.
Consequently, the amount of such indemnification by GenOn
Americas Generations subsidiaries cannot be quantified.
On a routine basis in the ordinary course of business, the
Companies and their subsidiaries indemnify financing parties and
consultants or other vendors who provide services to the
Companies. The Companies do not expect that it will be required
to make any material payments under these indemnity provisions.
Because some of the guarantees and indemnities the Companies
issues to third parties do not limit the amount or duration of
its obligations to perform under them, there exists a risk that
the Companies may have obligations in excess of the amounts
described above. For those guarantees and indemnities that do
not limit the Companies liability exposure, the Companies
may not be able to estimate its potential liability until a
claim is made for payment or performance, because of the
contingent nature of these contracts.
Except as otherwise noted, the Companies are unable to estimate
its maximum potential exposure under these agreements until an
event triggering payment occurs. The Companies do not expect to
make any material payments under these agreements.
|
|
8.
|
Segment
Reporting (GenOn Americas Generation)
|
GenOn Americas Generation previously had four reportable
segments: Mid-Atlantic, Northeast, California and Other
Operations. In the fourth quarter of 2010, in conjunction with
the Merger, GenOn Americas Generation began reporting in five
segments: Eastern PJM, Northeast, California, Energy Marketing
and Other Operations. GenOn Americas Generation reclassified
amounts for 2009 and 2008 to conform to the current segment
presentation. The segments were determined based on how the
business is managed and aligns with the information provided to
the chief operating decision maker for purposes of assessing
performance and
F-69
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
allocating resources. Generally, GenOn Americas
Generations segments are engaged in the sale of
electricity, capacity, ancillary and other energy services from
their generating facilities in hour-ahead, day-ahead and forward
markets in bilateral and ISO markets. GenOn Americas Generation
also engages in proprietary trading and fuel oil management.
Operating revenues consist of (a) power generation
revenues, (b) contracted and capacity revenues,
(c) fuel sales and proprietary trading revenues and
(d) power hedging revenues.
The Eastern PJM segment consists of four generating facilities
located in Maryland and Virginia with total net generating
capacity of 5,204 MW. The Northeast segment consists of
three generating facilities located in Massachusetts and one
generating facility located in New York with total net
generating capacity of 2,535 MW. For the year ended
December 31, 2008, the Northeast segment also included the
Lovett generating facility, which was shut down on
April 19, 2008. The California segment consists of three
generating facilities located in or near the City of
San Francisco, with total net generating capacity of
2,347 MW. Energy Marketing includes proprietary trading and
fuel oil management activities. Other Operations includes parent
company adjustments for affiliate transactions of GenOn Americas
Generation.
GenOn Americas Generations measure of profit or loss for
its reportable segments is operating income/loss. This measure
represents the lowest level of information that is provided to
the chief operating decision maker for GenOn Americas
Generations reportable segments. In the following tables,
eliminations are primarily related to intercompany sales of
emissions allowances, intercompany revenues and intercompany
cost of fuel.
F-70
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
GenOn
Americas Generation Operating Segments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eastern
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
PJM
|
|
|
Northeast
|
|
|
California
|
|
|
Marketing
|
|
|
Operations
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
(in millions)
|
|
|
2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenuesnonaffiliate(1)
|
|
$
|
347
|
|
|
$
|
15
|
|
|
$
|
118
|
|
|
$
|
1,622
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
2,102
|
|
Operating
revenuesaffiliate(2)
|
|
|
1,357
|
|
|
|
219
|
|
|
|
26
|
|
|
|
246
|
|
|
|
|
|
|
|
(1,845
|
)
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
1,704
|
|
|
|
234
|
|
|
|
144
|
|
|
|
1,868
|
|
|
|
|
|
|
|
(1,845
|
)
|
|
|
2,105
|
|
Cost of fuel, electricity and other
productsnonaffiliate(3)
|
|
|
18
|
|
|
|
2
|
|
|
|
|
|
|
|
826
|
|
|
|
|
|
|
|
|
|
|
|
846
|
|
Cost of fuel, electricity and other
productsaffiliate(4)
|
|
|
680
|
|
|
|
135
|
|
|
|
23
|
|
|
|
1,015
|
|
|
|
|
|
|
|
(1,845
|
)
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of fuel, electricity and other products
|
|
|
698
|
|
|
|
137
|
|
|
|
23
|
|
|
|
1,841
|
|
|
|
|
|
|
|
(1,845
|
)
|
|
|
854
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin (excluding depreciation and amortization)
|
|
|
1,006
|
|
|
|
97
|
|
|
|
121
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
1,251
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenancenonaffiliate
|
|
|
299
|
|
|
|
53
|
|
|
|
29
|
|
|
|
3
|
|
|
|
|
|
|
|
6
|
|
|
|
390
|
|
Operations and maintenanceaffiliate
|
|
|
194
|
|
|
|
55
|
|
|
|
43
|
|
|
|
7
|
|
|
|
|
|
|
|
(6
|
)
|
|
|
293
|
|
Depreciation and amortization
|
|
|
141
|
|
|
|
23
|
|
|
|
28
|
|
|
|
1
|
|
|
|
6
|
|
|
|
|
|
|
|
199
|
|
Impairment
losses(5)
|
|
|
1,153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28
|
|
|
|
(616
|
)
|
|
|
565
|
|
Gain on sales of assets, net
|
|
|
(3
|
)
|
|
|
(1
|
)
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
1,784
|
|
|
|
130
|
|
|
|
95
|
|
|
|
11
|
|
|
|
34
|
|
|
|
(616
|
)
|
|
|
1,438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
(778
|
)
|
|
$
|
(33
|
)
|
|
$
|
26
|
|
|
$
|
16
|
|
|
$
|
(34
|
)
|
|
$
|
616
|
|
|
$
|
(187
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
4,626
|
|
|
$
|
488
|
|
|
$
|
121
|
|
|
$
|
2,418
|
|
|
$
|
1,292
|
|
|
$
|
(1,132
|
)
|
|
$
|
7,813
|
|
Capital expenditures
|
|
$
|
233
|
|
|
$
|
11
|
|
|
$
|
2
|
|
|
$
|
1
|
|
|
$
|
5
|
|
|
$
|
|
|
|
$
|
252
|
|
|
|
|
(1) |
|
Includes unrealized gains of $123 million for Eastern PJM
and unrealized losses of $54 million for Energy Marketing. |
|
(2) |
|
Includes unrealized gains of $49 million for Energy
Marketing and unrealized losses of $43 million and
$3 million for Eastern PJM and Northeast, respectively. |
|
(3) |
|
Includes unrealized losses of $89 million for Energy
Marketing. |
|
(4) |
|
Includes unrealized losses of $73 million and
$16 million for Eastern PJM and Northeast, respectively,
and unrealized gains of $89 million for Energy Marketing. |
|
(5) |
|
Includes impairment loss of goodwill of $616 million
recorded at GenOn Mid-Atlantic on its stand alone balance sheet.
The goodwill does not exist at GenOn Americas Generations
consolidated balance sheet. As such, the goodwill impairment
loss is eliminated upon consolidation. |
F-71
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
GenOn
Americas Generation Operating Segments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eastern
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
PJM
|
|
|
Northeast
|
|
|
California
|
|
|
Marketing
|
|
|
Operations
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
(in millions)
|
|
|
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenuesnonaffiliate(1)
|
|
$
|
401
|
|
|
$
|
15
|
|
|
$
|
109
|
|
|
$
|
1,787
|
|
|
$
|
|
|
|
$
|
(3
|
)
|
|
$
|
2,309
|
|
Operating
revenuesaffiliate(2)
|
|
|
1,377
|
|
|
|
303
|
|
|
|
45
|
|
|
|
213
|
|
|
|
|
|
|
|
(1,938
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
1,778
|
|
|
|
318
|
|
|
|
154
|
|
|
|
2,000
|
|
|
|
|
|
|
|
(1,941
|
)
|
|
|
2,309
|
|
Cost of fuel, electricity and other
productsnonaffiliate(3)
|
|
|
17
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
686
|
|
|
|
|
|
|
|
|
|
|
|
701
|
|
Cost of fuel, electricity and other
productsaffiliate(4)
|
|
|
510
|
|
|
|
144
|
|
|
|
33
|
|
|
|
1,260
|
|
|
|
|
|
|
|
(1,938
|
)
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of fuel, electricity and other products
|
|
|
527
|
|
|
|
143
|
|
|
|
32
|
|
|
|
1,946
|
|
|
|
|
|
|
|
(1,938
|
)
|
|
|
710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin (excluding depreciation and amortization)
|
|
|
1,251
|
|
|
|
175
|
|
|
|
122
|
|
|
|
54
|
|
|
|
|
|
|
|
(3
|
)
|
|
|
1,599
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenancenonaffiliate
|
|
|
245
|
|
|
|
73
|
|
|
|
34
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
355
|
|
Operations and maintenanceaffiliate
|
|
|
189
|
|
|
|
53
|
|
|
|
40
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
290
|
|
Depreciation and amortization
|
|
|
98
|
|
|
|
18
|
|
|
|
22
|
|
|
|
1
|
|
|
|
3
|
|
|
|
|
|
|
|
142
|
|
Impairment
losses(5)
|
|
|
385
|
|
|
|
|
|
|
|
14
|
|
|
|
|
|
|
|
5
|
|
|
|
(183
|
)
|
|
|
221
|
|
Gain on sales of assets, net
|
|
|
(14
|
)
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
|
(22
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
903
|
|
|
|
140
|
|
|
|
110
|
|
|
|
12
|
|
|
|
8
|
|
|
|
(187
|
)
|
|
|
986
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
348
|
|
|
$
|
35
|
|
|
$
|
12
|
|
|
$
|
42
|
|
|
$
|
(8
|
)
|
|
$
|
184
|
|
|
$
|
613
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
5,807
|
|
|
$
|
616
|
|
|
$
|
139
|
|
|
$
|
2,782
|
|
|
$
|
407
|
|
|
$
|
(2,234
|
)
|
|
$
|
7,517
|
|
Capital expenditures
|
|
$
|
578
|
|
|
$
|
16
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
68
|
|
|
$
|
|
|
|
$
|
666
|
|
|
|
|
(1) |
|
Includes unrealized gains of $137 million for Eastern PJM
and unrealized losses of $139 million for Energy Marketing. |
|
(2) |
|
Includes unrealized gains of $26 million for Energy
Marketing and unrealized losses of $1 million and
$25 million for Eastern PJM and Northeast, respectively. |
|
(3) |
|
Includes unrealized gains of $49 million for Energy
Marketing. |
|
(4) |
|
Includes unrealized losses of $49 million for Energy
Marketing and unrealized gains of $8 million and
$41 million for Eastern PJM and Northeast, respectively. |
|
(5) |
|
Includes $183 million impairment loss of goodwill recorded
at GenOn Mid-Atlantic on its standalone balance sheet. The
goodwill does not exist at GenOn Americas Generations
consolidated balance sheet. As such, the goodwill impairment
loss is eliminated upon consolidation. |
F-72
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
GenOn
Americas Generation Operating Segments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eastern
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
PJM
|
|
|
Northeast
|
|
|
California
|
|
|
Marketing
|
|
|
Operations
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
(in millions)
|
|
|
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenuesnonaffiliate(1)
|
|
$
|
492
|
|
|
$
|
20
|
|
|
$
|
133
|
|
|
$
|
2,539
|
|
|
$
|
|
|
|
$
|
4
|
|
|
$
|
3,188
|
|
Operating
revenuesaffiliate(2)
|
|
|
1,787
|
|
|
|
597
|
|
|
|
53
|
|
|
|
8
|
|
|
|
|
|
|
|
(2,445
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
2,279
|
|
|
|
617
|
|
|
|
186
|
|
|
|
2,547
|
|
|
|
|
|
|
|
(2,441
|
)
|
|
|
3,188
|
|
Cost of fuel, electricity and other
productsnonaffiliate(3)
|
|
|
20
|
|
|
|
15
|
|
|
|
|
|
|
|
1,020
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
1,053
|
|
Cost of fuel, electricity and other
productsaffiliate(4)
|
|
|
545
|
|
|
|
423
|
|
|
|
59
|
|
|
|
1,424
|
|
|
|
|
|
|
|
(2,445
|
)
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of fuel, electricity and other products
|
|
|
565
|
|
|
|
438
|
|
|
|
59
|
|
|
|
2,444
|
|
|
|
|
|
|
|
(2,447
|
)
|
|
|
1,059
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin (excluding depreciation and amortization)
|
|
|
1,714
|
|
|
|
179
|
|
|
|
127
|
|
|
|
103
|
|
|
|
|
|
|
|
6
|
|
|
|
2,129
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenancenonaffiliate
|
|
|
239
|
|
|
|
103
|
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
372
|
|
Operations and maintenanceaffiliate
|
|
|
173
|
|
|
|
64
|
|
|
|
38
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
285
|
|
Depreciation and amortization
|
|
|
92
|
|
|
|
19
|
|
|
|
23
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
136
|
|
Loss (gain) on sales of assets, net
|
|
|
(8
|
)
|
|
|
(30
|
)
|
|
|
(7
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
8
|
|
|
|
(38
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses, net
|
|
|
496
|
|
|
|
156
|
|
|
|
84
|
|
|
|
11
|
|
|
|
|
|
|
|
8
|
|
|
|
755
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
1,218
|
|
|
$
|
23
|
|
|
$
|
43
|
|
|
$
|
92
|
|
|
$
|
|
|
|
$
|
(2
|
)
|
|
$
|
1,374
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
5,620
|
|
|
$
|
722
|
|
|
$
|
181
|
|
|
$
|
4,717
|
|
|
$
|
366
|
|
|
$
|
(3,054
|
)
|
|
$
|
8,552
|
|
Capital expenditures
|
|
$
|
641
|
|
|
$
|
25
|
|
|
$
|
6
|
|
|
$
|
1
|
|
|
$
|
47
|
|
|
$
|
|
|
|
$
|
720
|
|
|
|
|
(1) |
|
Includes unrealized gains of $525 million and
$315 million for Eastern PJM and Energy Marketing,
respectively. |
|
(2) |
|
Includes unrealized gains of $160 million and
$35 million for Eastern PJM and Northeast, respectively,
and unrealized losses of $195 million for Energy Marketing. |
|
(3) |
|
Includes unrealized losses of $54 million for Energy
Marketing. |
|
(4) |
|
Includes unrealized losses of $9 million and
$45 million for Eastern PJM and Northeast, respectively,
and unrealized gains of $54 million for Energy Marketing. |
F-73
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
Operating income (loss) for all segments
|
|
$
|
(187
|
)
|
|
$
|
613
|
|
|
$
|
1,374
|
|
Interest expense
|
|
|
200
|
|
|
|
137
|
|
|
|
189
|
|
Interest income
|
|
|
|
|
|
|
(1
|
)
|
|
|
(16
|
)
|
Other, net
|
|
|
9
|
|
|
|
1
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(396
|
)
|
|
$
|
476
|
|
|
$
|
1,198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9.
|
Litigation
and Other Contingencies
|
The Companies are involved in a number of legal proceedings. In
certain cases, plaintiffs seek to recover large and sometimes
unspecified damages, and some matters may be unresolved for
several years. The Companies cannot currently determine the
outcome of the proceedings described below or estimate the
reasonable amount or range of potential losses, if any, and
therefore have not made any provision for such matters unless
specifically noted below.
Scrubber
Contract Litigation
In January 2011, Stone & Webster, Inc., the EPC
contractor for the scrubber projects at the Chalk Point,
Dickerson and Morgantown facilities, filed two suits against
GenOn Mid-Atlantic and one suit against GenOn Chalk Point in the
United States District Court for the District of Maryland.
Stone & Webster, Inc. claims that it has not been paid
in accordance with the terms of the EPC agreements for the
scrubber projects and seeks a lien against the properties in the
amounts of $43.2 million at Chalk Point, $46.8 million
at Dickerson and $29.8 million at Morgantown. GenOn
Americas Generation and GenOn Mid-Atlantic dispute the
allegations. The current budget of $1.674 billion continues
to represent managements best estimate of the total
capital expenditures for compliance with the Maryland Healthy
Air Act.
Environmental
Matters
Riverkeeper Suit Against GenOn Lovett (GenOn Americas
Generation). In March 2005, Riverkeeper, Inc.
filed suit against GenOn Lovett in the United States District
Court for the Southern District of New York under the Clean
Water Act. The suit alleges that GenOn Lovett failed to
implement a marine life exclusion system at its former Lovett
facility and to perform monitoring for the exclusion of certain
aquatic organisms from the facilitys cooling water intake
structures in violation of GenOn Lovetts water discharge
permit issued by the State of New York. In November 2010, GenOn
Lovett and the plaintiff executed a stipulation settling the
litigation, which was approved by the court in February 2011.
The settlement requires GenOn Lovett to pay the plaintiff
$190,000 to fund fish studies or restoration projects in the
Hudson River and to reimburse plaintiff for its attorneys
fees.
GenOn Potomac River NOVs. In 2010, the
Virginia DEQ issued several NOVs to GenOn Potomac River.
Virginia DEQ asserted that GenOn Potomac River failed to include
required particulate matter data in compliance reports for
certain periods in 2009, and that, when the data were later
provided, they indicated that particulate matter emissions may
have exceeded the permitted limit. GenOn Potomac River thinks
that the data indicating exceedance of the limit are erroneous.
In another NOV, the Virginia DEQ asserted that on one day in
each of February 2010 and July 2010 the opacity readings from
the facility exceeded the applicable limits in several six
minute intervals. In a third NOV, the Virginia DEQ asserted that
GenOn Potomac River combusted used oils in the facilitys
boilers without authority under its permit and received one
shipment of coal that exceeded the maximum ash content allowed
under its permit. In a fourth NOV, issued in February
F-74
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
2011, the Virginia DEQ asserted that in January 2011 GenOn
Potomac River used a sorbent for the removal of
SO2
that was not permitted. Each of these NOVs states that such
violations can result in civil penalties of up to $32,500 per
day for each violation.
Montgomery County Carbon Emissions Levy. The
Dickerson facility is located in Montgomery County, Maryland,
and effective in May 2010, Montgomery County imposed a levy on
major emitters of
CO2
in the county of $5 per ton of
CO2
emitted. It is estimated that the
CO2
levy will impose an additional $10 million to
$15 million per year in levies owed to Montgomery County.
In June 2010, GenOn Mid-Atlantic filed an action against
Montgomery County in the United States District Court for the
District of Maryland seeking a determination that the
CO2
levy is unlawful. In its complaint, GenOn Mid-Atlantic contends
that the
CO2
levy violates its equal protection and due process rights,
imposes an unconstitutional excessive fine, is an
unconstitutional bill of attainder, constitutes a prohibited
special law under the Maryland Constitution, and is preempted by
Maryland law and the RGGI, an interstate compact to which
Maryland is a party. In July 2010, the district court ruled that
the
CO2
levy is a tax rather than a fee and granted a motion filed by
Montgomery County seeking dismissal of the suit under the
federal Tax Injunction Act for lack of jurisdiction. GenOn
Mid-Atlantic has appealed that ruling to the United States Court
of Appeals for the Fourth Circuit.
New Source Review Matters. The EPA and various
states are investigating compliance of coal-fueled electric
generating facilities with the pre-construction permitting
requirements of the Clean Air Act known as new source
review. In the past decade, the EPA has made information
requests concerning the Chalk Point, Dickerson, Morgantown and
Potomac River generating facilities. The Companies are
corresponding or have corresponded with the EPA regarding all of
these requests. The EPA agreed to share information relating to
its investigations with state environmental agencies.
Brandywine Fly Ash Facility. In April 2010,
the MDE filed a complaint against GenOn Mid-Atlantic and GenOn
MD Ash Management in the United States District Court for the
District of Maryland asserting violations of the Clean Water Act
and Marylands Water Pollution Control Law. The MDE
contends that the operation of the Brandywine fly ash facility
has resulted in discharges of pollutants that violate
Marylands water quality criteria. The complaint requests
that the court, among other things, (a) enjoin further
disposal of coal combustion waste at the Brandywine facility,
(b) require the defendants to close and cap the existing
open disposal cells within one year, (c) impose civil
penalties of up to $37,500 per day per violation and
(d) award them attorneys fees. GenOn MD Ash
Management and GenOn Mid-Atlantic dispute the allegations. In
September 2010, four environmental advocacy groups became
intervening parties in the proceeding.
Faulkner Fly Ash Facility. In May 2008, the
MDE filed a complaint against GenOn Mid-Atlantic and GenOn MD
Ash Management in the Circuit Court for Charles County, Maryland
alleging violations of Marylands water pollution laws. The
MDE contends that the operation of the Faulkner fly ash facility
has resulted in the discharge of pollutants that exceed
Marylands water quality criteria and without the
appropriate NPDES permit. The MDE also alleges that the
defendants failed to perform certain sampling and reporting
required under an applicable NPDES permit. The MDE complaint
requests that the court (a) prohibit continuation of the
alleged unpermitted discharges, (b) require the defendants
to cease from further disposal of any coal combustion byproducts
at the Faulkner facility and close and cap the existing disposal
cells and (c) assess civil penalties of up to $10,000 per
day per violation. In July 2008, GenOn MD Ash Management and
GenOn Mid-Atlantic filed a motion to dismiss the complaint,
arguing that the discharges are permitted by a December 2000
Consent Order. In January 2011, MDE sought to dismiss without
prejudice its complaint. MDE also informed GenOn that it intends
to file a similar lawsuit in federal court.
F-75
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Westland Fly Ash Facility. In January 2011,
MDE informed GenOn Americas Generation and GenOn Mid-Atlantic
that MDE intends to file a complaint related to alleged
violations of Marylands water pollution laws at GenOn
Mid-Atlantics Westland fly ash facility located in
Montgomery County, Maryland.
Ash Disposal Facility Closures. GenOn Americas
Generation and GenOn Mid-Atlantic are responsible for
environmental costs related to the future closures of several
ash disposal facilities. GenOn Americas Generation recorded the
estimated discounted costs ($9 million at December 31,
2010 and 2009) associated with these environmental
liabilities as part of its asset retirement obligations. GenOn
Mid-Atlantic recorded the estimated discounted costs
($7 million at December 31, 2010 and
2009) associated with these environmental liabilities as
part of its asset retirement obligations. See note 3(e).
Chapter 11
Proceedings
In July 2003, and various dates thereafter, GenOn Energy
Holdings and certain of its subsidiaries, (collectively, the
Mirant Debtors), including the Companies and their subsidiaries,
filed voluntary petitions for relief under Chapter 11 of
the United States Bankruptcy Code in the Bankruptcy Court. GenOn
Energy Holdings, the Companies and most of the other Mirant
Debtors emerged from bankruptcy on January 3, 2006, when
the Plan became effective. The remaining Mirant Debtors emerged
from bankruptcy on various dates in 2007. Approximately 461,000
of the shares of GenOn Energy Holdings common stock to be
distributed under the Plan have not yet been distributed and
have been reserved for distribution with respect to claims
disputed by the Mirant Debtors that have not been resolved. Upon
the Merger, those reserved shares converted into a reserve for
approximately 1.3 million shares of GenOn common stock.
Under the terms of the Plan, upon the resolution of such a
disputed claim, the claimant will receive the same pro rata
distributions of GenOn common stock, cash, or both as previously
allowed claims, regardless of the price at which the GenOn
common stock is trading at the time the claim is resolved.
Complaint
Challenging Capacity Rates Under the RPM Provisions of
PJMs Tariff
In May 2008, several parties, including the state public utility
commissions of Maryland, Pennsylvania, New Jersey and Delaware,
ratepayer advocates, certain electric cooperatives, various
groups representing industrial electricity users, and federal
agencies (the RPM Buyers), filed a complaint with the FERC
asserting that capacity auctions held to determine capacity
payments under the RPM provisions of PJMs tariff had
produced rates that were unjust and unreasonable. PJM conducted
the capacity auctions that are the subject of the complaint to
set the capacity payments in effect under the RPM provisions of
its tariff for twelve month periods beginning June 1, 2008,
June 1, 2009, and June 1, 2010. The RPM Buyers allege
that (a) the times between when the auctions were held and
the periods that the resulting capacity rates would be in effect
were too short to allow competition from new resources in the
auctions, (b) the administrative process established under
the RPM provisions of PJMs tariff was inadequate to
restrain the exercise of market power by the withholding of
capacity to increase prices, and (c) the locational pricing
established under the RPM provisions of PJMs tariff
created opportunities for sellers to raise prices while serving
no legitimate function. The RPM Buyers asked the FERC to reduce
significantly the capacity rates established by the capacity
auctions and to set June 1, 2008, as the date beginning on
which any rates found by the FERC to be excessive would be
subject to refund. If the FERC were to reduce the capacity
payments set through the capacity auctions to the rates proposed
by the RPM Buyers, the capacity revenue the Companies have
received or expect to receive for the period June 1, 2008
through May 31, 2011, would be reduced by approximately
$600 million. In September 2008, the FERC issued an order
dismissing the complaint. The FERC found that no party had
violated the RPM provisions of PJMs tariff and that the
prices determined during the auctions were in accordance with
the tariffs provisions. The RPM Buyers filed a request for
rehearing, which the FERC denied in June 2009. Certain of the
RPM Buyers have appealed the orders entered by the FERC to the
United States
F-76
GENON
AMERICAS GENERATION, LLC AND SUBSIDIARIES
GENON
MID-ATLANTIC, LLC AND SUBSIDIARIES
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Court of Appeals for the Fourth Circuit. That appeal was
transferred to the United States Court of Appeal for the
District of Columbia Circuit. On February 8, 2011, the D.C.
Circuit affirmed the FERC rulings.
|
|
10.
|
Settlements
and Other Charges
|
Potomac
River Settlement
In July 2008, the City of Alexandria, Virginia (in which the
Potomac River generating facility is located) and GenOn Potomac
River entered into an agreement pursuant to which GenOn Potomac
River committed to spend $34 million over several years to
reduce particulate emissions. The $34 million was placed in
escrow and included in funds on deposit and other noncurrent
assets in the consolidated balance sheets. At December 31,
2010, the balance in the escrow account was $32 million.
GenOn
Potrero Settlement with City of San Francisco (GenOn
Americas Generation)
GenOn Potrero and the City and County of San Francisco,
California entered into a settlement agreement (the Potrero
Settlement) that became effective in November 2009 upon its
approval by the Citys Board of Supervisors and Mayor.
Among other things, the Potrero Settlement obligates GenOn
Potrero to close permanently each of the remaining units of the
Potrero generating facility at the end of the year in which the
CAISO determines that such unit is no longer needed to maintain
the reliable operation of the electricity system. The agreement
also bars GenOn Potrero from building any additional generating
facilities on the site of the Potrero generating facility. In
September 2010, the CAISO notified GenOn Potrero that it was
designating all four units of the Potrero generating facility as
needed for reliability purposes in 2011. The subsequent
completion of the TransBay Cable project, an underwater electric
transmission cable that became fully operational in November
2010, eliminated the need for unit 3 of the Potrero generating
facility for reliability purposes. The replacement in late 2010
of two underground transmission cables eliminated the need for
units 4, 5 and 6 for reliability purposes. In December 2010, the
CAISO provided GenOn Potrero with the requisite notice of
termination of the RMR agreement. On January 19, 2011, at
the request of GenOn Potrero, the FERC approved changes to GenOn
Potreros RMR agreement to allow the CAISO to terminate the
RMR agreement effective February 28, 2011. On
February 28, 2011, the Potrero facility was shut down.
F-77
Report of
Independent Registered Public Accounting Firm
The Member
GenOn Americas Generation, LLC:
We have audited and reported separately herein on the
consolidated financial statements of GenOn Americas Generation,
LLC (a wholly-owned indirect subsidiary of GenOn Energy, Inc.)
and subsidiaries (the Company) as of December 31, 2010 and
2009, and the related consolidated statements of operations,
members equity and cash flows for each of the years in the
three-year period ended December 31, 2010. In connection
with our audits of the aforementioned consolidated financial
statements, we also audited the related financial statement
schedules as listed within Item 15. These financial
statement schedules are the responsibility of the Companys
management. Our responsibility is to express an opinion on these
financial statement schedules based on our audits.
In our opinion, such financial statement schedules, when
considered in relation to the basic consolidated financial
statements taken as a whole, present fairly, in all material
respects, the information set forth therein.
Houston, Texas
March 1, 2011
F-78
Report of
Independent Registered Public Accounting Firm
The Member
GenOn Mid-Atlantic, LLC:
We have audited and reported separately herein on the
consolidated financial statements of GenOn Mid-Atlantic, LLC (a
wholly-owned indirect subsidiary of GenOn Energy, Inc.) and
subsidiaries (the Company) as of December 31, 2010 and
2009, and the related consolidated statements of operations,
members equity and cash flows for each of the years in the
three-year period ended December 31, 2010. In connection
with our audits of the aforementioned consolidated financial
statements, we also audited the related financial statement
schedule as listed within Item 15. This financial statement
schedule is the responsibility of the Companys management.
Our responsibility is to express an opinion on the financial
statement schedule based on our audits.
In our opinion, this financial statement schedule, when
considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly, in all material
respects, the information set forth therein.
Houston, Texas
March 1, 2011
F-79
Schedule I
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
Operating income (loss)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Other Expense (Income), net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity losses (earnings) of subsidiaries
|
|
|
276
|
|
|
|
(597
|
)
|
|
|
(1,337
|
)
|
Interest expense-nonaffiliate
|
|
|
120
|
|
|
|
121
|
|
|
|
134
|
|
Interest expense-affiliate
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Other, net
|
|
|
(1
|
)
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense (income), net
|
|
|
395
|
|
|
|
(476
|
)
|
|
|
(1,198
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(395
|
)
|
|
|
476
|
|
|
|
1,198
|
|
Provision for income taxes
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(396
|
)
|
|
$
|
476
|
|
|
$
|
1,198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the
registrants condensed financial information.
F-80
Schedule I
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(in millions)
|
|
|
ASSETS
|
Current Assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
150
|
|
|
$
|
1
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
150
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
Noncurrent Assets:
|
|
|
|
|
|
|
|
|
Investments in affiliates
|
|
|
4,846
|
|
|
|
4,331
|
|
Debt issuance costs, net
|
|
|
5
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent assets
|
|
|
4,851
|
|
|
|
4,337
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
5,001
|
|
|
$
|
4,338
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS EQUITY
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
Current portion of long-term debt
|
|
$
|
535
|
|
|
$
|
|
|
Accounts payable and accrued liabilities
|
|
|
23
|
|
|
|
25
|
|
Payableaffiliates
|
|
|
9
|
|
|
|
102
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
567
|
|
|
|
127
|
|
|
|
|
|
|
|
|
|
|
Noncurrent Liabilities:
|
|
|
|
|
|
|
|
|
Long-term debt, net of current portion
|
|
|
848
|
|
|
|
1,382
|
|
Other
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent liabilities
|
|
|
849
|
|
|
|
1,382
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
Members Equity:
|
|
|
|
|
|
|
|
|
Members interest
|
|
|
3,585
|
|
|
|
3,109
|
|
Preferred stock in affiliate
|
|
|
|
|
|
|
(280
|
)
|
|
|
|
|
|
|
|
|
|
Total members equity
|
|
|
3,585
|
|
|
|
2,829
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Members Equity
|
|
$
|
5,001
|
|
|
$
|
4,338
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the
registrants condensed financial information.
F-81
Schedule I
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Cash Flows from Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
221
|
|
|
$
|
116
|
|
|
$
|
276
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Repayment of notes receivables affiliate
|
|
|
|
|
|
|
|
|
|
|
14
|
|
Capital contributions made to subsidiaries
|
|
|
(1,079
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) investing activities
|
|
|
(1,079
|
)
|
|
|
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Redemption of preferred stock in affiliate
|
|
|
150
|
|
|
|
|
|
|
|
|
|
Purchases of long-term debt
|
|
|
|
|
|
|
|
|
|
|
(276
|
)
|
Capital contributions from member
|
|
|
1,079
|
|
|
|
|
|
|
|
282
|
|
Distributions to member
|
|
|
(222
|
)
|
|
|
(115
|
)
|
|
|
(297
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
1,007
|
|
|
|
(115
|
)
|
|
|
(291
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents
|
|
|
149
|
|
|
|
1
|
|
|
|
(1
|
)
|
Cash and Cash Equivalents, beginning of year
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents, end of year
|
|
$
|
150
|
|
|
$
|
1
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosures:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest, net of amounts capitalized
|
|
$
|
119
|
|
|
$
|
119
|
|
|
$
|
137
|
|
Supplemental Disclosures for Non-Cash Investing and Financing
Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Conversion to equity of notes payable to subsidiary
|
|
$
|
93
|
|
|
$
|
|
|
|
$
|
|
|
The accompanying notes are an integral part of the
registrants condensed financial information.
F-82
Schedule I
December 31, 2010, 2009 and 2008
|
|
1.
|
Background
and Basis of Presentation
|
Background
The condensed parent company financial statements have been
prepared in accordance with
Rule 12-04,
Schedule I of
Regulation S-X,
as the restricted net assets of GenOn Americas Generation,
LLCs subsidiaries exceed 25 percent of the
consolidated net assets of GenOn Americas Generation,
LLCs. These statements should be read in conjunction with
the consolidated statements and notes thereto of GenOn Americas
Generation.
GenOn Americas Generation, LLC is a Delaware limited liability
company and indirect wholly-owned subsidiary of GenOn.
GenOn, a Delaware corporation, was formed in August 2000 by
CenterPoint (then known as Reliant Energy, Incorporated) in
connection with the planned separation of its regulated and
unregulated operations. CenterPoint transferred substantially
all of its unregulated businesses, including the name Reliant
Energy to the company now named GenOn Energy, Inc. In May 2001,
Reliant Energy (then known as Reliant Resources, Inc.) became a
publicly traded company and in September 2002, CenterPoint
distributed its remaining ownership of Reliant Energys
common stock to its stockholders. RRI Energy changed its name
from Reliant Energy, Inc. effective May 2, 2009 in
connection with the sale of its retail business. GenOn changed
its name from RRI Energy, Inc. effective December 3, 2010.
Merger
of Mirant and RRI Energy
On December 3, 2010, Mirant and RRI Energy completed the
Merger contemplated by the Merger Agreement. Upon completion of
the Merger, RRI Energy Holdings, Inc. (Merger Sub), a direct and
wholly-owned subsidiary of RRI Energy merged with and into
Mirant, with Mirant continuing as the surviving corporation and
a wholly-owned subsidiary of RRI Energy. Each of Mirant and RRI
Energy received legal opinions that the Merger qualified as a
tax-free reorganization under the IRC. Accordingly, none of RRI
Energy, Merger Sub, Mirant or any of the Mirant stockholders
will recognize any gain or loss in the transaction, except that
Mirant stockholders will recognize a gain or loss with respect
to cash received in lieu of fractional shares of RRI Energy
common stock. Upon the closing of the Merger, each issued and
outstanding share of Mirant common stock, including grants of
restricted common stock, automatically converted into
2.835 shares of common stock of RRI Energy based on the
Exchange Ratio. Additionally, upon the closing of the Merger,
RRI Energy was renamed GenOn. Mirant stock options and other
equity awards converted upon completion of the Merger into stock
options and equity awards with respect to GenOn common stock,
after giving effect to the Exchange Ratio. At the close of the
Merger, former Mirant stockholders owned approximately 54% of
the equity of the combined company and former RRI Energy
stockholders owned approximately 46% of the equity of the
combined company. See note 4 for additional information on
the related debt transactions in the consolidated financial
statements.
Basis
of Presentation
The condensed financial statements presented herein are the
condensed financial statements and other financial information
of GenOn Americas Generation, LLC.
Equity earnings of subsidiaries consist of earnings of direct
and indirect subsidiaries of GenOn Americas Generation, LLC
(parent).
F-83
GENON
AMERICAS GENERATION, LLC (PARENT)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
NOTES TO REGISTRANTS CONDENSED FINANCIAL
STATEMENTS (Continued)
In addition, certain prior period amounts have been reclassified
to conform to the current period financial statement
presentation.
During 2010, 2009 and 2008, GenOn Americas Generation, LLC
received cash dividends from its subsidiaries of
$341 million, $235 million and $414 million,
respectively.
For a discussion of GenOn Americas Generation, LLCs
long-term debt, see note 4 to GenOn Americas
Generations consolidated financial statements.
GenOn
Americas Generation
Debt maturities of GenOn Americas LLC, at December 31, 2010
are (in millions):
|
|
|
|
|
2011
|
|
$
|
535
|
|
2012
|
|
|
|
|
2013
|
|
|
|
|
2014
|
|
|
|
|
2015
|
|
|
|
|
2016 and thereafter
|
|
|
850
|
|
|
|
|
|
|
Total
|
|
$
|
1,385
|
|
|
|
|
|
|
|
|
3.
|
Commitments
and Contingencies
|
At December 31, 2010, GenOn Americas Generation, LLC
(parent) did not have any guarantees.
See notes 7 and 9 to GenOn Americas Generations
consolidated financial statements for a detailed discussion of
GenOn Americas Generation, LLCs contingencies.
F-84
Schedule II
VALUATION
AND QUALIFYING ACCOUNTS
GenOn
Americas Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010, 2009 and 2008
|
|
|
|
|
|
|
Additions
|
|
|
|
|
|
|
|
|
|
Balance at
|
|
|
Charged
|
|
|
Charged to
|
|
|
|
|
|
Balance at
|
|
|
|
Beginning
|
|
|
to
|
|
|
Other
|
|
|
|
|
|
End of
|
|
Description
|
|
of Period
|
|
|
Income
|
|
|
Accounts
|
|
|
Deductions
|
|
|
Period
|
|
|
|
(in millions)
|
|
|
Provision for uncollectible accounts (current)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
$
|
3
|
|
|
$
|
6
|
|
|
$
|
|
|
|
$
|
(5
|
)
|
|
$
|
4
|
|
2009
|
|
|
12
|
|
|
|
9
|
|
|
|
|
|
|
|
(18
|
)
|
|
|
3
|
|
2008
|
|
|
8
|
|
|
|
5
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
12
|
|
Provision for uncollectible accounts (noncurrent)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
$
|
11
|
|
|
$
|
18
|
|
|
$
|
|
|
|
$
|
(14
|
)
|
|
$
|
15
|
|
2009
|
|
|
42
|
|
|
|
13
|
|
|
|
|
|
|
|
(44
|
)
|
|
|
11
|
|
2008
|
|
|
1
|
|
|
|
41
|
|
|
|
|
|
|
|
|
|
|
|
42
|
|
|
|
|
(1) |
|
Deductions in 2010 and 2009 consisted primarily of reversals of
credit reserves for derivative contract assets. Deductions in
2008 consisted primarily of reductions in or write-offs of
allowances for uncollectible accounts and notes receivable. |
Schedule II
GenOn
Mid-Atlantic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010, 2009 and 2008
|
|
|
|
|
|
|
Additions
|
|
|
|
|
|
|
|
|
|
Balance at
|
|
|
Charged
|
|
|
Charged to
|
|
|
|
|
|
Balance at
|
|
|
|
Beginning
|
|
|
to
|
|
|
Other
|
|
|
|
|
|
End of
|
|
Description
|
|
of Period
|
|
|
Income
|
|
|
Accounts
|
|
|
Deductions
|
|
|
Period
|
|
|
|
(in millions)
|
|
|
Provision for uncollectible accounts (current)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
$
|
2
|
|
|
$
|
6
|
|
|
$
|
|
|
|
$
|
(4
|
)
|
|
$
|
4
|
|
2009
|
|
|
9
|
|
|
|
8
|
|
|
|
|
|
|
|
(15
|
)
|
|
|
2
|
|
2008
|
|
|
2
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
Provision for uncollectible accounts (noncurrent)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
$
|
11
|
|
|
$
|
18
|
|
|
$
|
|
|
|
$
|
(14
|
)
|
|
$
|
15
|
|
2009
|
|
|
42
|
|
|
|
13
|
|
|
|
|
|
|
|
(44
|
)
|
|
|
11
|
|
2008
|
|
|
1
|
|
|
|
42
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
42
|
|
|
|
|
(1) |
|
Deductions in 2010 and 2009 consisted primarily of reversals of
credit reserves for derivative contract assets. Deductions in
2008 consisted primarily of reductions in or write-offs of
allowances for uncollectible accounts and notes receivable. |
F-85
GenOn
Americas Generation
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Exhibit Name
|
|
|
1
|
.1
|
|
Purchase Agreement, dated at October 2, 2001, among Mirant
Americas Generation, Inc. and Salomon Smith Barney Inc., Banc of
America Securities LLC, Blaylock & Partners, L.P.,
Scotia Capital (USA) Inc., TD Securities (USA) Inc. and
Tokyo-Mitsubishi International plc, as Initial Purchaser
(Incorporated herein by reference to Exhibit 1.1 to
Registrants Registration Statement on
Form S-4/A
Amendment No. 1, Registration
No. 333-85124)
|
|
2
|
.1
|
|
Purchase and Sale Agreement by and between Mirant Americas, Inc.
and LS Power Acquisition Co. I, LLC, dated at
January 15, 2007 (Incorporated herein by reference to
Exhibit 2.1 to the Mirant Corporation Current Report on
Form 8-K
filed January 18, 2007)
|
|
3
|
.1
|
|
Certificate of Formation for Mirant Americas Generation, LLC,
filed with the Delaware Secretary of State dated at
November 1, 2001 (Incorporated herein by reference to
Exhibit 3.1 to Registrants Quarterly Report on
Form 10-Q
filed November 9, 2001, File
No. 333-63240)
|
|
3
|
.2A1*
|
|
Certificate of Amendment to Certificate of Formation of Mirant
Americas Generation, LLC, filed with the Delaware Secretary of
State dated at December 3, 2010
|
|
3
|
.3A1*
|
|
Second Amended and Restated Limited Liability Agreement for
GenOn Americas Generation, LLC dated December 3, 2010
|
|
4
|
.1
|
|
Indenture between Mirant Americas Generation, Inc. and Bankers
Trust Company, as trustee, relating to Senior Notes, dated
at May 1, 2001 (Incorporated herein by reference to
Exhibit 4.1 to the Registrants Registration Statement
on
Form S-4,
Registration
No. 333-63240)
|
|
4
|
.2
|
|
Second Supplemental Indenture relating to Senior
Notes 8.300% due 2011, dated at May 1, 2001
(Incorporated herein by reference to Exhibit 4.3 to
Registrants Registration Statement on
Form S-4,
Registration
No. 333-63240)
|
|
4
|
.3
|
|
Third Supplemental Indenture from Mirant Americas Generation,
Inc. to Bankers Trust Company, relating to
9.125% Senior Notes due 2031, dated at May 1, 2001
(Incorporated herein by reference to Exhibit 4.4 to
Registrants Registration Statement on
Form S-4,
Registration
No. 333-63240)
|
|
4
|
.4
|
|
Fifth Supplemental Indenture from Mirant Americas Generation,
Inc. to Bankers Trust Company, dated at October 9,
2001 (Incorporated herein by reference to Exhibit 4.6 to
Registrants Registration Statement on
Form S-4/A
Amendment No. 1, Registration
No. 333-85124)
|
|
4
|
.5
|
|
Form of Sixth Supplemental Indenture from Mirant Americas
Generation LLC to Bankers Trust Company, dated at
November 1, 2001 (Incorporated herein by reference to
Exhibit 4.6 to the Mirant Corporation Annual Report on
Form 10-K
filed February 27, 2009)
|
|
4
|
.6
|
|
Form of Seventh Supplemental Indenture from Mirant Americas
Generation LLC to Wells Fargo Bank National Association, dated
at January 3, 2006 (Incorporated herein by reference to
Exhibit 4.1 to Registrants Quarterly Report on
Form 10-Q
filed May 14, 2007)
|
|
4
|
.7
|
|
Senior Note Indenture between Mirant North America, LLC, Mirant
North America Escrow, LLC, MNA Finance Corp. and Law Debenture
Trust Company of New York, as trustee (Incorporated herein
by reference to Exhibit 4.2 to Registrants Annual
Report on
Form 10-K
filed March 14, 2006)
|
|
4
|
.8
|
|
Registration Rights Agreement, dated at October 9, 2001,
among Mirant Americas Generation, Inc., Salomon Smith Barney
Inc. and Banc of America Securities LLC, Blaylock &
Partners, L.P., Scotia Capital (USA) Inc., TD Securities (USA)
Inc. and Tokyo-Mitsubishi International plc, as Initial
Purchasers (Incorporated herein by reference to Exhibit 4.8
to Registrants Registration Statement on
Form S-4/A
Amendment No. 1, Registration
No. 333-85124)
|
|
10
|
.1
|
|
Engineering, Procurement and Construction Agreement, dated at
July 30, 2007, between Mirant Mid-Atlantic, LLC, Mirant
Chalk Point, LLC and Stone & Webster, Inc.
(Incorporated herein by reference to Exhibit 10.1 to the
Mirant Corporation Quarterly Report on
Form 10-Q
filed November 6, 2009)
|
|
10
|
.2
|
|
Membership Interest Purchase and Sale Agreement, dated at
January 31, 2007, between Mirant New York, Inc. and
Alliance Energy Renewables, LLC (Incorporated herein by
reference to Exhibit 10.1 to Registrants Quarterly
Report on
Form 10-Q
filed May 14, 2007)
|
F-86
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Exhibit Name
|
|
|
10
|
.3
|
|
Settlement and Release of Claims Agreement, by and among the
Mirant Parties, the California Parties and OMOI, dated at
January 13, 2005 (Incorporated herein by reference to
Exhibit 10.39 to the Mirant Corporation Annual Report on
Form 10-K
filed March 14, 2005, File
No. 001-16107)
|
|
10
|
.4
|
|
Credit Agreement among Mirant North America, LLC, JPMorgan Chase
Bank, N.A as administrative agent and Deutsche Bank Securities
Inc. and Goldman Sachs Credit Partners L.P., as co-syndication
agents, dated at January 3, 2006 (Incorporated herein by
reference to Exhibit 10.2 to the Mirant Corporation
Quarterly Report on
Form 10-Q
filed November 6, 2009)
|
|
10
|
.5
|
|
Administrative Services Agreement dated at January 3, 2006
by and between Mirant Americas Generation, LLC and Mirant
Services, LLC (Incorporated herein by reference to
Exhibit 10.5 to Registrants Annual Report on
Form 10-K
filed March 31, 2006)
|
|
10
|
.6
|
|
Power Sale, Fuel Supply and Services Agreement dated at
January 3, 2006 among Mirant Americas Energy Marketing, LP,
Mirant Bowline, LLC, Mirant Lovett, LLC, and Mirant NY-Gen, LLC
(Incorporated herein by reference to Exhibit 10.6 to
Registrants Annual Report on
Form 10-K
filed March 31, 2006)
|
|
10
|
.7
|
|
Power Sale, Fuel Supply and Services Agreement dated at
January 3, 2006 among Mirant Americas Energy Marketing, LP,
Mirant Canal, LLC, and Mirant Kendall, LLC (Incorporated herein
by reference to Exhibit 10.7 to Registrants Annual
Report on
Form 10-K
filed March 31, 2006)
|
|
10
|
.8
|
|
Power Sale, Fuel Supply and Services Agreement dated at
January 3, 2006 by and between Mirant Americas Energy
Marketing, LP and Mirant Chalk Point, LLC (Incorporated herein
by reference to Exhibit 10.8 to Registrants Annual
Report on
Form 10-K
filed March 31, 2006)
|
|
10
|
.9
|
|
Power Sale, Fuel Supply and Services Agreement dated at
January 3, 2006 by and between Mirant Americas Energy
Marketing, LP and Mirant Mid-Atlantic, LLC (Incorporated herein
by reference to Exhibit 10.9 to Registrants Annual
Report on
Form 10-K
filed March 31, 2006)
|
|
10
|
.10
|
|
Power Sale, Fuel Supply and Services Agreement dated at
January 3, 2006 by and between Mirant Americas Energy
Marketing, LP and Mirant Potomac River, LLC (Incorporated herein
by reference to Exhibit 10.10 to Registrants Annual
Report on
Form 10-K
filed March 31, 2006)
|
|
10
|
.11
|
|
Power Sale, Fuel Supply and Services Agreement dated at
January 3, 2006 among Mirant Americas Energy Marketing, LP,
Mirant Delta, LLC, and Mirant Potrero, LLC (Incorporated herein
by reference to Exhibit 10.12 to Registrants Annual
Report on
Form 10-K
filed March 31, 2006)
|
|
10
|
.12
|
|
Power Sale, Fuel Supply and Services Agreement dated at
January 3, 2006 by and between Mirant Americas Energy
Marketing, LP and Mirant Zeeland, LLC (Incorporated herein by
reference to Exhibit 10.13 to Registrants Annual
Report on
Form 10-K
filed March 31, 2006)
|
|
10
|
.13
|
|
Mirant Corporation 2005 Omnibus Incentive Compensation Plan,
effective December 2005 (Incorporated herein by reference to
Exhibit 10.1 to the Mirant Corporation Current Report on
Form 8-K
filed January 3, 2006, File
No. 001-16107)
|
|
12
|
.1
|
|
Statement of Ratio Earnings to Fixed Charges (Incorporated
herein by reference to Exhibit 12.1 to Registrants
Registration Statement on
Form S-4/A
Amendment No. 1, Registration
No. 333-85124)
|
|
21
|
.1*
|
|
Subsidiaries of GenOn Americas Generation, LLC
|
|
31
|
.1A1*
|
|
Certification of Chief Executive Officer pursuant to
Rule 13a-14(a)
under Securities Exchange Act of 1934
|
|
31
|
.2A3*
|
|
Certification of Chief Financial Officer pursuant to
Rule 13a-14(a)
under Securities Exchange Act of 1934
|
|
32
|
.1A1*
|
|
Certification of the Chief Executive Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
(Rule 13a-14(b))
|
|
32
|
.2A3*
|
|
Certification of the Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
(Rule 13a-14(b))
|
|
|
|
* |
|
Asterisk indicates exhibits filed herewith. |
|
|
|
The Registrant has requested confidential treatment for certain
portions of this Exhibit pursuant to
Rule 24b-2
under the Securities Exchange Act of 1934, as amended. |
F-87
GenOn
Mid-Atlantic
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Exhibit Name
|
|
|
3
|
.1
|
|
Certificate of Formation of Southern Energy Mid-Atlantic, LLC,
dated at July 12, 2000 (Incorporated herein by reference to
Exhibit 3.1 to Registrants Registration Statement on
Form S-4,
Registration No. 333-61668)
|
|
3
|
.2A2*
|
|
Certificate of Amendment to Certificate of Formation of Mirant
Mid-Atlantic, LLC, filed with the Delaware Secretary of State
dated at January 20, 2011
|
|
3
|
.3A2*
|
|
Second Amended and Restated Limited Liability Company Agreement
of GenOn Mid-Atlantic, LLC dated January 20, 2011
|
|
4
|
.1
|
|
Form of 8.625% Series A Pass Through Certificate (Incorporated
herein by reference to Exhibit 4.1 to Registrants
Registration Statement on Form S-4, Registration No. 333-61668)
|
|
4
|
.2
|
|
Form of 9.125% Series B Pass Through Certificate (Incorporated
herein by reference to Exhibit 4.2 to Registrants
Registration Statement on Form S-4, Registration No. 333-61668)
|
|
4
|
.3
|
|
Form of 10.060% Series C Pass Through Certificate (Incorporated
herein by reference to Exhibit 4.3 to Registrants
Registration Statement on Form S-4, Registration No. 333-61668)
|
|
4
|
.4(a)
|
|
Pass Through Trust Agreement A between Southern Energy
Mid-Atlantic, LLC and State Street Bank and Trust Company of
Connecticut, National Association, as Pass Through Trustee,
dated at December 18, 2000 (Incorporated herein by reference to
Exhibit 4.4(a) to Registrants Registration Statement on
Form S-4, Registration No. 333-61668)
|
|
4
|
.4(b)
|
|
Schedule identifying substantially identical agreement to Pass
Through Trust Agreement A constituting Exhibit 4.4(a)
(Incorporated herein by reference to Exhibit 4.4(b) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
4
|
.5(a)
|
|
Participation Agreement (L1) among Southern Energy Mid-Atlantic,
LLC, as Lessee, Dickerson OL1 LLC, as Owner Lessor, Wilmington
Trust Company, as Owner Manager, SEMA OP3 LLC, as Owner
Participant and State Street Bank and Trust Company of
Connecticut, National Association, as Lease Indenture Trustee
and as Pass Through Trustee, dated at December 18, 2000
(Incorporated herein by reference to Exhibit 4.5(a) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
4
|
.5(b)
|
|
Schedule identifying substantially identical agreements to
Participation Agreement constituting Exhibit 4.5(a)
(Incorporated herein by reference to Exhibit 4.5(b) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
4
|
.6(a)
|
|
Participation Agreement (Morgantown L1) among Southern Energy
Mid-Atlantic, LLC, as Lessee, Morgantown OL1 LLC, as Owner
Lessor, Wilmington Trust Company, as Owner Manager, SEMA OP1, as
Owner Participant and State Street Bank and Trust Company of
Connecticut, National Association, as Lease Indenture Trustee
and as Pass Through Trustee, dated at December 18, 2000
(Incorporated herein by reference to Exhibit 4.6(a) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
4
|
.6(b)
|
|
Schedule identifying substantially identical agreements to
Participation Agreement constituting Exhibit 4.6(a) hereto
(Incorporated herein by reference to Exhibit 4.6(b) to
Registrants Form S-4 in Registration No. 333-61668)
|
|
4
|
.7(a)
|
|
Facility Lease Agreement (L1) between Southern Energy
Mid-Atlantic, LLC, as Facility Lessee, and Dickerson OL1 LLC, as
Owner Lessor, dated at December 19, 2000 (Incorporated herein by
reference to Exhibit 4.7(a) to Registrants Registration
Statement on Form S-4, Registration No. 333-61668)
|
|
4
|
.7(b)
|
|
Schedule identifying substantially identical agreement to
Facility Lease Agreement constituting Exhibit 4.7(a)
(Incorporated herein by reference to Exhibit 4.7(b) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
4
|
.8(a)
|
|
Facility Lease Agreement (L1) between Southern Energy
Mid-Atlantic, LLC, as Facility Lessee, and Morgantown OL1 LLC,
as Owner Lessor, dated at December 19, 2000 (Incorporated herein
by reference to Exhibit 4.8(a) to Registrants Registration
Statement on Form S-4, Registration
No. 333-61668)
|
F-88
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Exhibit Name
|
|
|
4
|
.8(b)
|
|
Schedule identifying substantially identical agreement to
Facility Lease Agreement constituting Exhibit 4.8(a)
(Incorporated herein by reference to Exhibit 4.8(b) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
4
|
.9(a)
|
|
Indenture of Trust, Mortgage and Security Agreement (L1) between
Dickerson OL1 LLC, as Lessor, and State Street Bank and Trust
Company of Connecticut, National Association, as Lease Indenture
Trustee, dated at December 19, 2000 (Incorporated herein by
reference to Exhibit 4.9(a) to Registrants Registration
Statement on Form S-4, Registration No. 333-61668)
|
|
4
|
.9(b)
|
|
Schedule identifying substantially identical agreement to
Indenture of Trust, Mortgage and Security Agreement constituting
Exhibit 4.9(a) (Incorporated herein by reference to Exhibit
4.9(b) to Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
4
|
.10(a)
|
|
Indenture of Trust, Mortgage and Security Agreement (L1) between
Morgantown OL1 LLC, as Lessor, and State Street Bank and Trust
Company of Connecticut, National Association, as Lease Indenture
Trustee, dated at December 19, 2000 (Incorporated herein by
reference to Exhibit 4.10(a) to Registrants Registration
Statement on Form S-4, Registration No. 333-61668)
|
|
4
|
.10(b)
|
|
Schedule identifying substantially identical agreement to
Indenture of Trust, Mortgage and Security Agreement constituting
Exhibit 4.10(a) (Incorporated herein by reference to Exhibit
4.10(b) to Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
4
|
.11(a)
|
|
Series A Lessor Note Due June 20, 2012 for Dickerson OL1 LLC,
dated at December 19, 2000 (Incorporated herein by reference to
Exhibit 4.11(a) to Registrants Registration Statement on
Form S-4, Registration No. 333-61668)
|
|
4
|
.11(b)
|
|
Schedule identifying substantially identical Lessor Notes
constituting Exhibit 4.11(a) (Incorporated herein by reference
to Exhibit 4.11(b) to Registrants Registration Statement
on Form S-4, Registration No. 333-61668)
|
|
4
|
.12(a)
|
|
Series A Lessor Note Due June 30, 2008, for Morgantown OL1 LLC,
dated at December 19, 2000 (Incorporated herein by reference to
Exhibit 4.12(a) to Registrants Registration Statement on
Form S-4, Registration No. 333-61668)
|
|
4
|
.12(b)
|
|
Schedule identifying substantially Series A Lessor Notes
constituting Exhibit 4.12(a) (Incorporated herein by reference
to Exhibit 4.12(b) to Registrants Registration Statement
on Form S-4, Registration No. 333-61668)
|
|
4
|
.13(a)
|
|
Series B Lessor Note Due June 30, 2015, for Dickerson OL1 LLC,
dated at December 19, 2000 (Incorporated herein by reference to
Exhibit 4.13(a) to Registrants Registration Statement on
Form S-4, Registration No. 333-61668)
|
|
4
|
.13(b)
|
|
Schedule identifying substantially Lessor Note constituting
Exhibit 4.13(a) (Incorporated herein by reference to Exhibit
4.13(b) to Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
4
|
.14(a)
|
|
Series B Lessor Note Due June 30, 2017, for Morgantown OL1 LLC,
dated at December 19, 2000 (Incorporated herein by reference to
Exhibit 4.14(a) to Registrants Registration Statement on
Form S-4, Registration No. 333-61668)
|
|
4
|
.14(b)
|
|
Schedule identifying substantially identical Lessor Notes
constituting Exhibit 4.14(a) (Incorporated herein by reference
to Exhibit 4.14(b) to Registrants Registration Statement
on Form S-4, Registration No. 333-61668)
|
|
4
|
.15(a)
|
|
Series C Lessor Note Due June 30, 2020, for Morgantown OL1 LLC,
dated at December 19, 2000 (Incorporated herein by reference to
Exhibit 4.15(a) to Registrants Registration Statement on
Form S-4, Registration No. 333-61668)
|
|
4
|
.15(b)
|
|
Schedule identifying substantially identical Lessor Notes
constituting Exhibit 4.15(a) (Incorporated herein by reference
to Exhibit 4.15(b) to Registrants Registration Statement
on Form S-4, Registration No. 333-61668)
|
|
4
|
.16
|
|
Registration Rights Agreement, between Southern Energy
Mid-Atlantic, LLC and Credit Suisse First Boston, acting for
itself on behalf of the Purchasers, dated at December 18, 2000
(Incorporated herein by reference to Exhibit 4.16 to
Registrants Registration Statement on
Form S-4,
Registration No. 333-61668)
|
F-89
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Exhibit Name
|
|
|
4
|
.17(a)
|
|
Supplemental Pass Through Trust Agreement A between Mirant
Mid-Atlantic, LLC, and State Street Bank and Trust Company of
Connecticut, National Association, as Pass Through Trustee,
dated at June 29, 2001 (Incorporated herein by reference to
Exhibit 4.17(a) to Registrants Registration Statement on
Form S-4/A Registration No. 333-61668)
|
|
4
|
.17(b)
|
|
Schedule identifying substantially identical agreements to
Supplemental Pass Through Trust Agreement for Supplemental Pass
Through Trust Agreement B between Mirant Mid-Atlantic, LLC and
State Street Bank and Trust Company of Connecticut, National
Association, as Pass Through Trustee, dated at June 29, 2001,
and Supplemental Pass Through Trust Agreement C between Mirant
Mid-Atlantic, LLC and State Street Bank and Trust Company of
Connecticut, National Association, as Pass Through Trustee,
dated at June 29, 2001 constituting Exhibit 4.17(a)
(Incorporated herein by reference to Exhibit 4.17(b) to
Registrants Registration Statement on
Form S-4/A,
Registration No. 333-61668)
|
|
10
|
.1
|
|
Engineering, Procurement and Construction Agreement, dated at
July 30, 2007, between Mirant Mid-Atlantic, LLC, Mirant Chalk
Point, LLC and Stone & Webster, Inc. (Incorporated herein
by reference to Exhibit 10.1 to the Mirant Corporation Quarterly
Report on Form 10-Q filed November 6, 2009)
|
|
10
|
.2
|
|
Power Sale, Fuel Supply and Services Agreement dated at January
3, 2006 by and between Mirant Americas Energy Marketing, LP and
Mirant Mid-Atlantic, LLC (Incorporated herein by reference to
Exhibit 10.17 to Registrants Annual Report on Form 10-K
filed March 3, 2006)
|
|
10
|
.3
|
|
Power Sale, Fuel Supply and Services Agreement dated at January
3, 2006 by and between Mirant Americas Energy Marketing, LP and
Mirant Chalk Point, LLC (Incorporated herein by reference to
Exhibit 10.18 to Registrants Annual Report on Form 10-K
filed March 3, 2006)
|
|
10
|
.4
|
|
Power Sale, Fuel Supply and Services Agreement dated at January
3, 2006 by and between Mirant Americas Energy Marketing, LP and
Mirant Potomac River, LLC (Incorporated herein by reference to
Exhibit 10.19 to Registrants Annual Report on Form 10-K
filed March 3, 2006)
|
|
10
|
.5
|
|
Administrative Services Agreement dated at January 3, 2006 by
and between Mirant Mid-Atlantic, LLC and Mirant Services, LLC
(Incorporated herein by reference to Exhibit 10.20 to
Registrants Annual Report on Form 10-K filed March 3, 2006)
|
|
10
|
.6(a)
|
|
Asset Purchase and Sale Agreement for Generating Plants and
Related Assets by and between Potomac Electric Power Company and
Southern Energy, Inc. dated at June 7, 2000 (Incorporated herein
by reference to Exhibit 10.1(a) to Registrants
Registration Statement on Form S-4, Registration No. 333-61668)
|
|
10
|
.6(b)
|
|
Amendment No. 1 to Asset Purchase and Sale Agreement by and
between Potomac Electric Power Company and Southern Energy, Inc.
dated at September 18, 2000 (Incorporated herein by reference to
Exhibit 10.1(b) to Registrants Registration Statement on
Form S-4, Registration No. 333-61668)
|
|
10
|
.6(c)
|
|
Amendment No. 2 to Asset Purchase and Sale Agreement by and
between Potomac Electric Power Company and Southern Energy, Inc.
dated at December 19, 2000 (Incorporated herein by reference to
Exhibit 10.1(c) to Registrants Registration Statement on
Form S-4, Registration No. 333-61668)
|
|
10
|
.7(a)
|
|
Interconnection Agreement (Dickerson) by and between Potomac
Electric Power Company and Southern Energy Mid-Atlantic, LLC
dated at December 19, 2000 (Incorporated herein by reference to
Exhibit 10.2(a) to Registrants Registration Statement on
Form S-4, Registration No. 333-61668)
|
|
10
|
.7(b)
|
|
Schedule identifying substantially identical agreements to
Interconnection Agreement constituting Exhibit 10.7(a) hereto
(Incorporated herein by reference to Exhibit 10.2(b) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
10
|
.8(a)
|
|
Easement, License and Attachment Agreement (Dickerson Station)
by and between Potomac Electric Power Company, Southern Energy
Mid-Atlantic, LLC and Southern Energy MD Ash Management, LLC
dated at December 19, 2000 (Incorporated herein by reference to
Exhibit 10.3(a) to Registrants Registration Statement
on Form S-4, Registration No. 333-61668)
|
|
10
|
.8(b)
|
|
Schedule identifying substantially identical agreements to
Easement, License and Attachment Agreement constituting Exhibit
10.8(a) (Incorporated herein by reference to Exhibit 10.3(b) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
F-90
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Exhibit Name
|
|
|
10
|
.9(a)
|
|
Bill of Sale (SEMA: Dickerson; Morgantown; RR Spur; Production
Service Center) by Potomac Electric Power Company, for the
benefit of Southern Energy Mid-Atlantic, LLC dated at
December 19, 2000 (Incorporated herein by reference to
Exhibit 10.4(a) to Registrants Registration Statement on
Form S-4, Registration No. 333-61668)
|
|
10
|
.9(b)
|
|
Schedule identifying substantially identical documents to Bill
of Sale constituting Exhibit 10.9(a) hereto (Incorporated herein
by reference to Exhibit 10.4b to Registrants Registration
Statement on Form S-4, Registration No. 333-61668)
|
|
10
|
.10(a)
|
|
Facility Site Lease Agreement and Easement Agreement (L1)
between Southern Energy
Mid-Atlantic,
LLC, Dickerson OL1 LLC and Southern Energy MD Ash Management,
LLC, dated at December 19, 2000 (Incorporated herein by
reference to Exhibit 10.5(a) Registrants Registration
Statement on Form S-4, Registration No. 333-61668)
|
|
10
|
.10(b)
|
|
Schedule identifying substantially identical agreements to
Facility Site Lease Agreement constituting Exhibit 10.10(a)
(Incorporated herein by reference to Exhibit 10.5(b) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
10
|
.11(a)
|
|
Facility Site Lease Agreement (L1) between Southern Energy
Mid-Atlantic, LLC, Morgantown OL1 LLC and Southern Energy MD Ash
Management, LLC, dated at December 19, 2000 (Incorporated herein
by reference to Exhibit 10.6(a) to Registrants
Registration Statement on Form S-4, Registration No.
333-61668)
|
|
10
|
.11(b)
|
|
Schedule identifying substantially identical agreements to
Facility Site Lease Agreement constituting Exhibit 10.11(a)
(Incorporated herein by reference to Exhibit 10.6(b) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
10
|
.12(a)
|
|
Facility Site Sublease Agreement (L1) between Southern Energy
Mid-Atlantic, LLC, Dickerson OL1 LLC, dated at December 19, 2000
(Incorporated herein by reference to Exhibit 10.7(a) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
10
|
.12(b)
|
|
Schedule identifying substantially identical agreements to
Facility Site Sublease Agreement constituting Exhibit 10.12(a)
(Incorporated herein by reference to Exhibit 10.7b to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
10
|
.13(a)
|
|
Facility Site Sublease Agreement (L1) between Southern Energy
Mid-Atlantic, LLC, Morgantown OL1 LLC, dated at December 19,
2000 (Incorporated herein by reference to Exhibit 10.8a to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
10
|
.13(b)
|
|
Schedule identifying substantially identical agreements to
Facility Site Sublease Agreement constituting Exhibit 10.13(a)
(Incorporated herein by reference to Exhibit 10.8(b) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
10
|
.14
|
|
Capital Contribution Agreement by and between Southern Energy,
Inc. and Southern Energy
Mid-Atlantic,
LLC dated at December 19, 2000 (Incorporated herein by reference
to Exhibit 10.12 to Registrants Registration Statement on
Form S-4, Registration No. 333-61668)
|
|
10
|
.15
|
|
Promissory Note between Southern Energy Mid-Atlantic, LLC and
Southern Energy Peaker, LLC in the original principal amount of
$71,110,000 dated at December 19, 2000 (Incorporated herein by
reference to Exhibit 10.13 to Registrants Registration
Statement on Form S-4, Registration No. 333-61668)
|
|
10
|
.16
|
|
Promissory Note between Southern Energy Mid-Atlantic, LLC and
Southern Energy Potomac River, LLC in the original principal
amount of $152,165,000 dated at December 19, 2000 (Incorporated
herein by reference to Exhibit 10.14 to Registrants
Registration Statement on Form S-4, Registration No. 333-61668)
|
|
10
|
.17(a)
|
|
Shared Facilities Agreement between Southern Energy
Mid-Atlantic, LLC, Dickerson OL1 LLC, Dickerson OL2 LLC,
Dickerson OL3 LLC, and Dickerson OL4 LLC, dated at December 18,
2000 (Incorporated herein by reference to Exhibit 10.15(a) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
F-91
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Exhibit Name
|
|
|
10
|
.17(b)
|
|
Shared Facilities Agreement between Southern Energy
Mid-Atlantic, LLC, Morgantown OL1 LLC, Morgantown OL2 LLC,
Morgantown OL3 LLC, Morgantown OL4 LLC, Morgantown OL5 LLC,
Morgantown OL6 LLC, and Morgantown OL7 LLC, dated at December
18, 2000 constituting Exhibit 10.17(a) (Incorporated herein by
reference to Exhibit 10.15(b) to Registrants Registration
Statement on Form S-4, Registration No. 333-61668)
|
|
10
|
.18(a)
|
|
Assignment and Assumption Agreement between Southern Energy
Mid-Atlantic, LLC, Dickerson OL1 LLC, Dickerson OL2 LLC,
Dickerson OL3 LLC, and Dickerson OL4 LLC, dated at December 19,
2000 (Incorporated herein by reference to Exhibit 10.16(a) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
10
|
.18(b)
|
|
Assignment and Assumption Agreement between Southern Energy
Mid-Atlantic, LLC, Morgantown OL1 LLC, Morgantown OL2 LLC,
Morgantown OL3 LLC, Morgantown OL4 LLC, Morgantown OL5 LLC,
Morgantown OL6 LLC, and Morgantown OL7 LLC, dated at December
19, 2000 constituting Exhibit 10.18(a) (Incorporated herein by
reference to Exhibit 10.16(b) to Registrants Registration
Statement on Form S-4, Registration No. 333-61668)
|
|
10
|
.19(a)
|
|
Ownership and Operation Agreement between Dickerson OL1 LLC,
Dickerson OL2 LLC, Dickerson OL3 LLC, Dickerson OL4 LLC, and
Southern Energy Mid-Atlantic, LLC, dated at December 19, 2000
(Incorporated herein by reference to Exhibit 10.17(a) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
10
|
.19(b)
|
|
Ownership and Operation Agreement between Morgantown OL1 LLC,
Morgantown OL2 LLC, Morgantown OL3 LLC, Morgantown OL4 LLC,
Morgantown OL5 LLC, Morgantown OL6 LLC, Morgantown OL7 LLC, and
Southern Energy Mid-Atlantic, LLC, dated at December 18, 2000
constituting Exhibit 10.19(a) (Incorporated herein by reference
to Exhibit 10.17(b) to Registrants Registration Statement
on Form S-4, Registration No. 333-61668)
|
|
10
|
.20(a)
|
|
Guaranty Agreement (Dickerson L1) between Southern Energy, Inc.
and Dickerson OL1 LLC, dated at December 19, 2000 (Incorporated
herein by reference to Exhibit 10.21(a) to Registrants
Registration Statement on Form S-4, Registration No. 333-61668)
|
|
10
|
.20(b)
|
|
Schedule identifying substantially identical agreements to
Guaranty Agreement constituting Exhibit 10.20(a)
(Incorporated herein by reference to Exhibit 10.21(b) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
10
|
.21(a)
|
|
Guaranty Agreement (Morgantown L1) between Southern Energy, Inc.
and Morgantown OL1 LLC, dated at December 19, 2000 (Incorporated
herein by reference to Exhibit 10.22(a) to Registrants
Registration Statement on Form S-4, Registration No. 333-61668)
|
|
10
|
.21(b)
|
|
Schedule identifying substantially identical agreements to
Guaranty Agreement constituting Exhibit 10.21(a)
(Incorporated herein by reference to Exhibit 10.22(b) to
Registrants Registration Statement on Form S-4,
Registration No. 333-61668)
|
|
10
|
.22
|
|
Credit Agreement among Mirant North America, LLC, JPMorgan Chase
Bank, N.A as administrative agent and Deutsche Bank Securities
Inc. and Goldman Sachs Credit Partners L.P., as co-syndication
agents, dated at January 3, 2006 (Incorporated herein by
reference to Exhibit 10.2 to the Mirant Corporation Quarterly
Report on Form 10-Q filed November 6, 2009)
|
|
21
|
.1*
|
|
Subsidiaries of GenOn Mid-Atlantic, LLC
|
|
31
|
.1A2*
|
|
Certification of Chief Executive Officer pursuant to Rule
13a-14(a) under Securities Exchange Act of 1934
|
|
31
|
.2A4*
|
|
Certification of Chief Financial Officer pursuant to Rule
13a-14(a) under Securities Exchange Act of 1934
|
|
32
|
.1A2*
|
|
Certification of the Chief Executive Officer pursuant to Section
906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b))
|
|
32
|
.2A4*
|
|
Certification of the Chief Financial Officer pursuant to Section
906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b))
|
|
|
|
* |
|
Asterisk indicates exhibits filed herewith. |
|
|
|
The Registrant has requested confidential treatment for certain
portions of this Exhibit pursuant to
Rule 24b-2
under the Securities Exchange Act of 1934, as amended. |
F-92
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned
thereunto duly authorized.
GenOn Americas Generation, LLC
Mark M. Jacobs
President and Chief Executive Officer
(Principal Executive Officer)
Date: March 1, 2011
GENON
AMERICAS GENERATION, LLC
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
|
|
Signatures
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ Mark
M. Jacobs
Mark
M. Jacobs
|
|
President and Chief Executive Officer and Manager of GenOn
Americas Generation, LLC
(Principal Executive Officer)
|
|
March 1, 2011
|
|
|
|
|
|
/s/ J.
William Holden, III
J.
William Holden III
|
|
Executive Vice President and Chief Financial Officer and
Manager of GenOn Americas Generation, LLC (Principal Financial
Officer)
|
|
March 1, 2011
|
|
|
|
|
|
/s/ Michael
L. Jines
Michael
L. Jines
|
|
Executive Vice President and General Counsel, Secretary and
Chief Compliance Officer and Manager of GenOn Americas
Generation, LLC
|
|
March 1, 2011
|
|
|
|
|
|
/s/ Thomas
C. Livengood
Thomas
C. Livengood
|
|
Senior Vice President and Controller of GenOn Americas
Generation, LLC
(Principal Accounting Officer)
|
|
March 1, 2011
|
F-93
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) the
Securities Exchange Act of 1934, as amended, the registrant has
duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GenOn Mid-Atlantic, LLC
Mark M. Jacobs
President and Chief Executive Officer
(Principal Executive Officer)
Date: March 1, 2011
GENON
MID-ATLANTIC, LLC
Pursuant to the requirements of the Securities Exchange Act of
1934, as amended, this report has been signed below by the
following persons on behalf of the registrant and in the
capacities and on the dates indicated.
|
|
|
|
|
|
|
Signatures
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ Mark
M. Jacobs
Mark
M. Jacobs
|
|
President and Chief Executive Officer
and Manager of GenOn
Mid-Atlantic, LLC
(Principal Executive Officer)
|
|
March 1, 2011
|
|
|
|
|
|
/s/ J.
William Holden, III
J.
William Holden III
|
|
Executive Vice President and Chief Financial Officer and
Manager of GenOn Mid-Atlantic, LLC
(Principal Financial Officer)
|
|
March 1, 2011
|
|
|
|
|
|
/s/ Michael
L. Jines
Michael
L. Jines
|
|
Executive Vice President and General Counsel, Secretary and
Chief Compliance Officer and Manager of GenOn Mid-Atlantic,
LLC
|
|
March 1, 2011
|
|
|
|
|
|
/s/ Thomas
C. Livengood
Thomas
C. Livengood
|
|
Senior Vice President and Controller of GenOn Mid-Atlantic,
LLC (Principal Accounting Officer)
|
|
March 1, 2011
|
F-94
Supplemental
Information to be Furnished with Reports Filed Pursuant to
Section 15(d) of the Act by Registrants Which Have Not
Registered
Securities Pursuant to Section 12 of the Act
No annual report or proxy materials has been sent to securities
holders and no such report or proxy material is to be furnished
to securities holders subsequent to the filing of the annual
report on this
Form 10-K.
F-95