The discussion and analysis below has been organized as follows:
•Executive summary, including introduction and overview, business strategy, and
changes to the business environment
during the period, including environmental and regulatory matters;
•Results of operations;
•Financial condition, addressing liquidity position, sources and uses of
liquidity, capital resources and requirements,
commitments, and off-balance sheet arrangements; and
•Known trends that may affect NRG's results of operations and financial
condition in the future.
As you read this discussion and analysis, refer to NRG's Condensed Consolidated
Statements of Operations to this Form 10-Q, which present the results of
operations for the three months ended March 31, 2021 and 2020. Also refer to
NRG's 2020 Form 10-K, which includes detailed discussions of various items
impacting the Company's business, results of operations and financial condition,
including: General section; Strategy section; Business Overview section,
including how regulation, weather, and other factors affect NRG's business; and
Critical Accounting Policies and Estimates section.

Executive Summary
Introduction and Overview
NRG is an integrated power company built on dynamic retail brands with diverse
generation assets. NRG brings the power of energy to customers by producing and
selling electricity and related products and services in major competitive power
and gas markets in the U.S. and Canada in a manner that delivers value to all of
NRG's stakeholders. The Company sells energy, services, and innovative,
sustainable products and services directly to retail customers under the brand
names NRG, Reliant, Direct Energy, Green Mountain Energy, Stream, and XOOM
Energy, as well as other brand names owned by NRG, supported by approximately
23,000 MW of generation, including approximately 4,850 MW of fossil generation
assets held for sale as of March 31, 2021.
COVID-19
As the COVID-19 pandemic continues, NRG remains focused on protecting the health
and well-being of its employees, while supporting its customers and the
communities in which it operates and assuring the continuity of its operations.
During 2020, NRG migrated a substantial portion of its employees to a remote
work environment. The first COVID-19 vaccine became available in the United
States in December 2020. Vaccines have become increasingly accessible since the
initial rollout and all adults across the nation became eligible to receive a
vaccine as of April 19, 2021. The Company is currently planning to begin
returning certain employees to the offices through a phased approach expected to
be completed by the end of summer..
While the pandemic presents risks to the Company's business, as further
described in the Company's 2020 Form 10-K in Part II, Item 1A - Risk Factors,
there was not a material adverse impact on the Company's results of operations
for the three months ended March 31, 2021. NRG believes it has sufficient
liquidity on hand to continue business operations in light of current
circumstances posed by the pandemic. As disclosed in the Liquidity and Capital
Resources section, the Company has total available liquidity of $3.2 billion as
of March 31, 2021, consisting of cash on hand, its Revolving Credit Facility,
and additional facilities.
The situation surrounding COVID-19 remains fluid and the potential for a
material adverse impact on the Company exists as long as the virus impacts the
level of economic activity in the United States and abroad. While the Company
expects the risk to decrease as vaccinations are administered, NRG cannot
reasonably estimate with any degree of certainty the full impact COVID-19, nor
any resurgence of COVID-19, may have on the Company's results of operations,
financial position, and liquidity. The extent to which the COVID-19 pandemic may
impact the Company's business, operating results, financial condition, risk
exposure or liquidity will depend on future developments, including the duration
of the pandemic, travel restrictions, business and workforce disruptions, any
resurgence of the pandemic and the effectiveness of actions taken to contain,
mitigate and treat the disease.

Strategy

NRG's strategy is to maximize stockholder value through the safe production and sale of reliable power and gas to its customers in the markets it serves, while positioning the Company to provide innovative solutions to the end-use energy or service consumer. This strategy is intended to enable the Company to optimize the integrated model to generate stable and predictable cash flow, significantly strengthen earnings and cost competitiveness, and lower risk and volatility.



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To effectuate the Company's strategy, NRG is focused on: (i) serving the energy needs of end-use residential, commercial and industrial, and wholesale customers in competitive markets through multiple brands and channels; (ii) offering a variety of energy products and services, including renewable energy solutions, that are differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (iii) excellence in operating performance of its existing assets; (iv) optimal hedging of NRG's portfolio; and (v) engaging in disciplined and transparent capital allocation. Sustainability is an integral part of NRG's strategy and ties directly to business success, reduced risks and brand value. In 2019, NRG announced the acceleration of its science-based GHG emissions reduction goals to align with prevailing climate science, which seeks to limit global warming in the post-industrial era to 1.5 degrees Celsius. NRG is targeting a 50% reduction by 2025, from its current 2014 baseline, and net-zero emissions by 2050. The Company is on track to meet its 2025 goal.



Energy Regulatory Matters
The Company's regulatory matters are described in the Company's 2020 Form 10-K
in Item 1, Business - Regulatory Matters. These matters have been updated below
and in Note 17, Regulatory Matters.
As participants in wholesale and retail energy markets and owners and operators
of power plants, certain NRG entities are subject to regulation by various
federal and state government agencies. These include the CFTC, FERC, NRC and the
PUCT, as well as other public utility commissions in certain states where NRG's
generation or distributed generation assets are located. In addition, NRG is
subject to the market rules, procedures and protocols of the various ISO and RTO
markets in which it participates. Likewise, certain NRG entities participating
in the retail markets are subject to rules and regulations established by the
states and provinces in which NRG entities are licensed to sell at retail. NRG
must also comply with the mandatory reliability requirements imposed by NERC and
the regional reliability entities in the regions where NRG operates.
In March 2021, President Biden announced a framework for his "Build Back Better"
initiative. The announced framework includes ideas to address climate change
across the whole of the federal government through tax policy and research and
development, among other areas of focus. Relatedly, the U.S. House Energy and
Commerce Committee released the Climate Leadership and Environmental Action for
our Nation's ("CLEAN") Future Act, which is expected to influence legislative
drafts of the "Build Back Better" initiative. The CLEAN Future Act proposes,
among other things, a clean electricity standard that would require electricity
suppliers to procure and retire clean energy credits offsetting, in aggregate,
80% of the energy sold by 2030 and 100% by 2035. It would establish an
auction-based mechanism for these credits and award partial credits to certain
carbon-emitting generation that have lower-than-average emissions rates.
Although these proposals have not yet resulted in any new legislation being
enacted or regulations promulgated, NRG is closely monitoring both legislative
and executive agency action and expects to be an active participant as proposals
evolve into legislation. On April 22, 2021, the President announced that the
United States' Nationally Defined Contribution to the international Paris
Climate Agreement will be an economy-wide reduction in greenhouse gas emissions
of 50-52% by 2030, relative to 2005 levels. No methodology to achieve those
targets was announced, but legislation encompassing the "Build Back Better"
initiative is expected to be the bulk of the effort, with more details expected
to be announced by the November 2021 Conference of the Parties 26 meeting in
Glasgow, Scotland.
NRG's operations within the ERCOT footprint are not subject to rate regulation
by FERC, as they are deemed to operate solely within the ERCOT market and not in
interstate commerce. These operations are subject to regulation by the PUCT, as
well as to regulation by the NRC with respect to NRG's ownership interest in
STP.
State and Provincial Energy Regulation
State Proceedings Regarding States' Participation in the Wholesale Market -
Various states, including Connecticut, New Jersey, New York and Illinois, as
well as the District of Columbia have initiated proceedings to investigate
resource adequacy alternatives and to consider its participation in the regional
wholesale electricity market constructs, specifically withdrawal from the
regional market or implementing a state-directed capacity procurement regime.
Any actions taken by the states could affect market design and market prices in
the respective regional markets.
Regional Regulatory Developments
NRG is affected by rule and tariff changes that occur in the ISO regions. For
further discussion on regulatory developments see Note 17, Regulatory Matters.

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East/West

PJM


FERC Changes to Capacity Markets - On March 23, 2021, the Commission held its
first technical conference on Resource Adequacy in the Evolving Electricity
Sector to discuss the role of capacity market constructs in PJM, ISO-NE and
NYISO. The technical conference included the discussion of the implications of
retaining the expanded minimum offer price rule ("Expanded MOPR") in the PJM
capacity market, as well as prospective alternative approaches that could
replace PJM's Expanded MOPR. On April 5, 2021, the Commission issued a notice
inviting post-technical conference comments seeking comments on PJM's capacity
market, the implications of Expanded MOPR and potential alternatives to Expanded
MOPR in PJM. The Company filed comments on April 26, 2021. Any changes to the
PJM capacity market construct may impact the outcome of the Base Residual
Auction to be held in December 2021 for the 2023/2024 delivery year and future
auctions.
On April 22, 2021, PJM published updated Planning Period Parameters for the
2022/2023 Base Residual Auction that indicated a significant portion of Dominion
zone load, presumably the Dominion Energy Virginia utility, elected the Fixed
Resource Requirements ("FRR") Alternative. PJM approved the plan and adjusted
the reliability requirements downward for the RTO and the respective local
delivery areas. Under the existing PJM rules, an FRR election has a minimum
5-year term. Removing capacity from the auctions could impact the auction
results.
Independent Market Monitor Market Seller Offer Cap Complaint - On February 21,
2019, the Independent Market Monitor filed a complaint alleging that the current
Market Seller Offer Cap is too high. A number of parties, including PJM, filed
protests to the filing arguing that, among other things, the Market Monitor
failed to support its claim that the expected number of performance hours used
to calculate the cap is overstated. On March 18, 2021, finding that the
calculation of the default Market Seller Offer Cap was unjust and unreasonable,
the Order permitted the current PJM May 2021 capacity auction for the 2022/2023
delivery rule to continue under the existing rules and set a procedural schedule
for parties to file briefs with possible solutions within 45 days. As a result
of this proceeding, default market caps could be lower.
Indiana Municipal Power Agency and City of Lawrenceburg, Indiana Complaint on
Station Power - On September 17, 2020, FERC issued an order in response to a
complaint and request for declaratory judgement challenging the station power
wholesale netting provisions in PJM's tariff. FERC found that it does not have
jurisdiction over the supply of station power and the provision of station power
is a retail sale subject to state jurisdiction. The order established a Section
206 proceeding and required PJM to submit a filing to show why the station
service netting provisions of its tariff are just and reasonable. Lawrenceburg
Power, LLC filed for rehearing, which was denied by operation of law on November
19, 2020 and they subsequently appealed to the United States Court of Appeals
for the District of Columbia Circuit. The matter is pending. On November 23,
2020, PJM submitted its station power compliance filing to FERC. In an April 27,
2021 Order, FERC found that PJM's Tariff regarding station power whole netting
was unjust and unreasonable, but accepted in part and rejected in part PJM's
compliance filing, and required PJM to make an additional compliance filing
within 30 days of the Order. This decision could affect the rates that plants
pay for station power.
New England
Mystic's Complaint on Transmission Reliability Review - On June 10, 2020,
Constellation Mystic Power LLC filed a complaint at FERC against ISO-NE alleging
that ISO-NE violated its Tariff in its addition of language to its planning
procedure and in its conduct in carrying out a competitive transmission request
for proposal to address the retirements of Mystic Units 8 and 9. On August 17,
2020, FERC issued an order denying the complaint. After a rehearing that was
denied by operation of law, on January 4, 2021, Constellation Mystic Power LLC
filed an appeal to the D.C. Circuit. The ISO-NE auction for the 2024-2025
delivery year concluded on February 8, 2021. Subsequently, on February 18, 2021,
Constellation Mystic Power LLC withdrew the appeal.
Texas
Legislative Activity Post-Winter Storm Uri - The Texas Legislature convened
extensive fact-finding hearings the week after Winter Storm Uri, and
subsequently has been highly engaged in policymaking in respect to the energy
sector. The focuses of the legislation pertinent to the competitive power sector
include the design and governance of the ERCOT wholesale market, the
weatherization of sources of power and fuel supply and related infrastructure,
retail customer protections for the limited number of residential customers
exposed to real-time wholesale-price index products, communications protocols
before and during power outage events, and the financial security of market
participants and customers including a variety of securitization proposals. The
legislative session concludes at the end of May, but may reconvene in special
session. A significant number of legislative proposals would direct regulatory
agencies, such as the PUCT, to engage in extensive rulemaking. Due to the
preliminary nature of the legislation and rulemaking process, it is unclear
what, if any, impact these proposals would have on the Company or the ERCOT
wholesale market.

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Public Utility Commission of Texas' Actions with Respect to Winter Storm Uri
On February 15, 2021, the PUCT issued an emergency order that required the
energy prices of the ERCOT market to reflect the "Value of Lost Load" so long as
load was being involuntary curtailed during Energy Emergency Alert 3 ("EEA3")
conditions, as directed by ERCOT. This action effectively set the price of
energy at $9,000 per megawatt-hour for the duration of the EEA3 event.
Additionally, in the same order, the PUCT temporarily suspended the Low System
Wide Offer Cap ("LCAP"), reasoning that if triggered it would have the
unintended effect of raising the price cap of the ERCOT market above $9,000 per
megawatt-hour. On February 16, 2021, the PUCT largely reaffirmed its judgement,
but rescinded the retroactive applicability of its February 15, 2021 order to
the early hours of February 15, 2021. Consequently, energy prices remained at
$9,000/MWh from late February 15, 2021 to early February 19, 2021, when ERCOT
declared the EEA3 conditions terminated.
On February 21, 2021, citing a public emergency and imperative public necessity,
the PUCT issued an order directing retail electricity providers ("REP") to
suspend late fees and prohibiting REPs from disconnecting residential and small
commercial customers for non-payment. Although the late fee suspension was ended
by the PUCT by order dated March 3, 2021, the PUCT has yet to lift its
prohibition against disconnection.
On March 4, 2021, after the PUCT lifted its temporary suspension of the LCAP,
ERCOT transitioned from using the System Wide Offer Cap ("SWCAP") to the LCAP,
which resulted in the offer cap being reduced from $9,000 per MWh to $2,000 per
MWh, or 50 times the Katy fuel index price for the balance of the year,
whichever is greater. ERCOT makes the transition from the SWCAP to LCAP after a
hypothetical gas-fired peaker, using actual power prices, would have made
$315,000 MW/year (achieved on February 16, 2021), which is equal to three times
the assumed net cost of new entry. The PUCT has instituted a rulemaking to fix
the LCAP value at $2,000 per MWh. This transition of the offer cap may reduce
the balance of year 2021 power prices due to the lower offer cap.
Since Winter Storm Uri, all three then-sitting PUCT commissions have resigned.
The Governor has appointed Will McAdams and Peter Lake to the PUCT, designating
the latter to become Chairman upon taking office. Messrs. McAdams and Lake were
confirmed by the Texas State Senate during the week of April 19, 2021.
Regulatory and Legislative Activity on ERCOT Pricing during Winter Storm Uri -
The ERCOT Independent Market Monitor ("IMM") proposed that the PUCT reprice the
market such that prices during 32 hours of February 18 and 19 would not
automatically be fixed at $9,000/MWh, reasoning that ERCOT had recalled all
directives to transmission and distribution utilities to shed load by the late
evening of February 17, 2021. The PUCT rejected this proposal. Thereafter, the
Texas Senate passed SB2142 which directs the PUCT as recommended by the IMM, by
March 20, 2021, to reprice the market such that prices during 32 hours of
February 18 and 19 would not automatically be fixed at $9,000/MWh. The Texas
House has not referred the bill and House leadership has come out publicly
against the repricing. It appears Legislative members are now focused on
securitization as a way to address the financial issues from Winter Storm Uri.
A number of parties have either moved the PUCT to rehear its February 15 and 16
orders, arguing that they were adopted without due process and in violation of
law, or have directly appealed those orders to state court. The PUCT had until
April 12, 2021 to consider the pending motions for rehearing and, not having
taken action, these requests were considered denied by operation of law. Certain
parties consequently filed a petition for judicial review in Travis County
District Court on April 22. Separately, a party has also challenged the February
15 and 16 PUCT orders before the Court of Appeals for the Third District.
Briefing in that matter has been scheduled into the summer.
ERCOT Defaults and Securitization Legislation - A number of market participants
defaulted on their ERCOT transactions following Winter Storm Uri. Defaulting
parties result in ERCOT short-paying other market participants that are owed net
payments in the market operator's settlement process. The cumulative short pay
amount as of April 30, 2021 totaled $2.992 billion. Two electric co-operatives
represent 84% of this amount, with Brazos Electric Co-operative constituting an
overall majority of the sum ($1.879 billion). Brazos has filed for bankruptcy
protection and ERCOT is an unsecured creditor in the proceeding.
ERCOT's market protocols provide for the short pay to be extinguished through a
process of uplift, whereby the cost of defaults is allocated to all market
participants, including retailers, generators, municipal and co-operative
utilities, and financial traders. However, the total amount of this uplift is
limited by ERCOT's current protocols to $2.5 million per month. Consequently, it
would take approximately 96 years for the current net short-pay balance to be
uplifted to the market under the current market rules. NRG's undiscounted share
of the uplift based on its current market share is estimated to be approximately
$185 million and has been short-paid $83 million. The remaining $102 million has
been discounted based on the 96 year repayment term and the present value of $12
million was recorded as an additional liability.
The legislature is actively considering proposals to securitize these default
balances. If enacted, the PUCT would either be required or allowed to issue a
financing order that authorizes the issuance of bonds, the proceeds of which
would resolve the existing short pay, backed by a property right to a stream of
payments by market participants of an ERCOT surcharge associated with the bonds'
principal and interest. Other securitization proposals also have been introduced
that specifically

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permit co-operatives to securitize debts, including their ERCOT defaults, and
for costs associated with online reliability deployment price adders and
ancillary services to be securitized. However, the details and the scope of any
securitization legislation continue to be a matter of debate at the legislature.
California
California Resource Adequacy Proceedings - Since a summer 2020 heat storm that
resulted in emergency load curtailments, the State of California and CAISO have
embarked on numerous new regulatory activities while redirecting existing
proceedings related to the topic of resource adequacy. On March 25, 2021, the
CPUC directed the state's major investor-owned utilities to engage in up to 1.5
GW of emergency procurement for 2021 and 2022. In the same docket, the CPUC
approved a new demand response program for use during emergency conditions. The
CPUC is also considering longer term structural reforms of the resource adequacy
policy in California.
Midway-Sunset Reliability Must Run Proceeding - San Joaquin Energy, LLC, a
subsidiary of NRG, owns a 50%, non-controlling interest in the Midway-Sunset
Cogeneration Company ("MSCC"). MSCC owns a cogeneration facility near Fellows,
California and submitted mothball notices for the cogeneration facility to the
CAISO in the latter half of 2020. On December 17, 2020, the CAISO Board
effectively rejected the mothball notices by authorizing its staff to designate
the MSCC facility as a reliability must-run ("RMR") resource conditioned on
execution of a RMR contract. In a letter dated December 16, 2020 sent to the
CAISO Board, MSCC indicated that it did not object to the RMR designation but
noted certain permitting and maintenance requirements for RMR operation. On
January 29, 2021, MSCC made its RMR filing at FERC. Multiple parties filed
protests and on March 16, 2021, MSCC filed a response to those protests. On
April 2, 2021, FERC accepted the RMR filing, suspended it to become effective
February 1, 2021 subject to refund and established hearing and settlement judge
proceedings. The parties are engaging in settlement proceedings.
Canada
Alberta Energy Market - In December 2020, prior to its acquisition by NRG,
Direct Energy filed a Non-Energy Rate Application with the Alberta Utilities
Commission ("AUC") to approve cost recovery for the 2020-2022 period. Major cost
elements of this application relate to bad debt, corporate costs, and customer
care and billing contracts. The Company engaged in a mediation and settlement
process, and on April 20, 2021 an all-party settlement was executed, and was
filed with the AUC on April 23, 2021. The Company expects an AUC decision
approving the settlement agreement this year. Separately, the Company received
approval from the AUC of a negotiated rate settlement for its electricity
focused 2020-2022 Energy Price Setting Plan. The Company is also in the process
of repaying the remainder of amounts advanced to it from the Balance Pool and
the Alberta government as part of its 90 day utility bill deferral program. This
program, effective March 18, 2020, was designed to assist residential, farms,
and small business customers who were negatively affected by COVID-19 related
economic circumstances by temporarily deferring their utility bill payments. The
program was also designed to mitigate bad debt risks associated with the
implementation of the program.

Environmental Regulatory Matters
NRG is subject to numerous environmental laws in the development, construction,
ownership and operation of power plants. These laws generally require that
governmental permits and approvals be obtained before construction and
maintained during operation of power plants. Federal and state environmental
laws historically have become more stringent over time. Future laws may require
the addition of emissions controls or other environmental controls or impose
restrictions on the Company's operations. Complying with environmental laws
often involves specialized human resources and significant capital and operating
expenses, as well as occasionally curtailing operations. The COVID-19 pandemic
may prevent the Company from complying with certain of its environmental
requirements, which federal and state regulators have recognized. NRG decides to
invest capital for environmental controls based on the relative certainty of the
requirements, an evaluation of compliance options, and the expected economic
returns on capital.
A number of regulations that affect the Company have been revised recently by
the EPA, including ash storage and disposal requirements, NAAQS revisions and
implementation and effluent limitation guidelines. Some of these recent
revisions may, in turn, be revised by the new U.S. presidential administration.
NRG will evaluate the impact of these regulations as they are revised but cannot
fully predict the impact of each until anticipated revisions and legal
challenges are resolved. The Company's environmental matters are described in
the Company's 2020 Form 10-K in Item 1, Business - Environmental Matters and
Item 1A, Risk Factors. These matters have been updated in Note 18, Environmental
Matters, to the condensed consolidated financial statements of this Form 10-Q
and as follows.
Air
The CAA and the resulting regulations (as well as similar state and local
requirements) have the potential to affect air emissions, operating practices
and pollution control equipment required at power plants. Under the CAA, the EPA
sets NAAQS for certain pollutants including SO2, ozone, and PM2.5. Many of the
Company's facilities are located in or near areas that are

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classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS may become more stringent. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent air regulations could require the installation of additional emissions control equipment at some NRG facilities or retiring of units if installing such controls is not economic. Significant changes to air regulatory programs affecting the Company are described below. CPP/ACE Rules - The attention in recent years on GHG emissions has resulted in federal and state regulations. In October 2015, the EPA promulgated the CPP, addressing GHG emissions from existing EGUs. On February 9, 2016, the U.S. Supreme Court stayed the CPP. In July 2019, EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO2 emissions from the power sector. On January 19, 2021, the D.C. Circuit vacated the ACE rule (but on February 22, 2021, at the EPA's request, stayed the issuance of the portion of the mandate that would vacate the repeal of the CPP). Accordingly, we expect the EPA to promulgate a new rule to regulate GHG emissions from power plants.


 Byproducts, Wastes, Hazardous Materials and Contamination
In April 2015, the EPA finalized the rule regulating byproducts of coal
combustion (e.g., ash and gypsum) as solid wastes under the RCRA. In September
2017, the EPA agreed to reconsider the rule. On July 30, 2018, the EPA
promulgated a rule that amends the existing ash rule by extending some of the
deadlines and providing more flexibility for compliance. On August 21, 2018, the
D.C. Circuit found, among other things, that the EPA had not adequately
regulated unlined ponds and legacy ponds. In 2019 and 2020, the EPA proposed
several changes to this rule. On August 28, 2020, the EPA finalized "A Holistic
Approach to Closure Part A: Deadline to Initiate Closure," which amended the
April 2015 Rule to address the August 2018 D.C. Circuit decision and extend some
of the deadlines. On November 12, 2020, the EPA finalized "A Holistic Approach
to Closure Part B: Alternative Demonstration for Unlined Surface Impoundments,"
which further amended the April 2015 Rule to, among other things, provide
procedures for requesting approval to operate existing ash impoundments with an
alternate liner. The Company has updated its estimates of required environmental
capital expenditures to address this revised rule.
Domestic Site Remediation Matters
Under certain federal, state and local environmental laws, a current or previous
owner or operator of a facility, including an electric generating facility, may
be required to investigate and remediate releases or threatened releases of
hazardous or toxic substances or petroleum products. NRG may be responsible for
property damage, personal injury and investigation and remediation costs
incurred by a party in connection with hazardous material releases or threatened
releases. These laws impose liability without regard to whether the owner knew
of or caused the presence of the hazardous substances, and the courts have
interpreted liability under such laws to be strict (without fault) and joint and
several. Cleanup obligations can often be triggered during the closure or
decommissioning of a facility, in addition to spills during its operations.
Further discussions of affected NRG sites can be found in Note 16, Commitments
and Contingencies, to the condensed consolidated financial statements.
Nuclear Waste - The federal government's program to construct a nuclear waste
repository at Yucca Mountain, Nevada was discontinued in 2010. Since 1998, the
U.S. DOE has been in default of the federal government's obligations to begin
accepting spent nuclear fuel, or SNF, and high-level radioactive waste, or HLW,
under the Nuclear Waste Policy Act. Owners of nuclear plants, including the
owners of STP, had been required to enter into contracts setting out the
obligations of the owners and the U.S. DOE, including the fees to be paid by the
owners for the U.S. DOE's services to license a spent fuel repository. Effective
May 16, 2014, the U.S. DOE stopped collecting the fees.
On February 5, 2013, STPNOC entered into a settlement agreement with the U.S.
DOE for payment of damages relating to the U.S. DOE's failure to accept SNF and
HLW under the Nuclear Waste Policy Act through December 31, 2013, which has been
extended three times through addendums to cover payments through December 31,
2022. There are no facilities for the reprocessing or permanent disposal of SNF
currently in operation in the U.S., nor has the NRC licensed any such
facilities. STPNOC currently stores all SNF generated by its nuclear generating
facilities on-site. STPNOC plans to continue to assert claims against the U.S.
DOE for damages relating to the U.S. DOE's failure to accept SNF and HLW.
Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended in
1985, the state of Texas is required to provide, either on its own or jointly
with other states in a compact, for the disposal of all low-level radioactive
waste generated within the state. Texas is currently in a compact with the state
of Vermont, and the compact low-level waste facility located in Andrews County
in Texas has been operational since 2012.
Water
The Company is required under the CWA to comply with intake and discharge
requirements, requirements for technological controls and operating practices.
As with air quality regulations, federal and state water regulations have become
more stringent and imposed new requirements.
Effluent Limitations Guidelines - In November 2015, the EPA revised the Effluent
Limitations Guidelines for Steam Electric Generating Facilities, which imposed
more stringent requirements (as individual permits were renewed) for wastewater

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streams from FGD, fly ash, bottom ash, and flue gas mercury control. On September 18, 2017, the EPA promulgated a final rule that, among other things, postponed the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA amended the rule. On October 13, 2020, the EPA amended the 2015 ELG rule by: (i) altering the stringency of certain limits for FGD wastewater; (ii) relaxing the zero-discharge requirement for bottom ash transport water; and (iii) changing several deadlines. The Company is in the process of estimating the environmental capital expenditures that will be required to comply. The capital expenditures required to comply will depend on elections regarding future operations of each coal-fired unit. NRG expects to make these elections for each unit in the fourth quarter of 2021 at which time the EPA will be notified as required. Accordingly, we do not expect to provide estimates of ELG compliance costs until early 2022. Regional Environmental Developments Ash Regulation in Illinois - On July 30, 2019, Illinois enacted legislation that requires the state to promulgate regulations regarding coal ash at surface impoundments. On April 15, 2021, the state promulgated the implementing regulation, which became effective on April 21, 2021. The new regulation requires NRG to apply for initial operating permits for its coal ash surface impoundments by October 31, 2021 and construction permits (for closure) starting in 2022.



Significant Events
The following significant events have occurred during 2021 as further described
within this Management's Discussion and Analysis and the condensed consolidated
financial statements:
Extreme Weather Event in Texas During February 2021
During February 2021, Texas experienced unprecedented cold temperatures for a
prolonged duration, resulting in a power emergency, blackouts, and an estimated
all-time peak demand of 77 GW (without load shed). Ahead of the event, NRG
launched residential customer communications calling for conservation across all
of its brands, and initiated residential and commercial and industrial demand
response programs to curtail customer load. The Company maximized available
generating capacity and brought in additional resources to supplement in-state
staff with technical and operating experts from the rest of its U.S. fleet.
During the quarter ended March 31, 2021, Winter Storm Uri's financial impact to
loss before income taxes was a loss of $967 million. A number of factors may
mitigate or increase the financial impact, such as recently proposed regulatory
securitization packages, finalizing meter and settlement data, potential
customer and counterparty risk including ERCOT's shortfall payments and uplift
charges, and one-time cost savings.
Direct Energy Acquisition
On January 5, 2021, the Company acquired Direct Energy, a North American
subsidiary of Centrica. Direct Energy is a leading retail provider of
electricity, natural gas, and home and business energy related products and
services in North America, with operations in all 50 U.S. states and 8 Canadian
provinces. The acquisition increases NRG's retail portfolio by over 3 million
customers and complements its integrated model. It also broadens the Company's
presence in the Northeast and into states and locales where it does not
currently operate, supporting NRG's objective to diversify its business.
The Company paid an aggregate purchase price of $3.625 billion in cash and an
initial purchase price adjustment of $77 million. The Company funded the
purchase price using a combination of $715 million of cash on hand, $166 million
from a draw on its Revolving Credit Facility (of which $107 million was used to
fund acquisition costs and financing fees that are not included in the aggregate
purchase price above), as well as approximately $2.9 billion in secured and
unsecured corporate debt issued in December 2020. The final purchase price
adjustment resulted in a reduction of $38 million. The Company expects to
receive this payment from Centrica during the second quarter of 2021. The
Company also increased its collective liquidity and collateral facilities by
$3.4 billion through a combination of amending its Revolving Credit Facility,
amending its credit default swap facility, entering into a revolving accounts
receivable financing facility, entering into an uncommitted repurchase facility
and entering into multiple agreements for the issuance of letters of credit.
Sale of Agua Caliente
On February 3, 2021, the Company completed the sale of its 35% ownership in Agua
Caliente to Clearway Energy, Inc. for $202 million. NRG recognized a gain on the
sale of $17 million, including cash disposed of $7 million. On October 21, 2019,
the Company had repaid the Agua Caliente Borrower 1 notes associated with the
project of $83 million.

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Sale of 4.8 GW of Fossil Generation Assets
On February 28, 2021, the Company entered into a definitive purchase agreement
with Generation Bridge, an affiliate of ArcLight Capital Partners, to sell
approximately 4,850 MW of fossil generating assets from its East and West
regions of operations for total proceeds of $760 million, subject to standard
purchase price adjustments and certain other indemnifications. As part of the
transaction, NRG is entering into a tolling agreement for its 866 MW Arthur Kill
plant in New York City through April 2025.
The transaction is expected to close in the fourth quarter of 2021, and is
subject to various closing conditions, approvals and consents, including FERC,
NYSPSC, and antitrust review under the Hart-Scott-Rodino Act.
Renewable Power Purchase Agreements
The Company's strategy is to procure mid to long-term generation through power
purchase agreements. As of March 31, 2021, NRG has entered into PPAs totaling
approximately 2.2 GW with third-party project developers and other
counterparties. The tenor of these agreements is an average between twelve and
thirteen years. The Company expects to continue evaluating and executing similar
agreements that support the needs of the business. Due to COVID-19, certain of
these PPA contracts have been amended to allow for the delay of project
completion dates from mid-2021 into 2022. These amendments include improved
terms for NRG.
Trends Affecting Results of Operations and Future Business Performance
The Company's trends are described in the Company's 2020 Form 10-K in Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations - Business Environment.
Changes in Accounting Standards
See Note 2, Summary of Significant Accounting Policies, for a discussion of
recent accounting developments.


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