2024年10月30日，公司利用票據發行的淨收益，加上新的遞增期限貸款b的淨收益，總額爲$，以及手頭現金，支付APX Group Inc. 的任何及所有現金承購價格450百萬美元，並現金支付，用於支付任何以及所有到期日期爲2027年的APX Group Inc.的%優先擔保票據的現金收購價格 6.750%優先擔保票據，並償還APX Group Inc.的擔保
於2024年4月16日，公司作爲借款人，及其某些子公司作爲擔保人，與Citicorp North America，Inc.等簽訂了第八項修正協議，以修訂公司於2016年6月30日簽訂的第二份經修訂和重新規定的信貸協議（「第八項修正」），並與其他金融機構，如貸款方之間簽訂了新的：公司信貸協議，以便（i）設立合計貸款額爲$百萬美元的新期限貸款b工具（「現有期限貸款b工具」及其下的貸款，「期限貸款」），以及（ii）根據協議中規定的對信貸協議進行某些其他修改。期限貸款的款項用於償還公司可轉換高級票據的部分，以及所有公司的第一順位抵押2024年到期的％的優先擔保頭等票據，以及一般公司用途。875百萬美元總本金額貸款（「現有期限貸款b工具」及其下的貸款，「期限貸款」），以及（ii）根據協議中規定的對信貸協議進行某些其他修改。期限貸款的款項用於償還公司可轉換高級票據的部分，以及所有公司的 3.750％優先擔保頭等票據到期，及用於一般企業用途。
2024年6月21日，公司的間接全資子公司NRG應收款項有限責任公司（「NRG應收款項」）修改了其現有應收賬款授信設施，其中包括（i）將計劃終止日期延長至2025年6月20日，（ii）增加總承諾額至其他$1.4億美元2.3（季節性調整後）和（iii）新增一位新的原始人。截至2024年9月30日，尚有 no 未償還借款，且已發出的信用證金額爲$1.5十億。
另外，在2024年6月21日，Direct Energy Services, LLC（作爲額外原始債權人）簽署了一份聯合協議（「聯合協議」），加入作爲額外原始債權人的接收賬款出售協議。該接收賬款出售協議日期爲2020年9月22日，參與方包括Direct Energy, LP、Direct Energy Business, LLC、Green Mountain Energy Company、NRG Business Marketing, LLC、Reliant Energy Northeast LLC、Reliant Energy Retail Services, LLC、Stream SPE, Ltd.、US Retailers LLC和XOOm Energy Texas, LLC，NRG Retail爲服務商，NRG Receivables爲債權人。根據聯合協議，額外原始債權人同意受接收賬款出售協議條款約束，將銷售給NRG Receivables幾乎所有的銷售電力、天然氣和/或相關服務的應收賬款以及某些相關權利（統稱「應收賬款」），並在此過程中已將應收賬款的收益存入NRG Receivables的存款帳戶。
Sb IP Holdings LLC (「Skybell」) 對 Vivint 智能家居公司提起訴訟。 — 2023年10月23日，美國德克薩斯東區謝爾曼地方法院的陪審團裁定有利於Skybell公司，判決賠償金額爲45百萬美元，以賠償專利侵權問題。Skybell提出的索賠依據的專利於2021年11月被美國國際貿易委員會裁定無效。公司不認爲裁決在法律上支持，並正在尋求上訴救濟以及其他可用的法律選擇。這一事項在 Vivint 智能家居收購時已知並計提準備金。
合同糾紛
South Texas Project核發電站 — 2023年7月，STP、CPS和Austin Energy的合作伙伴發起訴訟，並向美國核規管委員會(NRC)申請干預許可轉讓申請，聲稱在NRG South Texas'擬議出售股份的情況下存在優先購買權。 44%利益的STP股份銷售給星座。各方於2024年5月簽署了和解協議，並撤銷了訴訟。由於達成和解協議，NRG未受到額外影響。
2024年5月6日，FERC指示PJm根據初始LDA可靠性要求規則重新計算2024/2025年度拍賣結果，並進一步指示PJm重新運行第三次增量拍賣。PJm分別於2024年5月8日和2024年5月23日發佈修訂後的BRA和第三次增量拍賣結果。2024年6月14日，多個當事方對FERC於2024年5月6日批准PJm恢復原始容量承諾規則以便重新計算2024/2025年BRA和重新運行2024/2025年BRA的命令提出上訴至第三巡迴上訴法院，結果爲2024/2025交付年度Delmarva Power and Light South地區的容量價格上漲。這一結果可能因尚未解決的投訴和上訴而發生變化。
Change to Energy Efficiency in the PJM Capacity Auction— On November 5, 2024, FERC approved PJM’s proposal to terminate compensation paid through the PJM capacity market to energy efficiency resources beginning in the 2026/2027 auction year. However, energy efficiency resources will be counted as a reduction in the PJM load forecast that is the basis of the PJM capacity auction. FERC's action will eliminate wholesale market financial support for utility-run programs authorized by state utility commissions, as well as certain third-party providers of energy efficiency services. NRG's demand-side programming is not significantly affected by the modification.
Other Regulatory Matters
From time to time, NRG entities may be subject to examinations, investigations and/or enforcement actions by federal, state and provincial licensing agencies and may face the risk of penalties for violation of financial services, consumer protections and other applicable laws and regulations.
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 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 including unit retirements. Complying with environmental laws often involves specialized human resources and significant capital and operating expenses, as well as occasionally curtailing operations. 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 and continue to be revised by the EPA, including requirements regarding coal ash, GHG emissions, NAAQS revisions and implementation and effluent limitation guidelines. NRG will evaluate the impact of these regulations as they are revised but cannot fully predict the impact of each until anticipated revisions, legal challenges and reconsiderations are resolved. The Company’s environmental matters are described in the Company’s 2023 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Note 16, Environmental Matters, to the condensed consolidated financial statements of this Form 10-Q and as follows.
Air
The CAA and related 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 classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS may become more stringent. In March 2024, the EPA increased the stringency of the PM2.5 NAAQS. 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 2019, the 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). On June 30, 2022, the U.S. Supreme Court held that the "generation shifting" approach in the CPP exceeded the powers granted to the EPA by Congress. The Court
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did not address the related issues of whether the EPA may adopt only measures applied at each source. On May 9, 2024, the EPA promulgated a rule that repealed the ACE rule and significantly revised the manner in which new combustion-turbine and existing steam EGU's GHG emissions will be regulated including capturing and storing/sequestering CO2 in some instances. This rule has been challenged by numerous parties in the D.C. Circuit including 27 states with 22 states intervening in support of the rule. The Company anticipates that the new U.S. presidential administration will revisit this rule.
CSAPR — On March 15, 2023, the EPA signed and released a prepublication of a final rule that sought to significantly revise the CSAPR to address the good-neighbor obligations of the 2015 ozone NAAQS for 23 states after earlier having disapproved numerous state plans to address the issue. Several states, including Texas, challenged the EPA's disapproval of their state plans. On May 1, 2023, the United States Court of Appeals for the Fifth Circuit stayed the EPA's disapproval of Texas' and Louisiana's state plans, which disapprovals are a condition precedent to the EPA imposing its plan on Texas and Louisiana. Several other states are also similarly situated because of similar stays. Nonetheless, on June 5, 2023, the EPA promulgated this rule. On July 31, 2023, the EPA promulgated an interim final rule that addresses the various judicial orders that have stayed several State-Implementation-Plan disapprovals by limiting the effectiveness of certain requirements of the final rule promulgated on June 5, 2023 in Texas and several other states. On June 27, 2024, the United States Supreme Court stayed the final rule in the 11 states where the rule had not already been stayed. The Company cannot predict the outcome of the legal challenges to the: (i) various state disapprovals; (ii) the final rule promulgated on June 5, 2023; and (iii) the interim final rule promulgated on July 31, 2023 that seeks to address the judicial orders. The Company anticipates that the new U.S. presidential administration will revisit this rule.
Regional Haze Proposal — On May 2023, the EPA proposed to withdraw the existing Texas Sulfur Dioxide Trading Program and replace it with unit-specific SO2 limits for 12 units in Texas to address requirements to improve visibility at National Parks and Wilderness areas. If finalized as proposed, the rule would result in more stringent SO2 limits for two of the Company's coal-fired units in Texas. The Company cannot predict the outcome of this proposal.
MATS — On May 7, 2024, the EPA promulgated a final rule that amends the MATS rule by, among other things, increasing the stringency of the filterable particulate matter standard at coal-burning units.The deadline for complying with this more stringent standard is 2027. Twenty three states have challenged this rule in the D.C. Circuit. Accordingly, the outcome of this rulemaking is uncertain. The Company anticipates that the new U.S. presidential administration will revisit this rule.
Byproducts
In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. On July 30, 2018, the EPA promulgated a rule that amended the 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 surface impoundments. 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. On May 8, 2024, the EPA promulgated a rule that establishes requirements for: (i) inactive (or legacy) surface impoundments at inactive facilities and (ii) coal combustion residual ("CCR") management units (regardless of how or when the CCR was placed) at regulated facilities. The rule also creates an obligation to conduct site assessments (at all active and certain inactive facilities) to determine whether CCR management units are present. The rule has been challenged in the D.C. Circuit and the outcome of the legal challenges is uncertain. The Company anticipates that the new U.S. presidential administration will revisit this 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.
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.
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ELG — In 2015, the EPA revised the ELG for Steam Electric Generating Facilities, which imposed more stringent requirements (as individual permits were renewed) for wastewater streams from FGD, fly ash, bottom ash and flue gas mercury control. In 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. In October 2021, NRG informed its regulators that the Company intends to comply with the ELG by ceasing combustion of coal by the end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants that have coal-fired units in Texas. On May 9, 2024, the EPA promulgated a rule that revises the ELG by, among other things, further restricting the discharge of (i) FGD wastewater, (ii) bottom ash transport water, and (iii) combustion residual leachate. The rule was challenged in numerous courts, but the cases have been consolidated in the Eighth Circuit of the United States Court of Appeals. The outcome of the legal challenges is uncertain. The Company anticipates that the new U.S. presidential administration will revisit this rule.
Regional Environmental Developments
Ash Regulation in Illinois — On July 30, 2019, Illinois enacted legislation that required 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. NRG has applied for initial operating permits and construction permits (for closure and retrofits) as required by the regulation and is waiting for most of its permits to be issued by the Illinois EPA.
Houston Nonattainment for 2008 Ozone Standard — In 2022, the EPA changed the Houston area's classification from Serious to Severe nonattainment for the 2008 Ozone Standard. Accordingly, Texas is required to develop a new control strategy and submit it to the EPA.
Significant Events
The following significant events have occurred during 2024 as further described within this Management's Discussion and Analysis and the condensed consolidated financial statements:
Dispositions
On September 16, 2024, the Company closed on the sale of its 100% ownership in the Airtron business unit. Proceeds of $500 million were reduced by working capital and other adjustments of $16 million, resulting in net proceeds of $484 million. The Company recorded a gain on the sale of $208 million within the West/Services/Other region of operations.
Capital Allocation
During the nine months ended September 30, 2024, the Company completed $319 million of open market share repurchases at an average price of $79.26 per share. Through October 31, 2024, an additional $225 million share repurchases were executed at an average price of $89.23 per share. See Note 9, Changes in Capital Structure for additional discussion.
In October 2024, the Board of Directors authorized an additional $1.0 billion for share repurchases as part of the existing share repurchase authorization. As of October 31, 2024, $2.0 billion is remaining under the $3.7 billion authorization.
On November 6, 2023, the Company executed Accelerated Share Repurchase agreements to repurchase a total of $950 million of NRG's outstanding common stock. The Company received shares of NRG's common stock on specified settlement dates. The ASR program concluded on March 28, 2024, with total of 18,839,372 shares received at an average price of $50.43 per share.
In the first quarter of 2024, NRG increased the annual common stock dividend to $1.63 from $1.51 per share, representing an 8% increase from 2023. Beginning in the first quarter of 2025, NRG will increase the annual dividend by 8% to $1.76 per share. The Company expects to target an annual dividend growth rate of 7-9% per share in subsequent years.
On April 16, 2024, the Company, as borrower, and certain of its subsidiaries, as guarantors, entered into the Eighth Amendment with, among others, Citicorp North America, Inc., as administrative agent and as the Agent, and certain financial institutions, as lenders, which amended the Credit Agreement, in order to (i) establish a new Term Loan Facility with borrowings of $875 million in aggregate principal amount and the Term Loans and (ii) make certain other modifications to the Credit Agreement as set forth therein. The proceeds from the Term Loans were used to repay a portion of the Company’s Convertible Senior Notes, all of the Company's 3.750% senior secured first lien notes due 2024 and for general corporate purposes. For further discussion, see Note 7, Long-term Debt and Finance Leases.
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During the nine months ended September 30, 2024, the Company repurchased $343 million in aggregate principal amount of its Convertible Senior Notes, for $603 million, which included the payment of $3 million of accrued interest, using cash on hand and a portion of the proceeds from the Term Loans. For further discussion, see Note 7, Long-term Debt and Finance Leases.
During the second quarter of 2024, the Company entered into privately negotiated capped call transactions with certain counterparties to effectively lock in a conversion premium of $257 million on the remaining $232 million of the Convertible Senior Notes. The option price of $257 million was incurred when the Company entered into the capped call transactions, which will be payable upon the earlier of settlement and expiration of the applicable Capped Call. For further discussion see Note 9, Changes in Capital Structure.
On June 21, 2024, NRG Receivables, amended its existing Receivables Facility to, among other things, (i) extend the scheduled termination date to June 20, 2025, (ii) increase the aggregate commitments from $1.4 billion to $2.3 billion (adjusted seasonally) and (iii) add a new originator. For further discussion, see Note 7, Long-term Debt and Finance Leases.
During the second quarter of 2024, the Company repaid $600 million in aggregate principal amount of its 3.750% Senior Secured First Lien Notes due 2024.
Debt Refinancing Transactions
In the fourth quarter of 2024, the Company entered into the following debt transactions:
Sources
Uses
Issuance by NRG of 6.000% Senior Notes due 2033
$925 million
Repayment of the Vivint Senior Secured Term Loan B
$1.310 billion
Issuance by NRG of 6.250% Senior Notes due 2034
$950 million
Cash tender offer for Vivint 6.750% Senior Secured Notes due 2027(a)
$600 million
Exchange offer for New NRG 5.750% Senior Notes due 2029
$798 million
Exchange offer for Vivint 5.750% Senior Notes due 2029(b)
$798 million
Incremental Term Loan B issued by NRG
$450 million
Repayment of NRG 6.625% Senior Notes due 2027
$375 million
Cash on hand
$5 million
Estimated transactions fees, expenses and premiums
$45 million
Total
$3.128 billion
Total
$3.128 billion
(a)On October 30, 2024, APX Group, Inc. delivered a notice of redemption with respect to the Vivint 6.750% Senior Secured Notes due 2027 to redeem the $11 million of the Vivint 6.750% Senior Secured Notes due 2027 that remained outstanding following the Tender Offer on November 8, 2024
(b)On November 4, 2024, APX Group, Inc. delivered a notice of redemption with respect to the Vivint 5.750% Senior Notes due 2029 to redeem the approximate $2 million of the Vivint 5.750% Senior Notes due 2029 that remained outstanding following the Exchange Offer on November 14, 2024
As part of the above transactions, the Company entered into the Tenth Amendment and Eleventh Amendment to the Credit Agreement to (i) increase the term loan B in an aggregate principal balance of $450 million, (ii) make certain other amendments to the Credit Agreement and (iii) extend the maturity date of its revolving credit facility to October 30, 2029. For further discussion on these amendments and the debt transactions in the table above, see Note 7, Long-term Debt and Finance Leases.
Operations
NRG has entered into a definitive partnership agreement with Renew Home, a leading Virtual Power Plant platform ("VPP") formed by the combination of Google's Nest Renew and OhmConnect. This first-of-its-kind commercial partnership reinforces NRG's customer focus and brings to market unique products and services which will help customers save money while enjoying the benefits of a seamless energy and smart home experience. Leveraging Google Cloud's AI and cloud platforms, NRG and Renew Home plan to develop a VPP portfolio of up to 1 GW of load management capacity, with instantaneous dispatch value during peak events and tight supply conditions. Participating customers will enroll in an NRG branded energy plan and will be eligible for favorable rates on Vivint Smart Home services and additional products. The partnership will initially focus in Texas, with Renew Home supporting upfront customer acquisition costs and Google Nest integration.
A component of the Company's strategy is to procure mid to long-term generation through power purchase agreements. NRG has entered into Renewable PPAs totaling approximately 1.9 GW with third-party project developers and other counterparties, of which all are operational as of September 30, 2024. The average tenure of these agreements is eleven years. The Company expects to continue evaluating and executing similar agreements that support the needs of the business. The total GW procured through Renewable PPAs may be impacted by contract terminations when they occur.
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Trends Affecting Results of Operations and Future Business Performance
The Company’s trends are described in the Company’s 2023 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Environment, except for the update below:
Load Growth — The electric industry is expected to experience a surge in demand driven primarily by new manufacturing, industrial and data center facilities (inclusive of generative artificial intelligence ("gen AI")). The U.S. Energy Information Administration's 2023 Annual Energy Outlook, combined with external forecasts of gen AI, shows the potential for 500 TWh of incremental load across the U.S. through 2030, as compared to 2023. ERCOT's current long term load forecast shows peak demand increasing from 86 GW in 2024 to 137 GW in 2028. This load growth will require significant planning and construction of new generation and transmission. ERCOT has announced its New Era of Planning effort to prepare for the possibility of very large and rapid load growth.
Texas Development Priorities
In the third quarter of 2024, the PUCT selected the T.H. Wharton project to move forward in the due diligence process for the Texas Energy Fund. The Company continues to explore its options for the Cedar Bayou 5 and Greens Bayou 6 projects. NRG's shovel ready projects are as follows:
Facility
Fuel Type
Net Generation Capacity (MW)
Cedar Bayou 5
Natural Gas
689
Greens Bayou 6
Natural Gas
448
T.H. Wharton
Natural Gas
415
Total
1,552
Changes in Accounting Standards
See Note 2, Summary of Significant Accounting Policies, for a discussion of recent accounting developments.
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Consolidated Results of Operations
The following table provides selected financial information for the Company:
Three months ended September 30,
Nine months ended September 30,
(In millions)
2024
2023
Change
2024
2023
Change
Revenue
Retail revenue
$
6,954
$
7,521
$
(567)
$
20,527
$
20,911
$
(384)
Energy revenue(a)
128
261
(133)
390
472
(82)
Capacity revenue(a)
47
59
(12)
133
150
(17)
Mark-to-market for economic hedging activities
8
(70)
78
32
96
(64)
Contract amortization
(8)
(5)
(3)
(25)
(24)
(1)
Other revenues(a)(b)
94
180
(86)
254
411
(157)
Total revenue
7,223
7,946
(723)
21,311
22,016
(705)
Operating Costs and Expenses
Cost of fuel
296
400
104
648
790
142
Purchased energy and other cost of sales(c)
4,775
5,585
810
14,723
15,863
1,140
Mark-to-market for economic hedging activities
1,638
(17)
(1,655)
315
2,029
1,714
Contract and emissions credit amortization(c)
(3)
(12)
(9)
43
78
35
Operations and maintenance
401
335
(66)
1,192
1,076
(116)
Other cost of operations
132
115
(17)
308
301
(7)
Cost of operations (excluding depreciation and amortization shown below)
7,239
6,406
(833)
17,229
20,137
2,908
Depreciation and amortization
352
359
7
1,045
921
(124)
Impairment losses
—
—
—
15
—
(15)
Selling, general and administrative costs (excluding amortization of customer acquisition costs of $55, $36, $144 and $84, respectively, which are included in depreciation and amortization shown separately above)
645
602
(43)
1,739
1,502
(237)
Acquisition-related transaction and integration costs
7
18
11
22
111
89
Total operating costs and expenses
8,243
7,385
(858)
20,050
22,671
2,621
Gain on sale of assets
208
—
208
209
202
7
Operating (Loss)/Income
(812)
561
(1,373)
1,470
(453)
1,923
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates
6
6
—
13
16
(3)
Other income, net
5
14
(9)
38
43
(5)
Loss on debt extinguishment
—
—
—
(260)
—
(260)
Interest expense
(213)
(173)
(40)
(528)
(472)
(56)
Total other expense
(202)
(153)
(49)
(737)
(413)
(324)
(Loss)/Income Before Income Taxes
(1,014)
408
(1,422)
733
(866)
1,599
Income tax (benefit)/expense
(247)
65
312
251
(182)
(433)
Net (Loss)/Income
$
(767)
$
343
$
(1,110)
$
482
$
(684)
$
1,166
(a)Includes gains and losses from financially settled transactions
(b)Includes trading gains and losses and ancillary revenues
(c)Includes amortization of SO2 and NOxcredits and excludes amortization of RGGI credits
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Management’s discussion of the results of operations for the three months ended September 30, 2024 and 2023
Electricity Prices
The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the three months ended September 30, 2024 and 2023.
Average on Peak Power Price ($/MWh)
Three months ended September 30,
Region
2024
2023
Change %
Texas
ERCOT - Houston(a)
$
34.12
$
183.49
(81)
%
ERCOT - North(a)
34.21
181.72
(81)
%
East
NY J/NYC(b)
$
44.09
$
40.86
8
%
NEPOOL(b)
45.87
40.41
14
%
COMED (PJM)(b)
38.03
39.38
(3)
%
PJM West Hub(b)
49.70
43.27
15
%
West
MISO - Louisiana Hub(b)
$
30.68
$
38.53
(20)
%
CAISO - SP15(b)
43.12
67.59
(36)
%
(a)Average on peak power prices based on real time settlement prices as published by the respective ISOs
(b)Average on peak power prices based on day ahead settlement prices as published by the respective ISOs
Natural Gas Prices
The following table summarizes the average Henry Hub natural gas price for the three months ended September 30, 2024 and 2023:
Three months ended September 30,
2024
2023
Change %
($/MMBtu)
$
2.16
$
2.55
(15)
%
Gross Margin
The Company calculates gross margin in order to evaluate operating performance as revenues less cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emissions credit amortization and depreciation and amortization.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of retail revenue, energy revenue, capacity revenue and other revenue, less cost of fuel, purchased energy and other cost of sales. Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emissions credit amortization, depreciation and amortization, operations and maintenance, or other cost of operations.
57
The following tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended September 30, 2024 and 2023:
Three months ended September 30, 2024
($ In millions)
Texas
East
West/Services/Other
Vivint Smart Home
Corporate/Eliminations
Total
Retail revenue
$
3,231
$
2,468
$
760
$
499
$
(4)
$
6,954
Energy revenue
12
67
52
—
(3)
128
Capacity revenue
—
40
8
—
(1)
47
Mark-to-market for economic hedging activities
—
1
6
—
1
8
Contract amortization
—
(7)
(1)
—
—
(8)
Other revenue(a)
58
31
8
—
(3)
94
Total revenue
3,301
2,600
833
499
(10)
7,223
Cost of fuel
(226)
(44)
(26)
—
—
(296)
Purchased energy and other cost of sales(b)(c)(d)
(1,996)
(2,122)
(625)
(37)
5
(4,775)
Mark-to-market for economic hedging activities
(1,537)
(10)
(90)
—
(1)
(1,638)
Contract and emissions credit amortization
(5)
11
(3)
—
—
3
Depreciation and amortization
(81)
(39)
(23)
(198)
(11)
(352)
Gross margin
$
(544)
$
396
$
66
$
264
$
(17)
$
165
Less: Mark-to-market for economic hedging activities, net
(1,537)
(9)
(84)
—
—
(1,630)
Less: Contract and emissions credit amortization, net
(5)
4
(4)
—
—
(5)
Less: Depreciation and amortization
(81)
(39)
(23)
(198)
(11)
(352)
Economic gross margin
$
1,079
$
440
$
177
$
462
$
(6)
$
2,152
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $960 million, $61 million and $203 million of TDSP expense in Texas, East and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately
Business Metrics
Texas
East
West/Services/Other
Vivint Smart Home
Corporate/Eliminations
Total
Retail sales
Home electricity sales volume (GWh)
13,126
4,357
582
—
—
18,065
Business electricity sales volume (GWh)
11,196
12,583
1,973
—
—
25,752
Home natural gas sales volume (MDth)
—
3,464
4,985
—
—
8,449
Business natural gas sales volume (MDth)
—
312,871
36,617
—
—
349,488
Average retail Home customer count (in thousands)(a)
2,946
2,157
755
—
—
5,858
Ending retail Home customer count (in thousands)(a)
2,921
2,132
718
—
—
5,771
Average Vivint Smart Home subscriber count (in thousands)(b)
—
—
—
2,137
—
2,137
Ending Vivint Smart Home subscriber count (in thousands) (b)
—
—
—
2,154
—
2,154
Power generation
GWh sold
8,598
1,521
1,468
—
—
11,587
GWh generated(c)
Coal
5,417
1,040
—
—
—
6,457
Gas
3,181
1
1,467
—
—
4,649
Oil
—
1
—
—
—
1
Renewables
—
—
1
—
—
1
Total
8,598
1,042
1,468
—
—
11,108
(a) Home customer count includes recurring residential customers, services customers and community choice
(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments
58
Three months ended September 30, 2023
($ In millions)
Texas
East
West/Services/Other
Vivint Smart Home
Corporate/Eliminations
Total
Retail revenue
$
3,489
$
2,633
$
922
$
478
$
(1)
$
7,521
Energy revenue
51
152
59
—
(1)
261
Capacity revenue
—
64
(4)
—
(1)
59
Mark-to-market for economic hedging activities
—
(60)
(10)
—
—
(70)
Contract amortization
—
(6)
1
—
—
(5)
Other revenue(a)
146
26
10
—
(2)
180
Total revenue
3,686
2,809
978
478
(5)
7,946
Cost of fuel
(300)
(64)
(36)
—
—
(400)
Purchased energy and other cost of sales(b)(c)(d)
(2,359)
(2,385)
(808)
(36)
3
(5,585)
Mark-to-market for economic hedging activities
(42)
244
(185)
—
—
17
Contract and emissions credit amortization
(5)
22
(5)
—
—
12
Depreciation and amortization
(84)
(39)
(24)
$
(203)
(9)
(359)
Gross margin
$
896
$
587
$
(80)
$
239
$
(11)
$
1,631
Less: Mark-to-market for economic hedging activities, net
(42)
184
(195)
—
—
(53)
Less: Contract and emissions credit amortization, net
(5)
16
(4)
—
—
7
Less: Depreciation and amortization
(84)
(39)
(24)
(203)
(9)
(359)
Economic gross margin
$
1,027
$
426
$
143
$
442
$
(2)
$
2,036
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $1.0 billion, $69 million and $207 million of TDSP expense in Texas, East, and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately
Business Metrics
Texas
East
West/Services/Other
Vivint Smart Home
Corporate/Eliminations
Total
Retail sales
Home electricity sales volume (GWh)
15,034
3,799
531
—
—
19,364
Business electricity sales volume (GWh)
12,116
13,296
2,889
—
—
28,301
Home natural gas sales volume (MDth)
—
3,438
5,064
—
—
8,502
Business natural gas sales volume (MDth)
—
351,154
39,953
—
—
391,107
Average retail Home customer count (in thousands)(a)
2,879
1,880
769
—
—
5,528
Ending retail Home customer count (in thousands)(a)
2,871
1,889
765
—
—
5,525
Average Vivint Smart Home subscriber count (in thousands)(b)
—
—
—
2,035
—
2,035
Ending Vivint Smart Home subscriber count (in thousands)(b)
—
—
—
2,051
—
2,051
Power generation
GWh sold
11,918
2,837
1,726
—
—
16,481
GWh generated(c)
Coal
5,459
873
—
—
—
6,332
Gas
3,964
600
1,725
—
—
6,289
Nuclear
2,495
—
—
—
—
2,495
Oil
—
5
—
—
5
Renewables
—
—
1
—
—
1
Total
11,918
1,478
1,726
—
—
15,122
(a) Home customer count includes recurring residential customers, services customers and community choice
(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments
59
The following table represents the weather metrics for the three months ended September 30, 2024 and 2023:
Three months ended September 30,
Weather Metrics
Texas
East
West/Services/Other(b)
2024
CDDs(a)
1,714
814
1,194
HDDs(a)
—
28
11
2023
CDDs
2,039
817
1,291
HDDs
—
48
4
10-year average
CDDs
1,710
833
1,192
HDDs
3
49
8
(a) National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period
(b) The West/Services/Other weather metrics are comprised of the average of the CDD and HDD regional results for the West - California and West - South Central regions
Gross Margin and Economic Gross Margin
Gross margin decreased $1.5 billion and economic gross margin increased $116 million during the three months ended September 30, 2024, compared to the same period in 2023.
The following tables describe the changes in gross margin and economic gross margin by segment:
Texas
(In millions)
Higher gross margin due to the net effect of:
•a 5%, or $66 million decrease in cost to serve the retail load, driven by lower realized power prices associated with the Company's diversified supply strategy including asset sales in 2023
•an increase in net revenue of $64 million, primarily driven by changes in customer term, product and mix
$
130
Lower gross margin due to a decrease in load of 2.3 TWhs, or $74 million, due to weather and a decrease in load of 526 GWhs, or $8 million, driven by a change in customer mix
(82)
Other
4
Increase in economic gross margin
$
52
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
(1,495)
Decrease in depreciation and amortization
3
Decrease in gross margin
$
(1,440)
60
East
(In millions)
Lower gross margin due to a decrease in generation and capacity as a result of asset retirements
$
(3)
Lower electric gross margin due to higher supply costs of $3.50 per MWh, or $67 million, driven primarily by increases in power prices, partially offset by higher net revenue rates as a result of changes in customer term, product and mix of $3.75 per MWh, or $63 million
(4)
Higher electric gross margin due to weather
4
Lower natural gas gross margin from a decrease in load due to customer count and change in customer mix
(12)
Higher natural gas gross margin, including the impact of transportation and storage contract optimization, resulting in lower supply costs of $0.45 per Dth, or $151 million, driven primarily by decreases in gas costs, partially offset by lower net revenue rates from changes in customer term, product, and mix of $0.30 per Dth, or $100 million
51
Lower gross margin due to a reduction in realized capacity prices, as well as a prior year reduction in capacity performance penalties resulting from Winter Storm Elliott in December 2022
(30)
Other
8
Increase in economic gross margin
$
14
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
(193)
Increase in contract amortization
(12)
Decrease in gross margin
$
(191)
West/Services/Other
(In millions)
Higher electric gross margin due to lower supply costs of $33.00 per MWh, or $117 million, partially offset by lower revenue rates of $25.00 per MWh, or $88 million
$
29
Higher gross margin at Cottonwood due to a prior year reduction in capacity performance bonus payments resulting from Winter Storm Elliott in December 2022, higher capacity revenues and spark spread expansion
15
Lower gross margin at Services primarily due to the sale of Airtron
(7)
Other
(3)
Increase in economic gross margin
$
34
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
111
Decrease in depreciation and amortization
1
Increase in gross margin
$
146
Vivint Smart Home
(In millions)
Higher gross margin driven by growth in subscribers, or $22 million and higher revenue rates of $2.04 per subscriber, or $14 million, partially offset by lower non-recurring sales revenue of $15 million
$
21
Lower gross margin due to recognition of fees associated with licensing products and services
(3)
Other
2
Increase in economic gross margin
$
20
Decrease in depreciation and amortization
5
Increase in gross margin
$
25
61
Mark-to-Market for Economic Hedging Activities
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results decreased by $1.6 billion during the three months ended September 30, 2024, compared to the same period in 2023.
The breakdown of gains and losses included in revenues and operating costs and expenses, by segment, was as follows:
Three months ended September 30, 2024
(In millions)
Texas
East
West/Services/Other
Eliminations
Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized losses on settled positions related to economic hedges
$
—
$
4
$
9
$
1
$
14
Reversal of acquired (gain) positions related to economic hedges
—
(1)
—
—
(1)
Net unrealized (losses) on open positions related to economic hedges
—
(2)
(3)
—
(5)
Total mark-to-market gains in revenue
$
—
$
1
$
6
$
1
$
8
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges
$
(498)
$
96
$
(25)
$
(1)
$
(428)
Reversal of acquired (gain)/loss positions related to economic hedges
(9)
3
(1)
—
(7)
Net unrealized (losses) on open positions related to economic hedges
(1,030)
(109)
(64)
—
(1,203)
Total mark-to-market (losses) in operating costs and expenses
$
(1,537)
$
(10)
$
(90)
$
(1)
$
(1,638)
Three months ended September 30, 2023
(In millions)
Texas
East
West/Services/Other
Eliminations
Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges
$
—
$
(8)
$
20
$
(2)
$
10
Net unrealized (losses) on open positions related to economic hedges
—
(52)
(30)
2
(80)
Total mark-to-market (losses) in revenue
$
—
$
(60)
$
(10)
$
—
$
(70)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges
$
(298)
$
(142)
$
(94)
$
2
$
(532)
Reversal of acquired (gain)/loss positions related to economic hedges
(11)
11
(6)
—
(6)
Net unrealized gains/(losses) on open positions related to economic hedges
267
375
(85)
(2)
555
Total mark-to-market (losses)/gains in operating costs and expenses
$
(42)
$
244
$
(185)
$
—
$
17
`
Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.
For the three months ended September 30, 2024, the $8 million gain in revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period. The $1.6 billion loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in power prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period.
For the three months ended September 30, 2023, the $70 million loss in revenues from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of increases in PJM power prices. The $17 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of Texas and East open positions as a result of increases in ERCOT and PJM power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period.
62
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended September 30, 2024 and 2023. The realized and unrealized financial and physical trading results are included in revenue. The Company's trading activities are subject to limits based on the Company's Risk Management Policy.
Three months ended September 30,
(In millions)
2024
2023
Trading gains/(losses)
Realized
$
25
$
7
Unrealized
(5)
(1)
Total trading gains
$
20
$
6
Operations and Maintenance Expense
Operations and maintenance expense is comprised of the following:
(In millions)
Texas
East
West/Services/Other
Vivint Smart Home
Corporate/Eliminations
Total
Three months ended September 30, 2024
$
170
$
102
$
61
$
67
$
1
$
401
Three months ended September 30, 2023
131
93
55
57
(1)
335
Operations and maintenance expense increased by $66 million for the three months ended September 30, 2024, compared to the same period in 2023, due to the following:
(In millions)
Increase primarily due to the prior year partial property insurance claim for the extended outage at W.A. Parish
$
51
Increase in planned major maintenance expenditures primarily associated with the scope of outages at the Texas coal facilities and Cottonwood
35
Increase driven by higher retail operations costs
17
Increase driven by higher Vivint Smart Home operations costs
10
Decrease primarily due to the sale of STP in November 2023
(33)
Decrease driven by a reduction in deactivation and asset retirement expenditures primarily in the East
(10)
Other
(4)
Increase in operations and maintenance expense
$
66
Other Cost of Operations
Other cost of operations is comprised of the following:
(In millions)
Texas
East
West/Services/Other
Vivint Smart Home
Total
Three months ended September 30, 2024
$
80
$
46
$
4
$
2
$
132
Three months ended September 30, 2023
78
33
3
1
115
Other cost of operations for the three months ended September 30, 2024 increased by $17 million, when compared to the same period in 2023, due to the following:
(In millions)
Increase due to changes in current year ARO cost estimates at Midwest Generation and Jewett Mine
$
17
Increase primarily due to higher retail gross receipt taxes in the East
6
Decrease primarily due to the sale of STP in November 2023
(7)
Increase due to higher insurance premiums
1
Increase in other cost of operations
$
17
63
Depreciation and Amortization
Depreciation and amortization are comprised of the following:
(In millions)
Texas
East
West/Services/Other
Vivint Smart Home
Corporate
Total
Three months ended September 30, 2024
$
81
$
39
$
23
$
198
$
11
$
352
Three months ended September 30, 2023
84
39
24
203
9
359
Depreciation and amortization decreased by $7 million for the three months ended September 30, 2024, compared to the same period in 2023, due to the following:
(In millions)
Decrease in amortization primarily driven by the expected roll off of the acquired Vivint Smart Home intangibles
$
(32)
Increase in amortization of capitalized contract costs
40
Other
(15)
Decrease in depreciation and amortization
$
(7)
Selling, General and Administrative Costs
Selling, general and administrative costs are comprised of the following:
(In millions)
Texas
East
West/Services/Other
Vivint Smart Home
Corporate/Elimination
Total
Three months ended September 30, 2024
$
260
$
157
$
66
$
151
$
11
$
645
Three months ended September 30, 2023
225
144
65
161
7
602
Selling, general and administrative costs increased by $43 million for the three months ended September 30, 2024, compared to the same period in 2023, due to the following:
(In millions)
Increase in personnel costs primarily driven by an increase in accruals as part of the Company's annual incentive plan reflecting financial outperformance for the year
$
54
Increase in provision for credit losses due to Hurricane Beryl related disconnect moratorium and customer payment behavior
10
Decrease in broker fee and commission expenses
(4)
Decrease in marketing and media expenses
(3)
Decrease due to the sale of STP in November 2023
(3)
Other
(11)
Increase in selling, general and administrative costs
$
43
Acquisition-Related Transaction and Integration Costs
Acquisition-related transaction and integration costs of $7 million and $18 million for the three months ended September 30, 2024 and 2023, respectively, include:
Three months ended September 30,
(In millions)
2024
2023
Vivint Smart Home integration costs
$
4
$
2
Other integration costs, primarily related to Direct Energy
3
16
Acquisition-related transaction and integration costs
$
7
$
18
64
Gain on Sale of Assets
The gain on sale of assets of $208 million for the three months ended September 30, 2024 was due to the sale of the Airtron business unit.
Interest Expense
Interest expense increased by $40 million for the three months ended September 30, 2024, compared to the same period in 2023, primarily due to unrealized losses on interest rate swaps for the 2024 period as compared to unrealized gains in the 2023 period.
Income Tax (Benefit)/Expense
For the three months ended September 30, 2024, income tax benefit of $247 million was recorded on pre-tax loss of $1.0 billion. For the same period in 2023, an income tax expense of $65 million was recorded on pre-tax income of $408 million. The effective tax rates were 24.4% and 15.9% for the three months ended September 30, 2024 and 2023, respectively.
For the three months ended September 30, 2024, the effective tax rate was higher than the statutory rate of 21% primarily due to the state tax expense. For the same period in 2023, the effective tax rate was lower than the statutory rate of 21% primarily due to a decrease in state tax expense resulting from a decrease in year-to-date financial statement losses.
65
Management’s discussion of the results of operations for the nine months ended September 30, 2024 and 2023
Electricity Prices
The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the nine months ended September 30, 2024 and 2023.
Average on Peak Power Price ($/MWh)
Nine months ended September 30,
Region
2024
2023
Change %
Texas
ERCOT - Houston (a)
$
34.09
$
89.00
(62)
%
ERCOT - North(a)
32.19
87.49
(63)
%
East
NY J/NYC(b)
$
42.79
$
39.43
9
%
NEPOOL(b)
42.62
41.87
2
%
COMED (PJM)(b)
32.50
33.05
(2)
%
PJM West Hub(b)
41.07
38.39
7
%
West
MISO - Louisiana Hub(b)
$
29.78
$
34.54
(14)
%
CAISO - SP15(b)
28.17
63.38
(56)
%
(a) Average on peak power prices based on real time settlement prices as published by the respective ISOs
(b) Average on peak power prices based on day ahead settlement prices as published by the respective ISOs
Natural Gas Prices
The following table summarizes the average Henry Hub natural gas price for the nine months ended September 30, 2024 and 2023:
Nine months ended September 30,
2024
2023
Change %
($/MMBtu)
$
2.10
$
2.69
(22)
%
Gross Margin
The Company calculates gross margin in order to evaluate operating performance as revenues less cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emissions credit amortization and depreciation and amortization.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuel, purchased energy and other cost of sales. Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract and emissions credit amortization, depreciation and amortization, operations and maintenance, or other cost of operations.
66
The following tables present the composition and reconciliation of gross margin and economic gross margin for the nine months ended September 30, 2024 and 2023:
Nine months ended September 30, 2024
($ In millions)
Texas
East
West/Services/Other
Vivint Smart Home
Corporate/Eliminations
Total
Retail revenue
$
8,101
$
8,257
$
2,747
$
1,434
$
(12)
$
20,527
Energy revenue
35
194
170
—
(9)
390
Capacity revenue
—
120
16
—
(3)
133
Mark-to-market for economic hedging activities
—
15
14
—
3
32
Contract amortization
—
(23)
(2)
—
—
(25)
Other revenue(a)
161
84
17
—
(8)
254
Total revenue
8,297
8,647
2,962
1,434
(29)
21,311
Cost of fuel
(471)
(98)
(79)
—
—
(648)
Purchased energy and other cost of sales(b)(c)(d)
(5,212)
(7,078)
(2,342)
(108)
17
(14,723)
Mark-to-market for economic hedging activities
(707)
595
(200)
—
(3)
(315)
Contract and emissions credit amortization
(7)
(31)
(5)
—
—
(43)
Depreciation and amortization
(240)
(117)
(96)
$
(561)
(31)
(1,045)
Gross margin
$
1,660
$
1,918
$
240
$
765
$
(46)
$
4,537
Less: Mark-to-market for economic hedging activities, net
(707)
610
(186)
—
—
(283)
Less: Contract and emissions credit amortization, net
(7)
(54)
(7)
—
—
(68)
Less: Depreciation and amortization
(240)
(117)
(96)
(561)
(31)
(1,045)
Economic gross margin
$
2,614
$
1,479
$
529
$
1,326
$
(15)
$
5,933
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $2.6 billion, $197 million and $860 million of TDSP expense in Texas, East, and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately
Business Metrics
Texas
East
West/Services/Other
Vivint Smart Home
Corporate/Eliminations
Total
Retail sales
Home electricity sales volume (GWh)
31,540
11,803
1,722
—
—
45,065
Business electricity sales volume (GWh)
30,936
35,792
7,985
—
—
74,713
Home natural gas sales volume (MDth)
—
33,577
50,027
—
—
83,604
Business natural gas sales volume (MDth)
—
1,118,695
134,310
—
—
1,253,005
Average retail Home customer count (in thousands)(a)
2,949
2,168
761
—
—
5,878
Ending retail Home customer count (in thousands)(a)
2,921
2,132
718
—
—
5,771
Average Vivint Smart Home subscriber count (in thousands)(b)
—
—
—
2,083
—
2,083
Ending Vivint Smart Home subscriber count (in thousands)(b)
—
—
—
2,154
—
2,154
Power generation
GWh sold
16,913
3,639
4,342
—
—
24,894
GWh generated(c)
Coal
10,353
2,005
—
—
—
12,358
Gas
6,560
1
4,338
—
—
10,899
Oil
—
4
—
—
—
4
Renewables
—
—
4
—
—
4
Total
16,913
2,010
4,342
—
—
23,265
(a) Home customer count includes recurring residential customers, services customers and community choice
(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments
67
Nine months ended September 30, 2023
($ In millions)
Texas
East
West/Services/Other
Vivint Smart Home(a)
Corporate/Eliminations
Total
Retail revenue
$
7,842
$
9,007
$
2,993
$
1,070
$
(1)
$
20,911
Energy revenue
71
254
147
—
—
472
Capacity revenue
—
154
(3)
—
(1)
150
Mark-to-market for economic hedging activities
—
27
80
—
(11)
96
Contract amortization
—
(24)
—
—
—
(24)
Other revenue(b)
322
70
27
—
(8)
411
Total revenue
8,235
9,488
3,244
1,070
(21)
22,016
Cost of fuel
(596)
(102)
(92)
—
—
(790)
Purchased energy and other cost of sales(c)(d)(e)
(5,017)
(8,091)
(2,679)
(82)
6
(15,863)
Mark-to-market for economic hedging activities
421
(1,750)
(711)
—
11
(2,029)
Contract and emissions credit amortization
(9)
(59)
(10)
—
—
(78)
Depreciation and amortization
(257)
(122)
(73)
$
(442)
(27)
(921)
Gross margin
$
2,777
$
(636)
$
(321)
$
546
$
(31)
$
2,335
Less: Mark-to-market for economic hedging activities, net
421
(1,723)
(631)
—
—
(1,933)
Less: Contract and emissions credit amortization, net
(9)
(83)
(10)
—
—
(102)
Less: Depreciation and amortization
(257)
(122)
(73)
(442)
(27)
(921)
Economic gross margin
$
2,622
$
1,292
$
393
$
988
$
(4)
$
5,291
(a) Includes results of operations following the acquisition date of March 10, 2023
(b) Includes trading gains and losses and ancillary revenues
(c) Includes capacity and emissions credits
(d) Includes $2.4 billion, $174 million and $806 million of TDSP expense in Texas, East and West/Services/Other, respectively
(e) Excludes depreciation and amortization shown separately
Business Metrics
Texas
East
West/Services/Other
Vivint Smart Home
Corporate/Eliminations
Total
Retail sales
Home electricity sales volume (GWh)
32,447
9,667
1,676
—
—
43,790
Business electricity sales volume (GWh)
30,712
35,138
7,564
—
—
73,414
Home natural gas sales volume (MDth)
—
33,549
53,379
—
—
86,928
Business natural gas sales volume (MDth)
—
1,174,282
133,011
—
—
1,307,293
Average retail Home customer count (in thousands)(a)
2,872
1,834
777
—
—
5,483
Ending retail Home customer count (in thousands)(a)
2,871
1,889
765
—
—
5,525
Average Vivint Smart Home subscriber count (in thousands)(b)
—
—
—
1,991
—
1,991
Ending Vivint Smart Home subscriber count (in thousands)(b)
—
—
—
2,051
—
2,051
Power generation
GWh sold
24,612
4,719
4,595
—
—
33,926
GWh generated(c)
Coal
11,230
1,239
—
—
—
12,469
Gas
6,374
685
4,592
—
—
11,651
Nuclear
7,008
—
—
—
—
7,008
Oil
—
4
—
—
—
4
Renewables
—
—
3
—
—
3
Total
24,612
1,928
4,595
—
—
31,135
(a) Home customer count includes recurring residential customers, services customers and community choice
(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments
68
The following table represents the weather metrics for the nine months ended September 30, 2024 and 2023:
Nine months ended September 30,
Weather Metrics
Texas
East
West/Services/Other(b)
2024
CDDs(a)
3,003
1,277
1,881
HDDs(a)
916
2,676
1,310
2023
CDDs
3,183
1,144
1,866
HDDs
856
2,619
1,417
10-year average
CDDs
2,811
1,225
1,797
HDDs
1,040
3,089
1,306
(a) National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period
(b) The West/Services/Other weather metrics are comprised of the average of the CDD and HDD regional results for the West-California and West-South Central regions
Gross Margin and Economic Gross Margin
Gross margin increased $2.2 billion and economic gross margin increased $642 million, both of which include intercompany sales, during the nine months ended September 30, 2024, compared to the same period in 2023.
The following tables describe the changes in gross margin and economic gross margin by segment:
Texas
(In millions)
Higher gross margin due to the net effect of:
•an increase in net revenue of $132 million primarily driven by changes in customer term, product and mix
•a 4%, or $103 million increase in cost to serve the retail load driven by higher realized power prices associated with the Company's diversified supply strategy including asset sales in 2023
$
29
Lower gross margin due to a decrease in load of 1.8 TWhs, or $57 million, due to weather, partially offset by an increase in load of 1.1 TWhs, or $23 million, driven by an increase in customer counts
(34)
Other
(3)
Decrease in economic gross margin
$
(8)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
(1,128)
Decrease in contract and emissions credit amortization
2
Decrease in depreciation and amortization
17
Decrease in gross margin
$
(1,117)
69
East
(In millions)
Lower gross margin due to a decrease in generation and capacity as a result of the Joliet and Astoria asset retirements
$
(20)
Higher electric gross margin due to higher net revenue rates as a result of changes in customer term, product and mix of $1.75 per MWh, or $79 million as well as lower supply costs of $0.75 per MWh, or $37 million, driven primarily by decreases in power prices
116
Higher electric gross margin due to an increase in customer count and a change in customer mix
31
Higher natural gas gross margin, including the impact of transportation and storage contract optimization, resulting in lower supply costs of $0.80 per Dth, or $938 million, driven primarily by a decrease in gas costs, partially offset by lower net revenue rates of $0.75 per Dth, or $879 million, from changes in customer term, product, and mix
59
Lower natural gas gross margin from a decrease in load due to customer count and a change in customer mix
(13)
Higher gross margin due to an increase in average realized price at Midwest Generation and tolled facilities, partially offset by higher supply costs
45
Lower gross margin due to a reduction in realized capacity prices, as well as a prior year reduction in capacity performance penalties resulting from Winter Storm Elliott in December 2022
(28)
Other
(3)
Increase in economic gross margin
$
187
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
2,333
Decrease in contract amortization
29
Decrease in depreciation and amortization
5
Increase in gross margin
$
2,554
West/Services/Other
(In millions)
Higher electric gross margin due to a decrease in supply costs of $21.00 per MWh, or $208 million, and changes in customer mix of $1 million, partially offset by lower revenue rates of $12.00 per MWh, or $118 million
$
91
Higher natural gas gross margin due to lower supply costs of $1.22 per Dth, or $224 million, partially offset by lower revenue rates of $1.15 per Dth, or $212 million, and changes in customer mix of $1 million
11
Higher gross margin at Cottonwood driven by spark spread expansion, favorable current year capacity
pricing and a prior year reduction in capacity performance bonus payments resulting from Winter Storm
Elliott in December 2022
53
Lower gross margin from market optimization activities
(11)
Lower gross margin at Services primarily due to higher costs primarily driven by inventory reserves, partially offset by increased sales
(9)
Other
1
Increase in economic gross margin
$
136
Increase in mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges
445
Decrease in contract amortization
3
Increase in depreciation and amortization
(23)
Increase in gross margin
$
561
70
Vivint Smart Home(a)
(In millions)
Increase due to the acquisition of Vivint Smart Home
$
289
Higher gross margin driven by growth in subscribers, or $53 million, higher revenue rates of $1.95 per subscriber or $29 million, partially offset by lower non-recurring sales revenue of $27 million
55
Lower gross margin due to recognition of fees associated with licensing products and services
(7)
Other
1
Increase in economic gross margin
$
338
Increase in depreciation and amortization
(119)
Increase in gross margin
$
219
(a) Includes results of operations following the acquisition date of March 10, 2023
Mark-to-Market for Economic Hedging Activities
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results increased by $1.7 billion during the nine months ended September 30, 2024, compared to the same period in 2023.
The breakdown of gains and losses included in revenues and operating costs and expenses by segment was as follows:
Nine months ended September 30, 2024
(In millions)
Texas
East
West/Services/Other
Eliminations
Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges
$
—
$
(28)
$
—
$
3
$
(25)
Reversal of acquired (gain) positions related to economic hedges
—
(1)
—
—
(1)
Net unrealized gains on open positions related to economic hedges
—
44
14
—
58
Total mark-to-market gains in revenue
$
—
$
15
$
14
$
3
$
32
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges
$
(616)
$
628
$
55
$
(3)
$
64
Reversal of acquired loss/(gain) positions related to economic hedges
2
(5)
1
—
(2)
Net unrealized (losses) on open positions related to economic hedges
(93)
(28)
(256)
—
(377)
Total mark-to-market (losses)/gains in operating costs and expenses
$
(707)
$
595
$
(200)
$
(3)
$
(315)
Nine months ended September 30, 2023
(In millions)
Texas
East
West/Services/Other
Eliminations
Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges
$
—
$
(23)
$
46
$
(8)
$
15
Reversal of acquired (gain) positions related to economic hedges
—
(1)
—
—
(1)
Net unrealized gains on open positions related to economic hedges
—
51
34
(3)
82
Total mark-to-market gains in revenue
$
—
$
27
$
80
$
(11)
$
96
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges
$
(416)
$
(697)
$
(429)
$
8
$
(1,534)
Reversal of acquired loss/(gain) positions related to economic hedges
7
3
(5)
—
5
Net unrealized gains/(losses) on open positions related to economic hedges
830
(1,056)
(277)
3
(500)
Total mark-to-market gains/(losses) in operating costs and expenses
$
421
$
(1,750)
$
(711)
$
11
$
(2,029)
Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.
71
For the nine months ended September 30, 2024, the $32 million gain in revenues from economic hedge positions was driven primarily by an increase in the value of open positions as a result of decreases in power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $315 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in power prices, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period.
For the nine months ended September 30, 2023, the $96 million gain in revenues from economic hedge positions was driven by an increase in the value of open positions as a result of decreases in power prices. The $2.0 billion loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, as well as a decrease in the value of East and West/Other open positions as a result of decreases in natural gas and power prices. This was partially offset by an increase in the value of Texas open positions as a result of increases in ERCOT power prices.
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the nine months ended September 30, 2024 and 2023. The realized and unrealized financial and physical trading results are included in revenue. The Company's trading activities are subject to limits based on the Company's Risk Management Policy.
Nine months ended September 30,
(In millions)
2024
2023
Trading gains
Realized
$
30
$
4
Unrealized
—
24
Total trading gains
$
30
$
28
Operations and Maintenance Expense
Operations and maintenance expense are comprised of the following:
(In millions)
Texas
East
West/Services/Other
Vivint Smart Home(a)
Corporate/Eliminations
Total
Nine months ended September 30, 2024
$
585
$
259
$
168
$
178
$
2
$
1,192
Nine months ended September 30, 2023
510
261
179
129
(3)
1,076
(a) Includes results of operations following the acquisition date of March 10, 2023
Operations and maintenance expense increased by $116 million for the nine months ended September 30, 2024, compared to the same period in 2023, due to the following:
(In millions)
Increase in planned major maintenance expenditures associated with the scope and duration of outages at the Texas coal facilities
$
99
Increase primarily due to the prior year partial property insurance claim for the extended outage at W.A. Parish
95
Increase due to the acquisition of Vivint Smart Home in March 2023
36
Increase driven by higher retail operations costs
14
Increase driven by higher Vivint Smart Home operations costs
13
Decrease primarily due to the sale of STP in November 2023
(115)
Decrease driven by a reduction in deactivation and asset retirement expenditures primarily in the East
(29)
Other
3
Increase in operations and maintenance expense
$
116
72
Other Cost of Operations
Other Cost of operations are comprised of the following:
(In millions)
Texas
East
West/Services/Other
Vivint Smart Home(a)
Total
Nine months ended September 30, 2024
$
187
$
104
$
11
$
6
$
308
Nine months ended September 30, 2023
190
98
11
2
301
(a) Includes results of operations following the acquisition date of March 10, 2023
Other cost of operations increased by $7 million for the nine months ended September 30, 2024, compared to the same period in 2023, due to the following:
(In millions)
Increase due to changes in current year ARO cost estimates at Midwest Generation and Jewett Mine
$
14
Increase in retail gross receipt taxes due to higher revenues in Texas and the East
9
Increase due to higher insurance premiums
8
Decrease primarily due to the sale of STP in November 2023
(22)
Other
(2)
Increase in other cost of operations
$
7
Depreciation and Amortization
Depreciation and amortization expenses are comprised of the following:
(In millions)
Texas
East
West/Services/Other
Vivint Smart Home(a)
Corporate
Total
Nine months ended September 30, 2024
$
240
$
117
$
96
$
561
$
31
$
1,045
Nine months ended September 30, 2023
257
122
73
442
27
921
(a) Includes results of operations following the acquisition date of March 10, 2023
Depreciation and amortization increased by $124 million for the nine months ended September 30, 2024, compared to the same period in 2023, due to the following:
(In millions)
Increase in amortization of capitalized contract costs
$
123
Increase due to the Vivint Smart Home acquisition in March 2023
93
Decrease in amortization primarily driven by the expected roll off of the acquired Vivint Smart Home intangibles
(74)
Other
(18)
Increase in depreciation and amortization
$
124
Selling, General and Administrative Costs
Selling, general and administrative costs comprised of the following:
(In millions)
Texas
East
West/Services/Other
Vivint Smart Home(a)
Corporate/Eliminations
Total
Nine months ended September 30, 2024
$
622
$
435
$
187
$
460
$
35
$
1,739
Nine months ended September 30, 2023
545
407
168
363
19
1,502
(a) Includes results of operations following the acquisition date of March 10, 2023
73
Total selling, general and administrative costs increased by $237 million for the nine months ended September 30, 2024, compared to the same period in 2023, due to the following:
(In millions)
Increase due to the Vivint Smart Home acquisition in March 2023
$
96
Increase in provision for credit losses primarily due to higher Texas Home retail revenues and customer payment behavior
54
Increase in personnel costs primarily driven by an increase in accruals as part of the Company's annual incentive plan reflecting financial outperformance for the year
52
Increase in marketing and media expenses
29
Increase in equity linked compensation primarily driven by a higher share price in 2024
24
Decrease driven by the sale of STP in November 2023
(9)
Other
(9)
Increase in selling, general and administrative costs
$
237
Acquisition-Related Transaction and Integration Costs
Acquisition-related transaction and integration costs were $22 million and $111 million for the nine months ended September 30, 2024 and 2023, respectively, include:
Nine months ended September 30,
(In millions)
2024
2023
Vivint Smart Home integration costs
$
17
$
46
Vivint Smart Home acquisition costs
—
38
Other integration costs, primarily related to Direct Energy
5
27
Acquisition-related transaction and integration costs
$
22
$
111
Gain on Sale of Assets
The gain on sale of assets of $209 million and $202 million for the nine months ended September 30, 2024 and 2023, respectively, included the following:
Nine months ended September 30,
(In millions)
2024
2023
Sale of the Airtron business unit
$
208
$
—
Sale of Astoria land and related assets
—
199
Other asset sales
1
3
Gain on sale of assets
$
209
$
202
Loss on Debt Extinguishment
A loss on debt extinguishment of $260 million was recorded for the nine months ended September 30, 2024, driven by the repurchase of a portion of the Convertible Senior Notes, as further discussed in Note 7, Long-term Debt and Finance Leases.
Interest Expense
Interest expense increased by $56 million for the nine months ended September 30, 2024, compared to the same period in 2023, primarily due to the acquisition of Vivint Smart Home in March 2023 and unrealized losses on interest rate swaps for the 2024 period as compared to unrealized gains in the 2023 period.
Income Tax Expense/(Benefit)
For the nine months ended September 30, 2024, an income tax expense of $251 million was recorded on a pre-tax income of $733 million. For the same period in 2023, income tax benefit of $182 million was recorded on pre-tax loss of $866 million. The effective tax rates were 34.2% and 21.0% for the nine months ended September 30, 2024 and 2023, respectively.
For the nine months ended September 30, 2024, NRG's effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense and permanent differences. For the same period in 2023, NRG's effective tax rate approximated the statutory rate of 21%, which includes the impact of state and foreign taxes.
74
Liquidity and Capital Resources
Liquidity Position
As of September 30, 2024 and December 31, 2023, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $6.4 billion and $4.8 billion, respectively, was comprised of the following:
(In millions)
September 30, 2024
December 31, 2023
Cash and cash equivalents
$
1,104
$
541
Restricted cash - operating
7
21
Restricted cash - reserves(a)
3
3
Total
1,114
565
Total availability under Revolving Credit Facility and collective collateral facilities(b)
5,330
4,278
Total liquidity, excluding funds deposited by counterparties
$
6,444
$
4,843
(a) Includes reserves primarily for debt service, performance obligations and capital expenditures
(b) Total capacity of Revolving Credit Facility and collective collateral facilities was $8.2 billion and $7.4 billion as of September 30, 2024 and December 31, 2023, respectively
For the nine months ended September 30, 2024, total liquidity, excluding funds deposited by counterparties, increased by $1.6 billion. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading CashFlow Discussion. Cash and cash equivalents at September 30, 2024 were predominantly held in bank deposits.
Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends, and to fund other liquidity commitments in the short and long-term. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.
The Company remains committed to maintaining a strong balance sheet and continues to work to achieve investment grade credit metrics over time primarily through debt reduction and the realization of growth initiatives.
Credit Ratings
On March 18, 2024, Standard and Poor's ("S&P") affirmed the Company's issuer credit rating of BB and changed the rating outlook from Stable to Positive.
Liquidity
The principal sources of liquidity for NRG's operating and capital expenditures are expected to be derived from cash on hand, cash flows from operations and financing arrangements. As described in Note 7, Long-term Debt and Finance Leases, to this Form 10-Q, the Company's financing arrangements consist mainly of the Senior Notes, Convertible Senior Notes, Senior Secured First Lien Notes, Revolving Credit Facility, Term Loan Facility, the Receivables Securitization Facilities and tax-exempt bonds. The Company also issues letters of credit through bilateral letter of credit facilities and the P-Caps letter of credit facility. The Company's capital structure also included the Vivint Senior Notes, Vivint Senior Secured Notes and Vivint Senior Secured Term-Loan.
The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) market operations activities; (ii) debt service obligations, as described in Note 7, Long-term Debt and Finance Leases; (iii) capital expenditures, including maintenance, environmental, and investments and integration; and (iv) allocations in connection with acquisition opportunities, debt repayments, share repurchases and dividend payments to stockholders, as described in Note 9, Changes in Capital Structure.
Sale of Airtron
On September 16, 2024, the Company closed on the sale of its 100% ownership in the Airtron business unit. Proceeds of $500 million were reduced by working capital and other adjustments of $16 million, resulting in net proceeds of $484 million. The Company recorded a gain on the sale of $208 million within the West/Services/Other region of operations.
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Debt Refinancing Transactions
In the fourth quarter of 2024, the Company entered into the following debt transactions:
Sources
Uses
Issuance by NRG of 6.000% Senior Notes due 2033
$925 million
Repayment of the Vivint Senior Secured Term Loan B
$1.310 billion
Issuance by NRG of 6.250% Senior Notes due 2034
$950 million
Cash tender offer for Vivint 6.750% Senior Secured Notes due 2027(a)
$600 million
Exchange offer for New NRG 5.750% Senior Notes due 2029
$798 million
Exchange offer for Vivint 5.750% Senior Notes due 2029(b)
$798 million
Incremental Term Loan B issued by NRG
$450 million
Repayment of NRG 6.625% Senior Notes due 2027
$375 million
Cash on hand
$5 million
Estimated transactions fees, expenses and premiums
$45 million
Total
$3.128 billion
Total
$3.128 billion
(a)On October 30, 2024, APX Group, Inc. delivered a notice of redemption with respect to the Vivint 6.750% Senior Secured Notes due 2027 to redeem the $11 million of the Vivint 6.750% Senior Secured Notes due 2027 that remained outstanding following the Tender Offer on November 8, 2024
(b)On November 4, 2024, APX Group, Inc. delivered a notice of redemption with respect to the Vivint 5.750% Senior Notes due 2029 to redeem the approximate $2 million of the Vivint 5.750% Senior Notes due 2029 that remained outstanding following the Exchange Offer on November 14, 2024
As part of the above transactions, the Company entered into the Tenth Amendment and Eleventh Amendment to the Credit Agreement to (i) increase the term loan B in an aggregate principal balance of $450 million, (ii) make certain other amendments to the Credit Agreement and (iii) extend the maturity date of its revolving credit facility to October 30, 2029. For further discussion on these amendments and the debt transactions in the table above, see Note 7, Long-term Debt and Finance Leases.
Senior Credit Facility
On April 16, 2024, the Company, as borrower, and certain of its subsidiaries, as guarantors, entered into the Eighth Amendment with, among others, Citicorp North America, Inc., as the Agent and as collateral agent, and certain financial institutions, as lenders, which amended the Credit Agreement, in order to (i) establish a new Term Loan Facility with borrowings of $875 million in aggregate principal amount and the Term Loans and (ii) make certain other modifications to the Credit Agreement as set forth therein. The proceeds from the Term Loans were used to repay a portion of the Company’s Convertible Senior notes, all of the Company’s 3.750% senior secured first lien notes due 2024 and for general corporate purposes.
At the Company’s election, the Term Loans bear interest at a rate per annum equal to either (1) a fluctuating rate equal to the highest of (A) the rate published by the Federal Reserve Bank of New York in effect on such day, plus 0.50%, (B) the rate of interest per annum publicly announced from time to time by The Wall Street Journal as the “Prime Rate” in the United States, and (C) a rate of one-month Term SOFR (as defined in the Credit Agreement) (after giving effect to any floor applicable to Term SOFR) plus 1.00%, in each case, plus a margin of 1.00% or (2) Term SOFR (as defined in the Credit Agreement) (which Term SOFR shall not be less than 0.00%) for a one-, three- or six-month interest period (or such other period as agreed to by the Agent and the lenders, as selected by the Company), plus a margin of 2.00%.
On April 22, 2024, the Company, as borrower, and certain of its subsidiaries, as guarantors, entered into the Ninth Amendment to its Revolving Credit Facility to extend the maturity date of a portion of the revolving commitments thereunder to February 14, 2028. For further discussion, see Note 7, Long-term Debt and Finance Leases.
Convertible Senior Notes
As of October 1, 2024, the Company's Convertible Senior Notes are convertible during the quarterly period ending September 30, 2024 due to the satisfaction of the Common Stock Sale Price Condition. For further discussion, see Note 7, Long-term Debt and Finance Leases.
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During the nine months ended September 30, 2024, the Company completed repurchases of a portion of the Convertible Senior Notes using cash on hand and a portion of the proceeds from the Term Loans, as detailed in the table below. For the nine months ended September 30, 2024, a $260 million loss on debt extinguishment was recorded.
(In millions, except percentages)
Settlement Period
Principal Repurchased
Cash Paid(a)
Average Repurchase Percentage
March 2024
$
92
$
151
162.356%
April 2024
251
452
179.454%
Total Repurchases
$
343
$
603
(a)Includes accrued interest of $1 million and $2 million for the March and April repurchases, respectively
During the second quarter of 2024, the Company entered into privately negotiated capped call transactions with certain counterparties. The Capped Calls have a cap price of $249.00 per share, subject to certain adjustments, and effectively lock in a conversion premium of $257 million on the remaining $232 million balance of the Convertible Senior Notes. The option price of $257 million was incurred when the Company entered into the Capped Calls, which will be payable upon the earlier of settlement and expiration of the applicable Capped Calls. For further discussion see Note 9, Changes in Capital Structure.
Receivables Securitization Facilities
On June 21, 2024, NRG Receivables, amended its existing Receivables Facility to, among other things, (i) extend the scheduled termination date to June 20, 2025, (ii) increase the aggregate commitments from $1.4 billion to $2.3 billion (adjusted seasonally) and (iii) add a new originator. As of September 30, 2024, there were no outstanding borrowings and there were $1.5 billion in letters of credit issued.
Also on June 21, 2024, the Additional Originator entered into the Joinder Agreement to join as Additional Originator to the Receivables Sale Agreement, dated as of September 22, 2020, among Direct Energy, LP, Direct Energy Business, LLC, Green Mountain Energy Company, NRG Business Marketing, LLC, Reliant Energy Northeast LLC, Reliant Energy Retail Services, LLC, Stream SPE, Ltd., US Retailers LLC and XOOM Energy Texas, LLC, as Originators, NRG Retail, as the servicer, and the Receivables Sale Agreement. Pursuant to the Joinder Agreement, the Additional Originator agrees to be bound by the terms of the Receivables Sale Agreement, will sell to NRG Receivables substantially all of its Receivables and in connection therewith have transferred to NRG Receivables the deposit accounts into which the proceeds of such Receivables are paid.
Concurrently with the amendments to the Receivables Facility, the Company and the originators thereunder terminated the existing uncommitted Repurchase Facility.
Senior Secured First Lien Note Repayment
During the second quarter of 2024, the Company repaid $600 million in aggregate principal amount of its 3.750% Senior Secured First Lien Notes due 2024.
Vivint Term Loan Repricing
On April 10, 2024, Vivint, entered into the Second Amendment with, among others, the Vivint Agent, and certain financial institutions, as lenders, which amended the Vivint Credit Agreement, in order to (i) reprice its term loan B facility (the term loans thereunder, the “Vivint Term Loans”) and (ii) make certain other modifications to the Vivint Credit Agreement as set forth therein.
At Vivint’s election, the Vivint Term Loans will bear interest at a rate per annum equal to either (1) a fluctuating rate equal to the highest of (A) the rate published by the Federal Reserve Bank of New York in effect on such day, plus 0.50%, (B) the rate of interest per annum publicly announced from time to time by The Wall Street Journal as the “Prime Rate” in the United States, and (C) a rate of one-month Term SOFR (as defined in the Vivint Credit Agreement), (after giving effect to any floor applicable to Term SOFR) plus 1.00% in each case, plus a margin of 1.75%, or (2) Term SOFR (as defined in the Vivint Credit Agreement) (which Term SOFR shall not be less than 0.50%) for a one-, three- or six-month interest period or such other period as agreed to by the Vivint Agent and the lenders, as selected by Vivint, plus a margin of 2.75%.
Liability Management
The Company previously announced it intended to spend approximately $500 million reducing debt during 2024 to maintain its targeted credit metrics. As the Company has updated the 2024 capital allocation plan, NRG's planned spend on reducing debt has been adjusted to $335 million, as NRG believes it will maintain its targeted credit metrics.
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Market Operations
The Company's market operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (e.g., buying energy before receiving retail revenues); and (iv) initial collateral for large structured transactions. As of September 30, 2024, the Company had total cash collateral outstanding of $449 million and $2.9 billion outstanding in letters of credit to third parties primarily to support its market activities. As of September 30, 2024, total funds deposited by counterparties were $12 million in cash and $275 million of letters of credit.
Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements depend on the Company's credit ratings and general perception of its creditworthiness.
First Lien Structure
NRG has the capacity to grant first liens to certain counterparties on a substantial portion of the Company's assets, subject to various exclusions including NRG's assets that have project-level financing and the assets of certain non-guarantor subsidiaries, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements. The first lien program does not limit the volume that can be hedged, or the value of underlying out-of-the-money positions. The first lien program also does not require NRG to post collateral above any threshold amount of exposure. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.
The Company's first lien counterparties may have a claim on its assets to the extent market prices differ from the hedged prices. As of September 30, 2024, all hedges under the first liens were out-of-the-money on a counterparty aggregate basis.
Capital Expenditures
The following table summarizes the Company's capital expenditures for maintenance, environmental and growth investments for the nine months ended September 30, 2024, and the estimated forecast for the remainder of the year.
(In millions)
Maintenance
Environmental
Investments and Integration
Total
Texas
$
142
$
13
$
57
$
212
East
—
2
—
2
West/Services/Other
12
—
1
13
Vivint Smart Home
14
—
4
18
Corporate
12
—
29
41
Total cash capital expenditures for the nine months ended September 30, 2024
$
180
$
15
$
91
$
286
Integration operating expenses and cost to achieve
—
—
47
47
Investments
—
—
156
156
Total cash capital expenditures and investments for the nine months ended September 30, 2024
$
180
$
15
$
294
$
489
Estimated cash capital expenditures and investments for the remainder of 2024(a)
130
10
96
236
Estimated full year 2024 cash capital expenditures and investments
$
310
$
25
$
390
$
725
(a)Excludes capital expenditures related to brownfield development projects that were submitted to the Texas Energy Fund
Investments and Integration for the nine months ended September 30, 2024 include growth expenditures, integration, small book acquisitions and other investments.
Environmental Capital Expenditures
NRG estimates that environmental capital expenditures from 2024 through 2028 required to comply with environmental laws will be approximately $93 million, primarily driven by the cost of complying with ELG at the Company's coal units in Texas.
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Share Repurchases
The Company's long-term capital allocation policy is to target allocating approximately 80% of cash available for allocation after debt reduction to be returned to shareholders. In June 2023, NRG announced an increase to its share repurchase authorization to $2.7 billion, to be executed through 2025 as part of the existing share repurchase authorization. In October 2024, the Board of Directors authorized an additional $1.0 billion for share repurchases as part of the existing share repurchase authorization.
During the nine months ended September 30, 2024, the Company completed $319 million of open market share repurchases at an average price of $79.26 per share. Through October 31, 2024, an additional $225 million of share repurchases were executed at an average price of $89.23 per share. As of October 31, 2024, $2.0 billion is remaining under the $3.7 billion authorization. See Note 9, Changes in Capital Structure for additional discussion.
Common Stock Dividends
During the first quarter of 2024, NRG increased the annual dividend to $1.63 from $1.51 per share. A quarterly dividend of $0.4075 per share was paid on the Company's common stock during the three months ended September 30, 2024. On October 11, 2024, NRG declared a quarterly dividend on the Company's common stock of $0.4075 per share, payable on November 15, 2024 to stockholders of record as of November 1, 2024. Beginning in the first quarter of 2025, NRG will increase the annual dividend by 8% to $1.76 per share. The Company expects to target an annual dividend growth rate of 7%-9% per share in subsequent years.
Series A Preferred Stock Dividends
During the quarters ended March 31, 2024 and September 30, 2024, the Company declared and paid a semi-annual 10.25% dividend of $51.25 per share on its outstanding Series A Preferred Stock, each totaling $33 million.
Obligations under Certain Guarantees
NRG and its subsidiaries enter into various contracts that include indemnifications and guarantee provisions as a routine part of the Company’s business activities. For further discussion, see Note 27, Guarantees, to the Company's 2023 Form 10-K.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
Variable interest in equity investments — NRG’s investment in Ivanpah is a variable interest entity for which NRG is not the primary beneficiary. NRG's pro-rata share of non-recourse debt was approximately $461 million as of September 30, 2024. This indebtedness may restrict the ability of Ivanpah to issue dividends or distributions to NRG.
Contractual Obligations and Market Commitments
NRG has a variety of contractual obligations and other market commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs, as disclosed in the Company's 2023 Form 10-K. See also Note 7, Long-term Debt and Finance Leases, and Note 14, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and market commitments that occurred during the three and nine months ended September 30, 2024.
Cash Flow Discussion
The following table reflects the changes in cash flows for the nine month ended September 30, 2024 and 2023, respectively:
Nine months ended September 30,
(In millions)
2024
2023
Change
Cash provided/(used) by operating activities
$
1,354
$
(462)
$
1,816
Cash provided/(used) by investing activities
163
(2,631)
2,794
Cash (used)/provided by financing activities
(1,041)
1,590
(2,631)
79
Cash provided/(used) by operating activities
Changes to cash provided/(used) by operating activities were driven by:
(In millions)
Changes in cash collateral in support of risk management activities due to change in commodity prices
$
1,108
Increase in operating income/loss adjusted for other non-cash items
636
Increase in working capital primarily due to lower gas pricing coupled with lower gas sales volumes
396
Decrease in working capital primarily driven by capitalized contract costs and deferred revenues
(209)
Decrease in working capital primarily related to the payout of the Company's annual incentive plan in 2024 reflecting financial outperformance for 2023
(115)
$
1,816
Cash provided/(used) by investing activities
Changes to cash provided/(used) by investing activities were driven by:
(In millions)
Decrease in cash paid for acquisitions primarily due to the acquisition of Vivint Smart Home in March 2023
$
2,469
Increase in proceeds from sale of assets primarily due to the sale of the Airtron business unit in 2024 as compared to the sale of the land and related assets from the Astoria site in 2023
266
Decrease in capital expenditures
207
Decrease in insurance proceeds for property, plant and equipment, net
(170)
Other
22
$
2,794
Cash (used)/provided by financing activities
Changes to cash (used)/provided by financing activities were driven by:
(In millions)
Decrease due to repayments of long-term debt and finance leases
$
(945)
Decrease in proceeds due to the issuance of preferred stock in 2023
(635)
Decrease in net receipts from settlement of acquired derivatives
(334)
Decrease in proceeds from Revolving Credit Facility and Receivables Securitization Facilities in 2023
(300)
Decrease due to payments for share repurchase activity
(292)
Decrease primarily due to debt extinguishment costs in 2024
(242)
Increase in proceeds due to the issuance of long-term debt
144
Increase in payments of dividends primarily due to preferred stock
(27)
$
(2,631)
NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
For the nine months ended September 30, 2024, the Company had domestic pre-tax book income of $827 million and foreign pre-tax book loss of $94 million. As of December 31, 2023, the Company had cumulative U.S. Federal NOL carryforwards of $8.4 billion, of which $6.4 billion do not have an expiration date, and cumulative state NOL carryforwards of $6.4 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of $411 million, most of which do not have an expiration date. In addition to the above NOLs, NRG has a $517 million indefinite carryforward for interest deductions, as well as $317 million of tax credits to be utilized in future years. As a result of the Company's tax position, including the utilization of federal and state NOLs, and based on current forecasts, the Company anticipates net income tax payments due to federal, state and foreign jurisdictions of up to $215 million in 2024, which includes the estimated impact of the sale of the Airtron business unit. As of September 30, 2024, there is no impact on the Company's provision for income taxes from the CAMT.
As of September 30, 2024, the Company has $66 million of tax-effected uncertain federal and state tax benefits, for which the Company has recorded a non-current tax liability of $70 million (inclusive of accrued interest) until final resolution is reached with the related taxing authority.
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On December 31, 2021, the OECD released rules which set forth a common approach to a global minimum tax at 15% for multinational companies, which has been enacted into law by certain countries effective for 2024. The Company's preliminary analysis indicates that there is no material impact to the Company's financial statements from these rules.
The Company is no longer subject to U.S. federal income tax examinations for years prior to 2020. With few exceptions, state and Canadian income tax examinations are no longer open for years prior to 2015.
Deferred tax assets and valuation allowance
Net deferred tax balance — As of September 30, 2024 and December 31, 2023, NRG recorded a net deferred tax asset, excluding valuation allowance, of $2.4 billion and $2.5 billion, respectively. The Company believes certain state net operating losses may not be realizable under the more-likely-than-not measurement and as such, a valuation allowance was recorded as of September 30, 2024 and December 31, 2023 as discussed below.
NOL Carryforwards — As of September 30, 2024, the Company had a tax-effected cumulative U.S. NOLs consisting of carryforwards for federal and state income tax purposes of $1.8 billion and $367 million, respectively. The Company estimates it will need to generate future taxable income to fully realize the net federal deferred tax asset before the expiration of certain carryforwards commences in 2030. In addition, NRG has tax-effected cumulative foreign NOL carryforwards of $110 million.
Valuation Allowance — As of September 30, 2024 and December 31, 2023, the Company’s tax-effected valuation allowance was $275 million, consisting of state NOL carryforwards and foreign NOL carryforwards. The valuation allowance was recorded based on the assessment of cumulative and forecasted pre-tax book earnings and the future reversal of existing taxable temporary differences.
Guarantor Financial Information
As of September 30, 2024, the Company's outstanding registered senior notes consisted of $375 million of the 2027 Senior Notes and $821 million of the 2028 Senior Notes as shown in Note 7, Long-term Debt and Finance Leases. These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries (the “Guarantors”). See Exhibit 22.1 to this Form 10-Q for a listing of the Guarantors. These guarantees are both joint and several. On October 30, 2024, NRG redeemed all of its outstanding 6.625% Senior Notes due 2027, of which $375 million aggregate principal amount was outstanding.
NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. There are no restrictions on the ability of any of the Guarantors to transfer funds to NRG. Other subsidiaries of the Company do not guarantee the registered debt securities of either NRG Energy, Inc. or the Guarantors (such subsidiaries are referred to as the “Non-Guarantors”). The Non-Guarantors include all of NRG's foreign subsidiaries and certain domestic subsidiaries.
The following tables present summarized financial information of NRG Energy, Inc. and the Guarantors in accordance with Rule 3-10 under the SEC's Regulation S-X. The financial information may not necessarily be indicative of the results of operations or financial position of NRG Energy, Inc. and the Guarantors in accordance with U.S. GAAP.
The following table presents the summarized statement of operations:
(In millions)
Nine months ended September 30, 2024
Revenue(a)
$
17,862
Operating income(b)
1,482
Total other expense
(553)
Income before income taxes
929
Net Income
649
(a)Intercompany transactions with Non-Guarantors of $2 million during the nine months ended September 30, 2024
(b)Intercompany transactions with Non-Guarantors including cost of operations of $10 million and selling, general and administrative of $247 million during the nine months ended September 30, 2024
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The following table presents the summarized balance sheet information:
(In millions)
September 30, 2024
Current assets(a)
$
5,244
Property, plant and equipment, net
1,213
Non-current assets
11,491
Current liabilities(b)
5,810
Non-current liabilities
9,873
(a)Includes intercompany receivables due from Non-Guarantors of $41 million as of September 30, 2024
(b)Includes intercompany payables due to Non-Guarantors of $31 million as of September 30, 2024
Fair Value of Derivative Instruments
NRG may enter into power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at power plants or retail load obligations. In order to mitigate interest rate risk associated with the issuance of the Company's variable rate debt, NRG enters into interest rate swap agreements. In addition, in order to mitigate foreign exchange rate risk primarily associated with the purchase of U.S. dollar denominated natural gas for the Company's Canadian business, NRG enters into foreign exchange contract agreements.
Under Flex Pay, offered by Vivint Smart Home, subscribers pay for smart home products by obtaining financing from a third-party financing provider under the Consumer Financing Program. Vivint Smart Home pays certain fees to the Financing Providers and shares in credit losses depending on the credit quality of the subscriber.
NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.
The following tables disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820, Fair Value Measurements and Disclosures ("ASC 820"). Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values as of September 30, 2024, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at September 30, 2024. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Note 5, Fair Value of Financial Instruments.
Derivative Activity Gains/(Losses)
(In millions)
Fair Value of Contracts as of December 31, 2023
$
648
Contracts realized or otherwise settled during the period
62
Other changes in fair value
(327)
Fair Value of Contracts as of September 30, 2024
$
383
Fair Value of Contracts as of September 30, 2024
(In millions)
Maturity
Fair Value Hierarchy (Losses)/Gains
1 Year or Less
Greater than 1 Year to 3 Years
Greater than 3 Years to 5 Years
Greater than 5 Years
Total Fair Value
Level 1
$
(2)
$
(15)
$
(8)
$
(3)
$
(28)
Level 2
216
210
98
113
637
Level 3
(109)
(97)
(21)
1
(226)
Total
$
105
$
98
$
69
$
111
$
383
The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or posted on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 3, Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative asset and liability position is a better
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indicator of NRG's hedging activity. As of September 30, 2024, NRG's net derivative asset was $383 million, a decrease to total fair value of $265 million as compared to December 31, 2023. This decrease was primarily driven by losses in fair value, partially offset by the roll-off of trades that settled during the period.
Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase or decrease in natural gas prices across the term of the derivative contracts would result in a change of approximately $1.8 billion in the net value of derivatives as of September 30, 2024.
Critical Accounting Estimates
NRG's discussion and analysis of the financial condition and results of operations are based upon the condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of appropriate technical accounting rules and guidance involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies has not changed.
NRG evaluates these estimates, on an ongoing basis, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company's estimates. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known.
The Company identifies its most critical accounting estimates as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain.
The Company's critical accounting estimates are described in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations,in the Company's 2023 Form 10-K. There have been no material changes to the Company's critical accounting estimates since the 2023 Form 10-K.
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ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's retail operations, merchant power generation or with existing or forecasted financial or commodity transactions. The types of market risks the Company is exposed to are commodity price risk, credit risk, liquidity risk, interest rate risk and currency exchange risk. The following disclosures about market risk provide an update to, and should be read in conjunction with, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of the Company's 2023 Form 10-K.
Commodity Price Risk
Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities and correlations between various commodities, such as natural gas, electricity, coal, oil and emissions credits. NRG manages the commodity price risk of the Company's load serving obligations and merchant generation operations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of energy and fuel. NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports and VaR. NRG uses a Monte Carlo simulation based VaR model to estimate the potential loss in the fair value of its energy assets and liabilities, which includes generation assets, gas transportation and storage assets, load obligations and bilateral physical and financial transactions, based on historical and forward values for factors such as customer demand, weather, commodity availability and commodity prices. The Company's VaR model is based on a one-day holding period at a 95% confidence interval for the forward 36 months, not including the spot month. The VaR model is not a complete picture of all risks that may affect the Company's results. Certain events such as counterparty defaults, regulatory changes, and extreme weather and prices that deviate significantly from historically observed values are not reflected in the model.
The following table summarizes average, maximum and minimum VaR for NRG's commodity portfolio, calculated using the VaR model for the three and nine months ended September 30, 2024 and 2023:
(In millions)
2024
2023
VaR as of September 30,
$
67
$
63
Three months ended September 30,
Average
$
58
$
64
Maximum
67
75
Minimum
50
45
Nine months ended September 30,
Average
$
61
$
66
Maximum
75
82
Minimum
50
45
The Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model for the entire term of these instruments entered into for both asset management and trading, was $149 million, as of September 30, 2024, primarily driven by asset-backed and hedging transactions.
Credit Risk
Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, and retail customer credit risk through its retail sales. Counterparty credit risk and retail customer credit risk are discussed below. See Note 6, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding credit risk contingent features.
Counterparty Credit Risk
The Company's counterparty credit risk policies are disclosed in its 2023 Form 10-K. As of September 30, 2024, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $1.3 billion and NRG held collateral (cash and letters of credit) against those positions of $128 million, resulting in a net exposure of $1.2 billion. NRG periodically receives collateral from counterparties in excess of their exposure. Collateral amounts shown include such excess while net exposure shown excludes excess collateral received. Approximately 30% of the Company's exposure before collateral is expected to roll off by the end of 2025. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net
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counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held and includes amounts net of receivables or payables.
Net Exposure(a)(b)
Category by Industry Sector
(% of Total)
Utilities, energy merchants, marketers and other
75
%
Financial institutions
25
Total as of September 30, 2024
100
%
Net Exposure (a)(b)
Category by Counterparty Credit Quality
(% of Total)
Investment grade
59
%
Non-investment grade/Non-Rated
41
Total as of September 30, 2024
100
%
(a)Counterparty credit exposure excludes coal transportation contracts because of the unavailability of market prices
(b)The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long-term contracts
The Company currently has no exposure to wholesale counterparties in excess of 10% of total net exposure discussed above as of September 30, 2024. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration.
RTOs and ISOs
The Company participates in the organized markets of CAISO, ERCOT, AESO, IESO, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in the majority of these markets is approved by FERC, whereas in the case of ERCOT, it is approved by the PUCT, and whereas in the case of AESO and IESO, both exist provincially with AESO primarily subject to Alberta Utilities Commission and the IESO to the Ontario Energy Board. These ISOs may include credit policies that, under certain circumstances, require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. As a result, the counterparty credit risk to these markets is limited to NRG’s share of the overall market and are excluded from the above exposures.
Exchange Traded Transactions
The Company enters into commodity transactions on registered exchanges, notably ICE, NYMEX and Nodal. These clearinghouses act as the counterparty and transactions are subject to extensive collateral and margining requirements. As a result, these commodity transactions have limited counterparty credit risk.
Long-Term Contracts
Counterparty credit exposure described above excludes credit risk exposure under certain long-term contracts, primarily solar under Renewable PPAs. As external sources or observable market quotes are not always available to estimate such exposure, the Company values these contracts based on various techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of September 30, 2024, aggregate credit risk exposure managed by NRG to these counterparties was approximately $890 million for the next five years.
Retail Customer Credit Risk
The Company is exposed to retail credit risk through the Company's retail electricity and gas providers as well as through Vivint Smart Home, which serve both Home and Business customers. Retail credit risk results in losses when a customer fails to pay for services rendered. The losses may result from both non-payment of customer accounts receivable and the loss of in-the-money forward value. The Company manages retail credit risk through the use of established credit policies, which include monitoring of the portfolio and the use of credit mitigation measures such as deposits or prepayment arrangements.
As of September 30, 2024, the Company's retail customer credit exposure to Home and Business customers was diversified across many customers and various industries, as well as government entities. Current economic conditions may affect the Company’s customers’ ability to pay their bills in a timely manner or at all, which could increase customer delinquencies and may lead to an increase in credit losses.
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Liquidity Risk
Liquidity risk arises from the general funding needs of the Company's activities and in the management of the Company's assets and liabilities. The Company is currently exposed to additional collateral posting if natural gas prices decline, primarily due to the long natural gas equivalent position at various exchanges used to hedge NRG's retail supply load obligations.
Based on a sensitivity analysis for power and gas positions under marginable contracts as of September 30, 2024, a $0.50 per MMBtu decrease in natural gas prices across the term of the marginable contracts would cause an increase in margin collateral posted of approximately $1.3 billion and a 1.00 MMBtu/MWh decrease in heat rates for heat rate positions would result in an increase in margin collateral posted of approximately $338 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of September 30, 2024.
Interest Rate Risk
NRG is exposed to fluctuations in interest rates through its issuance of variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combinations of the variable rate debt and the interest rate derivative instrument. NRG's management policies allow the Company to reduce interest rate exposure from variable rate debt obligations. In the first quarter of 2024, the Company entered into interest rate swaps with a total nominal value of $700 million extending through 2029 to hedge the floating rate of the Term Loans. Additionally, as of September 30, 2024, the Company had $1.0 billion of interest rate swaps extending through 2027 to hedge the floating rate on the Vivint Term Loans. In November 2024, in connection with the repayment of the Vivint Term Loans and the increase of the Term Loans, the Company decreased its interest rate swap notional value from $1.7 billion to $700 million.
As of September 30, 2024, the fair value and related carrying value of the Company's debt was $10.9 billion and $10.7 billion, respectively. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt as of September 30, 2024 by $464 million.
Currency Exchange Risk
NRG is subject to transactional exchange rate risk from transactions with customers in countries outside of the United States, primarily within Canada, as well as from intercompany transactions between affiliates. Transactional exchange rate risk arises from the purchase and sale of goods and services in currencies other than the Company's functional currency or the functional currency of an applicable subsidiary. NRG hedges a portion of its forecasted currency transactions with foreign exchange forward contracts. As of September 30, 2024, NRG is exposed to changes in foreign currency primarily associated with the purchase of U.S. dollar denominated natural gas for its Canadian business and entered into foreign exchange contracts with a notional amount of $433 million.
The Company is subject to translation exchange rate risk related to the translation of the financial statements of its foreign operations into U.S. dollars. Costs incurred and sales recorded by subsidiaries operating outside of the United States are translated into U.S. dollars using exchange rates effective during the respective period. As a result, the Company is exposed to movements in the exchange rates of various currencies against the U.S. dollar, primarily the Canadian and Australian dollars. A hypothetical 10% appreciation in major currencies relative to the U.S. dollar as of September 30, 2024 would have resulted in a decrease of $9 million to net income within the consolidated statement of operations.
ITEM 4 — CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure ControlsandProcedures
Under the supervision and with the participation of NRG's management, including its principal executive officer, principal financial officer and principal accounting officer, NRG conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as such term is defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act. Based on this evaluation, the Company's principal executive officer, principal financial officer and principal accounting officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q.
Changes in Internal Control over Financial Reporting
There were no changes in NRG's internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the quarter ended September 30, 2024 that materially affected, or are reasonably likely to materially affect, NRG's internal control over financial reporting.
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PART II — OTHER INFORMATION
ITEM 1 — LEGAL PROCEEDINGS
For a discussion of material legal proceedings in which NRG was involved through September 30, 2024, see Note 14, Commitments and Contingencies, to this Form 10-Q.
ITEM 1A — RISK FACTORS
During the nine months ended September 30, 2024, there were no material changes to the Risk Factors disclosed in Part I, Item 1A, Risk Factors, of the Company's 2023 Form 10-K.
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The table below sets forth the information with respect to purchases made by or on behalf of NRG or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Exchange Act), of NRG's common stock during the quarter ended September 30, 2024.
For the three months ended September 30, 2024
Total Number of Shares Purchased(a)
Average Price Paid per Share(b)
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions)(c)
Month #1
(July 1, 2024 to July 31, 2024)
1,128,299
$
76.28
1,127,232
$
1,374
Month #2
(August 1, 2024 to August 31, 2024)
933,540
$
78.26
932,019
$
1,301
Month #3
(September 1, 2024 to September 30, 2024)
844,543
$
82.41
844,543
$
1,231
Total at September 30, 2024
2,906,382
$
78.70
2,903,794
(a)Includes share repurchases under the June 22, 2023 $2.7 billion share repurchase authorization and partial settlement of Capped Call Options. For further discussion, see Note 9, Changes in Capital Structure
(b)The average price paid per share excludes excise tax and commissions paid in connection with the open market share repurchases
(c)Includes commissions paid in connection with the open market share repurchases and excludes the additional $1.0 billion share repurchases authorized by the Board of Directors in October 2024. For further discussion, see Note 9, Changes in Capital Structure
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4 — MINE SAFETY DISCLOSURES
There have been no events that are required to be reported under this Item.
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ITEM 5 — OTHER INFORMATION
During the three months ended September 30, 2024, the following directors or officers of the Company adopted or terminated a 'Rule 10b5-1 trading arrangement' or 'non-Rule 10b5-1 trading arrangement,' as each term is defined in Item 408(a) of Regulation S-K, as described in the table below:
Name
Title
Date Adopted
Character of Trading Arrangement
Aggregate Number of Shares of Common Stock to be Purchased or Sold Pursuant to Trading Arrangement(a)
Duration
Date Terminated
Robert Gaudette
Executive Vice President, NRG Business
9/6/2024
Rule 10b5-1 Trading Arrangement
Up to 60,000 shares to be Sold
1/2/2025-2/28/2025
N/A
Woo-Sung Chung
Executive Vice President and Chief Financial Officer
9/13/2024
Rule 10b5-1 Trading Arrangement
Up to 20,000(b) shares to be Sold
1/13/2025-3/1/2025
N/A
(a)Potential sales may be subject to certain price limitations set forth in the 10b5-1 plans and therefore actual number of shares sold could vary if certain minimum stock prices are not met
(b)Represents approximate number of shares to be sold based on outstanding awards expected to vest during the period, where certain underlying performance share awards are being calculated at target. Actual number of shares to be sold will depend on actual vesting, the number of shares withheld by NRG to satisfy tax withholding obligations and vesting of dividend equivalent rights
Cover Page Interactive Data File (the cover page interactive data file does not appear in Exhibit 104 because it's Inline XBRL tags are embedded within the Inline XBRL document).
Filed herewith.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.