filings.toolsItem 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The discussion and analysis below has been organized as follows:
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Executive summary, including introduction and overview, business strategy, and changes to the business environment during the period, including environmental and regulatory matters;
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Results of operations;
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Liquidity and capital resources including liquidity position, financial condition addressing credit ratings, material cash requirements and commitments, and other obligations; and
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Known trends that may affect NRG's results of operations and financial condition in the future.
As you read this discussion and analysis, refer to NRG's condensed consolidated statements of operations to this Form 10-Q, which present the results of operations for the three and six months ended June 30, 2024 and 2023. Also refer to NRG's 2023 Form 10-K, which includes detailed discussions of various items impacting the Company's business, results of operations and financial condition, including: General section; Strategy section; Business Overview section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Estimates section.
Executive Summary
Introduction and Overview
NRG Energy, Inc., or NRG or the Company, sits at the intersection of energy and home services. NRG is a leading energy and home services company fueled by market-leading brands, proprietary technologies, and complementary sales channels. Across the U.S. and Canada, NRG delivers innovative, sustainable solutions, predominately under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy and Vivint, while also advocating for competitive energy markets and customer choice. The Company has a customer base that includes approximately 8 million residential consumers in addition to commercial, industrial, and wholesale customers, supported by approximately 13 GW of generation as of June 30, 2024.
Strategy
NRG's strategy is to maximize stakeholder value by being a leader in the emerging convergence of energy and smart automation in the home and business. Through a diversified supply strategy, the Company sells reliable electricity and natural gas to its customers in the markets it serves, while also providing innovative home solutions to customers. NRG's unique combination of assets and capabilities enables the Company to develop and sell highly differentiated offerings that bring together every day essential services like powering and securing the home through a seamless and integrated experience. This strategy is intended to enable the Company to optimize its unique integrated platform to delight customers, generate recurring cash flow, significantly strengthen earnings and cost competitiveness, and lower risk and volatility. Sustainability is a philosophy that underpins and facilitates value creation across NRG's business for its stakeholders. It is an integral piece of NRG's strategy and ties directly to the Company's business success, reduced risks and enhanced reputation.
To effectuate the Company’s strategy, NRG is focused on: (i) serving the energy needs of end-use residential, commercial and industrial, and wholesale counterparties in competitive markets and optimizing on additional revenue opportunities through its multiple brands and channels; (ii) offering a variety of energy products and services, including renewable energy solutions and smart home products and services that are differentiated by innovative features, premium service, integrated platforms, sustainability, and loyalty/affinity programs; (iii) excellence in operating performance of its assets; (iv) achieving the optimal mix of supply to serve its customer load requirements through a diversified supply strategy ; and (v) engaging in disciplined and transparent capital allocation.
Energy Regulatory Matters
The Company’s regulatory matters are described in the Company’s 2023 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 15, Regulatory Matters.
As participants in wholesale and retail energy markets and owners and operators of power plants, certain NRG entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC, NRC and the PUCT, as well as other public utility commissions in certain states where NRG's generation or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO and RTO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states and provinces in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where NRG operates.
NRG's operations within the ERCOT footprint are not subject to rate regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the PUCT.
State and Provincial Energy Regulation
Maryland Legislation — On May 9, 2024, Maryland Governor Wes Moore signed Senate Bill 1 into law, which restricts the competitive retail electric and natural-gas market in Maryland, affecting residential customers but not commercial and industrial customers. The new law contains provisions which will come into force by January 1, 2025. The legislation imposes a price cap on residential contracts tied to a trailing 12-month historical average of utility rates, with only a limited exception for renewable power products. Renewable products must now have their price pre-approved pursuant to a process to be established and run by the Maryland Public Service Commission and source their renewable electricity certificates from within the PJM region. The law also requires that any variable-price contract not contain a change in price more than once a year, except time-of-use contracts, and limits contract terms to 12 months. It requires affirmative consent for the renewal of customer contracts for renewable power products. The law also imposes licensing requirements on energy salespersons. The law states that it does not impair existing contracts. The Maryland Public Service Commission is expected to conduct rulemakings to determine the details of a variety of the law’s provisions, but timing is not yet certain.
Regional Regulatory Developments
NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments, see Note 15, Regulatory Matters.
Texas
Public Utility Commission of Texas’ Actions with Respect to Wholesale Pricing and Market Design — The PUCT continues to analyze and implement multiple options for promoting increased reliability in the wholesale electric market, including the adoption of a reliability standard for resource adequacy and market-based mechanisms to achieve this standard. The Commission is expected to adopt a reliability standard by the end of 2024. During the 88th Regular Session, the Texas Legislature authorized implementation of the Performance Credit Mechanism ("PCM"), which will measure real-time contribution to system reliability and provide compensation for resources to be available, subject to certain "guardrails" such as an absolute annual net cost cap, as part of its adoption of the PUCT Sunset Bill (House Bill 1500). The Texas Legislature also directed the PUCT to implement additional market design changes such as the creation of a new ancillary service called Dispatchable Reliability Reserve Service ("DRRS") to further increase ERCOT's capability to manage net load variability and firming requirements for new generation resources which penalize poor performance during periods of low grid reserves. The PUCT directed ERCOT to implement DRRS as a standalone product which will delay implementation until 2026 or 2027.
Through Senate Bill 2627, the Texas Legislature created the Texas Energy Fund, which received voter approval in November 2023, and will provide grants and low-interest loans (3%) to incentivize the development of more dispatchable generation and smaller backup generation in ERCOT. The PUCT adopted a rule in March 2024, which establishes the application and participation requirements and the process by which the Texas Energy Fund loan proceeds for dispatchable generation in ERCOT will be distributed. The initial window for submitting loan applications was opened on June 1, 2024 and closed on July 27, 2024. NRG, through its subsidiaries, has filed for loan proceeds for three separate projects, totaling more than 1,500 MWs of capacity. The PUCT also adopted a rule for the completion bonus grant program in April 2024, which provides for opportunities for grants of $120,000 per MW for dispatchable generation projects interconnected before June 1, 2026, or $80,000 per MW for dispatchable generation projects interconnected on or after June 1, 2026 but before June 1, 2029, subject to performance requirements. Applications for completion bonus grants can be submitted beginning in January 2025.
Real-time Co-optimization of Energy and Ancillary Services ("RTC") – ERCOT is progressing with a multi-year project to upgrade their systems to co-optimize the dispatch of energy and ancillary services in real-time. The RTC project will also replace the Operating Reserve Demand Curve with demand curves for each ancillary service product which will act as the primary scarcity pricing mechanism when energy or ancillary services are in shortage. ERCOT anticipates commencing market trials for testing the RTC project in Spring 2025 with production go-live in late 2025 or early 2026.
Supreme Court of Texas Ruling on Pricing during Winter Storm Uri — On June 14, 2024, the Supreme Court of Texas issued an order affirming the validity of two orders issued by the PUCT on February 15 and 16, 2021, respectively, governing scarcity pricing in the ERCOT wholesale electricity market during Winter Storm Uri. The Supreme Court's order reversed the judgment of the Third Court of Appeals, which held that the PUCT exceeded its statutory authority by ordering the market price of energy to be set at the high system wide offer cap due to scarcity conditions as a result of firm load shed occurring in ERCOT. In addition to holding that the PUCT's orders were consistent with the agency's statutory authority, the Supreme Court of Texas's order found that the PUCT had substantially complied with the Administrative Procedure Act's procedural rulemaking requirements, which was an issue that the Third Court of Appeals did not reach.
Voluntary Mitigation Plan ("VMP") Changes — On March 13, 2023, the PUCT Staff determined that a portion of NRG's VMP should be terminated due to the increase in procurement of ancillary services by ERCOT, specifically non-spin reserve services, following Winter Storm Uri. As such, PUCT Staff terminated part of the VMP for NRG which provides protection from wholesale market power abuse accusations related to offers for ancillary services. NRG agreed with these changes to the VMP. At the March 23, 2023 open meeting, the PUCT approved the amended VMP. In February 2024, NRG filed a notice of intent with the PUCT and terminated its existing VMP as of March 1, 2024.
Lubbock, Texas Transition to Competition — The customers of Lubbock Power and Light ("LP&L"), a municipally owned utility, entered the Texas retail competitive market in March 2024. Starting in January 2024, LP&L customers were able to shop for a REP. Customers who did not select a REP by February 15, 2024 were assigned to one of three default REPs, one of which is Reliant. LP&L customers started transitioning to their chosen REP or a default REP on March 4, 2024.
PJM
Revisions to PJM Local Deliverability Area Reliability Requirement — The Base Residual Auction for the 2024/2025 delivery year commenced on December 7, 2022 and closed on December 13, 2022. On December 19, 2022, PJM announced that it would delay the publication of the auction results. On December 23, 2022, PJM made a filing at FERC to revise the definition of Locational Deliverability Area ("LDA") Reliability Requirement in the Tariff. This would allow PJM to exclude certain resources from the calculation of the Local Deliverability Area Reliability Requirement. On February 21, 2023, FERC accepted PJM's filing. Multiple parties, including NRG, filed for rehearing. Rehearing was denied by operation of law, and multiple parties, including the Company, filed appeals to the Third Circuit Court of Appeals. On March 12, 2024, the court vacated the portion of the FERC orders that allow PJM to apply the Local Deliverability Area Reliability Requirement to the 2024/2025 capacity auction. On March 29, 2024, PJM filed a petition seeking confirmation as to the capacity commitments rules for the 2024/2025 auction. On April 22, 2024, multiple parties filed a complaint seeking to find the revised rate unjust and unreasonable and implement rates consistent with FERC's February 2023 decision, which was denied on July 9, 2024. On May 6, 2024, FERC directed PJM to recalculate the 2024/2025 auction results under the Initial LDA Reliability Requirement rules, and further directed PJM to rerun the Third Incremental Auction. PJM published the revised Base Residual Auction and Third Incremental Auction results on May 8, 2024 and May 23, 2024, respectively. On June 14, 2024, multiple parties filed appeals to the Third Circuit Court of Appeals seeking review of the May 6, 2024 FERC orders approving PJM's petition to restore the original capacity commitment rules for PJM to recalculate the 2024/2025 Base Residual Auction and the rerun of the 2024/2025. As a result, the capacity for the 2024/2025 delivery year in the Delmarva Power and Light South zone resulted in higher prices. This outcome may change depending upon the disposition of the outstanding complaint and appeals.
PJM Base Residual Auction Revisions and Delay — On April 11, 2023, PJM filed, and FERC subsequently approved, to delay the Base Residual Auctions for the 2025/2026 to 2028/2029 delivery years. On October 13, 2023, PJM made two filings proposing to develop market reforms to improve the operation of the capacity market through changes to the Market Seller Offer Cap rules, changes to PJM's resource adequacy risk modeling and capacity accreditation processes, and changes to capacity performance enhancements. On January 30, 2024, FERC accepted certain reforms to PJM's resource adequacy risk modeling and accreditation processes; on February 6, 2024, FERC rejected PJM's proposed changes to certain Market Seller Offer Cap rules and capacity performance enhancements. The approved changes were in effect for the 2025/2026 Base Residual Auction that occurred in July 2024.
Indian River RMR Proceeding — On June 29, 2021, Indian River notified PJM that it intended to retire Unit 4, effective May 31, 2022, due to expected uneconomic operations. On July 30, 2021, PJM responded to the deactivation notice and stated that PJM had identified reliability violations resulting from the proposed deactivation of Unit 4. NRG filed a cost based RMR rate schedule at FERC on April 1, 2022. FERC accepted the rate schedule with a June 1, 2022 effective date, subject to refund and established hearing and settlement procedures. The Company reached settlement with a number of the intervening parties and the settlement agreement was filed at FERC on April 2, 2024 and is pending FERC review. Delmarva Power submitted to PJM and the Maryland Public Service Commission an update on its projected completion date for the transmission upgrades that would eliminate the need for the Indian River RMR. The new anticipated date is in December 2024, which is sooner than originally estimated by PJM.
Independent Market Monitor Market Seller Offer Cap Complaint — On March 18, 2021, finding that the calculation of the default Market Seller Offer Cap was unjust and unreasonable, FERC issued an Order, which permitted the PJM May 2021 capacity auction for the 2022/2023 delivery year to continue under the existing rules and set a procedural schedule for parties to file briefs with possible solutions. On September 2, 2021, FERC issued an order in response to a complaint filed by the PJM Independent Market Monitor's proposal, which eliminated the Cost of New Entry-based Market Seller Offer Cap, implemented a limited default cap for certain asset classes based on going-forward costs and provided for unit specific cost review by the Independent Market Monitor for all other non-zero offers into the auctions. On October 4, 2021, as required by the Order, PJM submitted its compliance tariff and certain parties filed a motion for rehearing, which was denied by operation of law. On February 18, 2022, FERC addressed the arguments raised on rehearing and rejected the rehearing requests. Multiple parties
filed appeals at the Court of Appeals for the D.C. Circuit, and on August 15, 2023, the Court denied the petitions for review. On January 12, 2024, the generator trade association filed a petition for review with the U.S. Supreme Court to overturn the August 15, 2023 judgment. On May 28, 2024, the U.S. Supreme Court denied the petition for review.
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 and legal challenges are finally 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 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 EPA has stated that it will address GHG emissions from existing combustion turbines in a future 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.
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 may be uncertain for several years.
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 may be uncertain for several years.
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.
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 Company expects that the outcome of the legal challenges will be uncertain for several years.
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 — During the fourth quarter of 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 August 3, 2024, the Company entered into a definitive agreement to sell its Airtron business unit for total proceeds of $500 million, subject to standard purchase price adjustments. Airton is a leading provider of HVAC systems for residential new construction homes and was acquired as part of the Direct Energy acquisition in 2021. The transaction is subject to regulatory approval under the Hart Scott Rodino act and is expected to close by the end of 2024.
Capital Allocation
During the six months ended June 30, 2024, the Company completed $90 million of open market share repurchases at an average price of $80.76 per share. Through July 31, 2024, an additional $86 million share repurchases were executed at an average price of $76.27 per share. See Note 9, Changes in Capital Structure for additional discussion.
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.
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.
Through April 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 six months ended June 30, 2024, the Company repaid $600 million in aggregate principal amount of its 3.750% Senior Secured First Lien Notes due 2024.
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. The Company expects to target an annual dividend growth rate of 7-9% per share in subsequent years.
Operations
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 July 31, 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.
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 EIA'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
NRG continues to evaluate the expansion of flexible dispatchable power plants within the ERCOT market in connection with the creation of the Texas Energy Fund, a loan program created by the Texas Legislature to finance new build of generation assets within their footprint. The Company submitted applications to the Texas Energy Fund to receive financing for the following projects:
| Facility | Fuel Type | Net Generation Capacity (MW) | ||||||||||||
| Cedar Bayou 5 | Natural Gas | 689 | ||||||||||||
| Greens Bayou 6 | Natural Gas | 443 | ||||||||||||
| T.H. Wharton | Natural Gas | 415 | ||||||||||||
| Total | 1,547 |
Changes in Accounting Standards
See Note 2, Summary of Significant Accounting Policies, for a discussion of recent accounting developments.
Consolidated Results of Operations
The following table provides selected financial information for the Company:
| Three months ended June 30, | Six months ended June 30, | ||||||||||||||||||||||||||||||||||
| (In millions) | 2024 | 2023 | Change | 2024 | 2023 | Change | |||||||||||||||||||||||||||||
| Revenue | |||||||||||||||||||||||||||||||||||
| Retail revenue | $ | 6,344 | $ | 6,027 | $ | 317 | $ | 13,573 | $ | 13,390 | $ | 183 | |||||||||||||||||||||||
| Energy revenue(a) | 110 | 83 | 27 | 262 | 211 | 51 | |||||||||||||||||||||||||||||
| Capacity revenue(a) | 44 | 49 | (5) | 86 | 91 | (5) | |||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | 84 | 75 | 9 | 24 | 166 | (142) | |||||||||||||||||||||||||||||
| Contract amortization | (7) | (8) | 1 | (17) | (19) | 2 | |||||||||||||||||||||||||||||
| Other revenues(a)(b) | 84 | 122 | (38) | 160 | 231 | (71) | |||||||||||||||||||||||||||||
| Total revenue | 6,659 | 6,348 | 311 | 14,088 | 14,070 | 18 | |||||||||||||||||||||||||||||
| Operating Costs and Expenses | |||||||||||||||||||||||||||||||||||
| Cost of fuel | 169 | 227 | 58 | 352 | 390 | 38 | |||||||||||||||||||||||||||||
| Purchased energy and other cost of sales(c) | 4,482 | 4,282 | (200) | 9,996 | 10,284 | 288 | |||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | (791) | 11 | 802 | (1,323) | 2,046 | 3,369 | |||||||||||||||||||||||||||||
| Contract and emissions credit amortization(c) | (17) | (18) | (1) | 46 | 90 | 44 | |||||||||||||||||||||||||||||
| Operations and maintenance | 424 | 361 | (63) | 794 | 746 | (48) | |||||||||||||||||||||||||||||
| Other cost of operations | 89 | 99 | 10 | 176 | 184 | 8 | |||||||||||||||||||||||||||||
| Cost of operations (excluding depreciation and amortization shown below) | 4,356 | 4,962 | 606 | 10,041 | 13,740 | 3,699 | |||||||||||||||||||||||||||||
| Depreciation and amortization | 285 | 315 | 30 | 553 | 505 | (48) | |||||||||||||||||||||||||||||
| Impairment losses | 15 | — | (15) | 15 | — | (15) | |||||||||||||||||||||||||||||
| Selling, general and administrative costs | 592 | 522 | (70) | 1,183 | 948 | (235) | |||||||||||||||||||||||||||||
| Acquisition-related transaction and integration costs | 6 | 22 | 16 | 15 | 93 | 78 | |||||||||||||||||||||||||||||
| Total operating costs and expenses | 5,254 | 5,821 | 567 | 11,807 | 15,286 | 3,479 | |||||||||||||||||||||||||||||
| Gain on sale of assets | 5 | 3 | 2 | 1 | 202 | (201) | |||||||||||||||||||||||||||||
| Operating Income/(Loss) | 1,410 | 530 | 880 | 2,282 | (1,014) | 3,296 | |||||||||||||||||||||||||||||
| Other Income/(Expense) | |||||||||||||||||||||||||||||||||||
| Equity in earnings of unconsolidated affiliates | 4 | 5 | (1) | 7 | 10 | (3) | |||||||||||||||||||||||||||||
| Other income, net | 3 | 13 | (10) | 33 | 29 | 4 | |||||||||||||||||||||||||||||
| Loss on debt extinguishment | (202) | — | (202) | (260) | — | (260) | |||||||||||||||||||||||||||||
| Interest expense | (163) | (151) | (12) | (315) | (299) | (16) | |||||||||||||||||||||||||||||
| Total other expense | (358) | (133) | (225) | (535) | (260) | (275) | |||||||||||||||||||||||||||||
| Income/(Loss) Before Income Taxes | 1,052 | 397 | 655 | 1,747 | (1,274) | 3,021 | |||||||||||||||||||||||||||||
| Income tax expense/(benefit) | 314 | 89 | (225) | 498 | (247) | (745) | |||||||||||||||||||||||||||||
| Net Income/(Loss) | $ | 738 | $ | 308 | $ | 430 | $ | 1,249 | $ | (1,027) | $ | 2,276 | |||||||||||||||||||||||
(a)Includes gains and losses from financially settled transactions
(b)Includes trading gains and losses and ancillary revenues
(c)Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits
Management’s discussion of the results of operations for the three months ended June 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 June 30, 2024 and 2023.
| Average on Peak Power Price ($/MWh) | |||||||||||||||||
| Three months ended June 30, | |||||||||||||||||
| Region | 2024 | 2023 | Change % | ||||||||||||||
| Texas | |||||||||||||||||
| ERCOT - Houston(a) | $ | 42.05 | $ | 56.54 | (26) | % | |||||||||||
| ERCOT - North(a) | 37.07 | 54.02 | (31) | % | |||||||||||||
| East | |||||||||||||||||
| NY J/NYC(b) | $ | 35.93 | $ | 32.02 | 12 | % | |||||||||||
| NEPOOL(b) | 34.50 | 32.55 | 6 | % | |||||||||||||
| COMED (PJM)(b) | 29.31 | 30.00 | (2) | % | |||||||||||||
| PJM West Hub(b) | 37.75 | 35.41 | 7 | % | |||||||||||||
| West | |||||||||||||||||
| MISO - Louisiana Hub(b) | $ | 30.60 | $ | 35.30 | (13) | % | |||||||||||
| CAISO - SP15(b) | 7.97 | 30.00 | (73) | % |
(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 June 30, 2024 and 2023:
| Three months ended June 30, | |||||||||||||||||
| 2024 | 2023 | Change % | |||||||||||||||
| ($/MMBtu) | $ | 1.89 | $ | 2.10 | (10) | % |
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.
The following tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended June 30, 2024 and 2023:
| Three months ended June 30, 2024 | ||||||||||||||||||||||||||||||||||||||
| ($ In millions) | Texas | East | West/Services/Other | Vivint Smart Home | Corporate/Eliminations | Total | ||||||||||||||||||||||||||||||||
| Retail revenue | $ | 2,692 | $ | 2,361 | $ | 832 | $ | 467 | $ | (8) | $ | 6,344 | ||||||||||||||||||||||||||
| Energy revenue | 16 | 46 | 51 | — | (3) | 110 | ||||||||||||||||||||||||||||||||
| Capacity revenue | — | 39 | 6 | — | (1) | 44 | ||||||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | — | 65 | 17 | — | 2 | 84 | ||||||||||||||||||||||||||||||||
| Contract amortization | — | (6) | (1) | — | — | (7) | ||||||||||||||||||||||||||||||||
| Other revenue(a) | 55 | 27 | 5 | — | (3) | 84 | ||||||||||||||||||||||||||||||||
| Total revenue | 2,763 | 2,532 | 910 | 467 | (13) | 6,659 | ||||||||||||||||||||||||||||||||
| Cost of fuel | (124) | (25) | (20) | — | — | (169) | ||||||||||||||||||||||||||||||||
| Purchased energy and other cost of sales(b)(c)(d) | (1,729) | (2,004) | (689) | (66) | 6 | (4,482) | ||||||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | 605 | 203 | (15) | — | (2) | 791 | ||||||||||||||||||||||||||||||||
| Contract and emissions credit amortization | (2) | 20 | (1) | — | — | 17 | ||||||||||||||||||||||||||||||||
| Depreciation and amortization | (63) | (22) | (46) | (144) | (10) | (285) | ||||||||||||||||||||||||||||||||
| Gross margin | $ | 1,450 | $ | 704 | $ | 139 | $ | 257 | $ | (19) | $ | 2,531 | ||||||||||||||||||||||||||
| Less: Mark-to-market for economic hedging activities, net | 605 | 268 | 2 | — | — | 875 | ||||||||||||||||||||||||||||||||
| Less: Contract and emissions credit amortization, net | (2) | 14 | (2) | — | — | 10 | ||||||||||||||||||||||||||||||||
| Less: Depreciation and amortization | (63) | (22) | (46) | (144) | (10) | (285) | ||||||||||||||||||||||||||||||||
| Economic gross margin | $ | 910 | $ | 444 | $ | 185 | $ | 401 | $ | (9) | $ | 1,931 | ||||||||||||||||||||||||||
| (a) Includes trading gains and losses and ancillary revenues | ||||||||||||||||||||||||||||||||||||||
| (b) Includes capacity and emissions credits | ||||||||||||||||||||||||||||||||||||||
| (c) Includes $840 million, $71 million and $249 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) | 10,528 | 3,615 | 498 | — | — | 14,641 | ||||||||||||||||||||||||||||||||
| Business electricity sales volume (GWh) | 10,180 | 11,695 | 2,974 | — | — | 24,849 | ||||||||||||||||||||||||||||||||
| Home natural gas sales volume (MDth) | — | 5,683 | 9,922 | — | — | 15,605 | ||||||||||||||||||||||||||||||||
| Business natural gas sales volume (MDth) | — | 336,160 | 43,562 | — | — | 379,722 | ||||||||||||||||||||||||||||||||
| Average retail Home customer count (in thousands)(a) | 2,975 | 2,189 | 766 | — | — | 5,930 | ||||||||||||||||||||||||||||||||
| Ending retail Home customer count (in thousands)(a) | 2,960 | 2,194 | 772 | — | — | 5,926 | ||||||||||||||||||||||||||||||||
| Average Vivint Smart Home subscriber count (in thousands)(b) | — | — | — | 2,071 | — | 2,071 | ||||||||||||||||||||||||||||||||
| Ending Vivint Smart Home subscriber count (in thousands) (b) | — | — | — | 2,106 | — | 2,106 | ||||||||||||||||||||||||||||||||
| Power generation | ||||||||||||||||||||||||||||||||||||||
| GWh sold | 4,784 | 1,033 | 1,290 | — | — | 7,107 | ||||||||||||||||||||||||||||||||
| GWh generated(c) | ||||||||||||||||||||||||||||||||||||||
| Coal | 2,372 | 574 | — | — | — | 2,946 | ||||||||||||||||||||||||||||||||
| Gas | 2,412 | — | 1,288 | — | — | 3,700 | ||||||||||||||||||||||||||||||||
| Oil | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
| Renewables | — | — | 2 | — | — | 2 | ||||||||||||||||||||||||||||||||
| Total | 4,784 | 574 | 1,290 | — | — | 6,648 | ||||||||||||||||||||||||||||||||
| (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 |
| Three months ended June 30, 2023 | |||||||||||||||||||||||||||||||||||
| ($ In millions) | Texas | East | West/Services/Other | Vivint Smart Home | Corporate/Eliminations | Total | |||||||||||||||||||||||||||||
| Retail revenue | $ | 2,395 | $ | 2,358 | $ | 830 | $ | 444 | $ | — | $ | 6,027 | |||||||||||||||||||||||
| Energy revenue | 16 | 28 | 40 | — | (1) | 83 | |||||||||||||||||||||||||||||
| Capacity revenue | — | 49 | — | — | — | 49 | |||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | — | 52 | 23 | — | — | 75 | |||||||||||||||||||||||||||||
| Contract amortization | — | (7) | (1) | — | — | (8) | |||||||||||||||||||||||||||||
| Other revenue(a) | 104 | 23 | — | — | (5) | 122 | |||||||||||||||||||||||||||||
| Total revenue | 2,515 | 2,503 | 892 | 444 | (6) | 6,348 | |||||||||||||||||||||||||||||
| Cost of fuel | (184) | (15) | (28) | — | — | (227) | |||||||||||||||||||||||||||||
| Purchased energy and other cost of sales(b)(c)(d) | (1,403) | (2,129) | (714) | (41) | 5 | (4,282) | |||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | 334 | (204) | (141) | — | — | (11) | |||||||||||||||||||||||||||||
| Contract and emissions credit amortization | (3) | 23 | (2) | — | — | 18 | |||||||||||||||||||||||||||||
| Depreciation and amortization | (73) | (30) | (23) | $ | (180) | (9) | (315) | ||||||||||||||||||||||||||||
| Gross margin | $ | 1,186 | $ | 148 | $ | (16) | $ | 223 | $ | (10) | $ | 1,531 | |||||||||||||||||||||||
| Less: Mark-to-market for economic hedging activities, net | 334 | (152) | (118) | — | — | 64 | |||||||||||||||||||||||||||||
| Less: Contract and emissions credit amortization, net | (3) | 16 | (3) | — | — | 10 | |||||||||||||||||||||||||||||
| Less: Depreciation and amortization | (73) | (30) | (23) | (180) | (9) | (315) | |||||||||||||||||||||||||||||
| Economic gross margin | $ | 928 | $ | 314 | $ | 128 | $ | 403 | $ | (1) | $ | 1,772 | |||||||||||||||||||||||
| (a) Includes trading gains and losses and ancillary revenues | |||||||||||||||||||||||||||||||||||
| (b) Includes capacity and emissions credits | |||||||||||||||||||||||||||||||||||
| (c) Includes $688 million, $56 million and $241 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) | 9,799 | 2,789 | 509 | — | — | 13,097 | |||||||||||||||||||||||||||||
| Business electricity sales volume (GWh) | 10,028 | 11,391 | 2,282 | — | — | 23,701 | |||||||||||||||||||||||||||||
| Home natural gas sales volume (MDth) | — | 7,716 | 11,582 | — | — | 19,298 | |||||||||||||||||||||||||||||
| Business natural gas sales volume (MDth) | — | 352,007 | 42,179 | — | — | 394,186 | |||||||||||||||||||||||||||||
| Average retail Home customer count (in thousands)(a) | 2,866 | 1,850 | 777 | — | — | 5,493 | |||||||||||||||||||||||||||||
| Ending retail Home customer count (in thousands)(a) | 2,869 | 1,858 | 772 | — | — | 5,499 | |||||||||||||||||||||||||||||
| Average Vivint Smart Home subscriber count (in thousands)(b) | — | — | — | 1,965 | — | 1,965 | |||||||||||||||||||||||||||||
| Ending Vivint Smart Home subscriber count (in thousands)(b) | — | — | — | 2,004 | — | 2,004 | |||||||||||||||||||||||||||||
| Power generation | |||||||||||||||||||||||||||||||||||
| GWh sold | 7,508 | 624 | 1,566 | — | — | 9,698 | |||||||||||||||||||||||||||||
| GWh generated(c) | |||||||||||||||||||||||||||||||||||
| Coal | 3,690 | 148 | — | — | — | 3,838 | |||||||||||||||||||||||||||||
| Gas | 1,625 | 46 | 1,565 | — | — | 3,236 | |||||||||||||||||||||||||||||
| Nuclear | 2,193 | — | — | — | — | 2,193 | |||||||||||||||||||||||||||||
| Renewables | — | — | 1 | — | — | 1 | |||||||||||||||||||||||||||||
| Total | 7,508 | 194 | 1,566 | — | — | 9,268 | |||||||||||||||||||||||||||||
| (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 |
The following table represents the weather metrics for the three months ended June 30, 2024 and 2023:
| Three months ended June 30, | |||||||||||||||||||||||||||||||||||||||||
| Weather Metrics | Texas | East | West/Services/Other**(b)** | ||||||||||||||||||||||||||||||||||||||
| 2024 | |||||||||||||||||||||||||||||||||||||||||
| CDDs(a) | 1,173 | 431 | 638 | ||||||||||||||||||||||||||||||||||||||
| HDDs(a) | 31 | 435 | 200 | ||||||||||||||||||||||||||||||||||||||
| 2023 | |||||||||||||||||||||||||||||||||||||||||
| CDDs | 978 | 273 | 502 | ||||||||||||||||||||||||||||||||||||||
| HDDs | 57 | 479 | 254 | ||||||||||||||||||||||||||||||||||||||
| 10-year average | |||||||||||||||||||||||||||||||||||||||||
| CDDs | 989 | 350 | 554 | ||||||||||||||||||||||||||||||||||||||
| HDDs | 59 | 538 | 192 |
(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 $1.0 billion and economic gross margin increased $159 million during the three months ended June 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) | |||||
| Lower gross margin due to the net effect of: •a 12%, or $83 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 •an increase in net revenue of $50 million, primarily driven by changes in customer term, product and mix | $ | (33) | |||
| Higher gross margin due to an increase in load of 510 GWhs, or $12 million, driven by an increase in customer counts and an increase in load of 371 GWhs, or $12 million, from weather | 24 | ||||
| Lower gross margin due to market optimization activities | (6) | ||||
| Other | (3) | ||||
| Decrease in economic gross margin | $ | (18) | |||
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 271 | ||||
| Decrease in contract and emissions credit amortization | 1 | ||||
| Decrease in depreciation and amortization | 10 | ||||
| Increase in gross margin | $ | 264 |
East
| (In millions) | ||||||||
| Lower gross margin due to a decrease in generation and capacity as a result of the Joliet and Astoria asset retirements | $ | (6) | ||||||
| Higher electric gross margin due to higher net revenue rates as a result of changes in customer term, product and mix of $2.00 per MWh, or $33 million as well as lower supply costs of $1.25 per MWh, or $17 million, driven primarily by decreases in power prices | 50 | |||||||
| Higher electric gross margin due to weather | 6 | |||||||
| Higher electric gross margin due to an increase in customer count and change in customer mix | 11 | |||||||
| Higher natural gas gross margin, including the impact of transportation and storage contract optimization, resulting in lower supply costs of $0.40 per Dth, or $148 million, driven primarily by decreases in gas costs, partially offset lower net revenue rates from changes in customer term, product, and mix of $0.30 per Dth, or $99 million | 49 | |||||||
| Higher gross margin due to an increase in average realized prices at Midwest Generation | 24 | |||||||
| Other | (4) | |||||||
| Increase in economic gross margin | $ | 130 | ||||||
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 420 | |||||||
| Increase in contract amortization | (2) | |||||||
| Decrease in depreciation and amortization | 8 | |||||||
| Increase in gross margin | $ | 556 |
West/Services/Other
| (In millions) | |||||
| Higher electric gross margin due to lower supply costs of $21.00 per MWh, or $73 million and changes in customer mix of $4 million, partially offset by lower revenue rates of $16.00 per MWh, or $55 million | $ | 22 | |||
| Higher natural gas gross margin due to lower supply costs of $0.55 per Dth, or $29 million, partially offset by lower revenue rates of $0.50 per Dth, or $27 million | 2 | ||||
| Higher gross margin at Cottonwood driven by spark spread expansion | 26 | ||||
| Higher gross margin from market optimization activities | 8 | ||||
| Other | (1) | ||||
| Increase in economic gross margin | $ | 57 | |||
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 120 | ||||
| Decrease in contract amortization | 1 | ||||
| Increase in depreciation and amortization | (23) | ||||
| Increase in gross margin | $ | 155 |
Vivint Smart Home
| (In millions) | |||||
| Higher gross margin due to an increase in subscribers of $23 million, as well as higher revenue rates of $1.51 per subscriber, or $9 million; partially offset by lower non-recurring sales revenue of $9 million | $ | 23 | |||
| Lower gross margin due to an increase in amortized capitalized contract costs in 2024, associated with the fulfillment of subscriber contracts(a) | (21) | ||||
| Lower gross margin due to recognition of fees associated with licensing products and services | (3) | ||||
| Other | (1) | ||||
| Decrease in economic gross margin | $ | (2) | |||
| Decrease in depreciation and amortization | 36 | ||||
| Increase in gross margin | $ | 34 |
(a) Capitalized contract costs began accumulating post acquisition and will continue to accumulate as new customers are acquired, leading to an expected increase in amortizations costs over time
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 $811 million during the three months ended June 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 June 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 | $ | — | $ | 1 | $ | 2 | $ | 1 | $ | 4 | |||||||||||||||||||
| Net unrealized gains on open positions related to economic hedges | — | 64 | 15 | 1 | 80 | ||||||||||||||||||||||||
| Total mark-to-market gains in revenue | $ | — | $ | 65 | $ | 17 | $ | 2 | $ | 84 | |||||||||||||||||||
| Mark-to-market results in operating costs and expenses | |||||||||||||||||||||||||||||
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | (32) | $ | 201 | $ | 37 | $ | (1) | $ | 205 | |||||||||||||||||||
| Reversal of acquired loss positions related to economic hedges | 7 | 8 | 2 | — | 17 | ||||||||||||||||||||||||
| Net unrealized gains/(losses) on open positions related to economic hedges | 630 | (6) | (54) | (1) | 569 | ||||||||||||||||||||||||
| Total mark-to-market gains/(losses) in operating costs and expenses | $ | 605 | $ | 203 | $ | (15) | $ | (2) | $ | 791 |
| Three months ended June 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 | $ | — | $ | (2) | $ | 17 | $ | (3) | $ | 12 | |||||||||||||||||||||||||
| Net unrealized gains on open positions related to economic hedges | — | 54 | 6 | 3 | 63 | ||||||||||||||||||||||||||||||
| Total mark-to-market gains in revenue | $ | — | $ | 52 | $ | 23 | $ | — | $ | 75 | |||||||||||||||||||||||||
| Mark-to-market results in operating costs and expenses | |||||||||||||||||||||||||||||||||||
| Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges | $ | (39) | $ | (73) | $ | (54) | $ | 3 | $ | (163) | |||||||||||||||||||||||||
| Reversal of acquired loss positions related to economic hedges | 11 | 20 | 4 | — | 35 | ||||||||||||||||||||||||||||||
| Net unrealized gains/(losses) on open positions related to economic hedges | 362 | (151) | (91) | (3) | 117 | ||||||||||||||||||||||||||||||
| Total mark-to-market gains/(losses) in operating costs and expenses | $ | 334 | $ | (204) | $ | (141) | $ | — | $ | (11) |
`
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 June 30, 2024, the $84 million gain in revenues from economic hedge positions was driven primarily by an increase in the value of East open positions as a result of decreases in PJM power prices. The $791 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of open positions in Texas as a result of increases in ERCOT power prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period.
For the three months ended June 30, 2023, the $75 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 natural gas and power prices as well as the reversal of previously recognized unrealized losses on contracts that settled during the period. The $11 million 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 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 and the reversal of acquired loss positions.
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 June 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 June 30, | |||||||||||
| (In millions) | 2024 | 2023 | |||||||||
| Trading (losses)/gains | |||||||||||
| Realized | $ | — | $ | (5) | |||||||
| Unrealized | 9 | 13 | |||||||||
| Total trading gains | $ | 9 | $ | 8 |
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 June 30, 2024 | $ | 231 | $ | 80 | $ | 55 | $ | 57 | $ | 1 | $ | 424 | |||||||||||||||||||||||
| Three months ended June 30, 2023 | 164 | 89 | 55 | 54 | (1) | 361 |
Operations and maintenance expense increased by $63 million for the three months ended June 30, 2024, compared to the same period in 2023, due to the following:
| (In millions) | |||||
| Increase in planned major maintenance expenditures primarily associated with the scope and duration of outages at the Texas coal facilities | $ | 54 | |||
| Increase primarily due to the prior year partial property insurance claim for the extended outage at W.A. Parish | 48 | ||||
| Decrease primarily due to the sale of STP in November 2023 | (38) | ||||
| Decrease driven by a reduction in deactivation expenditures primarily in the East | (11) | ||||
| Other | 10 | ||||
| Increase in operations and maintenance expense | $ | 63 |
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 June 30, 2024 | $ | 57 | $ | 26 | $ | 4 | $ | 2 | $ | 89 | |||||||||||||||||||
| Three months ended June 30, 2023 | 62 | 34 | 2 | 1 | 99 |
Other cost of operations for the three months ended June 30, 2024 decreased by $10 million, when compared to the same period in 2023, due to the following:
| (In millions) | |||||
| Decrease due to the sale of STP in November 2023 | $ | (10) | |||
| Decrease primarily due to lower retail gross receipt taxes in the East | (1) | ||||
| Other | 1 | ||||
| Decrease in other cost of operations | $ | (10) |
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 June 30, 2024 | $ | 63 | $ | 22 | $ | 46 | $ | 144 | $ | 10 | $ | 285 | |||||||||||||||||||||||
| Three months ended June 30, 2023 | 73 | 30 | 23 | 180 | 9 | 315 |
Depreciation and amortization decreased by $30 million for the three months ended June 30, 2024, compared to the same period in 2023, primarily due to lower amortization as a result of the expected roll off of the acquired Vivint Smart Home intangibles.
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 June 30, 2024 | $ | 195 | $ | 150 | $ | 69 | $ | 170 | $ | 8 | $ | 592 | |||||||||||||||||||||||
| Three months ended June 30, 2023 | 173 | 136 | 54 | 153 | 6 | 522 | |||||||||||||||||||||||||||||
Selling, general and administrative costs increased by $70 million for the three months ended June 30, 2024, compared to the same period in 2023, due to the following:
| (In millions) | |||||
| Increase in broker fee and commission expenses | $ | 18 | |||
| Increase in marketing and media expenses | 18 | ||||
| Increase in personnel costs | 14 | ||||
| Increase in provision for credit losses due to higher Home retail revenues | 13 | ||||
| Decrease due to the sale of STP in November 2023 | (3) | ||||
| Other | 10 | ||||
| Increase in selling, general and administrative costs | $ | 70 |
Acquisition-Related Transaction and Integration Costs
Acquisition-related transaction and integration costs of $6 million and $22 million for the three months ended June 30, 2024 and 2023, respectively, include:
| Three months ended June 30, | |||||||||||
| (In millions) | 2024 | 2023 | |||||||||
| Vivint Smart Home integration costs | $ | 5 | $ | 14 | |||||||
| Vivint Smart Home acquisition costs | — | 2 | |||||||||
| Other integration costs, primarily related to Direct Energy | 1 | 6 | |||||||||
| Acquisition-related transaction and integration costs | $ | 6 | $ | 22 |
Loss on Debt Extinguishment
A loss on debt extinguishment of $202 million was recorded for the three months ended June 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 $12 million for the three months ended June 30, 2024, compared to the same period in 2023, due to a decrease in unrealized gains on interest rate swaps, partially offset by lower interest primarily due to the repayment on the borrowings in connection with the Vivint Smart Home acquisition.
Income Tax Expense
For the three months ended June 30, 2024, income tax expense of $314 million was recorded on pre-tax income of $1.1 billion. For the same period in 2023, an income tax expense of $89 million was recorded on pre-tax income of $397 million. The effective tax rates were 29.8% and 22.4% for the three months ended June 30, 2024 and 2023, respectively.
For the three months ended June 30, 2024, the effective tax rate was higher than the statutory rate of 21% primarily due to the state tax expense and permanent differences. For the same period in 2023, the effective tax rate was higher than the statutory rate of 21% primarily due to the state tax expense.
Management’s discussion of the results of operations for the six months ended June 30, 2024 and 2023
Electricity Prices
The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the six months ended June 30, 2024 and 2023.
| Average on Peak Power Price ($/MWh) | |||||||||||||||||
| Six months ended June 30, | |||||||||||||||||
| Region | 2024 | 2023 | Change % | ||||||||||||||
| Texas | |||||||||||||||||
| ERCOT - Houston (a) | $ | 34.07 | $ | 41.76 | (18) | % | |||||||||||
| ERCOT - North(a) | 31.18 | 40.37 | (23) | % | |||||||||||||
| East | |||||||||||||||||
| NY J/NYC(b) | $ | 42.13 | $ | 38.71 | 9 | % | |||||||||||
| NEPOOL(b) | 41.00 | 42.59 | (4) | % | |||||||||||||
| COMED (PJM)(b) | 29.74 | 29.89 | (1) | % | |||||||||||||
| PJM West Hub(b) | 36.75 | 35.95 | 2 | % | |||||||||||||
| West | |||||||||||||||||
| MISO - Louisiana Hub(b) | $ | 29.33 | $ | 32.54 | (10) | % | |||||||||||
| CAISO - SP15(b) | 20.69 | 61.27 | (66) | % |
(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 six months ended June 30, 2024 and 2023:
| Six months ended June 30, | |||||||||||||||||
| 2024 | 2023 | Change % | |||||||||||||||
| ($/MMBtu) | $ | 2.07 | $ | 2.76 | (25) | % |
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.
The following tables present the composition and reconciliation of gross margin and economic gross margin for the six months ended June 30, 2024 and 2023:
| Six months ended June 30, 2024 | ||||||||||||||||||||||||||||||||||||||||||||
| ($ In millions) | Texas | East | West/Services/Other | Vivint Smart Home | Corporate/Eliminations | Total | ||||||||||||||||||||||||||||||||||||||
| Retail revenue | $ | 4,870 | $ | 5,789 | $ | 1,987 | $ | 935 | $ | (8) | $ | 13,573 | ||||||||||||||||||||||||||||||||
| Energy revenue | 23 | 127 | 118 | — | (6) | 262 | ||||||||||||||||||||||||||||||||||||||
| Capacity revenue | — | 80 | 8 | — | (2) | 86 | ||||||||||||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | — | 14 | 8 | — | 2 | 24 | ||||||||||||||||||||||||||||||||||||||
| Contract amortization | — | (16) | (1) | — | — | (17) | ||||||||||||||||||||||||||||||||||||||
| Other revenue(a) | 103 | 53 | 9 | — | (5) | 160 | ||||||||||||||||||||||||||||||||||||||
| Total revenue | 4,996 | 6,047 | 2,129 | 935 | (19) | 14,088 | ||||||||||||||||||||||||||||||||||||||
| Cost of fuel | (245) | (54) | (53) | — | — | (352) | ||||||||||||||||||||||||||||||||||||||
| Purchased energy and other cost of sales(b)(c)(d) | (3,216) | (4,956) | (1,717) | (119) | 12 | (9,996) | ||||||||||||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | 830 | 605 | (110) | — | (2) | 1,323 | ||||||||||||||||||||||||||||||||||||||
| Contract and emissions credit amortization | (2) | (42) | (2) | — | — | (46) | ||||||||||||||||||||||||||||||||||||||
| Depreciation and amortization | (130) | (45) | (70) | $ | (288) | (20) | (553) | |||||||||||||||||||||||||||||||||||||
| Gross margin | $ | 2,233 | $ | 1,555 | $ | 177 | $ | 528 | $ | (29) | $ | 4,464 | ||||||||||||||||||||||||||||||||
| Less: Mark-to-market for economic hedging activities, net | 830 | 619 | (102) | — | — | 1,347 | ||||||||||||||||||||||||||||||||||||||
| Less: Contract and emissions credit amortization, net | (2) | (58) | (3) | — | — | (63) | ||||||||||||||||||||||||||||||||||||||
| Less: Depreciation and amortization | (130) | (45) | (70) | (288) | (20) | (553) | ||||||||||||||||||||||||||||||||||||||
| Economic gross margin | $ | 1,535 | $ | 1,039 | $ | 352 | $ | 816 | $ | (9) | $ | 3,733 | ||||||||||||||||||||||||||||||||
| (a) Includes trading gains and losses and ancillary revenues | ||||||||||||||||||||||||||||||||||||||||||||
| (b) Includes capacity and emissions credits | ||||||||||||||||||||||||||||||||||||||||||||
| (c) Includes $1.6 billion, $136 million and $657 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) | 18,414 | 7,446 | 1,140 | — | — | 27,000 | ||||||||||||||||||||||||||||||||||||||
| Business electricity sales volume (GWh) | 19,740 | 23,209 | 6,012 | — | — | 48,961 | ||||||||||||||||||||||||||||||||||||||
| Home natural gas sales volume (MDth) | — | 30,113 | 45,042 | — | — | 75,155 | ||||||||||||||||||||||||||||||||||||||
| Business natural gas sales volume (MDth) | — | 805,824 | 97,693 | — | — | 903,517 | ||||||||||||||||||||||||||||||||||||||
| Average retail Home customer count (in thousands)(a) | 2,951 | 2,174 | 764 | — | — | 5,889 | ||||||||||||||||||||||||||||||||||||||
| Ending retail Home customer count (in thousands)(a) | 2,960 | 2,194 | 772 | — | — | 5,926 | ||||||||||||||||||||||||||||||||||||||
| Average Vivint Smart Home subscriber count (in thousands)(b) | — | — | — | 2,056 | — | 2,056 | ||||||||||||||||||||||||||||||||||||||
| Ending Vivint Smart Home subscriber count (in thousands)(b) | — | — | — | 2,106 | — | 2,106 | ||||||||||||||||||||||||||||||||||||||
| Power generation | ||||||||||||||||||||||||||||||||||||||||||||
| GWh sold | 8,315 | 2,118 | 2,874 | — | — | 13,307 | ||||||||||||||||||||||||||||||||||||||
| GWh generated(c) | ||||||||||||||||||||||||||||||||||||||||||||
| Coal | 4,936 | 965 | 2,871 | — | — | 8,772 | ||||||||||||||||||||||||||||||||||||||
| Gas | 3,379 | — | — | — | — | 3,379 | ||||||||||||||||||||||||||||||||||||||
| Nuclear | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||
| Oil | — | 3 | — | — | — | 3 | ||||||||||||||||||||||||||||||||||||||
| Renewables | — | — | 3 | — | — | 3 | ||||||||||||||||||||||||||||||||||||||
| Total | 8,315 | 968 | 2,874 | — | — | 12,157 | ||||||||||||||||||||||||||||||||||||||
| (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 |
| Six months ended June 30, 2023 | ||||||||||||||||||||||||||||||||||||||
| ($ In millions) | Texas | East | West/Services/Other | Vivint Smart Home**(a)** | Corporate/Eliminations | Total | ||||||||||||||||||||||||||||||||
| Retail revenue | $ | 4,353 | $ | 6,374 | $ | 2,071 | $ | 592 | $ | — | $ | 13,390 | ||||||||||||||||||||||||||
| Energy revenue | 20 | 102 | 88 | — | 1 | 211 | ||||||||||||||||||||||||||||||||
| Capacity revenue | — | 90 | 1 | — | — | 91 | ||||||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | — | 87 | 90 | — | (11) | 166 | ||||||||||||||||||||||||||||||||
| Contract amortization | — | (18) | (1) | — | — | (19) | ||||||||||||||||||||||||||||||||
| Other revenue(b) | 176 | 44 | 17 | — | (6) | 231 | ||||||||||||||||||||||||||||||||
| Total revenue | 4,549 | 6,679 | 2,266 | 592 | (16) | 14,070 | ||||||||||||||||||||||||||||||||
| Cost of fuel | (296) | (38) | (56) | — | — | (390) | ||||||||||||||||||||||||||||||||
| Purchased energy and other cost of sales(c)(d)(e) | (2,658) | (5,706) | (1,871) | (52) | 3 | (10,284) | ||||||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | 463 | (1,994) | (526) | — | 11 | (2,046) | ||||||||||||||||||||||||||||||||
| Contract and emissions credit amortization | (4) | (81) | (5) | — | — | (90) | ||||||||||||||||||||||||||||||||
| Depreciation and amortization | (148) | (60) | (47) | $ | (232) | (18) | (505) | |||||||||||||||||||||||||||||||
| Gross margin | $ | 1,906 | $ | (1,200) | $ | (239) | $ | 308 | $ | (20) | $ | 755 | ||||||||||||||||||||||||||
| Less: Mark-to-market for economic hedging activities, net | 463 | (1,907) | (436) | — | — | (1,880) | ||||||||||||||||||||||||||||||||
| Less: Contract and emissions credit amortization, net | (4) | (99) | (6) | — | — | (109) | ||||||||||||||||||||||||||||||||
| Less: Depreciation and amortization | (148) | (60) | (47) | (232) | (18) | (505) | ||||||||||||||||||||||||||||||||
| Economic gross margin | $ | 1,595 | $ | 866 | $ | 250 | $ | 540 | $ | (2) | $ | 3,249 | ||||||||||||||||||||||||||
| (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 $1.3 billion, $105 million and $598 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) | 17,413 | 5,868 | 1,145 | — | — | 24,426 | ||||||||||||||||||||||||||||||||
| Business electricity sales volume (GWh) | 18,596 | 21,842 | 4,675 | — | — | 45,113 | ||||||||||||||||||||||||||||||||
| Home natural gas sales volume (MDth) | — | 30,111 | 48,315 | — | — | 78,426 | ||||||||||||||||||||||||||||||||
| Business natural gas sales volume (MDth) | — | 823,128 | 93,058 | — | — | 916,186 | ||||||||||||||||||||||||||||||||
| Average retail Home customer count (in thousands)(a) | 2,868 | 1,810 | 781 | — | — | 5,459 | ||||||||||||||||||||||||||||||||
| Ending retail Home customer count (in thousands)(a) | 2,869 | 1,858 | 772 | — | — | 5,499 | ||||||||||||||||||||||||||||||||
| Average Vivint Smart Home subscriber count (in thousands)(b) | — | — | — | 1,958 | — | 1,958 | ||||||||||||||||||||||||||||||||
| Ending Vivint Smart Home subscriber count (in thousands)(b) | — | — | — | 2,004 | — | 2,004 | ||||||||||||||||||||||||||||||||
| Power generation | ||||||||||||||||||||||||||||||||||||||
| GWh sold | 12,694 | 1,882 | 2,869 | — | — | 17,445 | ||||||||||||||||||||||||||||||||
| GWh generated(c) | ||||||||||||||||||||||||||||||||||||||
| Coal | 5,771 | 366 | — | — | — | 6,137 | ||||||||||||||||||||||||||||||||
| Gas | 2,410 | 85 | 2,867 | — | — | 5,362 | ||||||||||||||||||||||||||||||||
| Nuclear | 4,513 | — | — | — | — | 4,513 | ||||||||||||||||||||||||||||||||
| Renewables | — | — | 2 | — | — | 2 | ||||||||||||||||||||||||||||||||
| Total | 12,694 | 451 | 2,869 | — | — | 16,014 | ||||||||||||||||||||||||||||||||
| (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 |
The following table represents the weather metrics for the six months ended June 30, 2024 and 2023:
| Six months ended June 30, | |||||||||||||||||||||||||||||||||||||||||
| Weather Metrics | Texas | East | West/Services/Other**(b)** | ||||||||||||||||||||||||||||||||||||||
| 2024 | |||||||||||||||||||||||||||||||||||||||||
| CDDs(a) | 1,289 | 463 | 687 | ||||||||||||||||||||||||||||||||||||||
| HDDs(a) | 916 | 2,648 | 1,299 | ||||||||||||||||||||||||||||||||||||||
| 2023 | |||||||||||||||||||||||||||||||||||||||||
| CDDs | 1,144 | 327 | 575 | ||||||||||||||||||||||||||||||||||||||
| HDDs | 856 | 2,570 | 1,413 | ||||||||||||||||||||||||||||||||||||||
| 10-year average | |||||||||||||||||||||||||||||||||||||||||
| CDDs | 1,101 | 392 | 605 | ||||||||||||||||||||||||||||||||||||||
| HDDs | 1,037 | 3,040 | 1,298 |
(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 $3.7 billion and economic gross margin increased $484 million, both of which include intercompany sales, during the six months ended June 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) | ||||||||
| Lower gross margin due to the net effect of: •a 13% or $169 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 •an increase in net revenue of $68 million, primarily driven by changes in customer term, product and mix | $ | (101) | ||||||
| Higher gross margin due to an increase in load of 1.6 TWhs, or $30 million, driven by an increase in customer counts and an increase in load of 515 GWhs, or $17 million, from weather | 47 | |||||||
| Lower gross margin due to market optimization activities | (6) | |||||||
| Decrease in economic gross margin | $ | (60) | ||||||
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 367 | |||||||
| Decrease in contract and emissions credit amortization | 2 | |||||||
| Decrease in depreciation and amortization | 18 | |||||||
| Increase in gross margin | $ | 327 |
East
| (In millions) | |||||
| Lower gross margin due to a decrease in generation and capacity as a result of Joliet and Astoria asset retirements | $ | (18) | |||
| Higher electric gross margin due to lower supply costs of $3.50 per MWh, or $106 million, driven primarily by decreases in power prices as well as higher net revenue rates as a result of changes in customer term, product and mix of $0.50 per MWh, or $14 million | 120 | ||||
| Higher electric gross margin due to an increase in customer count and change in customer mix | 30 | ||||
| Higher natural gas gross margin, including the impact of transportation and storage contract optimization, resulting in lower supply costs of $1.00 per Dth, or $817 million, driven primarily by a decrease in gas costs, partially offset by lower net revenue rates of $0.95 per Dth, or $809 million, from changes in customer term, product, and mix | 8 | ||||
| Lower natural gas gross margin due to weather | (4) | ||||
| Higher gross margin due to an increase in average realized price at Midwest Generation | 44 | ||||
| Other | (7) | ||||
| Increase in economic gross margin | $ | 173 | |||
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 2,526 | ||||
| Decrease in contract amortization | 41 | ||||
| Decrease in depreciation and amortization | 15 | ||||
| Increase in gross margin | $ | 2,755 |
West/Services/Other
| (In millions) | |||||
| Higher electric gross margin due to a decrease in supply costs of $20.00 per MWh, or $143 million, and changes in customer mix of $8 million, offset by lower revenue rates of $12.50 per MWh, or $89 million | $ | 62 | |||
| Higher natural gas gross margin due to lower supply costs of $1.40 per Dth, or $201 million, partially offset by lower revenue rates $1.35 per Dth, or $190 million | 11 | ||||
| Higher gross margin at Cottonwood driven by spark spread expansion | 38 | ||||
| Lower gross margin from market optimization activities | (8) | ||||
| Other | (1) | ||||
| Increase in economic gross margin | $ | 102 | |||
| Increase in mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges | 334 | ||||
| Decrease in contract amortization | 3 | ||||
| Increase in depreciation and amortization | (23) | ||||
| Increase in gross margin | $ | 416 |
Vivint Smart Home**(a)**
| (In millions) | |||||
| Increase due to the acquisition of Vivint Smart Home | $ | 276 | |||
| Higher gross margin due to increased subscribers, or $31 million, as well as higher revenue rates of $1.85 per subscriber or $15 million, partially offset by lower non-recurring sales revenue of $12 million | 34 | ||||
| Lower gross margin due to an increase in amortized capitalized contract costs in 2024, associated with the fulfillment of subscriber contracts(b) | (28) | ||||
| Lower gross margin due to recognition of fees associated with licensing products and services | (4) | ||||
| Other | (2) | ||||
| Increase in economic gross margin | $ | 276 | |||
| Increase in depreciation and amortization | (56) | ||||
| Increase in gross margin | $ | 220 |
(a) Includes results of operations following the acquisition date of March 10, 2023
(b) Capitalized contract costs began accumulating post acquisition and will continue to accumulate as new customers are acquired, leading to an expected increase in amortizations costs over time
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 $3.2 billion during the six months ended June 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:
| Six months ended June 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 | $ | — | $ | (32) | $ | (9) | $ | 2 | $ | (39) | |||||||||||||||||||||||||
| Net unrealized gains on open positions related to economic hedges | — | 46 | 17 | — | 63 | ||||||||||||||||||||||||||||||
| Total mark-to-market gains in revenue | $ | — | $ | 14 | $ | 8 | $ | 2 | $ | 24 | |||||||||||||||||||||||||
| Mark-to-market results in operating costs and expenses | |||||||||||||||||||||||||||||||||||
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | (118) | $ | 532 | $ | 80 | $ | (2) | $ | 492 | |||||||||||||||||||||||||
| Reversal of acquired loss/(gain) positions related to economic hedges | 11 | (8) | 2 | — | 5 | ||||||||||||||||||||||||||||||
| Net unrealized gains/(losses) on open positions related to economic hedges | 937 | 81 | (192) | — | 826 | ||||||||||||||||||||||||||||||
| Total mark-to-market gains/(losses) in operating costs and expenses | $ | 830 | $ | 605 | $ | (110) | $ | (2) | $ | 1,323 |
| Six months ended June 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 | $ | — | $ | (15) | $ | 26 | $ | (6) | $ | 5 | |||||||||||||||||||||||||
| Reversal of acquired (gain) positions related to economic hedges | — | (1) | — | — | (1) | ||||||||||||||||||||||||||||||
| Net unrealized gains on open positions related to economic hedges | — | 103 | 64 | (5) | 162 | ||||||||||||||||||||||||||||||
| Total mark-to-market gains in revenue | $ | — | $ | 87 | $ | 90 | $ | (11) | $ | 166 | |||||||||||||||||||||||||
| Mark-to-market results in operating costs and expenses | |||||||||||||||||||||||||||||||||||
| Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges | $ | (118) | $ | (555) | $ | (335) | $ | 6 | $ | (1,002) | |||||||||||||||||||||||||
| Reversal of acquired loss/(gain) positions related to economic hedges | 18 | (8) | 1 | — | 11 | ||||||||||||||||||||||||||||||
| Net unrealized gains/(losses) on open positions related to economic hedges | 563 | (1,431) | (192) | 5 | (1,055) | ||||||||||||||||||||||||||||||
| Total mark-to-market gains/(losses) in operating costs and expenses | $ | 463 | $ | (1,994) | $ | (526) | $ | 11 | $ | (2,046) |
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 six months ended June 30, 2024, the $24 million gain in revenues from economic hedge positions was primarily driven by an increase in the value of newly executed East open positions and decreases in PJM power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $1.3 billion gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of Texas open positions as a result of increases in ERCOT power prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period.
For the six months ended June 30, 2023, the $166 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 and natural gas prices. The $2.0 billion loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of East and West open positions as a result of decreases in natural gas and power prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period. This was partially offset by an increase in the value of Texas open positions as a result of increase in ERCOT power prices and the reversal of acquired loss positions.
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the six months ended June 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.
| Six months ended June 30, | |||||||||||
| (In millions) | 2024 | 2023 | |||||||||
| Trading gains/(losses) | |||||||||||
| Realized | $ | 5 | $ | (3) | |||||||
| Unrealized | 5 | 25 | |||||||||
| Total trading gains | $ | 10 | $ | 22 |
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 | |||||||||||||||||||||||||||||
| Six months ended June 30, 2024 | $ | 417 | $ | 158 | $ | 107 | $ | 111 | $ | 1 | $ | 794 | |||||||||||||||||||||||
| Six months ended June 30, 2023 | 382 | 168 | 126 | 72 | (2) | 746 | |||||||||||||||||||||||||||||
(a) Includes results of operations following the acquisition date of March 10, 2023
Operations and maintenance expense increased by $48 million for the six months ended June 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 | $ | 63 | |||
| Increase primarily due to the prior year partial property insurance claim for the extended outage at W.A. Parish | 44 | ||||
| Increase due to the acquisition of Vivint Smart Home in March 2023 | 36 | ||||
| Decrease primarily due to the sale of STP in November 2023 | (82) | ||||
| Decrease driven by a reduction in deactivation expenditures primarily in the East | (19) | ||||
| Other | 6 | ||||
| Increase in operations and maintenance expense | $ | 48 |
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 | |||||||||||||||||||||||||||||||||
| Six months ended June 30, 2024 | $ | 107 | $ | 58 | $ | 7 | $ | 4 | $ | 176 | ||||||||||||||||||||||||||||
| Six months ended June 30, 2023 | 111 | 66 | 6 | 1 | 184 |
(a) Includes results of operations following the acquisition date of March 10, 2023
Other cost of operations decreased by $8 million for the six months ended June 30, 2024, compared to the same period in 2023, due to the following:
| (In millions) | |||||
| Decrease primarily due to the sale of STP in November 2023 | $ | (15) | |||
| Increase in retail gross receipt taxes due to higher revenues in Texas partially offset by lower retail gross receipt taxes in the East | 4 | ||||
| Other | 3 | ||||
| Decrease in other cost of operations | $ | (8) |
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 | |||||||||||||||||||||||||||||
| Six months ended June 30, 2024 | $ | 130 | $ | 45 | $ | 70 | $ | 288 | $ | 20 | $ | 553 | |||||||||||||||||||||||
| Six months ended June 30, 2023 | 148 | 60 | 47 | 232 | 18 | 505 |
(a) Includes results of operations following the acquisition date of March 10, 2023
Depreciation and amortization increased by $48 million for the six months ended June 30, 2024, compared to the same period in 2023, primarily due to higher amortization of intangible assets due to the acquisition of Vivint Smart Home in March 2023.
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 | |||||||||||||||||||||||||||||
| Six months ended June 30, 2024 | $ | 389 | $ | 310 | $ | 124 | $ | 336 | $ | 24 | $ | 1,183 | |||||||||||||||||||||||
| Six months ended June 30, 2023 | 343 | 285 | 105 | 203 | 12 | 948 | |||||||||||||||||||||||||||||
(a) Includes results of operations following the acquisition date of March 10, 2023
Total selling, general and administrative costs increased by $235 million for the six months ended June 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 | $ | 104 | ||||||
| Increase in provision for credit losses due to higher Home retail revenues and customer payment behavior | 44 | |||||||
| Increase in broker fee and commissions expenses | 37 | |||||||
| Increase in marketing and media expenses | 32 | |||||||
| Increase in personnel costs | 22 | |||||||
| Decrease driven by the sale of STP in November 2023 | (6) | |||||||
| Other | 2 | |||||||
| Increase in selling, general and administrative costs | $ | 235 |
Acquisition-Related Transaction and Integration Costs
Acquisition-related transaction and integration costs were $15 million and $93 million for the six months ended June 30, 2024 and 2023, respectively include:
| Six months ended June 30, | |||||||||||
| (In millions) | 2024 | 2023 | |||||||||
| Vivint Smart Home integration costs | $ | 13 | $ | 44 | |||||||
| Vivint Smart Home acquisition costs | — | 38 | |||||||||
| Other integration costs, primarily related to Direct Energy | 2 | 11 | |||||||||
| Acquisition-related transaction and integration costs | $ | 15 | $ | 93 |
Gain on Sale of Assets
The gain on sale of assets of $202 million for the six months ended June 30, 2023 was due to the $199 million gain related to the sale of land and related assets from the Astoria site, as well as other assets sales of $3 million.
Loss on Debt Extinguishment
A loss on debt extinguishment of $260 million was recorded for the six months ended June 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 $16 million for the six months ended June 30, 2024, compared to the same period in 2023, primarily due to the acquisition of Vivint Smart Home in March 2023.
Income Tax Expense/(Benefit)
For the six months ended June 30, 2024, an income tax expense of $498 million was recorded on a pre-tax income of $1.7 billion. For the same period in 2023, income tax benefit of $247 million was recorded on pre-tax loss of $1.3 billion. The effective tax rates were 28.5% and 19.4% for the six months ended June 30, 2024 and 2023, respectively.
For the six months ended June 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 overall effective tax rate was lower than the statutory rate of 21%, primarily due to current state tax expense which has an inverted effect and reduces the overall effective tax rate when applied to year-to-date financial statement losses.
Liquidity and Capital Resources
Liquidity Position
As of June 30, 2024 and December 31, 2023, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $5.3 billion and $4.8 billion, respectively, was comprised of the following:
| (In millions) | June 30, 2024 | December 31, 2023 | |||||||||
| Cash and cash equivalents | $ | 376 | $ | 541 | |||||||
| Restricted cash - operating | 10 | 21 | |||||||||
| Restricted cash - reserves(a) | 6 | 3 | |||||||||
| Total | 392 | 565 | |||||||||
| Total availability under Revolving Credit Facility and collective collateral facilities(b) | 4,950 | 4,278 | |||||||||
| Total liquidity, excluding funds deposited by counterparties | $ | 5,342 | $ | 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 $7.9 billion and $7.4 billion as of June 30, 2024 and December 31, 2023, respectively.
For the six months ended June 30, 2024, total liquidity, excluding funds deposited by counterparties, increased by $499 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at June 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. As part of the acquisition of Vivint Smart Home on March 10, 2023, NRG acquired Vivint's existing debt, which includes senior secured notes, senior notes and a 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.
Planned sale of Airtron
On August 3, 2024, the Company entered into a definitive agreement to sell its Airtron business unit for total proceeds of $500 million, subject to standard purchase price adjustments. Airton is a leading provider of HVAC systems for residential new construction homes and was acquired as part of the Direct Energy acquisition in 2021. The transaction is subject to regulatory approval under the Hart Scott Rodino act and is expected to close by the end of 2024.
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), 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 July 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.
During the six months ended June 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 six months ended June 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 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 June 30, 2024, there were no outstanding borrowings and there were $1.1 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 six months ended June 30, 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 changes to the Vivint Credit Agreement.
From and after the closing of the Second Amendment, 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%.
Debt Reduction
The Company intends to spend approximately $500 million reducing debt during 2024 to maintain its targeted credit metrics. The Company intends to fund the debt reduction from cash from operations. Through June 30, 2024, as part of the 2024 capital allocation plan, the Company has spent $325 million on the planned debt reduction.
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 June 30, 2024, the Company had total cash collateral outstanding of $384 million and $2.9 billion outstanding in letters of credit to third parties primarily to support its market activities. As of June 30, 2024, total funds deposited by counterparties were $688 million in cash and $801 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 June 30, 2024, all hedges under the first liens were in-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 six months ended June 30, 2024, and the estimated forecast for the remainder of the year.
| (In millions) | Maintenance | Environmental | Investments and Integration | Total | |||||||||||||||||||
| Texas | $ | 101 | $ | 8 | $ | 16 | $ | 125 | |||||||||||||||
| West/Services/Other | 9 | — | 1 | 10 | |||||||||||||||||||
| Vivint Smart Home | 8 | 2 | 10 | ||||||||||||||||||||
| Corporate | 8 | — | 19 | 27 | |||||||||||||||||||
| Total cash capital expenditures for the six months ended June 30, 2024 | 126 | 8 | 38 | 172 | |||||||||||||||||||
| Integration operating expenses and cost to achieve | — | — | 32 | 32 | |||||||||||||||||||
| Investments | — | — | 90 | 90 | |||||||||||||||||||
| Total cash capital expenditures and investments for the six months ended June 30, 2024 | $ | 126 | $ | 8 | $ | 160 | $ | 294 | |||||||||||||||
| Estimated cash capital expenditures and investments for the remainder of 2024(a) | 184 | 17 | 175 | 376 | |||||||||||||||||||
| Estimated full year 2024 cash capital expenditures and investments | $ | 310 | $ | 25 | $ | 335 | $ | 670 |
(a)Excludes capital expenditures related to brownfield development projects that were submitted to the Texas Energy Fund
Investments and Integration for the six months ended June 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 $62 million, primarily driven by the cost of complying with ELG at the Company's coal units in Texas.
Share Repurchases
On June 22, 2023, NRG revised its long-term capital allocation policy to target allocating approximately 80% of cash available for allocation after debt reduction to be returned to shareholders. As part of the revised capital allocation framework, the Company announced an increase to its share repurchase authorization to $2.7 billion, to be executed through 2025.
During the six months ended June 30, 2024, the Company completed $90 million of open market share repurchases at an average price of $80.76 per share. Through July 31, 2024, an additional $86 million of share repurchases were executed at an average price of $76.27 per share. As of July 31, 2024, $1.4 billion is remaining under the $2.7 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 and expects to target an annual dividend growth rate of 7%-9% per share in subsequent years. A quarterly dividend of $0.4075 per share was paid on the Company's common stock during the three months ended June 30, 2024. On July 19, 2024, NRG declared a quarterly dividend on the Company's common stock of $0.4075 per share, payable on August 15, 2024 to stockholders of record as of August 1, 2024.
Series A Preferred Stock Dividends
During the quarter ended March 31, 2024, the Company declared and paid a semi-annual 10.25% dividend of $51.25 per share on its outstanding Series A Preferred Stock, 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 June 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 six months ended June 30, 2024.
Cash Flow Discussion
The following table reflects the changes in cash flows for the six month ended June 30, 2024 and 2023, respectively:
| Six months ended June 30, | |||||||||||||||||
| (In millions) | 2024 | 2023 | Change | ||||||||||||||
| Cash provided/(used) by operating activities | $ | 1,323 | $ | (1,028) | $ | 2,351 | |||||||||||
| Cash used by investing activities | (201) | (2,502) | 2,301 | ||||||||||||||
| Cash (used)/provided by financing activities | (691) | 2,162 | (2,853) |
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 | $ | 2,015 | |||
| Increase in operating income/loss adjusted for other non-cash items | 542 | ||||
| Decrease in working capital primarily related to the payout of the Company's annual incentive plan in 2024 reflecting financial outperformance for 2023 | (173) | ||||
| Other | (33) | ||||
| $ | 2,351 |
Cash 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 | $ | 2,466 | |||
| Decrease in proceeds from sale of assets primarily due to the sale of the land and related assets from the Astoria site in January 2023 | (218) | ||||
| Decrease in capital expenditures | 152 | ||||
| Decrease in insurance proceeds for property, plant and equipment, net | (118) | ||||
| Increase due to fewer purchases of emissions allowances, net of sales | 14 | ||||
| Other | 5 | ||||
| $ | 2,301 |
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 | $ | (946) | |||
| Decrease in proceeds from Revolving Credit Facility and Receivables Securitization Facilities in 2023 | (700) | ||||
| Decrease in proceeds due to the issuance of preferred stock in 2023 | (635) | ||||
| Decrease in net receipts from settlement of acquired derivatives | (330) | ||||
| Decrease primarily due to debt extinguishment costs in 2024 | (247) | ||||
| Increase in proceeds due to the issuance of long-term debt | 144 | ||||
| Decrease due to payments for share repurchase activity | (109) | ||||
| Increase in payments of dividends primarily due to preferred stock | (30) | ||||
| $ | (2,853) |
NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
For the six months ended June 30, 2024, the Company had domestic pre-tax book income of $1.8 billion and foreign pre-tax book loss of $100 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 $160 million in 2024. As of June 30, 2024, NRG as an applicable corporation is subject to the CAMT and expects to claim a CAMT credit in future years. The Company has reflected the impact of the CAMT in its current and deferred taxes. There is no CAMT impact to NRG's effective income tax rate.
As of June 30, 2024, the Company has $64 million of tax-effected uncertain federal and state tax benefits, for which the Company has recorded a non-current tax liability of $67 million (inclusive of accrued interest) until final resolution is reached with the related taxing authority.
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 June 30, 2024 and December 31, 2023, NRG recorded a net deferred tax asset, excluding valuation allowance, of $2.1 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 June 30, 2024 and December 31, 2023 as discussed below.
NOL Carryforwards — As of June 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 $106 million.
Valuation Allowance — As of June 30, 2024 and December 31, 2023, the Company’s tax-effected valuation allowance was $271 million and $275 million, respectively, 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 June 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.
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) | Six months ended June 30, 2024 | ||||
| Revenue(a) | $ | 11,664 | |||
| Operating income(b) | 2,291 | ||||
| Total other expense | (430) | ||||
| Income before income taxes | 1,861 | ||||
| Net Income | 1,341 |
(a)Intercompany transactions with Non-Guarantors of $1 million during the six months ended June 30, 2024
(b)Intercompany transactions with Non-Guarantors including cost of operations of $44 million and selling, general and administrative of $122 million during the six months ended June 30, 2024
The following table presents the summarized balance sheet information:
| (In millions) | June 30, 2024 | ||||
| Current assets(a) | $ | 6,363 | |||
| Property, plant and equipment, net | 1,235 | ||||
| Non-current assets | 12,481 | ||||
| Current liabilities(b) | 6,844 | ||||
| Non-current liabilities | 9,919 |
(a)Includes intercompany receivables due from Non-Guarantors of $45 million as of June 30, 2024
(b)Includes intercompany payables due to Non-Guarantors of $23 million as of June 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 June 30, 2024, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at June 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 | (In millions) | ||||
| Fair Value of Contracts as of December 31, 2023 | $ | 648 | |||
| Contracts realized or otherwise settled during the period | 471 | ||||
| Other changes in fair value | 927 | ||||
| Fair Value of Contracts as of June 30, 2024 | $ | 2,046 |
| Fair Value of Contracts as of June 30, 2024 | |||||||||||||||||||||||||||||
| (In millions) | Maturity | ||||||||||||||||||||||||||||
| Fair Value Hierarchy Gains/(Losses) | 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 | $ | 1 | $ | 36 | $ | — | $ | (2) | $ | 35 | |||||||||||||||||||
| Level 2 | 868 | 773 | 227 | 173 | 2,041 | ||||||||||||||||||||||||
| Level 3 | (13) | (27) | (10) | 20 | (30) | ||||||||||||||||||||||||
| Total | $ | 856 | $ | 782 | $ | 217 | $ | 191 | $ | 2,046 |
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 indicator of NRG's hedging activity. As of June 30, 2024, NRG's net derivative asset was $2.0 billion, an increase to total fair value of $1.4 billion as compared to December 31, 2023. This increase was primarily driven by gains in fair value and 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 $2.1 billion in the net value of derivatives as of June 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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