Chord Energy Corp: Form 10-Q for the period ended Jun 30, 2024

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2023 (“2023 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategic tactics, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plans” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed below and detailed under “Part II, Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Without limiting the generality of the foregoing, certain statements incorporated by reference or included in this Quarterly Report on Form 10-Q constitute forward-looking statements.

Forward-looking statements may include statements about:

• crude oil, NGLs and natural gas realized prices;
• uncertainty regarding the future actions of foreign oil producers and the related impacts such actions have on the balance between the supply of and demand for crude oil, NGLs and natural gas;
• the actions taken by OPEC+ with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations;
• war between Russia and Ukraine as well as war between Hamas and Israel, with the potential for escalation of hostilities across the surrounding countries in the Middle East, and their effect on commodity prices;
• changes in general economic and geopolitical conditions, including as a result of the 2024 U.S. presidential election;
• inflation rates and the impact of associated monetary policy responses, including increased interest rates;
• logistical challenges and supply chain disruptions;
• our business strategy;
• the geographic concentration of our operations;
• estimated future net reserves and present value thereof;
• timing and amount of future production of crude oil, NGLs and natural gas;
• drilling and completion of wells;
• estimated inventory of wells remaining to be drilled and completed;
• costs of exploiting and developing our properties and conducting other operations;
• availability of drilling, completion and production equipment and materials;
• availability of qualified personnel;
• infrastructure for produced and flowback water gathering and disposal;
• gathering, transportation and marketing of crude oil, NGLs and natural gas in the Williston Basin and other regions in the United States;
• the possible shutdown of the Dakota Access Pipeline;
• incurring significant transaction and other costs in connection with the Arrangement (as defined in the “Recent Developments” section of Item 2 below) in excess of those anticipated;
• the ultimate timing, outcome and results of integrating the operations of Chord and Enerplus;
• failure to realize the anticipated benefits or synergies from the Arrangement in the timeframe expected or at all;
• property acquisitions, including the Arrangement, and divestitures;
• integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness, including the Arrangement;
• any litigation relating to the Arrangement;
• the amount, nature and timing of capital expenditures;
• availability and terms of capital;
• our financial strategic tactics, budget, projections, execution of business plan and operating results;
• cash flows and liquidity;
• our ability to return capital to shareholders;
• our ability to utilize net operating loss carryforwards or other tax attributes in future periods;
• our ability to comply with the covenants under our Credit Agreement and other indebtedness;
• operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
• interruptions in service and fluctuations in tariff provisions of third-party connecting pipelines;
• potential effects arising from cybersecurity threats, terrorist attacks and any consequential or other hostilities;
• compliance with, and changes in, environmental, safety and other laws and regulations, including the Inflation Reduction Act of 2022;
• execution of our ESG initiatives;
• effectiveness of risk management activities;
• competition in the oil and gas industry;
• counterparty credit risk;
• incurring environmental liabilities;
• developments in the global economy as well as any public health crisis similar to or caused by a recurrence of the novel COVID-19 pandemic and resulting demand and supply for crude oil, NGLs and natural gas;
• governmental regulation and the taxation of the oil and gas industry;
• developments in crude oil-producing and natural gas-producing countries;
• technology;
• consumer demand and preferences for, and governmental policies encouraging, fossil fuel alternatives;
• the effects of accounting pronouncements issued periodically during the periods covered by forward-looking statements;
• uncertainty regarding future operating results;
• our ability to successfully forecast future operating results and manage activity levels with ongoing macroeconomic uncertainty;
• the impact of disruptions in the financial markets, including any bank failures and the interest rate environment;
• plans, objectives, expectations and intentions contained in this Quarterly Report on Form 10-Q that are not historical; and
• certain factors discussed elsewhere in this Quarterly Report on Form 10-Q, in our 2023 Annual Report and in our other filings with the SEC.

All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include changes in crude oil, NGL and natural gas prices, climatic and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, inflation, the proximity to and capacity of transportation facilities and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Quarterly Report on Form 10-Q, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Overview

Chord Energy Corporation (together with its consolidated subsidiaries, the “Company”, “Chord”, “we”, “us,” or “our”) is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, NGL and natural gas primarily in the Williston Basin. Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a rewarding environment for our employees. We are ideally positioned to enhance return of capital and generate strong free cash flow, while being responsible stewards of the communities and environment where we operate.

Market Conditions and Commodity Prices

Our revenue, profitability and ability to return cash to shareholders depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Prices for crude oil, NGLs and natural gas have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future due to a combination of macro-economic factors that impact the supply and demand for crude oil, NGLs and natural gas.

While we are unable to predict future commodity prices, we do not believe that an impairment of our oil and gas properties is reasonably likely to occur in the near future at current price levels; however, we would evaluate the recoverability of the carrying value of our oil and gas properties as a result of a future material or extended decline in the price of crude oil, NGLs or natural gas or a material increase in the costs of labor, materials or services.

In an effort to improve price realizations from the sale of our crude oil, NGLs and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGLs and natural gas to a broader array of potential purchasers. We enter into crude oil, NGL and natural gas sales contracts with purchasers who have access to transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single customer would have a material adverse effect on our results of operations or cash flows.

Additionally, we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of June 30, 2024, substantially all of our gross operated crude oil and natural gas production were connected to gathering systems.

Recent Developments

Enerplus Arrangement

On February 21, 2024, we entered into an arrangement agreement (the “Arrangement Agreement ”) with Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”), and Spark Acquisition ULC, an unlimited liability company organized and existing under the laws of the Province of Alberta, Canada and a wholly-owned subsidiary of the Company, pursuant to which, among other things, we agreed to acquire Enerplus in a stock-and-cash transaction (such transaction, the “Arrangement”). Enerplus was an independent North American oil and gas E&P company domiciled in Canada with substantially all of its producing assets in the Williston Basin of North Dakota, with limited non-operated interests in the Marcellus Shale. The Arrangement was completed on May 31, 2024.

Upon completion of the Arrangement on May 31, 2024, we issued 20,680,097 shares of common stock and paid $375.8 million in cash to Enerplus shareholders. Under the terms of the Arrangement Agreement, Enerplus shareholders received 0.10125 shares of Chord common stock, par value $0.01 per share, and $1.84 per share in cash in exchange for each share of Enerplus they owned at closing.

Results of Operations

Comparability of Financial Statements

The results of operations presented below relate to the periods ended June 30, 2024 and 2023. The results reported for the three and six months ended June 30, 2024 reflect the consolidated results of Chord, including combined operations with Enerplus beginning on May 31, 2024, while the results reported for the three and six months ended June 30, 2023 reflect the consolidated results of Chord, excluding the impact from the business combination with Enerplus and the 2023 acquisition of acreage in the Williston Basin, unless otherwise noted.

Operational and Financial Highlights

• Production volumes averaged 207,187 Boepd (57% oil), including crude oil volumes of 118,143 Bopd in the second quarter of 2024.
• E&P and other capital expenditures (excluding capitalized interest) were $314.3 million in the second quarter of 2024.
• Lease operating expenses (“LOE”) were $9.37 Boe in the second quarter of 2024.
• Net cash provided by operating activities was $460.9 million and net income was $213.4 million in the second quarter of 2024.

Shareholder Return Highlights

• Paid $2.94 per share base-plus-variable cash dividend on June 5, 2024.
• Repurchased $61.7 million of common stock in the second quarter of 2024 with $591.3 million remaining under our $750 million share repurchase program.
• Declared a base-plus-variable cash dividend of $2.52 per share of common stock. The dividend will be payable on September 5, 2024 to shareholders of record as of August 21, 2024.

Revenues

Our crude oil, NGL and natural gas revenues are derived from the sale of crude oil, NGL and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Our revenues for the three and six months ended June 30, 2024 increased due to the Arrangement, which expanded our operations primarily in the Williston Basin. Our purchased oil and gas sales are derived from the sale of crude oil, NGLs and natural gas purchased through our marketing activities primarily to optimize transportation costs, for blending to meet pipeline specifications or to cover production shortfalls. Revenues and expenses from crude oil, NGL and natural gas sales and purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the counterparty. In certain cases, we enter into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis.

The following table summarizes our revenues, production and average realized prices for the periods presented:

(1) Natural gas production volumes from the Marcellus Shale were 3,764 MMcf for both the three and six months ended June 30, 2024, and the realized natural gas price related to this production was $1.66 per Mcf (prior to the effect of derivative settlements).

(2) The effect of derivative settlements includes the gains or losses on commodity derivatives for contracts ending in the periods presented. Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes.

Three months ended June 30, 2024 as compared to three months ended March 31, 2024

Crude oil revenues. Our crude oil revenues increased $169.3 million to $848.1 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024. Our expanded operations after the Arrangement contributed $127.0 million of additional crude oil revenues quarter over quarter. Excluding the impacts of the Arrangement, our crude oil revenues increased $42.3 million due to an increase of $38.7 million driven by higher crude oil realized prices quarter over quarter, coupled with an increase of $3.6 million due to higher crude oil production volumes sold. Average crude oil sales prices, without derivative settlements, increased by $3.57 per barrel quarter over quarter to an average of $78.89 per barrel for the three months ended June 30, 2024 primarily due to an increase in NYMEX WTI.

NGL revenues. Our NGL revenues decreased $10.5 million to $36.8 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024. Our expanded operations after the Arrangement were not material to NGL revenues quarter over quarter. The decrease was primarily driven by a $16.0 million decrease due to lower NGL realized prices, partially offset by a $5.5 million increase due to higher production volumes sold quarter over quarter. Average NGL sales prices, without derivative settlements, decreased by $5.10 per barrel quarter over quarter to an average of $9.99 per barrel for the three months ended June 30, 2024 primarily due to lower index prices at the Conway hub in Kansas as well as widening differentials.

Natural gas revenues. Our natural gas revenues decreased $4.3 million to $17.8 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024. Our expanded operations after the Arrangement contributed $6.5 million of additional natural gas revenues quarter over quarter. Excluding the impacts of the Arrangement, our natural gas revenues decreased $10.8 million primarily due to lower natural gas realized prices quarter over quarter. Average natural gas sales prices, without derivative settlements, decreased by $0.49 per Mcf quarter over quarter to $0.67 per Mcf for the three months ended June 30, 2024 primarily due to lower index prices.

Purchased oil and gas sales. Purchased oil and gas sales increased $20.9 million to $358.0 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024. This increase was primarily due to an increase in the price of crude oil purchased and subsequently sold quarter over quarter.

Six months ended June 30, 2024 as compared to six months ended June 30, 2023

Crude oil revenues. Our crude oil revenues increased $228.2 million to $1,527.0 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023. Our expanded operations after the Arrangement contributed $127.0 million of additional crude oil revenues period over period. Excluding the impacts of the Arrangement, our crude oil revenues increased $101.2 million due to higher production volumes sold of $57.5 million coupled with higher crude oil realized prices of $43.7 million. Production volumes period over period increased in part due to the 2023 acquisition of acreage in the Williston Basin. Average crude oil sales prices, without derivative settlements, increased by $2.31 per barrel period over period to an average of $77.26 per barrel for the six months ended June 30, 2024 primarily due to an increase in NYMEX WTI.

NGL revenues. Our NGL revenues decreased $6.8 million to $84.0 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023. Our expanded operations after the Arrangement were not material to NGL revenues period over period. The decrease was primarily due to lower NGL realized prices of $14.0 million, partially offset by higher production volumes sold of $7.2 million period over period. Average NGL sales prices, without derivative settlements, decreased by $2.25 per barrel period over period to an average of $12.33 per barrel for the six months ended June 30, 2024 primarily due to the impact of incurring a fixed fee for the majority of our NGL marketing contracts beginning in the second quarter of 2023, partially offset by higher index prices.

Natural gas revenues. Our natural gas revenues decreased $32.2 million to $39.9 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023. Our expanded operations after the Arrangement contributed $6.5 million of additional natural gas revenues period over period. Excluding the impacts of the Arrangement, our natural gas revenues decreased $38.7 million primarily due to lower natural gas realized prices period over period. Average natural gas sales prices, without derivative settlements, decreased by $0.94 per Mcf period over period to $0.87 per Mcf for the six months ended June 30, 2024 primarily due to the impact of incurring a fixed fee for the majority of our natural gas marketing contracts beginning in the second quarter of 2023, coupled with lower index prices.

Purchased oil and gas sales. Purchased oil and gas sales increased $348.1 million to $695.1 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023. This increase was primarily due to an increase in the volume of crude oil purchased and subsequently sold period over period.

Expenses and other income (expense)

The following table summarizes our operating expenses and other income (expense) for the periods presented:

(In thousands, except per Boe of production data)

Three months ended June 30, 2024 as compared to three months ended March 31, 2024

Lease operating expenses. LOE increased $17.4 million to $176.6 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024. Our expanded operations after the Arrangement contributed $22.9 million of additional LOE quarter over quarter. Excluding the impacts of the Arrangement, LOE decreased $5.5 million primarily due to lower workover costs quarter over quarter. LOE per Boe decreased $1.02 per Boe quarter over quarter to $9.37 per Boe for the three months ended June 30, 2024 primarily due to lower workover costs coupled with higher production volumes quarter over quarter.

Gathering, processing and transportation expenses. GPT expenses increased $9.1 million to $63.1 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024. Our expanded operations after the Arrangement contributed $10.7 million of additional GPT quarter over quarter. Excluding the impacts of the Arrangement, GPT remained relatively consistent quarter over quarter. GPT expenses per Boe decreased $0.17 per Boe to $3.35 per Boe for the three months ended June 30, 2024.

Purchased oil and gas expenses. Purchased oil and gas expenses increased $20.6 million to $356.4 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024 driven by an increase in the price of crude oil purchased and subsequently sold quarter over quarter.

Production taxes. Production taxes increased $15.6 million to $79.5 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024. Our expanded operations after the Arrangement contributed $11.1 million of additional production taxes quarter over quarter. Excluding the impacts of the Arrangement, production taxes increased $4.5 million primarily due to higher crude oil sales quarter over quarter. The production tax rate as a percentage of crude oil, NGL and natural gas sales was 8.8% for the three months ended June 30, 2024 as compared to 8.5% for the three months ended March 31, 2024. This rate increase quarter over quarter was primarily due to a decrease in natural gas and NGL sales revenues as a result of lower realized prices.

Depreciation, depletion and amortization. DD&A expense increased $59.0 million to $227.9 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024. Our expanded operations after the Arrangement contributed $40.4 million of additional DD&A quarter over quarter. Excluding the impacts of the Arrangement, DD&A expense increased $18.6 million primarily due to a higher depletion rate quarter over quarter. The depletion rate increased $1.21 per Boe quarter over quarter to $11.83 per Boe for the three months ended June 30, 2024 primarily due to the addition of oil and gas properties acquired in the Arrangement.

General and administrative expenses. G&A expenses increased $56.4 million to $82.1 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024. Our expanded operations after the Arrangement contributed $50.7 million of additional G&A expenses quarter over quarter, including merger-related costs of $46.6 million and other G&A expenses of $4.1 million.

Gain on sale of assets, net. During the three months ended June 30, 2024 and March 31, 2024, we recorded a net gain on sale of assets of $15.5 million and $1.3 million, respectively, primarily related to the divestitures of certain non-operated properties within each quarter.

Derivative instruments. We recorded a $4.6 million net gain on derivative instruments for the three months ended June 30, 2024, which was comprised of a net gain of $4.0 million associated with our contracts to manage commodity price risk and an unrealized gain of $0.6 million associated with a contract that includes contingent consideration. The net gain of $4.0 million on commodity derivative contracts included an unrealized gain of $7.9 million related to the change in fair value of our commodity derivative contracts, partially offset by a realized loss of $3.9 million on settled commodity derivative contracts. During the three months ended March 31, 2024, we recorded a $27.6 million net loss on derivative instruments, which was comprised of a net loss of $31.0 million associated with our contracts to manage commodity price risk, partially offset by an unrealized gain of $3.4 million associated with a contract that includes contingent consideration. The net loss of $31.0 million on commodity derivative contracts included an unrealized loss of $29.6 million related to the change in fair value of our commodity derivative contracts and a realized loss of $1.4 million on settled commodity derivative contracts.

Investment in unconsolidated affiliate. We recorded a $5.9 million gain related to our investment in Energy Transfer LP (“Energy Transfer”) for the three months ended June 30, 2024 due to an unrealized gain of $3.6 million as a result of an increase in the fair value of the investment during the period, coupled with a gain of $2.3 million for a cash distribution received from Energy Transfer during the period. During the three months ended March 31, 2024, we recorded a $16.3 million gain related to our investment in Energy Transfer due to an unrealized gain of $14.0 million as a result of an increase in the fair value of the investment during the period, coupled with a gain of $2.3 million for a cash distribution received from Energy Transfer during the period.

Income tax expense. Our income tax expense was recorded at 26.8% and 22.4% of pre-tax income for the three months ended June 30, 2024 and March 31, 2024, respectively. Our effective tax rate for the three months ended June 30, 2024 was higher than the effective tax rate for the three months ended March 31, 2024 primarily due to Canadian losses for which no benefit is recognized, coupled with the impacts of equity-based compensation windfalls.

Six months ended June 30, 2024 as compared to six months ended June 30, 2023

Lease operating expenses. LOE increased $23.9 million to $335.9 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023. Our expanded operations after the Arrangement contributed $22.9 million of additional LOE period over period. Excluding the impacts of the Arrangement, LOE was relatively consistent period over period. LOE per Boe decreased $0.50 per Boe period over period to $9.83 per Boe for the six months ended June 30, 2024 primarily due to higher production volumes.

Gathering, processing and transportation expenses. GPT expenses increased $36.7 million to $117.1 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023. Our expanded operations after the Arrangement contributed $10.7 million of additional GPT period over period. Excluding the impacts of the Arrangement, GPT increased $26.0 million primarily due to an increased loss attributable to the change in fair value of certain derivative transportation contracts period over period of $24.2 million. GPT expenses per Boe increased $0.77 per Boe period over period to $3.43 per Boe for the six months ended June 30, 2024 due to the increases described above.

Purchased oil and gas expenses. Purchased oil and gas expenses increased $346.3 million to $692.1 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023 primarily due to an increase in the volume of crude oil purchased and subsequently sold period over period.

Production taxes. Production taxes increased $24.4 million to $143.4 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023. Our expanded operations after the Arrangement contributed $11.0 million of additional production taxes period over period. Excluding the impacts of the Arrangement, production taxes increased $13.4 million primarily due to an increase in crude oil revenues period over period. The production tax rate as a percentage of crude oil, NGL and natural gas sales increased to 8.7% for the six months ended June 30, 2024 as compared to 8.1% for the six months ended June 30, 2023. This rate increase period over period was primarily due to a decrease in natural gas revenue as a result of lower realized prices.

Depreciation, depletion and amortization. DD&A expense increased $126.0 million to $396.8 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023. Our expanded operations after the Arrangement contributed $40.4 million of additional DD&A period over period. Excluding the impacts of the Arrangement, DD&A expense increased $77.6 million primarily due to an increased depletion rate period over period driven by the addition of oil and gas properties acquired in the Arrangement and the 2023 acquisition of acreage in the Williston Basin coupled with a decrease in reserves as a result of lower commodity prices. DD&A expense increased an additional $8.0 million due to higher production volumes. The depletion rate increased $2.61 per Boe period over period to $11.29 per Boe for the six months ended June 30, 2024.

General and administrative expenses. G&A expenses increased $33.1 million to $107.8 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023. Our expanded operations after the Arrangement contributed $66.9 million of additional G&A expense period over period, including merger-related costs of $62.8 million and other G&A expenses of $4.1 million. Excluding the impacts of the Arrangement, G&A expenses decreased $33.8 million primarily due to a decrease in stock-based compensation costs of $17.0 million due to the vesting of certain equity-based compensation awards in the first half of 2024 as well as higher credits related to billable overhead of $12.7 million.

Exploration and impairment. Exploration and impairment expenses decreased $24.0 million to $7.6 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023. During the six months ended June 30, 2024, we recorded an impairment charge of $3.9 million associated with a lower of cost or net realizable value write down of oil-in-tank inventory, coupled with $3.7 million of exploration expenses. During the six months ended June 30, 2023, exploration and impairment expenses totaled $31.6 million, which was primarily due to impairment expenses of $29.0 million, including $17.5 million associated with the write-down of the right-of-use asset for our Denver office lease acquired in 2022, $5.8 million associated with a lower of cost or net realizable value write down of oil-in-tank inventory and $5.6 million to adjust the carrying value of non-core properties held for sale to their estimated fair value less costs to sell.

Gain on sale of assets, net. During the six months ended June 30, 2024 and 2023, we recorded a net gain on sale of assets of $16.8 million and $2.8 million, respectively, primarily related to the divestitures of certain non-operated properties within each period.

Derivative instruments. We recorded a $23.0 million net loss on derivative instruments for the six months ended June 30, 2024, which was comprised of a net loss of $27.0 million associated with our contracts to manage commodity price risk, partially offset by an unrealized gain of $4.0 million associated with a contract that includes contingent consideration. The net loss of $27.0 million on commodity derivative contracts included an unrealized loss of $21.7 million related to the change in fair value of our commodity derivative contracts and a realized loss of $5.3 million on settled commodity derivative contracts. During the six months ended June 30, 2023, we recorded a $96.5 million net gain on derivative instruments, which was primarily due to a net gain of $95.6 million associated with our contracts to manage commodity price risk. This net gain of $95.6 million on commodity derivative contracts included an unrealized gain of $238.7 million related to the change in fair value of our commodity derivative contracts, partially offset by a realized loss of $143.1 million on settled commodity derivative contracts.

Investment in unconsolidated affiliate. We recorded a $22.2 million gain related to our investment in Energy Transfer for the six months ended June 30, 2024, which included an unrealized gain of $17.6 million as a result of an increase in the fair value of the investment during the period, coupled with a gain of $4.6 million for cash distributions received from Energy Transfer during the period. During the six months ended June 30, 2023, we recorded a gain of $7.9 million related to our investment in Energy Transfer, which included a gain of $6.0 million for cash distributions received from Energy Transfer during the period, coupled with an unrealized gain of $1.1 million as a result of an increase in the fair value of the investment during the period.

Income tax expense. Our effective tax rate for the six months ended June 30, 2024 was recorded at 24.7% of pre-tax income which was materially unchanged compared to 23.9% of pre-tax income for the six months ended June 30, 2023.

Liquidity and Capital Resources

As of June 30, 2024, we had $1.1 billion of liquidity available, including $197.4 million in cash and cash equivalents and $894.8 million of aggregate unused borrowing capacity available under our Credit Facility (defined below). Our primary sources of liquidity were from cash on hand, cash flows from operations and available borrowing capacity under our Credit Facility. Our primary liquidity requirements were capital expenditures for the development of oil and gas properties, dividend payments, debt repayments, share repurchases, cash consideration and transaction costs associated with the Arrangement, and working capital requirements.

Capital availability will be affected by prevailing conditions in our industry, the global economy, the global banking and financial markets, stakeholder scrutiny of ESG matters and other factors, many of which are beyond our control. The U.S. Federal Reserve’s increases in interest rates and the potential for such rates to increase further or to remain elevated for an extended period of time have created additional economic uncertainty. Although we are unable to predict future interest rates, this disruption to the broader economy and financial markets may reduce our ability to access capital or result in such capital being available on less favorable terms, which could in the future negatively affect our liquidity. We believe, however, we have adequate liquidity to fund our capital expenditures and meet our contractual obligations during the next 12 months and the foreseeable future.

Our cash flows depend on many factors, including the price of crude oil, NGLs and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the impact of changes in crude oil, NGL and natural gas prices on our production, which mitigates our exposure to crude oil, NGL and natural gas price declines; however, these transactions may also limit our cash flow in periods of rising crude oil, NGL and natural gas prices.

Enerplus Arrangement. In connection with the consummation of the Arrangement on May 31, 2024, we paid $375.8 million, or $1.84 per Enerplus common share, to Enerplus shareholders. In addition, we paid $395.0 million to settle Enerplus’ revolving bank credit facility balance and $102.4 million to settle all outstanding Enerplus equity-based compensation awards.

In connection with the Arrangement, we incurred certain costs for advisory, legal and other third-party fees which were recorded to G&A expenses on the Condensed Consolidated Statements of Operations. During the three and six months ended June 30, 2024, we incurred merger-related costs of $54.7 million and $62.8 million, respectively, primarily related to legal and advisory services and severance costs.

Commodity derivative contracts. As of June 30, 2024, our commodity derivative contracts cover 4,692 MBbls of our crude oil production for 2024, 5,377 MBbls of our crude oil production and 4,301,600 MMBtu of our natural gas production for 2025 and 1,175 MBbls of our crude oil production for 2026. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk” for additional information.

In July 2024, we entered into new commodity derivative contracts to manage risks related to changes in crude oil prices. The following table summarizes these commodity derivative contracts:

We also have contracts which include provisions for the delivery, transport or purchase of a minimum volume of crude oil, NGLs, natural gas and water within specified time frames, the majority of which are five years or less. Under the terms of these contracts, if we fail to deliver, transport or purchase the committed volumes we will be required to pay a deficiency payment for the volumes not tendered over the duration of the contract. We believe that for the substantial majority of these agreements our future production will be adequate to meet our delivery commitments or that we will be able to purchase sufficient volumes of crude oil, NGLs and natural gas from third parties to satisfy our minimum volume commitments. See “Item 1. Financial Statements (Unaudited)—Note 17—Commitments and Contingencies” for additional information on our volume delivery commitments.

Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations related to our long-term debt, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, payment of income taxes, obligations associated with outstanding commodity derivative contracts that settle in a loss position, obligations to pay dividends on vested equity awards that include dividend equivalent rights and obligations associated with our leases. In addition, we have announced a return of capital plan pursuant to which we intend to return capital to stockholders through a mix of base and variable dividend payouts, supplemented by opportunistic share repurchases. On a quarterly basis, we pay a commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.

Revolving credit facility. We have a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $3.0 billion and elected commitments of $1.5 billion that is due July 1, 2027. As of June 30, 2024, we had $575.0 million borrowings outstanding and $30.2 million of outstanding letters of credit, resulting in an unused borrowing capacity of $894.8 million. Additionally, we are permitted to incur term loans in addition to the revolving loans provided under the Credit Facility. We were in compliance with the financial covenants under the Credit Facility as of June 30, 2024. See “Item 1. Financial Statements (Unaudited)—Note 11—Long-Term Debt” for additional information.

Senior unsecured notes. As of June 30, 2024, we had $400.0 million of 6.375% senior unsecured notes outstanding (the “Senior Notes”) that mature on June 1, 2026. Interest on the Senior Notes is payable semi-annually on June 1 and December 1 of each year. See “Item 1. Financial Statements (Unaudited)—Note 11—Long-Term Debt” for additional information.

Enerplus senior unsecured notes. In connection with the Arrangement on May 31, 2024, we assumed $63.0 million of 3.79% senior unsecured notes from Enerplus with a fair value of $60.1 million (the “Enerplus Senior Notes”). On July 2, 2024, we repaid all of the remaining outstanding Enerplus Senior Notes and $0.8 million of accrued interest on such notes.

Cash Flows

Our cash flows for the six months ended June 30, 2024 and 2023 are presented below:

(In thousands)

Cash flows provided by operating activities

Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, operating costs and G&A expenses. Net cash provided by operating activities was $867.6 million for the six months ended June 30, 2024. The decrease in net cash provided by operating activities of $9.5 million as compared to the six months ended June 30, 2023 was primarily due to increases in merger-related costs, production taxes and LOE as well as changes in our working capital, partially offset by an increase in oil revenues. See “Results of Operations” above for additional information.

Working Capital. Our working capital is primarily impacted by the factors discussed above, coupled with the timing of cash receipts and disbursements. Changes in working capital (as reflected in the Condensed Consolidated Statements of Cash Flows) decreased net cash flows from operating activities by $18.1 million and $2.4 million during the six months ended June 30, 2024 and 2023, respectively. Changes in working capital associated with our capital expenditure activities and settlement of outstanding commodity derivative instruments impact our cash flows from investing activities.

The Credit Facility includes a requirement that we maintain a Current Ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter. For purposes of the Current Ratio, the Credit Facility’s definition of total current assets includes unused commitments under the Credit Facility, which were $894.8 million as of June 30, 2024, and excludes current hedge assets, which were $25.3 million as of June 30, 2024. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, which were $13.9 million as of June 30, 2024.

Cash flows used in investing activities

For the six months ended June 30, 2024, net cash used in investing activities of $1,150.6 million was primarily attributable to the Arrangement, including $395.0 million paid to settle Enerplus’ revolving bank credit facility balance, $375.8 million paid to Enerplus shareholders and $102.4 million paid to settle Enerplus’ equity awards, partially offset by cash acquired in the Arrangement of $239.9 million. Net cash used in investing activities during the six months ended June 30, 2024 also included capital expenditures of $538.7 million incurred to develop our oil and gas properties, partially offset by the receipt of the 2023 contingent consideration earn-out payment of $25.0 million and proceeds from divestitures of $20.9 million. Net cash used in investing activities for the six months ended June 30, 2023 of $858.3 million was primarily attributable to capital expenditures of $407.8 million, $361.6 million paid for the 2023 acquisition of acreage in the Williston Basin and $154.1 million associated with the settlement of derivative contracts.

Cash flows provided by (used in) financing activities

For the six months ended June 30, 2024, net cash provided by financing activities of $162.4 million was primarily attributable to borrowings under the credit facility of $575.0 million, net of repayments of $250.0 million, in connection with the Arrangement and proceeds of $21.0 million from the exercise of outstanding warrants, partially offset by dividends paid to shareholders of $281.7 million, payments of $93.7 million to repurchase our common stock and income tax withholding on vested equity-based compensation awards of $57.4 million. Net cash used in financing activities for the six months ended June 30, 2023 of $397.1 million was primarily attributable to dividends paid to shareholders of $337.7 million, payments of $45.8 million to repurchase our common stock and payments of $13.6 million for income tax withholdings on vested equity-based compensation awards.

Capital Expenditures

Expenditures for the acquisition and development of oil and gas properties are the primary use of our capital resources. Our capital expenditures are summarized in the following table:

(In thousands)

(1) Other capital expenditures include items such as infrastructure capital, administrative capital and capitalized interest. Capitalized interest totaled $1.2 million and $1.9 million for the three and six months ended June 30, 2024, respectively.

(2) Total capital expenditures for the three and six months ended June 30, 2024 include approximately $16.1 million and $20.0 million, respectively, related to non-operated divested assets that are expected to be reimbursed.

(3) Excludes amounts attributable to the Arrangement including cash consideration of $375.8 million.

(4) Total capital expenditures reflected in the table above differs from the amounts shown in the statements of cash flows in our unaudited condensed consolidated financial statements because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis.

Dividends

On August 7, 2024, we declared a base-plus-variable cash dividend of $2.52 per share of common stock. The dividend will be payable on September 5, 2024 to shareholders of record as of August 21, 2024. See “Item 1. Financial Statements (Unaudited)—Note 15—Stockholders’ Equity” for additional information.

See “Part II. Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Return of Capital Plan” in our 2023 Annual Report for additional information regarding our strategy on future dividend payments. Future dividend payments will depend on the Company’s earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that the Board of Directors deems relevant.

Share Repurchase Program

During the six months ended June 30, 2024, we repurchased 558,579 shares of common stock at a weighted average price of $164.23 per common share for a total cost of $91.7 million, under our $750 million share repurchase program. As of June 30, 2024, there was $591.3 million of capacity remaining under our $750 million share repurchase program.

We repurchased 319,458 shares of common stock during the six months ended June 30, 2023 under the previous share repurchase program, which was replaced by our current $750 million share repurchase program.

Fair Value of Financial Instruments

See “Item 1. Financial Statements (Unaudited)—Note 5—Fair Value Measurements” for additional information on our derivative instruments and their related fair value measurements. See also “Item 3. Quantitative and Qualitative Disclosures about Market Risk” below.

Critical Accounting Policies and Estimates

There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2023 Annual Report, except as follows.

Business combinations. We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred.

We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions in the Arrangement relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of crude oil, NGL and natural gas properties within the same regions, and use that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties. Different techniques may be used to determine fair values, including market prices (where available), comparisons to transactions for similar assets and liabilities and present values of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.

Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill and is subject to ongoing impairment evaluation as described in Item 1. Financial Statements (Unaudited)—Note 1—Organization and Summary of Significant Accounting Policies—Goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

We are exposed to a variety of market risks, including commodity price risk, interest rate risk, counterparty and customer risk and inflation risk. We address these risks through a program of risk management, including the use of derivative instruments.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in crude oil, NGL and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk derivative instruments were entered into for hedging purposes, rather than for speculative trading. The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2023 Annual Report, as well as with the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

Commodity price exposure risk. We are exposed to market risk as the prices of crude oil, NGLs and natural gas fluctuate as a result of a variety of factors, including changes in supply and demand and the macroeconomic environment, all of which are typically beyond our control. The markets for crude oil, NGLs and natural gas have been volatile, especially over the last several years, and these prices will likely continue to be volatile in the future. To partially reduce price risk caused by these market fluctuations, we have entered into derivative instruments in the past and expect to enter into derivative instruments in the future to cover a portion of our future production. In addition, entering into derivative instruments could limit the benefit we would receive from increases in the prices for crude oil, NGLs and natural gas. We recognize all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on our unaudited condensed consolidated balance sheets. Derivative assets and liabilities arising from our derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement. See “Item 1. Financial Statements (Unaudited)—Note 5—Fair Value Measurements” and “Note 6—Derivative Instruments” for additional information regarding our derivative instruments.

The fair value of our unrealized crude oil derivative positions at June 30, 2024 was a net liability position of $15.0 million. A 10% increase in crude oil prices would increase the fair value of this unrealized derivative liability position by approximately $53.2 million, while a 10% decrease in crude oil prices would decrease the fair value of this unrealized derivative liability position by approximately $45.4 million. The fair value of our unrealized natural gas derivative positions at June 30, 2024 was a net asset position of $1.2 million. A 10% increase in natural gas prices would decrease the fair value of this unrealized derivative asset position by approximately $1.4 million, while a 10% decrease in natural gas prices would increase the fair value of this unrealized derivative asset position by approximately $1.4 million. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Market Conditions and Commodity Prices,” for further discussion on the commodity price environment. See “Item 1. Financial Statements (Unaudited)—Note 6—Derivative Instruments” for additional information regarding our derivative instruments.

In addition, in connection with the 2021 divestiture of oil and gas properties in the Texas region of in the Permian Basin, we are entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI crude oil exceeds $60 per barrel for such year. If the NYMEX WTI crude oil price for calendar year 2023 or 2024 is less than $45 per barrel, then each calendar year thereafter our right to receive any remaining earn-out payments is terminated. As of June 30, 2024, the fair value of this contingent consideration was $46.7 million. During the six months ended June 30, 2024, we received $25.0 million related to the 2023 earn-out payment. See “Item 1. Financial Statements (Unaudited)—Note 6—Derivative Instruments” for additional information.

Interest rate risk. At June 30, 2024, we had $400.0 million of senior unsecured notes at a fixed interest rate of 6.375% per annum and $63.0 million of senior unsecured notes at a fixed interest rate of 3.79% per annum. At June 30, 2024, we had $575.0 million borrowings and $30.2 million of outstanding letters of credit issued under the Credit Facility. Borrowings under the Credit Facility are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a Term SOFR Loan or an ABR Loan (each as defined in the Credit Facility). See “Item 1. Financial Statements (Unaudited)—Note 11—Long-Term Debt” for additional information on the interest incurred on the Credit Facility.

We do not currently, but may in the future, utilize interest rate derivatives to mitigate interest rate exposure in an attempt to reduce interest rate expense related to debt issued under the Credit Facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. For the three and six months ended June 30, 2024, our credit losses on joint interest receivables were immaterial. We are also subject to credit risk due to the concentration of our crude oil, NGL and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial position and related financial results.

We monitor our exposure to counterparties on crude oil, NGL and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to secure crude oil, NGL and natural gas sales receivables owed to us. Historically, our credit losses on crude oil, NGL and natural gas sales receivables have been immaterial.

In addition, our crude oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. However, in order to mitigate the risk of nonperformance, we only enter into derivative contracts with counterparties that are high credit-quality financial institutions. All of the counterparties on our derivative instruments currently in place are lenders under the Credit Facility with investment grade ratings. We are likely to enter into any future derivative instruments with these or other lenders under the Credit Facility, which also carry investment grade ratings. This risk is also managed by spreading our derivative exposure across several institutions and limiting the volumes placed under individual contracts. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting provisions. As a result of these netting provisions, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts.

Evaluation of disclosure controls and procedures

As required by Rule 13a-15(b) of the Exchange Act, management, under the supervision and with the participation of our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our principal financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2024. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, 2024.

On May 31, 2024, we completed the Arrangement. Management’s assessment and conclusion on the effectiveness of our internal control over financial reporting as of June 30, 2024 excludes an assessment of the internal control over financial reporting of Enerplus.

Changes in internal control over financial reporting

On May 31, 2024, we completed the Arrangement. As part of the ongoing integration, we are in the process of incorporating the controls and related procedures of Enerplus. Other than incorporating Enerplus’ controls, there were no changes in internal control over financial reporting that occurred during the quarter ended June 30, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position, results of operations or cash flows. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

For a discussion of our potential risks and uncertainties, see the information in “Part I. Item 1A. Risk Factors” in our 2023 Annual Report. There have been no material changes in our risk factors from those described in our 2023 Annual Report, except as described below.

The SEC’s Final Rules on The Enhancement and Standardization of Climate-Related Disclosures could result in increased compliance risks and costs.

The SEC released its final rule on climate-related disclosures on March 6, 2024, requiring the disclosure of certain climate-related risks, management and governance practices, and financial impacts, as well as greenhouse gas emissions. Large accelerated filers will be required to incorporate the applicable climate-related disclosures into their filings beginning in fiscal year 2025, with additional requirements relating to the disclosure of Scope 1 and 2 greenhouse gas emissions, if material, and attestation reports for certain large accelerated filers subsequently phasing in. Refer to “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” in our 2023 Annual Report for prior discussion of the SEC’s then-proposed rule. While we are still assessing our obligations under the rule, complying with such obligations may result in increased costs and SEC or investor scrutiny of our disclosures. The SEC has paused implementation of the final rule pending the resolution of consolidated legal challenges that are currently proceeding before the U.S. Court of Appeals for the Eighth Circuit. The outcome of this litigation may reduce or expand our obligations under the final rule.