EQT Corp (EQT) FY 2023 MD&A
This page reproduces the company's own Item 7 MD&A text from the linked SEC filing. It is filer text, not grepcent analysis, scoring, or investment advice.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of financial condition and results of operations should be read in conjunction with the Consolidated Financial Statements and the notes thereto included in Item 8., "Financial Statements and Supplementary Data."
Consolidated Results of Operations
Net income attributable to EQT Corporation for 2023 was $1,735 million, $4.22 per diluted share, compared to $1,771 million, $4.38 per diluted share, for 2022. The decrease was attributable primarily to decreased sales of natural gas, NGLs and oil, partly offset by a gain on derivatives in 2023 compared to a loss on derivatives in 2022, impairment of the contract asset (discussed in Note 5 to the Consolidated Financial Statements) in 2022, decreased income tax expense and a loss on debt extinguishment in 2022.
See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on Form 10-K for the year ended December 31, 2022, which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year ended December 31, 2021.
Results of operations for the period beginning August 22, 2023 through December 31, 2023 include the results of our operation of assets acquired in the Tug Hill and XcL Midstream Acquisition. See Note 6 to the Consolidated Financial Statements for further discussion of the Tug Hill and XcL Midstream Acquisition.
See "Sales Volume and Revenues" and "Operating Expenses" for discussions of items affecting operating income and "Other Income Statement Items" for a discussion of other income statement items. See "Investing Activities" under "Capital Resources and Liquidity" for a discussion of capital expenditures.
Trends and Uncertainties
Our sales volume and operating expenses on a per Mcfe basis during the first half of 2023 were negatively impacted by fewer wells turned-in-line during 2022 compared to our 2022 planned development schedule due to third-party supply chain constraints. In addition, as a result of third-party supply chain constraints in 2022, we shifted the planned development of approximately 30 wells from 2022 to 2023 (the Rescheduled Wells). All of the Rescheduled Wells were completed and turned-to-sales as of July 2023, resulting in our third quarter 2023 sales volumes returning to our normalized level of production; however, our sales volume during the second half of 2023 was negatively impacted by approximately 13 Bcfe of curtailments (inclusive of non-operated wells in which we have a working interest) principally in response to lower natural gas prices in the Appalachian Basin. Future supply chain constraints or declines in natural gas prices may result in adjustments to our 2024 planned development schedule or the development schedule of non-operated wells in which we have a working interest. Further, we cannot control or otherwise influence the development schedule of non-operated wells in which we have a working interest. Adjustments to our 2024 planned development schedule or the development schedule of non-operated wells in which we have a working interest, including due to declines in natural gas prices, the pace of well completions, access to sand and water to conduct drilling operations, access to sufficient pipeline takeaway capacity, unscheduled downtime at processing facilities or otherwise, could impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.
The annual inflation rate in the United States increased rapidly during 2022, and, although the inflation rate decreased through 2023, it still remains elevated compared to the rate of inflation over the prior five years. Inflationary pressures have multiple impacts on our business, including increasing our operating expenses and our cost of capital. While the prices for certain of the raw materials and services we use in our operations have generally decreased from the peak prices experienced during 2022, we will not fully realize the benefit of such reduced prices until we enter into new contracts for such materials and services, and inflationary pressures may cause prices to fluctuate. Additionally, certain of our commitments for demand charges under our existing long-term contracts and processing capacity are subject to consumer price index adjustments. Although we believe our scale and supply chain contracting strategy of using multi-year sand and frac crew contracts allows us to maximize capital and operating efficiencies, future increases in the inflation rate will negatively impact our long-term contracts with consumer price index adjustments.
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While the prices for natural gas, NGLs and oil have historically been volatile, price volatility was especially pronounced during 2022, with natural gas prices peaking in August 2022, then steadily declining into the first half of 2023. The second half of 2023 saw moderate increases in natural gas prices; however, on average, prices in 2023 remained lower than in 2022. We expect commodity prices to be volatile throughout 2024 due to macroeconomic uncertainty and geopolitical tensions, including developments pertaining to Russia's invasion of Ukraine and conflicts in the Middle East. Our revenue, profitability, liquidity and financial position will continue to be impacted in the future by the market prices for natural gas and, to a lesser extent, NGLs and oil.
Additionally, after several years of delays, in the third quarter of 2023, Equitrans Midstream resumed forward construction of the Mountain Valley Pipeline following the approval of federal legislation ratifying and approving all permits and authorizations necessary for the construction and initial operation of the project. The fee structure and various conditions precedent specified in certain of our agreements with Equitrans Midstream, including but not limited to the Consolidated GGA, are tied to the date on which the Mountain Valley Pipeline is placed in service. As a result, the timing of the date on which the Mountain Valley Pipeline is ultimately placed in service, which is outside of our control, could impact our operating results during 2024, including our operating expenses and per unit metrics, average differential and any payments required to settle the Henry Hub Cash Bonus (defined and described in Note 3 to the Consolidated Financial Statements), if required.
Average Realized Price Reconciliation
The following table presents detailed natural gas and liquids operational information to assist in the understanding of our consolidated operations, including the calculation of our average realized price ($/Mcfe), which is based on adjusted operating revenues, a non-GAAP supplemental financial measure. Adjusted operating revenues is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends. Adjusted operating revenues should not be considered as an alternative to total operating revenues. See "Non-GAAP Financial Measures Reconciliation" for a reconciliation of adjusted operating revenues with total operating revenues, the most directly comparable financial measure calculated in accordance with GAAP.
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| Years Ended December 31, | ||||||
|---|---|---|---|---|---|---|
| 2023 | 2022 | |||||
| (Thousands, unless otherwise noted) | ||||||
| NATURAL GAS | ||||||
| Sales volume (MMcf) | 1,907,343 | 1,842,044 | ||||
| NYMEX price ($/MMBtu) | $ | 2.74 | $ | 6.64 | ||
| Btu uplift | 0.14 | 0.35 | ||||
| Natural gas price ($/Mcf) | $ | 2.88 | $ | 6.99 | ||
| Basis ($/Mcf) (a) | $ | (0.51) | $ | (0.77) | ||
| Cash settled basis swaps ($/Mcf) | (0.03) | (0.02) | ||||
| Average differential, including cash settled basis swaps ($/Mcf) | $ | (0.54) | $ | (0.79) | ||
| Average adjusted price ($/Mcf) | $ | 2.34 | $ | 6.20 | ||
| Cash settled derivatives ($/Mcf) | 0.34 | (3.20) | ||||
| Average natural gas price, including cash settled derivatives ($/Mcf) | $ | 2.68 | $ | 3.00 | ||
| Natural gas sales, including cash settled derivatives | $ | 5,112,278 | $ | 5,529,963 | ||
| LIQUIDS | ||||||
| NGLs, excluding ethane: | ||||||
| Sales volume (MMcfe) (b) | 64,859 | 56,735 | ||||
| Sales volume (Mbbl) | 10,810 | 9,456 | ||||
| NGLs price ($/Bbl) | $ | 36.39 | $ | 53.26 | ||
| Cash settled derivatives ($/Bbl) | (1.27) | (3.91) | ||||
| Average NGLs price, including cash settled derivatives ($/Bbl) | $ | 35.12 | $ | 49.35 | ||
| NGLs sales, including cash settled derivatives | $ | 379,663 | $ | 466,664 | ||
| Ethane: | ||||||
| Sales volume (MMcfe) (b) | 34,441 | 35,100 | ||||
| Sales volume (Mbbl) | 5,740 | 5,850 | ||||
| Ethane price ($/Bbl) | $ | 6.00 | $ | 14.20 | ||
| Ethane sales | $ | 34,417 | $ | 83,096 | ||
| Oil: | ||||||
| Sales volume (MMcfe) (b) | 9,630 | 6,164 | ||||
| Sales volume (Mbbl) | 1,605 | 1,027 | ||||
| Oil price ($/Bbl) | $ | 59.93 | $ | 77.06 | ||
| Oil sales | $ | 96,191 | $ | 79,160 | ||
| Total liquids sales volume (MMcfe) (b) | 108,930 | 97,999 | ||||
| Total liquids sales volume (Mbbl) | 18,155 | 16,333 | ||||
| Total liquids sales | $ | 510,271 | $ | 628,920 | ||
| TOTAL | ||||||
| Total natural gas and liquids sales, including cash settled derivatives (c) | $ | 5,622,549 | $ | 6,158,883 | ||
| Total sales volume (MMcfe) | 2,016,273 | 1,940,043 | ||||
| Average realized price ($/Mcfe) | $ | 2.79 | $ | 3.17 |
(a)Basis represents the difference between the ultimate sales price for natural gas, including the effects of delivered price benefit or deficit associated with our firm transportation agreements, and the NYMEX natural gas price.
(b)NGLs, ethane and oil were converted to Mcfe at a rate of six Mcfe per barrel.
(c)Total natural gas and liquids sales, including cash settled derivatives, is also referred to in this report as adjusted operating revenues, a non-GAAP supplemental financial measure.
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Non-GAAP Financial Measures Reconciliation
The table below reconciles adjusted operating revenues, a non-GAAP supplemental financial measure, with total operating revenues, its most directly comparable financial measure calculated in accordance with GAAP. Adjusted operating revenues (also referred to in this report as total natural gas and liquids sales, including cash settled derivatives) is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends. Adjusted operating revenues excludes the revenue impacts of changes in the fair value of derivative instruments prior to settlement and net marketing services and other. We use adjusted operating revenues to evaluate earnings trends because, as a result of the measure's exclusion of the often-volatile changes in the fair value of derivative instruments prior to settlement, the measure reflects only the impact of settled derivative contracts. Net marketing services and other consists of the costs of, and recoveries on, pipeline capacity releases, revenues for gathering and processing services provided to third parties and other revenues. Because we consider net marketing services and other to be unrelated to our natural gas and liquids production activities, adjusted operating revenues excludes net marketing services and other. We believe that adjusted operating revenues provides useful information to investors for evaluating period-to-period comparisons of earnings trends.
| Years Ended December 31, | ||||||
|---|---|---|---|---|---|---|
| 2023 | 2022 | |||||
| (Thousands, unless otherwise noted) | ||||||
| Total operating revenues | $ | 6,908,923 | $ | 7,497,689 | ||
| (Deduct) add: | ||||||
| (Gain) loss on derivatives | (1,838,941) | 4,642,932 | ||||
| Net cash settlements received (paid) on derivatives | 900,650 | (5,927,698) | ||||
| Premiums paid for derivatives that settled during the period | (322,869) | (27,587) | ||||
| Net marketing services and other | (25,214) | (26,453) | ||||
| Adjusted operating revenues, a non-GAAP financial measure | $ | 5,622,549 | $ | 6,158,883 | ||
| Total sales volume (MMcfe) | 2,016,273 | 1,940,043 | ||||
| Average realized price ($/Mcfe) | $ | 2.79 | $ | 3.17 |
Sales Volume and Revenues
| Years Ended December 31, | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2023 | 2022 | Change | % Change | ||||||||||
| (Thousands, unless otherwise noted) | |||||||||||||
| Sales volume (MMcfe) | 2,016,273 | 1,940,043 | 76,230 | 3.9 | |||||||||
| Average daily sales volume (MMcfe/d) | 5,524 | 5,315 | 209 | 3.9 | |||||||||
| Operating revenues: | |||||||||||||
| Sales of natural gas, NGLs and oil | $ | 5,044,768 | $ | 12,114,168 | $ | (7,069,400) | (58.4) | ||||||
| Gain (loss) on derivatives | 1,838,941 | (4,642,932) | 6,481,873 | (139.6) | |||||||||
| Net marketing services and other | 25,214 | 26,453 | (1,239) | (4.7) | |||||||||
| Total operating revenues | $ | 6,908,923 | $ | 7,497,689 | $ | (588,766) | (7.9) |
Sales of natural gas, NGLs and oil. Sales of natural gas, NGLs and oil decreased for 2023 compared to 2022 due to lower average realized price, partly offset by increased sales volume.
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Average realized price decreased for 2023 compared to 2022 due to lower NYMEX and liquids prices, partly offset by favorable cash settled derivatives and favorable differential. The following table presents the composition of net cash settlements that we received (paid) on derivatives.
| Years Ended December 31, | ||||||
|---|---|---|---|---|---|---|
| 2023 | 2022 | |||||
| (Thousands) | ||||||
| Net cash settlements received (paid) on NYMEX natural gas hedge positions | $ | 976,432 | $ | (5,855,959) | ||
| Net cash settlements paid on basis and liquids hedge positions | (75,782) | (71,739) | ||||
| Net cash settlements received (paid) on derivatives | $ | 900,650 | $ | (5,927,698) |
Net cash settlements received (paid) on derivatives are included in average realized price but may not be included in operating revenues.
For 2023 and 2022, we paid premiums for derivatives that settled during the period of $322.9 million and $27.6 million, respectively.
Sales volume increased for 2023 compared to 2022 due to sales volume increases of 90 Bcfe from the assets acquired in the Tug Hill and XcL Midstream Acquisition, partly offset by sales volume decreases from the natural decline of producing wells and fewer wells turned-in-line during 2022 as a result of third-party supply chain constraints and delays in the development schedule of certain non-operated wells in which we have a working interest.
Gain (loss) on derivatives. For 2023, we recognized a gain on derivatives of $1,838.9 million related primarily to increases in the fair market value of our NYMEX swaps and options due to decreases in NYMEX forward prices, partly offset by a loss on the derivative liability related to the Henry Hub Cash Bonus. For 2022, we recognized a loss on derivatives of $4,642.9 million related primarily to decreases in the fair market value of our NYMEX swaps and options due to increases in NYMEX forward prices, partly offset by a gain on the derivative liability related to the Henry Hub Cash Bonus.
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Operating Expenses
| Years Ended December 31, | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2023 | 2022 | Change | % Change | ||||||||||
| (Thousands, unless otherwise noted) | |||||||||||||
| Operating expenses: | |||||||||||||
| Gathering | $ | 1,282,402 | $ | 1,316,213 | $ | (33,811) | (2.6) | ||||||
| Transmission | 642,688 | 601,497 | 41,191 | 6.8 | |||||||||
| Processing | 232,170 | 199,266 | 32,904 | 16.5 | |||||||||
| Lease operating expenses (LOE) | 158,973 | 156,523 | 2,450 | 1.6 | |||||||||
| Production taxes | 95,727 | 144,462 | (48,735) | (33.7) | |||||||||
| Exploration | 3,330 | 3,438 | (108) | (3.1) | |||||||||
| Selling, general and administrative | 236,171 | 252,645 | (16,474) | (6.5) | |||||||||
| Production depletion | $ | 1,702,198 | $ | 1,644,625 | $ | 57,573 | 3.5 | ||||||
| Other depreciation and depletion | 29,944 | 21,337 | 8,607 | 40.3 | |||||||||
| Total depreciation and depletion | $ | 1,732,142 | $ | 1,665,962 | $ | 66,180 | 4.0 | ||||||
| Per Unit ($/Mcfe): | |||||||||||||
| Gathering | $ | 0.64 | $ | 0.68 | $ | (0.04) | (5.9) | ||||||
| Transmission | 0.32 | 0.31 | 0.01 | 3.2 | |||||||||
| Processing | 0.12 | 0.10 | 0.02 | 20.0 | |||||||||
| LOE | 0.08 | 0.08 | — | — | |||||||||
| Production taxes | 0.05 | 0.07 | (0.02) | (28.6) | |||||||||
| Selling, general and administrative | 0.12 | 0.13 | (0.01) | (7.7) | |||||||||
| Production depletion | 0.84 | 0.85 | (0.01) | (1.2) |
Gathering. Gathering expense decreased on an absolute basis for 2023 compared to 2022 due primarily to lower gathering rates on certain contracts indexed to price. Gathering expense decreased on a per Mcfe basis for 2023 compared to 2022 due primarily to lower gathering rates on certain contracts indexed to price, which decreased in 2023, as well as the impact of the gathering assets acquired in the Tug Hill and XcL Midstream Acquisition, which are wholly owned by us and, therefore, reduce our gathering cost structure.
Transmission. Transmission expense increased on an absolute and per Mcfe basis for 2023 compared to 2022 due primarily to additional capacity acquired, partly offset by increased credits received from the Texas Eastern Transmission Pipeline.
Processing. Processing expense increased on an absolute and per Mcfe basis for 2023 compared to 2022 due primarily to processing expenses for the liquids-rich assets acquired in the Tug Hill and XcL Midstream Acquisition as well as inflation of third-party-contracted processing rates.
LOE. LOE increased on an absolute basis for 2023 compared to 2022 due primarily to increased LOE from the assets acquired in the Tug Hill and XcL Midstream Acquisition, partly offset by lower saltwater disposal costs and increased recycling. Saltwater disposal costs and recycle rates were favorably impacted by increased use of our internally developed produced water gathering and storage system, which was placed in service during the fourth quarter of 2022.
Production taxes. Production taxes decreased on an absolute and per Mcfe basis for 2023 compared to 2022 due to lower West Virginia severance taxes due to lower TETCO M2 price and lower Pennsylvania impact fees due to lower NYMEX price, partly offset by higher West Virginia property taxes due to assets acquired in the Tug Hill and XcL Midstream Acquisition and higher rates.
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Selling, general and administrative. Selling, general and administrative expense decreased on an absolute and per Mcfe basis for 2023 compared to 2022 due primarily to lower long-term incentive compensation costs as a result of decreases in awards outstanding and changes in the fair value of awards. Long-term incentive compensation may fluctuate with changes in our stock price and performance conditions.
Depreciation and depletion. Production depletion expense increased on an absolute basis for 2023 compared to 2022 due to increased sales volume, partly offset by a lower annual depletion rate.
Loss (gain) on sale/exchange of long-lived assets. During 2023, we recognized a loss on sale/exchange of long-lived assets of $17.4 million related to acreage trade agreements where the carrying value of the acres traded exceeded the fair value of the acres received.
Impairment of contract asset. During 2022, we recognized impairment of our contract asset of $214.2 million. See Note 5 to the Consolidated Financial Statements.
Impairment and expiration of leases. During 2023 and 2022, we recognized impairment and expiration of leases of $109.4 million and $176.6 million, respectively, related primarily to leases that we no longer expect to extend or develop prior to their expiration based on our development plan.
Other operating expenses. Other operating expenses increased for 2023 compared to 2022 due primarily to transaction costs associated with the Tug Hill and XcL Midstream Acquisition, partly offset by decreased legal and environmental reserves, including from settlements. See Note 1 to the Consolidated Financial Statements for a summary of other operating expenses.
Other Income Statement Items
(Income) loss from investments. The change in (income) loss from investments was due primarily to a loss on our sale of our investment in Equitrans Midstream in 2022, partly offset by lower equity earnings recognized on our investment in LMM (defined in Note 1 to the Consolidated Financial Statements).
Dividend and other income. Dividend and other income decreased for 2023 compared to 2022 due primarily to lower dividends received on our investment in the Investment Fund (defined in Note 1 to the Consolidated Financial Statements) as well as dividends received on our investment in Equitrans Midstream in 2022.
Loss on debt extinguishment. During 2022, we recognized a loss on debt extinguishment of $140.0 million due to our repayment and repurchase of debt, including our 3.00% notes due October 1, 2022.
Interest expense, net. Interest expense decreased for 2023 compared to 2022 due primarily to higher interest income earned on cash on hand and lower interest expense on lower revolving credit facility borrowings, partly offset by higher interest expense on debt as a result of the August 2023 draw down of the Term Loan Facility (defined and discussed in Note 8 to the Consolidated Financial Statements) and October 2022 senior notes issuances. The higher interest expense on debt was partly offset by our repayment and repurchase of debt disclosed in Note 8 to the Consolidated Financial Statements.
Income tax expense (benefit). See Note 7 to the Consolidated Financial Statements.
See "Critical Accounting Estimates" and Note 1 to the Consolidated Financial Statements for a discussion of our significant accounting policies and assumptions related to accounting for natural gas, NGLs and oil producing activities and impairment of our oil and gas properties. See also Item 1A., "Risk Factors – Natural gas, NGLs and oil price declines, and changes in our development strategy, have resulted in impairment of certain of our assets. Future declines in commodity prices, increases in operating costs or adverse changes in well performance or additional changes in our development strategy may result in additional write-downs of the carrying amounts of our assets, including long-lived intangible assets, which could materially and adversely affect our results of operations in future periods."
Capital Resources and Liquidity
Although we cannot provide any assurance, we believe cash flows from operating activities and availability under our revolving credit facility should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, debt service obligations, planned capital expenditures and commitments for at least the next twelve months and, based on current expectations, for the long term.
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Revolving Credit Facility
We primarily use borrowings under our revolving credit facility to fund working capital needs, timing differences between capital expenditures and other cash uses and cash flows from operating activities, margin deposit requirements on our derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts. See Note 8 to the Consolidated Financial Statements for further discussion of our revolving credit facility.
Known Contractual and Other Obligations; Planned Capital Expenditures
Purchase Obligations. We have commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines, some of which extend up to 20 years or longer. We have entered into agreements to release some of our capacity under these long-term contracts, subject to certain conditions that are currently unsatisfied. We also have commitments for processing capacity in order to extract heavier liquid hydrocarbons from the natural gas stream. In addition, we have commitments to pay for services and materials related to our operations, which primarily include minimum volume commitments to obtain water services and electric hydraulic fracturing services and commitments to purchase equipment, materials and sand. See Note 11 to the Consolidated Financial Statements for further discussion, including details regarding aggregate future payments for these items.
Contractual Commitments. We have contractual commitments under our debt agreements, including interest payments and principal repayments. See Note 8 to the Consolidated Financial Statements for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments.
Unrecognized Tax Benefits. As discussed further in Note 7 to the Consolidated Financial Statements, as of December 31, 2023, we had a total reserve for unrecognized tax benefits of $8.5 million and an additional reserve of $77.0 million that was offset against deferred tax assets for general business tax credit carryforwards and net operating losses (NOLs). We settled our consolidated U.S. federal income tax liability with the IRS through 2017 in January of 2023. We are currently unable to make reasonably reliable estimates of the period of cash settlement of these potential liabilities with taxing authorities.
Planned Capital Expenditures and Sales Volume. In 2024, we expect to spend approximately $2.15 billion to $2.35 billion in total capital expenditures. We expect to fund our capital expenditures with cash generated from operations and, if required, borrowings under our revolving credit facility. Because we are the operator of a high percentage of our developed acreage, the amount and timing of certain of our capital expenditures is largely discretionary. We could choose to defer a portion of our planned 2024 capital expenditures depending on a variety of factors, including prevailing and anticipated prices for natural gas, NGLs and oil; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; and drilling, completion and acquisition costs. In 2024, we expect our sales volume to be 2,200 Bcfe to 2,300 Bcfe.
Operating Activities
Net cash provided by operating activities was $3,179 million and $3,466 million for 2023 and 2022, respectively. The decrease in 2023 compared to 2022 was due primarily to lower cash operating revenues, partly offset by net cash settlements received on derivatives in 2023 compared to net cash settlements paid on derivatives in 2022, favorable changes in working capital driven by declining accounts receivable and lower margin postings.
Our cash flows from operating activities are affected by movements in the market price for commodities. We are unable to predict such movements outside of the current market view as reflected in forward strip pricing. For a discussion of potential commodity market risks, refer to Item 1A., "Risk Factors – Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position."
Investing Activities
Net cash used in investing activities was $4,314 million and $1,422 million for 2023 and 2022, respectively. The increase in 2023 compared to 2022 was attributable primarily to cash paid for the Tug Hill and XcL Midstream Acquisition in 2023 and increased capital expenditures.
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The following table summarizes our capital expenditures.
| Years Ended December 31, | ||||||
|---|---|---|---|---|---|---|
| 2023 | 2022 | |||||
| (Millions) | ||||||
| Reserve development (a) | $ | 1,587 | $ | 1,131 | ||
| Land and lease (b) | 130 | 138 | ||||
| Other production infrastructure | 63 | 82 | ||||
| Midstream | 31 | 6 | ||||
| Capitalized overhead | 60 | 51 | ||||
| Capitalized interest | 41 | 28 | ||||
| Other | 13 | 4 | ||||
| Total capital expenditures | 1,925 | 1,440 | ||||
| Add (deduct): Non-cash items (c) | 94 | (40) | ||||
| Total cash capital expenditures | $ | 2,019 | $ | 1,400 |
(a)Includes capital expenditures for water infrastructure of $35.9 million and $44.5 million for 2023 and 2022, respectively.
(b)Capital expenditures attributable to noncontrolling interests were $8.5 million and $12.8 million for 2023 and 2022, respectively.
(c)Represents the net impact of non-cash capital expenditures, including the effect of timing of receivables from working interest partners, accrued capital expenditures and capitalized share-based compensation costs. The impact of accrued capital expenditures includes the current period estimate, net of the reversal of the prior period accrual.
Financing Activities
Net cash used in financing activities was $243 million and $699 million for 2023 and 2022, respectively. For 2023, the primary uses of financing cash flows were repayment and retirement of debt, payment of dividends and repurchase and retirement of EQT Corporation common stock, and the primary source of financing cash flows was proceeds from the Term Loan Facility borrowings. For 2022, the primary uses of financing cash flows were repayment and retirement of debt, repurchase and retirement of EQT Corporation common stock and payment of dividends, and the primary source of financing cash flows was proceeds from the issuance of debt.
See Note 8 to the Consolidated Financial Statements for further discussion of our debt and borrowings under our revolving credit facility and the Term Loan Facility, including discussion of events that occurred subsequent to December 31, 2023.
On February 8, 2024, our Board of Directors declared a quarterly cash dividend of $0.1575 per share of EQT Corporation common stock, payable on March 1, 2024, to shareholders of record at the close of business on February 20, 2024.
Depending on our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may from time to time seek to redeem or repurchase our outstanding debt or equity securities through tender offers or other cash purchases in the open market or privately negotiated transactions. The amounts involved in any such transactions may be material. See Note 8 to the Consolidated Financial Statements for discussion of redemptions and repurchases of debt and Note 9 to the Consolidated Financial Statements for discussion of repurchases of EQT Corporation common stock.
Security Ratings and Financing Triggers
The table below reflects the credit ratings and rating outlooks assigned to our debt instruments as of December 31, 2023. Our credit ratings and rating outlooks are subject to revision or withdrawal at any time by the assigning rating agency, and each rating should be evaluated independent from any other rating. We cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in the rating agency's judgment, circumstances so warrant. See Note 3 to the Consolidated Financial Statements for a description of what is deemed investment grade.
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| Rating agency | Senior notes | Outlook | ||
|---|---|---|---|---|
| Moody's Investors Service (Moody's) | Baa3 | Stable | ||
| Standard & Poor's Ratings Service (S&P) | BBB– | Stable | ||
| Fitch Ratings Service (Fitch) | BBB– | Stable |
Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our revolving credit facility, the interest rate on the Term Loan Facility and senior notes with adjustable rates, the rates available on new long-term debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts. Margin deposits on our OTC derivative instruments are also subject to factors other than credit rating, such as natural gas prices and credit thresholds set forth in the agreements between us and our hedging counterparties.
Our debt agreements and other financial obligations contain various provisions that, if not complied with, could result in default or event of default under our revolving credit facility and the Term Loan Facility, mandatory partial or full repayment of amounts outstanding, reduced loan capacity or other similar actions. The most significant covenants and events of default under our debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. Our revolving credit facility and the Term Loan Facility contain financial covenants that require us to have a total debt-to-total capitalization ratio no greater than 65%. As of December 31, 2023, we were in compliance with all debt provisions and covenants under our debt agreements.
See Note 8 to the Consolidated Financial Statements for a discussion of borrowings under our revolving credit facility and the Term Loan Facility.
Commodity Risk Management
The substantial majority of our commodity risk management program is related to hedging sales of our produced natural gas. The overall objective of our hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices. The derivative commodity instruments that we use are primarily swap, collar and option agreements. The following table summarizes the approximate volume and prices of our NYMEX hedge positions as of February 9, 2024. The difference between the fixed price and NYMEX price is included in average differential presented in our price reconciliation in "Average Realized Price Reconciliation." The fixed price natural gas sales agreements can be physically or financially settled.
| Q1 2024(a) | Q2 2024 | Q3 2024 | Q4 2024 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Hedged Volume (MMDth) | 283 | 260 | 237 | 127 | ||||||||||
| Hedged Volume (MMDth/d) | 3.1 | 2.9 | 2.6 | 1.4 | ||||||||||
| Swaps – Short | ||||||||||||||
| Volume (MMDth) | 136 | 215 | 192 | 95 | ||||||||||
| Avg. Price ($/Dth) | $ | 3.52 | $ | 3.26 | $ | 3.27 | $ | 3.26 | ||||||
| Calls – Long | ||||||||||||||
| Volume (MMDth) | 13 | 13 | 13 | 13 | ||||||||||
| Avg. Strike ($/Dth) | $ | 3.20 | $ | 3.20 | $ | 3.20 | $ | 3.20 | ||||||
| Calls – Short | ||||||||||||||
| Volume (MMDth) | 162 | 61 | 62 | 46 | ||||||||||
| Avg. Strike ($/Dth) | $ | 6.16 | $ | 4.22 | $ | 4.22 | $ | 4.27 | ||||||
| Puts – Long | ||||||||||||||
| Volume (MMDth) | 147 | 45 | 45 | 32 | ||||||||||
| Avg. Strike ($/Dth) | $ | 4.20 | $ | 4.05 | $ | 4.05 | $ | 4.10 | ||||||
| Option Premiums | ||||||||||||||
| Cash Settlement of Deferred Premiums (millions) | $ | (34) | $ | (4) | $ | (4) | $ | — |
(a)January 1 through March 31.
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We have also entered into derivative instruments to hedge basis. We may use other contractual agreements to implement our commodity hedging strategy from time to time.
See Item 7A., "Quantitative and Qualitative Disclosures About Market Risk" and Note 3 to the Consolidated Financial Statements for further discussion of our hedging program.
Off-Balance Sheet Arrangements
As of December 31, 2023, we did not have any material off-balance sheet arrangements other than the commitments described in Note 11 to the Consolidated Financial Statements.
Commitments and Contingencies
See Note 11 to the Consolidated Financial Statements for a discussion of our commitments and contingencies.
Recently Issued Accounting Standards
Our recently issued accounting standards are described in Note 1 to the Consolidated Financial Statements.
Critical Accounting Estimates
Our significant accounting policies are described in Note 1 to the Consolidated Financial Statements. Management's discussion and analysis of the Consolidated Financial Statements and results of operations are based on our Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of the Consolidated Financial Statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosure of contingent assets and liabilities. The following critical accounting estimates, which were reviewed by the Audit Committee of our Board of Directors (the Audit Committee), relate to our more significant judgments and estimates used in the preparation of our Consolidated Financial Statements. Actual results could differ from our estimates.
Accounting for Gas, NGLs and Oil Producing Activities. We use the successful efforts method of accounting for our oil and gas producing activities. See Note 1 to the Consolidated Financial Statements for a discussion of the fair value measurement and any subsequent impairments of our proved and unproved oil and gas properties and other long-lived assets as well as evaluation of the recoverability of capitalized costs of unproved oil and gas properties.
We believe accounting for natural gas, NGLs and oil producing activities is a "critical accounting estimate" because the evaluations of impairment of proved properties involve significant judgment about future events, such as future sales prices of natural gas and NGLs and future production costs, as well as the amount of natural gas and NGLs recorded and timing of recoveries. Significant changes in these estimates could result in the costs of our proved and unproved properties not being recoverable; therefore, we would be required to recognize impairment. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.
See Note 1 to the Consolidated Financial Statements for additional information on impairments of our proved and unproved oil and gas properties. See also Item 1A., "Risk Factors – Natural gas, NGLs and oil price declines, and changes in our development strategy, have resulted in impairment of certain of our assets. Future declines in commodity prices, increases in operating costs or adverse changes in well performance or additional changes in our development strategy may result in additional write-downs of the carrying amounts of our assets, including long-lived intangible assets, which could materially and adversely affect our results of operations in future periods."
Oil and Gas Reserves. Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10, are those quantities of oil and gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire unless evidence indicates that renewal is reasonably certain regardless of whether deterministic or probabilistic methods are used for the estimation.
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Our estimates of proved reserves are reassessed annually using geological, reservoir and production performance data. Reserve estimates are prepared by our engineers and audited by independent engineers. Revisions may result from changes in, among other things, reservoir performance, development plans, prices, operating costs, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in certain proved reserves due to reaching economic limits sooner. A material change in the estimated volume of reserves could have an impact on the depletion rate calculation and our Consolidated Financial Statements.
We estimate future net cash flows from natural gas, NGLs and oil reserves based on selling prices and costs using a twelve-month average price, which is calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period and, as such, is subject to change in subsequent periods. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Income tax expense is based on currently enacted statutory tax rates and tax deductions and credits available under current laws.
We believe oil and gas reserves is a "critical accounting estimate" because we must periodically reevaluate proved reserves along with estimates of future production rates, production costs and the timing of development expenditures. Future results of operations and the strength of our Consolidated Balance Sheet for any quarterly or annual period could be materially affected by changes in our assumptions. Based on proved reserves as of December 31, 2023, we estimate that a 1% change in proved reserves would decrease or increase 2024 depletion expense by approximately $15 million and $27 million, respectively, based on current production estimates for 2024.
See also Item 1A., "Risk Factors – Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position."
Income Taxes. We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in our Consolidated Financial Statements or tax returns. See Note 1 to the Consolidated Financial Statements for a discussion of significant accounting policies related to income taxes and Note 7 to the Consolidated Financial Statements for a discussion of deferred tax assets, valuation allowances and the amount of financial statement benefit recorded for uncertain tax positions.
We believe income taxes are "critical accounting estimates" because we must assess the likelihood that our deferred tax assets will be recovered from future taxable income and exercise judgment on the amount of financial statement benefit recorded for uncertain tax positions. To the extent that a valuation allowance or uncertain tax position is established or increased or decreased during a period, we record an expense or benefit in income tax expense in our Statements of Consolidated Operations. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. A change to future taxable income or tax planning strategies could impact our ability to utilize deferred tax assets, which would increase or decrease our income tax expense and taxes paid. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.
Derivative Instruments. We enter into derivative commodity instrument contracts primarily to reduce exposure to commodity price risk associated with future sales of our natural gas production. See Note 4 to the Consolidated Financial Statements for a description of the fair value hierarchy. The values reported in the Consolidated Financial Statements change as these estimates are revised to reflect actual results or as market conditions or other factors, many of which are beyond our control, change.
We believe derivative instruments are "critical accounting estimates" because our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments due to the volatility of both NYMEX natural gas prices and basis. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. Refer to Item 7A., "Quantitative and Qualitative Disclosures about Market Risk" for discussion of a hypothetical increase or decrease of 10% in the market price of natural gas.
Business Combinations. Accounting for a business combination requires a company to record the identifiable assets and liabilities acquired at fair value. In the third quarter of 2023, we completed the Tug Hill and XcL Midstream Acquisition, and in the third quarter of 2021, we completed the Alta Acquisition (defined and discussed in Note 6 to the Consolidated Financial Statements). See Note 6 to the Consolidated Financial Statements for a discussion of the most significant assumptions used to estimate the fair value of the assets acquired and liabilities assumed.
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We believe business combinations are "critical accounting estimates" because the valuation of acquired assets and assumed liabilities involves significant judgment about future events. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.
Contingencies and Asset Retirement Obligations. We are involved in various legal and regulatory proceedings that arise in the ordinary course of business. We record a liability for contingencies based on our assessment that a loss is probable and the amount of the loss can be reasonably estimated. We consider many factors in making these assessments, including historical experience and matter specifics. Estimates are developed in consultation with legal counsel and are based on an analysis of potential results. See Note 11 to the Consolidated Financial Statements.
We accrue a liability for asset retirement obligations based on an estimate of the amount and timing of settlement. For oil and gas wells, the fair value of our plugging and abandonment obligations is recorded at the time the obligation is incurred, which is typically at the time the well is spud. See Note 1 to the Consolidated Financial Statements.
We believe contingencies and asset retirement obligations are "critical accounting estimates" because we must assess the probability of loss related to contingencies and the expected amount and timing of asset retirement obligation settlement. In addition, we must determine the estimated present value of future liabilities. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. If we incur losses related to contingencies that are higher than we expect, we could incur additional costs to settle such obligations. If the expected amount and timing of our asset retirement obligations change, we will be required to adjust the carrying value of our liabilities in future periods. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.