Item 7. Management’s Discussion and Analysis
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read in conjunction with our financial statements and accompanying notes to financial statements appearing elsewhere in this report. 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 for discussion and analysis of results of operations for the year ended December 31, 2021.
Executive Overview
Our primary strategy is to invest in non-operated minority working and mineral interests in oil and gas properties, with a core area of focus in the premier basins within the United States. Using this strategy, we had participated in 9,765 gross (951.6 net) producing wells as of December 31, 2023. As of December 31, 2023, we had leased approximately 272,251 net acres, of which approximately 89% were developed and all were located in the United States.
Our average daily production for full year 2023 was 98,822 Boe per day, and in the fourth quarter of 2023 was 114,363 Boe per day (approximately 60% oil). This represented significant growth from 2022, which was driven in large part by our substantial acquisition activity in 2022 and 2023, as described in Note 3 to our financial statements.
During 2023, we added 76.6 new net wells to production, plus an additional 80.4 net wells added from acquisitions which were already producing when acquired. We ended 2023 with 66.5 net wells in process.
Our financial and operating performance for the year ended December 31, 2023 included the following:
• Total production of 98,822 Boe per day, a 31% increase compared to 2022
• Cash flows from operations of $1.2 billion, a 27% increase compared to 2022
• Proved reserves of 339.7 MMBoe at year-end, a 3% increase compared to year-end 2022
• Grew and diversified the business through over $1.0 billion in substantial bolt-on acquisitions that closed during 2023
• Grew our quarterly common stock dividend by 33%, from $0.30 per share for the fourth quarter of 2022 to $0.40 per share for the fourth quarter of 2023
Source of Our Revenues
We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties. Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market. We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil and natural gas production. We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations. The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.
Principal Components of Our Cost Structure
• Commodity price differentials . The price differential between our well head price for oil and the NYMEX WTI benchmark price is primarily driven by the cost to transport oil via train, pipeline or truck to refineries. The price differential between our well head price for natural gas and NGLs and the NYMEX Henry Hub benchmark price is primarily driven by gathering and transportation costs.
• Gain (loss) on commodity derivatives, net. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas. Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end.
• Production expenses. Production expenses are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include
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field personnel compensation, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties.
• Production taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.
• Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a full cost company, we capitalize all costs associated with our development and acquisition efforts and allocate these costs to each unit of production using the units-of-production method. Accretion expense relates to the passage of time of our asset retirement obligations.
• General and administrative expenses. General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance.
• Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We capitalize a portion of the interest paid on applicable borrowings into our unproved cost pool. We include interest expense that is not capitalized into the unproved cost pool, the amortization of deferred financing costs and bond premiums (including origination and amendment fees), commitment fees and annual agency fees as interest expense.
• Impairment expense. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, a non-cash impairment expense is required.
• Income tax expense. Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
Selected Factors That Affect Our Operating Results
Our revenues, cash flows from operations and future growth depend substantially upon:
• the timing and success of drilling and production activities by our operating partners;
• the prices and the supply and demand for oil, natural gas and NGLs;
• the quantity of oil and natural gas production from the wells in which we participate;
• changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in commodity prices;
• our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and
• the level of our operating expenses.
In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage and wells in the Williston, Permian and Appalachian Basins subjects our operating results to factors specific to these regions. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly
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during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these regions.
The price at which our oil production is sold typically reflects a discount to the NYMEX benchmark price. The price at which our natural gas production is sold may reflect either a discount or premium to the NYMEX benchmark price. Thus, our operating results are also affected by changes in the price differentials between the applicable benchmark and the sales prices we receive for our production. Our oil price differential to the NYMEX benchmark price during 2023 was $2.83 per barrel, as compared to $2.73 per barrel in 2022. Our net realized gas price during 2023 was $2.98 per Mcf, representing 112% realization relative to average Henry Hub pricing, compared to a net realized gas price of $7.43 per Mcf during 2022, which represented 113% realization relative to average Henry Hub pricing. Fluctuations in our oil and gas price realizations are due to several factors such as pricing by basin, gathering and transportation costs, transportation method, takeaway capacity relative to production levels, regional storage capacity, seasonal refinery maintenance temporarily depressing demand, and in the case of gas realizations, the price of NGLs.
Another significant factor affecting our operating results is drilling costs. The cost of drilling wells can vary significantly, driven in part by volatility in commodity prices that can substantially impact the level of drilling activity. Generally, higher oil prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher. Lower oil prices have generally had the opposite effect. In addition, individual components of the cost can vary depending on numerous factors such as the length of the horizontal lateral, the number of fracture stimulation stages, and the type and amount of proppant. Since 2021, we have observed inflationary pressures on drilling and other operating costs due to various factors, such as higher commodity prices, labor shortages, supply chain disruptions and other factors. During 2023, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $9.5 million, compared to $8.0 million for the wells we elected to participate in during 2022.
Market Conditions
The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Because our oil and gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can significantly impact oil prices. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production.
Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2023 and 2022.
December 31,
2023 2022
Average NYMEX Prices (1)
Oil (per Bbl) $ 77.61 $ 94.38
Natural Gas (per Mcf) 2.66 6.56
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(1) Based on average NYMEX closing prices.
For 2023, the average NYMEX pricing was $77.61 per barrel of oil, or 18% lower than in 2022. Our average realized oil price before reflecting settled oil derivatives was $74.78 per barrel of oil in 2023. Our average realized oil price after reflecting settled oil derivatives was $73.88 per barrel of oil in 2023, or 5% higher than in 2022, due to a significantly smaller loss on settled oil derivatives in 2023 compared to 2022, partially offset by the lower average NYMEX price and a higher oil price differential.
For 2023, the average NYMEX pricing for natural gas was $2.66 per Mcf, or 59% lower than in 2022. Our average realized natural gas price before reflecting settled natural gas derivatives was $2.98 per Mcf in 2023. Our average realized natural gas price after reflecting settled natural gas derivatives was $3.90 per Mcf in 2023, or 33% lower than in 2022, due to the lower average NYMEX price, partially offset by a gain on settled natural gas derivatives in 2023 compared to a loss in 2022.
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We have entered into derivatives contracts to hedge commodity price risk on a portion of our future expected oil and natural gas production. For a summary as of December 31, 2023, of our open commodity price derivative contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” in Item 7A below. See also Note 12 to our financial statements.
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Results of Operations for 2023 and 2022
The following table sets forth selected operating data for the periods indicated. Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.
Year Ended December 31,
2023 2022
Net Production:
Oil (Bbl) 22,012,986 16,090,072
Natural Gas and NGLs (Mcf) 84,341,858 68,829,142
Total (Boe) 36,069,962 27,561,596
Net Sales (in thousands):
Oil Sales $ 1,646,096 $ 1,474,610
Natural Gas and NGL Sales 251,683 511,188
Gain (Loss) on Settled Commodity Derivatives 57,919 (455,450)
Gain on Unsettled Commodity Derivatives 201,331 40,187
Other Revenue 9,230 —
Total Revenues 2,166,259 1,570,535
Average Sales Prices:
Oil (per Bbl) $ 74.78 $ 91.65
Effect of Loss on Settled Oil Derivatives on Average Price (per Bbl) (0.90) (21.48)
Oil Net of Settled Oil Derivatives (per Bbl) 73.88 70.17
Natural Gas and NGLs (per Mcf) 2.98 7.43
Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf) 0.92 (1.60)
Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf) 3.90 5.83
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives 52.61 72.05
Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) 1.61 (16.52)
Realized Price on a Boe Basis Including Settled Commodity Derivatives 54.22 55.53
Operating Expenses (in thousands):
Production Expenses $ 347,006 $ 260,676
Production Taxes 160,118 158,194
General and Administrative Expenses 46,801 47,201
Depletion, Depreciation, Amortization and Accretion 486,024 251,272
Other Expenses 4,448 —
Costs and Expenses (per Boe):
Production Expenses $ 9.62 $ 9.46
Production Taxes 4.44 5.74
General and Administrative Expenses 1.30 1.71
Depletion, Depreciation, Amortization and Accretion 13.47 9.12
Net Producing Wells at Period-End 951.6 799.3
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Oil and Natural Gas Sales
Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes. In 2023, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, decreased 4% from 2022, driven by a 27% decrease in realized prices, excluding the effect of settled commodity derivatives, partially offset by a 31% increase in production volumes. The lower average realized price in 2023 as compared to 2022 was driven by lower average NYMEX oil and natural gas prices and slightly higher average oil price differential in 2023 as compared to 2022. Oil price differential during 2023 averaged $2.83 per barrel, as compared to $2.73 per barrel in 2022.
We add production through drilling success as we place new wells into production and through additions from acquisitions, which is offset by the natural decline of our oil and natural gas production from existing wells. Our substantial acquisition activities in 2022 and 2023 (see Note 3 to our financial statements) helped drive the 31% increase in production levels in 2023 as compared to 2022. In addition, the number of net wells we added to production (excluding acquisitions) increased by 35% in 2023 as compared to 2022, due to our growing organic acreage footprint and increased development on our properties.
Our production for the last two years is set forth in the following table:
Year Ended December 31,
2023 2022
Production:
Oil (Bbl) 22,012,986 16,090,072
Natural Gas and NGL (Mcf) 84,341,858 68,829,142
Total (Boe) (1)
36,069,962 27,561,596
Average Daily Production:
Oil (Bbl) 60,310 44,082
Natural Gas and NGL (Mcf) 231,074 188,573
Total (Boe) (1)
98,822 75,511
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(1) Natural gas and NGLs are converted to Boe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.
Commodity Derivative Instruments
We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production. Our gain (loss) on commodity derivatives, net was a gain of $259.3 million in 2023, compared to a loss of $415.3 million in 2022. Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (ii) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end.
For 2023, we realized a gain on settled commodity derivatives of $57.9 million, compared to a $455.4 million loss in 2022. The increased gain on settled derivatives was primarily due to a significant decrease in the average NYMEX oil price in 2023 compared to 2022. The average NYMEX oil price for 2023 was $77.61 per barrel, compared to $94.38 per barrel for 2022. During 2023, our derivative settlements included 8.1 million barrels of oil subject to swaps at an average settlement price of $75.19 per barrel, and we had an additional 6.3 million barrels of oil hedged subject to collars. During 2022, our settled commodity derivatives included 10.9 million barrels of oil at an average settlement price of $62.52 per barrel. Our average realized price (including all commodity derivative cash settlements) in 2023 was $54.22 per Boe compared to $55.53 per Boe in 2022. The gain (loss) on settled commodity derivatives increased our average realized price per Boe by $1.61 in 2023 and decreased our average realized price per Boe by $16.52 in 2022. The percentage of oil production hedged under our derivative contracts was 65% and 68% in 2023 and 2022, respectively.
Unsettled commodity derivative gains and losses was a gain of $201.3 million in 2023 compared to a gain of $40.2 million in 2022. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized
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immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as gains and losses from unsettled derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our commodity derivatives. Any gains on our unsettled commodity derivatives are expected to be offset by lower wellhead revenues in the future, while any losses are expected to be offset by higher future wellhead revenues based on the value at the settlement date. At December 31, 2023, all of our derivative contracts are recorded at their fair value, which was a net liability of $36.2 million, a change of $200.3 million from the $236.5 million net liability recorded as of December 31, 2022. The decrease in the net liability at December 31, 2023 as compared to December 31, 2022 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2022. Our open commodity derivative contracts are summarized in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”
Production Expenses
Production expenses were $347.0 million in 2023 compared to $260.7 million in 2022. On a per unit basis, production expenses increased 2%, from $9.46 per Boe in 2022 to $9.62 per Boe in 2023, due to higher service and maintenance costs and higher workover expenses, which was partially offset by lower processing costs associated with a change in our production mix. On an absolute dollar basis, the 33% increase in our production expenses in 2023 compared to 2022 was primarily due to a 31% increase in production volumes and a 2% increase in per unit costs.
Production Taxes
We pay production taxes based on realized oil and natural gas sales. Production taxes were $160.1 million in 2023 compared to $158.2 million in 2022. The increase is due to higher production and a higher oil cut percentage, offset by the significantly lower realized prices and the change in our geographical production mix. As a percentage of oil and natural gas sales, our production taxes were 8.4% and 8.0% in 2023 and 2022, respectively. The fluctuation in our average production tax rate from year to year is primarily due to changes in our oil sales as a percentage of our total oil and gas sales, as well as the mix of our production by basin. Oil sales are taxed at a higher rate than natural gas sales.
General and Administrative Expenses
General and administrative expenses were $46.8 million for 2023 compared to $47.2 million for 2022. The decrease in 2023 compared to 2022 was primarily due to a $5.3 million decrease in acquisition costs, partially offset by a $2.5 million increase in professional fees and a $1.2 million increase in compensation costs.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion (“DD&A”) was $486.0 million in 2023 compared to $251.3 million in 2022. The aggregate increase in DD&A expense for 2023 compared to 2022 was driven by a 31% increase in production levels and a 48% increase in the depletion rate per Boe. The increase in depletion rate per Boe for 2023 as compared to 2022 was primarily due to a significant increase to our depletable base, due to the closing of several larger acquisitions in 2022 and 2023 (see Note 3 to our financial statements). The following table summarizes DD&A expense per Boe for 2023 and 2022:
Year Ended December 31,
2023 2022 Change % Change
Depletion $ 13.37 $ 9.01 $ 4.36 48 %
Depreciation, Amortization, and Accretion 0.10 0.11 (0.01) (9) %
Total DD&A expense $ 13.47 $ 9.12 $ 4.35 48 %
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Interest Expense
Interest expense, net of capitalized interest, was $135.7 million in 2023 compared to $80.3 million in 2022. The increase in interest expense for 2023 as compared to 2022 was primarily due to higher levels of debt and higher weighted-average interest rates on debt outstanding during 2023 compared to 2022.
Contingent Consideration Gain (Loss)
We have incurred contingent consideration liabilities in connection with certain acquisitions of oil and gas properties. During the years ended December 31, 2023 and 2022, we recorded a contingent consideration gain of $10.1 million compared to a gain of $1.9 million, respectively, due to the change in the fair value of these liabilities. As of December 31, 2023, there were no remaining outstanding contingent consideration liabilities.
Income Tax Expense
During 2023, we recorded income tax expense of $77.8 million related to federal and state income taxes as a result of the release of the majority of our valuation allowance during the period. During 2022, we recorded income tax expense of $3.1 million related to state income taxes as the Company maintained a full valuation allowance for its deferred tax assets. The effective tax rate for 2023 was 7.8% compared to an effective tax rate of 0.4% for 2022. The difference was due primarily to the release of our full valuation allowance and recording of deferred tax liabilities in 2023.
Liquidity and Capital Resources
Overview
Our main sources of liquidity and capital resources as of the date of this report have been internally generated cash flow from operations, proceeds from equity and debt financings, credit facility borrowings and cash settlements of commodity derivative instruments. Our primary uses of capital have been for the acquisition, development and operation of our oil and natural gas properties, cash settlements of commodity derivative instruments and for stockholder returns. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.
In May 2023, we issued $500.0 million in aggregate principal amount of Senior Notes due 2031, the proceeds of which were used primarily to refinance existing indebtedness, and for general corporate purposes.
In May 2023, we closed an underwritten public offering of 7,647,500 shares of our common stock at a price of $29.40 per share, after deducting underwriting discounts. This offering resulted in net proceeds of approximately $224.7 million, after deducting underwriting discounts and commissions, which were used primarily to finance the cash consideration for the acquisition of Delaware Basin assets from Forge Energy II Delaware, LLC. In October 2023, we closed an underwritten public offering of 7,475,000 shares of our common stock at a price of $38.88 per share, after deducting underwriting discounts. This offering resulted in net proceeds of approximately $290.6 million, after deducting underwriting discounts and commissions, which were primarily used for the repayment of existing indebtedness, and for general corporate purposes.
During 2023, we repurchased and retired (i) 287,751 shares of our common stock for total consideration of $8.0 million and (ii) $19.1 million aggregate principal amount of our Senior Notes due 2028 for total consideration of $18.4 million, plus accrued and unpaid interest.
We completed over $1.0 billion in substantial bolt-on acquisitions that closed during 2023 (see Note 3 to our financial statements). We financed these acquisitions with a combination of debt and equity financings, credit facility borrowings, and internally generated cash flow from operations.
As of December 31, 2023, we had outstanding debt consisting of $161.0 million of borrowings under our Revolving Credit Facility, $705.1 million aggregate principal amount of our Senior Notes due 2028, $500.0 million aggregate principal amount of our Convertible Notes, and $500.0 million aggregate principal amount of our Senior Notes due 2031. We had total liquidity of $1,097.2 million as of December 31, 2023, consisting of $1,089.0 million of committed borrowing availability under the Revolving Credit Facility and $8.2 million of cash on hand.
One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 87% and 74% of our total oil and gas sales in 2023 and 2022, respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas and NGL prices. We seek to maintain
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a robust hedging program to mitigate volatility in commodity prices with respect to a portion of our expected production. For the years ended 2023 and 2022, we hedged approximately 65% and 68% of our crude oil production, respectively. For a summary as of December 31, 2023, of our open commodity swap contracts for future periods, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below.
With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months and, based on current expectations, for the foreseeable future. However, we may seek additional access to capital and liquidity. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all.
Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash flows from operations and available borrowing capacity under our Revolving Credit Facility. Our capital expenditures could be curtailed if our cash flows decline from expected levels. Because production from existing oil and natural gas wells declines over time, reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future.
Working Capital
Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, collection of receivables, expenditures related to our development and production operations and the impact of our outstanding derivative instruments. At December 31, 2023, we had a working capital surplus of $123.6 million, compared to a deficit of $24.5 million at December 31, 2022. Current assets increased by $188.9 million and current liabilities increased by $40.8 million at December 31, 2023 as compared to December 31, 2022.
The $188.9 million increase in current assets in 2023 as compared to 2022 was driven by a $99.2 million increase in accounts receivable, primarily due to higher production levels, and a $40.4 million increase in derivative instruments due to the change in fair value as a result of commodity price changes.
The $40.8 million increase in current liabilities in 2023 as compared to 2022 was driven by a $90.3 million increase in accounts payable and accrued liabilities, primarily as a result of increased development activity, and a $1.9 million increase in accrued interest. These increases were partially offset by a $41.6 million decrease in our derivative instruments as a result of commodity price changes and a $10.1 million decrease in contingent consideration liabilities related to our acquisition activities (see Note 3 to our financial statements).
Cash Flows
Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. We typically enter into commodity derivative transactions covering a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 24 months. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”
Our cash flows for the years ended December 31, 2023 and 2022 are presented below:
Year Ended December 31,
(In thousands) 2023 2022
Net Cash Provided by Operating Activities $ 1,183,321 $ 928,418
Net Cash Used for Investing Activities (1,862,346) (1,402,777)
Net Cash Provided by Financing Activities 684,692 467,367
Net Change in Cash $ 5,667 $ (6,992)
Cash Flows from Operating Activities
Net cash provided by operating activities in 2023 was $1,183.3 million, compared to $928.4 million in 2022. This increase was driven by a 31% year-over-year increase in production levels and a 5% increase in our realized oil price after the
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effect of settled derivatives, which was partially offset by an increase in production expenses. Net cash provided by operating activities is also affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital and other items (as reflected in our statements of cash flows) in the year ended December 31, 2023 was a deficit of $106.1 million compared to a deficit of $62.4 million in 2022.
Cash Flows from Investing Activities
We had cash flows used in investing activities of $1,862.3 million and $1,402.8 million during the years ended December 31, 2023 and 2022, respectively, primarily as a result of our capital expenditures for drilling, development and acquisition costs. The year-over-year increase in cash used in investing activities in 2023 was mainly attributable to our 2023 acquisitions. In addition, cash flows used in investing activities included a $17.1 million acquisition deposit for an acquisition that was pending at year-end 2023. During 2023 and 2022, we added 76.6 and 56.8 net wells to production, respectively, excluding already producing wells from acquisitions.
Our cash flows used in investing activities reflects actual cash spending, which can lag several months from when the related costs were incurred. As a result, our actual cash spending is not always reflective of current levels of development activity. For instance, during the year ended December 31, 2023, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g. drilling and completion costs, acquisitions, and other capital expenditures) amounted to $1,925.9 million, while the actual cash spend in this regard amounted to $1,861.1 million.
Development and acquisition activities are discretionary. We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and returns. Our cash spend for development and acquisition activities for the years ended December 31, 2023 and 2022 are summarized in the following table:
Year Ended December 31,
(In millions) 2023 2022
Drilling and Development Capital Expenditures $ 809.8 $ 392.5
Acquisition of Oil and Natural Gas Properties 1,047.7 958.8
Other Capital Expenditures 3.6 4.0
Total $ 1,861.1 $ 1,355.2
Cash Flows from Financing Activities
Net cash provided by financing activities was $684.7 million and $467.4 million for the years ended December 31, 2023 and 2022, respectively. The cash provided by financing activities in 2023 was primarily related to the issuance of the Senior Notes due 2031 of $492.8 million and the issuance of common stock of $514.7 million, which was partially offset by $8.0 million in repurchases of common stock, $18.4 million in repurchases of our Senior Notes due 2028, and $158.0 million of net repayments on our Revolving Credit Facility. Additionally, we paid common stock dividends of $123.9 million and spent $11.9 million in fees in connection with debt financing transactions in 2023.
The cash provided by financing activities in 2022 was primarily related to $264.0 million of net advances under our Revolving Credit Facility and issuance of Convertible Notes of $483.0 million, which was partially offset by $81.2 million in repurchases of our 6.500 % Series A Perpetual Cumulative Convertible Preferred Stock (the “Series A Preferred Stock”), $54.5 million in repurchases of common stock, $24.9 million in repurchases of our Senior Notes due 2028, and $36.1 million of capped call purchases related to the issuance of our Convertible Notes. Additionally, we paid common and preferred stock dividends of $51.6 million and $21.7 million, respectively, and spent $7.4 million in fees in connection with debt financing transactions in 2022.
Revolving Credit Facility
We have entered into a revolving credit facility with Wells Fargo Bank, as administrative agent, and the lenders from time to time party thereto (the “Revolving Credit Facility”). The Revolving Credit Facility is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to our oil and gas properties. As of December 31, 2023, the Revolving Credit Facility had a borrowing base of $1.8 billion and an elected commitment amount of $1.25 billion, and we had $161.0 million in borrowings outstanding under the facility, leaving $1,089.0 million in available committed borrowing capacity. See Note 4 to our financial statements for further details regarding the Revolving Credit Facility.
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Senior Notes due 2028
As of December 31, 2023, we had outstanding $705.1 million aggregate principal amount of our 8.125% senior notes due 2028. See Note 4 to our financial statements for further details regarding the Senior Notes due 2028.
Convertible Notes due 2029
As of December 31, 2023, we had outstanding $500.0 million aggregate principal amount of our Convertible Notes. See Note 4 to our financial statements for further details regarding the Convertible Notes.
Senior Notes due 2031
As of December 31, 2023, we had outstanding $500.0 million aggregate principal amount of our 8.750% senior notes due 2031. See Note 4 to our financial statements for further details regarding the Senior Notes due 2031.
Series A Preferred Stock
In November 2022, we exercised in full our mandatory conversion rights on the Series A Preferred Stock. All outstanding shares of Series A Preferred Stock automatically converted into shares of common stock on November 15, 2022. As of December 31, 2023, we h ad no outsta nding shares of Series A Preferred Stock. See Note 5 to our financial statements for further details regarding the Series A Preferred Stock and the mandatory conversion.
Known Contractual and Other Obligations; Planned Capital Expenditures
Contractual and Other Obligations. We have contractual commitments under our debt agreements, including interest payments and principal repayments. See Note 4 to our financial statements. We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 12 to our financial statements. We have firm commitments on certain assets that we assumed in our April 2021 acquisition of natural gas properties in the Appalachian Basin. See “Item 2—Properties—Delivery Commitments” above. We have future obligations related to the abandonment of our oil and natural gas properties. See Note 9 to our financial statements. With respect to all of these items, except for our commitments under our debt agreements, we cannot determine with accuracy the amount and/or timing of such payments.
Planned Capital Expenditures. For 2024, we are budgeting approximately $825 to $900 million in total planned capital expenditures, including development expenditures and our smaller day-to-day acquisition activity, which we refer to as our “ground game” acquisition activity. As of December 31, 2023, we had incurred $236 million in capital expenditures that were included in accounts payable and accrued liabilities, and we estimate that we were committed to an additional approximately $393 million in development capital expenditures not yet incurred for wells we had elected to participate in. We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our Revolving Credit Facility. The foregoing excludes larger acquisitions, which are typically not included in our annual capital expenditure budget. See also “Capital Requirements” below.
Capital Stock and Debt Security Repurchases . In May 2022, the Company’s board of directors approved a stock repurchase program to acquire up to $150.0 million of the Company’s outstanding common stock. The stock repurchase program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions. During the year ended December 31, 2023 the Company repurchased 287,751 shares of its common stock under the stock repurchase program at a total cost of $8.0 million. During the year ended December 31, 2023, the Company also repurchased and retired $19.1 million in aggregate principal amount of the Senior Notes due 2028 in open market transactions for a total of $18.4 million in cash, plus accrued interest. The Company may in the future engage in similar transactions.
The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors. If oil, NGL and natural gas prices decline below our acceptable levels, or costs increase above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We will carefully monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs,
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fluctuations in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control. For additional information on the impact of changing prices and market conditions on our financial position, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
Capital Requirements
Development and acquisition activities are discretionary, and, for the near term, we expect such activities to be maintained at levels we can fund through cash on hand, internal cash flow and borrowings under our Revolving Credit Facility. To the extent capital requirements exceed internal cash flow and borrowing capacity under our Revolving Credit Facility, additional financings from the capital markets may be pursued to fund these requirements. We monitor our capital expenditures on a regular basis, adjusting the amount up or down and also between our projects, depending on commodity prices, cash flow and projected returns. Also, our obligations may change due to acquisitions, divestitures and continued growth. Our future success in growing proved reserves and production may be dependent on our ability to access outside sources of capital. If internally generated cash flow and borrowing capacity under our Revolving Credit Facility are not available or sufficient, we may issue additional equity or debt to fund capital expenditures, make acquisitions, extend maturities or to repay debt.
Satisfaction of Our Cash Obligations for the Next Twelve Months
With our Revolving Credit Facility and our cash flows from operations, we believe we will have sufficient capital to meet our drilling commitments, expected general and administrative expenses and other cash needs for the next twelve months and, based on current expectations, for the foreseeable future. Nonetheless, any strategic acquisition of assets or increase in drilling activity may lead us to seek additional capital. We may also choose to seek additional capital rather than utilize our Revolving Credit Facility or other debt instruments to fund accelerated or continued drilling at the discretion of management and depending on prevailing market conditions. We will evaluate any potential opportunities for acquisitions as they arise. However, there can be no assurance that any additional capital will be available to us on favorable terms or at all.
Effects of Inflation and Pricing
The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. Based on current conditions and expectations, we are not budgeting for any significant change in per well drilling and completion and other associated costs in 2024 compared to 2023.
Critical Accounting Estimates
The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our financial statements in accordance with generally accepted accounting principles in the United States (GAAP), as well as ensuring compliance with applicable laws and regulations governing financial reporting. While there are rarely alternative methods or rules from which to select in establishing accounting and financial reporting policies, proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions.
Use of Estimates
The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect our reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Our estimates of our proved oil and natural gas reserves, future development costs, estimates relating to certain oil and natural gas revenues and expenses, and fair value of derivative instruments are the most critical to our financial statements.
Oil and Natural Gas Reserves
The determination of depreciation, depletion and amortization expense as well as impairments that are recognized on our oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and
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engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change. Approximately 31% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserve, future cash flows from our reserves, and future development of our proved undeveloped reserves.
The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. Such information includes revisions of certain reserve estimates attributable to our properties included in the prior year’s estimates. These revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in oil and natural gas prices.
Our third-party independent reserve engineers, Cawley, Gillespie & Associates, Inc., audited 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2023. Our estimates of proved reserves quantities were prepared in accordance with the rules promulgated by the SEC. In connection with our external petroleum engineers performing their independent reserve audits, we furnish them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests.
Oil and Natural Gas Properties
The method of accounting we use to account for our oil and natural gas investments determines what costs are capitalized and how these costs are ultimately matched with revenues and expensed.
We utilize the full cost method of accounting to account for our oil and natural gas investments instead of the successful efforts method because we believe it more accurately reflects the underlying economics of our programs to explore and develop oil and natural gas reserves. The full cost method embraces the concept that dry holes and other expenditures that fail to add reserves are intrinsic to the oil and natural gas exploration business. Thus, under the full cost method, all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs, geological and geophysical costs that are directly attributable to the properties and capitalized interest. Although some of these costs will ultimately result in no additional reserves, they are part of a program from which we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. The full cost method differs from the successful efforts method of accounting for oil and natural gas investments. The primary difference between these two methods is the treatment of exploratory dry hole costs. These costs are generally expensed under the successful efforts method when it is determined that measurable reserves do not exist. Geological and geophysical costs are also expensed under the successful efforts method. Under the full cost method, both dry hole costs and geological and geophysical costs are initially capitalized and classified as unproved properties pending determination of proved reserves. If no proved reserves are discovered, these costs are then amortized with all the costs in the full cost pool.
Capitalized amounts except unproved costs are depleted using the units of production method. The depletion expense per unit of production is the ratio of the sum of our unamortized historical costs and estimated future development costs to our proved reserve volumes. Estimation of hydrocarbon reserves relies on professional judgment and use of factors that cannot be precisely determined. Subsequent reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting periods. For the year ended December 31, 2023, our average depletion expense per unit of production w as $13.37 per Boe.
To the extent the capitalized costs in our full cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the sum of the present value (using a 10% discount rate and based on 12-month/SEC oil and natural gas prices) of the estimated future net cash flows from our proved oil and natural gas reserves and the capitalized cost associated with our unproved properties, we would have a capitalized ceiling impairment. Such costs would be charged to operations as a reduction of the carrying value of oil and natural gas properties. The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are depressed, even if the low prices are temporary. In addition, capitalized ceiling impairment charges may occur if we experience poor drilling results or if
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estimations of our proved reserves are substantially reduced. A capitalized ceiling impairment is a reduction in earnings that does not impact cash flows, but does impact operating income and stockholders’ equity. Once recognized, a capitalized ceiling impairment charge to oil and natural gas properties cannot be reversed at a later date. The risk that we will experience a ceiling test writedown increases when oil and natural gas prices are depressed or if we have substantial downward revisions in our estimated proved reserves.
At December 31, 2023, we performed an impairment review using prices that reflect an average of 2023’s monthly prices as prescribed pursuant to the SEC’s guidelines. We did not record any full cost impairment expense for the years ended December 31, 2023 or 2022. If a low price environment reoccurs, we might be required to write down the value of our oil and gas properties. In addition, capitalized ceiling impairment charges may occur if estimates of proved reserves are substantially reduced or estimates of future development costs increase significantly. See “Item 2. Properties” for a discussion of our reserve estimation assumptions.
Derivative Instrument Activities
We use derivative instruments from time to time to manage market risks resulting primarily from fluctuations in the prices of oil and natural gas. We may periodically enter into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells. We may also use exchange traded futures contracts and option contracts to hedge the delivery price of oil at a future date.
All derivative positions are carried at their fair value in the balance sheet and are marked-to-market at the end of each period. Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to gain (loss) on derivative instruments, net on the statements of operations rather than as a component of accumulated other comprehensive income or other income (expense). The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 12 to our financial statements for a description of the derivative contracts.
Recently Issued or Adopted Accounting Pronouncements
For discussion of recently issued or adopted accounting pronouncements, see Notes to Financial Statements—Note 2. Significant Accounting Policies.
Off-Balance Sheet Arrangements
We currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
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