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Cautionary Statement Concerning Forward-Looking Statements
We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the "safe harbor" protection for forward-looking statements that applicable federal securities law affords. From time to time, our management or persons acting on our behalf may make forward-looking statements to inform existing and potential security holders about our company. All statements other than statements of historical facts included in this report regarding our financial position, business strategy, plans and objectives of management for future operations, industry conditions, indebtedness covenant compliance, capital expenditures, production, cash flow, borrowing base under our revolving credit facility, our intention or ability to pay or increase dividends on our capital stock, and impairment are forward-looking statements. When used in this report, forward-looking statements are generally accompanied by terms or phrases such as "estimate," "project," "predict," "believe," "expect," "continue," "anticipate," "target," "could," "plan," "intend," "seek," "goal," "will," "should," "may" or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future production sales, market size, collaborations, cash flows, and trends or operating results also constitute such forward-looking statements. Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our company's control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: changes in crude oil and natural gas prices, the pace of drilling and completions activity on our current properties and properties pending acquisition, infrastructure constraints and related factors affecting our properties, cost inflation or supply chain disruptions, ongoing legal disputes over and potential shutdown of the Dakota Access Pipeline, our ability to acquire additional development opportunities, potential or pending acquisition transactions, the projected capital efficiency savings and other operating efficiencies and synergies resulting from our acquisition transactions, integration and benefits of property acquisitions, or the effects of such acquisitions on our company's cash position and levels of indebtedness, changes in our reserves estimates or the value thereof, disruption to our company's business due to acquisitions and other significant transactions, general economic or industry conditions, nationally and/or in the communities in which our company conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, our ability to consummate any pending acquisition transactions, other risks and uncertainties related to the closing of pending acquisition transactions, our ability to raise or access capital, cyber-related risks, changes in accounting principles, policies or guidelines, financial or political instability, health-related epidemics, acts of war or terrorism, and other economic, competitive, governmental, regulatory and technical factors affecting our operations, products and prices. We have based any forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Accordingly, results actually achieved may differ materially from expected results described in these statements. Forward-looking statements speak only as of the date they are made. You should consider carefully the statements in the section entitled "Item 1A. Risk Factors" and other sections of our Annual Report on Form 10-K for the fiscal year endedDecember 31, 2021 , as updated by subsequent reports we file with theSEC (including this report), which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our Company does not undertake, and specifically disclaims, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements.
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 withinthe United States . Using this strategy, we had participated in 8,259 gross (761.2 net) producing wells as ofSeptember 30, 2022 . As ofSeptember 30, 2022 , we had leased approximately 254,567 net acres, of which approximately 87% were developed and all were located inthe United States . We have grown and diversified our business significantly over the last several years. Prior to 2020, we focused our operations exclusively on oil-weighted properties in theWilliston Basin . We first expanded beyond theWilliston Basin in 2020, with several small acquisitions in thePermian Basin . Since then, we have accelerated our diversification outside theWilliston Basin via several larger acquisitions, including by acquiring natural gas properties in theAppalachian Basin and through several acquisitions in thePermian Basin (including, most recently, onePermian Basin acquisition that closed inOctober 2022 , two 31 -------------------------------------------------------------------------------- Table of Contents that are expected to close inDecember 2022 , and another that is expected to close inJanuary 2023 ). We have also grown our legacyWilliston Basin position via acquisitions, most recently the Incline Acquisition that closed during the three months endedSeptember 30, 2022 . See Notes 3 and 12 to our condensed financial statements for further details regarding our recent acquisition activity. Our average daily production in the third quarter of 2022 was approximately 79,123 Boe per day, of which approximately 57% was oil. This was a 9% sequential increase in production compared to the second quarter of 2022, primarily due to production attributable to recent acquisitions and new wells added to production. During the three months endedSeptember 30, 2022 , we added 16.2 net wells to production (excluding wells added at closing of the Incline Acquisition).
Our percentage of production volumes by basin for the three months ended
Three Months Ended Three Months Ended
September 30, 2022 September 30, 2021
Williston Permian Appalachian Total Williston Permian Appalachian Total
Oil (Bbl) 71 % 29 % - % 100 % 95 % 5 % - % 100 %
Natural Gas and NGLs
(Mcf) 40 % 21 % 39 % 100 % 45 % 3 % 52 % 100 %
Total (Boe) 57 % 26 % 17 % 100 % 74 % 4 % 22 % 100 %
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 NYMEXHenry 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 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. 32 -------------------------------------------------------------------------------- Table of Contents •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 full 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. •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 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 the third quarter of 2022 was$0.84 per barrel, as compared to$5.63 per barrel in the third quarter of 2021. Our net realized gas price in the third quarter of 2022 was$8.43 per Mcf, representing 106% realization relative to averageHenry Hub pricing, compared to a net realized gas price of$4.33 per Mcf in the third quarter of 2021, which represented 100% realization relative to averageHenry 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 33 -------------------------------------------------------------------------------- Table of Contents fracture stimulation stages, and the type and amount of proppant. During the first nine months of 2022, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was$7.7 million , compared to$6.9 million for the wells we elected to participate in during 2021. Certain drilling and completion costs and costs of oilfield services, equipment, and materials decreased in recent years as service providers reduced their costs in response to reduced demand arising from historically low crude oil prices. However, inflationary pressures returned in 2021 and continue to persist in 2022 in conjunction with the significant increase in commodity prices over the past year, labor shortages, and other factors. Additionally, supply chain disruptions stemming from the COVID-19 pandemic have led to shortages of certain materials and equipment and resulting increases in material and labor costs. Our capital spending budget for 2022 includes an estimate for the impact of cost inflation and, despite inflationary pressures, we expect to continue generating significant amounts of free cash flow at current commodity price levels.
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 withinthe United States , the production quota set byOPEC , and the strength of theU.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 three and nine months endedSeptember 30, 2022 and 2021. Three Months Ended September 30, 2022 2021 Average NYMEX Prices(1) Natural Gas (per Mcf) $ 7.95$ 4.31 Oil (per Bbl) $ 91.38$ 70.54 _________
(1)Based on average NYMEX closing prices.
Nine Months Ended September 30,
2022 2021
Average NYMEX Prices(1)
Natural Gas (per Mcf) $ 6.71 $ 3.54
Oil (per Bbl) $ 98.31 $ 65.05
_________
(1)Based on average NYMEX closing prices.
For the three months endedSeptember 30, 2022 , the average NYMEX pricing was$91.38 per barrel of oil, or 30% higher than the average NYMEX price per barrel for the comparable period in 2021. Our realized oil price after reflecting settled commodity derivatives was 36% higher in the third quarter of 2022 than in the third quarter of 2021 due to higher average NYMEX price per barrel and a lower oil price differential, partially offset by a larger loss on settled oil derivatives in the third quarter of 2022 compared to the third quarter of 2021. For the three months endedSeptember 30, 2022 , the average NYMEX pricing for natural gas was$7.95 per Mcf, or 84% higher than in the comparable period in 2021. Our realized natural gas price after reflecting settled commodity derivatives was 99% higher in the third quarter of 2022 than in the third quarter of 2021 due to the higher average NYMEX natural gas price, partially offset by a larger loss on settled natural gas derivatives in the third quarter of 2022 compared to the third quarter of 2021. 34 -------------------------------------------------------------------------------- Table of Contents We have entered into derivatives contracts to hedge commodity price risk on a portion of our future expected oil and natural gas production. For a summary as ofSeptember 30, 2022 , of our open commodity price derivative contracts for future periods, see "Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk" in Part I, Item 3 below. See also Note 11 to the condensed financial statements for additional information. 35
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Results of Operations for the Three Months Ended
The following table sets forth selected operating data for the periods
indicated.
Three Months Ended
2022 2021 % Change Net Production: Oil (Bbl) 4,149,841 3,131,182 33 % Natural Gas and NGLs (Mcf) 18,776,821 13,034,251 44 % Total (Boe) 7,279,311 5,303,557 37 %Net Sales (in thousands): Oil Sales$ 375,732 $ 203,234 85 % Natural Gas and NGL Sales 158,318 56,436 Gain (Loss) on Settled Commodity Derivatives (124,911) (56,318) Gain (Loss) on Unsettled Commodity Derivatives 382,501 (71,845) Total Revenues 791,640 131,507 Average Sales Prices: Oil (per Bbl)$ 90.54 $ 64.91 39 %
Effect Loss on Settled Oil Derivatives on Average Price (per
Bbl)
(19.12) (12.52) Oil Net of Settled Oil Derivatives (per Bbl) 71.42 52.39 36 % Natural Gas and NGLs (per Mcf) 8.43 4.33 95 %
Effect of Loss on Settled Natural Gas Derivatives on Average
Price (per Mcf)
(2.43) (1.31)
Natural Gas and NGLs Net of Settled Natural Gas Derivatives
(per Mcf)
6.00 3.02 99 %
Realized Price on a Boe Basis Excluding Settled Commodity
Derivatives
73.37 48.96 50 %
Effect of Loss on Settled Commodity Derivatives on Average
Price (per Boe)
(17.16) (10.62)
Realized Price on a Boe Basis Including Settled Commodity
Derivatives
56.21 38.34 47 % Operating Expenses (in thousands): Production Expenses$ 68,478 $ 43,236 58 % Production Taxes 42,273 19,932 112 % General and Administrative Expenses 10,278 5,490 87 % Depletion, Depreciation, Amortization and Accretion 65,975 35,885 84 % Costs and Expenses (per Boe): Production Expenses$ 9.41 $ 8.15 15 % Production Taxes 5.81 3.76 55 % General and Administrative Expenses 1.41 1.04 36 % Depletion, Depreciation, Amortization and Accretion 9.06 6.77 34 % Net Producing Wells at Period End 761.2 601.8 26 % Oil and Natural Gas Sales In the third quarter of 2022, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was$534.1 million compared to$259.7 million in the third quarter of 2021, driven by a 37% increase in production and 50% increase in realized prices, excluding the effect of settled commodity derivatives. The higher average realized price in the third quarter of 2022 compared to the same period in 2021 was driven by higher average NYMEX oil prices and a lower oil price 36 -------------------------------------------------------------------------------- Table of Contents differential. Oil price differential during the third quarter of 2022 was$0.84 per barrel, as compared to$5.63 per barrel in the third quarter of 2021. The higher average realized price in the third quarter of 2022 as compared to the same period in 2021 was also driven by a$4.10 per Mcf increase in realized natural gas and NGL prices, excluding the effect of settled commodity derivatives, in the third quarter of 2022 compared to the same period of 2021. See "Market Conditions" above. 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. Acquisitions were a significant driver of our 37% increase in production levels in the third quarter of 2022 compared to the same period in 2021.
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$257.6 million in the third quarter of 2022, compared to a loss of$128.2 million in the third quarter of 2021. 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 the third quarter of 2022, we realized a loss on settled commodity derivatives of$124.9 million , compared to a$56.3 million loss in the third quarter of 2021. The increased loss on settled derivatives was primarily due to a significant increase in the average NYMEX oil price in the third quarter of 2022 compared to the same period of 2021. During the third quarter of 2022, our derivative settlements included 2.8 million barrels of oil at an average settlement price of$63.88 per barrel. During the third quarter of 2021, our settled commodity derivatives included 2.2 million barrels of oil at an average settlement price of$54.63 per barrel. The average NYMEX oil price for the third quarter of 2022 was$91.38 compared to$70.54 for the third quarter of 2021. Our average realized price (including all commodity derivative cash settlements) in the third quarter of 2022 was$56.21 per Boe compared to$38.34 per Boe in the third quarter of 2021. The gain (loss) on settled commodity derivatives decreased our average realized price per Boe by$17.16 in the third quarter of 2022 and decreased our average realized price per Boe by$10.62 in the third quarter of 2021. Unsettled commodity derivative gains and losses was a gain of$382.5 million in the third quarter of 2022, compared to a loss of$71.8 million in the third quarter of 2021. 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 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. AtSeptember 30, 2022 , all of our derivative contracts are recorded at their fair value, which was a net liability of$223.5 million , a change of$54.2 million from the$277.7 million net liability recorded as ofDecember 31, 2021 . The decrease in liability atSeptember 30, 2022 as compared toDecember 31, 2021 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts sinceDecember 31, 2021 . Our open commodity derivative contracts are summarized in "Item 3. Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk." Production Expenses Production expenses were$68.5 million in the third quarter of 2022, compared to$43.2 million in the third quarter of 2021. On a per unit basis, production expenses increased from$8.15 per Boe in the third quarter of 2021 to$9.41 per Boe in the third quarter of 2022, due to higher processing costs due in part to elevated NGL pricing, which drives increased payments under percentage of proceeds contracts. Additionally, higher service and maintenance costs have contributed to an increase in production expense per Boe in the third quarter of 2022 On an absolute dollar basis, the increase in our production expenses in the third quarter of 2022, as compared to the third quarter of 2021, was primarily due to a 37% increase in production volumes, a 26% increase in the total number of net producing wells and the aforementioned higher per unit costs.
Production Taxes
We pay production taxes based on realized oil and natural gas sales. Production taxes were$42.3 million in the third quarter of 2022 compared to$19.9 million in the third quarter of 2021. The increase is due to higher production and higher realized prices, which significantly increased our oil and natural gas sales in the third quarter of 2022 as compared to the third quarter of 2021. As a percentage of oil and natural gas sales, our production taxes were 7.9% and 7.7% in the third quarter of 37 -------------------------------------------------------------------------------- Table of Contents 2022 and 2021, 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$10.3 million in the third quarter of 2022 compared to$5.5 million in the third quarter of 2021. The increase was primarily due to increases of$1.7 million in compensation expense,$0.9 million in legal and professional fees, and$2.3 million in acquisition-related costs in the third quarter of 2022 as compared to the third quarter of 2021.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion ("DD&A") was $66.0 million
in the third quarter of 2022, compared to $35.9 million in the third quarter of
2021. Depletion expense, the largest component of DD&A, increased by $29.8
million in the third quarter of 2022 compared to the third quarter of 2021. The
aggregate increase in depletion expense was driven by a 37% increase in
production levels and a 34% increase in the depletion rate per Boe. On a per
unit basis, depletion expense was $8.95 per Boe in the third quarter of 2022
compared to $6.66 per Boe in the third quarter of 2021. The higher depletion
rate per Boe was primarily driven by the closing of our Comstock Acquisition in
the fourth quarter of 2021, coupled with our Veritas Acquisition in January 2022
and Incline Acquisition in August 2022 , which significantly increased our
depletable base. Depreciation, amortization and accretion was $0.8 million and
$0.6 million in the third quarter of 2022 and 2021, respectively. The following
table summarizes DD&A expense per Boe for the third quarter of 2022 and 2021:
Three Months Ended
2022 2021 $ Change % Change
Depletion $ 8.95 $ 6.66 $ 2.29 34 %
Depreciation, Amortization and Accretion 0.11 0.11 - - %
Total DD&A Expense $ 9.06 $ 6.77 $ 2.29 34 %
Interest Expense
Interest expense, net of capitalized interest, was $20.1 million in the third
quarter of 2022 compared to $14.6 million in the third quarter of 2021. The
increase was primarily due to higher levels of debt and higher weighted-average
interest rates associated with our revolving credit facility in the third
quarter of 2022 compared to the third quarter of 2021.
Gain (Loss) on the Extinguishment of Debt
During the third quarter of 2022, we recorded a gain on the extinguishment of debt of$0.3 million , based on the differences between the reacquisition costs of retiring the applicable debt and the net carrying values thereof. We did not record a gain (loss) on the extinguishment of debt during the third quarter of 2021. Income Tax During the third quarter of 2022, we recorded income tax expense of$1.3 million related to state income taxes. During the third quarter of 2021, no income tax expense (benefit) was recorded. We continue to maintain a full valuation allowance placed on our net deferred tax asset as ofSeptember 30, 2022 . We intend to continue maintaining a full valuation allowance on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of these allowances. Release of any portion of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense for the period the release is recorded. It is reasonably possible that sufficient positive evidence will exist within the next 12 months to release our current valuation allowance position which would be indicative of our ability to utilize deferred tax assets in the future. The exact timing and amount of the valuation allowance release are subject to change based on the evaluation of all evidence and actual results, including, but not limited to, the level of profitability that we are forecasted to achieve in future periods. For further discussion of our valuation allowance, see Note 9 to our condensed financial statements. 38
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Results of Operations for the Nine Months Ended
The following table sets forth selected operating data for the periods
indicated.
Nine Months Ended
2022 2021 % Change Net Production: Oil (Bbl) 11,775,526 8,795,802 34 % Natural Gas and NGLs (Mcf) 51,188,941 29,615,822 73 % Total (Boe) 20,307,016 13,731,772 48 %Net Sales (in thousands): Oil Sales$ 1,128,439 $ 523,150 116 % Natural Gas and NGL Sales 411,712 119,567 Gain (Loss) on Settled Commodity Derivatives (392,385) (91,470) Gain (Loss) on Unsettled Commodity Derivatives 52,390 (373,540) Total Revenues 1,200,156 177,709 Average Sales Prices: Oil (per Bbl) $ 95.83$ 59.48 61 %
Effect of Gain (Loss) on Settled Oil Derivatives on Average
Price (per Bbl)
(25.72) (7.97) Oil Net of Settled Oil Derivatives (per Bbl) 70.11 51.51 36 % Natural Gas and NGLs (per Mcf) 8.04 4.04 99 %
Effect of Gain (Loss) on Settled Natural Gas Derivatives on
Average Price (per Mcf)
(1.93) (0.72)
Natural Gas and NGLs Net of Settled Natural Gas Derivatives
(per Mcf)
6.11 3.32 84 %
Realized Price on a Boe Basis Excluding Settled Commodity
Derivatives
75.84 46.81 62 %
Effect of Gain (Loss) on Settled Commodity Derivatives on
Average Price (per Boe)
(19.32) (6.67)
Realized Price on a Boe Basis Including Settled Commodity
Derivatives
56.52 40.14 41 % Operating Expenses (in thousands): Production Expenses $ 187,659$ 120,246 56 % Production Taxes 120,729 51,899 133 % General and Administrative Expenses 32,155 19,878 62 % Depletion, Depreciation, Amortization and Accretion 173,956 98,013 77 % Costs and Expenses (per Boe): Production Expenses $ 9.24$ 8.76 5 % Production Taxes 5.95 3.78 57 % General and Administrative Expenses 1.58 1.45 9 % Depletion, Depreciation, Amortization and Accretion 8.57 7.14 20 % Net Producing Wells at Period End 761.2 601.8 26 %
Oil and Natural Gas Sales
In the first nine months of 2022, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was$1,540.2 million compared to$642.7 million in the first nine months of 2021, driven by a 48% increase in production and 62% increase in realized prices, excluding the effect of settled commodity derivatives. The higher average realized price in the first nine months of 2022 compared to the same period in 2021 was driven by higher average NYMEX oil 39 -------------------------------------------------------------------------------- Table of Contents prices and a lower oil price differential. Oil price differential during the first nine months of 2022 was$2.48 per barrel, as compared to$5.57 per barrel in the first nine months of 2021. The higher average realized price in the first nine months of 2022 as compared to the same period in 2021 was also driven by a$4.00 per Mcf increase in realized natural gas and NGL prices, excluding the effect of settled commodity derivatives, in the first nine months of 2022 compared to the same period of 2021. See "Market Conditions" above. 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. Acquisitions were a significant driver of our 48% increase in production levels in the first nine months of 2022 compared to the same period in 2021.
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 loss of$340.0 million in the first nine months of 2022, compared to a loss of$465.0 million in the first nine months of 2021. 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 the first nine months of 2022, we realized a loss on settled commodity derivatives of$392.4 million , compared to a$91.5 million loss in the first nine months of 2021. The higher loss on settled derivatives was primarily due to a significant increase in the average NYMEX oil price in the first nine months of 2022 compared to the same period of 2021. During the first nine months of 2022, our derivative settlements included 8.13 million barrels of oil at an average settlement price of$61.91 per barrel. During the first nine months of 2021, our settled commodity derivatives included 6.6 million barrels of oil at an average settlement price of$55.55 per barrel. The average NYMEX oil price for the first nine months of 2022 was$98.31 compared to$65.05 for the first nine months of 2021. Our average realized price (including all commodity derivative cash settlements) in the first nine months of 2022 was$56.52 per Boe compared to$40.14 per Boe in the first nine months of 2021. The gain (loss) on settled commodity derivatives decreased our average realized price per Boe by$19.32 in the first nine months of 2022 and decreased our average realized price per Boe by$6.67 in the first nine months of 2021. Unsettled commodity derivative gains and losses was a loss of$52.4 million in the first nine months of 2022, compared to a loss of$373.5 million in the first nine months of 2021. 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 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. AtSeptember 30, 2022 , all of our derivative contracts are recorded at their fair value, which was a net liability of$223.5 million , a change of$54.2 million from the$277.7 million net liability recorded as ofDecember 31, 2021 . The decreased liability atSeptember 30, 2022 as compared toDecember 31, 2021 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts sinceDecember 31, 2021 . Our open commodity derivative contracts are summarized in "Item 3. Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk." Production Expenses Production expenses were$187.7 million in the second quarter of 2022, compared to$120.2 million in the first nine months of 2021. On a per unit basis, production expenses were$9.24 per Boe in the first nine months of 2022, compared to$8.76 per Boe in the first nine months of 2021. The increase was primarily due to a$5.4 million firm transport charge on ourAppalachian Basin properties and higher processing costs, which were largely offset by a 48% increase in our production volumes, which increased the production base over which fixed costs are spread. On an absolute dollar basis, the increase in our production expenses in the first nine months of 2022, as compared to the first nine months of 2021, was primarily due to a 48% increase in production volumes and a 26% increase in the total number of net producing wells and the aforementioned firm transport charge and higher processing costs. 40 -------------------------------------------------------------------------------- Table of Contents Production Taxes We pay production taxes based on realized oil and natural gas sales. Production taxes were$120.7 million in the first nine months of 2022 compared to$51.9 million in the first nine months of 2021. The increase is due to higher production and higher realized prices, which significantly increased our oil and natural gas sales in the first nine months of 2022 as compared to the first nine months of 2021. As a percentage of oil and natural gas sales, our production taxes were 7.8% and 8.1% in the first nine months of 2022 and 2021, 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$32.2 million in the first nine months of 2022 compared to$19.9 million in the first nine months of 2021. The increase was primarily due to increases of$4.6 million in compensation costs,$4.1 million in acquisition-related costs, and$2.3 million of professional fees in the first nine months of 2022 compared to the first nine months of of 2021.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion ("DD&A") was $174.0 million
in the first nine months of 2022, compared to $98.0 million in the first nine
months of 2021. Depletion expense, the largest component of DD&A, increased by
$75.3 million in the first nine months of 2022 compared to the first nine months
of 2021. The aggregate increase in depletion expense was driven by a 48%
increase in production levels and a 20% increase in the depletion rate per Boe.
On a per unit basis, depletion expense was $8.46 per Boe in the first nine
months of 2022 compared to $7.03 per Boe in the first nine months of 2021. The
higher depletion rate per Boe was primarily driven by the closing of our CM
Resources Acquisition and Comstock Acquisitions in the second half of 2021,
coupled with our Veritas Acquisition in January 2022 and Incline Acquisition in
August 2022 , which significantly increased our depletable base. Depreciation,
amortization and accretion was $2.2 million and $1.5 million in the first nine
months of 2022 and 2021, respectively. The following table summarizes DD&A
expense per Boe for the first nine months of 2022 and 2021:
Nine Months Ended
2022 2021 $ Change % Change
Depletion $ 8.46 $ 7.03 $ 1.43 20 %
Depreciation, Amortization and Accretion 0.11 0.11 - - %
Total DD&A Expense $ 8.57 $ 7.14 $ 1.43 20 %
Interest Expense
Interest expense, net of capitalized interest, was $56.5 million in the first
nine months of 2022 compared to $43.1 million in the first nine months of 2021.
The increase was primarily due to higher levels of debt in the first nine months
of 2022 compared to the first nine months of 2021.
Gain (Loss) on the Extinguishment of Debt
During the first nine months of 2022, we recorded a gain on the extinguishment of debt of$0.6 million based on the differences between the reacquisition costs of retiring the applicable debt and the net carrying values thereof. As a result of our refinancing transactions during the first nine months of 2021, we recorded a loss on the extinguishment of debt of$13.1 million based on the differences between the reacquisition costs of retiring the applicable debt and the net carrying values thereof.
Income Tax
During the first nine months of 2022, we recorded income tax expense of$3.1 million related to state income taxes. During the first nine months of 2021, no income tax expense (benefit) was recorded. We continue to maintain a full valuation allowance placed on our net deferred tax asset as ofSeptember 30, 2022 . We intend to continue maintaining a full valuation allowance on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of these allowances. Release of any portion of the valuation allowance 41 -------------------------------------------------------------------------------- Table of Contents would result in the recognition of certain deferred tax assets and a decrease to income tax expense for the period the release is recorded. It is reasonably possible that sufficient positive evidence will exist within the next 12 months to release our current valuation allowance position which would be indicative of our ability to utilize deferred tax assets in the future. The exact timing and amount of the valuation allowance release are subject to change based on the evaluation of all evidence and actual results, including, but not limited to, the level of profitability that we are forecasted to achieve in future periods. For further discussion of our valuation allowance, see Note 9 to our condensed financial statements. 42
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Table of Contents
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 and development of our oil and natural gas properties and cash settlements of commodity derivative instruments. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position. During the nine months endedSeptember 30, 2022 , we repurchased and retired (i) 575,000 shares of our 6.500% Series A Perpetual Cumulative Convertible Preferred Stock (the "Series A Preferred Stock") for total consideration of$81.2 million , (ii) 805,919 shares of our common stock for total consideration of$21.5 million and (iii)$20.4 million aggregate principal amount of our 2028 Notes for total consideration of$19.8 million , plus accrued interest. As ofSeptember 30, 2022 , we had outstanding debt consisting of$441.0 million of borrowings under our Revolving Credit Facility and$729.6 million aggregate principal amount of our 2028 Notes. We had total liquidity of$418.1 million as ofSeptember 30, 2022 , consisting of$409.0 million of committed borrowing availability under the Revolving Credit Facility and$9.1 million of cash on hand. InOctober 2022 , after the end of the three months endedSeptember 30, 2022 , we issued$500.0 million in aggregate principal amount of 3.625% convertible senior notes due 2029 (the "Convertible Notes"), the proceeds of which were used to pay down outstanding borrowings under our Revolving Credit Facility and for other general corporate purposes (see Note 12 to our condensed financial statements). The debt pay down creates additional borrowing capacity under our Revolving Credit Facility, and we expect to use a portion of that borrowing capacity to fund the purchase price for recently-announcedPermian Basin acquisitions that we currently expect to close inDecember 2022 andJanuary 2023 . One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 57% and 59% of our total production volumes in the third quarter of 2022 and 2021, 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 a robust hedging program to mitigate volatility in commodity prices with respect to a portion of our expected production. For the nine months endedSeptember 30, 2022 , we hedged approximately 61% of our production. For a summary as ofSeptember 30, 2022 , of our open commodity price derivative contracts for future periods, see "Quantitative and Qualitative Disclosures about Market Risk" in Part I, Item 3 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. 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. AtSeptember 30, 2022 , we had a working capital deficit of$5.1 million , compared to a deficit of$112.2 million atDecember 31, 2021 . Current assets increased by$161.4 million and current liabilities increased by$54.2 million atSeptember 30, 2022 , compared toDecember 31, 2021 . The increase in current assets is primarily due to a$124.6 million increase in our accounts receivable due to higher commodity prices and higher production. The change in current liabilities is 43 -------------------------------------------------------------------------------- Table of Contents primarily due to a$86.5 million increase in our accounts payable and accrued liabilities due in part to increased completion activity levels on our properties, which was partially offset by a$20.9 million decrease in our derivative instruments.
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. The Company typically enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future oil and gas production for the next 12 to 36 months. Our cash flows for the nine months endedSeptember 30, 2022 and 2021 are presented below: Nine Months Ended September 30, (In thousands, unaudited) 2022 2021
Net Cash Provided by Operating Activities
Net Cash Provided by Financing Activities 217,112 102,029
Net Change in Cash
$ (390) $ 578
Cash Flows from Operating Activities
Net cash provided by operating activities for the nine months endedSeptember 30, 2022 was$641.0 million , compared to$263.4 million in the same period of the prior year. This increase was due to higher production volumes and higher realized commodity prices (including the effect of settled derivatives), which was partially offset by higher operating costs and interest costs, as well as changes in working capital. Net cash provided by operating activities is 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 nine months endedSeptember 30, 2022 was a deficit of$115.4 million compared to a deficit of$60.9 million in the same period of the prior year.
Cash Flows from Investing Activities
Cash flows used in investing activities during the nine months endedSeptember 30, 2022 and 2021 were$858.5 million and$364.8 million , respectively. The increase in cash used in investing activities for the first nine months of 2022 as compared to the same period of 2021 was attributable to a$461.0 million increase in our development and acquisition spending, which included the closing of our Veritas Acquisition in the first quarter of 2022 and our Incline Acquisition in the third quarter of 2022. Additionally, the amount of capital expenditures included in accounts payable (and thus not included in cash flows from investing activities) was$164.2 million and$111.9 million atSeptember 30, 2022 and 2021, respectively. 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 nine months endedSeptember 30, 2022 , our capitalized costs incurred for oil and natural gas properties (e.g., drilling and completion costs, acquisitions, and other capital expenditures) amounted to$929.8 million , while the actual cash spend in this regard amounted to$825.5 million . Development and acquisition activities are discretionary. We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and returns. Our cash spend for development and acquisition activities for the nine months endedSeptember 30, 2022 and 2021 are summarized in the following table: Nine Months Ended September 30, (In millions, unaudited) 2022 2021 Drilling and Development Capital Expenditures$ 270.4 $ 116.7 Acquisition of Oil and Natural Gas Properties 551.5 246.3 Other Capital Expenditures 3.6 1.5 Total$ 825.5 $ 364.5 44
-------------------------------------------------------------------------------- Table of Contents Cash Flows from Financing Activities Net cash provided by financing activities was$217.1 million during the nine months endedSeptember 30, 2022 , compared to net cash provided by financing activities of$102.0 million during the nine months endedSeptember 30, 2021 . For the nine months endedSeptember 30, 2022 , cash provided by financing activities was primarily related to$386.0 million of net advances under our Revolving Credit Facility, which was partially offset by$81.2 million in repurchases of preferred stock,$21.5 million in repurchases of common stock,$19.8 million in repurchases of senior unsecured notes,$32.0 million of common stock dividend payments, and$5.9 million of preferred stock dividend payments. For the nine months endedSeptember 30, 2021 , cash provided by financing activities was primarily related to the net proceeds of our 2028 Notes of$537.6 million and equity offerings of$228.2 million , partially offset by$295.9 million in repurchases of Second Lien Notes, net repayments under our Revolving Credit Facility of$213.0 million and the retirement of VEN Bakken Note for$130.0 million .
Revolving Credit Facility
InJune 2022 , we entered into the Revolving Credit Facility withWells Fargo Bank , as administrative agent, and the lenders from time to time party thereto, which amended and restated our existing revolving credit facility that was entered into inNovember 2019 . 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 ofSeptember 30, 2022 , the Revolving Credit Facility had a borrowing base of$1.3 billion and an elected commitment amount of$850.0 million , and we had$441.0 million in borrowings outstanding under the facility, leaving$409.0 million in available committed borrowing capacity. See Note 4 to our condensed financial statements for further details regarding the Revolving Credit Facility.
Unsecured Notes due 2028
As ofSeptember 30, 2022 , we had$729.6 million outstanding aggregate principal amount of our 2028 Notes. See Note 4 to our condensed financial statements for further details regarding the 2028 Notes.
Series A Preferred Stock
As ofSeptember 30, 2022 , we had 1,643,732 outstanding shares of 6.500% Series A Perpetual Cumulative Convertible Preferred Stock (the "Series A Preferred Stock"), having an aggregate liquidation preference of$164.4 million (excluding accumulated dividends). OnNovember 8, 2022 , we exercised in full our mandatory conversion rights on the Series A Preferred Stock. All outstanding shares of Series A Preferred Stock will automatically convert into shares of common stock onNovember 15, 2022 . See Note 5 and Note 12 to our condensed financial statements for further details regarding the Series A Preferred Stock and the mandatory conversion.
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. Higher prices for oil and natural gas have resulted in increases in the costs of materials, services and personnel in 2022 compared to 2021.
Contractual Obligations and Commitments
Please see our disclosure of contractual obligations and commitments as of
for the fiscal year ended
45 -------------------------------------------------------------------------------- Table of Contents Critical Accounting Estimates Critical accounting estimates are those estimates made in accordance with GAAP that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on our financial condition or results of operations. Our critical accounting estimates include impairment testing of natural gas and crude oil production properties, asset retirement obligations, revenue recognition, derivative instruments and hedging activity, and income taxes. There were no material changes in our critical accounting estimates from those reported in our Annual Report on Form 10-K for the fiscal year endedDecember 31, 2021 .
A description of our critical accounting policies, including estimates, was
provided in Note 2 to our financial statements provided in Part II, Item 8 of
our Annual Report on Form 10-K for the fiscal year ended
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