# Northern Oil & Gas, Inc.: Form 10-Q for the period ended Sep 30, 2023

- Company: [Northern Oil & Gas, Inc.](/companies/nog.md) (CIK 1104485)
- Form: 10-Q
- Filed: 2023-11-02
- Accepted by EDGAR: Nov 2, 2023, 16:16 ET
- Period: 2023-09-30
- Accession: 0001104485-23-000188
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1104485/000110448523000188/nog-20230930.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1104485/000110448523000188/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2023-09-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2023-07-01 to 2023-09-30 | $314.0m | us-gaap:Revenues |
| Revenue | 9 months, 2023-01-01 to 2023-09-30 | $1.37bn | us-gaap:Revenues |
| Cost of revenue | 3 months, 2023-07-01 to 2023-09-30 | $82.5m | us-gaap:CostOfGoodsAndServicesSold |
| Cost of revenue | 9 months, 2023-01-01 to 2023-09-30 | $244.9m | us-gaap:CostOfGoodsAndServicesSold |
| Operating income | 3 months, 2023-07-01 to 2023-09-30 | $42.4m | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2023-01-01 to 2023-09-30 | $637.8m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2023-07-01 to 2023-09-30 | $37.0m | us-gaap:InterestExpense |
| Interest expense | 9 months, 2023-01-01 to 2023-09-30 | $99.2m | us-gaap:InterestExpense |
| Income tax | 3 months, 2023-07-01 to 2023-09-30 | −$20.7m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 9 months, 2023-01-01 to 2023-09-30 | $19.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2023-07-01 to 2023-09-30 | $26.1m | us-gaap:NetIncomeLoss |
| Net income | 9 months, 2023-01-01 to 2023-09-30 | $534.1m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2023-07-01 to 2023-09-30 | $0.28 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 9 months, 2023-01-01 to 2023-09-30 | $5.97 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2023-07-01 to 2023-09-30 | $0.28 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 9 months, 2023-01-01 to 2023-09-30 | $6.01 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2023-07-01 to 2023-09-30 | 93,742,407 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 9 months, 2023-01-01 to 2023-09-30 | 89,449,731 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 9 months, 2023-01-01 to 2023-09-30 | $841.0m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Dividends paid | 9 months, 2023-01-01 to 2023-09-30 | $88.7m | us-gaap:PaymentsOfDividendsCommonStock |
| Share repurchases | 9 months, 2023-01-01 to 2023-09-30 | $8.0m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2023-09-30 | $13.0m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2023-09-30 | $469.6m | us-gaap:AssetsCurrent |
| Total assets | at 2023-09-30 | $4.30bn | us-gaap:Assets |
| Current liabilities | at 2023-09-30 | $602.5m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2023-09-30 | $2.90bn | us-gaap:Liabilities |
| Long-term debt | at 2023-09-30 | $2.06bn | us-gaap:LongTermDebt |
| Shareholders' equity | at 2023-09-30 | $1.41bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 55,363 characters.

### 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;
- risks associated with our Convertible Notes, including the potential impact that the Convertible Notes may have on our financial position and liquidity, potential dilution, and that provisions of the Convertible Notes could delay or prevent a beneficial takeover of our company;
- the potential impact of the capped call transactions undertaken in tandem with the Convertible Notes issuance, including counterparty risk;
- increasing attention to environmental, social and governance matters;
- 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-incidents could have a material adverse effect on our business, financial condition or results of operations;
- changes in accounting principles, policies or guidelines;
- events beyond our control, including a global or domestic health crisis, acts of terrorism, political or economic instability or armed conflict in oil and gas producing regions; 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 ended December 31, 2022, as updated by subsequent reports we file with the SEC (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 within the United States. Using this strategy, we had participated in 9,489 gross (923.7 net) producing wells as of September 30, 2023. As of September 30, 2023, we had leased approximately 272,397 net acres, of which approximately 89% were developed and all were located in the 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 the Williston Basin. We first expanded beyond the Williston Basin in 2020, with several small acquisitions in the Permian Basin. In 2021 and 2022, we accelerated our diversification outside the Williston Basin via larger acquisitions, including the acquisition of significant producing natural gas properties in the Appalachian Basin and several acquisitions in the Permian Basin. We have also added to our legacy position in the Williston Basin via larger acquisitions. See Note 3 to our condensed financial statements for further details regarding our recent acquisition activity.

Our average daily production in the third quarter of 2023 was approximately 102,327 Boe per day, of which approximately 62% was oil. This was a 29% increase in production compared to the third quarter of 2022, primarily due to production attributable to recent acquisitions and new wells added to production. During the three months ended September 30, 2023, we added 22.6 net wells to production (excluding wells producing at closing of the Novo Acquisition and in-quarter ground game acquisitions).

Our percentage of production volumes by basin for the three months ended September 30, 2023 and 2022 were as follows:

|  | Three Months Ended September 30, 2023 Williston | Permian | Appalachian | Total | Three Months Ended September 30, 2022 Williston | Permian | Appalachian | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Oil (Bbl) | 55% | 45% | —% | 100% | 71% | 29% | —% | 100% |
| Natural Gas and NGLs (Mcf) | 37% | 36% | 27% | 100% | 40% | 21% | 39% | 100% |
| Total (Boe) | 48% | 42% | 10% | 100% | 57% | 26% | 17% | 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 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 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 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, 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 2023 was $2.84 per barrel, as compared to $0.84 per barrel in the third quarter of 2022. Our net realized gas price in the third quarter of 2023 was $2.19 per Mcf, representing 82% realization relative to average Henry Hub pricing, compared to a net realized gas price of $8.43 per Mcf in the third quarter of 2022, which represented 106% 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 the first nine months of 2023, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $9.4 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 three and nine months ended September 30, 2023 and 2022.

| Average NYMEX Prices(1) | Three Months Ended September 30, 2023 | 2022 |
| --- | ---: | ---: |
| Natural Gas (per Mcf) | $2.66 | $7.95 |
| Oil (per Bbl) | $82.32 | $91.38 |

(1) Based on average NYMEX closing prices.

| Average NYMEX Prices(1) | Nine Months Ended September 30, 2023 | 2022 |
| --- | ---: | ---: |
| Natural Gas (per Mcf) | $2.58 | $6.71 |
| Oil (per Bbl) | $77.33 | $98.31 |

(1) Based on average NYMEX closing prices.

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 September 30, 2023, 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 our condensed financial statements.

### Results of Operations for the Three Months Ended September 30, 2023 and September 30, 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.

| Net Production: | Three Months Ended September 30, 2023 | 2022 | % Change |
| --- | ---: | ---: | ---: |
| Oil (Bbl) | 5,847,894 | 4,149,841 | 41% |
| Natural Gas and NGLs (Mcf) | 21,396,966 | 18,776,821 | 14% |
| Total (Boe) | 9,414,055 | 7,279,311 | 29% |
| **Net Sales (in thousands):** |  |  |  |
| Oil Sales | 464,793 | 375,732 | 24% |
| Natural Gas and NGL Sales | 46,858 | 158,318 | (70)% |
| Gain (Loss) on Settled Commodity Derivatives | 5,164 | (124,911) |  |
| Gain (Loss) on Unsettled Commodity Derivatives | (204,712) | 382,501 |  |
| Other Revenue | 1,870 | — |  |
| Total Revenues | 313,973 | 791,640 | (60)% |
| **Average Sales Prices:** |  |  |  |
| Oil (per Bbl) | $79.48 | $90.54 | (12)% |
| Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl) | (2.58) | (19.12) |  |
| Oil Net of Settled Oil Derivatives (per Bbl) | 76.90 | 71.42 | 8% |
| Natural Gas and NGLs (per Mcf) | 2.19 | 8.43 | (74)% |
| Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf) | 0.95 | (2.43) |  |
| Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf) | 3.14 | 6.00 | (48)% |
| Realized Price on a Boe Basis Excluding Settled Commodity Derivatives | 54.35 | 73.37 | (26)% |
| Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) | 0.55 | (17.16) |  |
| Realized Price on a Boe Basis Including Settled Commodity Derivatives | 54.90 | 56.21 | (2)% |
| **Operating Expenses (in thousands):** |  |  |  |
| Production Expenses | $82,506 | $68,478 | 20% |
| Production Taxes | 42,158 | 42,273 | —% |
| General and Administrative Expenses | 11,846 | 10,278 | 15% |
| Depletion, Depreciation, Amortization and Accretion | 133,791 | 65,975 | 103% |
| Other Expense | 1,235 | — |  |
| **Costs and Expenses (per Boe):** |  |  |  |
| Production Expenses | $8.76 | $9.41 | (7)% |
| Production Taxes | 4.48 | 5.81 | (23)% |
| General and Administrative Expenses | 1.26 | 1.41 | (11)% |
| Depletion, Depreciation, Amortization and Accretion | 14.21 | 9.06 | 57% |
| **Net Producing Wells at Period End** | 923.7 | 761.2 | 21% |

38

#### Oil and Natural Gas Sales

In the third quarter of 2023, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was $511.7 million, compared to $534.1 million in the third quarter of 2022. This 4% reduction was driven by a 26% decrease in realized prices, excluding the effect of settled commodity derivatives, partially offset by a 29% increase in production volumes. The lower average realized price in the third quarter of 2023 as compared to the same period in 2022 was driven by a $6.24 per Mcf (or 74%) decrease in realized natural gas and NGL prices, excluding the effect of settled commodity derivatives, in the third quarter of 2023 compared to the same period of 2022. The lower average realized price in the third quarter of 2023 compared to the same period in 2022 was also driven by 12% lower average NYMEX oil prices and a higher average oil price differential. Oil price differential during the third quarter of 2023 was $2.84 per barrel, as compared to $0.84 per barrel in the third quarter of 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. Acquisitions were a significant driver of our 29% increase in production levels in the third quarter of 2023 compared to the same period of 2022.

#### 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 $199.5 million in the third quarter of 2023, compared to a gain of $257.6 million in the third quarter of 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 the third quarter of 2023, we realized a gain on settled commodity derivatives of $5.2 million, compared to a $124.9 million loss in the third quarter of 2022. The increased gain on settled derivatives was primarily due to a significant decrease in the average NYMEX oil price in the third quarter of 2023 compared to the same period of 2022. The average NYMEX oil price for the third quarter of 2023 was $82.32 per barrel, compared to $91.38 per barrel for the third quarter of 2022. During the third quarter of 2023, our derivative settlements included 1.9 million barrels of oil at an average settlement price of $76.73 per barrel. During the third quarter of 2022, our settled commodity derivatives included 2.8 million barrels of oil at an average settlement price of $63.88 per barrel. Our average realized price (including all commodity derivative cash settlements) in the third quarter of 2023 was $54.90 per Boe compared to $56.21 per Boe in the third quarter of 2022. The gain (loss) on settled commodity derivatives increased our average realized price per Boe by $0.55 in the third quarter of 2023 and decreased our average realized price per Boe by $17.16 in the third quarter of 2022.

Unsettled commodity derivative gains and losses was a loss of $204.7 million in the third quarter of 2023, compared to a gain of $382.5 million in the third quarter of 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 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 September 30, 2023, all of our derivative contracts are recorded at their fair value, which was a net liability of $271.7 million, a change of $35.2 million from the $236.5 million net liability recorded as of December 31, 2022. The increase in liability at September 30, 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 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

#### Production Expenses

Production expenses were $82.5 million in the third quarter of 2023, compared to $68.5 million in the third quarter of 2022. On a per unit basis, production expenses were $8.76 per Boe in the third quarter of 2023 compared to $9.41 per Boe in the third quarter of 2022. The lower production expenses per Boe was driven by decreased salt water disposal costs and workover expenses in the third quarter of 2023 compared to the third quarter of 2022. On an absolute dollar basis, the increase in our production expenses in the third quarter of 2023 compared to the third quarter of 2022 was primarily due to a 29% increase in production volumes and a 21% increase in the total number of net producing wells .

#### Production Taxes

We pay production taxes based on realized oil and natural gas sales. Production taxes were $42.2 million in the third quarter of 2023, compared to $42.3 million in the third quarter of 2022. As a percentage of oil and natural gas sales, our production taxes were 8.2% and 7.9% in the third quarter of 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 $11.8 million in the third quarter of 2023 compared to $10.3 million in the third quarter of 2022. The increase was primarily due to a $0.5 million increase in acquisition-related costs in the third quarter of 2023 as compared to the third quarter of 2022, coupled with an increase of $1.0 million in professional fees and other.

#### Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation, amortization and accretion (“DD&A”) was $133.8 million in the third quarter of 2023, compared to $66.0 million in the third quarter of 2022. Depletion expense, the largest component of DD&A, increased by $67.7 million in the third quarter of 2023 compared to the third quarter of 2022. The aggregate increase in depletion expense was driven by a 29% increase in production levels and a 58% increase in the depletion rate per Boe. On a per unit basis, depletion expense was $14.11 per Boe in the third quarter of 2023 compared to $8.95 per Boe in the third quarter of 2022. The higher depletion rate per Boe was primarily driven by a significant increase to our depletable base, due to the closing of several larger acquisitions in 2022 and 2023 (see Note 3 to our condensed financial statements). Depreciation, amortization and accretion was $1.0 million and $0.8 million in the third quarter of 2023 and 2022, respectively. The following table summarizes DD&A expense per Boe for the third quarter of 2023 and 2022:

|  | Three Months Ended September 30, 2023 | 2022 | $ Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Depletion | $14.11 | $8.95 | $5.16 | 58% |
| Depreciation, Amortization and Accretion | 0.10 | 0.11 | (0.01) | (9)% |
| Total DD&A Expense | $14.21 | $9.06 | $5.15 | 57% |

#### Interest Expense

Interest expense, net of capitalized interest, was $37.0 million in the third quarter of 2023 compared to $20.1 million in the third quarter of 2022. The increase was primarily due to higher levels of debt outstanding during the third quarter of 2023 compared to the third quarter of 2022. Additionally, higher interest rates on our floating rate debt contributed to higher interest expense in the third quarter of 2023 compared to the third quarter of 2022.

#### Income Taxes

During the third quarter of 2023, we recorded income tax benefit of $20.7 million related to federal and state income taxes as a result of the release of our valuation allowance in the second quarter of 2023. During the third quarter of 2022, we recorded income tax expense of $1.3 million related to state income taxes as the Company maintained a full valuation allowance for its deferred tax assets.

### Results of Operations for the Nine Months Ended September 30, 2023 and September 30, 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.

| Net Production: | Nine Months Ended September 30, 2023 | 2022 | % Change |
| --- | ---: | ---: | ---: |
| Oil (Bbl) | 15,676,829 | 11,775,526 | 33% |
| Natural Gas and NGLs (Mcf) | 59,230,464 | 51,188,941 | 16% |
| Total (Boe) | 25,548,573 | 20,307,016 | 26% |
| **Net Sales (in thousands):** |  |  |  |
| Oil Sales | $1,174,006 | $1,128,439 | 4% |
| Natural Gas and NGL Sales | 180,370 | 411,712 | (56)% |
| Gain (Loss) on Settled Commodity Derivatives | 46,099 | (392,385) |  |
| Gain (Loss) on Unsettled Commodity Derivatives | (34,222) | 52,390 |  |
| Other Revenue | 6,488 | — |  |
| Total Revenues | 1,372,742 | 1,200,156 | 14% |
| **Average Sales Prices:** |  |  |  |
| Oil (per Bbl) | $74.89 | $95.83 | (22)% |
| Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl) | (0.92) | (25.72) |  |
| Oil Net of Settled Oil Derivatives (per Bbl) | 73.97 | 70.11 | 6% |
| Natural Gas and NGLs (per Mcf) | 3.05 | 8.04 | (62)% |
| Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf) | 1.02 | (1.93) |  |
| Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf) | 4.07 | 6.11 | (33)% |
| Realized Price on a Boe Basis Excluding Settled Commodity Derivatives | 53.01 | 75.84 | (30)% |
| Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) | 1.80 | (19.32) |  |
| Realized Price on a Boe Basis Including Settled Commodity Derivatives | 54.81 | 56.52 | (3)% |
| **Operating Expenses (in thousands):** |  |  |  |
| Production Expenses | $244,944 | $187,659 | 31% |
| Production Taxes | 114,215 | 120,729 | (5)% |
| General and Administrative Expenses | 37,248 | 32,155 | 16% |
| Depletion, Depreciation, Amortization and Accretion | 334,836 | 173,956 | 92% |
| Other Expense | 3,681 | — |  |
| **Costs and Expenses (per Boe):** |  |  |  |
| Production Expenses | $9.59 | $9.24 | 4% |
| Production Taxes | 4.47 | 5.95 | (25)% |
| General and Administrative Expenses | 1.46 | 1.58 | (8)% |
| Depletion, Depreciation, Amortization and Accretion | 13.11 | 8.57 | 53% |
| **Net Producing Wells at Period End** | 923.7 | 761.2 | 21% |

41

#### Oil and Natural Gas Sales

In the first nine months of 2023, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was $1,354.4 million, compared to $1,540.2 million in the first nine months of 2022. This 12.0% reduction was driven by a 30% decrease in realized prices, excluding the effect of settled commodity derivatives, partially offset by a 26% increase in production volumes. The lower average realized price in the first nine months of 2023 as compared to the same period in 2022 was driven by a $4.99 per Mcf (or 62%) decrease in realized natural gas and NGL prices, excluding the effect of settled commodity derivatives, in the first nine months of 2023 compared to the same period of 2022. The lower average realized price in the first nine months of 2023 compared to the same period in 2022 was also driven by 22% lower average NYMEX oil and natural gas prices, partially offset by a lower average oil price differential. Oil price differential during the first nine months of 2023 was $2.44 per barrel, as compared to $2.48 per barrel in the first nine months of 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. Acquisitions were a significant driver of our 26% increase in production levels in the first nine months of 2023 compared to the same period of 2022.

#### 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 $11.9 million in the first nine months of 2023, compared to a loss of $340.0 million in the first nine months of 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 the first nine months of 2023, we realized a gain on settled commodity derivatives of $46.1 million, compared to a $392.4 million loss in the first nine months of 2022. The increased gain on settled derivatives was primarily due to a significant decrease in the average NYMEX oil price in the first nine months of 2023 compared to the same period of 2022. The average NYMEX oil price for the first nine months of 2023 was $77.33 per barrel, compared to $98.31 per barrel for the first nine months of 2022. During the first nine months of 2023, our derivative settlements included 6.1 million barrels of oil at an average settlement price of $74.92 per barrel. During the first nine months of 2022, our settled commodity derivatives included 8.1 million barrels of oil at an average settlement price of $61.91 per barrel. Our average realized price (including all commodity derivative cash settlements) in the first nine months of 2023 was $54.81 per Boe compared to $56.52 per Boe in the first nine months of 2022. The gain (loss) on settled commodity derivatives increased our average realized price per Boe by $1.80 in the first nine months of 2023 and decreased our average realized price per Boe by $19.32 in the first nine months of 2022.

Unsettled commodity derivative gains and losses was a loss of $34.2 million in the first nine months of 2023, compared to a gain of $52.4 million in the first nine months of 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 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 September 30, 2023, all of our derivative contracts are recorded at their fair value, which was a net liability of $271.7 million, a change of $35.2 million from the $236.5 million net liability recorded as of December 31, 2022. The increase in liability at September 30, 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 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

#### Production Expenses

Production expenses were $244.9 million in the first nine months of 2023, compared to $187.7 million in the first nine months of 2022. On a per unit basis, production expenses were $9.59 per Boe in the first nine months of 2023 compared to $9.24 per Boe in the first nine months of 2022. The higher production expense was driven by increased service and maintenance costs and higher workover expenses per Boe in the first nine months of 2023. On an absolute dollar basis, the increase in our production expenses in the first nine months of 2023 compared to the first nine months of 2022 was primarily due to a 26% increase in production volumes, a 21% 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 $114.2 million in the first nine months of 2023, compared to $120.7 million in the first nine months of 2022. As a percentage of oil and natural gas sales, our production taxes were 8.4% and 7.8% in the first nine months of 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 $37.2 million in the first nine months of 2023 compared to $32.2 million in the first nine months of 2022. The increase was primarily due to increases of $2.0 million in compensation expense and $1.9 million in professional fees in the first nine months of 2023 as compared to the first nine months of 2022.

#### Depletion, Depreciation, Amortization and Accretion

DD&A was $334.8 million in the first nine months of 2023, compared to $174.0 million in the first nine months of 2022. Depletion expense, the largest component of DD&A, increased by $160.3 million in the first nine months of 2023 compared to the first nine months of 2022. The aggregate increase in depletion expense was driven by a 26% increase in production levels and a 54% increase in the depletion rate per Boe. On a per unit basis, depletion expense was $13.00 per Boe in the first nine months of 2023 compared to $8.46 per Boe in the first nine months of 2022. The higher depletion rate per Boe was primarily driven by a significant increase to our depletable base, due to the closing of several larger acquisitions in the second half of 2022 and the the first nine months of 2023 (see Note 3 to our condensed financial statements). Depreciation, amortization and accretion was $2.7 million and $2.2 million in the first nine months of 2023 and 2022, respectively. The following table summarizes DD&A expense per Boe for the first nine months of 2023 and 2022:

|  | Nine Months Ended September 30, 2023 | 2022 | $ Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Depletion | $13.00 | $8.46 | $4.54 | 54% |
| Depreciation, Amortization and Accretion | 0.11 | 0.11 | — | —% |
| Total DD&A Expense | $13.11 | $8.57 | $4.54 | 53% |

#### Interest Expense

Interest expense, net of capitalized interest, was $99.2 million in the first nine months of 2023 compared to $56.5 million in the first nine months of 2022. The increase was primarily due to higher levels of debt outstanding during the first nine months of 2023 compared to the first nine months of 2022. Additionally, higher interest rates on our floating rate debt contributed to higher interest expense in the first nine months of 2023 compared to the first nine months of 2022.

#### Income Taxes

During the first nine months of 2023, we recorded income tax expense of $19.0 million related to federal and state income taxes as a result of the release of our valuation allowance during the period. During the first nine months of 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 the first nine months of 2023 was 3.4% compared to an effective tax rate of 0.5% for the first nine months of 2022. The difference was due primarily to the release of our full valuation allowance 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, and credit facility borrowings. Our primary uses of capital have been for the acquisition, development and operation of our oil and natural gas properties and for shareholder returns. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

In January 2023, we completed the MPDC Acquisition for total cash consideration of $319.9 million, in June 2023 we completed the Forge Acquisition for total cash consideration of $167.9 million, and in August 2023 we completed the Novo Acquisition for total cash consideration of $468.4 million (see Note 3 to our condensed financial statements).

During the first nine months of 2023, to finance the foregoing acquisitions, reduce borrowings under our Revolving Credit Facility, and maintain a strong balance sheet, we completed a $224.7 million common stock offering and issued $500.0 million aggregate principal amount of Senior Notes due 2031. In addition, subsequent to September 30, 2023, we completed an offering of common stock resulting in proceeds of $290.6 million to the Company, before offering expenses, to further reduce borrowings under our Revolving Credit Facility (see Note 12 to our condensed financial statements).

During the nine months ended September 30, 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 interest.

As of September 30, 2023, we had outstanding total debt of $2,089.1 million consisting of $384.0 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 Senior Notes due 2031, and $500.0 million aggregate principal amount of our Convertible Notes.

As of September 30, 2023, we had total liquidity of $879.0 million, consisting of $866.0 million of committed borrowing availability under the Revolving Credit Facility and $13.0 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 91% and 70% of our total oil and gas sales in the third quarter of 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 a robust hedging program to mitigate volatility in commodity prices with respect to a portion of our expected production. For the nine months ended September 30, 2023, we hedged approximately 65% of our crude oil production and approximately 64% of our natural gas and NGL production. For a summary as of September 30, 2023, 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 and, based on current expectations, for the long term. 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 September 30, 2023, we had a working capital deficit of $132.9 million, compared to a deficit of $24.5 million at December 31, 2022. Current assets increased by $149.1 million and current liabilities increased by $257.5 million at September 30, 2023, compared to December 31, 2022. The increase in current assets is due to a $29.9 million increase in fair value of our derivative instruments as a result of commodity price changes and an increase of $92.2 million in accounts receivable. The increase in current liabilities is primarily related to a $139.7 million increase in our accounts payable and accrued liabilities due in part to increased completion activity levels on our properties and a $117.9 million increase in our derivative instruments as a result of the decrease in fair value.

### 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 36 months. Our cash flows for the nine months ended September 30, 2023 and 2022 are presented below:

*(In thousands, unaudited)*

|  | Nine Months Ended September 30, 2023 | 2022 |
| --- | ---: | ---: |
| Net Cash Provided by Operating Activities | $840,959 | $641,039 |
| Net Cash Used for Investing Activities | (1,484,203) | (858,542) |
| Net Cash Provided by Financing Activities | 653,668 | 217,112 |
| Net Change in Cash | $10,424 | $(390) |

#### Cash Flows from Operating Activities

Net cash provided by operating activities for the nine months ended September 30, 2023 was $841.0 million, compared to $641.0 million in the same period of the prior year. This increase was due to significantly higher production volumes and higher realized oil prices (including the effect of settled derivatives), offset by lower realized natural gas prices (including the effect of settled derivatives) and higher operating costs. 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 ended September 30, 2023 was a deficit of $82.6 million compared to a deficit of $115.4 million in the same period of the prior year.

#### Cash Flows from Investing Activities

Cash flows used in investing activities during the nine months ended September 30, 2023 and 2022 were $1,484.2 million and $858.5 million, respectively. The increase in cash used in investing activities for the first nine months of 2023 as compared to the same period of 2022 was attributable to a $658.2 million increase in our capital expenditures for oil and natural gas properties spending, which included the closing of our MPDC Acquisition, Forge Acquisition and Novo Acquisition in the first nine months of 2023. Additionally, the amount of capital expenditures included in accounts payable (and thus not included in cash flows from investing activities) was $281.5 million and $164.2 million at September 30, 2023 and 2022, 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 ended September 30, 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 $1,638.2 million, while the actual cash spend in this regard amounted to $1,483.6 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 ended September 30, 2023 and 2022 are summarized in the following table:

*(In millions, unaudited)*

|  | Nine Months Ended September 30, 2023 | 2022 |
| --- | ---: | ---: |
| Drilling and Development Capital Expenditures | $484.3 | $270.4 |
| Acquisition of Oil and Natural Gas Properties | 996.6 | 551.5 |
| Other Capital Expenditures | 2.7 | 3.6 |
| Total | $1,483.6 | $825.5 |

45

#### Cash Flows from Financing Activities

Net cash provided by financing activities was $653.7 million during the nine months ended September 30, 2023, compared to net cash provided by financing activities of $217.1 million during the nine months ended September 30, 2022. For the nine months September 30, 2023, cash provided by financing activities was primarily related to the issuance of the Senior Notes due 2031 of $492.8 million, the issuance of common stock of $224.7 million, and $65.0 million of net advances under our Revolving Credit Facility partially offset by $8.0 million in repurchases of common stock, $18.4 million in repurchases of our Senior Notes due 2028, and $88.7 million of common stock dividend payments. For the nine months ended September 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 $21.5 million in repurchases of common stock, $19.8 million in repurchases of our Senior Notes due 2028, $81.2 million in repurchases of Series A Preferred Stock, $32.0 million of common stock dividend payments and $5.9 million of preferred stock dividend payments.

### Revolving Credit Facility

We have a Revolving Credit Facility with Wells Fargo Bank, as administrative agent, and the lenders from time to time party thereto. 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 September 30, 2023, the Revolving Credit Facility had a borrowing base of $1.80 billion and an elected commitment amount of $1.25 billion, and we had $384.0 million in borrowings outstanding under the facility, leaving $866.0 million in available committed borrowing capacity. See Note 4 to our condensed financial statements for further details regarding the Revolving Credit Facility.

### Senior Notes due 2028

As of September 30, 2023, we had outstanding $705.1 million aggregate principal amount of our Senior Notes due 2028. See Note 4 to our condensed financial statements for further details regarding the Senior Notes due 2028.

### Senior Notes due 2031

As of September 30, 2023, we had outstanding $500.0 million million aggregate principal amount of our Senior Notes due 2031. See Note 4 to our condensed financial statements for further details regarding the Senior Notes due 2031.

### Convertible Notes

As of September 30, 2023, we had outstanding $500.0 million aggregate principal amount of our Convertible Notes. See Note 4 to our condensed financial statements for further details regarding the Convertible Notes.

### 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 typically result in increases in the costs of materials, services and personnel. We budgeted for a 5-10% increase in drilling and completion and other associated costs in 2023 compared to 2022.

### Contractual Obligations and Commitments

Please see our disclosure of contractual obligations and commitments as of December 31, 2022, included in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

### 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, 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 ended December 31, 2022.

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 December 31, 2022.

## Market risk

As filed, 6,491 characters.

Our quantitative and qualitative disclosures about market risk for changes in commodity prices and interest rates are included in Item 7A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2022 and, except as set forth below, have not materially changed since that report was filed.

### Commodity Price Risk

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand and other factors. Historically, the markets for oil and natural gas have been volatile, and we believe these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Our revenue generally would have increased or decreased along with any increases or decreases in oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling oil that also increase and decrease along with oil prices.

We enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to commodity price volatility. All derivative positions are carried at their fair value on 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 other comprehensive income or other income (expense).

We generally use derivatives to economically hedge a significant, but varying portion of our anticipated future production. Any payments due to counterparties under our derivative contracts are funded by proceeds received from the sale of our production. Production receipts, however, lag payments to the counterparties. Any interim cash needs are funded by cash from operations or borrowings under our Revolving Credit Facility.

The following table summarizes our open crude oil derivative contracts as of September 30, 2023, by fiscal quarter.

*Crude Oil Contracts*

| Settlement Period 2023: | Swaps(1) Volume (Bbls) | Weighted Average Price ($/Bbl) | Collars Collar Call Volume (Bbls) | Collar Put Volume (Bbls) | Weighted Average Ceiling Price ($/Bbl) | Weighted Average Floor Price ($/Bbl) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Q4 | 1,998,576 | $76.00 | 2,291,252 | 1,899,676 | $86.02 | $72.39 |
| **2024:** |  |  |  |  |  |  |
| Q1 | 1,501,203 | $77.19 | 2,218,397 | 1,565,178 | $84.56 | $70.00 |
| Q2 | 1,418,017 | 76.22 | 2,128,387 | 1,488,267 | 84.32 | 69.23 |
| Q3 | 1,513,456 | 74.71 | 1,012,056 | 860,256 | 80.70 | 68.92 |
| Q4 | 1,131,469 | 72.94 | 953,749 | 779,800 | 81.75 | 68.99 |
| **2025:** |  |  |  |  |  |  |
| Q1 | 432,749 | $72.20 | 413,286 | 314,849 | $79.20 | $67.84 |
| Q2 | 417,633 | 72.42 | 273,171 | 199,233 | 75.49 | 67.63 |
| Q3 | 414,394 | 71.90 | 234,994 | 161,970 | 75.76 | 67.88 |
| Q4 | 410,911 | 71.90 | 208,511 | 135,487 | 76.87 | 67.63 |
| **2026:** |  |  |  |  |  |  |
| Q1 | 263,726 | $69.05 | 43,226 | 39,289 | $70.25 | $62.50 |
| Q2 | 266,657 | 68.98 | 43,707 | 39,727 | 70.25 | 62.50 |
| Q3 | 269,587 | 68.91 | 44,187 | 40,163 | 70.25 | 62.50 |
| Q4 | 269,587 | 68.83 | 44,187 | 40,163 | 70.25 | 62.50 |

**(1)** This table does not include volumes subject to swaptions and call options, which are crude oil derivative contracts we have entered into which may increase our swapped volumes at the option of our counterparties. See Note 11 to our condensed financial statements for further details regarding our commodity derivatives, including the swaptions and call options that are not included in the foregoing table.

The following table summarizes our open natural gas derivative contracts as of September 30, 2023, by fiscal quarter.

*Natural Gas Contracts*

| Contract Period 2023: | Swaps(1) Volume (MMBTU) | Weighted Average Price ($/MMBTU) | Collars Collar Call Volume (MMBTU) | Collar Put Volume (MMBTU) | Weighted Average Ceiling Price ($/MMBTU) | Weighted Average Floor Price ($/MMBTU) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Q4 | 9,716,958 | $3.82 | 5,742,500 | 5,742,500 | $6.58 | $3.96 |
| **2024:** |  |  |  |  |  |  |
| Q1 | 9,916,616 | $3.60 | 3,825,000 | 3,825,000 | $5.39 | $3.36 |
| Q2 | 9,950,805 | 3.47 | 3,222,500 | 3,222,500 | 4.70 | 3.15 |
| Q3 | 9,940,457 | 3.47 | 4,600,000 | 4,600,000 | 4.80 | 3.08 |
| Q4 | 6,802,909 | 3.46 | 5,571,586 | 5,571,586 | 5.22 | 3.10 |
| **2025:** |  |  |  |  |  |  |
| Q1 | 1,485,000 | $3.61 | 6,971,417 | 6,971,417 | $5.58 | $3.14 |
| Q2 | 915,000 | 3.60 | 6,471,297 | 6,471,297 | 5.23 | 3.14 |
| Q3 | 920,000 | 3.60 | 6,107,569 | 6,107,569 | 5.31 | 3.14 |
| Q4 | 765,000 | 3.52 | 5,473,723 | 5,473,723 | 5.46 | 3.13 |
| **2026:** |  |  |  |  |  |  |
| Q1 | 450,000 | $3.20 | 4,048,249 | 4,048,249 | $5.66 | $3.13 |
| Q2 | 455,000 | 3.20 | 4,184,706 | 4,184,706 | 5.66 | 3.13 |
| Q3 | 460,000 | 3.20 | 4,184,706 | 4,184,706 | 5.66 | 3.13 |
| Q4 | 460,000 | 3.20 | 2,774,642 | 2,774,642 | 5.66 | 3.13 |

**(1)** This table does not include volumes subject to call options, which are natural gas derivative contracts we have entered into which may increase our swapped volumes at the option of our counterparties. This table also does not include basis swaps. See Note 11 to our condensed financial statements for further details regarding our commodity derivatives, including the call options and basis swaps that are not included in the foregoing table.

### Interest Rate Risk

Our long-term debt as of September 30, 2023 was comprised of borrowings that contain fixed and floating interest rates. The Senior Notes due 2028, Senior Notes due 2031, and Convertible Notes bear cash interest at fixed rates. Our Revolving Credit Facility interest rate is a floating rate option that is designated by us within the parameters established by the underlying agreement (see Note 4 to our condensed financial statements).

Changes in interest rates can impact results of operations and cash flows. A 1% increase in short-term interest rates on our floating-rate debt outstanding at September 30, 2023 would have cost us an additional $3.8 million in annual interest expense under our Revolving Credit Facility.

## Controls and procedures

As filed, 1,941 characters.

### Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that is designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934, as amended (“Exchange Act”), reports is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.

As of September 30, 2023, our management, including our principal executive officer and principal financial officer, had evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) pursuant to Rule 13a-15(b) under the Exchange Act. Based upon and as of the date of the evaluation, our principal executive officer and principal financial officer concluded that information required to be disclosed is recorded, processed, summarized and reported within the specified periods and is accumulated and communicated to management, including our principal executive officer and principal financial officer, to allow for timely decisions regarding required disclosure of material information required to be included in our periodic SEC reports. Based on the foregoing, our management determined that our disclosure controls and procedures were effective as of September 30, 2023.

### Changes in Internal Control over Financial Reporting

No change in our Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the quarter ended September 30, 2023, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

## Risk factors

As filed, 300 characters.

Except as described in our Quarterly Report on Form 10-Q filed with the SEC for the period ended June 30, 2023, there have been no material changes to the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K filed with the SEC for the period ended December 31, 2022.

Filed Nov 2, 2023.
Source: SEC EDGAR, the filing index for accession 0001104485-23-000188. Last ingested by Listed: Nov 6, 2026, 17:01 ET. No prices; not investment advice.