Permian Resources Corp 10-Q

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying consolidated financial statements and related notes. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, future market prices for oil, natural gas and NGLs, future production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, inflation, regulatory changes, the success of our pending merger transaction, continued and future impacts of COVID-19 and other uncertainties, as well as those factors discussed in “Cautionary Statement Concerning Forward-Looking Statements” and under the heading “Item 1A. Risk Factors” in this Quarterly Report and our 2021 Annual Report all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. Overview Centennial Resource Development, Inc. is an independent oil and natural gas company focused on the development of oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. Our principal business objective is to increase shareholder value by efficiently developing our oil and natural gas assets in an environmentally and socially responsible way, with an overall objective of improving our rates of return and generating sustainable free cash flow. Unless otherwise specified or the context otherwise requires, all references in these discussions to “Centennial,” “we,” “us,” or “our” are to Centennial Resource Development, Inc. and its consolidated subsidiary, Centennial Resource Production, LLC (“CRP”). Market Conditions The demand for oil and natural gas has been significantly impacted by the worldwide outbreak of COVID-19, specifically regarding the uncertainty surrounding the virus’s impact and because of various governmental actions taken to mitigate the spread of the virus. Con currently, global oil and natural gas supplies have been disrupted by production curtailment agreements among the Organization of Petroleum Exporting Countries and other oil producing countries (“OPEC+”) and reduced drilling and completion activity from U.S. producers. Both OPEC+ output and U.S. drilling activity has increased since 2020 levels; however, these factors have only led to a gradual increase in oil and gas supply, and global supply has not returned to pre-pandemic levels. Further in the first half of 2022, Russia’s invasion of Ukraine and global sanctions placed on Russia in response have created additional downward pressures on the supply of oil and natural gas. Meanwhile, demand for oil and gas has risen steadily throughout 2021 and 2022 due to the availability of COVID-19 vaccinations, fewer government mandated restrictions and the global-wide transition away from coal to natural gas. Despite governmental actions from several countries to release a portion of their strategic petroleum reserves, global oil inventories have continued to decline due to the resulting supply and demand imbalances. These factors, among others, have aided in the recovery of global commodity prices throughout 2021 and have led to heightened commodity prices in the first half of 2022. Specifically, WTI spot prices for crude oil reached a high of $123.70 per barrel on March 8, 2022, from a low of negative $37.63 per barrel on April 20, 2020. Similarly, the Henry Hub index price for natural gas reached a high of $9.46 per MMBtu on June 9, 2022, from a low of $1.33 per MMBtu on September 22, 2020. The oil and natural gas industry is cyclical, and it is likely that commodity prices, as well as commodity price differentials, will continue to be volatile due to fluctuations in global supply and demand, inventory levels, the continued effects from COVID-19 and variant strains of the virus, geopolitical events, federal and state government regulations, weather conditions, the global transition to alternative energy sources, supply chain constraints and other factors. The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of 2020: 2020 2021 2022 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Crude oil (per Bbl) $ 46.19 $ 28.00 $ 40.93 $ 42.66 $ 57.84 $ 66.06 $ 70.56 $ 77.09 $ 94.40 $ 108.34 Natural gas (per MMBtu) $ 1.88 $ 1.65 $ 1.95 $ 2.47 $ 3.44 $ 2.88 $ 4.28 $ 4.74 $ 4.60 $ 7.39 Lower commodity prices and lower futures curves for oil and gas prices can result in impairments of our proved oil and natural gas properties or undeveloped acreage and may materially and adversely affect our operating cash flows, liquidity, financial condition, results of operations, future business, and/or our ability to finance planned capital expenditures. Lower realized prices may also reduce the borrowing base under CRP’s credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Upon a redetermination, if any borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to 29 Table of Contents immediately repay a portion of the debt outstanding under the credit agreement. Additionally, lower prices can affect our operations, which could impact our ability to comply with the covenants under our credit agreement and senior notes. Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. In addition, the U.S. inflation rate has been steadily increasing during 2021 and 2022. These inflationary pressures may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. COVID-19 Outbreak The COVID-19 outbreak and its development into a pandemic in March 2020 have required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, vendors, suppliers and the communities in which we operate. Our operational employees have been and are currently able to work on site, while certain non-operational employees have been working remotely part-time and then also reporting to our offices on a part-time basis. We have taken various precautionary measures with respect to our operational employees, direct contractors and employees who returned to our offices or job sites and have followed the Center of Disease Control (the “CDC”) recommended preventive measures to limit the spread of COVID-19 . We have continued to update our safety protocols in alignment with CDC guidance and government mandates. We have not experienced any significant operational disruptions, including disruptions from our suppliers or service providers, as a result of the COVID-19 outbreak. 2022 Highlights and Future Considerations Pending Merger On May 19, 2022, we entered into a Business Combination Agreement (the “Business Combination Agreement”) with Colgate Energy Partners III, LLC (“Colgate”), which provides for the combination of Centennial and Colgate in a merger of equals transaction (the “Merger”). Colgate is an independent oil and gas company focused on the acquisition, development, exploration and production of oil and natural gas properties in the Permian Basin. Colgate owns approximately 105,000 net leasehold acres and 25,000 net royalty acres in Reeves and Ward counties in Texas and Eddy County in New Mexico. We believe that the Merger will provide significant increases to operational and financial scale, drive accretion across our key financial and operating metrics, and enhance the combined company’s shareholder returns. Pursuant to the Business Combination Agreement, all membership interests in CRP issued and outstanding will be converted into units in the surviving company (“Surviving Company Units”) equal to the number of shares of our Class A common stock (“Common Stock”) that are outstanding at such time, and all of the membership interest in Colgate will be exchanged for 269,300,000 shares of Class C common stock (with underlying Surviving Company Units) and $525 million in cash. The shares of Class C common stock will represent a noncontrolling interest in the Surviving Company. The transaction has been unanimously approved by the Boards of Directors of both companies. The definitive proxy statement has been filed with the SEC and the shareholder meeting is scheduled for August 29, 2022, where the Merger will be voted on by our shareholders. The Merger is expected to close shortly after the shareholder meeting subject to customary closing conditions, including, among others, receipt of the required approvals from our shareholders. Operational Highlights We operated a two-rig drilling program during the first six months of 2022, which enabled us to complete and bring online 31 gross operated wells with an average effective lateral length of approximately 9,100 feet. Financing Highlights On February 18, 2022, we closed on a new five-year revolving credit facility (the “Credit Agreement”), which replaced our previous credit agreement that was set to mature on May 4, 2023. The elected commitments under the new Credit Agreement increased to $750 million from $700 million under our previous facility, and the borrowing base increased to $1.15 billion from $700 million previously. The new Credit Agreement will mature in February 2027. In February 2022, our Board of Directors authorized a stock repurchase program to acquire up to $350 million of our outstanding Common Stock, which program is approved to run through April 1, 2024 (the “Repurchase Program”). We intend to use the Repurchase Program to reduce shares of our Common Stock outstanding and plan to fund these share repurchases with cash on hand and cash flows from operations. Due to restrictions related to the Merger, we have been unable to make or initiate any share repurchases under the Repurchase Program since the announcement and therefore, we will not be able to begin repurchasing our shares until the pending Merger closes or is otherwise terminated. 30 Table of Contents On July 15, 2022, we entered into the first amendment to our Credit Agreement (the “Amendment”). The Amendment, among other things, waives compliance with certain restrictive covenants and provides the lenders’ consent to a planned Pre-Merger Reorganization (as defined within the Amendment) in order to enable the Merger. In addition, the Amendment increases the elected commitments under our Credit Agreement to $1.5 billion from $750 million and the borrowing base to $2.5 billion from $1.15 billion. The Amendment is subject to and effective as of the closing date of the Merger and will be terminated if the Merger has not occurred prior to November 30, 2022. 31 Table of Contents Results of Operations Three Months Ended June 30, 2022 Compared to Three Months Ended June 30, 2021 The following table provides the components of our net revenues and net production (net of all royalties, overriding royalties and production due to others) for the periods indicated, as well as each period’s average prices and average daily production volumes: Three Months Ended June 30, Increase/(Decrease) 2022 2021 $ % Net revenues (in thousands): Oil sales $ 349,591 $ 177,105 $ 172,486 97 % Natural gas sales 68,030 27,015 41,015 152 % NGL sales 55,033 28,457 26,576 93 % Oil and gas sales $ 472,654 $ 232,577 $ 240,077 103 % Average sales prices: Oil (per Bbl) $ 104.69 $ 60.99 $ 43.70 72 % Effect of derivative settlements on average price (per Bbl) (16.97) (12.59) (4.38) (35) % Oil net of hedging (per Bbl) $ 87.72 $ 48.40 $ 39.32 81 % Average NYMEX price for oil (per Bbl) $ 108.34 $ 66.06 $ 42.28 64 % Oil differential from NYMEX (3.65) (5.07) 1.42 28 % Natural gas (per Mcf) $ 6.22 $ 2.55 $ 3.67 144 % Effect of derivative settlements on average price (per Mcf) (1.55) (0.09) (1.46) (1,622) % Natural gas net of hedging (per Mcf) $ 4.67 $ 2.46 $ 2.21 90 % Average NYMEX price for natural gas (per Mcf) $ 7.39 $ 2.88 $ 4.51 157 % Natural gas differential from NYMEX (1.17) (0.33) (0.84) (255) % NGL (per Bbl) $ 44.77 $ 30.37 $ 14.40 47 % Net production: Oil (MBbls) 3,339 2,904 435 15 % Natural gas (MMcf) 10,941 10,613 328 3 % NGL (MBbls) 1,230 937 293 31 % Total (MBoe) (1) 6,392 5,610 782 14 % Average daily net production: Oil (Bbls/d) 36,696 31,912 4,784 15 % Natural gas (Mcf/d) 120,225 116,629 3,596 3 % NGL (Bbls/d) 13,507 10,297 3,210 31 % Total (Boe/d) (1) 70,240 61,647 8,593 14 % (1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe. 32 Table of Contents Oil, Natural Gas and NGL Sales Revenues . Total net revenues for the three months ended June 30, 2022 were $240.1 million (or 103%) higher than total net revenues for the three months ended June 30, 2021. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized. Average realized sales prices for oil, residue gas and NGLs increased in the second quarter of 2022 compared to the same 2021 period by 72%, 144% and 47%, respectively. The 72% increase in the average realized oil price was mainly the result of higher (64%) NYMEX crude prices between periods, as well as improved oil differentials ($1.42 per Bbl narrower). The average realized sales price of natural gas increased 144% due to higher (157%) NYMEX gas prices between periods, partially offset by wider gas differentials ($0.84 per Mcf wider). The 47% increase in average realized NGL prices between periods was primarily attributable to higher Mont Belvieu spot prices for plant products in the second quarter of 2022 as compared to the second quarter of 2021. The market prices for oil, natural gas and NGLs have all been impacted by global supply constraints for oil and gas throughout 2021 and 2022, as well as increasing demand worldwide as global economies emerge from COVID-19 era lockdowns and restrictions, as discussed in the market conditions section above. Net production volumes for oil, natural gas and NGLs increased 15%, 3% and 31%, respectively, between periods. The increase in oil production resulted from our successful drilling program in the Delaware Basin. Since the second quarter of 2021, we placed 50 wells on production, which added 1,649 MBbls of net oil production to the three months ended June 30, 2022, as compared to 28 wells brought online since the second quarter of 2020 that added 872 MBbls of net oil production to the second quarter of 2021. These oil volume increases were partially offset by normal production decline across our existing wells. Natural gas and NGLs are produced concurrently with our crude oil volumes, which typically results in a high correlation between fluctuations in oil quantities sold and natural gas and NGL quantities sold. However, the main processor of our raw gas operated in partial ethane-recovery during the second quarter of 2022, as compared to operating in full ethane-rejection during the 2021 period, and this resulted in fewer natural gas volumes and more NGLs being recovered from our wet gas stream during the 2022 period. Operating Expenses. The following table sets forth selected operating expense data for the periods indicated: Three Months Ended June 30, Increase/(Decrease) 2022 2021 Change % Operating costs (in thousands): Lease operating expenses $ 28,900 $ 22,976 $ 5,924 26 % Severance and ad valorem taxes 34,695 15,784 18,911 120 % Gathering, processing and transportation expenses 25,756 19,494 6,262 32 % Operating cost metrics: Lease operating expenses (per Boe) $ 4.52 $ 4.10 $ 0.42 10 % Severance and ad valorem taxes (% of revenue) 7.3 % 6.8 % 0.5 % 7 % Gathering, processing and transportation expenses (per Boe) $ 4.03 $ 3.47 $ 0.56 16 % Lease Operating Expenses. Lease operating expenses (“LOE”) for the three months ended June 30, 2022 increased $5.9 million compared to the three months ended June 30, 2021. Higher LOE for the second quarter of 2022 was primarily related to (i) a $2.9 million increase in electricity costs between periods due to electricity credits received during the second quarter of 2021 related to the severe winter storm in the Permian Basin (“Winter Storm Uri”) that were not similarly received in 2022; (ii) an increase in workover expense of $0.9 million between periods; and (iii) higher fixed and variable costs associated with our higher well count, which increased to 435 gross operated horizontal wells as of June 30, 2022 from 409 gross operated horizontal wells as of June 30, 2021. These increases were partially offset by lower water handling costs, which are associated with our higher level of recycling activity whereby produced water from our operated wells is recycled and then reused in our drilling and completion operations. This process results in significantly lower costs as compared to typical water disposal rates. LOE per Boe was $4.52 for the second quarter of 2022, which represents an increase of $0.42 per Boe (or 10%) from the second quarter of 2021. This increase was primarily driven by per Boe increases associated with (i) higher electricity expenses between periods (discussed above); (ii) higher workover expense; and (iii) fixed and semi-variable costs, such as monthly equipment rentals, repair work, labor, and wellhead chemical costs, that increase at a higher rate than increases in production. These per Boe increases were partially offset by decreases in our water handling costs described above. 33 Table of Contents Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three months ended June 30, 2022 increased $18.9 million compared to the three months ended June 30, 2021. Severance taxes are based on the market value of our oil and gas production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of proved developed oil and gas properties and vary across the different counties in which we operate. Severance taxes for the second quarter of 2022 increased $17.6 million compared to the same 2021 period primarily due to higher oil, natural gas and NGL revenues between periods. Ad valorem taxes between periods also increased $1.3 million due to higher tax assessments on our oil and gas reserve values. Severance and ad valorem taxes as a percentage of total net revenues increased to 7.3% for the three months ended June 30, 2022 as compared to 6.8% for the same prior year quarter. This increase in rate was the result of a larger portion of our oil and gas volumes being produced in New Mexico, which levies higher severance tax rates than Texas, during the second quarter of 2022. Gathering, Processing and Transportation Expenses. Gathering, processing and transportation expenses (“GP&T”) for the three months ended June 30, 2022 increased $6.3 million as compared to the three months ended June 30, 2021. Similarly, GP&T increased on a per Boe basis from $3.47 for the second quarter of 2021 to $4.03 for the second quarter of 2022. These increases were mainly attributable to higher gas plant processing costs, whose variable fee portion is based on natural gas and NGL prices, both of which increased substantially between periods as discussed above. This increase was partially offset by a higher portion of our 2022 oil and gas volumes being produced from our New Mexico wells, where our GP&T rates are currently lower than those in Texas. Depreciation, Depletion and Amortization. The following table summarizes our depreciation, depletion and amortization (“DD&A”) for the periods indicated: Three Months Ended June 30, (in thousands, except per Boe data) 2022 2021 Depreciation, depletion and amortization $ 82,117 $ 73,429 Depreciation, depletion and amortization per Boe $ 12.85 $ 13.09 For the three months ended June 30, 2022, DD&A expense amounted to $82.1 million, an increase of $8.7 million over the same 2021 period. The primary factor contributing to higher DD&A expense in 2022 was the increase in our overall production volumes between periods, which increased DD&A expense by $10.2 million for the three months ended June 30, 2022. This was partially offset by our lower DD&A rate in the 2022 period, which decreased DD&A expense by $1.5 million between periods. Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves. DD&A per Boe was $12.85 for the second quarter of 2022 compared to $13.09 for the same period in 2021. This decrease in DD&A rate was primarily due to the Company continuing to complete wells with low finding and development costs and high quantities of associated proved developed reserves since the second quarter of 2021. General and Administrative Expenses. The following table summarizes our general and administrative (“G&A”) expenses for the periods indicated: Three Months Ended June 30, (in thousands) 2022 2021 Cash general and administrative expenses $ 12,434 $ 10,126 Stock-based compensation - equity awards 6,106 4,260 Stock-based compensation - liability awards (8,593) 14,421 General and administrative expenses 9,947 28,807 G&A expenses for the three months ended June 30, 2022 were $9.9 million compared to $28.8 million for the three months ended June 30, 2021. Lower G&A in the second quarter of 2022 was the result of a $21.2 million decrease in total stock-based compensation expense between periods. This decrease was primarily related to performance stock units granted in 2020 that are recorded at their respective fair value each balance sheet date, and such fair value decreased between periods. This decrease was slightly offset by an increase in cash G&A, which increased $2.3 million period over period due to higher payroll and other personnel costs. 34 Table of Contents Merger and integration expense. Merger and integration expense for the three months ended June 30, 2022 was $5.7 million and includes costs incurred for the pending Merger consisting primarily of legal and advisory fees. See Note 2—Business Combination for further details regarding the pending Merger. Impairment and Abandonment Expense . During the three months ended June 30, 2022, impairment and abandonment expense was $0.5 million as compared to $9.2 million during the three months ended June 30, 2021. Both periods consist solely of amortization of leasehold expiration costs associated with individually insignificant unproved properties. Exploration and Other Expenses. The following table summarizes our exploration and other expenses for the periods indicated: Three Months Ended June 30, (in thousands) 2022 2021 Geological and geophysical costs $ 1,534 $ 1,173 Stock-based compensation - equity awards 551 221 Stock-based compensation - liability awards — 239 Other expenses (131) 131 Exploration and other expenses $ 1,954 $ 1,764 Exploration and other expenses were $2.0 million for the three months ended June 30, 2022 compared to $1.8 million for the three months ended June 30, 2021. Exploration and other expenses mainly consist of topographical studies, geographical and geophysical (“G&G”) projects, salaries and expenses of G&G personnel and includes other operating costs. The period over period increase was primarily related to higher G&G personnel costs in the second quarter of 2022. Interest Expense. The following table summarizes our interest expense for the periods indicated: Three Months Ended June 30, (in thousands) 2022 2021 Credit facility $ 772 $ 2,762 8.00% Senior Secured Notes due 2025 — 367 5.375% Senior Notes due 2026 3,889 3,889 6.875% Senior Notes due 2027 6,125 6,125 3.25% Convertible Senior Notes due 2028 1,381 1,381 Amortization of debt issuance costs and debt discount 2,734 1,040 Interest capitalized (575) (382) Total $ 14,326 $ 15,182 Interest expense decreased $0.9 million for the three months ended June 30, 2022 as compared to the three months ended June 30, 2021 primarily due to (i) $2.0 million in lower interest incurred on our Credit Agreement due to lower borrowings outstanding during the 2022 period, and (ii) $0.4 million in interest expense on our Senior Secured Notes due 2025 that was incurred in the second quarter of 2021 but not in the 2022 period, as these notes were redeemed in April of 2021. These decreases were partially offset by additional debt issuance costs amortized during the second quarter of 2022 related to fees incurred for an incremental commitment letter we entered into in connection with the Merger. Our weighted average borrowings outstanding under our Credit Agreement were $5.4 million versus $289.8 million for the three months ended June 30, 2022 and 2021, respectively. Our Credit Agreement’s weighted average effective interest rate was 2.7% and 3.3% for the three months ended June 30, 2022 and 2021, respectively. Gain (loss) on extinguishment of debt. During the three months ended June 30, 2021, we redeemed at par all of our $127.1 million aggregate principal amount of Senior Secured Notes outstanding. In connection with this redemption, we recorded a loss on debt extinguishment of $22.2 million related to the write-off of all unamortized debt issuance costs and debt discounts associated with these notes. 35 Table of Contents Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying each of our hedge contracts outstanding and (ii) monthly cash settlements on any closed out hedge positions during the period. The following table presents gains and losses on our derivative instruments for the periods indicated: Three Months Ended June 30, (in thousands) 2022 2021 Realized cash settlement gains (losses) $ (73,648) $ (37,513) Non-cash mark-to-market derivative gain (loss) 39,514 (17,446) Total $ (34,134) $ (54,959) Income Tax (Expense) Benefit . The following table summarizes our pre-tax income (loss) and income tax (expense) benefit for the periods indicated: Three Months Ended June 30, (in thousands) 2022 2021 Income (loss) before income taxes $ 233,313 $ (25,055) Income tax (expense) benefit (41,487) — Our provisions for income taxes for the three months ended June 30, 2022 and 2021 differs from the amounts that would be provided by applying the U.S. federal statutory rate of 21% to pre-tax book income (loss) primarily due to (i) permanent differences, (ii) state income taxes, and (iii) any changes during the period in our deferred tax asset valuation allowance. For the three months ended June 30, 2022, we generated pre-tax net income of $233.3 million and recorded income tax expense of $41.5 million. The primary factor decreasing our income tax expense below the U.S. statutory rate was the partial release of our deferred tax valuation allowance due to the generation of net income in the current year. For the three months ended June 30, 2021, we recognized a deferred tax asset valuation allowance of $7.6 million against net operating losses (“NOLs”) we generated during the quarter, and such NOLs were estimated at such time as unlikely to be realized in future periods. The increase in the valuation allowance was the primary factor reducing our income tax benefit (based on the U.S. statutory rate) to zero for the second quarter of 2021. 36 Table of Contents Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021 The following table provides the components of our net revenues and net production (net of all royalties, overriding royalties and production due to others) for the periods indicated, as well as each period’s average prices and average daily production volumes: Six Months Ended June 30, Increase/(Decrease) 2022 2021 $ % Net revenues (in thousands): Oil sales $ 612,358 $ 310,831 $ 301,527 97 % Natural gas sales 107,048 62,466 44,582 71 % NGL sales 100,525 51,671 48,854 95 % Oil and gas sales $ 819,931 $ 424,968 $ 394,963 93 % Average sales prices: Oil (per Bbl) $ 97.42 $ 57.08 $ 40.34 71 % Effect of derivative settlements on average price (per Bbl) (15.03) (11.12) (3.91) (35) % Oil net of hedging (per Bbl) $ 82.39 $ 45.96 $ 36.43 79 % Average NYMEX price for oil (per Bbl) $ 101.37 $ 61.95 $ 39.42 64 % Oil differential from NYMEX (3.95) (4.87) 0.92 19 % Natural gas (per Mcf) $ 5.13 $ 3.13 $ 2.00 64 % Effect of derivative settlements on average price (per Mcf) (1.06) 0.01 (1.07) (10,700) % Natural gas net of hedging (per Mcf) $ 4.07 $ 3.14 $ 0.93 30 % Average NYMEX price for natural gas (per Mcf) $ 6.00 $ 3.15 $ 2.85 90 % Natural gas differential from NYMEX (0.87) (0.02) (0.85) (4,250) % NGL (per Bbl) $ 46.74 $ 30.10 $ 16.64 55 % Net production: Oil (MBbls) 6,286 5,446 840 15 % Natural gas (MMcf) 20,866 19,956 910 5 % NGL (MBbls) 2,151 1,717 434 25 % Total (MBoe) (1) 11,914 10,488 1,426 14 % Average daily net production: Oil (Bbls/d) 34,729 30,086 4,643 15 % Natural gas (Mcf/d) 115,280 110,253 5,027 5 % NGLs (Bbls/d) 11,881 9,484 2,397 25 % Total (Boe/d) (1) 65,824 57,945 7,879 14 % (1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe. 37 Table of Contents Oil, Natural Gas and NGL Sales Revenues . Total net revenues for the six months ended June 30, 2022 were $395.0 million, or 93%, higher than total net revenues for the six months ended June 30, 2021. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized. Average realized sales prices for oil, residue gas and NGLs increased for the first half of 2022 compared to the same 2021 period by 71%, 64%, and 55%, respectively. The 71% increase in the average realized oil price was mainly the result of higher (64%) NYMEX crude prices between periods, as well as improved oil differentials ($0.92 per Bbl narrower). The average realized sales price of natural gas increased 64% due to higher (90%) average NYMEX gas prices between periods, partially offset by wider gas differentials ($0.85 per Mcf wider). The 55% increase in average realized NGL prices between periods was primarily attributable to higher Mont Belvieu spot prices for plant products for the first half of 2022 compared to the first half of 2021. The market prices for oil, natural gas and NGLs have all been impacted by global supply constraints for oil and gas throughout 2021 and 2022, as well as increasing demand worldwide as global economies emerge from COVID-19 era lockdowns and restrictions, as discussed in the market conditions section above. Net production volumes for oil, natural gas, and NGLs increased 15%, 5%, and 25%, respectively, between periods. The oil production volume increase resulted from our successful drilling program in the Delaware Basin. Since the second quarter of 2021, we placed 50 wells on production, which added 2,788 MBbls of net oil production to the six months ended June 30, 2022 as compared to 28 wells brought online since the second quarter of 2020 that added 1,214 MBbls of net oil production to the six months ended June 30, 2021. These oil volume increases were partially offset by normal production decline across our existing wells. Natural gas and NGLs are produced concurrently with our crude oil volumes, typically resulting in a high correlation between fluctuations in oil quantities sold and natural gas and NGL quantities sold. However, the main processor of our raw gas operated in partial ethane-recovery during the first half of 2022, as compared to operating in full ethane-rejection during the 2021 period, and this resulted in fewer natural gas volumes and more NGLs being recovered from our wet gas stream during the 2022 period. Operating Expenses. The following table summarizes our operating expenses for the periods indicated: Six Months Ended June 30, Increase/(Decrease) 2022 2021 Change % Operating costs (in thousands): Lease operating expenses $ 57,634 $ 48,837 $ 8,797 18 % Severance and ad valorem taxes 59,746 28,367 31,379 111 % Gathering, processing and transportation expenses 47,647 40,119 7,528 19 % Operating cost metrics: Lease operating expenses (per Boe) $ 4.84 $ 4.66 $ 0.18 4 % Severance and ad valorem taxes (% of revenue) 7.3 % 6.7 % 0.6 % 9 % Gathering, processing and transportation expenses (per Boe) $ 4.00 $ 3.83 $ 0.17 4 % Lease Operating Expenses. LOE for the six months ended June 30, 2022 increased $8.8 million compared to the six months ended June 30, 2021. Higher LOE for the first half of 2022 was primarily related to (i) a $2.2 million increase in electricity costs between periods due to electricity credits received during 2021 related Winter Storm Uri that were not similarly received in 2022; (ii) an increase in workover expense of $1.8 million between periods; and (iii) higher fixed and variable costs associated with our higher well count, which increased to 435 gross operated horizontal wells as of June 30, 2022 from 409 gross operated horizontal wells as of June 30, 2021. These increases were partially offset by lower water handling costs, which are associated with our higher level of recycling activity whereby produced water from our operated wells is recycled and then reused in our drilling and completion operations. This process results in significantly lower costs as compared to typical water disposal rates. LOE per Boe was $4.84 for the six months ended June 30, 2022, which represents an increase of $0.18 per Boe (or 4%) from the comparable 2021 period. This increase was primarily driven by per Boe increases associated with (i) higher electricity expenses between periods (discussed above); (ii) higher workover expense; and (iii) fixed and semi-variable costs, such as monthly equipment rentals, repair work, labor, and wellhead chemical costs, that increase at a higher rate than increases in production. These per Boe increases were partially offset by decreases in our water handling costs described above. Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the six months ended June 30, 2022 increased $31.4 million compared to the six months ended June 30, 2021. Severance taxes are based on the market value of our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate. Severance taxes for the first half of 2022 increased $29.0 million compared to the same 2021 period primarily due to higher oil, natural gas and NGL revenues between periods. Ad valorem taxes between periods also increased $2.4 million due to higher tax assessments on our oil and gas reserve values. 38 Table of Contents Severance and ad valorem taxes as a percentage of total net revenues increased to 7.3% for the first half of 2022 as compared to 6.7% for the same 2021 period. This increase in rate was the result of a larger portion of our oil and gas volumes being produced in New Mexico, which levies higher severance tax rates than Texas, during the first half of 2022. Gathering, Processing and Transportation Expenses. GP&T for the six months ended June 30, 2022 increased $7.5 million compared to the six months ended June 30, 2021. Similarly, GP&T on a per Boe basis increased from $3.83 for the first half of 2021 to $4.00 for the same 2022 period. These increases were mainly attributable to higher gas plant processing costs, whose variable fee portion is based on natural gas and NGL prices, both of which increased substantially between periods as discussed above. This increase was partially offset by a higher portion of our 2022 oil and gas volumes being produced from our New Mexico wells, where our GP&T rates are currently lower than those in Texas. Depreciation, Depletion and Amortization. The following table summarizes our DD&A for the periods indicated: Six Months Ended June 30, (in thousands, except per Boe data) 2022 2021 Depreciation, depletion and amortization $ 153,126 $ 137,212 Depreciation, depletion and amortization per Boe $ 12.85 $ 13.08 For the six months ended June 30, 2022, DD&A expense amounted to $153.1 million, an increase of $15.9 million over the same 2021 period. The primary factor contributing to higher DD&A expense in 2022 was the increase in our overall production volumes between periods, which increased DD&A expense by $18.6 million during the first half of 2022, while lower DD&A rates between periods decreased DD&A expense by $2.7 million for the six months ended June 30, 2022. Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves. DD&A per Boe was $12.85 for the first half of 2022 compared to $13.08 for the same period in 2021. This decrease in DD&A rate was primarily due to the Company continuing to complete wells with low finding and development costs and high quantities of associated proved developed reserves since the second quarter of 2021. General and Administrative Expenses. The following table summarizes our G&A expenses for the periods indicated: Six Months Ended June 30, (in thousands) 2022 2021 Cash general and administrative expenses $ 24,203 $ 20,758 Stock-based compensation expense - equity awards 11,220 8,637 Stock-based compensation expense - liability awards 5,127 24,668 General and administrative expenses $ 40,550 $ 54,063 G&A expenses for the six months ended June 30, 2022 were $40.6 million compared to $54.1 million for the six months ended June 30, 2021. Lower G&A in the first half of 2022 was the result of a $17.0 million decrease in total stock-based compensation expense between periods. This decrease was primarily related to performance stock units granted in 2020 that are recorded at their respective fair value each balance sheet date, and such fair value decreased between periods. This decrease was slightly offset by higher cash G&A which increased $3.4 million period over period due to higher payroll and other personnel cost increases. Merger and integration expense. Merger and integration expense for the six months ended June 30, 2022 was $5.7 million and includes costs incurred for the pending Merger consisting primarily of legal and advisory fees. See Note 2—Business Combination for further details regarding the pending Merger. Impairment and Abandonment Expense. During the six months ended June 30, 2022, impairment and abandonment expense was $3.1 million as compared to $18.4 million during the six months ended June 30, 2021. Both periods consist solely of amortization of leasehold expiration costs associated with individually insignificant unproved properties. 39 Table of Contents Exploration and Other Expenses. The following table summarizes our exploration and other expenses for the periods indicated: Six Months Ended June 30, (in thousands) 2022 2021 Geological and geophysical costs $ 3,237 $ 1,786 Stock-based compensation - equity awards 982 429 Stock-based compensation - liability awards — 406 Other expenses 42 238 Exploration and other expenses $ 4,261 $ 2,859 Exploration and other expenses were $4.3 million for the six months ended June 30, 2022 compared to $2.9 million for the same prior year period. Exploration and other expenses mainly consist of topographical studies, G&G projects, salaries and expenses of G&G personnel and includes other operating costs. The period over period increase was primarily related to higher G&G personnel costs in the second half of 2022. Other Income and Expenses. Interest Expense. The following table summarizes our interest expense for the periods indicated: Six Months Ended June 30, (in thousands) 2022 2021 Credit facility $ 1,649 $ 6,077 8.00% Senior Secured Notes due 2025 — 2,908 5.375% Senior Notes due 2026 7,778 7,778 6.875% Senior Notes due 2027 12,250 12,250 3.25% Convertible Senior Notes due 2028 2,762 1,553 Amortization of debt issuance costs and debt discount 4,226 2,887 Interest capitalized (1,185) (786) Total $ 27,480 $ 32,667 Interest expense was $5.2 million lower for the six months ended June 30, 2022 compared to the same 2021 period mainly due to (i) $4.4 million in lower interest incurred on our Credit Agreement due to lower borrowings outstanding during the 2022 period, and (ii) $2.9 million in decreased interest expense on our Senior Secured Notes due 2025 that were redeemed in April of 2021. These decreases were partially offset by (i) additional debt issuance costs amortized during the six months ended June 30, 2022 related to fees incurred for an incremental commitment letter we entered into in connection with the Merger, and (ii) interest on our Convertible Senior Notes that was incurred in 2022 but only partially during the 2021 period due to their issuance in March of 2021. Our weighted average borrowings outstanding under our Credit Agreement were $16.5 million versus $310.2 million for the first half of 2022 and 2021, respectively. Our Credit Agreement’s weighted average effective interest rate was 2.9% and 3.4% for the six months ended June 30, 2022 and 2021, respectively. Gain (loss) on extinguishment of debt. During the six months ended June 30, 2021, we redeemed at par all of our $127.1 million aggregate principal amount of Senior Secured Notes outstanding. In connection with this redemption, we recorded a loss on debt extinguishment of $22.2 million related to the write-off of all unamortized debt issuance costs and debt discounts associated with these notes. Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying each of our hedge contracts outstanding and (ii) monthly cash settlements on any closed out hedge positions during the period. The following table presents gains and losses for derivative instruments for the periods indicated: Six Months Ended June 30, (in thousands) 2022 2021 Realized cash settlement gains (losses) $ (116,526) $ (60,399) Non-cash mark-to-market derivative gain (loss) (47,131) (45,759) Total $ (163,657) $ (106,158) 40 Table of Contents Income Tax (Expense) Benefit . The following table summarizes our pre-tax income (loss) and income tax (expense) benefit for the periods indicated: Six Months Ended June 30, (in thousands) 2022 2021 Income (loss) before income taxes $ 255,891 $ (59,700) Income tax (expense) benefit (48,263) — Our provisions for income taxes for the first half of 2022 and 2021 differs from the amounts that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax book income (loss) primarily due to (i) state income taxes; (ii) permanent differences; and (iii) any changes during the period in our deferred tax asset valuation allowance. For the six months ended June 30, 2022 we generated pre-tax net income of $255.9 million and recorded income tax expense of $48.3 million. The primary factor decreasing our income tax expense below the U.S. statutory rate was the partial release of our deferred tax valuation allowance due to the generation of net income in the current year. For the six months ended June 30, 2021, we recognized deferred tax asset valuation allowances of $20.0 million against NOLs we generated during the period, and such NOLs were estimated at such time as unlikely to be realized in future periods. The increase in our valuation allowance was the primary factor reducing our income tax benefit (based on the U.S. statutory rate) to zero for the first six months of 2021. 41 Table of Contents Liquidity and Capital Resources Overview Our drilling and completion activities require us to make significant capital expenditures. Historically, our primary sources of liquidity have been cash flows from operations, borrowings under CRP’s revolving credit facility, proceeds from offerings of debt or equity securities, or proceeds from the sale of oil and gas properties. Our future cash flows are subject to a number of variables, including oil and natural gas prices, which have been and will likely continue to be volatile. Lower commodity prices can negatively impact our cash flows and our ability to access debt or equity markets, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. To date, our primary use of capital has been for drilling and development capital expenditures and the acquisition of oil and natural gas properties. The following table summarizes our capital expenditures (“capex”) incurred for the six months ended June 30, 2022: (in millions) Six Months Ended June 30, 2022 Drilling, completion and facilities $ 248.4 Infrastructure, land and other 6.9 Total capital expenditures incurred $ 255.3 We continually evaluate our capital needs and compare them to our capital resources. We operated a two-rig drilling program during the first half of 2022. We expect our total capex budget for 2022 on a stand alone basis to be between $365 million to $425 million, of which $350 million to $400 million is allocated to drilling, completion and facilities activity. We funded our capital expenditures for the six months ended June 30, 2022 entirely from cash flows from operations, and we expect to fund the remainder of our stand alone 2022 capex budget entirely from cash flows from operations as well, given our anticipated level of oil and gas production, current commodity prices and our commodity hedge positions in place. We generated free cash flow during the first half of 2022 such that we were able to pay down all of our borrowings under our Credit Agreement during the period. In May 2022, we announced the pending Merger with Colgate that is expected close in the third quarter of 2022. If the Merger closes as expected, our 2022 operational plans and sources and use of capital, among others things, as a combined entity will change, and such changes are expected to include (i) the Company assuming $1.0 billion of Colgate’s senior notes and Colgate’s credit facility borrowings outstanding at closing, which will be refinanced under CRP’s Credit Agreement, (ii) potential borrowings under CRP’s Credit Agreement to fund some portion of the $525 million in cash Merger consideration due at closing, and (iii) the funding of additional transaction costs yet to be incurred related to the Merger. In February 2022, our Board of Directors authorized the Repurchase Program to acquire up to $350 million of our outstanding Common Stock. We intend to use the Repurchase Program to reduce our shares of Common Stock outstanding and plan to fund these share repurchases with cash on hand and cash flows from operations. Such repurchases would be made at terms and prices determined by us based upon prevailing market conditions, applicable legal requirements, available liquidity, compliance with our debt and other agreements and other factors. Due to restrictions related to the Merger, we have been unable to make or initiate any share repurchases under the Repurchase Program since the announcement and therefore, we will not be able to begin repurchasing our shares until the pending Merger closes or is otherwise terminated. In addition, we may, from time to time, seek to retire or purchase our outstanding senior notes through cash purchases and/or exchanges for debt in open-market purchases, privately negotiated transactions or otherwise. Because we are the operator of a high percentage of our acreage, we can control the amount and timing of our capital expenditures. We can choose to defer or accelerate a portion of our planned capex depending on a variety of factors, including but not limited to: prevailing and anticipated prices for oil and natural gas; oil storage or transportation constraints; the success of our drilling activities; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; seasonal conditions; property or land acquisition costs; and the level of participation by other working interest owners. We cannot ensure that cash flows from operations will be available or other sources of needed capital on acceptable terms or at all. Further, our ability to access the public or private debt or equity capital markets at economic terms in the future will be affected by general economic conditions, the domestic and global oil and financial markets, our operational and financial performance, the value and performance of our debt or equity securities, prevailing commodity prices and other macroeconomic factors outside of our control. 42 Table of Contents Analysis of Cash Flow Changes The following table summarizes our cash flows for the periods indicated: Six Months Ended June 30, (in thousands) 2022 2021 Net cash provided by operating activities $ 455,099 $ 179,625 Net cash used in investing activities (228,603) (127,076) Net cash used in financing activities (34,784) (53,644) For the six months ended June 30, 2022, we generated $455.1 million of cash from operating activities, an increase of $275.5 million from the same period in 2021. Cash provided by operating activities increased primarily due to higher realized prices for all commodities, higher production volumes, decreased cash interest costs, and the timing of our supplier payments during the six months ended June 30, 2022. These increasing factors were partially offset by higher lease operating expenses, GP&T, cash G&A, severance and ad valorem taxes, cash settlement losses on derivatives, and the timing of our receivable collections for the six months ended June 30, 2022 as compared to the same 2021 period. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and on fluctuations in our operating costs between periods. During the six months ended June 30, 2022, cash flows from operating activities were used to finance $224.0 million of drilling and development cash expenditures and repay net borrowings of $25.0 million under our Credit Agreement. During the six months ended June 30, 2021, cash flows from operating activities and net proceeds from the issuance of the Convertible Senior Notes (defined below) were used to finance $126.7 million of drilling and development cash expenditures, repay net borrowings of $75.0 million under our credit facility, redeem $127.1 million of our 2025 senior secured notes outstanding and to fund $14.7 million in capped call spread transactions. Credit Agreement On February 18, 2022, CRP entered into an amended and restated five-year secured Credit Agreement with a syndicate of banks, which replaced our previous credit facility that was set to mature in May of 2023. The Credit Agreement increased our elected commitments to $750 million, increased our borrowing base to $1.15 billion and extended the maturity of the Credit Agreement to February 2027. As of June 30, 2022, the Company had no borrowings outstanding and $744.2 million in available borrowing capacity, which was net of $5.8 million in letters of credit outstanding, under its new facility. The Credit Agreement provides for, among other things, the ability to repurchase outstanding shares of Common Stock and junior debt, subject to certain leverage and elected commitment availability conditions and subject to the requirement that such repurchases are funded from our free cash flow. The Credit Agreement contains restrictive covenants that limit our ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make restricted payments; (v) repurchase or redeem junior debt; (vi) enter into commodity hedges exceeding a specified percentage of our expected production; (vii) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (viii) incur liens; (ix) sell assets; and (x) engage in transactions with affiliates. The Credit Agreement also requires CRP to maintain compliance with the following financial ratios: (i) a current ratio, which is the ratio of CRP’s consolidated current assets (including an add back of unused commitments under the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and (ii) a leverage ratio, as defined within the Credit Agreement as the ratio of total funded debt to consolidated EBITDAX for the prior four fiscal quarters, of not greater than 3.5 to 1.0. CRP was in compliance with the covenants and the applicable financial ratios described above as of June 30, 2022 and through the filing of this Quarterly Report. On July 15, 2022, CRP and the Company entered into the Amendment to our Credit Agreement. The Amendment, among other things, waives compliance with certain restrictive covenants and provides the lenders’ consent to a planned Pre-Merger Reorganization (as defined within the Amendment) in order to enable the Merger. In addition, the Amendment increases the elected commitments under the Credit Agreement to $1.5 billion from $750 million and the borrowing base to $2.5 billion from $1.15 billion. The Amendment is subject to and effective as of the closing date of the Merger and will be terminated if the Merger has not occurred prior to November 30, 2022. For further information on the Credit Agreement, refer to Note 4—Long-Term Debt under Part I, Item I of this Quarterly Report. 43 Table of Contents Convertible Senior Notes On March 19, 2021, CRP issued $150.0 million of 3.25% senior unsecured convertible notes due 2028 (the “Convertible Senior Notes”). On March 26, 2021, CRP issued an additional $20.0 million of Convertible Senior Notes pursuant to the exercise of the underwriters’ over-allotment option to purchase additional notes. These issuances resulted in aggregate net proceeds to CRP of $163.6 million, which were used to repay borrowings outstanding under the Credit Agreement and to fund the cost of entering into capped call spread transactions of $14.7 million. Subsequently in April 2021, we redeemed at par all of our Senior Secured Notes (defined below), which was the intended use of proceeds from the Convertible Senior Notes offering. The Convertible Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of CRP’s current subsidiaries that guarantee CRP’s outstanding Senior Unsecured Notes as defined below. The Convertible Senior Notes bear interest at an annual rate of 3.25% and are due on April 1, 2028 unless earlier repurchased, redeemed or converted. The Convertible Senior Notes may become convertible prior to April 1, 2028, upon the occurrence of certain events or conditions being met as disclosed in Note 4—Long-Term Debt under Part I, Item I of this Quarterly Report. CRP can settle the Convertible Senior Notes by paying or delivering cash, shares of the Common Stock, or a combination of cash and Common Stock, at CRP’s election. In connection with the Convertible Senior Notes issuance, CRP entered into privately negotiated capped call spread transactions (the “Capped Call Transactions”), that are expected to reduce potential dilution to our Common Stock upon a conversion and/or offset any cash payments CRP is required to make in excess of the principal amount of the Convertible Senior Notes, subject to a cap. The Capped Call Transactions have an initial strike price of $6.28 per share of Common Stock and an initial capped price of $8.4525 per share of Common Stock (each subject to certain customary adjustments per the agreements). Senior Notes On November 30, 2017, CRP issued $400.0 million of 5.375% senior notes due 2026 (the “2026 Senior Notes”) and on March 15, 2019, CRP issued $500.0 million of 6.875% senior notes due 2027 (the “2027 Senior Notes” and, together with the 2026 Senior Notes, the “Senior Unsecured Notes”) in 144A private placements. In May 2020, $110.6 million aggregate principal amount of the 2026 Senior Notes and $143.7 million aggregate principal amount of the 2027 Senior Notes were validly tendered and exchanged by certain eligible bondholders for consideration consisting of $127.1 million aggregate principal amount of 8.00% second lien senior secured notes (the “Senior Secured Notes”). The Senior Secured Notes were fully redeemed at par in connection with the Convertible Senior Notes issuance during the second quarter of 2021. The Senior Unsecured Notes are fully and unconditionally guaranteed on a senior unsecured basis by Centennial and each of CRP’s current subsidiaries that guarantee CRP’s Credit Agreement. The indentures governing the Senior Unsecured Notes contain covenants that, among other things and subject to certain exceptions and qualifications, limit CRP’s ability and the ability of CRP’s restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. CRP was in compliance with these covenants as of June 30, 2022 and through the filing of this Quarterly Report. For further information on our Convertible Senior Notes and Senior Unsecured Notes, refer to Note 4—Long-Term Debt under Part I, Item I of this Quarterly Report. Contractual Obligations Our contractual obligations include operating and transportation agreements, drilling rig contracts, office and equipment leases, asset retirement obligations, long-term debt obligations and cash interest expense on long-term debt obligations, which we routinely enter into, modify o r extend. Since December 31, 2021, there have not been any significant, non-routin e changes in our contractual obligations other than the new frac’ sand agreements entered into as discussed in Note 12—Commitments and Contingencies under Part I, Item I of this Quarterly Report. Critical Accounting Policies and Estimates There have been no material changes during the six months ended June 30, 2022 to the critical accounting policies. Please refer to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates in our 2021 Annual Report for a discussion of our critical accounting policies and estimates. New Accounting Pronouncements There were no significant new accounting standards adopted or new accounting pronouncements that would have potential effects to us as of June 30, 2022. 44 Table of Contents