# Permian Resources Corp (PR) FY 2021 MD&A

Verbatim Item 7 Management's Discussion and Analysis from Permian Resources Corp's 10-K for fiscal year 2021.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1658566/000165856622000022/cdev-20211231.htm
Accession: 0001658566-22-000022
Filing date: 2022-02-24
Report date: 2021-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary.
Confidence: high

Company profile: /company/PR/
All MD&A years: /company/PR/mda/
Next year: /company/PR/mda/fy2022/ (FY 2022)

ITEM 7. 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 in “Item 8. Financial Statements and Supplementary Data” in this Annual Report. 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, continued and future impacts of COVID-19 and other uncertainties, as well as those factors discussed in “Cautionary Statement Concerning Forward-Looking Statements” and “Item 1A. Risk Factors” in this 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

We are an independent oil and natural gas company focused on the development of crude 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 capital programs are focused on projects that we believe provide the highest return on capital.

Market Conditions

The 2020 worldwide outbreak of COVID-19, the uncertainty regarding its impact and various governmental actions taken to mitigate the effects of COVID-19 resulted in an unprecedented decline in the demand for oil and natural gas throughout 2020. In addition, the decision by Saudi Arabia to drastically reduce export prices and increase oil production in March 2020 (the “Saudi-Russia oil price war”) followed by curtailment agreements among Organization of Petroleum Exporting Countries (“OPEC”) and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. However, in April of 2020, the members of OPEC and other oil producing countries (“OPEC+”) agreed to reduce their crude oil production throughout the year, while U.S. producers substantially reduced or suspended drilling and completion activity due to low oil prices and poor economics.

The demand for oil and natural gas continued to remain low in early 2021 due to continued uncertainty regarding the impacts of COVID-19. OPEC+ extended their production cuts through the first quarter of 2021 and began to gradually increase output during the second quarter of 2021 with more substantial output increases announced from August 2021 through September 2022. U.S. drilling activity began to increase in the fourth quarter of 2020 and has continued to increase steadily since. These factors have led to a gradual increase in oil and gas supply but has not returned global supply to pre-pandemic levels. Meanwhile, the global demand for oil and gas has risen steadily throughout 2021 and has outpaced supply growth due to the availability of COVID-19 vaccinations, increased mobility due to less governmental mandated restrictions and the global transition away from coal to natural gas. As a result of this imbalance, global oil inventories have continued to decline throughout 2021 and are currently below pre-pandemic levels. These factors, among others, have aided in the recovery of global commodity prices during 2021. Specifically, WTI spot prices for crude oil reached a high of $84.65 per barrel on October 26, 2021 from a low of negative $37.63 per barrel on April 20, 2020 (which was due to depressed demand and insufficient storage capacity, particularly at the WTI physical settlement location in Cushing, Oklahoma). Similarly, the average Henry Hub index price for natural gas reached $4.74 during the fourth quarter of 2021, which was more than double of the average Henry Hub price of $1.99 for the year ended December 31, 2020.

The oil and natural gas industry is cyclical, and it is likely that commodity prices 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 2019:

[[GREPCENT_TABLE]]
[["","2019","","2020","","2021"],["","Q1","","Q2","","Q3","","Q4","","Q1","","Q2","","Q3","","Q4","","Q1","","Q2","","Q3","","Q4"],["Crude Oil (per Bbl)","$","54.90","","","$","59.81","","","$","56.45","","","$","56.94","","","$","46.19","","","$","28.00","","","$","40.93","","","$","42.66","","","$","57.84","","","$","66.06","","","$","70.56","","","$","77.09"],["Natural Gas (per MMBtu)","$","2.88","","","$","2.51","","","$","2.33","","","$","2.34","","","$","1.88","","","$","1.65","","","$","1.95","","","$","2.47","","","$","3.44","","","$","2.88","","","$","4.28","","","$","4.74"]]
[[/GREPCENT_TABLE]]

Lower commodity prices (including our realized differentials) and lower futures curves for oil and gas prices can also result in impairments of our proved oil and natural gas properties or undeveloped acreage (such as the impairments incurred in the first quarter of 2020) and may materially and adversely affect our future business, financial condition, results of operations, operating

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cash flows, liquidity and/or 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 immediately repay a portion of the debt outstanding under the credit agreement. Additionally, a lower price environment and its impact to our operations could impact our ability to comply with the covenants under our credit agreement and senior notes.

The oil and gas industry is cyclical, and the demand for oilfield goods and services, as well as other inflationary factors in the economy, 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. Further, the U.S. inflation rate has been steadily increasing during 2021 and into 2022. These inflationary pressures could also result in increases to the costs of our materials, services and personnel, which would in turn cause our capital expenditures and operating costs to go up.

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 reporting to our offices on a limited 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 such as (i) requesting that they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site or office, (ii) self-quarantining any employees or contractors who have shown signs or symptoms of COVID-19 (regardless of whether such person has been confirmed to be infected), (iii) imposing certain mask and social distancing requirements on work sites and at our offices, and (iv) encouraging all employees and contractors to follow the Center of Disease Control (the “CDC”) recommended preventive measures (including those mentioned above) to limit the spread of COVID-19. We have continued to update our safety protocols in alignment with CDC guidance and governmental mandates, and have been able to reduce some requirements if employees, customers, vendors, or suppliers are fully vaccinated. We have not experienced any significant operational disruptions (including disruptions from our suppliers or service providers) as a result of the COVID-19 outbreak.

2021 Highlights and Future Considerations

Operational Highlights

We operated a two-rig drilling program during 2021, which enabled us to complete and bring online 42 gross operated wells with an average effective lateral length of approximately 8,900 feet.

In February 2021, the Permian Basin was impacted by record-low temperatures and a severe winter storm (“Winter Storm Uri”) that caused multi-day electrical outages and shortages, pipeline and infrastructure freezes, and transportation disruptions. These events led to significant increases in gas prices, gathering, processing and transportation fees and electrical rates during this time, and our operations were also impacted by a partial shut-in of certain wells and their associated production for about seven days during the event. Refer to the discussion below for the current impacts from Winter Storm Uri on our results of operations during the year ended December 31, 2021.

Divestiture Highlights

On December 1, 2021, we completed the sale of approximately 6,200 net leasehold acres for an unadjusted sales price of $101 million. The divested assets represent non-core acreage that was mainly undeveloped but which also contained 20 low producing wells located on the southernmost portion of our acreage position in Reeves County, Texas. The properties divested consisted of 5,830 MBoe of proved reserves as of December 31, 2020, representing approximately 2% of our proved reserves as of that date, and generated approximately 1,600 Boe/d (64% oil) during the third quarter of 2021. Net proceeds from the sale were used to repay a portion of our borrowings outstanding under CRP’s revolving credit facility, reducing the outstanding balance to $25.0 million as of December 31, 2021.

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Financing Highlights

On March 19, 2021, we issued $150.0 million of 3.25% senior convertible notes due 2028 (the “Convertible Senior Notes”) in a public offering. On March 26, 2021, an additional $20.0 million of Convertible Senior Notes were issued pursuant to the exercise of the underwriters’ over-allotment option to purchase additional notes. The issuance resulted in net proceeds of $163.6 million, after deducting debt issuance costs of $6.4 million, and such proceeds were used to fund the cost of entering into capped call spread transactions totaling $14.7 million and to repay borrowings outstanding under CRP’s revolving credit facility. In April 2021, we redeemed at par all of our 2025 senior secured notes ($127.1 million), which was the intended use of proceeds from the Convertible Senior Notes offering.

On February 18, 2022, we closed on a new five-year revolving credit facility, which replaced our previous credit agreement that was set to mature on May 4, 2023. The elected commitments under the new credit facility 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 facility will mature in February 2027.

In February 2022, our Board of Directors authorized the Repurchase Program to acquire up to $350 million of our outstanding Common Stock, and the program is approved to run through April 1, 2024. 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.

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Results of Operations

For the Year Ended December 31, 2021 Compared to the Year Ended December 31, 2020

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:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,","","Increase/(Decrease)"],["","2021","","2020","","$","","%"],["Net revenues (in thousands):"],["Oil sales","$","743,069","","","$","475,694","","","$","267,375","","","56","%"],["Natural gas sales","149,478","","","46,776","","","102,702","","","220","%"],["NGL sales","137,345","","","57,986","","","79,359","","","137","%"],["Oil and gas sales","$","1,029,892","","","$","580,456","","","$","449,436","","","77","%"],["Average sales price:"],["Oil (per Bbl)","$","63.50","","","$","36.02","","","$","27.48","","","76","%"],["Effect of derivative settlements on average price (per Bbl)","(10.19)","","","(3.15)","","","(7.04)","","","(223)","%"],["Oil net of hedging (per Bbl)","$","53.31","","","$","32.87","","","$","20.44","","","62","%"],["Average NYMEX price for oil (per Bbl)","$","67.89","","","$","39.44","","","$","28.45","","","72","%"],["Oil differential from NYMEX","(4.39)","","","(3.42)","","","(0.97)","","","(28)","%"],["Natural gas (per Mcf)","$","3.67","","","$","1.13","","","$","2.54","","","225","%"],["Effect of derivative settlements on average price (per Mcf)","(0.32)","","","(0.12)","","","(0.20)","","","(167)","%"],["Natural gas net of hedging (per Mcf)","$","3.35","","","$","1.01","","","$","2.34","","","232","%"],["Average NYMEX price for natural gas (per Mcf)","$","3.84","","","$","1.99","","","$","1.85","","","93","%"],["Natural gas differential from NYMEX","(0.17)","","","(0.86)","","","0.69","","","80","%"],["NGL (per Bbl)","$","36.61","","","$","12.91","","","$","23.70","","","184","%"],["Net production:"],["Oil (MBbls)","11,701","","","13,207","","","(1,506)","","","(11)","%"],["Natural gas (MMcf)","40,741","","","41,302","","","(561)","","","(1)","%"],["NGL (MBbls)","3,752","","","4,490","","","(738)","","","(16)","%"],["Total (MBoe)(1)","22,243","","","24,581","","","(2,338)","","","(10)","%"],["Average daily net production:"],["Oil (Bbls/d)","32,058","","","36,084","","","(4,026)","","","(11)","%"],["Natural gas (Mcf/d)","111,619","","","112,848","","","(1,229)","","","(1)","%"],["NGL (Bbls/d)","10,278","","","12,269","","","(1,991)","","","(16)","%"],["Total (Boe/d)(1)","60,939","","","67,161","","","(6,222)","","","(9)","%"]]
[[/GREPCENT_TABLE]]

(1)    Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.

Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the year ended December 31, 2021 increased by $449.4 million, or 77%, compared to the year ended December 31, 2020. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.

Average realized sale prices for oil, residue gas and NGLs increased for the year ended December 31, 2021 as compared to 2020 by 76%, 225%, and 184%, respectively. The 76% increase in the average realized oil price was mainly the result of higher (72%) NYMEX crude prices between periods, which was minimally offset by wider oil differentials ($0.97 per Bbl wider). The average realized sales price of natural gas increased 225% due to higher (93%) average NYMEX gas prices between periods, as well as improved gas differentials (by $0.69 per Mcf). The 184% increase in average realized NGL prices between periods was primarily attributable to higher Mont Belvieu spot prices for plant products in 2021 compared to 2020. The market prices for oil, natural gas and NGLs have all been impacted by higher global demand for oil and gas compared to 2020, when prices decreased significantly beginning in March 2020 as a result of COVID-19 and supply disruptions from the Russia-Saudi oil price war as discussed in the market conditions section above. Additionally, the first quarter 2021 realized price for natural gas in the Permian

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Basin was impacted by Winter Storm Uri, which caused gas pipeline and supply disruptions and resulted in significant increases in Permian natural gas prices during this period.

Net production volumes for oil, natural gas, and NGLs decreased 11%, 1% and 16%, respectively, between periods. The oil production volume decrease was primarily related to normal production decline across our existing wells and temporary shut-ins of our wells during mid-February as a result of Winter Storm Uri. Oil volume declines for the year ended December 31, 2021, were further impacted by the suspension of our drilling and completion activity for several months during 2020 due to the drastic decline in oil prices discussed above. As a result, only 31 wells were completed in 2020, and we therefore entered 2021 producing just 28,550 Bbls/d of oil, as compared to the 84 wells we completed in 2019, which enabled us to enter 2020 producing 47,927 Bbls/d of crude oil. This 40% decline in exit rates was partially offset by our 2021 development program that placed 42 wells online during the year and thereby added 3,490 MBbls of oil to our 2021 annual production volumes. Natural gas and NGLs are produced concurrently with our crude oil volumes, typically resulting in a high correlation between fluctuations in our oil quantities sold and our natural gas and NGL quantities sold. However, during 2021, the main processor of our raw gas operated in full ethane-rejection, as compared to operating in partial ethane-recovery during 2020. Additionally, the amount of gas flared as a percentage of wellhead gas produced was significantly less during the year ended December 31, 2021, as compared to the year ended December 31, 2020. Both of these factors combined resulted in an increase in the amount of natural gas recovered and sold from our wet gas stream between periods, while the aforementioned variations in ethane-rejection between periods resulted in fewer NGLs being recovered during 2021.

Operating Expenses. The following table sets forth selected operating expense data for the periods indicated:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,","","Increase/(Decrease)"],["","2021","","2020","","Change","","%"],["Operating costs (in thousands):"],["Lease operating expenses","$","106,419","","","$","109,282","","","$","(2,863)","","","(3)","%"],["Severance and ad valorem taxes","67,140","","","39,417","","","27,723","","","70","%"],["Gathering, processing, and transportation expense","85,896","","","71,309","","","14,587","","","20","%"],["Operating cost metrics:"],["Lease operating expenses (per Boe)","$","4.78","","","$","4.45","","","$","0.33","","","7","%"],["Severance and ad valorem taxes (% of revenue)","6.5","%","","6.8","%","","(0.3)","%","","(4.0)","%"],["Gathering, processing, and transportation expense (per Boe)","3.86","","","2.90","","","0.96","","","33","%"]]
[[/GREPCENT_TABLE]]

Lease Operating Expenses. Lease operating expenses (“LOE”) for the year ended December 31, 2021 decreased $2.9 million compared to the year ended December 31, 2020. Lower LOE for 2021 was primarily related to (i) a $2.9 million decrease in workover expense between periods; (ii) decreases in electricity costs in 2021 as a result of credits realized in the current year related to Winter Storm Uri; (iii) lower well operating expenses due to cost reduction initiatives, which included moving multiple wells off generator to lower cost line-power and switching wells away from electric submersible pumps to more reliable and cost-efficient gas lift; and (iv) lower variable and semi-variable costs stemming from the 10% production decline between periods. These decreases were partially offset by higher chemical costs, environmental and preventative maintenance expenses, and other fixed and variable costs associated with our higher well count, which increased to 404 gross operated horizontal wells as of December 31, 2021 from 386 gross operated horizontal wells as of December 31, 2020.

LOE per Boe was $4.78 for the year ended December 31, 2021, which represents an increase of $0.33 per Boe (or 7%) from 2020. This increase was primarily driven by per BOE cost increases between periods associated with fixed and semi-variable costs that don’t decrease at the same rate as declines in production, such as monthly rental fees for compressors and other equipment, wellhead chemical costs, and water handling fees. In addition, environmental expenses and preventative maintenance costs were higher for the year ended December 31, 2021 as compared to the same prior year period. These increases were partially offset by the lower level of workover activity in 2021, decreased electricity costs, and the cost reduction initiatives we have undertaken, as discussed above.

Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the year ended December 31, 2021 increased $27.7 million compared to the year ended December 31, 2020. Severance taxes are primarily based on the market value of our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of proved developed oil and natural gas properties and vary across the different counties in which we operate. Severance taxes for the year ended 2021 increased $31.3 million compared to the same 2020 period primarily due to higher oil, natural gas and NGL revenues between periods. These increases were partially offset by a $3.6 million decrease in ad valorem taxes between periods due to lower tax assessments on our oil and gas reserve values.

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Severance and ad valorem taxes as a percentage of total net revenues decreased to 6.5% for the year ended December 31, 2021 as compared to 6.8% for the year ended December 31, 2020 as a result of the lower 2021 ad valorem tax assessments discussed above.

Gathering, Processing and Transportation Expenses. Gathering, processing and transportation costs (“GP&T”) for the year ended December 31, 2021 increased $14.6 million compared to the year ended December 31, 2020. On a per Boe basis, GP&T likewise increased 33% from $2.90 for the year ended December 31, 2020 to $3.86 per Boe for the year ended December 31, 2021. These increases were mainly attributable to (i) 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, and (ii) a $2.9 million decrease in reimbursements received from third parties for their usage of our available firm transport capacity.

Depreciation, Depletion and Amortization. The following table summarizes our depreciation, depletion and amortization (“DD&A”) for the periods indicated: 

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(in thousands, except per Boe data)","2021","","2020"],["Depreciation, depletion and amortization","$","289,122","","","$","358,554"],["Depreciation, depletion and amortization per Boe","$","13.00","","","$","14.59"]]
[[/GREPCENT_TABLE]]

For the year ended December 31, 2021, DD&A expense amounted to $289.1 million, a decrease of $69.4 million from 2020. Lower DD&A expense in 2021 was due to i) the decline in DD&A rates between periods which decreased DD&A expense by $35.3 million, and ii) the decline in our overall production volumes between periods that lowered DD&A expense by $34.1 million from year to year.

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 $13.00 for the year ended December 31, 2021 compared to $14.59 in 2020. This decrease in DD&A rate was primarily due to (i) the proved property impairment recognized in the first quarter of 2020, which lowered the carrying value of our depletion base by $591.8 million; (ii) net upward revisions in our proved developed reserves of 4.5 MMBoe for the year ended December 31, 2021 mainly related to higher SEC reserve pricing; and (iii) lower drilling and completion costs per lateral foot in 2021 versus 2020.

Impairment and Abandonment Expense. For the year ended December 31, 2021, $32.5 million of impairment and abandonment expense was incurred related to the amortization of leasehold expiration costs associated with individually insignificant unproved properties.

For the year ended December 31, 2020, $691.2 million of impairment and abandonment expense was incurred related to certain of our oil and gas properties. This expense consisted of (i) a $591.8 million non-cash impairment of our proved properties in the first quarter of 2020 as a result of the depressed NYMEX oil and gas futures curves as of March 31, 2020; (ii) $78.8 million related to the amortization of leasehold expiration costs associated with individually insignificant unproved properties, and (iii) a $20.6 million write-off of individually significant leasehold acreage costs for acres that are not currently included in our future development plan.

Exploration and Other Expenses. The following table summarizes exploration and other expenses for the periods indicated:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(in thousands)","2021","","2020"],["Geological and geophysical costs","$","3,508","","","$","4,533"],["Stock-based compensation - equity awards","1,883","","","1,433"],["Stock-based compensation - liability awards","(89)","","","90"],["Stock-based compensation - cash settled awards","314","","","\u2014"],["Exploratory dry hole costs","\u2014","","","6,615"],["Rig termination fees","\u2014","","","3,046"],["Severance payments","\u2014","","","722"],["Other expenses","2,267","","","1,916"],["Exploration and other expenses","$","7,883","","","$","18,355"]]
[[/GREPCENT_TABLE]]

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Exploration and other expenses were $7.9 million for the year ended December 31, 2021 compared to $18.4 million for the year ended December 31, 2020. Exploration and other expenses mainly consist of topographical studies, geographical and geophysical (“G&G”) projects, salaries and expenses of G&G personnel and include other operating costs. The period over period decrease was primarily related to charges incurred in 2020 that did not reoccur in 2021 including: (i) $6.6 million in exploratory dry hole costs; (ii) rig termination fees of $3.0 million recognized in 2020 when we reduced our drilling program from five rigs to none; (iii) $1.7 million in environmental remediation costs; and (iv) $0.7 million in severance payments to G&G employees. Additionally, for the year ended December 31, 2021 there was $1.0 million in lower ongoing G&G personnel costs compared to the year ended December 31, 2020 due to the decrease in headcount related to our 2020 workforce reduction. These decreases were partially offset by $1.3 million in nonrecurring costs incurred in 2021 associated with a sulfur clean-out of a third party’s processing facility and an increase in total stock-based compensation costs incurred during the year ended December 31, 2021 related to restricted stock units that became fully vested during the period as discussed below.

General and Administrative Expenses. The following table summarizes our general and administrative (“G&A”) expenses for the periods indicated:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(in thousands)","2021","","2020"],["Cash general and administrative expenses","$","48,269","","","$","46,356"],["Stock-based compensation - equity awards","35,658","","","19,533"],["Stock-based compensation - liability awards","20,662","","","3,512"],["Stock-based compensation - cash settled awards","5,865","","","\u2014"],["Severance payments","\u2014","","","3,466"],["General and administrative expenses","$","110,454","","","$","72,867"]]
[[/GREPCENT_TABLE]]

G&A expenses for the year ended December 31, 2021 were $110.5 million compared to $72.9 million for the year ended December 31, 2020. Higher G&A in 2021 was the result of a $39.1 million increase in total stock-based compensation expense between periods. This increase was primarily related to a portion of our liability-classified restricted stock units, held by certain officers (non-NEOs) and employees, becoming fully vested following a maximum return event that was triggered in the third quarter of 2021. These awards were settled one-third in cash ($5.9 million) and two-thirds in equity, resulting in an aggregate charge of $21.4 million being recognized during the year ended December 31, 2021. There was an additional $20.5 million increase in total stock-based compensation related to liability-classified performance stock units granted in July 2020 that were outstanding for the entire year and which had a higher fair value as of December 31, 2021, as their fair value is required to be re-measured at each period end date. Refer to Note 6—Stock-Based Compensation under Part II, Item 8 of this Annual Report for additional information regarding these awards and the maximum return event. These increases were partially offset by $3.5 million in severance payments to G&A employees in the 2020 period that did not reoccur in 2021.

Net Gain (Loss) on Sale of Long-Lived Assets. During the year ended December 31, 2021, we completed the sale of approximately 6,200 net leasehold acres for an unadjusted sales price of $101 million. This divestiture represented the sale of an entire field, which resulted in a net gain on sale of $33.9 million. Refer to Note 2—Property Divestitures under Part II, Item 8 of this Annual Report for additional information.

Other Income and Expense. 

Interest Expense. The following table summarizes interest expense for the periods indicated:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(in thousands)","2021","","2020"],["Credit Facility","$","10,771","","","$","12,973"],["8.000% Senior Secured Notes due 2025","2,908","","","6,185"],["5.375% Senior Notes due 2026","15,556","","","17,884"],["6.875% Senior Notes due 2027","24,500","","","28,368"],["3.250% Convertible Senior Notes due 2028","4,315","","","\u2014"],["Amortization of debt issuance costs and debt discount","4,992","","","5,923"],["Interest capitalized","(1,754)","","","(2,141)"],["Total","$","61,288","","","$","69,192"]]
[[/GREPCENT_TABLE]]

Interest expense was $7.9 million lower for the year ended December 31, 2021 compared to the year ended December 31, 2020 mainly due to (i) $6.2 million in lower interest incurred on our Senior Unsecured Notes during 2021, as $110.6 million of the senior notes due 2026 and $143.7 million of the senior notes due 2027 were extinguished in our debt exchange transaction in

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May 2020; (ii) $3.3 million in decreased interest expense on our Senior Secured Notes due 2025 that were redeemed in their entirety in April of 2021; and (iii) $2.2 million in lower interest expense incurred on our credit facility due to fewer borrowings outstanding during 2021. These decreases were partially offset by $4.3 million in interest incurred on our Convertible Senior Notes that were issued in March of 2021. Refer to Note 4—Long-Term Debt under Part II, Item 8 of this Annual Report for additional information on our senior notes and debt transactions.

Our weighted average borrowings outstanding under our credit facility were $265.8 million during 2021 compared to $334.2 million in 2020. Our credit facility’s weighted average effective interest rate (which is a LIBOR-based rate) remained consistent at 3.3% for the years ended December 31, 2021 and 2020.

Gain (loss) on extinguishment of debt. During the year ended December 31, 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 incurred 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.

A gain of $143.4 million was recognized for the year ended December 31, 2020 related to our 2020 debt exchange transaction. This gain was determined based on the difference between the carrying value of the Senior Unsecured Notes extinguished less the fair value of our newly issued Senior Secured Notes on their date of issuance. Refer to Note 4—Long-Term Debt under Part II, Item 8 of this Annual Report for additional information regarding the debt extinguishment transactions discussed above.

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:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(in thousands)","2021","","2020"],["Realized cash settlement gains (losses)","$","(132,125)","","","$","(46,651)"],["Non-cash mark-to-market derivative gain (loss)","(16,700)","","","(17,884)"],["Total","$","(148,825)","","","$","(64,535)"]]
[[/GREPCENT_TABLE]]

Income Tax (Expense) Benefit: The following table summarizes our pre-tax income (loss) and income tax (expense) benefit for the periods indicated.

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(in thousands)","2021","","2020"],["Income (loss) before income taxes","$","138,744","","","$","(770,323)"],["Income tax (expense) benefit","(569)","","","85,124"]]
[[/GREPCENT_TABLE]]

Our provision for income taxes for the years ended December 31, 2021 and 2020 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) permanent differences; (ii) state income taxes; and (iii) any changes during the period in our deferred tax asset valuation allowance.

For the year ended December 31, 2020, we recognized a deferred tax asset valuation allowance (“Valuation Allowance”) of $77.0 million against net operating losses generated during the period, which were estimated as unlikely to be realized in future periods. During the year ended December 31, 2021, we reduced our Valuation Allowance to $40.1 million as a result of net income generated during the year. These changes in our Valuation Allowance during each respective year are the primary factor reducing our income tax expense to $0.6 million and benefit to $85.1 million from the income tax expense or benefit that would otherwise be due based on U.S. statutory rates, for the years ended December 31, 2021 and December 31, 2020, respectively.

For the Year Ended December 31, 2020 Compared to the Year Ended December 31, 2019

Refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2020 Annual Report on Form 10-K filed with the SEC for a discussion of the results of operations for the year ended December 31, 2020 compared to the year ended December 31, 2019.

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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. 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 for the acquisition of oil and natural gas properties. The following table summarizes our capital expenditures (“capex”) incurred during the year:

[[GREPCENT_TABLE]]
[["(in millions)","Year Ended December 31, 2021"],["Drilling, completion and facilities","$","313.0"],["Infrastructure, land and other","8.5"],["Total capital expenditures incurred","$","321.5"]]
[[/GREPCENT_TABLE]]

We continually evaluate our capital needs and compare them to our capital resources. We operated a two-rig drilling program for the year ended December 31, 2021, and we plan to operate two rigs throughout 2022. We expect our total capex budget for 2022 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 2021 entirely from cash flows from operations, and we expect to fund our 2022 capex budget entirely from cash flows from operations given our anticipated level of oil and gas production, current commodity prices and our commodity hedge positions in place. We were free cash flow positive during the year ended December 31, 2021 such that (notwithstanding our debt refinancing transactions discussed below and net proceeds received from oil and gas property sales) we were still able to pay down material borrowings under our credit agreement during the period. Based upon current commodity prices, we expect to continue to pay down borrowings next year from our expected free cash flow generation in 2022, and 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 or equity in open-market purchases, privately negotiated transactions or otherwise.

In February 2022, our Board of Directors authorized a Repurchase Program to acquire up to $350 million of our outstanding Common Stock. We intend to use the program to reduce our shares of Common Stock outstanding and plan to fund these share repurchases with cash on hand and cash flow from operations. Such repurchases or exchanges 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.

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 crude 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.

Moreover, to manage our future maturities, lower interest expense, and improve our liquidity position, we issued 3.25% Convertible Senior Notes in March 2021, which resulted in net proceeds of $163.6 million. The proceeds were used to repay borrowing outstanding under CRP’s revolving credit facility and to fund the cost of entering into capped call spread transactions of $14.7 million. In April 2021, we redeemed at par all of our 2025 senior secured notes ($127.1 million) that bore interest at 8% per year and paid accrued interest of $3.8 million on these notes, which was the intended use of proceeds from the Convertible Senior Notes offering. As a result of this refinancing transaction, we were also able to reduce net borrowings outstanding under CRP’s revolving credit facility by approximately $20 million.

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Analysis of Cash Flow Changes

The following table summarizes our cash flows for the periods indicated:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(in thousands)","2021","","2020","","2019"],["Net cash provided by operating activities","$","525,619","","","$","171,376","","","$","564,173"],["Net cash used in investing activities","(226,476)","","","(326,323)","","","(932,989)"],["Net cash (used in) provided by financing activities","(297,547)","","","147,743","","","362,937"]]
[[/GREPCENT_TABLE]]

Cash Flows from 2021 Compared to 2020. For the year ended December 31, 2021, we generated $525.6 million of cash from operating activities, an increase of $354.2 million from 2020. Cash provided by operating activities increased primarily due to higher realized prices for all commodities, lower exploration and other expense, cash interest payments, lease operating expenses, and the timing of vendor payments during 2021 as compared to 2020. These increasing factors were partially offset by lower production volumes, higher GP&T and severance and ad valorem costs, the timing of our receivable collections, and cash settlement losses from derivatives for the year ended December 31, 2021 as compared to the same 2020 period. Refer to Results of Operations for more information on the impact of volumes and prices on revenues and on fluctuations in our operating expenses between periods.

For the year ended December 31, 2021, cash flows from operating activities, proceeds from the sale of oil and natural gas properties and net proceeds from the issuance of the Convertible Senior Notes were used to finance $319.6 million of drilling and development cash expenditures, repay net borrowings of $305 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 transactions.

Cash Flows from 2020 Compared to 2019. For the year ended December 31, 2020, we generated $171.4 million of cash from operating activities, a decrease of $392.8 million from 2019. Cash provided by operating activities decreased primarily due to lower realized prices for oil and NGLs, lower production volumes for crude oil, residue gas and NGLs, higher exploration and other expenses, interest payments, cash settlement losses on derivatives, and the timing of vendor payments during 2020 as compared to 2019. These declining factors were partially offset by higher realized natural gas prices, lower lease operating expenses, production taxes, GP&T costs, cash G&A expenses, and the timing of our receivable collections during 2020 as compared to the same 2019 period.

For the year ended December 31, 2020, cash flows from operating activities, cash on hand, and net borrowings of $155.0 million under our credit facility were used to finance $318.5 million of drilling and development cash expenditures, to fund $8.5 million in oil and gas property acquisitions, and to finance $6.7 million of debt issuance and exchange costs.

Credit Agreement

CRP, our consolidated subsidiary, had a credit agreement with a syndicate of banks that provides for a five-year secured revolving credit facility, maturing on May 4, 2023 (the “Credit Agreement”). As of December 31, 2021, we had $25.0 million in borrowings outstanding and $669.2 million in available borrowing capacity, which was net of $5.8 million in letters of credit.

On February 18, 2022, CRP entered into an amended and restated credit agreement (the “Amended Credit Agreement”) with a syndicate of banks replacing our previous Credit Agreement. The Amended Credit Agreement increased our elected commitments to $750 million, increased our borrowing base to $1.15 billion and extended the maturity of the credit facility to February 2027. Additionally, the Amended Credit Agreement provides for, among other things, the ability to repurchase outstanding 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 Amended Credit Agreement also reflected a replacement of all provisions and related definitions regarding LIBOR with the Secured Overnight Financing Rate (“SOFR”).

The amount available to be borrowed under the Amended Credit Agreement is redetermined semi-annually each April 1 and October 1 by the lenders in their sole discretion. It also allows for two optional borrowing base redeterminations in between the scheduled redeterminations. The borrowing base depends on, among other things, the quantities of CRP’s proved oil and natural gas reserves, estimated cash flows from those reserves, and our commodity hedge positions. Upon a redetermination of the borrowing base, if actual borrowings outstanding exceed the revised borrowing capacity, CRP could be required to immediately repay a portion of its debt outstanding. Borrowings under the Amended Credit Agreement are guaranteed by certain of CRP’s subsidiaries and the Company.

Borrowings under the Amended Credit Agreement may be base rate loans or SOFR loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for SOFR loans. SOFR loans bear interest at SOFR plus an applicable margin ranging from 225 to 325 basis points, depending on the percentage of elected commitments utilized, plus an additional 10 basis point credit spread adjustment. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; or (iii) the adjusted Term SOFR rate for a one-

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month interest period plus 100 basis points, plus an applicable margin, ranging from 125 to 225 basis points, depending on the percentage of the borrowing base utilized. CRP also pays a commitment fee of 37.5 to 50 basis points on unused elected commitment amounts under its facility.

The Amended 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 Amended Credit Agreement also requires it 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 Amended 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 Amended 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 financial ratios under the Amended Credit Agreement described above through the filing of this Annual Report.

Convertible Senior Notes

On March 19, 2021, CRP issued $150.0 million in aggregate principal amount of 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. The Convertible Senior Notes bear interest at an annual rate of 3.25% and are due on April 1, 2028. Interest is payable semi-annually in arrears on each April 1 and October 1, which commenced on October 1, 2021. The Convertible Senior Notes can be converted by noteholders prior to their maturity date upon the occurrence of certain events. CRP can settle the Convertible Senior Notes by paying or delivering cash, shares of our Common Stock, or a combination of cash and Common Stock, at CRP’s election.

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.

In connection with the Convertible Senior Note issuance, CRP entered into privately negotiated capped call spread transactions (the “Capped Call Transactions”), that are expected to reduce potential dilution to the 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 due (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 revolving credit facility.

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 December 31, 2021 and through the filing of this Annual Report.

For further information on our Convertible Senior Notes and Senior Unsecured Notes, refer to Note 4—Long-Term Debt under Part II, Item 8 of this Annual Report.

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Obligations and Commitments

We routinely enter into or extend operating and transportation agreements, office and equipment leases, drilling rig contracts, among others, in the ordinary course of business. The following table summarizes our obligations and commitments as of December 31, 2021 to make future payments under long-term contracts for the time periods specified below.

[[GREPCENT_TABLE]]
[["(in thousands)","2022","","2023","","2024","","2025","","2026","","Thereafter","","Total"],["Operating leases(1)","$","1,603","","","$","2,395","","","$","2,452","","","$","2,522","","","$","2,341","","","$","10,691","","","$","22,004"],["Purchase obligations(2)","5,157","","","5,192","","","5,206","","","5,192","","","5,192","","","\u2014","","","25,939"],["Asset retirement obligations(3)","229","","","\u2014","","","490","","","\u2014","","","\u2014","","","16,521","","","17,240"],["Long term debt obligations(4)","\u2014","","","25,000","","","\u2014","","","\u2014","","","289,448","","","526,351","","","840,799"],["Cash interest expense on long-term debt obligations(5)","48,841","","","46,689","","","45,582","","","45,582","","","30,672","","","13,114","","","230,480"],["Transportation agreements(6)","2,989","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","2,989"],["Cash based compensation awards(7)","859","","","50,366","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","51,225"],["Total","$","59,678","","","$","129,642","","","$","53,730","","","$","53,296","","","$","327,653","","","$","566,677","","","$","1,190,676"]]
[[/GREPCENT_TABLE]]

(1)    Operating leases consist of our office rental agreements and other wellhead equipment. Please refer to Note 15—Leases under Part II, Item 8 of this Annual Report for details on our operating lease commitments.

(2)    Consists of an energy purchase agreement to buy a minimum amount of electricity at a fixed price or pay for underutilization. The obligations reported above represent our remaining minimum financial commitments pursuant to the terms of this contract as of December 31, 2021, however actual expenditures may exceed the minimum commitments presented above.

(3)    Asset retirement obligations reflect the present value of the estimated future costs associated with the plugging and abandonment of oil and gas wells and the related land restoration in accordance with applicable laws and regulations.

(4)    Long-term debt consists of the principal amounts of our senior notes due and borrowings outstanding under the Credit Agreement as of December 31, 2021.

(5)    Cash interest expense on our senior notes is estimated assuming no principal repayment until the maturity of the instruments. Cash interest expense on the Credit Agreement includes unused commitment fees and assumes no additional principal borrowings, repayments or changes to commitments under the agreement through the instrument due date.

(6)    Transportation agreements include various firm natural gas transportation contracts whereby we are required to pay fixed pipeline capacity reservation fees over the contractual terms. The obligations reported above represent minimum financial commitments pursuant to the terms of these contracts. However, our expenditures under these contracts are likely to exceed the minimum commitments presented above.

(7)    Consists of compensation based awards that are settable in cash including 5.5 million performance stock units. The obligation reported above for these performance stock units is based upon their estimated fair value as of December 31, 2021. However, these awards are subject to market-based vesting criteria with a payout ranging from 0% to 200% of the target number of units. Refer to Note 6—Stock-Based Compensation in Part II, Item 8. Financial Statements and Supplementary Data in this Annual Report for more information.

Recently Issued Accounting Standards

Please refer to Note 1—Basis of Presentation and Summary of Significant Accounting Policies, in Part II, Item 8. Financial Statements and Supplementary Data in this Annual Report for a discussion of recently issued accounting standards and their anticipated effect on our business.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these statements requires us to make certain assumptions, judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as, the disclosure of contingent assets, contingent liabilities and commitments as of the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, commodity prices, production performance, drilling results, mechanical problems, general business conditions and other factors. A summary of our significant accounting policies can be found in Note 1—Basis of Presentation and Summary of Significant Accounting Policies, Item 8. Financial Statements and Supplementary Data in this Annual Report.

We have outlined certain of our accounting policies below which require the application of significant judgment by our management.

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Oil and Natural Gas Reserve Quantities

We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved crude oil, natural gas and NGL reserves. Reserve quantities and the related estimates of future net cash flows are used as inputs to our calculation of depletion, evaluation of proved properties for impairment, assessment of the expected realizability of our deferred income tax assets, and the standardized measure of discounted future net cash flows computations.

 The process of estimating quantities of proved reserves is inherently imprecise and relies on the following: i) interpretations and judgment of available geological, geophysical, engineering and production data; ii) certain economic assumptions, some of which are mandated by the SEC, such as commodity prices; and iii) assumptions and estimates of underlying inputs such as operating expenses, capital expenditures, plug and abandonment costs and taxes. All of these assumptions may differ substantially from actual results, which could result in a significant change in our estimated quantities of proved reserves and their future net cash flows. We continually make revisions to reserve estimates throughout the year as additional information becomes available, and we make changes to depletion rates in the same reporting period that changes to reserve estimates are made.

Impairment of Oil and Natural Gas Properties

We assess our proved properties for impairment when events or changes in circumstances indicate that the carrying value of such proved property assets may not be recoverable. For purposes of an impairment evaluation, our proved oil and natural gas properties must be grouped at the lowest level for which independent cash flows can be identified. If the sum of the undiscounted estimated cash flows from the use of the asset group and its eventual disposition is less than the carrying value of an asset group, the carrying value is written down to its estimated fair value. Fair value for the purpose of measuring impairment write-downs are calculated using the present value of expected future cash flows that are estimated to be generated from the asset group. Fair value estimates are based on projected financial information which we believe to be reasonably likely to occur, as of the date that the impairment write-down is being measured. However, such future cash flow estimates are based on numerous assumptions that can materially affect our estimates, and such assumptions are subject to change with variations in commodity prices, production performance, drilling results, operating and development costs, underlying oil and gas reserve quantities, and other internal or external factors.

Unproved properties consist of the costs we incurred to acquire undeveloped leasehold acreage as well as the costs we incurred to acquire unproved reserves. Unproved properties with individually significant acquisition costs are periodically assessed for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or changes in future plans to develop acreage. Unproved properties which are not individually significant are amortized by prospect, based on our historical experience, current drilling plan, existing geological data and average remaining lease terms. Changes in our assumptions as to the estimated nonproductive portion of our undeveloped leases could result in additional impairment charges.

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