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, 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 unconventional oil and associated liquids-rich natural gas reserves in thePermian Basin . Our assets are concentrated in theDelaware Basin , a sub-basin of thePermian Basin . Our capital programs are focused on projects that we believe provide the highest return on capital. Market Conditions The recent worldwide outbreak of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19 have resulted in an unprecedented decline in the demand for oil and natural gas. In addition inMarch 2020 , the decision bySaudi Arabia to drastically reduce export prices and increase oil production (the "Saudi-Russia oil price war") followed by curtailment agreements amongOPEC and other countries such asRussia further increased uncertainty and volatility around global oil supply-demand dynamics. As a result, there was a significant decline in commodity prices starting at the end of the first quarter of 2020. However, during the second quarter of 2020,OPEC and other oil producing countries agreed to reduce their crude oil production, whileU.S. producers substantially reduced or suspended drilling activity and in most cases curtailed production due to low oil prices and poor economics. The oil production cuts byOPEC and other producing countries were agreed upon and continued during the remainder of 2020, andU.S. drilling activity remained low throughout the second half of 2020. These actions have aided in a partial recovery of global commodity prices. Specifically, WTI spot prices for crude oil fell to a low of negative$37.63 per barrel onApril 20, 2020 (due to depressed demand and insufficient storage capacity, particularly at the WTI physical settlement location inCushing, Oklahoma ) and have since recovered to a high of$49.10 per barrel onDecember 18, 2020 . The oil and natural gas industry is cyclical, and it is likely that commodity prices, as well as commodity price differentials, will continue to be volatile due to fluctuations in global supply and demand, inventory levels, the continued effects of COVID-19, geopolitical events, weather conditions, global transition to alternative energy sources and other factors. The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of 2018: 2018 2019 2020 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Crude Oil (per Bbl)$ 62.91 $ 68.07 $ 69.50
$ 3.77 $ 2.88 $ 2.51 $ 2.33 $ 2.34 $ 1.88 $ 1.65 $ 1.95 $ 2.47 A sustained drop in oil, natural gas and NGL prices, such as those we have experienced during 2020, will not only decrease our revenues but can also reduce the amount of oil, natural gas and NGLs that we can produce economically and can therefore potentially lower our oil, natural gas and NGL reserve quantities. Lower commodity prices (including our realized differentials) and lower futures curves for oil and gas prices, can also result in further impairments of our proved oil and natural gas properties or undeveloped acreage (such as the impairments discussed below under "Results of Operations") and may materially and adversely affect our future business, financial condition, results of operations, operating 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 (such as the reduction discussed below under "Financing Highlights"), 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, the 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. 42 -------------------------------------------------------------------------------- Table of Contents COVID-19 Outbreak The COVID-19 outbreak and its development into a pandemic inMarch 2020 have required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, contractors, suppliers and the communities in which we operate. Our operational employees have been and are currently able to work on site, while the vast majority of our non-operational employees have worked remotely or reported to our offices on a limited basis during 2020. We have taken various precautionary measures with respect to our operational employees, direct contractors and employees who returned to our offices or job sites during the year such as (i) requiring them to verify 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 social distancing requirements on work sites and at our offices that are in accordance with the guidelines released by theCenter for Disease Control (the "CDC") as well as local and state authorities, (iv) requiring all employees and contractors to have a fit-test for and wear KN-95 type respirators while in our offices and work sites, and (v) encouraging all employees and contractors to follow theCDC recommended preventive measures (including those mentioned above) to limit the spread of COVID-19. We have not experienced any operational disruptions (including disruptions from our suppliers or service providers) as a result of the COVID-19 outbreak. 2020 Highlights and Future Considerations The changes in the macro environment and related volatility in commodity prices that occurred during 2020 discussed above have significantly impacted our results of operations for the year endedDecember 31, 2020 , and we believe that our future operating results and near-term financial condition could continue to be impacted, until such time that oil supply and demand dynamics re-balance and stabilize. Operational Highlights We operated a five-rig drilling program during the majority of the first quarter of 2020, which enabled us to complete and bring online 26 gross operated wells with an average effective lateral length of approximately 7,000 feet during the first half of 2020. Due to the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, in the second quarter of 2020, we suspended all drilling and completion activities in order to preserve capital. Specifically, we reduced our operated drilling rig program to zero rigs starting in April of 2020 and continued with no drilling rigs in operation until the end of the third quarter. In addition, given the weakness in realized oil prices, we voluntarily curtailed or shut-in approximately 20% of our production during the month of May, but we were able to bring the majority of this production back online in June as crude oil prices recovered, with minimal incremental cost. We did not experience any further curtailments to our production during the remainder of 2020, and we recommenced drilling and completion activity in the third quarter of 2020. We completed an additional 5 gross operated wells during August of 2020 with an effective lateral length of approximately 9,000 feet, which were previously drilled during the first quarter of 2020. Further, we initiated a one-rig drilling program at the end of the third quarter, which we operated through the remainder of the year and added a second drilling rig in December. During the second half of 2020, we drilled six gross operated wells to total depth and began drilling an additional three gross operated wells, all of which we plan to complete in the first quarter of 2021. Financing Highlights OnMay 22, 2020 , we completed an opportunistic private exchange of our debt pursuant to which$110.6 million aggregate principal amount of CRP's 5.375% senior unsecured notes due 2026 (the "2026 Senior Notes") and$143.7 million aggregate principal amount of CRP's 6.875% senior unsecured notes due 2027 (the "2027 Senior Notes" and, together with the 2026 Senior Notes, the "Senior Unsecured Notes") were validly tendered and exchanged by certain eligible bondholders for consideration consisting of$127.1 million aggregate principal amount (the "Debt Exchange") of newly issued 8.00% second lien senior secured notes due 2025 (the "Senior Secured Notes"). This transaction resulted in the removal of$127.1 million in aggregate principal amount of Senior Unsecured Notes from the long-term debt balance in our consolidated balance sheets. OnMay 1, 2020 , we entered into the second and third amendments to CRP's amended and restated credit agreement (the "Q2 2020 Amendments") with the lenders to our existing credit agreement. Pursuant to the Q2 2020 Amendments, the borrowing base and level of elected commitments were both reduced to$700.0 million from their previous amounts of$1.2 billion and$800.0 million , respectively. The Q2 2020 Amendments, which were approved by the lenders, permitted the issuance of the Senior Secured Notes in connection with the Debt Exchange, and they implemented an availability blocker of$31.8 million equal to 25% of the newly issued and outstanding Senior Secured Notes. Among other things, the Q2 2020 Amendments also suspended the 43 -------------------------------------------------------------------------------- Table of Contents total funded debt to EBITDAX ratio (as specified in the existing credit agreement) through year-end 2021 and introduced a new financial covenant testing the ratio of first lien debt to EBITDAX. In connection with the credit facility's fall 2020 semi-annual redetermination process, the borrowing base and amount of elected commitments were reaffirmed at$700.0 million . Results of Operations For the Year EndedDecember 31, 2020 Compared to the Year EndedDecember 31, 2019 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: Year Ended December 31, Increase/(Decrease) 2020 2019 $ % Net revenues (in thousands): Oil sales$ 475,694 $ 810,655 $ (334,961) (41) % Natural gas sales 46,776 44,556 2,220 5 % NGL sales 57,986 89,119 (31,133) (35) % Oil and gas sales$ 580,456 $ 944,330 $ (363,874) (39) % Average sales price: Oil (per Bbl)$ 36.02 $ 52.02 $ (16.00) (31) % Effect of derivative settlements on average price (per Bbl) (3.15) (1.13) (2.02) (179) % Oil net of hedging (per Bbl)$ 32.87 $ 50.89 $ (18.02) (35) % Average NYMEX price for oil (per Bbl)$ 39.44 $ 57.03 $ (17.59) (31) % Oil differential from NYMEX (3.42) (5.01) 1.59 32 % Natural gas (per Mcf)$ 1.13 $ 1.07 $ 0.06 6 % Effect of derivative settlements on average price (per Mcf) (0.12) 0.29 (0.41) (141) % Natural gas net of hedging (per Mcf)$ 1.01 $ 1.36 $ (0.35) (26) % Average NYMEX price for natural gas (per Mcf)$ 1.99 $ 2.52 $ (0.53) (21) % Natural gas differential from NYMEX (0.86) (1.45) 0.59 41 % NGL (per Bbl)$ 12.91 $ 17.03 $ (4.12) (24) % Net production: Oil (MBbls) 13,207 15,582 (2,375) (15) % Natural gas (MMcf) 41,302 41,703 (401) (1) % NGL (MBbls) 4,490 5,234 (744) (14) % Total (MBoe)(1) 24,581 27,766 (3,185) (11) % Average daily net production: Oil (Bbls/d) 36,084 42,692 (6,608) (15) % Natural gas (Mcf/d) 112,848 114,254 (1,406) (1) % NGL (Bbls/d) 12,269 14,338 (2,069) (14) % Total (Boe/d)(1) 67,161 76,072 (8,911) (12) % (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 endedDecember 31, 2020 were lower by$363.9 million , or 39%, compared to the year endedDecember 31, 2019 . Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized. Average realized sale prices for oil and NGLs decreased for the year endedDecember 31, 2020 as compared to 2019. The average price for oil before the effects of hedging decreased 31% and the average price for NGLs decreased 24% between periods. The 31% decrease in the average realized oil price was the result of lower NYMEX crude prices in 2020 (average NYMEX oil prices decreased 31%), which was minimally offset by improved oil differentials of$1.59 per Bbl during 2020. The 44 -------------------------------------------------------------------------------- Table of Contents 24% decrease in average realized NGL prices between periods was primarily attributable to lower Mont Belvieu spot prices for plant products in 2020. Conversely, the average realized sales price of natural gas before the effects of hedging increased 6% in 2020 as compared to 2019. This increase was mainly due to improved gas differentials ($0.59 per Mcf), which was partially offset by lower average NYMEX gas prices (down$0.53 per Mcf) between periods. The improvement in gas differentials is the result of higher natural gas prices realized inWest Texas as several producers shut-in wells and curtailed production in thePermian Basin during the year and as new pipelines have been placed into service. These pipelines have provided relief from the gas takeaway capacity constraints experienced in 2019. The market prices for oil, natural gas and NGLs have all been significantly impacted by lower demand globally for oil and gas as a result of COVID-19 as well as by supply disruptions from theRussia -Saudi oil price war early in 2020, which combined have resulted in significant price declines starting inMarch 2020 as discussed in the market conditions section above. Net production volumes for oil, natural gas, and NGLs decreased 15%, 1% and 14%, respectively, between periods. The oil production volume decrease between periods was the result of (i) the temporary suspension of our drilling and completion activity during most of the second and third quarters of 2020, which resulted in only 31 new wells being completed and brought online during 2020 and added 2,849 MBbls of net oil production during the year endedDecember 31, 2020 as compared to 84 wells completed and brought online during 2019 adding 5,611 MBbls of net oil production during the year endedDecember 31, 2019 ; (ii) the curtailment of a portion of our production during the second quarter of 2020; and (iii) normal field production declines 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, during 2020, we flared significantly less wellhead gas as compared to 2019, resulting in a higher ratio of natural gas and NGL sales compared to oil sales in the period. In addition, for over half of 2020, the main processor of our raw gas operated in ethane-rejection as compared to operating in ethane-recovery during the majority of 2019. As a result, we sold an increased amount of natural gas from our wet gas stream and recovered fewer NGLs during the 2020 period, resulting in a lower decline in natural gas volumes (down 1%) as compared to the 14% decrease in NGL volumes between periods. Operating Expenses. The following table sets forth selected operating expense data for the periods indicated: Year Ended December 31, Increase/(Decrease) 2020 2019 $ % Operating costs (in thousands): Lease operating expenses$ 109,282 $ 145,976 $ (36,694) (25) % Severance and ad valorem taxes 39,417 63,200 (23,783) (38) % Gathering, processing, and transportation expense 71,309 72,834 (1,525) (2) % Operating costs per Boe: Lease operating expenses$ 4.45 $ 5.26 $ (0.81) (15) % Severance and ad valorem taxes 1.60 2.28 (0.68) (30) % Gathering, processing, and transportation expense 2.90 2.62 0.28 11 % Lease Operating Expenses. Lease operating expenses ("LOE") for the year endedDecember 31, 2020 decreased$36.7 million compared to the year endedDecember 31, 2019 . Lower LOE for 2020 was primarily related to a$21.9 million decrease in workover expense between periods as a result of less workover activity and a$14.8 million decrease in well operating expenses associated with cost reduction initiatives, described below, as well as lower variable and semi-variable costs stemming from the 11% production decline between periods. These decreases were partially offset by LOE costs associated with our higher well count in 2020. We had 386 gross operated horizontal wells as ofDecember 31, 2020 compared to 349 gross operated horizontal wells as ofDecember 31, 2019 . The net increase in well count was mainly the result of our drilling activity adding 31 gross operated wells in 2020, which was further adjusted for acquisitions and divestitures. LOE on a per Boe basis decreased when comparing the year endedDecember 31, 2020 to the year endedDecember 31, 2019 . LOE per Boe was$4.45 for the year endedDecember 31, 2020 , which represents a decrease of$0.81 per Boe (or 15%) from 2019. This decrease in rate was mainly due to the lower level of workover activity discussed above as well as cost reduction initiatives we have undertaken such as (i) moving multiple wells off generators to more cost-efficient electrical line-power, (ii) switching wells away from electric submersible pumps ("ESPs") to more reliable and lower cost gas lift, and (iii) performing field reviews to reduce or eliminate various costs for contract labor, oilfield equipment and supplies. These decreases were partially offset 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 costs. Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the year endedDecember 31, 2020 decreased$23.8 million compared to the year endedDecember 31, 2019 . Severance taxes are primarily based on the market value of our 45 -------------------------------------------------------------------------------- Table of Contents 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 2020 decreased$17.9 million compared to the same 2019 period primarily due to lower oil, natural gas and NGL revenues between periods. Ad valorem taxes decreased$5.9 million between periods due to lower tax assessments on our oil and gas reserve values. Severance and ad valorem taxes as a percentage of total net revenues remained consistent between periods at 6.8% and 6.7% for the years endedDecember 31, 2020 and 2019, respectively. Gathering, Processing and Transportation Expenses. Gathering, processing and transportation costs ("GP&T") for the year endedDecember 31, 2020 decreased$1.5 million compared to the year endedDecember 31, 2019 due to an$8.3 million decrease in plant processing, transportation and gathering fees incurred between periods as a result of lower wellhead production in 2020. This was partially offset by a$6.5 million decrease in reimbursements (net of related fees) received from third parties for their usage of our available firm transportation capacity. On a per Boe basis, GP&T increased 11% from$2.62 for the year endedDecember 31, 2019 to$2.90 per Boe for the year endedDecember 31, 2020 . On a natural gas and NGLs volume basis (i.e. excluding crude oil barrels) the Boe rate likewise increased between periods from$5.98 to$6.27 for the year endedDecember 31, 2019 and 2020, respectively. These rate increases were mainly attributable to a lower amount of FT reimbursements (net of related fees) for the usage of our available FT capacity as referenced above. Depreciation, Depletion, and Amortization. The following table summarizes our depreciation, depletion and amortization ("DD&A") for the periods indicated: Year Ended
(in thousands, except per Boe data) 2020 2019 Depreciation, depletion and amortization$ 358,554 $ 444,243 Depreciation, depletion and amortization per Boe$ 14.59 $ 16.00 Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved developed reserves and proved undeveloped reserves. For the year endedDecember 31, 2020 , DD&A expense amounted to$358.6 million , a decrease of$85.7 million over 2019. The primary factor contributing to lower DD&A expense in 2020 was the decrease in our overall production volumes between periods, which decreased DD&A expense by$51.0 million for the year endedDecember 31, 2020 , while lower DD&A rates between periods lowered DD&A expense by$34.7 million . DD&A per Boe was$14.59 for the year endedDecember 31, 2020 compared to$16.00 in 2019. 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 and (ii) upward revisions to proved developed reserves of 18.3 MMBoe for the year endedDecember 31, 2020 related to lower operating costs that we realized during 2020, which were partially offset by downward revisions associated with lowerSEC reserve pricing. Impairment and Abandonment Expense. For the year endedDecember 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 as a result of the depressed NYMEX oil and gas futures curves as ofMarch 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 non-cash impairment of other noncurrent assets, which represented advances paid to a third-party broker to acquire exploratory leasehold acres on our behalf, which acres are not currently included in our current development plan. We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that the fair value of these assets may be below their carrying value. Fair values of our oil and natural gas properties are estimated using an income approach that is based on the discounted expected future net cash flows from these assets. These valuations are based on inputs which require significant judgment and include estimates of: (i) oil and gas reserves quantities; (ii) future production decline rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; and (v) a market participant-based weighted-average cost of capital discount rate. We performed an impairment assessment of all our proved oil and gas properties as ofMarch 31, 2020 . Two of our fields were subject to impairment write-downs as quantified above, but the remaining five fields were not impaired due to their undiscounted cash flows exceeding their carrying values by 30% to over 100%. This impairment assessment was performed using commodity price futures curves as ofMarch 31, 2020 . If future oil, natural gas and NGL prices were to decline to lower levels, or other estimates impacting future net cash flows deteriorate (e.g. reserves, price differentials, future operating and/or development costs), our proved oil and gas properties could be subject to additional impairment write-downs in future periods. We did not recognize any additional impairment write-downs with respect to our proved oil and gas properties for the remainder of 2020. 46 -------------------------------------------------------------------------------- Table of Contents For the year endedDecember 31, 2019 ,$47.2 million of impairment and abandonment expense was incurred related to undeveloped leasehold acreage. This expense consisted of (i)$19.1 million related to non-core acreage that expired during 2019 after efforts to extend, sell or trade these leases were unsuccessful, (ii)$16.6 million for impaired acreage following an acreage sale initiated in the first quarter of 2019, and (iii)$11.5 million related to the amortization of leasehold expiration costs associated with individually insignificant unproved properties. Exploration and Other Expenses. The following table summarizes exploration and other expenses for the periods indicated: Year Ended December 31, (in thousands) 2020
2019
Geological and geophysical costs$ 4,533 $
8,424
Stock-based compensation - equity awards 1,433
2,682
Stock-based compensation - liability awards 90 - Exploratory dry hole costs 6,615 - Rig termination fees 3,046 284 Severance payments 722 - Other expenses 1,916 - Exploration and other expenses$ 18,355 $
11,390
Exploration and other expenses were$18.4 million for the year endedDecember 31, 2020 compared to$11.4 million for the year endedDecember 31, 2019 . Exploration and other expenses mainly consists 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 (i)$6.6 million in exploratory dry hole costs incurred in 2020; (ii)$2.8 million in higher rig termination fees as a result of temporarily suspending drilling activity in 2020; and (iii)$1.7 million in environmental remediation costs incurred in 2020 associated with a recently acquired proved property. These increases were partially offset by (i) a$1.7 million decrease in G&G project and seismic costs incurred between periods, and (ii)$2.2 million in lower G&G personnel costs and$1.2 million in lower stock-based compensation in the 2020 period, both of which were associated with the lower headcount from our 2020 workforce reduction (as further described below under General and Administrative Expenses). General and Administrative Expenses. The following table summarizes our general and administrative ("G&A") expenses for the periods indicated: Year EndedDecember 31 , (in thousands) 2020
2019
Cash general and administrative expenses$ 46,356 $
52,841
Stock-based compensation - equity awards 19,533
26,315
Stock-based compensation - liability awards 3,512
-
Severance payments 3,466
-
General and administrative expenses$ 72,867 $
79,156
G&A expenses for the year endedDecember 31, 2020 were$72.9 million compared to$79.2 million for the year endedDecember 31, 2019 . Lower G&A expenses incurred in 2020 were primarily the result of a reduction to our workforce and reduced salaries effectiveMay 1, 2020 for employees that were retained. These two factors combined resulted in a$5.4 million decrease in payroll and other personnel related costs and a$6.8 million decrease in equity-based stock compensation expense between periods. In addition, in 2019 we incurred a$1.8 million charge for the settlement of a water disposal contract dispute that did not re-occur in 2020. These decreases were partially offset by 2020 charges related to (i)$3.5 million of nonrecurring severance payments paid to G&A employees who were included in our workforce reduction and (ii)$3.5 million in stock compensation expense related to liability awards granted to G&A employees in the third quarter of 2020 that we will settle in cash upon vesting. These liability stock-based awards are recorded at their respective fair values, and such fair values are re-measured each balance sheet date (refer to Note 6-Stock-Based Compensation under Part II, Item 8 of this Annual Report for additional information regarding the liability awards). 47 -------------------------------------------------------------------------------- Table of Contents Other Income and Expense. Interest Expense. The following table summarizes interest expense for the periods indicated: Year Ended December 31, (in thousands) 2020 2019 Credit facility$ 12,973 $ 8,371 6.875% Senior Notes due 2027 28,368 27,309 5.375% Senior Notes due 2026 17,884 21,500 8.000% Senior Secured Notes due 2025 6,185 - Amortization of debt issuance costs and debt discount 5,923 2,861 Interest capitalized (2,141) (4,050) Total$ 69,192 $ 55,991 Interest expense was$13.2 million higher for the year endedDecember 31, 2020 compared to the year endedDecember 31, 2019 . Higher interest expense incurred during the year ended 2020 was mainly due to (i)$6.2 million in interest incurred on our new Senior Secured Notes issued in May of 2020 in connection with our Debt Exchange (refer to Note 4-Long-Term Debt under Part II, Item 8 of this Annual Report), (ii)$4.6 million in higher interest expense incurred on our credit facility borrowings, (iii)$3.1 million in higher amortization of debt issuance costs and the debt discount recognized inMay 2020 in connection with our Debt Exchange and (iv)$1.9 million in lower capitalized interest due to our decreased capital spend in 2020. These increases were partially offset by lower interest expense incurred on our 2026 Senior Notes during the 2020 period, as$110.6 million of the 2026 Senior Notes were extinguished in our Debt Exchange transaction. Our weighted average borrowings outstanding under our credit facility were$334.2 million during 2020 compared to$154.8 million in 2019. Our credit facility's weighted average effective interest rate (which is a LIBOR-based rate) was 3.3% for 2020 as compared to 3.7% during 2019 as a result of lower LIBOR in 2020. Gain on exchange of debt. A gain of$143.4 million was recognized for the year endedDecember 31, 2020 related to our opportunistic Debt Exchange that was executed in the second quarter of 2020. This gain was determined based on the difference between the carrying value of the Senior Unsecured Notes extinguished less the fair value of our newly issued Senior Secured Notes on their date of issuance. Refer to Note 4-Long-Term Debt under Part II, Item 8 of this Annual Report for additional information regarding the gain on exchange of debt.Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) fluctuations in mark-to-market derivative fair values associated with changes in the forward price curves for the commodities underlying our hedge contracts outstanding and (ii) monthly settlements of our hedged derivative positions. The following table presents gains and losses on our derivative instruments for the periods indicated: Year Ended December 31, (in thousands) 2020 2019 Realized cash settlement gains (losses)$ (46,651) $ (5,655) Non-cash mark-to-market derivative gain (loss) (17,884) 4,094 Total$ (64,535) $ (1,561)
Income Tax (Expense) Benefit: The following table summarizes our pre-tax income (loss) and income tax (expense) benefit for the periods indicated.
Year Ended December 31, (in thousands) 2020 2019
Income (loss) before income taxes
85,124 (5,797) Our provision for income taxes for the years endedDecember 31, 2020 and 2019 differs from the amounts that would be provided by applying the statutoryU.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 endedDecember 31, 2020 , we recognized a deferred tax asset valuation allowance of$77.0 million against net operating losses that we generated during the period, which are estimated as unlikely to be realized in future periods. This 48 -------------------------------------------------------------------------------- Table of Contents increase in valuation allowance was the primary factor reducing our income tax benefit for the year endedDecember 31, 2020 from theU.S. statutory rate to$85.1 million . For the year endedDecember 31, 2019 , we recognized a discrete permanent item of$1.7 million for lower deductions on stock awards that vested during the period, which was partially offset by a decrease in a projected permanent item of$0.8 million related to future stock compensation not expected to be deductible. These items were the primary factors increasing our income tax expense for the year endedDecember 31, 2019 from theU.S. statutory rate to$5.8 million . For the Year EndedDecember 31, 2019 Compared to the Year EndedDecember 31, 2018 Refer to Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in the 2019 Annual Report on Form 10-K filed with theSEC for a discussion of the results of operations for the year endedDecember 31, 2019 compared to the year endedDecember 31, 2018 . 49 -------------------------------------------------------------------------------- Table of Contents Liquidity and Capital Resources Overview Our drilling and completion and land acquisition 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, and proceeds from offerings of debt or equity securities. Future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly inMarch 2020 and have remained volatile since. These lower commodity prices negatively impact our operating 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: (in millions) Year EndedDecember 31 ,
2020
Drilling and completion capital expenditures $
212.0
Facilities, infrastructure and other
38.2
Land
4.6
Total capital expenditures $
254.8
We continually evaluate our capital needs and compare them to our capital resources. As a result of the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we temporarily suspended all drilling and completion activities at the end of the first quarter of 2020 in order to preserve capital. Specifically, we reduced our operated drilling rig program to zero rigs starting in April of 2020 and continued with no drilling rigs in operation until the end ofSeptember 2020 when we resumed drilling activity with a one-rig program. Of our$212.0 million in drilling and completion capital expenditures incurred during the year endedDecember 31, 2020 , approximately 70% was incurred during the first quarter of 2020. We operated one drilling rig during the entire fourth quarter, added a second drilling rig in lateDecember 2020 , and we plan to continue to operate a two rig program through 2021. We expect our total capex budget for 2021 to be between$260 million to$310 million , of which$250 million to$290 million is allocated to drilling, completion and facilities activity. We expect to fund our capex budget entirely from cash flows from operations given current commodity price levels. We were free cash flow positive during the second half of 2020 such that we were able to partially pay down borrowings under our credit agreement during the third and fourth quarters of 2020. Based upon current commodity prices, we expect to continue to pay down borrowings through expected free cash flow generation during 2021. 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. Given the weakness in realized oil prices, we voluntarily curtailed or shut-in a portion of our second quarter 2020 production volumes. Specifically, we curtailed approximately 20% of our production during the month of May but were able to bring the majority of our production back online in June as crude oil prices recovered. We did not experience any further curtailments of our production during the remainder of the year, but curtailments could occur in the future as a result of depressed market conditions, storage and transportation constraints and weather. Any decision in the future to curtail or shut-in our production or reduce our drilling and completion activity could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. 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, in order to manage our future financing cash outflows and improve our liquidity position, we completed the Debt Exchange with respect to our Senior Unsecured Notes inMay 2020 , which reduced the total principal amounts due of our aggregated secured and unsecured notes by$127.1 million and also reduced future interest payments. 50 -------------------------------------------------------------------------------- Table of Contents Analysis of Cash Flow Changes The following table summarizes our cash flows for the periods indicated: Year Ended December
31,
(in thousands) 2020 2019
2018
Net cash provided by operating activities
(1,068,664)
Net cash provided by financing activities 147,743 362,937
294,160
Cash Flows from 2020 Compared to 2019. For the year endedDecember 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. Refer to "Results of Operations" for more information on the impact of volumes and prices on revenues and on fluctuations in our operating costs periods. For the year endedDecember 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. Cash Flows from 2019 Compared to 2018. For the year endedDecember 31, 2019 , we generated$564.2 million of cash from operating activities, a decrease of$105.8 million from 2018. Cash provided by operating activities decreased primarily due to lower realized prices for crude oil, natural gas and NGLs, higher lease operating expenses, severance and ad valorem taxes, GP&T costs, exploration expense, cash G&A expenses, interest payments, cash settlement losses from derivatives and the timing of our supplier payments during 2019. These declining factors were partially offset by higher crude oil, natural gas and NGL production volumes and the timing of our receivable collections during 2019 as compared to the 2018 period. For the year endedDecember 31, 2019 , cash flows from operating activities, cash on hand, proceeds from sales of oil and gas properties and proceeds from the issuance of our 2027 Senior Notes were used to repay net borrowings of$125.0 million under our credit facility, to finance$855.2 million of drilling and development capex, to fund$103.7 million in oil and gas property acquisitions and to purchase$8.9 million of other property and equipment. Credit Agreement CRP, our consolidated subsidiary, has a credit agreement with a syndicate of banks that provides for a five-year secured revolving credit facility, maturing onMay 4, 2023 (the "Credit Agreement"). OnMay 1, 2020 , CRP as borrower and we, as parent guarantor, entered into the Q2 2020 Amendments, which among other things established a new borrowing base of$700.0 million and a new level of elected commitments also$700.0 million . The Q2 2020 Amendments that the lenders approved permitted the issuance of the Senior Secured Notes in connection with the Debt Exchange (discussed below), and they implemented an availability blocker equal to 25% of the newly issued amount of Senior Secured Notes. As ofDecember 31, 2020 , we had$330.0 million in borrowings outstanding and$333.9 million in available borrowing capacity, which was net of$4.3 million in letters of credit outstanding and the availability blocker of$31.8 million . In connection with the Credit Agreement's fall 2020 semi-annual borrowing base redetermination, the borrowing base and amount of elected commitments were both reaffirmed at$700.0 million . CRP's Credit Agreement contains restrictive covenants that limit its ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make or declare dividends; (v) enter into commodity hedges exceeding a specified percentage of our expected production; (vi) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (vii) incur liens; (viii) sell assets; and (ix) engage in transactions with affiliates. CRP's 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 Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; (ii) a first lien leverage ratio, as defined within the Credit Agreement as the ratio of first lien debt to EBITDAX for the rolling four fiscal quarter period, which may not exceed 2.75 to 1.00 beginning with the quarter endingJune 30, 2020 and extending through the quarter endingDecember 31, 2021 , after which the maximum ratio shall decrease to 2.50 to 1.00 for each of the quarters ending in 2022; and 51 -------------------------------------------------------------------------------- Table of Contents (iii) a leverage ratio, as defined within the Credit Agreement as the ratio of total funded debt to consolidated EBITDAX for the rolling four fiscal quarter period. Pursuant to the Q2 2020 Amendments, the leverage ratio is suspended untilMarch 31, 2022 , at which time, the ratio may not exceed 5.00 to 1.00, with such maximum ratio declining at a rate of 0.25 for each succeeding quarter untilMarch 31, 2023 when the ratio is set at not greater than 4.0 to 1.0. CRP was in compliance with the covenants and applicable financial ratios described above as ofDecember 31, 2020 and through the filing of this Annual Report. For further information on the Credit Agreement, refer to Note 4-Long-Term Debt under Part II, Item 8 of this Annual Report. Senior Unsecured Notes Debt Exchange and Senior Secured Notes OnMay 22, 2020 , CRP completed the Debt Exchange pursuant to which$110.6 million aggregate principal amount of CRP's 2026 Senior Notes and$143.7 million aggregate principal amount of CRP's 2027 Senior Notes were validly tendered and exchanged by certain eligible bondholders for consideration consisting of$127.1 million aggregate principal amount of newly issued Senior Secured Notes. The Senior Secured Notes bear interest at an annual rate of 8% and are due onJune 1, 2025 . Interest is payable semi-annually in arrears on eachJune 1 andDecember 1 , commencing onDecember 1, 2020 . The Debt Exchange was accounted for as an extinguishment of debt in accordance withFinancial Accounting Standards Board's Accounting Standard Codification Topic 470-50, Modifications and Extinguishments. As a result, a gain on the exchange of debt of$143.4 million was recognized in the consolidated statement of operations, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of new Senior Secured Notes issued, net of their associated debt discount of$21.0 million (which was based on the Senior Secured Notes' estimated fair value on the exchange date). The Senior Secured Notes are guaranteed, subject to certain exceptions, by us and each of CRP's subsidiaries and are secured on a second-priority basis (subject in priority only to certain exceptions) by substantially all of CRP's and our assets, including deposit accounts and substantially all proved reserves and undeveloped acreage. Senior Unsecured Notes OnNovember 30, 2017 , CRP issued$400.0 million of 5.375% senior notes due 2026 and onMarch 15, 2019 , CRP issued$500.0 million of 6.875% senior notes due 2027 in 144A private placements. 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. InMay 2020 , a portion of the Senior Unsecured Notes were exchanged for Senior Secured Notes (see above discussion for details of the Debt Exchange). The indentures governing the Senior Unsecured Notes and Senior Secured Notes (collectively, the "Senior 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 ofDecember 31, 2020 and through the filing of this Annual Report. For further information on our Senior Notes, refer to Note 4-Long-Term Debt under Part II, Item 8 of this Annual Report. Off-Balance Sheet Arrangements We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As ofDecember 31, 2020 , we had no off-balance sheet arrangements. 52 -------------------------------------------------------------------------------- Table of Contents Contractual Obligations 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 ofDecember 31, 2020 to make future payments under long-term contracts for the time periods specified below. (in thousands) 2021 2022 2023 2024 2025 Thereafter Total Operating leases(1)$ 3,260 $ 425 $ - $ - $ - $ -$ 3,685 Water disposal agreements(2) 1,825 100 - - - - 1,925 Asset retirement obligations(3) 384 - - 457 - 16,168
17,009
Long term debt obligations(4) - - 330,000 - 127,073 645,799
1,102,872
Cash interest expense on long-term debt obligations(5) 62,319 62,319 58,749 50,223 44,290 30,547
308,447
Transportation agreements(6) 9,060 1,770 - - - - 10,830 Total$ 76,848 $ 64,614 $ 388,749 $ 50,680 $ 171,363 $ 692,514 $ 1,444,768 (1) Operating leases include 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) Water disposal agreements consist of contracts for transportation and disposal of produced water from our operated wells. Under the terms of these agreements, we are obligated to deliver a minimum volume of produced water or else pay for any deficiencies at the prices stipulated in the contracts. The obligations reported above represent our remaining minimum financial commitments pursuant to the terms of these contracts as ofDecember 31, 2020 . Actual expenditures under these contracts 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 the Senior Notes due and borrowings outstanding under the Credit Agreement maturing onMay 4, 2023 . (5) Cash interest expense on the 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. Recently Issued Accounting Standards There were no significant new accounting standards adopted or new accounting pronouncements that would have a potential effect on us as ofDecember 31, 2020 . 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. 53 -------------------------------------------------------------------------------- Table of Contents 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 theSEC , 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 period that changes to reserve estimates are made. Impairment ofOil 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 testing impairment is 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. 54
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