The following discussion and analysis of our financial condition and results of operation should be read in conjunction with the accompanying consolidated financial statements and related notes. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, 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 Coronavirus Disease 2019 ("COVID-19") and other uncertainties, as well as those factors discussed above in "Cautionary Statement Regarding Forward-Looking Statements" and under the heading "Item 1A. Risk Factors" in our 2020 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. OverviewCentennial Resource Development, Inc. ("Centennial," "we," "us," or "our") is an independent oil and natural gas company focused on the development of 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. Unless otherwise specified or the context otherwise requires, all references in these discussions to "Centennial," "we," "us," or "our" are toCentennial Resource Development, Inc. and its consolidated subsidiary,Centennial Resource Production, LLC ("CRP"). 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 bySaudi Arabia to drastically reduce export prices and increase oil production inMarch 2020 (the "Saudi-Russia oil price war") followed by curtailment agreements amongOrganization of Petroleum Exporting Countries ("OPEC") and other countries such asRussia further increased uncertainty and volatility around global oil supply-demand dynamics. However, in April of 2020, the members ofOPEC and other oil producing countries agreed to reduce their crude oil production throughout the year, whileU.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 and other producing countries extended their production cuts through the first quarter of 2021 with gradual output increases expected to begin in the second quarter of 2021. Further,U.S. drilling activity only began to increase in the fourth quarter of 2020 and has continued to increase steadily since. The continued reduction in overall oil supply paired with the expectation of a recovery in global oil demand due to the availability of COVID-19 vaccinations and less governmental mandated restrictions have aided in the recovery of global commodity prices during the first quarter of 2021. Specifically, WTI spot prices for crude oil reached a high of$66.09 per barrel onMarch 5, 2021 from a low of negative$37.63 per barrel onApril 20, 2020 (which was due to depressed demand and insufficient storage capacity, particularly at the WTI physical settlement location inCushing, Oklahoma ). The oil and natural gas industry is cyclical, and it is likely that commodity prices, as well as commodity price differentials, will continue to be volatile due to fluctuations in global supply and demand, inventory levels, the continued effects from COVID-19, geopolitical events, weather conditions, the global transition to alternative energy sources and other factors. The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of 2019: 2019 2020 2021 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Crude oil (per Bbl)$ 54.90 $ 59.81 $ 56.45 $ 56.94 $ 46.19 $ 28.00 $ 40.93 $ 42.66 $ 57.84 Natural gas (per MMBtu)$ 2.88 $ 2.51 $ 2.33 $ 2.34 $ 1.88 $ 1.65 $ 1.95 $ 2.47 $ 3.44 Lower commodity prices (including realized differentials) and lower futures curves for oil and gas prices, can result in further 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 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 32 -------------------------------------------------------------------------------- Table of Contents 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. 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, vendors, 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 been working remotely or 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) 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 and 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 the first quarter of 2021, which enabled us to complete and bring online 11 gross operated wells with an average effective lateral length of approximately 8,100 feet. InFebruary 2021 , thePermian 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, which further lead to significant increases in gas prices, gathering, processing and transportation fees and electrical rates during this time. Our operations were impacted by Winter Storm Uri and lead to a partial shut-in of certain wells and associated production for about seven days during the event. Refer to the discussion below for the current impacts from the Winter Storm Uri on results of operations for the three months endedMarch 31, 2021 . Financing Highlights OnMarch 19, 2021 , we issued$150.0 million of 3.25% senior convertible notes due 2028 (the "Convertible Senior Notes") in a public offering. OnMarch 26, 2021 , the Company issued an additional$20.0 million of Convertible Senior Notes pursuant to the exercise of the underwriters' over-allotment option to purchase additional Convertible Senior Notes. The issuance resulted in net proceeds of$163.7 million , after deducting debt issuance costs of$6.3 million , and such proceeds were used to fund the cost of entering into capped call spread transactions of$14.7 million and repay borrowing outstanding under CRP's revolving credit facility. InApril 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. In connection with CRP's credit facility spring 2021 semi-annual borrowing base redetermination, the borrowing base and amount of elected commitments were reaffirmed at$700.0 million . 33 -------------------------------------------------------------------------------- Table of Contents Results of Operations Three Months EndedMarch 31, 2021 Compared to Three Months EndedMarch 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: Three Months Ended March 31, Increase/(Decrease) 2021 2020 $ % Net revenues (in thousands): Oil sales$ 133,726 $ 170,505 $ (36,779) (22) % Natural gas sales 35,451 8,358 27,093 324 % NGL sales 23,214 13,906 9,308 67 % Oil and gas sales$ 192,391 $ 192,769 $ (378) - % Average sales prices: Oil (per Bbl) $ 52.62$ 45.14 $ 7.48 17 % Effect of derivative settlements on average price (per Bbl) (9.43) (0.01) (9.42) (94,200) % Oil net of hedging (per Bbl) $ 43.19$ 45.13 $ (1.94) (4) %
Average NYMEX price for oil (per Bbl) $ 57.84
11.65 25 % Oil differential from NYMEX (5.22) (1.05) (4.17) (397) % Natural gas (per Mcf) $ 3.79$ 0.78 $ 3.01 386 % Effect of derivative settlements on average price (per Mcf) 0.12 - 0.12 100 %
Natural gas net of hedging (per Mcf) $ 3.91
3.13 401 % Average NYMEX price for natural gas (per Mcf) $ 3.44$ 1.88 $ 1.56 83 % Natural gas differential from NYMEX 0.35 (1.10) 1.45 132 % NGL (per Bbl) $ 29.78$ 14.30 $ 15.48 108 % Net production: Oil (MBbls) 2,542 3,778 (1,236) (33) % Natural gas (MMcf) 9,343 10,715 (1,372) (13) % NGL (MBbls) 780 972 (192) (20) % Total (MBoe)(1) 4,878 6,536 (1,658) (25) % Average daily net production: Oil (Bbls/d) 28,239 41,512 (13,273) (32) % Natural gas (Mcf/d) 103,806 117,751 (13,945) (12) % NGL (Bbls/d) 8,662 10,683 (2,021) (19) % Total (Boe/d)(1) 54,202 71,820 (17,618) (25) %
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
34 -------------------------------------------------------------------------------- Table of Contents Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the three months endedMarch 31, 2021 were$0.4 million (or 0.2%) lower than total net revenues for the three months endedMarch 31, 2020 . Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized. Average realized sales prices for oil, residue gas and NGLs increased in the first quarter of 2021 compared to the same 2020 period by 17%, 386% and 108% respectively. The 17% increase in the average realized oil price before the effects of hedging was the result of higher NYMEX crude prices between periods (average NYMEX prices increased 25%), which was partially offset by wider oil differentials ($4.17 per Bbl wider) associated with our firm oil sales agreement that is based upon the prevailing market price of ICE Brent less contractual differentials. The 386% increase in average realized sales price of natural gas before the effects of hedging was due to higher NYMEX prices (average prices increased 83%) and improved gas differentials ($1.45 per Mcf). The increase in average realized NGL prices of 108% between periods was primarily attributable to higher Mont Belvieu spot prices for plant products in the first quarter of 2021 as compared to the first quarter of 2020. The market prices for oil, natural gas and NGLs have all been impacted by higher global demand for oil and gas compared to the first quarter of 2020 when prices decreased significantly as a result of COVID-19 and supply disruptions from the Saudi-Russia oil price war, beginning inMarch 2020 as discussed in the market conditions section above. Additionally, the first quarter 2021 realized price for natural gas in thePermian Basin was impacted by Winter Storm Uri, which caused gas pipeline and supply disruptions and resulted in significant natural gas price increases in the area during this period. Net production volumes for oil, natural gas, and NGLs decreased 33%, 13% and 20%, respectively. The crude oil production volume decrease was primarily the result of less drilling and completion activity over the past 12 months as a result of depressed oil and gas prices, which resulted in only 20 wells being placed on production since the first quarter of 2020. This added 422 MBbls of net oil production to the three months endedMarch 31, 2021 as compared to 86 wells brought online since the first quarter of 2019 that added 1,864 MBbls of net oil production to the first quarter of 2020. Oil volume declines in the first quarter of 2021 were additionally impacted by the temporary shut-in of our wells during mid-February as a result of Winter Storm Uri and 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 the first quarter of 2021, the amount of gas flared as a percentage of wellhead gas produced was significantly less as compared to the same 2020 period, resulting in a higher ratio of natural gas and NGL volumes produced compared to oil volumes during the period. Operating Expenses. The following table sets forth selected operating expense data for the periods indicated: Three Months Ended March 31, Increase/(Decrease) 2021 2020 $ % Operating costs (in thousands): Lease operating expenses$ 25,861 $ 32,639 $ (6,778) (21) % Severance and ad valorem taxes 12,583 16,573 (3,990) (24) % Gathering, processing and transportation expenses 20,625 16,939 3,686 22 % Operating costs per Boe: Lease operating expenses $ 5.30$ 4.99 $ 0.31 6 % Severance and ad valorem taxes 2.58 2.54 0.04 2 % Gathering, processing and transportation 4.23 2.59 expenses 1.64 63 % Lease Operating Expenses. Lease operating expenses ("LOE") for the three months endedMarch 31, 2021 decreased$6.8 million compared to the three months endedMarch 31, 2020 . Lower LOE for the first quarter of 2021 was primarily related to (i) a$4.6 million decrease in workover expense as a result of lower workover activity between periods; (ii) lower well operating expenses associated with cost reduction initiatives including moving multiple wells off generators to more cost-efficient electrical line-power and switching wells away from electric submersible pumps to more reliable and lower cost gas lift; and (iii) lower variable and semi-variable costs stemming from the 25% production decline between periods. These decreases were partially offset by LOE costs associated with our higher well count, which increased to 397 gross operated horizontal wells as ofMarch 31, 2021 from 377 gross operated horizontal wells as ofMarch 31, 2020 as a result of our drilling activity adding 20 wells since the first quarter of 2020. LOE per Boe was$5.30 for the first quarter of 2021, which represents an increase of$0.31 per Boe (or 6%) from the first quarter of 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 costs. These increases were partially offset by the lower level of workover activity as well as cost reduction initiatives we have undertaken, both of which are discussed above. 35 -------------------------------------------------------------------------------- Table of Contents Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three months endedMarch 31, 2021 decreased$4.0 million compared to the three months endedMarch 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. Ad valorem taxes decreased$3.3 million between periods due to lower tax assessments on our oil and gas reserve values. Severance taxes remained consistent between periods at 5.3% of total net revenues during the first quarter of 2021 as comparable to 5.5% during the same prior year quarter. Gathering, Processing and Transportation Expenses. Gathering, processing and transportation expenses ("GP&T") for the three months endedMarch 31, 2021 increased$3.7 million as compared to the three months endedMarch 31, 2020 . On a per Boe basis, GP&T likewise increased from$2.59 for the first quarter of 2020 to$4.23 for the first quarter of 2021. These increases were mainly attributable to (i) higher gas plant processing costs, which are primarily based on natural gas and NGL prices both of which increased substantially between periods as discussed above, and (ii) a$0.9 million decrease in reimbursements received from third parties for their usage of our available firm transport capacity. Depreciation, Depletion and Amortization. The following table summarizes our depreciation, depletion and amortization ("DD&A") for the periods indicated: Three Months Ended March 31, (in thousands, except per Boe data) 2021 2020 Depreciation, depletion and amortization$ 63,783 $ 101,258 Depreciation, depletion and amortization per Boe $
13.08
For the three months endedMarch 31, 2021 , DD&A expense amounted to$63.8 million , a decrease of$37.5 million over the same 2020 period. The primary factor contributing to lower DD&A expense in 2021 was the decrease in our overall production volumes between periods, which lowered our DD&A expense by$25.7 million , while our lower DD&A rates between periods decreased DD&A expense by an additional$11.8 million during the three months endedMarch 31, 2021 . 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$13.08 for the first quarter of 2021 compared to$15.49 for the same period in 2020. This decrease in DD&A rate was primarily due to the proved property impairment recognized in the first quarter of 2020, which lowered the carrying value of our depletion base by$591.8 million , combined with lower finding and development costs incurred on our recently completed wells. These downward impacts were partially offset by net downward revisions in our proved reserves since the first quarter of 2020, which are mainly due to lowerSEC reserve pricing. Impairment and Abandonment Expense. During the three months endedMarch 31, 2021 impairment and abandonment expense was$9.2 million and related to the amortization of leasehold expiration costs associated with individually insignificant unproved properties. During the three months endedMarch 31, 2020 , impairment and abandonment expense was$611.3 million and consisted of (i) a$591.8 million non-cash impairment of our proved oil and gas properties as a result of depressed NYMEX oil and gas forward curves as ofMarch 31, 2020 , and (ii)$19.5 million related to the amortization of leasehold expiration costs associated with individually insignificant unproved properties. Exploration and Other Expenses. The following table summarizes our exploration and other expenses for the periods indicated: Three Months Ended
(in thousands) 2021
2020
Geological and geophysical costs $ 613
Rig termination fees -
1,499
Stock-based compensation - equity awards 208
517
Stock-based compensation - liability awards 167 - Other expenses 107 - Exploration and other expenses$ 1,095
Exploration and other expenses were$1.1 million for the three months endedMarch 31, 2021 compared to$4.0 million for the three months endedMarch 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 includes other operating costs. The period over period decrease was primarily related to a (i)$1.5 million decrease in rig termination fees, that were incurred when we reduced our drilling program from five rigs to one in March of 2020, (ii)$0.7 million in lower ongoing G&G personnel costs associated 36 -------------------------------------------------------------------------------- Table of Contents with the 2020 workforce reduction (as further described below under General and Administrative Expenses), and (iii) a$0.6 million decrease in G&G project costs and seismic studies between periods. General and Administrative Expenses. The following table summarizes our general and administrative ("G&A") expenses for the periods indicated: Three Months Ended
(in thousands) 2021
2020
Cash general and administrative expenses$ 10,632
Stock-based compensation - equity awards 4,377
5,892
Stock-based compensation - liability awards 10,247 - Severance payments - - General and administrative expenses$ 25,256
G&A expenses for the three months endedMarch 31, 2021 were$25.3 million compared to$18.9 million for the three months endedMarch 31, 2020 . The higher G&A incurred in the first quarter of 2021 was primarily the result of$10.2 million in stock compensation expense related to liability awards granted to G&A employees in the third quarter of 2020 that are settleable 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 5-Stock-Based Compensation for additional information regarding the liability awards). This increase was partially offset by a decrease in cash G&A primarily related to$1.8 million in lower payroll and other personnel related costs and a$1.5 million decrease in equity-based stock compensation expense between periods, both of which were primarily the result of a reduction to our workforce effectiveMay 1, 2020 . Other Income and Expenses. Interest Expense. The following table summarizes our interest expense for the periods indicated: Three Months Ended March 31, (in thousands) 2021 2020 Credit facility $ 3,315$ 2,167 8.00% Senior Secured Notes due 2025 2,541 - 5.375% Senior Notes due 2026 3,889 5,374 6.875% Senior Notes due 2027 6,125 8,594 3.25% Convertible Senior Notes due 2028 172 - Amortization of debt issuance costs and discount 1,847 799 Interest capitalized (404) (513) Total$ 17,485 $ 16,421 Interest expense was$1.1 million higher for the three months endedMarch 31, 2021 as compared to the three months endedMarch 31, 2020 primarily due to (i)$2.5 million in interest incurred on our Senior Secured Notes issued in May of 2020 in connection with our debt exchange; (ii)$1.1 million in increased interest expense incurred on our credit facility borrowings; and (iii)$1.0 million in higher amortization of debt issuance costs and discount between periods. These increases were partially offset by lower interest expense incurred on our Senior Unsecured Notes during the first quarter of 2021, as$110.6 million of the 2026 Senior Notes and$143.7 million of the 2027 Senior Notes were extinguished in our debt exchange transaction. Refer to Note 3-Long-Term Debt under Part I, Item I of this Quarterly Report for additional information on our Senior Notes and debt exchange transaction. Our weighted average borrowings outstanding under our credit facility were$330.9 million versus$233.9 million for the three months endedMarch 31, 2021 and 2020, respectively. Our credit facility's weighted average effective interest rate (which is a LIBOR-based rate) was 3.5% and 2.8% for the three months endedMarch 31, 2021 and 2020, respectively, as a result of higher LIBOR in the first quarter of 2021 versus the prior year quarter. 37 -------------------------------------------------------------------------------- Table of ContentsNet Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) fluctuations in mark-to-market derivative fair values associated with changes in the forward price curves for the commodities underlying our hedge contracts outstanding and (ii) monthly settlements on our hedged derivative positions. The following table presents gains and losses on our derivative instruments for the periods indicated: Three Months Ended March 31, (in thousands) 2021 2020 Realized cash settlement gains (losses)$ (22,886) $ (53) Non-cash mark-to-market derivative gain (loss) (28,313) (8,452) Total$ (51,199) $ (8,505)
Income Tax (Expense) Benefit. The following table summarizes our pre-tax income (loss) and income tax (expense) benefit for the periods indicated:
Three Months Ended March 31, (in thousands) 2021 2020 Income (loss) before income taxes$ (34,645) $
(633,553)
Income tax (expense) benefit -
83,208
Our provisions for income taxes for the three months endedMarch 31, 2021 and 2020 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) state income taxes, (ii) permanent differences, and (iii) any changes during the period in our deferred tax asset valuation allowance. For the three months endedMarch 31, 2021 and 2020, we recognized deferred tax asset valuation allowances of$12.4 million and$55.6 million , respectively, against net operating losses ("NOLs") we generated during those respective quarters, and such NOLs are estimated as unlikely to be realized in future periods. These increases in the valuation allowance were the primary factor reducing our income tax benefits (based on theU.S. statutory rate) in each respective quarter to zero for the first quarter of 2021 and to$83.2 million for the first quarter of 2020. 38 -------------------------------------------------------------------------------- Table of Contents Liquidity and Capital Resources Overview Our drilling and completion activities require us to make significant capital expenditures. Historically, our primary sources of liquidity have been cash flows from operations, borrowings under CRP's revolving credit facility, 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, which have been and will likely continue to be volatile. Lower commodity prices can negatively impact our cash flows and our ability to access debt or equity markets, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. To date, our primary use of capital has been for drilling and development capital expenditures and the acquisition of oil and natural gas properties. The following table summarizes our capital expenditures ("capex") incurred for the three months endedMarch 31, 2021 : (in millions) Three Months EndedMarch 31 ,
2021
Drilling, completion and facilities $
70.6
Infrastructure, land and other
2.3
Total capital expenditures incurred $
72.9
We continually evaluate our capital needs and compare them to our capital resources. We operated a two-rig drilling program during the first three months of 2021 and plan to continue with two rigs for the remainder of the year. 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 funded our capital expenditures for the three months endedMarch 31, 2021 entirely from cash flows from operations, and we expect to fund the remainder of our 2021 capex budget entirely from cash flows from operations as well, given current commodity price levels. We were free cash flow positive during the first quarter of 2021 such that we were able to partially pay down borrowings under our credit agreement during the period, and based upon current commodity prices, we expect to continue to pay down borrowings through expected free cash flow generation during the remainder of 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. 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 financing cash outflows and liquidity position, we issued 3.25% Convertible Senior Notes inMarch 2021 , which resulted in net proceeds of$163.7 million . The proceeds were used to fund the cost of entering into capped call spread transactions of$14.7 million and to repay borrowings outstanding under CRP's revolving credit facility during the first quarter of 2021. Subsequently inApril 2021 , we fully redeemed and repaid at par our Senior Secured Notes (defined below), which were due in 2025 and bore interest at 8.00% per year, which was the intended use of proceeds from the Convertible Senior Notes offering. Analysis of Cash Flow Changes The following table summarizes our cash flows for the periods indicated: Three Months Ended March 31, (in thousands) 2021 2020 Net cash provided by operating activities$ 72,346 $ 100,818 Net cash used in investing activities (46,598) (166,976) Net cash (used in) provided by financing activities (20,609) 59,792 For the three months endedMarch 31, 2021 , we generated$72.3 million of cash from operating activities, a decrease of$28.5 million from the same period in 2020. Cash provided by operating activities decreased primarily due to lower production volumes, higher GP&T costs, cash settlement losses on derivatives, and the timing of our receivable collections during the three 39 -------------------------------------------------------------------------------- Table of Contents months endedMarch 31, 2021 . These declining factors were partially offset by higher realized prices for all commodities, lower lease operating expenses, production taxes, cash G&A and the timing of our supplier payments for the three months endedMarch 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. During the three months endedMarch 31, 2021 , cash flows from operating activities and net proceeds from the issuance of the Convertible Senior Notes were used to finance$46.2 million of drilling and development cash expenditures, repay net borrowings of$170.0 million under our credit facility and to fund$14.7 million in capped call spread transactions. During the three months endedMarch 31, 2020 , cash flows from operating activities, cash on hand, and net borrowings of$60.0 million under our credit facility were used to finance$161.9 million of drilling and development cash expenditures and to fund$5.8 million in oil and gas property acquisitions. 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"). As ofMarch 31, 2021 , we had$160.0 million in borrowings outstanding and$503.9 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 spring 2021 semi-annual borrowing base redetermination, the borrowing base and amount of elected commitments were 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 us to maintain compliance with the following financial ratios: (i) a current ratio, which is the ratio of CRP's consolidated current assets (including unused commitments under its revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding any current portion of long-term debt due 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 (iii) a leverage ratio, as defined with 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 the applicable financial ratios described above as ofMarch 31, 2021 and through the filing of this Quarterly Report. For further information on the Credit Agreement, refer to Note 3-Long-Term Debt under Part I, Item I of this Quarterly Report. Convertible Senior Notes OnMarch 19, 2021 , CRP issued$150.0 million in aggregate principal amount of Convertible Senior Notes. OnMarch 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 Convertible Senior Notes. The Convertible Senior Notes bear interest at an annual rate of 3.25% and are due onApril 1, 2028 . Interest is payable semi-annually in arrears on eachApril 1 andOctober 1 , commencing onOctober 1, 2021 . CRP can settle the Convertible Senior Notes by paying or delivering cash, shares of the Company's Class A common stock (the "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. 40 -------------------------------------------------------------------------------- Table of Contents Senior Notes OnNovember 30, 2017 , CRP issued$400.0 million of 5.375% senior notes due 2026 (the "2026 Senior Notes") and onMarch 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. InMay 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 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 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 ofMarch 31, 2021 and through the filing of this Quarterly Report. For further information on our Convertible Senior Notes and Senior Notes, refer to Note 3-Long-Term Debt under Part I, Item I of this Quarterly Report. Contractual Obligations Our contractual obligations include operating and transportation agreements, drilling rig contracts, office and equipment leases, asset retirement obligations, long-term debt obligations and cash interest expense on long-term debt obligations, which we routinely enter into, modify or extend. SinceDecember 31, 2020 , there have not been any significant, non-routine changes in our contractual obligations, other than the changes to certain of our operating lease commitments and principal and interest due under our Convertible Senior Notes discussed above. Refer to Note 12-Leases under Part I, Item I of this Quarterly Report for updated contractual obligations associated with our operating leases as ofMarch 31, 2021 . Critical Accounting Policies and Estimates There have been no material changes during the three months endedMarch 31, 2021 to the critical accounting policies previously disclosed in our 2020 Annual Report. Please refer to Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Policies and Estimates in our 2020 Annual Report for a discussion of our critical accounting policies and estimates. New Accounting Pronouncements Please refer to Note 1-Basis of Presentation and Summary of Significant Accounting Policies under Part I, Item 1. of this Quarterly Report for a discussion of recently adopted accounting standards and the potential effects of new accounting pronouncements. 41
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