Centennial Resource Development Announces Full Year 2020 Results and 2021 Guidance
DENVER, February 23, 2021 (GLOBE NEWSWIRE) -- Centennial Resource Development, Inc. (“Centennial” or the “Company”) (NASDAQ: CDEV) today announced 2020 financial and operational results and 2021 operational plans and targets.
Financial and Operational Highlights
•Generated free cash flow and reduced total debt for the second consecutive quarter
•Reported 2020 production volumes, capital expenditures and total unit costs within full year guidance ranges
•Achieved record spud-to-total depth time for a two-mile lateral
•Increased year-over-year acreage position primarily through cost-free swaps and trades
2021 Financial and Operational Plan
•Expect to be free cash flow positive in 2021 using current strip pricing
•Anticipate significant reduction in leverage by year-end 2021
•Plan to operate two-rig drilling program
•Expect to average full year oil production consistent with fourth quarter 2020 levels
•Operational plan supported by structurally lower well costs and increased lateral lengths
Financial Results
For the full year, Centennial reported a net loss of $682.8 million, or $2.46 per diluted share, driven primarily by a non-cash impairment charge incurred during the first quarter in addition to historically low oil prices during a portion of the year as a result of the COVID-19 pandemic. Full year results compare to net income of $15.8 million, or $0.06 per diluted share, in the prior year. For the fourth quarter, the Company reported a net loss of $88.7 million, or $0.32 per diluted share, compared to net income of $9.6 million, or $0.03 per diluted share, in the prior year period. As a result of higher realized commodity prices and continued cost discipline, the Company generated net cash from operating activities of $41.1 million and free cash flow1 of $29.0 million in the fourth quarter of 2020.
Full year total equivalent production averaged 67,161 barrels of oil equivalent per day (“Boe/d”) compared to 76,072 Boe/d in the prior year. Average daily crude oil production during the full year was 36,084 barrels of oil per day (“Bbls/d”) compared to 42,692 Bbls/d in the prior year. For the fourth quarter, crude oil production averaged 30,196 Bbls/d, in-line with Company expectations as no new wells were placed on production during the quarter.
“We added a second rig in December and are excited to resume operational activity. Importantly, our team continues to drive higher efficiencies in the field which will remain a key focus for us in 2021,” said Sean R. Smith, Chief Executive Officer. “Coupled with current strip pricing, our reduced cost structure, lower well costs and shallower base decline rate sets us up for free cash flow generation this year. We expect to organically de-lever the balance sheet and end the year in a stronger financial position.”
2021 Operational Plans and Targets
Centennial plans to operate a two-rig drilling program in 2021. Assuming planned activity levels and current commodity prices, the Company expects its full year average oil production to remain largely consistent with fourth quarter 2020 levels. During 2021, Centennial will continue to focus on managing its balance sheet and improving liquidity.
“Our capital plan will position Centennial to be free cash flow positive, while improving our leverage metrics during 2021,” said Smith. “Ultimately, we expect to end the year with a net debt-to-LTM EBITDAX2 ratio below 2.5x, assuming current strip pricing.”
The estimated fiscal year 2021 total capital budget is approximately $260 million to $310 million. Total drilling, completion and facilities (“DC&F”) costs are estimated to be $250 million to $290 million, of which essentially all is associated with operated activity. The Company’s capital budget is underpinned by a 33% reduction in well costs compared to year-end 2019. Lastly, Centennial has allocated approximately $10 million to $20 million to infrastructure, land and other capital expenditures.
During 2021, Centennial anticipates that approximately 70% of its completions will occur in Lea County, New Mexico, with the remaining portion allocated to its Reeves County, Texas position. Additionally, the Company expects its average completed lateral length for the full year to increase 17% to approximately 8,800 feet compared to the prior year, driving further capital efficiency improvements.
(For a detailed table summarizing Centennial’s 2021 operational and financial guidance, please see the Appendix of this press release.)
Recent Winter Weather Impacts
The severe winter weather which recently affected millions of Americans across Texas and other states also impacted Centennial’s employees and operations. While the Company continues to assess developments in the field, Centennial recently regained full electric power to its operations and is in the process of placing wells back on production. As a result of these events and the expected timing of operational activity, Centennial expects its first quarter 2021 production levels to decline compared to the previous quarter. The Company expects a modestly increasing quarterly production profile for the remainder of the year.
“Our employees and their families’ well-being remain our top priority, and I would like to personally thank our team members in the field for their hard work and dedication over the past two weeks,” said Smith. “While the recent winter weather and associated power outages significantly impacted our operations, we now have the majority of our production back online and expect to restore the remaining portion by the end of this week.”
Fourth Quarter Operational Results
Centennial operated one drilling rig for a majority of the fourth quarter and added a second drilling rig and commenced completion activity in late December. The Company spud seven wells during the quarter, which was higher than anticipated due to drilling efficiencies.
“Our operations team continues to build upon the efficiencies gained last year. During the fourth quarter, we set a new Company drilling record, reaching spud-to-total depth on a two-mile lateral in just under eight days,” said Smith. “These reduced cycle times and structural cost reductions have driven a material reduction in well costs and are evidenced by our year-to-date 2021 completions, which consist of six wells with an average gross cost of approximately $790 per lateral foot.”
Additionally, Centennial has placed a heightened focus on reducing the volume of natural gas flared at its production locations. During the fourth quarter, Centennial’s flaring rate was 0.5% of total gross operated gas production. “Gas capture will continue to be an ongoing priority, and for 2021, we have set a flaring target of 1%,” said Smith.
Total capital expenditures incurred for the quarter were $29.9 million. Fourth quarter drilling and completion capital expenditures totaled $24.1 million and included higher activity than originally anticipated due to continued drilling efficiencies. The remaining $5.8 million was primarily spent on facilities and infrastructure. For the full year, total capital expenditures were $254.8 million, of which nearly 70% was incurred in the first quarter.
Acreage Position Update
In 2020, Centennial increased its acreage position by approximately 3,500 net acres primarily through cost-free acreage swaps and trades, further adding high-quality inventory to its portfolio. As of December 31, 2020, Centennial’s Delaware Basin position totaled 81,657 net acres, which is allocated between Texas (71%) and New Mexico (29%). During the year, the Company increased its New Mexico position by 27% to approximately 23,900 net acres. Notably, these additions were comprised almost entirely of state and fee acreage. As a result, the Company’s net acreage located on Federal lands is now approximately 4% of its overall Delaware Basin position, representing a slight reduction from the prior year.
Year-End 2020 Proved Reserves
Centennial reported year-end 2020 total proved reserves of 299 MMBoe compared to 301 MMBoe in the prior year. The modest decrease from the prior year was primarily attributable to lower SEC pricing, which was largely offset by the Company’s lower DC&F and operating costs that resulted in significant reserve additions during the year. At year-end 2020, proved reserves consisted of 50% oil, 30% natural gas and 20% natural gas liquids. Proved developed reserves were 149 MMBoe (50% of total proved reserves) as of December 31, 2020. For 2020, Centennial’s organic reserve replacement ratio was 91%. The Company’s 2020 proved developed finding and development cost totaled $11.48 per Boe. Centennial’s drill-bit finding and development cost was $13.53 per Boe for 2020. Centennial had a standardized measure of discounted future net cash flows of $1.2 billion at December 31, 2020. The present value at 10% (“PV 10%”, a non-GAAP financial measure reconciled within the Appendix) of Centennial’s total proved reserves was also $1.2 billion at year-end.
Netherland Sewell & Associates, Inc., an independent reserve engineering firm, prepared Centennial’s year-end reserves estimates as of December 31, 2020. (For additional information relating to our reserves, in addition to an explanation of how we calculate and use the organic reserve replacement ratio and finding and development costs, please see the Appendix of this press release.)
Capital Structure and Liquidity
During the quarter, the Company used a portion of its operating cash flow to pay down $25 million in borrowings under its credit facility. As of December 31, 2020, Centennial had approximately $6 million in cash on hand and $330 million of borrowings outstanding under its revolving credit facility. As a result, Centennial’s total liquidity position increased by approximately $25 million from the prior quarter to end the year at $340 million, which is based on its $700 million borrowing base, borrowings outstanding, the availability blocker of $32 million and $4 million in current letters of credit outstanding, plus cash on hand.
Hedge Position
For the full year 2021, Centennial has a total of 14,595 Bbls/d of oil hedged, consisting of approximately 85% fixed price swaps. For 2021, the Company currently has 9,734 Bbls/d and 2,870 Bbls/d of oil hedged at weighted average fixed prices of $43.70 per barrel WTI and $50.57 per barrel Brent, respectively. Also for 2021, the Company has 1,990 Bbls/d of WTI oil collars in place with a weighted average floor and ceiling price of $41.13 per barrel and $49.58 per barrel, respectively. Notably, a majority of the Company’s oil hedges is weighted towards the first half of 2021. Centennial’s oil production is currently unhedged in 2022 and beyond. In addition, Centennial has certain crude oil basis swaps in place for 2021 and certain natural gas hedges in place for 2021 and 2022. (For a summary table of Centennial’s derivative contracts as of February 19, 2021, please see the Appendix to this press release.)
Annual Report on Form 10-K
Centennial’s financial statements and related footnotes will be available in its Annual Report on Form 10-K for the year ended December 31, 2020, which is expected to be filed with the U.S. Securities and Exchange Commission (“SEC”) on February 24, 2021.
Conference Call and Webcast
Centennial will host an investor conference call on Wednesday, February 24, 2021 at 8:00 a.m. Mountain (10:00 a.m. Eastern) to discuss fourth quarter and full year 2020 operating and financial results. Interested parties may join the webcast by visiting Centennial’s website at www.cdevinc.com and clicking on the webcast link or by dialing (844) 348-0017, or (213) 358-0877 for international calls, (Conference ID: 9171897) at least 15 minutes prior to the start of the call. A replay of the call will be available on Centennial’s website or by phone at (855) 859-2056 (Conference ID: 9171897) for a seven day period following the call.
About Centennial Resource Development, Inc.
Centennial Resource Development, Inc. is an independent oil and natural gas company focused on the development of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. The Company’s assets and operations, which are held and conducted through Centennial Resource Production, LLC, are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. For additional information about the Company, please visit www.cdevinc.com.
Cautionary Note Regarding Forward-Looking Statements
The information in this press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this press release, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this press release, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “goal,” “plan,” “target” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.
Forward-looking statements may include statements about:
•volatility of oil, natural gas and NGL prices or a prolonged period of low oil, natural gas or NGL prices and the effects of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”), such as Saudi Arabia, and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil;
•the effects of excess supply of oil and natural gas resulting from reduced demand caused by the COVID-19 pandemic and the actions taken in response by certain oil and natural gas producing countries;
•our business strategy and future drilling plans;
•our reserves and our ability to replace the reserves we produce through drilling and property acquisitions;
•our drilling prospects, inventories, projects and programs;
•our financial strategy, liquidity and capital required for our development program;
•our realized oil, natural gas and NGL prices;
•the timing and amount of our future production of oil, natural gas and NGLs;
•our hedging strategy and results;
•our competition and government regulations;
•our ability to obtain permits and governmental approvals;
•our pending legal or environmental matters;
•the marketing and transportation of our oil, natural gas and NGLs;
•our leasehold or business acquisitions;
•cost of developing our properties;
•our anticipated rate of return;
•general economic conditions;
•weather conditions in the areas where we operate;
•credit markets;
•uncertainty regarding our future operating results;
•our plans, objectives, expectations and intentions contained in this press release that are not historical; and
•the other factors described in our most recent Annual Report on Form 10-K, and any updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.
We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described in our filings with the SEC.
Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any oil and gas reserve estimate depends on the quality of available data, the interpretation of such data, and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.
Should one or more of the risks or uncertainties described in this press release occur or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this press release are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this press release.
1) Free Cash Flow is a non-GAAP financial measure. See “Non-GAAP Financial Measures” included within the Appendix of this press release for related disclosures and a reconciliation to net cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP.
2) Net debt-to-LTM EBITDAX is a non-GAAP financial measure. The Company defines net debt (reconciled in the Appendix of this press release) as long-term debt, net, plus unamortized debt discount and debt issuance costs on senior notes minus cash and cash equivalents. The Company defines net debt-to-LTM EBITDAX as net debt (defined above) divided by Adjusted EBITDAX (defined and reconciled in the Appendix of this press release) for the prior twelve-month period. The Company presents this metric to show trends that investors may find useful in understanding the Company's ability to service its debt. This metric is widely used by professional research analysts, including credit analysts, in the valuation and comparison of companies in the oil and gas exploration and production industry. Centennial does not provide guidance on the items used to reconcile between forecasted net debt-to-LTM EBITDAX to forecasted long-term debt, net, or forecasted net income due to the uncertainty regarding timing and estimates of certain items; therefore, Centennial cannot reconcile forecasted net debt-to-LTM EBITDAX to forecasted long-term debt, net, or forecasted net income without unreasonable effort.
Contact:
Hays Mabry
Director, Investor Relations
(832) 240-3265
ir@cdevinc.com
SOURCE Centennial Resource Development, Inc.
Details of our 2021 operational and financial guidance are presented below:
| 2021 FY Guidance | |||||||||||
| Net average daily production (Boe/d) | 56,000 | — | 63,000 | ||||||||
| Net average daily oil production (Bbls/d) | 29,700 | — | 32,700 | ||||||||
| Production costs | |||||||||||
| Lease operating expenses ($/Boe) | $4.50 | — | $5.10 | ||||||||
| Gathering, processing and transportation expenses ($/Boe) | $3.00 | — | $3.40 | ||||||||
| Depreciation, depletion, and amortization ($/Boe) | $13.00 | — | $15.00 | ||||||||
Cash general and administrative ($/Boe)1 | $1.95 | — | $2.25 | ||||||||
Stock-based compensation ($/Boe)2 | $1.50 | — | $2.00 | ||||||||
| Severance and ad valorem taxes (% of revenue) | 6.0% | — | 8.0% | ||||||||
| Capital expenditure program ($MM) | $260 | — | $310 | ||||||||
| Drilling, completion and facilities | $250 | — | $290 | ||||||||
| Infrastructure, land and other | $10 | — | $20 | ||||||||
| Operated drilling program | |||||||||||
| Wells spud (gross) | 40 | — | 46 | ||||||||
| Wells completed (gross) | 40 | — | 48 | ||||||||
| Average working interest | ~85% | ||||||||||
| Average lateral length (feet) | ~8,800 | ||||||||||
(1) Cash general and administrative guidance does not include the portion of stock-based compensation that will settle in cash.
(2) Stock-based compensation guidance includes expense amounts for both equity awards and for cash-based liability awards. The amount of actual expense to be incurred for the liability awards included in this guidance range may vary from our forecast, as such expense can fluctuate materially in future periods with changes in Centennial’s stock price and, for certain awards, with changes in Centennial’s stock price performance versus a defined peer group of companies. A portion of these liability awards are expected to be paid in cash during fiscal year 2021.
Centennial Resource Development, Inc.
Operating Highlights
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||
| Net revenues (in thousands): | |||||||||||||||||||||||
| Oil sales | $ | 112,123 | $ | 220,600 | $ | 475,694 | $ | 810,655 | |||||||||||||||
| Natural gas sales | 17,724 | 12,901 | 46,776 | 44,556 | |||||||||||||||||||
| NGL sales | 18,230 | 22,891 | 57,986 | 89,119 | |||||||||||||||||||
| Oil and gas sales | $ | 148,077 | $ | 256,392 | $ | 580,456 | $ | 944,330 | |||||||||||||||
| Average sales price: | |||||||||||||||||||||||
| Oil (per Bbl) | $ | 40.36 | $ | 53.25 | $ | 36.02 | $ | 52.02 | |||||||||||||||
| Effect of derivative settlements on average price (per Bbl) | (1.54) | (1.09) | (3.15) | (1.13) | |||||||||||||||||||
| Oil net of hedging (per Bbl) | $ | 38.82 | $ | 52.16 | $ | 32.87 | $ | 50.89 | |||||||||||||||
| Average NYMEX price for oil (per Bbl) | $ | 42.66 | $ | 56.94 | $ | 39.44 | $ | 57.03 | |||||||||||||||
| Oil differential from NYMEX | (2.30) | (3.69) | (3.42) | (5.01) | |||||||||||||||||||
| Natural gas (per Mcf) | $ | 1.76 | $ | 1.14 | $ | 1.13 | $ | 1.07 | |||||||||||||||
| Effect of derivative settlements on average price (per Mcf) | (0.09) | 0.09 | (0.12) | 0.29 | |||||||||||||||||||
| Natural gas net of hedging (per Mcf) | $ | 1.67 | $ | 1.23 | $ | 1.01 | $ | 1.36 | |||||||||||||||
| Average NYMEX price for natural gas (per Mcf) | $ | 2.47 | $ | 2.34 | $ | 1.99 | $ | 2.52 | |||||||||||||||
| Natural gas differential from NYMEX | (0.71) | (1.20) | (0.86) | (1.45) | |||||||||||||||||||
| NGL (per Bbl) | $ | 17.65 | 17.47 | $ | 12.91 | $ | 17.03 | ||||||||||||||||
| Net production: | |||||||||||||||||||||||
| Oil (MBbls) | 2,778 | 4,142 | 13,207 | 15,582 | |||||||||||||||||||
| Natural gas (MMcf) | 10,093 | 11,294 | 41,302 | 41,703 | |||||||||||||||||||
| NGL (MBbls) | 1,032 | 1,311 | 4,490 | 5,234 | |||||||||||||||||||
Total (MBoe)(1) | 5,493 | 7,335 | 24,581 | 27,766 | |||||||||||||||||||
| Average daily net production: | |||||||||||||||||||||||
| Oil (Bbls/d) | 30,196 | 45,031 | 36,084 | 42,692 | |||||||||||||||||||
| Natural gas (Mcf/d) | 109,712 | 122,759 | 112,848 | 114,254 | |||||||||||||||||||
| NGL (Bbls/d) | 11,226 | 14,242 | 12,269 | 14,338 | |||||||||||||||||||
Total (Boe/d)(1) | 59,708 | 79,734 | 67,161 | 76,072 | |||||||||||||||||||
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
Centennial Resource Development, Inc.
Operating Expenses
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||
| Operating costs (in thousands): | |||||||||||||||||||||||
| Lease operating expenses | $ | 26,261 | $ | 38,899 | $ | 109,282 | $ | 145,976 | |||||||||||||||
| Severance and ad valorem taxes | 9,309 | 17,681 | 39,417 | 63,200 | |||||||||||||||||||
| Gathering, processing, and transportation expense | 17,956 | 20,714 | 71,309 | 72,834 | |||||||||||||||||||
| Operating costs per Boe: | |||||||||||||||||||||||
| Lease operating expenses | $ | 4.78 | $ | 5.30 | $ | 4.45 | $ | 5.26 | |||||||||||||||
| Severance and ad valorem taxes | 1.69 | 2.41 | 1.60 | 2.28 | |||||||||||||||||||
| Gathering, processing, and transportation expense | 3.27 | 2.82 | 2.90 | 2.62 | |||||||||||||||||||
Centennial Resource Development, Inc.
Consolidated Statements of Operations
(in thousands, except per share data)
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||
| Operating revenues | |||||||||||||||||||||||
| Oil and gas sales | $ | 148,077 | $ | 256,392 | $ | 580,456 | $ | 944,330 | |||||||||||||||
| Operating expenses | |||||||||||||||||||||||
| Lease operating expenses | 26,261 | 38,899 | 109,282 | 145,976 | |||||||||||||||||||
| Severance and ad valorem taxes | 9,309 | 17,681 | 39,417 | 63,200 | |||||||||||||||||||
| Gathering, processing and transportation expenses | 17,956 | 20,714 | 71,309 | 72,834 | |||||||||||||||||||
| Depreciation, depletion and amortization | 74,832 | 122,851 | 358,554 | 444,243 | |||||||||||||||||||
| Impairment and abandonment expense | 40,561 | 4,818 | 691,190 | 47,245 | |||||||||||||||||||
| Exploration and other expenses | 7,625 | 2,144 | 18,355 | 11,390 | |||||||||||||||||||
| General and administrative expenses | 18,421 | 22,567 | 72,867 | 79,156 | |||||||||||||||||||
| Total operating expenses | 194,965 | 229,674 | 1,360,974 | 864,044 | |||||||||||||||||||
| Net gain (loss) on sale of long-lived assets | 10 | (842) | 398 | (857) | |||||||||||||||||||
| Income (loss) from operations | (46,878) | 25,876 | (780,120) | 79,429 | |||||||||||||||||||
| Other income (expense) | |||||||||||||||||||||||
| Interest expense | (17,682) | (16,148) | (69,192) | (55,991) | |||||||||||||||||||
| Gain on exchange of debt | — | — | 143,443 | — | |||||||||||||||||||
| Net gain (loss) on derivative instruments | (24,205) | 660 | (64,535) | (1,561) | |||||||||||||||||||
| Other income (expense) | 110 | 13 | 81 | 334 | |||||||||||||||||||
| Total other income (expense) | (41,777) | (15,475) | 9,797 | (57,218) | |||||||||||||||||||
| Income (loss) before income taxes | (88,655) | 10,401 | (770,323) | 22,211 | |||||||||||||||||||
| Income tax (expense) benefit | — | (739) | 85,124 | (5,797) | |||||||||||||||||||
| Net income (loss) | (88,655) | 9,662 | (685,199) | 16,414 | |||||||||||||||||||
| Less: Net (income) loss attributable to noncontrolling interest | — | (44) | 2,362 | (616) | |||||||||||||||||||
| Net income (loss) attributable to Class A Common Stock | $ | (88,655) | $ | 9,618 | $ | (682,837) | $ | 15,798 | |||||||||||||||
| Income (loss) per share of Class A Common Stock: | |||||||||||||||||||||||
| Basic | $ | (0.32) | $ | 0.03 | $ | (2.46) | $ | 0.06 | |||||||||||||||
| Diluted | $ | (0.32) | $ | 0.03 | $ | (2.46) | $ | 0.06 | |||||||||||||||
Centennial Resource Development, Inc.
Consolidated Balance Sheets
(in thousands, except share and per share amounts)
| December 31, 2020 | December 31, 2019 | ||||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | 5,800 | $ | 10,223 | |||||||
| Accounts receivable, net | 54,557 | 101,912 | |||||||||
| Prepaid and other current assets | 5,229 | 7,994 | |||||||||
| Total current assets | 65,586 | 120,129 | |||||||||
| Property and Equipment | |||||||||||
| Oil and natural gas properties, successful efforts method | |||||||||||
| Unproved properties | 1,209,205 | 1,470,903 | |||||||||
| Proved properties | 4,395,473 | 3,962,175 | |||||||||
| Accumulated depreciation, depletion and amortization | (1,877,832) | (931,737) | |||||||||
| Total oil and natural gas properties, net | 3,726,846 | 4,501,341 | |||||||||
| Other property and equipment, net | 12,650 | 14,612 | |||||||||
| Total property and equipment, net | 3,739,496 | 4,515,953 | |||||||||
| Noncurrent assets | |||||||||||
| Operating lease right-of-use assets | 3,176 | 11,841 | |||||||||
| Other noncurrent assets | 19,167 | 40,365 | |||||||||
| TOTAL ASSETS | $ | 3,827,425 | $ | 4,688,288 | |||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities | |||||||||||
| Accounts payable and accrued expenses | $ | 110,439 | $ | 244,309 | |||||||
| Operating lease liabilities | 3,155 | 9,232 | |||||||||
| Other current liabilities | 18,274 | 925 | |||||||||
| Total current liabilities | 131,868 | 254,466 | |||||||||
| Noncurrent liabilities | |||||||||||
| Long-term debt, net | 1,068,624 | 1,057,389 | |||||||||
| Asset retirement obligations | 17,009 | 16,874 | |||||||||
| Deferred income taxes | 2,589 | 85,504 | |||||||||
| Operating lease liabilities | 422 | 3,354 | |||||||||
| Other noncurrent liabilities | 2,952 | — | |||||||||
| Total liabilities | 1,223,464 | 1,417,587 | |||||||||
| Shareholders’ equity | |||||||||||
| Preferred stock, $.0001 par value, 1,000,000 shares authorized: | |||||||||||
| Series A: No shares issued and outstanding at December 31, 2020 and 1 share issued and outstanding at December 31, 2019 | — | — | |||||||||
| Common stock, $0.0001 par value, 620,000,000 shares authorized: | |||||||||||
| Class A: 290,645,623 shares issued and 278,551,901 shares outstanding at December 31, 2020 and 280,650,341 shares issued and 275,811,346 shares outstanding at December 31, 2019 | 29 | 28 | |||||||||
| Class C (Convertible): No shares issued and outstanding at December 31, 2020 and 1,034,119 shares issued and outstanding at December 31, 2019 | — | — | |||||||||
| Additional paid-in capital | 3,004,433 | 2,975,756 | |||||||||
| Retained earnings (accumulated deficit) | (400,501) | 282,336 | |||||||||
| Total shareholders’ equity | 2,603,961 | 3,258,120 | |||||||||
| Noncontrolling interest | — | 12,581 | |||||||||
| Total equity | 2,603,961 | 3,270,701 | |||||||||
| TOTAL LIABILITIES AND EQUITY | $ | 3,827,425 | $ | 4,688,288 | |||||||
Centennial Resource Development, Inc.
Consolidated Statements of Cash Flows
(in thousands)
| Year Ended December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Cash flows from operating activities: | |||||||||||
| Net income (loss) | $ | (685,199) | $ | 16,414 | |||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
| Depreciation, depletion and amortization | 358,554 | 444,243 | |||||||||
| Stock-based compensation expense - equity awards | 20,966 | 28,997 | |||||||||
| Impairment and abandonment expense | 691,190 | 47,245 | |||||||||
| Exploratory dry hole costs | 6,615 | — | |||||||||
| Deferred tax expense (benefit) | (85,124) | 5,797 | |||||||||
| Net (gain) loss on sale of long-lived assets | (398) | 857 | |||||||||
| Non-cash portion of derivative (gain) loss | 17,884 | (4,094) | |||||||||
| Amortization of debt issuance costs and discount | 5,923 | 2,861 | |||||||||
| Gain on exchange of debt | (143,443) | — | |||||||||
| Changes in operating assets and liabilities: | |||||||||||
| (Increase) decrease in accounts receivable | 44,572 | (10,098) | |||||||||
| (Increase) decrease in prepaid and other assets | (3,804) | (1,882) | |||||||||
| Increase (decrease) in accounts payable and other liabilities | (56,360) | 33,833 | |||||||||
| Net cash provided by operating activities | 171,376 | 564,173 | |||||||||
| Cash flows from investing activities: | |||||||||||
| Acquisition of oil and natural gas properties | (8,464) | (103,709) | |||||||||
| Drilling and development capital expenditures | (318,465) | (855,153) | |||||||||
| Purchases of other property and equipment | (1,083) | (8,857) | |||||||||
| Proceeds from sales of oil and natural gas properties | 1,689 | 34,730 | |||||||||
| Net cash used in investing activities | (326,323) | (932,989) | |||||||||
| Cash flows from financing activities: | |||||||||||
| Proceeds from borrowings under revolving credit facility | 570,000 | 595,000 | |||||||||
| Repayment of borrowings under revolving credit facility | (415,000) | (720,000) | |||||||||
| Proceeds from issuance of senior notes | — | 496,175 | |||||||||
| Debt exchange and debt issuance costs | (6,650) | (7,200) | |||||||||
| Restricted stock used for tax withholdings | (607) | (1,038) | |||||||||
| Net cash provided by financing activities | 147,743 | 362,937 | |||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | (7,204) | (5,879) | |||||||||
| Cash, cash equivalents and restricted cash, beginning of period | 15,543 | 21,422 | |||||||||
| Cash, cash equivalents and restricted cash, end of period | $ | 8,339 | $ | 15,543 | |||||||
Reconciliation of cash, cash equivalents and restricted cash presented on the consolidated statements of cash flows for the periods presented:
| Year Ended December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Cash and cash equivalents | $ | 5,800 | $ | 10,223 | |||||||
| Restricted cash | $ | 2,539 | $ | 5,320 | |||||||
| Total cash, cash equivalents and restricted cash | $ | 8,339 | $ | 15,543 | |||||||
Non-GAAP Financial Measures
In addition to disclosing financial results calculated in accordance with U.S. generally accepted accounting principles (“GAAP”), our earnings release contains non-GAAP financial measures as described below.
Adjusted EBITDAX
Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income before interest expense, income taxes, depreciation, depletion and amortization, exploration and other expenses, impairment and abandonment expenses, non-cash gains or losses on derivatives, stock-based compensation, gain on exchange of debt, gains and losses from the sale of assets, transaction costs and nonrecurring workforce reduction severance payments. Adjusted EBITDAX is not a measure of net income as determined by GAAP.
Our management believes Adjusted EBITDAX is useful as it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers, without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or nonrecurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table presents a reconciliation of Adjusted EBITDAX to net income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP:
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| (in thousands) | 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||
| Adjusted EBITDAX reconciliation to net income: | |||||||||||||||||||||||
| Net income (loss) attributable to Class A Common Stock | $ | (88,655) | $ | 9,618 | $ | (682,837) | $ | 15,798 | |||||||||||||||
| Net income (loss) attributable to noncontrolling interest | — | 44 | (2,362) | 616 | |||||||||||||||||||
| Interest expense | 17,682 | 16,148 | 69,192 | 55,991 | |||||||||||||||||||
| Income tax expense (benefit) | — | 739 | (85,124) | 5,797 | |||||||||||||||||||
| Depreciation, depletion and amortization | 74,832 | 122,851 | 358,554 | 444,243 | |||||||||||||||||||
| Impairment and abandonment expense | 40,561 | 4,818 | 691,190 | 47,245 | |||||||||||||||||||
| Gain on exchange of debt | — | — | (143,443) | — | |||||||||||||||||||
| Non-cash derivative (gain) loss | 18,987 | (4,108) | 17,884 | (4,094) | |||||||||||||||||||
Stock-based compensation expense(1) | 8,111 | 6,998 | 23,045 | 26,315 | |||||||||||||||||||
| Exploration and other expenses | 7,625 | 2,144 | 18,355 | 11,390 | |||||||||||||||||||
| Workforce reduction severance payments | — | — | 3,466 | — | |||||||||||||||||||
| Transaction costs | — | — | 476 | — | |||||||||||||||||||
| (Gain) loss on sale of long-lived assets | (10) | 842 | (398) | 857 | |||||||||||||||||||
| Adjusted EBITDAX | $ | 79,133 | $ | 160,094 | $ | 267,998 | $ | 604,158 | |||||||||||||||
(1) Includes stock-based compensation for equity awards and also for cash-based liability awards that have not yet been settled in cash, both of which relate to general and administrative employees only. Stock-based compensation amounts for geographical and geophysical personnel are included within the Exploration and other expenses line item.
Free Cash Flow (Deficit)
Free cash flow (deficit) is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define free cash flow (deficit) as net cash provided by operating activities before changes in working capital, less incurred capital expenditures.
Our management believes free cash flow (deficit) is a useful indicator of the Company’s ability to internally fund its exploration and development activities and to service or incur additional debt, without regard to the timing of settlement of either operating assets and liabilities or accounts payable related to capital expenditures. The Company believes that this measure, as so adjusted, presents a meaningful indicator of the Company’s actual sources and uses of capital associated with its operations conducted during the applicable period. Our computations of free cash flow (deficit) may not be comparable to other similarly titled measures of other companies. Free cash flow (deficit) should not be considered as an alternative to, or more meaningful than, cash provided by operating activities as determined in accordance with GAAP or as indicator of our operating performance or liquidity.
Free cash flow (deficit) is not a financial measure that is determined in accordance with GAAP. Accordingly, the following table presents a reconciliation of free cash flow (deficit) to net cash provided by operating activities, which is the most directly comparable financial measure calculated and presented in accordance with GAAP:
| Three Months Ended December 31, | |||||||||||
| (in thousands) | 2020 | 2019 | |||||||||
| Net cash provided by operating activities | $ | 41,144 | $ | 179,298 | |||||||
| Changes in working capital: | |||||||||||
| Accounts receivable | 3,567 | (37,673) | |||||||||
| Prepaid and other assets | 979 | 887 | |||||||||
| Accounts payable and other liabilities | 13,253 | 729 | |||||||||
| Discretionary cash flow | 58,943 | 143,241 | |||||||||
| Less: total capital expenditures incurred | (29,900) | (197,100) | |||||||||
| Free cash flow (deficit) | $ | 29,043 | $ | (53,859) | |||||||
Net Debt / Book Capitalization Ratio
Net debt / book capitalization ratio is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define net debt / book capitalization ratio as net debt divided by book capitalization (non-GAAP). Net debt is defined as long-term debt, net, plus unamortized debt discount and debt issuance costs on senior notes minus cash and cash equivalents. Book capitalization (non-GAAP) is defined as long-term debt, net, plus unamortized debt discount and issuance costs on senior notes, plus total equity. Net debt / book capitalization ratio is not a measure calculated in accordance with GAAP.
Our management believes net debt / book capitalization ratio is useful as it allows them to more effectively evaluate our capital structure and liquidity and compare the results against our peers. Net debt / book capitalization ratio should not be considered as an alternative to, or more meaningful than, debt / book capitalization (GAAP) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Our computations of net debt / book capital ratio may not be comparable to other similarly titled measures of other companies.
The following table presents a reconciliation of our net debt / book capitalization ratio to our most directly comparable financial measure calculated and presented in accordance with GAAP:
| (in thousands) | December 31, 2020 | December 31, 2019 | ||||||||||||
| Total equity | $ | 2,603,961 | $ | 3,270,701 | ||||||||||
| Long-term debt, net | 1,068,624 | 1,057,389 | ||||||||||||
| Unamortized debt discount and debt issuance costs on senior notes | 34,248 | 17,611 | ||||||||||||
| Long-term debt | 1,102,872 | 1,075,000 | ||||||||||||
| Less: cash and cash equivalents | (5,800) | (10,223) | ||||||||||||
| Net debt (Non-GAAP) | 1,097,072 | 1,064,777 | ||||||||||||
Book capitalization (GAAP)(1) | $ | 3,672,585 | $ | 4,328,090 | ||||||||||
Book capitalization (non-GAAP)(2) | $ | 3,706,833 | $ | 4,345,701 | ||||||||||
Debt / book capitalization (GAAP)(3) | 29 | % | 24 | % | ||||||||||
Net debt / book capitalization (non-GAAP)(4) | 30 | % | 25 | % | ||||||||||
(1) Book capitalization (GAAP) is calculated as total equity plus long-term debt, net.
(2) Book capitalization (non-GAAP) is calculated as total equity plus long-term debt.
(3) Debt / book capitalization (GAAP) is calculated as long-term debt, net divided by book capitalization (GAAP).
(4) Net debt / book capitalization (non-GAAP) is calculated as net debt (non-GAAP) divided by book capitalization (non-GAAP).
The following table summarizes the approximate volumes and average contract prices of the hedge contracts the Company had in place as of December 31, 2020 and additional contracts entered into through February 19, 2021:
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Crude Price ($/Bbl)(1) | ||||||||||||||||||||
| Crude oil swaps | |||||||||||||||||||||||
| NYMEX WTI | January 2021 - March 2021 | 990,000 | 11,000 | $41.48 | |||||||||||||||||||
| April 2021 - June 2021 | 1,183,000 | 13,000 | 43.18 | ||||||||||||||||||||
| July 2021 - September 2021 | 736,000 | 8,000 | 45.87 | ||||||||||||||||||||
| October 2021 - December 2021 | 644,000 | 7,000 | 45.59 | ||||||||||||||||||||
| ICE Brent | January 2021 - March 2021 | 270,000 | 3,000 | $46.85 | |||||||||||||||||||
| April 2021 - June 2021 | 409,500 | 4,500 | 54.98 | ||||||||||||||||||||
| July 2021 - September 2021 | 184,000 | 2,000 | 48.25 | ||||||||||||||||||||
| October 2021 - December 2021 | 184,000 | 2,000 | 48.50 | ||||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Collar Price Ranges ($/Bbl)(2) | ||||||||||||||||||||
| Crude oil collars | January 2021 - March 2021 | 315,000 | 3,500 | $40.00 - $48.14 | |||||||||||||||||||
| April 2021 - June 2021 | 227,500 | 2,500 | 42.00 - 51.14 | ||||||||||||||||||||
| July 2021 - September 2021 | 92,000 | 1,000 | 42.00 - 50.10 | ||||||||||||||||||||
| October 2021 - December 2021 | 92,000 | 1,000 | 42.00 - 50.10 | ||||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Differential ($/Bbl)(3) | ||||||||||||||||||||
| Crude oil basis differential swaps | January 2021 - March 2021 | 990,000 | 11,000 | $0.01 | |||||||||||||||||||
| April 2021 - June 2021 | 1,183,000 | 13,000 | 0.11 | ||||||||||||||||||||
| July 2021 - September 2021 | 736,000 | 8,000 | 0.26 | ||||||||||||||||||||
| October 2021 - December 2021 | 644,000 | 7,000 | 0.26 | ||||||||||||||||||||
(1) These crude oil swap transactions are settled based on the NYMEX WTI or ICE Brent oil price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2) These crude oil collars are settled based on the NYMEX WTI price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3) These oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable monthly settlement period.
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd Avg. Gas Price ($/MMBtu)(1) | ||||||||||||||||||||
| Natural gas swaps | January 2021 - March 2021 | 5,400,000 | 60,000 | $2.91 | |||||||||||||||||||
| April 2021 - June 2021 | 3,640,000 | 40,000 | 2.89 | ||||||||||||||||||||
| July 2021 - September 2021 | 3,680,000 | 40,000 | 2.89 | ||||||||||||||||||||
| October 2021 - December 2021 | 3,680,000 | 40,000 | 2.95 | ||||||||||||||||||||
| January 2022 - March 2022 | 1,800,000 | 20,000 | 3.00 | ||||||||||||||||||||
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Collar Price Ranges ($/MMBtu)(2) | ||||||||||||||||||||
| Natural gas collars | January 2021 - March 2021 | 1,800,000 | 20,000 | $2.90 - $3.64 | |||||||||||||||||||
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Differential ($/MMBtu)(3) | ||||||||||||||||||||
| Natural gas basis differential swaps | January 2021 - March 2021 | 1,800,000 | 20,000 | $(0.30) | |||||||||||||||||||
| April 2021 - June 2021 | 3,640,000 | 40,000 | (0.30) | ||||||||||||||||||||
| July 2021 - September 2021 | 3,680,000 | 40,000 | (0.30) | ||||||||||||||||||||
| October 2021 - December 2021 | 3,680,000 | 40,000 | (0.28) | ||||||||||||||||||||
| January 2022 - March 2022 | 1,800,000 | 20,000 | (0.26) | ||||||||||||||||||||
(1) These natural gas swap contracts are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2) These natural gas collars are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3) These natural gas basis swap contracts are settled based on the difference between the Inside FERC’s West Texas WAHA price and the NYMEX price of natural gas, during each applicable monthly settlement period.
The following table summarizes estimated proved reserves, pre-tax PV 10%, and standardized measure of discounted future cash flows as of the periods indicated:
| December 31, 2020 | December 31, 2019 | December 31, 2018 | |||||||||||||||
| Proved developed reserves: | |||||||||||||||||
| Oil (MBbls) | 70,716 | 74,842 | 63,317 | ||||||||||||||
| Natural gas (MMcf) | 279,556 | 237,791 | 180,542 | ||||||||||||||
| NGL (MBbls) | 31,672 | 32,743 | 23,093 | ||||||||||||||
Total proved developed reserves (MBoe)(1) | 148,981 | 147,216 | 116,500 | ||||||||||||||
| Proved undeveloped reserves: | |||||||||||||||||
| Oil (MBbls) | 79,776 | 75,317 | 79,449 | ||||||||||||||
| Natural gas (MMcf) | 248,231 | 264,639 | 222,310 | ||||||||||||||
| NGL (MBbls) | 28,773 | 34,499 | 28,825 | ||||||||||||||
Total proved undeveloped reserves (MBoe)(1) | 149,921 | 153,923 | 145,326 | ||||||||||||||
| Total proved reserves: | |||||||||||||||||
| Oil (MBbls) | 150,492 | 150,159 | 142,766 | ||||||||||||||
| Natural gas (MMcf) | 527,787 | 502,430 | 402,852 | ||||||||||||||
| NGL (MBbls) | 60,445 | 67,242 | 51,918 | ||||||||||||||
Total proved reserves (MBoe)(1) | 298,902 | 301,139 | 261,826 | ||||||||||||||
| Proved developed reserves % | 50 | % | 49 | % | 44 | % | |||||||||||
| Proved undeveloped reserves % | 50 | % | 51 | % | 56 | % | |||||||||||
| Reserve values (in millions): | |||||||||||||||||
| Standard measure of discounted future net cash flows | $ | 1,184.7 | $ | 2,062.4 | $ | 2,479.9 | |||||||||||
| Discounted future income tax expense | 4.4 | 135.5 | 499.6 | ||||||||||||||
Total proved pre-tax PV 10%(2) | $ | 1,189.1 | $ | 2,197.9 | $ | 2,979.5 | |||||||||||
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
(2) Total proved pre-tax PV 10% (“Pre-tax PV 10%”) is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, and it is derived from the standardized measure of discounted future net cash flows (the ‘‘Standardized Measure’’), which is the most directly comparable GAAP financial measure. Pre-tax PV 10% is computed on the same basis as the Standardized Measure but without deducting future income taxes. We believe Pre-tax PV 10% is a useful measure for investors when evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our Pre-tax PV 10% as a basis for comparison of the relative size and value of our proved reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our oil and gas properties and acquisitions. However, Pre-tax PV 10% is not a substitute for the Standardized Measure. Our Pre-tax PV 10% and Standardized Measure do not purport to present the fair value of our proved oil, NGL and natural gas reserves.
Supplemental Measures
Organic Reserve Replacement Ratio
The Company uses the organic reserve replacement ratio as an indicator of the Company’s ability to replace the reserves that it has developed and to increase its reserves over time. The ratio is not a representation of value creation and has a number of limitations that should be considered. For example, the ratio does not incorporate the costs or timing of developing future reserves. The organic reserve replacement ratio of 91% is calculated as (a) our total 2020 proved reserve extensions and discoveries and revisions to previous estimates of 22.3 MMBoe divided by (b) the Company’s total 2020 production of 24.6 MMBoe. The ratio calculation excludes acquisitions and divestitures.
Proved Developed and Drill-Bit Finding and Development (“F&D”) Costs
The Company uses proved developed F&D cost and drill-bit F&D cost as indicators of capital efficiency, in that they measure the Company’s costs to add proved reserves on a per Boe basis. Both calculations exclude acquisitions and divestitures and are subject to limitations, including the uncertainty of future costs to develop the Company’s reserves.
Proved developed F&D of $11.48 per Boe is calculated as our total 2020 exploration and developments costs incurred of $302.4 million divided by the sum of (i) total proved developed reserve extensions and discoveries, (ii) transfers from proved undeveloped reserves at year-end 2019, and (iii) proved developed reserve revisions to previous estimates, which altogether totaled 26.3 MMBoe.
Drill-bit F&D of $13.53 per Boe is calculated as (a) our total 2020 exploration and developments costs incurred of $302.4 million divided by (b) the Company’s total 2020 proved reserve extensions and discoveries and revisions to previous estimates of 22.3 MMBoe.