DENVER, Feb. 26, 2018 (GLOBE NEWSWIRE) -- Centennial Resource Development, Inc. (“Centennial” or the “Company”) (NASDAQ:CDEV) today announced financial and operational results for the full year 2017 and 2018 operational plans and targets.
Recent Financial and Operational Highlights:
- Increased fourth quarter daily crude oil production 30% quarter-over-quarter
- Grew 2017 daily oil and equivalent production volumes 233% and 278% year-over-year, respectively
- Delivered strong well results from the Northern and Southern Delaware Basins
- Successfully completed wells in the 3rd Bone Spring Sand and Carbonate in Reeves County, Texas
- Increased 2017 total proved reserves 125% at attractive finding and development costs with organic reserves replacement ratio over 950%
- Acquired approximately 4,000 net acres in Lea County, New Mexico adjacent to Company’s existing position
- Announced pending sale of approximately 8,600 mostly non-operated net acres in Reeves County, Texas
Financial and Operational Plan:
- Expect to grow 2018 crude oil production approximately 85% year-over-year
- Expect to increase 2018 total company production approximately 86% year-over-year
- Plan to maintain seven rig drilling program throughout 2018
- Announced full year 2018 total capital budget of $885 million to $1,050 million
- Increased 2020 oil production growth target from 60,000 to 65,000 barrels per day (“Bbls/d”)
Financial Results
Centennial reported 2017 net income of $75.6 million, or $0.32 per diluted share. For the fourth quarter, net income increased 111% to $30.5 million, or $0.12 per diluted share, compared to $14.4 million, or $0.06 per diluted share, in the third quarter 2017.
Crude oil production increased 30% to 27,402 Bbls/d compared to the third quarter 2017. For the full year 2017, average daily oil and total equivalent production volumes increased to 19,161 Bbls/d and 31,864 barrels of oil equivalent per day (“Boe/d”), or 233% and 278% compared to 2016, respectively.
“In our first full year of operation, Centennial delivered on the 2017 goals we articulated last March. After raising production targets three times during the year, the Company delivered oil production that ultimately exceeded the high-end of our 2017 guidance range. Within a short period of time, we assembled one of the highest quality technical teams in the industry,” said Mark G. Papa, Chairman and Chief Executive Officer. “Based on the Company’s strong operational outperformance in 2017 and the continued confidence in our technical capability, we are increasing our 2020 oil production target to 65,000 barrels per day, which is likely one of the highest four-year oil growth rates in the E&P industry.”
Operational Update
In Reeves County, Texas, Centennial posted a number of strong well results from multiple zones in the Southern Delaware Basin. Targeting the 3rd Bone Spring Sand, the Weaver C T34H (86% WI) was Centennial’s first well in the horizon using modern completion techniques. The well was drilled with an approximate 9,350 foot lateral and tested at an IP-10 rate of 2,072 Boe/d (75% oil).
“We are excited about the initial results of the Weaver. Based on early flowback, it appears comparable to a strong Upper Wolfcamp A well,” Papa said. “It's encouraging to see positive industry results from the same zone offsetting our acreage. We expect to drill additional wells in the 3rd Bone Spring Sand during the year and test the viability of co-developing this zone with the Wolfcamp.”
Additionally, Centennial drilled the Big House C 3H (100% WI), one of the industry's first 3rd Bone Spring Carbonate tests in Reeves County. The well was drilled with a short 4,150 foot lateral and produced 806 Boe/d (60% oil) for the initial 30-day production period. The well proved an important test for the Company, and plans are to drill a two-mile lateral later in the year to further test the economics of the zone. Centennial is in the early stages of testing several Bone Spring intervals on its Reeves County acreage and will continue to evaluate these zones throughout the year.
Centennial's ongoing Wolfcamp development program in Reeves County drove its strong fourth quarter oil production growth profile. The Blackstone West 1H and 2H were drilled in the Upper Wolfcamp A interval with 880-foot spacing and approximate 4,115 foot laterals. The Blackstone West 1H (100% WI) produced 1,745 Boe/d (81% oil) for the initial 30-day production period. The Blackstone West 2H (100% WI) reported an initial 30-day production rate of 1,316 Boe/d (82% oil). On a per lateral foot basis, the Blackstone West 1H and 2H delivered initial 30-day oil production rates of 342 and 263 Bbls/d per 1,000 foot of lateral, respectively.
Targeting the Upper Wolfcamp A, the Big House A 4 57-60 1H and 2H were drilled using 660-foot spacing, or eight wells per section, with average 7,040 foot effective laterals on the Company’s Silverback acreage. The Big House A 4 57-60 1H (100% WI) achieved an initial 30-day production rate of 2,705 Boe/d (52% oil). The Big House A 4 57-60 2H (100% WI) achieved an initial 30-day production rate of 2,731 Boe/d (53% oil). During its initial 60-day production period, the two well-pad produced approximately 137,300 barrels of oil.
“The Big House A 4 57-60 was a positive 660-foot test. To date, our development program and drilling inventory has been based on 880-foot spacing. With continued successful down-spacing tests, there is the potential to meaningfully increase our drilling inventory in this area. We plan additional spacing and delineation tests throughout the year,” Papa said. “We drilled these wells with extended laterals reflecting our shift to more efficient, higher return drilling operations. During the fourth quarter, we completed more extended lateral wells than in the first three quarters of the year combined.”
The Company drilled the Sundown 1H (82% WI) on the southern portion of its Reeves County acreage position with an approximate 4,150 foot effective lateral targeting the Lower Wolfcamp A interval. The well achieved an initial 30-day production rate of 1,263 Boe/d (88% oil), with 268 Bbls/d of oil per 1,000 foot of lateral.
In the Northern Delaware Basin, Centennial reported strong results from its first wells completed in different intervals in Lea County, New Mexico. The Pirate State 101H (100% WI), Centennial’s first operated well, was completed in the Avalon Shale with an approximate 4,190 foot effective lateral and delivered an initial 30-day production rate of 1,112 Boe/d (79% oil). The Tour Bus 23 State 503H and 504H (both 100% WI) were completed in the 2nd Bone Spring with an average effective lateral length of 4,040 feet. The wells averaged 1,016 Boe/d (83% oil) for the initial 30-day production period.
“We continue to see higher well productivity from our enhanced completion techniques. Centennial’s current completion design represents a 30% increase in pounds of proppant per foot and an 80% increase in clusters per stage, compared to 2016,” Papa said. “We expect to combine these new completion techniques with longer laterals to improve the overall drilling returns of our capital program in 2018.”
Centennial reported total 2017 drilling and completion ("D&C") capital expenditures incurred of approximately $624 million. D&C capital expenditures incurred for the fourth quarter were approximately $226 million, compared to $163 million in the third quarter 2017.
2018 Operational Plans and Targets
The Company is targeting total company production growth of 86% during 2018. Centennial added a seventh drilling rig in February and plans to continue operating a seven rig program throughout the year. With a focus on capital returns, Centennial expects the majority of its wells drilled during the year to be extended laterals on multi-well pads.
During 2018, Centennial expects to operate six of its seven rigs in Reeves County, where it will spend approximately 85% of the total operated D&C capital budget. Centennial will focus its Reeves County activity in the Upper Wolfcamp A zone following successful results from its 2017 capital program, with plans to develop additional zones throughout the year. The remaining operated rig and associated D&C capital will be allocated to a newly expanded Lea County position. (For a detailed table summarizing Centennial’s 2018 operational and financial guidance, please see the Appendix of this press release.)
“In 2018, we expect to grow our annual oil production by approximately 85% while maintaining a low and differentiated leverage profile,” Papa said. “We remain focused on generating corporate returns for our shareholders and estimate our 2018 total capital program could generate GAAP return on equity and return on capital employed of approximately seven to ten percent, assuming $60 oil.”
Estimated fiscal year 2018 total capital budget is approximately $885 million to $1,050 million, including D&C capital, facilities, infrastructure, seismic, land and other expenditures. Centennial’s production profile is predicated on a D&C budget of $710 million to $820 million, of which approximately 90% is associated with operated activity. To support future production growth, in 2018 Centennial has allocated approximately $125 million to $160 million to facilities, infrastructure and other, which includes production facilities, saltwater disposal wells, water pipeline infrastructure and seismic, among other capitalized items.
Acreage Position Update
On February 8, 2018, Centennial acquired approximately 4,000 net acres in Lea County, New Mexico from OneEnergy Partners, LLC for a total purchase price of $95 million. The operated acreage position contains an average 95% working interest and is largely contiguous to Centennial’s existing position. Centennial has identified approximately 100 gross horizontal locations on the acreage, which are additive to its existing inventory in Lea County.
Centennial also entered into a definitive agreement with an undisclosed third-party for the sale of approximately 8,600 net acres in Reeves County for a purchase price of $141 million. The divested acreage represents a largely non-operated position (average 32% WI) on the western portion of Centennial’s position in Reeves County. 2017 average net production on the divested acreage was less than 250 Boe/d, or less than 1% of total company production. The transaction is expected to close on March 1, 2018, subject to customary closing terms and conditions.
“These transactions are consistent with our strategy to own and operate high-quality acreage in the Delaware Basin. The acquisition increases our Northern Delaware position by approximately thirty percent to over 16,000 net acres and adds operated locations to our inventory in Lea County,” Papa said. “The net of these two transactions will upgrade our overall portfolio. We basically sold acreage with low working interest in Reeves County for higher quality, operated acreage in Lea County.”
(For a map summarizing Centennial’s recent acquisition and divestiture, please see the presentation materials on Centennial’s website under the Investor Relations tab.)
Year-End 2017 Proved Reserves
Centennial reported a 125% increase in year-end 2017 total proved reserves to 186,454 MBoe, consisting of 54% oil, 29% natural gas and 17% natural gas liquids. Proved developed reserves increased by 197% to 74,929 MBoe (40% of total proved reserves) as of December 31, 2017, reflecting the continued successful development of the Company's horizontal well inventory. During 2017, Centennial’s organic reserves replacement ratio was 954%. The Company's 2017 proved developed finding and development cost totaled $10.62 per Boe. Centennial's drill-bit finding and development cost was $5.47 per Boe for 2017. Using SEC prices and discounting the present value at 10% (“PV-10”), the value of Centennial’s total proved reserves at December 31, 2017 increased 309% to $1,748 million, and Centennial had a standardized measure of discounted future net cash flows of $1,503 million. Netherland Sewell & Associates, Inc., an independent reserve engineering firm, prepared Centennial’s year-end reserves estimates as of December 31, 2017. (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
As of December 31, 2017, Centennial had approximately $117 million in cash on hand and $400 million outstanding of long-term debt. During the fourth quarter 2017, Centennial bolstered its liquidity position and extended debt maturities by issuing $400 million of 5.375% senior notes due in 2026, resulting in net proceeds of approximately $391 million which were used to fully repay borrowings under the Company’s credit facility and pre-fund capital expenditures. As of December 31, 2017, total liquidity was approximately $591 million, which included $474 million of availability under the revolving credit facility.
Hedge Position
As of February 26, 2018, Centennial had no crude oil or natural gas hedges in-place. (For a summary table of crude oil and natural gas basis swap contracts as of December 31, 2017, please see the Appendix of this press release.)
“Despite the recent increase in U.S. oil production, we remain bullish on the macro crude oil environment given current supply and demand fundamentals, showing strong global demand and declining global inventories. As a result, our future oil production will remain unhedged until we see a change in these market fundamentals,” Papa said.
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, 2017, which is expected be filed with the U.S. Securities and Exchange Commission (“SEC”) on February 26, 2018.
Conference Call and Webcast
Centennial will host an investor conference call on Tuesday, February 27, 2018 at 8:00 a.m. Mountain (10:00 a.m. Eastern) to discuss fourth quarter and full year 2017 operating and financial results and 2018 outlook. Interested parties may join the webcast by visiting Centennial’s website at www.cdevinc.com and clicking on the webcast link or by dialing (800) 789-3525, or (442) 268-1041 for international calls, (Conference ID: 9488549) 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: 9488549) for a 14-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,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” 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:
- our business strategy;
- our reserves;
- our drilling prospects, inventories, projects and programs;
- our ability to replace the reserves we produce through drilling and property acquisitions;
- 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 future drilling plans;
- our competition and government regulations;
- our ability to obtain permits and governmental approvals;
- our pending legal or environmental matters;
- our marketing of oil, natural gas and NGLs;
- our leasehold or business acquisitions;
- our costs of developing our properties;
- general economic conditions;
- 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 Annual Report on Form 10-K for the year ended December 31, 2017, 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 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 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.
Contact:
Hays Mabry
Director, Investor Relations
(832) 240-3265
ir@cdevinc.com
Details of our 2018 operational and financial guidance are presented below:
| 2018 FY Guidance | |||
| Net average daily production (Boe/d) | 55,000 | — | 63,500 |
| Oil net average daily production (Bbls/d) | 33,500 | — | 37,500 |
| Production costs | |||
| Lease operating expenses ($/Boe) | $3.60 | — | $4.20 |
| Gathering, processing and transportation expenses ($/Boe) | $3.20 | — | $3.80 |
| Depreciation, depletion, and amortization ($/Boe) | $14.00 | — | $16.00 |
| Cash general and administrative ($/Boe) | $2.20 | — | $2.70 |
| Non-cash stock-based compensation ($/Boe) | $0.90 | — | $1.20 |
| Severance and ad valorem taxes (% of revenue) | 6.0% | — | 8.0% |
| Capital expenditure program ($MM) | $885 | — | $1,050 |
| Drilling and completion capital expenditure | $710 | — | $820 |
| Facilities, infrastructure and other | $125 | — | $160 |
| Land | $50 | — | $70 |
| Operated drilling program | |||
| Wells spud (gross) | 80 | — | 95 |
| Wells completed (gross) | 75 | — | 85 |
| Average working interest | 85% | — | 90% |
| Average lateral length (Feet) | 7,250 | — | 7,750 |
Non-GAAP Financial Measure
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 (loss) before interest expense, income taxes, depreciation, depletion and amortization, exploration costs, impairment and abandonment expenses, non-cash gains or losses on derivatives, non-cash stock-based compensation, gains and losses from the sale of assets, transaction costs and write-off of deferred offering costs. 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 non-recurring 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, our most directly comparable financial measure calculated and presented in accordance with GAAP:
| Successor | Predecessor | |||||||||||||||
| (in thousands) | Three Months Ended December 31, 2017 | Year Ended December 31, 2017 | October 11, 2016, through December 31, 2016 | January 1, 2016, through October 10, 2016 | ||||||||||||
| Adjusted EBITDAX reconciliation to net income: | ||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 30,536 | $ | 75,568 | $ | (8,081 | ) | $ | (218,724 | ) | ||||||
| Net income (loss) attributable to noncontrolling interest | 2,854 | 7,987 | (904 | ) | — | |||||||||||
| Interest expense | 3,597 | 5,729 | 378 | 5,626 | ||||||||||||
| Income tax expense (benefit) | 12,628 | 29,930 | — | (406 | ) | |||||||||||
| Depreciation, depletion and amortization | 58,781 | 161,628 | 14,877 | 62,964 | ||||||||||||
| Impairment and abandonment expenses | — | (29 | ) | — | 2,545 | |||||||||||
| Non-cash portion of derivative (gain) loss | (679 | ) | (5,805 | ) | 2,602 | 23,461 | ||||||||||
| Stock-based compensation expense | 3,862 | 12,150 | 1,333 | — | ||||||||||||
| Exploration expense | 10,281 | 14,373 | 1,468 | 920 | ||||||||||||
| Transaction costs | 68 | 1,454 | 4,097 | 15,792 | ||||||||||||
| Write-off of deferred offering costs | — | — | — | 1,181 | ||||||||||||
| Incentive unit compensation | — | — | — | 165,394 | ||||||||||||
| (Gain) loss on sale of oil and natural gas properties | (1,580 | ) | (8,796 | ) | (24 | ) | (11 | ) | ||||||||
| Adjusted EBITDAX | $ | 120,348 | $ | 294,189 | $ | 15,746 | $ | 58,742 | ||||||||
| Centennial Resource Development, Inc. Operating Highlights | ||||||||||||||||||||||||
| Successor | Combined | Successor | Predecessor | Combined | ||||||||||||||||||||
| Three Months Ended December 31, 2017 | Three Months Ended December 31, 2016 (1) | Year Ended December 31, 2017 | October 11, 2016 through December 31, 2016 | January 1, 2016 through October 10, 2016 | Year Ended December 31, 2016 | |||||||||||||||||||
| Net revenues (in thousands): | ||||||||||||||||||||||||
| Oil sales | $ | 132,229 | $ | 27,125 | $ | 336,931 | $ | 24,313 | $ | 59,787 | $ | 84,100 | ||||||||||||
| Natural gas sales | 15,642 | 3,777 | 48,868 | 3,449 | 6,045 | 9,494 | ||||||||||||||||||
| NGL sales | 18,259 | 2,142 | 44,103 | 1,955 | 3,284 | 5,239 | ||||||||||||||||||
| Total net revenues | $ | 166,130 | $ | 33,044 | $ | 429,902 | $ | 29,717 | $ | 69,116 | $ | 98,833 | ||||||||||||
| Average sales price: | ||||||||||||||||||||||||
| Oil (per Bbl) | $ | 52.45 | $ | 46.21 | $ | 48.17 | $ | 46.49 | $ | 37.74 | $ | 39.91 | ||||||||||||
| Effect of derivative settlements on average price (per Bbl) | (0.37 | ) | 1.80 | (0.06 | ) | 2.02 | 10.49 | 8.39 | ||||||||||||||||
| Oil net of hedging (per Bbl) | $ | 52.08 | $ | 48.01 | $ | 48.11 | $ | 48.51 | $ | 48.23 | $ | 48.30 | ||||||||||||
| Average NYMEX price for oil (per Bbl) | $ | 55.31 | $ | 49.27 | $ | 50.88 | $ | 49.21 | $ | 41.75 | $ | 43.43 | ||||||||||||
| Natural gas (per Mcf) | $ | 2.69 | $ | 3.09 | $ | 2.75 | $ | 3.10 | $ | 2.27 | $ | 2.52 | ||||||||||||
| Effect of derivative settlements on average price (per Mcf) | — | — | — | — | — | — | ||||||||||||||||||
| Natural gas net of hedging (per Mcf) | $ | 2.69 | $ | 3.09 | $ | 2.75 | $ | 3.10 | $ | 2.27 | $ | 2.52 | ||||||||||||
| Average NYMEX price for natural gas (per Mcf) | $ | 2.91 | $ | 3.17 | $ | 3.02 | $ | 3.18 | $ | 2.37 | $ | 2.55 | ||||||||||||
| NGL (per Bbl) | $ | 31.16 | $ | 20.02 | $ | 26.28 | $ | 20.36 | $ | 12.98 | $ | 15.01 | ||||||||||||
| Net production: | ||||||||||||||||||||||||
| Oil (MBbls) | 2,521 | 587 | 6,994 | 523 | 1,584 | 2,107 | ||||||||||||||||||
| Natural gas (MMcf) | 5,816 | 1,222 | 17,754 | 1,113 | 2,660 | 3,773 | ||||||||||||||||||
| NGLs (MBbls) | 586 | 107 | 1,678 | 96 | 253 | 349 | ||||||||||||||||||
| Total (MBoe) | 4,076 | 898 | 11,630 | 805 | 2,280 | 3,085 | ||||||||||||||||||
| Average daily net production volume: | ||||||||||||||||||||||||
| Oil (Bbls/d) | 27,402 | 6,380 | 19,161 | 6,378 | 5,577 | 5,757 | ||||||||||||||||||
| Natural gas (Mcf/d) | 63,217 | 13,283 | 48,640 | 13,573 | 9,366 | 10,309 | ||||||||||||||||||
| NGLs (Bbls/d) | 6,370 | 1,163 | 4,596 | 1,171 | 891 | 954 | ||||||||||||||||||
| Total (Boe/d) | 44,304 | 9,761 | 31,864 | 9,811 | 8,029 | 8,429 | ||||||||||||||||||
_______________________
(1) The three months ended December 31, 2016 includes 10 days of Predecessor results prior to the Business Combination on October 11, 2016.
| Centennial Resource Development, Inc. Operating Expenses | ||||||||||||||||||||||||
| Successor | Combined | Successor | Predecessor | Combined | ||||||||||||||||||||
| Three Months Ended December 31, 2017 | December 31, 2016 | Year Ended December 31, 2017 | October 11, 2016 through December 31, 2016 | January 1, 2016 through October 10, 2016 | Year Ended December 31, 2016 | |||||||||||||||||||
| Operating Expenses (in thousands): | ||||||||||||||||||||||||
| Lease operating expenses | $ | 14,412 | $ | 4,282 | $ | 41,336 | $ | 3,541 | $ | 11,036 | $ | 14,577 | ||||||||||||
| Severance and ad valorem taxes | 8,815 | 1,809 | 23,173 | 1,636 | 3,696 | 5,332 | ||||||||||||||||||
| Gathering, processing, and transportation expense | 11,687 | 2,395 | 34,259 | 2,187 | 4,583 | 6,770 | ||||||||||||||||||
| Production costs per Boe: | ||||||||||||||||||||||||
| Lease operating expenses | $ | 3.54 | $ | 4.77 | $ | 3.55 | $ | 4.40 | $ | 4.84 | $ | 4.73 | ||||||||||||
| Severance and ad valorem taxes | 2.16 | 2.01 | 1.99 | 2.03 | 1.62 | 1.73 | ||||||||||||||||||
| Gathering, processing, and transportation expense | 2.87 | 2.67 | 2.95 | 2.72 | 2.01 | 2.19 | ||||||||||||||||||
_______________________
(1) The three months ended December 31, 2016 includes 10 days of Predecessor results prior to the Business Combination on October 11, 2016.
| Centennial Resource Development, Inc. Condensed Consolidated Statements of Operations (in thousands, except per share data) | ||||||||||||||||||||
| Successor | Combined | Successor | Predecessor | |||||||||||||||||
| Three Months Ended December 31, 2017 | Three Months Ended December 31, 2016 (1) | Year Ended December 31, 2017 | October 11, 2016 through December 31, 2016 | January 1, 2016 through October 10, 2016 | ||||||||||||||||
| Net revenues | ||||||||||||||||||||
| Oil sales | $ | 132,229 | $ | 27,125 | $ | 336,931 | $ | 24,313 | $ | 59,787 | ||||||||||
| Natural gas sales | 15,642 | 3,777 | 48,868 | 3,449 | 6,045 | |||||||||||||||
| NGL sales | 18,259 | 2,142 | 44,103 | 1,955 | 3,284 | |||||||||||||||
| Total net revenues | 166,130 | 33,044 | 429,902 | 29,717 | 69,116 | |||||||||||||||
| Operating expenses | ||||||||||||||||||||
| Lease operating expenses | 14,412 | 4,282 | 41,336 | 3,541 | 11,036 | |||||||||||||||
| Severance and ad valorem taxes | 8,815 | 1,809 | 23,173 | 1,636 | 3,696 | |||||||||||||||
| Gathering, processing and transportation expenses | 11,687 | 2,395 | 34,259 | 2,187 | 4,583 | |||||||||||||||
| Depreciation, depletion and amortization | 58,781 | 16,902 | 161,628 | 14,877 | 62,964 | |||||||||||||||
| Impairment and abandonment expenses | — | (1 | ) | (29 | ) | — | 2,545 | |||||||||||||
| Exploration expense | 10,281 | 1,468 | 14,373 | 1,468 | 920 | |||||||||||||||
| Contract termination and rig stacking | — | — | — | — | — | |||||||||||||||
| General and administrative expenses | 13,865 | 28,017 | 49,882 | 13,091 | 24,661 | |||||||||||||||
| Incentive unit compensation | — | 165,394 | — | — | 165,394 | |||||||||||||||
| Total operating expenses | 117,841 | 220,266 | 324,622 | 36,800 | 275,799 | |||||||||||||||
| Total operating income (loss) | 48,289 | (187,222 | ) | 105,280 | (7,083 | ) | (206,683 | ) | ||||||||||||
| Other income (expense) | ||||||||||||||||||||
| Gain (loss) on sale of oil and natural gas properties | 1,580 | 24 | 8,796 | 24 | 11 | |||||||||||||||
| Interest expense | (3,597 | ) | (582 | ) | (5,729 | ) | (378 | ) | (5,626 | ) | ||||||||||
| Net gain (loss) on derivative instruments | (254 | ) | (4,202 | ) | 5,138 | (1,548 | ) | (6,838 | ) | |||||||||||
| Other income | — | — | — | — | 6 | |||||||||||||||
| Other income (expense) | (2,271 | ) | (4,760 | ) | 8,205 | (1,902 | ) | (12,447 | ) | |||||||||||
| Income (loss) before income taxes | 46,018 | (191,982 | ) | 113,485 | (8,985 | ) | (219,130 | ) | ||||||||||||
| Income tax (expense) benefit | (12,628 | ) | — | (29,930 | ) | — | 406 | |||||||||||||
| Net income (loss) | 33,390 | (191,982 | ) | 83,555 | (8,985 | ) | (218,724 | ) | ||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | 2,854 | (904 | ) | 7,987 | (904 | ) | — | |||||||||||||
| Net income (loss) attributable to common shareholders | $ | 30,536 | $ | (191,078 | ) | $ | 75,568 | $ | (8,081 | ) | $ | (218,724 | ) | |||||||
| Income (loss) per share: | ||||||||||||||||||||
| Basic | $ | 0.12 | $ | 0.32 | $ | (0.05 | ) | |||||||||||||
| Diluted | $ | 0.12 | $ | 0.32 | $ | (0.05 | ) | |||||||||||||
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(1) The three months ended December 31, 2016 includes 10 days of Predecessor results prior to the Business Combination on October 11, 2016.
The following table summarizes our estimated proved reserves, PV-10, and standardized measure of discounted future cash flows as of December 31, 2015, 2016 and 2017.
| Successor | Predecessor | |||||||||||
| December 31, 2017 | December 31, 2016 | December 31, 2015 | ||||||||||
| Proved developed reserves: | ||||||||||||
| Oil (MBbls) | 41,786 | 14,551 | 9,347 | |||||||||
| Natural gas (MMcf) | 126,065 | 42,190 | 12,711 | |||||||||
| NGL (MBbls) | 12,133 | 3,618 | 1,603 | |||||||||
| Total proved developed reserves (MBoe) | 74,929 | 25,200 | 13,068 | |||||||||
| Proved undeveloped reserves: | ||||||||||||
| Oil (MBbls) | 59,147 | 31,914 | 13,852 | |||||||||
| Natural gas (MMcf) | 201,147 | 106,154 | 19,731 | |||||||||
| NGL (MBbls) | 18,853 | 8,152 | 2,248 | |||||||||
| Total proved undeveloped reserves (MBoe) | 111,525 | 57,759 | 19,389 | |||||||||
| Total proved reserves: | ||||||||||||
| Oil (MBbls) | 100,933 | 46,466 | 23,199 | |||||||||
| Natural gas (MMcf) | 327,212 | 148,344 | 32,442 | |||||||||
| NGL (MBbls) | 30,986 | 11,770 | 3,851 | |||||||||
| Total proved reserves (MBoe) | 186,454 | 82,959 | 32,457 | |||||||||
| Proved developed reserves % | 40 | % | 30 | % | 40 | % | ||||||
| Proved undeveloped reserves % | 60 | % | 70 | % | 60 | % | ||||||
| Reserve values (in millions): | ||||||||||||
| Standard measure of discounted future net cash flows | $ | 1,503.3 | $ | 375.1 | $ | 135.1 | ||||||
| Discounted future income tax expense | 244.8 | 52.4 | 10.4 | |||||||||
| Total proved pre-tax PV 10% (1) | $ | 1,748.1 | $ | 427.5 | $ | 145.5 | ||||||
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(1) Pre-tax PV 10% may be considered a non-GAAP financial measure as defined by the SEC and 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.
The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of December 31, 2017:
| Period | Volume (Bbl) | Weighted Average Differential ($/Bbl) (1) | |||||
| Crude oil basis swaps | January 2018 - June 2018 | 905,000 | $ | 0.18 | |||
| January 2018 - December 2018 | 1,825,000 | $ | 0.00 | ||||
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(1) The oil basis swap transactions are settled based on the difference between the arithmetic average of the ARGUS MIDLAND WTI and ARGUS WTI CUSHING settlements, during the relevant calculation period.
| Period | Volume (MMBtu) | Weighted Average Differential ($/MMBtu) (1) | |||||
| Natural gas basis swaps | January 2018 - December 2018 | 1,825,000 | $ | (0.43 | ) | ||
| January 2019 - December 2019 | 1,825,000 | $ | (0.43 | ) | |||
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(1) The natural gas basis swap contracts are settled based on the difference between Inside FERC’s West Texas WAHA price of natural gas and the NYMEX price of Natural Gas during the relevant calculation period.
Supplemental Measures
Organic Reserves Replacement Ratio
The Company uses the organic reserves 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 reserves replacement ratio of 954% was calculated as the sum of total 2017 reserve extensions, discoveries and revisions (technical and pricing) of 111.0 MMBoe, divided by total 2017 production of 11.6 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 development the Company’s reserves.
Proved developed F&D of $10.62 per Boe is defined as total 2017 exploration and developments costs of $607.4 million divided by the sum of total proved developed reserve extensions and discoveries, transfers from proved undeveloped reserves at year-end 2016, and proved developed reserve revisions (technical and pricing), totaling 57.2 MMBoe.
Drill-bit F&D of $5.47 per Boe is defined as total 2017 exploration and developments costs of $607.4 million divided by the sum of total 2017 proved reserve extensions, discoveries and revisions (technical and pricing) of 111.0 MMBoe.