Centennial Resource Development Announces Third Quarter 2018 Financial and Operational Results
Financial and Operational Highlights:
- Increased daily crude oil production 15 percent quarter-over-quarter and 71 percent year-over-year
- Increased daily equivalent production 9 percent quarter-over-quarter and 81 percent year-over-year
- Announced strong well results from six intervals in the Northern and Southern Delaware Basins, including one of the best First Bone Spring wells drilled in
New Mexico - Acquired approximately 2,900 net acres adjacent to positions in
Reeves County, Texas andLea County, New Mexico - Continued to show cost discipline with year-to-date unit costs at low end of guidance
- Maintained conservative balance sheet and strong liquidity
Financial Results
Third quarter net income increased 172 percent to
Average daily crude oil production increased 71 percent to 36,027 barrels of oil per day (“Bbls/d”) compared to the prior year period. Crude oil volumes accounted for 57% of total equivalent volumes compared to 54% in the prior quarter. Average daily total equivalent production increased 81 percent compared to the prior year period.
“Centennial delivered another quarter of solid operating results driven by strong well performance and cost control. Our operations team continues to generate some of the best wells in the
Operational Update
Centennial reported a number of strong wells across multiple intervals in the
“Consistent with our strategy of driving efficiencies and increasing economic returns, our average completed lateral length during the quarter increased 33 percent to approximately 7,700 feet compared to the prior year period,” Papa said. “The Doc Gardner, a very prolific well, represents our longest lateral drilled to date and has produced approximately 100,000 barrels of oil during its first 60 days on production.”
On the Company’s Miramar acreage in
In
The Tour Bus 23 State 505H and 506H (100% WI), drilled from Centennial’s first operated multi-well pad in
Total capital expenditures incurred for the quarter were
“As expected, drilling and completion capital expenditures increased sequentially as a result of the increased number of completions on higher working interest wells with longer laterals compared to the prior quarter,” said Papa. “Overall, we continue to be quite pleased with the capital cost control our operations team has demonstrated this year and remain confident on delivering full-year total capital expenditures within our guidance range.”
Recent Acquisitions
During the fourth quarter 2018, Centennial closed three acquisitions for a total of approximately 2,900 net acres adjacent to its existing positions in the Northern and Southern Delaware Basins. In
“Consistent with our strategy of targeting tactical bolt-on acquisitions, these transactions are adjacent to our existing positions and increase our working interests,” said Papa. “The Reeves County acquisition represents the addition of high-quality acreage and offsets Centennial’s recent Highlander and
In
"Our strategy of driving organic growth on our existing acreage, complemented by smaller offset acquisitions should provide superior GAAP returns to our shareholders over the long-run,” said Papa. “Through our acquisitions and organic leasing efforts year-to-date, we have more than fully replenished the inventory expected to be drilled this year. This will be key for the Company going forward.”
(For a map summarizing Centennial’s recent acquisitions and offset operated wells, please see the presentation materials on Centennial’s website under the Investor Relations tab.)
Capital Structure and Liquidity
As of
Hedge Position
As of November 5, 2018, Centennial's crude oil hedge portfolio consisted only of basis swaps. For the period October to
“Through previously announced firm sales agreements, approximately half of Centennial’s 2019 expected crude oil volumes will receive
Quarterly Report on Form 10-Q
Centennial’s financial statements and related footnotes will be available in its Quarterly Report on Form 10-Q for the three months ended
Conference Call and Webcast
Centennial will host an investor conference call on Tuesday, November 6, 2018 at
About
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 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;
- 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
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
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 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 and transaction costs. Adjusted EBITDAX is not a measure of net income as determined by generally accepted accounting principles (“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:
For the Three Months Ended September 30, | For the Nine Months Ended September 30, | ||||||||||||||
(in thousands) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Adjusted EBITDAX reconciliation to net income: | |||||||||||||||
Net income attributable to Class A Common Stock | $ | 39,288 | $ | 14,447 | $ | 168,919 | $ | 45,032 | |||||||
Net income attributable to noncontrolling interest | 2,386 | 1,813 | 11,009 | 5,133 | |||||||||||
Interest expense | 6,534 | 1,015 | 18,138 | 2,132 | |||||||||||
Income tax expense | 11,652 | 8,233 | 50,729 | 17,302 | |||||||||||
Depreciation, depletion and amortization | 83,423 | 42,387 | 224,379 | 102,847 | |||||||||||
Impairment and abandonment expenses | 8,612 | — | 10,396 | (29 | ) | ||||||||||
Non-cash mark-to-market derivative (gain) loss | 18,437 | 1,286 | (579 | ) | (5,126 | ) | |||||||||
Stock-based compensation expense | 4,888 | 3,360 | 13,006 | 8,288 | |||||||||||
Exploration expense | 2,712 | 1,622 | 8,026 | 4,092 | |||||||||||
Transaction costs | — | 42 | — | 1,386 | |||||||||||
(Gain) loss on sale of oil and natural gas properties | (52 | ) | 141 | 74 | (7,216 | ) | |||||||||
Adjusted EBITDAX | $ | 177,880 | $ | 74,346 | $ | 504,097 | $ | 173,841 | |||||||
Operating Highlights
For the Three Months Ended September 30, | For the Nine Months Ended September 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Operating revenues (in thousands): | |||||||||||||||
Oil sales | $ | 184,510 | $ | 87,286 | $ | 533,507 | $ | 204,702 | |||||||
Natural gas sales | 14,311 | 12,852 | 46,612 | 33,226 | |||||||||||
NGL sales | 36,059 | 11,473 | 88,422 | 25,844 | |||||||||||
Oil and gas sales | $ | 234,880 | $ | 111,611 | $ | 668,541 | $ | 263,772 | |||||||
Average sales prices: | |||||||||||||||
Oil (per Bbl) | $ | 55.68 | $ | 44.95 | $ | 59.27 | $ | 45.76 | |||||||
Effect of derivative settlements on average price (per Bbl) | 2.56 | 0.21 | 1.50 | 0.12 | |||||||||||
Oil net of hedging (per Bbl) | $ | 58.24 | $ | 45.16 | $ | 60.77 | $ | 45.88 | |||||||
Average NYMEX price for oil (per Bbl) | $ | 69.50 | $ | 48.17 | $ | 66.75 | $ | 49.44 | |||||||
Oil differential from NYMEX | (13.82 | ) | (3.22 | ) | (7.48 | ) | (3.68 | ) | |||||||
Natural gas (per Mcf) | $ | 1.83 | $ | 2.72 | $ | 2.02 | $ | 2.78 | |||||||
Effect of derivative settlements on average price (per Mcf) | 0.05 | — | 0.04 | (0.02 | ) | ||||||||||
Natural gas net of hedging (per Mcf) | $ | 1.88 | $ | 2.72 | $ | 2.06 | $ | 2.76 | |||||||
Average NYMEX price for natural gas (per Mcf) | $ | 2.93 | $ | 2.95 | $ | 2.95 | $ | 3.05 | |||||||
Natural gas differential from NYMEX | (1.10 | ) | $ | (0.23 | ) | $ | (0.93 | ) | (0.27 | ) | |||||
NGL (per Bbl) | $ | 30.85 | $ | 24.83 | $ | 29.08 | $ | 23.67 | |||||||
Net production: | |||||||||||||||
Oil (MBbls) | 3,314 | 1,942 | 9,002 | 4,473 | |||||||||||
Natural gas (MMcf) | 7,837 | 4,733 | 23,092 | 11,938 | |||||||||||
NGL (MBbls) | 1,169 | 462 | 3,040 | 1,092 | |||||||||||
Total (MBoe)(1) | 5,790 | 3,192 | 15,891 | 7,554 | |||||||||||
Average daily net production volume: | |||||||||||||||
Oil (Bbls/d) | 36,027 | 21,108 | 32,973 | 16,384 | |||||||||||
Natural gas (Mcf/d) | 85,180 | 51,444 | 84,585 | 43,729 | |||||||||||
NGL (Bbls/d) | 12,706 | 5,018 | 11,137 | 3,999 | |||||||||||
Total (Boe/d)(1) | 62,930 | 34,700 | 58,208 | 27,670 |
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. | ||
Operating Expenses
For the Three Months Ended September 30, | For the Nine Months Ended September 30, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Operating costs (in thousands): | |||||||||||
Lease operating expenses | $ | 23,706 | $ | 11,373 | $ | 59,164 | $ | 26,924 | |||
Severance and ad valorem taxes | 14,410 | 6,448 | 42,791 | 14,358 | |||||||
Gathering, processing and transportation expenses | 16,090 | 9,925 | 45,214 | 22,572 | |||||||
Operating costs per Boe: | |||||||||||
Lease operating expenses | $ | 4.09 | $ | 3.56 | $ | 3.72 | $ | 3.56 | |||
Severance and ad valorem taxes | 2.49 | 2.02 | 2.69 | 1.90 | |||||||
Gathering, processing and transportation expenses | 2.78 | 3.11 | 2.85 | 2.99 | |||||||
Condensed Consolidated Statements of Operations
(in thousands, except per share data)
For the Three Months Ended September 30, | For the Nine Months Ended September 30, | ||||||||||||||||||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||||||||||||||||||
Operating revenues | |||||||||||||||||||||||||||||||
Oil and gas sales | $ | 234,880 | $ | 111,611 | $ | 668,541 | $ | 263,772 | |||||||||||||||||||||||
Operating expenses | |||||||||||||||||||||||||||||||
Lease operating expenses | 23,706 | 11,373 | 59,164 | 26,924 | |||||||||||||||||||||||||||
Severance and ad valorem taxes | 14,410 | 6,448 | 42,791 | 14,358 | |||||||||||||||||||||||||||
Gathering, processing and transportation expenses | 16,090 | 9,925 | 45,214 | 22,572 | |||||||||||||||||||||||||||
Depreciation, depletion and amortization | 83,423 | 42,387 | 224,379 | 102,847 | |||||||||||||||||||||||||||
Impairment and abandonment expenses | 8,612 | — | 10,396 | (29 | ) | ||||||||||||||||||||||||||
Exploration expense | 2,712 | 1,622 | 8,026 | 4,092 | |||||||||||||||||||||||||||
General and administrative expenses | 16,561 | 13,311 | 44,667 | 36,017 | |||||||||||||||||||||||||||
Total operating expenses | 165,514 | 85,066 | 434,637 | 206,781 | |||||||||||||||||||||||||||
Income from operations | 69,366 | 26,545 | 233,904 | 56,991 | |||||||||||||||||||||||||||
Other income (expense) | |||||||||||||||||||||||||||||||
Gain (loss) on sale of oil and natural gas properties | 52 | (141 | ) | (74 | ) | 7,216 | |||||||||||||||||||||||||
Interest expense | (6,534 | ) | (1,015 | ) | (18,138 | ) | (2,132 | ) | |||||||||||||||||||||||
Net gain (loss) on derivative instruments | (9,571 | ) | (896 | ) | 14,969 | 5,392 | |||||||||||||||||||||||||
Other income (expense) | 13 | — | (4 | ) | — | ||||||||||||||||||||||||||
Other income (expense) | (16,040 | ) | (2,052 | ) | (3,247 | ) | 10,476 | ||||||||||||||||||||||||
Income before income taxes | 53,326 | 24,493 | 230,657 | 67,467 | |||||||||||||||||||||||||||
Income tax expense | (11,652 | ) | (8,233 | ) | (50,729 | ) | (17,302 | ) | |||||||||||||||||||||||
Net income | 41,674 | 16,260 | 179,928 | 50,165 | |||||||||||||||||||||||||||
Less: Net income attributable to noncontrolling interest | 2,386 | 1,813 | 11,009 | 5,133 | |||||||||||||||||||||||||||
Net income attributable to Class A Common Stock | $ | 39,288 | $ | 14,447 | $ | 168,919 | $ | 45,032 | |||||||||||||||||||||||
Income per share of Class A Common Stock: | |||||||||||||||||||||||||||||||
Basic | $ | 0.15 | $ | 0.06 | $ | 0.64 | $ | 0.20 | |||||||||||||||||||||||
Diluted | $ | 0.15 | $ | 0.06 | $ | 0.63 | $ | 0.19 | |||||||||||||||||||||||
The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of September 30, 2018:
Period | Volume (Bbls) | Volume (Bbls/d) | Weighted Average Differential ($/Bbl)(1) |
||||||||||||
Crude oil basis swaps | October 2018 - December 2018 | 828,000 | 9,000 | $ | (2.38 | ) | |||||||||
January 2019 - March 2019 | 540,000 | 6,000 | (5.34 | ) | |||||||||||
April 2019 - June 2019 | 91,000 | 1,000 | (10.00 | ) | |||||||||||
July 2019 - September 2019 | 1,380,000 | 15,000 | (9.03 | ) | |||||||||||
October 2019 - December 2019 | 920,000 | 10,000 | (4.24 | ) | |||||||||||
(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 indices, during the relevant calculation period.
Period | Volume (MMBtu) | Volume (MMBtu/d) | Weighted Average Fixed Price ($/MMBtu)(1) |
||||||||||||
Natural Gas Swaps - Henry Hub | January 2019 - December 2019 | 10,950,000 | 30,000 | $ | 2.78 | ||||||||||
Natural Gas Swaps - West Texas WAHA | January 2019 - December 2019 | 5,475,000 | 15,000 | 1.61 | |||||||||||
Period | Volume (MMBtu) | Volume (MMBtu/d) | Weighted Average Differential ($/MMBtu)(2) |
||||||||||||
Natural gas basis swaps | October 2018 - December 2018 | 460,000 | 5,000 | $ | (0.43 | ) | |||||||||
January 2019 - December 2019 | 12,775,000 | 35,000 | (1.31 | ) |
(1) The natural gas swap contracts are settled based on either i) the NYMEX Henry Hub price or ii) the Inside FERC West Texas WAHA price of natural gas as of the specified settlement date, as applicable.
(2) The 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 the relevant calculation period.
Source: Centennial Resource Development