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| 8-K - 8-K - Centennial Resource Development, Inc. | q1-18earningsrelease8xk.htm |
Centennial Resource Development Announces First Quarter 2018 Financial and Operational Results
DENVER, CO, May 8, 2018 (GLOBE NEWSWIRE) - Centennial Resource Development, Inc. (“Centennial” or the “Company”) (NASDAQ: CDEV) today announced financial and operational results for the first quarter 2018.
Financial and Operational Highlights:
• | Increased daily crude oil production 15 percent quarter-over-quarter and 201 percent year-over-year |
• | Announced strong Wolfcamp A well results including a positive test in Lea County, New Mexico |
• | Delivered consistent well results from multiple intervals in the Delaware Basin |
• | Decreased unit costs sequentially |
• | Reported drilling and completion capital expenditures in line with expectations |
• | Maintained conservative balance sheet and strong liquidity |
Financial Results
First quarter net income increased 116% to $66.1 million, or $0.25 per diluted share, compared to $30.5 million, or $0.12 per diluted share, in the fourth quarter 2017.
For the quarter, average daily crude oil production increased 15 percent compared to the prior quarter and 201 percent compared to the same prior year period. Average daily total equivalent production increased 22 percent compared to the prior period. Centennial’s robust production profile enhanced overall financial performance with the reduction of unit cost metrics, including a reduction in depreciation, depletion and amortization to $13.57 per barrel of oil equivalent ("Boe") for the quarter from $14.42 per Boe in the prior quarter.
“Centennial delivered another quarter of solid operating results. This puts us on-track to deliver the 2018 goals articulated at the beginning of the year,” said Mark G. Papa, Chairman and Chief Executive Officer. “We saw consistent well performance during the quarter, with the average well producing approximately 1,200 barrels of oil per day for the initial 30-day production period. Individual wells are outperforming our expectations. These well results coupled with low unit costs were key to giving us very strong overall results for the quarter.”
Operational Update
Centennial continues to efficiently develop its acreage position in the Delaware Basin. In Lea County, New Mexico, the Juliet Federal Com 1H (85% WI) was drilled with an approximate 4,000-foot effective lateral and reported an initial 30-day production rate of 1,447 Boe/d (78% oil). The well averaged 282 Bbls/d of oil per 1,000 foot of lateral for the first 30 days and produced over 50,000 barrels of oil during its initial 60-day period.
“The Juliet is Centennial’s first operated well targeting the Wolfcamp A in Lea County. The initial results are very positive, and we believe this confirms the productivity of this interval on our acreage in the Northern Delaware,” Papa said. “Since entering this part of the basin last year, essentially every well has either met or exceeded expectations, highlighting the quality of our acreage and the expertise of our technical team.”
Centennial also reported results from new horizons on the Texas side of the Delaware Basin where it is operating a six rig drilling program. While still drilling some delineation wells across its acreage, drilling and completion operations have largely shifted to multi-well pad development where possible, leading to greater operational efficiencies and cost improvements.
In Reeves County, Texas, Centennial posted robust results from the Third Bone Spring Sand, Upper Wolfcamp A and the Wolfcamp B intervals. With 98% WI in both wells, the Carpenter State A U30H and B U39H were drilled in the Upper Wolfcamp A with approximate 6,900-foot laterals. The Carpenter State A U30H averaged 2,020 Boe/d (84% oil) for the initial 30-day production period. The Carpenter State B U39H reported an initial 30-day production rate of 1,532 Boe/d (86% oil). The Carpenter State A U30H and B U39H delivered an average initial 30-day oil production rate of 216 Bbls/d per 1,000 foot of lateral per well. Additionally, Centennial drilled and completed an extended 9,100-foot lateral, the Sieber Trust B13H (100% WI) in the Wolfcamp B formation. The well achieved an initial 30-day production rate of 1,877 Boe/d, or 1,441 Bbls/d of oil (77% oil).
“During the first quarter, the average completed lateral length increased more than 20 percent over the previous quarter. The impact of cost savings from drilling longer laterals from multi-well pads and higher well productivity is reflected in our improved bottom line,” Papa said. “Also, the encouraging results from the Sieber Trust well give us greater confidence in future upside potential of our Reeves County acreage position in the Wolfcamp B.”
As previously announced, the Weaver C T34H (86% WI) was Centennial’s first Reeves County well in the Third Bone Spring Sand, using modern completion techniques. The well, drilled with an approximate 9,350-foot effective lateral, reported an initial 30-day production rate of 2,129 Boe/d, or 1,563 Bbls/d of oil (73% oil). The well has proved the viability of the zone with results comparable to some of Centennial’s best producers from the Wolfcamp A zone.
“With 82,000 barrels of oil in the first 60 days, the Weaver well continues to demonstrate a very strong production profile,” Papa said. “The Third Bone Spring Sand extends over a significant portion of our Reeves County position and has the potential to add substantial, high rate-of-return inventory to our drilling portfolio. We expect to drill additional wells in the zone during the year.”
Drilling and completion capital expenditures incurred for the first quarter were approximately $181.8 million. Centennial’s facilities, infrastructure, land and other capital totaled approximately $56.5 million during the quarter.
“Operationally, this was a significant quarter for us. We drilled a Wolfcamp A well in Lea County, while testing longer laterals in the Wolfcamp A and B zones in Reeves County. All wells came on-line with strong oil production over the initial thirty-day period,” Papa said. “Furthermore, we now have over sixty days of production from our Third Bone Spring Sand test that continues to produce at a very healthy rate of oil production. These data points set us up nicely and confirm additional running room for the future.”
Capital Structure and Liquidity
As of March 31, 2018, Centennial had approximately $38 million in cash on hand, with zero borrowings under the revolving credit facility and $400 million of senior unsecured notes. On May 4, 2018, the Company closed a new five-year revolving credit facility. The borrowing base under the new credit facility increased by 39% to $800 million from $575 million under the Company’s prior credit facility, with a new elected commitment of $600 million. As of March 31, 2018, after giving effect to the new borrowing base and elected commitment, total liquidity was approximately $637 million, including letters of credit.
Hedge Position
As of May 8, 2018, Centennial had no fixed-price crude oil hedges. For the period April to December 2018, Centennial’s crude oil basis hedges represent approximately 27% of its expected crude oil production (using the mid-point of guidance) at a weighted average price of $(1.77) per barrel. To protect its associated rich natural gas production from
current market dynamics in the Permian Basin, Centennial also entered into additional natural gas swap and basis hedges effective 2019. (For a summary table of Centennial’s derivative contracts as of May 1, 2018, please see the Appendix of this press release.)
“As predicted, crude oil prices have responded positively to tightening global supply and demand fundamentals. At this time, we plan to remain fully unhedged on future oil production given our positive macro view,” Papa said. “We will also look to ensure adequate gas takeaway from the basin and minimize basis pricing risk for both crude oil and natural gas.”
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 March 31, 2018, which is expected be filed with the U.S. Securities and Exchange Commission (“SEC”) on May 8, 2018.
Conference Call and Webcast
Centennial will host an investor conference call on Wednesday, May 9, 2018 at 8:00 a.m. Mountain (10:00 a.m. Eastern) to discuss first quarter 2018 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 (800) 789-3525, or (442) 268-1041 for international calls, (Conference ID: 1872225) 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: 1872225) 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 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; |
• | our marketing of 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 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
SOURCE Centennial Resource Development, Inc.
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 March 31, | |||||||
(in thousands) | 2018 | 2017 | |||||
Adjusted EBITDAX reconciliation to net income: | |||||||
Net income attributable to Class A Common Stock | $ | 66,090 | $ | 9,823 | |||
Net income attributable to noncontrolling interest | 4,682 | 884 | |||||
Interest expense | 5,813 | 410 | |||||
Income tax expense | 19,137 | — | |||||
Depreciation, depletion and amortization | 66,010 | 26,160 | |||||
Impairment and abandonment expenses | — | (29 | ) | ||||
Non-cash portion of derivative gain | (7,482 | ) | (4,156 | ) | |||
Stock-based compensation expense | 3,952 | 2,370 | |||||
Exploration expense | 3,447 | 1,181 | |||||
Transaction costs | — | 887 | |||||
(Gain) loss on sale of oil and natural gas properties | (15 | ) | (166 | ) | |||
Adjusted EBITDAX | $ | 161,634 | $ | 37,364 | |||
Centennial Resource Development, Inc.
Operating Highlights
For the Three Months Ended March 31, | Increase/(Decrease) | |||||||||||||
2018 | 2017 | $ | % | |||||||||||
Operating revenues (in thousands): | ||||||||||||||
Oil sales | $ | 174,841 | $ | 46,681 | $ | 128,160 | 275 | % | ||||||
Natural gas sales | 18,580 | 8,241 | 10,339 | 125 | % | |||||||||
NGL sales | 22,477 | 6,175 | 16,302 | 264 | % | |||||||||
Oil and gas sales | $ | 215,898 | $ | 61,097 | $ | 154,801 | 253 | % | ||||||
Average sales prices: | ||||||||||||||
Oil (per Bbl) | $ | 61.53 | $ | 49.45 | $ | 12.08 | 24 | % | ||||||
Effect of derivative settlements on average price (per Bbl) | (0.09 | ) | 0.28 | (0.37 | ) | (132 | )% | |||||||
Oil net of hedging (per Bbl) | $ | 61.44 | $ | 49.73 | $ | 11.71 | 24 | % | ||||||
Average NYMEX price for oil (per Bbl) | $ | 62.91 | $ | 51.82 | $ | 11.09 | 21 | % | ||||||
Natural gas (per Mcf) | $ | 2.42 | $ | 2.91 | $ | (0.49 | ) | (17 | )% | |||||
Effect of derivative settlements on average price (per Mcf) | (0.01 | ) | 0.05 | (0.06 | ) | (120 | )% | |||||||
Natural gas net of hedging (per Mcf) | $ | 2.41 | $ | 2.96 | $ | (0.55 | ) | (19 | )% | |||||
Average NYMEX price for natural gas (per Mcf) | $ | 3.08 | $ | 3.06 | $ | 0.02 | 1 | % | ||||||
NGL (per Bbl) | $ | 30.21 | $ | 25.10 | $ | 5.11 | 20 | % | ||||||
Net production: | ||||||||||||||
Oil (MBbls) | 2,842 | 944 | 1,898 | 201 | % | |||||||||
Natural gas (MMcf) | 7,683 | 2,833 | 4,850 | 171 | % | |||||||||
NGL (MBbls) | 744 | 246 | 498 | 202 | % | |||||||||
Total (MBoe) | 4,866 | 1,662 | 3,204 | 193 | % | |||||||||
Average daily net production volume: | ||||||||||||||
Oil (Bbls/d) | 31,573 | 10,489 | 21,084 | 201 | % | |||||||||
Natural gas (Mcf/d) | 85,372 | 31,478 | 53,894 | 171 | % | |||||||||
NGL (Bbls/d) | 8,267 | 2,733 | 5,534 | 202 | % | |||||||||
Total (Boe/d) | 54,069 | 18,469 | 35,600 | 193 | % | |||||||||
Centennial Resource Development, Inc.
Operating Expenses
For the Three Months Ended March 31, | Increase/(Decrease) | |||||||||||||
2018 | 2017 | $ | % | |||||||||||
Operating costs (in thousands): | ||||||||||||||
Lease operating expenses | $ | 16,276 | $ | 7,278 | $ | 8,998 | 124 | % | ||||||
Severance and ad valorem taxes | 14,173 | 3,187 | 10,986 | 345 | % | |||||||||
Gathering, processing and transportation expenses | 13,828 | 5,244 | 8,584 | 164 | % | |||||||||
Operating costs per Boe: | ||||||||||||||
Lease operating expenses | $ | 3.34 | $ | 4.38 | $ | (1.04 | ) | (24 | )% | |||||
Severance and ad valorem taxes | 2.91 | 1.92 | 0.99 | 52 | % | |||||||||
Gathering, processing and transportation expenses | 2.84 | 3.16 | (0.32 | ) | (10 | )% | ||||||||
Centennial Resource Development, Inc.
Condensed Consolidated Statements of Operations
(in thousands, except per share data)
For the Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
Operating revenues | |||||||
Oil and gas sales | 215,898 | 61,097 | |||||
Operating expenses | |||||||
Lease operating expenses | 16,276 | 7,278 | |||||
Severance and ad valorem taxes | 14,173 | 3,187 | |||||
Gathering, processing and transportation expenses | 13,828 | 5,244 | |||||
Depreciation, depletion and amortization | 66,010 | 26,160 | |||||
Impairment and abandonment expenses | — | (29 | ) | ||||
Exploration expense | 3,447 | 1,181 | |||||
General and administrative expenses | 14,297 | 10,884 | |||||
Total operating expenses | 128,031 | 53,905 | |||||
Income from operations | 87,867 | 7,192 | |||||
Other income (expense) | |||||||
Gain (loss) on sale of oil and natural gas properties | 15 | 166 | |||||
Interest expense | (5,813 | ) | (410 | ) | |||
Net gain (loss) on derivative instruments | 7,843 | 3,759 | |||||
Other income (expense) | (3 | ) | — | ||||
Other income (expense) | 2,042 | 3,515 | |||||
Income before income taxes | 89,909 | 10,707 | |||||
Income tax expense | 19,137 | — | |||||
Net income | 70,772 | 10,707 | |||||
Less: Net income attributable to noncontrolling interest | 4,682 | 884 | |||||
Net income attributable to Class A Common Stock | $ | 66,090 | $ | 9,823 | |||
Income per share of Class A Common Stock: | |||||||
Basic | $ | 0.25 | $ | 0.04 | |||
Diluted | $ | 0.25 | $ | 0.04 | |||
The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of March 31, 2018 and additional contracts entered into through May 1, 2018:
Description and Production Period | Volume (Bbl) | Weighted Average Differential ($/Bbl) (1) | ||||
Crude Oil Basis Swaps: | ||||||
April 2018 - June 2018 | 91,000 | $ | 0.10 | |||
April 2018 - June 2018 | 91,000 | 0.20 | ||||
April 2018 - June 2018 | 91,000 | 0.20 | ||||
April 2018 - June 2018 | 91,000 | 0.22 | ||||
April 2018 - June 2018 | 91,000 | 0.17 | ||||
April 2018 - December 2018 | 137,500 | 0.00 | ||||
April 2018 - December 2018 | 137,500 | 0.00 | ||||
April 2018 - December 2018 | 550,000 | 0.00 | ||||
April 2018 - December 2018 | 275,000 | 0.00 | ||||
April 2018 - December 2018 | 275,000 | 0.00 | ||||
May 2018 - March 2019 | 760,000 | (5.25) | ||||
May 2018 - March 2019 | 190,000 | (5.25) | ||||
June 2018 - March 2019 | 174,500 | (5.50) | ||||
June 2018 - March 2019 | 349,000 | (5.50) | ||||
(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. |
Description and Production Period | Volume (MMBtu) | Weighted Average Fixed Price ($/MMBtu)(1) | ||||
Natural Gas Swaps: | ||||||
January 2019 - December 2019 | 3,650,000 | $ | 2.78 | |||
January 2019 - December 2019 | 3,650,000 | 2.78 | ||||
January 2019 - December 2019 | 3,650,000 | 2.78 | ||||
Description and Production Period | Volume (MMBtu) | Weighted Average Differential ($/MMBtu)(2) | ||||
Natural Gas Basis Swaps: | ||||||
April 2018 - December 2018 | 1,375,000 | $ | (0.43 | ) | ||
January 2019 - December 2019 | 1,825,000 | $ | (0.43 | ) | ||
January 2019 - December 2019 | 3,650,000 | $ | (1.46 | ) | ||
January 2019 - December 2019 | 3,650,000 | $ | (1.46 | ) | ||
January 2019 - December 2019 | 3,650,000 | $ | (1.47 | ) | ||
(1) | The natural gas swap contracts are settled based on the month’s average daily NYMEX price of Henry Hub Natural Gas. |
(2) | 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. |