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|Centennial Resource Development Announces Second Quarter 2018 Financial and Operational Results and Lowers 2018 Cost Guidance|
Financial and Operational Highlights:
Second quarter net income increased 206 percent to
Average daily crude oil production increased 79 percent in the second quarter and 125 percent for the first half of 2018 compared to prior year periods.
“As evidenced by our results, we continue to deliver some of the best wells in
NGL volumes increased 50% to 12,389 Bbls/d compared to the first quarter 2018 and accounted for 22% of total equivalent volumes compared to 15% in the prior quarter. The increase was attributable to the Company’s primary gas processor shifting to ethane recovery during the quarter and extracting additional liquids from the gas stream to provide enhanced economics for a portion of our production.
“The change to ethane recovery was solely an economic decision, and we recognized higher revenue as a result,” Papa said. “The increase in NGL volumes increased our overall equivalent production causing oil as a percentage of total production to decline quarter-over-quarter, but had no effect on actual oil volumes.”
Centennial’s operational shift to multi-well pad development in the
“In our second full year of operations, we have made the shift from drilling one-off wells to a full development program. During the second quarter, ninety percent of wells completed were on multi-well pads, reflecting the transition to more efficient, higher return operations. The long-term economic benefits from this development mode will offset any short-term irregular production trends,” Papa said.
The Red Rock A Unit T09H and U04H (74% WI) were drilled using a stacked, staggered pattern in the Third Bone Spring Sand and Upper Wolfcamp A intervals, respectively, with effective 10,900 foot laterals. The Red Rock A Unit T09H achieved an initial 30-day production rate of 1,578 Boe/d, with 1,143 Bbls/d of oil. The Red Rock A Unit U04H reported an initial 30-day production rate of 1,268 Boe/d, with 940 Bbls/d of oil.
“The Red Rock A Unit wells prove the viability of simultaneously pairing the Third Bone Spring Sand and Upper Wolfcamp A intervals. The Unit T09H was a key well, it was our second successful Third Bone Spring Sand test and our first co-development test of another interval,” Papa said. “We have organically added a new, high rate of return play on a portion of our
The CWI Long A U31H, B U40H and C U49H (64% WI) were drilled in the Upper Wolfcamp A interval with approximate 9,850-foot laterals. These wells achieved initial 30-day production rates of 2,158 Boe/d (78% oil), 2,899 Boe/d (78% oil) and 2,278 Boe/d (78% oil), respectively. The three-well pad delivered an average initial 30-day oil production rate of 194 Bbls/d per 1,000 foot of lateral per well.
“The CWI Long pad represents our best and most productive wells drilled to date. Combined, these wells have produced over 200,000 barrels of oil during their first forty days on production,” Papa said.
On the Company’s Miramar acreage, the Ninja 4-50 49 2H, 3H, 4H and 5H (89% WI) were drilled on a four-well pad targeting the Lower Wolfcamp A, Upper Wolfcamp A, Wolfcamp C and Upper Wolfcamp A intervals, respectively. Drilled with an average extended lateral length of 9,800 feet, the wells delivered an average initial 30-day production rate of 1,878 Boe/d (58% oil) per well. During its initial 60-day production period, the pad produced over 225,000 barrels of oil.
Targeting the Upper Wolfcamp A zone, the Balmorhea State G 8H, H 9H and I 10H (100% WI) wells were drilled with average 6,150 foot effective laterals. Each well began production at an average initial 30-day production rate of 1,337 Boe/d (77% oil) per well, or 166 Bbls/d of oil per 1,000 foot of lateral.
“Notably, all of our highlighted wells this quarter commenced production in mid-May or June and, therefore, had only a minor impact on second quarter production," Papa said. “Given these robust results, we feel confident headed into the second half of the year.”
Total capital expenditures incurred for the quarter were
Midstream and Marketing Update
Centennial recently entered into a firm sales agreement for a significant portion of its oil production with a large diversified crude oil purchaser. Utilizing the buyer’s existing firm transport capacity out of the Basin, the six-year agreement provides for firm gross sales of 20,000 Bbls/d beginning in
“This agreement secures flow assurance for a large portion of our crude oil volumes. Additionally, it provides access to Brent-weighted pricing in 2020, enabling us to diversify our pricing portfolio longer term,” Papa said. “We are working with other major marketers and expect to execute similar contracts within the next few months. Our goal is to secure transportation for essentially all of our future crude oil production.”
Centennial also finalized transportation agreements for all of its expected associated natural gas production. Through firm transportation and sales agreements, Centennial has ensured flow assurance both to the Waha Hub and out of the
“We expect natural gas egress will become a significant issue in the
Updated 2018 Operational Targets
Based on recent operational results, Centennial lowered its full-year 2018 guidance ranges for LOE, Cash G&A, GP&T and DD&A on a per unit basis. As a result of ethane recovery and anticipated further extraction of additional NGLs from the natural gas stream, the Company adjusted its full-year 2018 total equivalent production target as illustrated in the Appendix to this press release.
“Centennial delivered second quarter unit costs either below or at the low-end of our full-year guidance ranges. We have the confidence to lower our total unit cost for the second consecutive year,” Papa said. “Overall, our operations team continues to do an outstanding job driving down costs and keeping drilling and completion costs in-line, even in light of the current inflationary oilfield service cost environment in the
(For a summary table of Centennial’s updated 2018 operational guidance, please see the Appendix to this press release.)
Capital Structure and Liquidity
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 June 30, 2018, which is expected be filed with the
Conference Call and Webcast
Centennial will host an investor conference call on Tuesday, August 7, 2018 at
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:
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.
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:
The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of June 30, 2018 and additional contracts entered into through August 1, 2018:
(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.