Investor Relations

Centennial Resource Development is an independent oil producer focused in the Delaware Basin. Centennial was formed in 2016 through the business combination of Centennial Resource Production, LLC and Silver Run Acquisition Corporation, a special purpose acquisition company formed by Mark Papa, our former Chairman and CEO, and Riverstone Holdings, LLC, an energy private equity fund. Centennial is headquartered in Denver, Colorado.

Press Release

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Centennial Resource Development Announces Second Quarter 2018 Financial and Operational Results and Lowers 2018 Cost Guidance

DENVER, Aug. 06, 2018 (GLOBE NEWSWIRE) -- Centennial Resource Development, Inc. (“Centennial” or the “Company”) (NASDAQ: CDEV) today announced financial and operational results for the second quarter 2018 and updated 2018 operational targets.

Financial and Operational Highlights:

  • Increased daily equivalent production 6 percent quarter-over-quarter and 94 percent year-over-year
  • Reported successful Third Bone Spring Sand result in Reeves County, Texas
  • Announced strong well results from multiple intervals in Southern Delaware Basin, including most productive wells to date
  • Executed firm sales agreement for significant portion of crude oil production
  • Secured firm transportation agreements for natural gas production through 2021
  • Delivered unit costs at or below low-end of full-year guidance ranges
  • Reported drilling and completion capital expenditures approximately 10% below prior quarter

Financial Results

Second quarter net income increased 206 percent to $63.5 million, or $0.24 per diluted share, compared to $20.8 million, or $0.09 per diluted share, in the prior year period.

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 Reeves County and remain on track to achieve our full-year production targets with lower unit costs. These strong operational reports were somewhat offset by the impact of the timing of completions in addition to higher than anticipated volumes shut-in by offset frac jobs. With approximately half of our second quarter completions coming online in June, the production impact from these wells was only minimal during the quarter,” said Mark G. Papa, Chairman and Chief Executive Officer.

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.”

Operational Update

Centennial’s operational shift to multi-well pad development in the Delaware Basin has yielded positive results while driving efficiencies and increasing economic returns. In Reeves County, Centennial posted robust results from the Third Bone Spring Sand, Upper Wolfcamp A, Lower Wolfcamp A and Wolfcamp C intervals.

“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 Reeves County acreage with the success of our drilling program. We plan to test the Third Bone Spring Sand in other areas throughout the year and expect this interval to play a larger role in Centennial’s 2019 development program.”

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 $203.2 million compared to $169.6 million in the prior year period. During the second quarter, drilling and completion capital expenditures incurred were approximately $162.7 million. Centennial’s facilities, infrastructure, land and other capital totaled approximately $40.5 million during the quarter.

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 January 2019, increasing to 30,000 Bbls/d in 2020 for the remainder of the agreement.

“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 Permian Basin through the end of 2021.

“We expect natural gas egress will become a significant issue in the Permian Basin by early 2019. These transportation agreements not only provide flow assurance for our natural gas, but also enable Centennial to recognize the economic value of our natural gas and NGL streams,” Papa said.

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 Permian Basin.”

(For a summary table of Centennial’s updated 2018 operational guidance, please see the Appendix to this press release.)

Capital Structure and Liquidity

As of June 30, 2018, Centennial had $43 million in cash on hand and $430 million of long-term debt, inclusive of $30 million outstanding under its revolving credit facility and $400 million of senior unsecured notes. Total liquidity was approximately $612 million, including the impact of letters of credit.

Hedge Position

As of August 6, 2018, Centennial had no fixed-price crude oil hedges. For the period July to December 2018, Centennial’s crude oil basis hedges represent approximately 23% of its expected crude oil production (using the mid-point of guidance) at a weighted average price of $(2.38) per barrel. For 2019, Centennial has 8,030 Bbls/d of crude oil basis hedges in place at a weighted average price of $(6.88) per barrel. During the quarter, Centennial entered into additional natural gas swap and basis hedges effective 2019. (For a summary table of Centennial’s derivative contracts as of August 1, 2018, please see the Appendix to this press release.)

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 U.S. Securities and Exchange Commission (“SEC”) on August 6, 2018.

Conference Call and Webcast

Centennial will host an investor conference call on Tuesday, August 7, 2018 at 8:00 a.m. Mountain (10:00 a.m. Eastern) to discuss second quarter 2018 operating and financial results. Interested parties may join the webcast by visiting Centennial’s website at and clicking on the webcast link or by dialing (800) 789-3525, or (442) 268-1041 for international calls, (Conference ID: 7818579) 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: 7818579) 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

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 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.

Hays Mabry
Director, Investor Relations
(832) 240-3265

Details of our updated 2018 operational and financial guidance are presented below:
  2018 FY Guidance
  2018 FY Guidance
Net average daily production (Boe/d)   55,000     63,500       55,750     64,250  
Oil net average daily production (Bbls/d)   33,500     37,500       33,500     37,500  
Production costs              
Lease operating expenses ($/Boe) $ 3.60   $ 4.20     $ 3.50   $ 4.10  
Gathering, processing and transportation expenses ($/Boe) $ 3.20   $ 3.80     $ 2.85   $ 3.45  
Depreciation, depletion, and amortization ($/Boe) $ 14.00   $ 16.00     $ 14.00   $ 15.50  
Cash general and administrative ($/Boe) $ 2.20   $ 2.70     $ 2.00   $ 2.40  
Non-cash stock-based compensation ($/Boe) $ 0.90   $ 1.20     $ 0.90   $ 1.20  
Severance and ad valorem taxes (% of revenue)   6.0 %   8.0 %     6.0 %   8.0 %
Capital expenditure program ($MM) $ 885   $ 1,050     $ 885   $ 1,050  
Drilling and completion capital expenditure $ 710   $ 820     $ 710   $ 820  
Facilities, infrastructure and other $ 125   $ 160     $ 125   $ 160  
Land $ 50   $ 70     $ 50   $ 70  
Operated drilling program              
Wells spud (gross)   80     95       80     95  
Wells completed (gross)   75     85       75     85  
Average working interest   85 %   90 %     85 %   90 %
Average lateral length (Feet)   7,250     7,750       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 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 June 30, 2018   For the Six Months Ended June 30, 2018
(in thousands) 2018   2017   2018   2017
Adjusted EBITDAX reconciliation to net income:              
Net income attributable to Class A Common Stock $ 63,541     $ 20,762     $ 129,631     $ 30,585  
Net income attributable to noncontrolling interest 3,941     2,436     8,623     3,320  
Interest expense 5,791     707     11,604     1,117  
Income tax expense 19,940     9,069     39,077     9,069  
Depreciation, depletion and amortization 74,946     34,300     140,956     60,460  
Impairment and abandonment expenses 1,784         1,784     (29 )
Non-cash portion of derivative gain (11,534 )   (2,256 )   (19,016 )   (6,412 )
Stock-based compensation expense 4,166     2,558     8,118     4,928  
Exploration expense 1,867     1,289     5,314     2,470  
Transaction costs     457         1,344  
(Gain) loss on sale of oil and natural gas properties 141     (7,191 )   126     (7,357 )
Adjusted EBITDAX $ 164,583     $ 62,131     $ 326,217     $ 99,495  

Centennial Resource Development, Inc.
Operating Highlights

  For the Three Months Ended June 30,   For the Six Months Ended June 30,
  2018   2017   2018   2017
Operating revenues (in thousands):              
Oil sales $ 174,156     $ 70,735     $ 348,997     $ 117,416  
Natural gas sales 13,721     12,133     32,301     20,374  
NGL sales 29,886     8,196     52,363     14,371  
Oil and gas sales $ 217,763     $ 91,064     $ 433,661     $ 152,161  
Average sales prices:              
Oil (per Bbl) $ 61.21     $ 44.57     $ 61.37     $ 46.39  
Effect of derivative settlements on average price (per Bbl) 1.69     0.24     0.89     0.05  
Oil net of hedging (per Bbl) $ 62.90     $ 44.81     $ 62.26     $ 46.44  
Average NYMEX price for oil (per Bbl) $ 68.07     $ 48.32     $ 65.55     $ 50.05  
Oil differential to NYMEX (6.86 )   (3.75 )   (4.18 )   (3.66 )
Natural gas (per Mcf) $ 1.81     $ 2.78     $ 2.12     $ 2.83  
Effect of derivative settlements on average price (per Mcf) 0.05     (0.02 )   0.03     (0.04 )
Natural gas net of hedging (per Mcf) $ 1.86     $ 2.76     $ 2.15     $ 2.79  
Average NYMEX price for natural gas (per Mcf) $ 2.85     $ 3.14     $ 2.96     $ 3.10  
Natural gas differential to NYMEX (1.04 )   $ (0.36 )   $ (0.84 )   (0.27 )
NGL (per Bbl) $ 26.52     $ 21.34     $ 27.99     $ 22.81  
Net production:              
Oil (MBbls) 2,845     1,587     5,687     2,531  
Natural gas (MMcf) 7,572     4,372     15,255     7,205  
NGL (MBbls) 1,127     384     1,871     630  
Total (MBoe) 5,235     2,700     10,101     4,362  
Average daily net production volume:              
Oil (Bbls/d) 31,271     17,435     31,421     13,982  
Natural gas (Mcf/d) 83,205     48,042     84,283     39,807  
NGL (Bbls/d) 12,389     4,222     10,340     3,481  
Total (Boe/d) 57,528     29,664     55,808     24,097  

Centennial Resource Development, Inc.
Operating Expenses

  For the Three Months Ended June 30,   For the Six Months Ended June 30,
  2018   2017   2018   2017
Operating costs (in thousands):              
Lease operating expenses $ 19,182     $ 8,273     $ 35,458     $ 15,551  
Severance and ad valorem taxes 14,208     4,723     28,381     7,910  
Gathering, processing and transportation expenses 15,296     7,403     29,124     12,647  
Operating costs per Boe:              
Lease operating expenses $ 3.66     $ 3.06     $ 3.51     $ 3.57  
Severance and ad valorem taxes 2.71     1.75     2.81     1.81  
Gathering, processing and transportation expenses 2.92     2.74     2.88     2.90  

Centennial Resource Development, Inc.
Condensed Consolidated Statements of Operations
(in thousands, except per share data)

  For the Three Months Ended June 30,   For the Six Months Ended June 30,
  2018   2017   2018   2017
Operating revenues              
Oil and gas sales $ 217,763     $ 91,064     $ 433,661     $ 152,161  
Operating expenses              
Lease operating expenses 19,182     8,273     35,458     15,551  
Severance and ad valorem taxes 14,208     4,723     28,381     7,910  
Gathering, processing and transportation expenses 15,296     7,403     29,124     12,647  
Depreciation, depletion and amortization 74,946     34,300     140,956     60,460  
Impairment and abandonment expenses 1,784         1,784     (29 )
Exploration expense 1,867     1,289     5,314     2,470  
General and administrative expenses 13,809     11,822     28,106     22,706  
Total operating expenses 141,092     67,810     269,123     121,715  
Income from operations 76,671     23,254     164,538     30,446  
Other income (expense)              
Gain (loss) on sale of oil and natural gas properties (141 )   7,191     (126 )   7,357  
Interest expense (5,791 )   (707 )   (11,604 )   (1,117 )
Net gain (loss) on derivative instruments 16,697     2,529     24,540     6,288  
Other income (expense) (14 )       (17 )    
Other income (expense) 10,751     9,013     12,793     12,528  
Income before income taxes 87,422     32,267     177,331     42,974  
Income tax expense (19,940 )   (9,069 )   (39,077 )   (9,069 )
Net income 67,482     23,198     138,254     33,905  
Less: Net income attributable to noncontrolling interest 3,941     2,436     8,623     3,320  
Net income attributable to Class A Common Stock $ 63,541     $ 20,762     $ 129,631     $ 30,585  
Income per share of Class A Common Stock:              
Basic $ 0.24     $ 0.09     $ 0.49     $ 0.14  
Diluted $ 0.24     $ 0.09     $ 0.49     $ 0.14  

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:

  Period   Volume
  Volume (Bbls/d)   Weighted
Crude oil basis swaps July 2018 - September 2018   828,000     9,000     $ (2.38 )
  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 )

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
Fixed Price
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
Natural gas basis swaps July 2018 - December 2018   920,000     5,000     $ (0.43 )
  January 2019 - December 2019   12,775,000   35,000     (1.31 )

  The natural gas swap contracts are settled based on the month’s average daily NYMEX price of Henry Hub Natural Gas or Inside FERC’s West Texas WAHA price of 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.

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