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Centennial Resource Development Announces Second Quarter 2019 Financial and Operational Results and Increases 2019 Production Targets While Lowering Cost Guidance


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Source: Centennial Resource Development

DENVER, Aug. 05, 2019 (GLOBE NEWSWIRE) — Centennial Resource Development, Inc. (“Centennial” or the “Company”) (NASDAQ: CDEV) today announced financial and operational results for the second quarter 2019.

Financial and Operational Highlights:

  • Reported 38 percent increase in daily oil and 32 percent increase in equivalent production volumes year-over-year
  • Increased 2019 oil and total company production guidance by 5 percent and 8 percent, respectively
  • Generated strong operational efficiencies that drove drilling and completion activity ahead of schedule
  • Plan to reduce operated rig count from six to five in September 2019
  • Reduced full-year unit cost guidance as a result of year-to-date cost discipline
  • Delivered best oil producing well to date and four of the top five wells in Company history
  • Maintained conservative balance sheet and strong liquidity

Financial Results

For the second quarter 2019, Centennial reported net income of $17.9 million, or $0.07 per diluted share, compared to $63.5 million, or $0.24 per diluted share, in the prior year period.

Average daily crude oil production increased 38 percent to 43,105 barrels of oil per day (“Bbls/d”) compared to the prior year period. Average total equivalent production increased 32 percent in the second quarter and 33 percent for the first six months of 2019 compared to prior year periods.

“Centennial delivered a solid second quarter. Better than expected individual well results coupled with increased efficiencies have allowed us to raise our production targets for the year, while reducing our full-year rig guidance and maintaining our initial capital expenditure guidance,” said Mark G. Papa, Chairman and Chief Executive Officer. “Based on six months of strong results, Centennial has increased its previous 2019 oil growth target from 12 percent to 18 percent and total company growth target from 8 percent to 17 percent. Additionally, as a result of our cost control efforts, we are lowering our unit cost guidance for the full-year.”

Operational Update

Centennial reported a number of strong wells across multiple intervals in the Delaware Basin, including some of its best wells to date from both New Mexico and Texas. In Lea County, New Mexico, Centennial reported its two best wells completed in Company history. Drilled in the area where Centennial reported success earlier in the year from the Second Bone Spring, the Chorizo 12 State Com 601H (100% WI) was completed in the Third Bone Spring interval with an approximate 9,800-foot effective lateral. The well achieved an initial 30-day production rate of 2,961 barrels of oil equivalent per day (“Boe/d”) (86% oil) and 260 Bbls/d of oil per 1,000 foot of lateral.

“The Chorizo represents Centennial’s best well drilled to date and has produced over 110,000 barrels of oil during its first sixty days on production. The well exceeded our type curve for the area and gives us further confidence as we continue to push the Third Bone Spring north on our acreage,” Papa said.

Drilled south of the Chorizo well, the three Duck Hunt wells were vertically stacked in the First, Second and Third Bone Spring intervals. The Duck Hunt 1 State Com 301H, 501H and 601H (average 58% WI) wells were drilled with an approximate lateral length of 6,900 feet. The wells averaged 2,207 Boe/d per well (83% oil), or 266 Bbls/d of oil per 1,000 foot of lateral for the initial 30-day production period.

“Our recent results in Lea County have been outstanding. The Duck Hunt wells were our first test to directly stack the various Bone Spring Sands. We saw strong well performance from each interval,” Papa said. “We plan to develop the majority of wells in this area on multi-well pads with extended laterals, further increasing operational efficiencies and economic returns.”

In Reeves County, Texas, Centennial reported outstanding results from a co-development test of the Third Bone Spring Sand and Upper Wolfcamp A intervals. On the border of Reeves and Ward Counties, the Red Rock T34H, T17H, U30H and U13H (average 77% WI) wells were drilled using a stacked, staggered pattern with approximate 9,500-foot laterals. Completed in the Third Bone Spring Sand, the Red Rock T34H and T17H achieved an average initial 30-day production rate of 2,689 Boe/d per well (70% oil), or 182 Bbls/d of oil per 1,000 foot of lateral. Targeting the Upper Wolfcamp A, the Red Rock U30H and U13H averaged 2,390 Boe/d per well (74% oil) for the initial 30-day production period, or 201 Bbls/d of oil per 1,000 foot of lateral.

“The Red Rocks represent our first four-well test co-developing the Third Bone Spring Sand and Upper Wolfcamp A intervals. The positive analogous production results between the two zones are key and further underscore the quality of our Third Bone Spring Sand inventory in Reeves County,” Papa said. “We now have multiple successful tests pairing the Third Bone Spring Sand and Upper Wolfcamp A intervals, proving the viability of co-developing our two highest rate-of-return intervals in Reeves County.”

Total capital expenditures incurred for the quarter were $237.4 million. During the second quarter, drilling and completion capital expenditures incurred were $179.8 million. Centennial’s facilities, infrastructure and other totaled $44.6 million for the quarter, with an additional $13.0 million spent on land.

“Our operations team has increased efficiencies through reduced drilling days and shortened completion times. As a result, we completed twenty gross wells during the quarter, ahead of our original expectations,” said Papa.

Updated 2019 Operational Plans and Targets

Centennial plans to reduce its operated rig count from six to five in September 2019, maintaining a five-rig drilling program for the remainder of the year. Centennial expects the number of spud and completed gross wells to be near the high-end of its initial 2019 guidance ranges. The Company’s full-year capital budget remains unchanged. Centennial also lowered its full-year 2019 guidance ranges for G&A, GP&T and DD&A on a per unit basis. (For a summary table of Centennial’s updated 2019 operational guidance, please see the Appendix to this press release.)

“Operational efficiencies gained to date will allow us to spud and complete more wells during the year while operating fewer rigs than previously expected,” said Papa. “The efforts by our operations team have resulted in lower drilling and completion costs and reduced drilling days, providing us the confidence to maintain our full-year total capital expenditure guidance.”

Capital Structure and Liquidity

As of June 30, 2019, Centennial had $28 million in cash on hand, with zero borrowings under its revolving credit facility and $900 million of long-term debt. Centennial’s total liquidity was $828 million, based on $800 million of elected commitments under its revolving credit facility and letters of credit outstanding as of June 30, 2019.

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, 2019, which is expected be filed with the U.S. Securities and Exchange Commission (“SEC”) on August 5, 2019.

Conference Call and Webcast

Centennial will host an investor conference call on Tuesday, August 6, 2019 at 9:00 a.m. Mountain (11:00 a.m. Eastern) to discuss second quarter 2019 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: 1857979 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: 1857979 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 exclusively 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,” “may”, “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” “goal”, “plan”, “target” 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;
  • cost of developing our properties;
  • our anticipated rate of return;
  • 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, 2018, 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
[email protected]

Details of our updated 2019 operational and financial guidance are presented below:

2019 FY Guidance
(Prior)
2019 FY Guidance
(Updated)
Net average daily production (Boe/d) 61,500 70,500 68,000 75,000
Oil net average daily production (Bbls/d) 36,500 41,500 39,500 42,500
Production costs
Lease operating expenses ($/Boe) $4.35 $4.95 $4.35 $4.95
Gathering, processing and transportation expenses ($/Boe) $2.75 $3.25 $2.50 $2.80
Depreciation, depletion, and amortization ($/Boe) $15.50 $17.50 $15.25 $17.25
Cash general and administrative ($/Boe) $2.25 $2.75 $1.90 $2.30
Non-cash stock-based compensation ($/Boe) $1.00 $1.20 $0.90 $1.10
Severance and ad valorem taxes (% of revenue) 5.5% 7.5% 5.5% 7.5%
Capital expenditure program ($MM) $765 $925 $765 $925
Drilling and completion capital expenditure $625 $725 $625 $725
Facilities, infrastructure and other $120 $160 $120 $160
Land $20 $40 $20 $40
Operated drilling program
Wells spud (gross) 70 80 70 80
Wells completed (gross) 65 75 65 75
Average working interest 80% 90% 80% 90%
Average lateral length (Feet) 7,250 7,750 7,250 7,750

Centennial Resource Development, Inc.

Operating Highlights

For the Three Months Ended June 30, Six Months Ended June 30, 2019
2019       2018       2019       2018
Net revenues (in thousands):
Oil sales $ 214,305 $ 174,156 $ 389,859 $ 348,997
Natural gas sales 8,088 13,721 20,585 32,301
NGL sales 21,846 29,886 48,364 52,363
Oil and gas sales $ 244,239 $ 217,763 $ 458,808 $ 433,661
Average sales prices:
Oil (per Bbl) $ 54.63 $ 61.21 $ 51.51 $ 61.37
Effect of derivative settlements on average price (per Bbl) (0.18 ) 1.69 (0.20 ) 0.89
Oil net of hedging (per Bbl) $ 54.45 $ 62.90 $ 51.31 $ 62.26
Average NYMEX price for oil (per Bbl) $ 59.81 $ 68.07 $ 57.36 $ 65.55
Oil differential from NYMEX (5.18 ) (6.86 ) (5.85 ) (4.18 )
Natural gas (per Mcf) $ 0.81 $ 1.81 $ 1.09 $ 2.12
Effect of derivative settlements on average price (per Mcf) 0.71 0.05 0.40 0.03
Natural gas net of hedging (per Mcf) $ 1.52 $ 1.86 $ 1.49 $ 2.15
Average NYMEX price for natural gas (per Mcf) $ 2.51 $ 2.85 $ 2.69 $ 2.96
Natural gas differential from NYMEX (1.70 ) (1.04 ) (1.60 ) (0.84 )
NGL (per Bbl) $ 16.24 $ 26.52 $ 17.99 $ 27.99
Net production:
Oil (MBbls) 3,922 2,845 7,568 5,687
Natural gas (MMcf) 9,954 7,572 18,918 15,255
NGL (MBbls) 1,346 1,127 2,689 1,871
Total (MBoe)(1) 6,927 5,235 13,410 10,101
Average daily net production volume:
Oil (Bbls/d) 43,105 31,271 41,814 31,421
Natural gas (Mcf/d) 109,392 83,205 104,521 84,283
NGL (Bbls/d) 14,785 12,389 14,856 10,340
Total (Boe/d)(1) 76,122 57,528 74,089 55,808

(1)     Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

Centennial Resource Development, Inc.

Operating Expenses

For the Three Months Ended June 30, Six Months Ended June 30,
2019 2018 2019 2018
Operating costs (in thousands):
Lease operating expenses $ 34,885 $ 19,182 $ 64,747 $ 35,458
Severance and ad valorem taxes 17,186 14,208 33,306 28,381
Gathering, processing and transportation expenses 16,243 15,296 31,267 29,124
Operating costs per Boe:
Lease operating expenses $ 5.04 $ 3.66 $ 4.83 $ 3.51
Severance and ad valorem taxes 2.48 2.71 2.48 2.81
Gathering, processing and transportation expenses 2.34 2.92 2.33 2.88

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

For the Three Months Ended June 30,   For the Six Months Ended June 30,
  2019       2018       2019       2018  
Operating revenues
Oil and gas sales $ 244,239 $ 217,763 $ 458,808 $ 433,661
Operating expenses
Lease operating expenses 34,885 19,182 64,747 35,458
Severance and ad valorem taxes 17,186 14,208 33,306 28,381
Gathering, processing and transportation expenses 16,243 15,296 31,267 29,124
Depreciation, depletion and amortization 112,114 74,946 208,672 140,956
Impairment and abandonment expense 4,418 1,784 35,682 1,784
Exploration expense 3,861 1,867 6,377 5,314
General and administrative expenses 18,435 13,809 36,553 28,106
Total operating expenses 207,142 141,092 416,604 269,123
Net gain (loss) on sale of long-lived assets 9 (141 ) 7 (126 )
Income from operations 37,106 76,530 42,211 164,412
Other income (expense)
Interest expense (14,437 ) (5,791 ) (24,597 ) (11,604 )
Net gain (loss) on derivative instruments 2,128 16,697 (3,743 ) 24,540
Other income (expense) 133 (14 ) 259 (17 )
Total other income (expense) (12,176 ) 10,892 (28,081 ) 12,919
Income before income taxes 24,930 87,422 14,130 177,331
Income tax expense (5,928 ) (19,940 ) (3,665 ) (39,077 )
Net income 19,002 67,482 10,465 138,254
Less: Net income attributable to noncontrolling interest 1,125 3,941 700 8,623
Net income attributable to Class A Common Stock $ 17,877 $ 63,541 $ 9,765 $ 129,631
Income per share of Class A Common Stock:
Basic $ 0.07 $ 0.24 $ 0.04 $ 0.49
Diluted $ 0.07 $ 0.24 $ 0.04 $ 0.49

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 and gains and losses from the sale of assets. 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,   For the Six Months Ended June 30,
(in thousands)   2019       2018       2019       2018  
Adjusted EBITDAX reconciliation to net income:                              
Net income attributable to Class A Common Stock $ 17,877 $ 63,541 $ 9,765 $ 129,631
Net income attributable to noncontrolling interest 1,125 3,941 700 8,623
Interest expense 14,437 5,791 24,597 11,604
Income tax expense 5,928 19,940 3,665 39,077
Depreciation, depletion and amortization 112,114 74,946 208,672 140,956
Impairment and abandonment expenses 4,418 1,784 35,682 1,784
Non-cash derivative loss (gain) 4,260 (11,534 ) 9,754 (19,016 )
Stock-based compensation expense 6,076 4,166 11,959 8,118
Exploration expense 3,861 1,867 6,377 5,314
(Gain) loss on sale of long-lived assets (9 ) 141 (7 ) 126
Adjusted EBITDAX $ 170,087 $ 164,583 $ 311,164 $ 326,217

The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of June 30, 2019:

Period

Volume
(Bbls)

Volume
(Bbls/d)

Weighted
Average
Differential
($/Bbl)
(1)
Crude oil basis swaps July 2019 – September 2019 1,380,000 15,000 $ (9.03 )
October 2019 – December 2019 920,000 10,000 (4.24 )

(1) These 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 each applicable settlement period.

Period


Volume
(MMBtu)

Volume
(MMBtu/d)
Weighted Average
Fixed Price
($/MMBtu)(1)
Natural Gas Swaps – Henry Hub July 2019 – December 2019 5,520,000 30,000 $ 2.78
Natural Gas Swaps – West Texas WAHA July 2019 – December 2019 2,760,000 15,000 1.61

Period


Volume
(MMBtu)

Volume
(MMBtu/d)
Weighted Average
Differential
($/MMBtu)(2)
Natural gas basis swaps July 2019 – December 2019 6,440,000 35,000 $ (1.31 )

(1) These 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 applicable, as of the specified settlement date.

(2) These 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 each applicable settlement period.



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