DENVER, Nov. 05, 2018 (GLOBE NEWSWIRE) -- Centennial Resource Development, Inc. (“Centennial” or the “Company”) (NASDAQ: CDEV) today announced financial and operational results for the third quarter 2018.

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 and Lea 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 $39.3 million, or $0.15 per diluted share, compared to $14.4 million, or $0.06 per diluted share, in the prior year period.

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 Permian Basin while maintaining one of the lowest unit cost profiles among Permian E&Ps,” said Mark G. Papa, Chairman and Chief Executive Officer. “Furthermore, we remain on track to achieve our 2018 production targets, while maintaining capital budget discipline. These early efforts should set us up to produce respectable GAAP ROE and ROCEs in 2020, assuming $75 per barrel WTI.”

Operational Update

Centennial reported a number of strong wells across multiple intervals in the Delaware Basin, including some of its best wells to date. In Reeves County, Centennial reported two strong wells from the Upper Wolfcamp A. The Highlander U49H (76% WI), drilled with an effective lateral of approximately 7,300 feet achieved an initial 30-day production rate of 2,339 barrels of oil equivalent per day (“Boe/d”) (79% oil). During this period, the well averaged 254 Bbls/d of oil per 1,000 foot of lateral and produced over 55,000 cumulative barrels of oil. The Doc Gardner A U23H (97% WI) was drilled with an approximate 12,200-foot lateral. The well produced 2,327 Boe/d (82% oil) for the initial 30-day production period.

“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 Reeves County, the Big House D U03H, F L07H and E B03HR (100% WI) were drilled on a three-well pad targeting the Upper Wolfcamp A, Lower Wolfcamp A and Wolfcamp B intervals, respectively. Drilled with an average lateral length of 7,100 feet, the wells achieved initial 30-day production rates of 2,547 Boe/d (56% oil), 1,807 Boe/d (64% oil) and 1,548 Boe/d (65% oil), respectively. On the southern portion of its Reeves County acreage position, the War Eagle A Unit L 49H (100% WI) was drilled with an approximate 7,400 foot effective lateral targeting the Upper Wolfcamp A interval. The well achieved an initial 30-day production rate of 1,858 Boe/d (87% oil), with 219 Bbls/d of oil per 1,000 foot of lateral.

In Lea County, the Pirate State 301H (100% WI) was completed in the First Bone Spring interval with an approximate 4,800 foot effective lateral and delivered an initial 30-day production rate of 1,929 Boe/d (79% oil). On a per lateral foot basis, the well delivered an initial 30-day production rate of 317 Bbls/d of oil per 1,000 foot of lateral. “The Pirate State is likely one of the best First Bone Spring wells drilled in New Mexico and is certainly one of Centennial’s most productive wells on a per lateral foot basis. The well produced over 65,000 barrels of oil during its first 50 days on production,” Papa said. “We continue to see improved well productivity from our Lea County asset since integrating it into our portfolio a little over a year ago.”

The Tour Bus 23 State 505H and 506H (100% WI), drilled from Centennial’s first operated multi-well pad in New Mexico, were completed in the Second Bone Spring interval with an average effective lateral length of 4,550 feet. The wells averaged 1,179 Boe/d (84% oil) for the initial 30-day production period. The two-well pad delivered an average initial 30-day oil production rate of 218 Bbls/d per 1,000 foot of lateral per well. Also in New Mexico, the Cheddar 3BS Federal Com 1H (100% WI), completed in the Third Bone Spring interval with an effective lateral length of approximately 9,600 feet, achieved 1,713 Boe/d (75% oil) for the initial 30-day production period.

Total capital expenditures incurred for the quarter were $273.6 million. During the third quarter, drilling and completion capital expenditures incurred were approximately $222.4 million. Centennial’s facilities, infrastructure, land and other capital totaled approximately $51.2 million during the quarter.

“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 Reeves County, approximately 2,100 net acres were acquired from an undisclosed third-party. The operated acreage position contains an approximate 82% working interest and represents a bolt-on to Centennial’s existing position with strong operated well results. The acquired acreage contains no horizontal development and is predominantly held by production through minimal existing vertical wells.

“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 Doc Gardner wells, which each averaged over 1,800 Bbls/d of oil during their initial 30-days on production.”

In Lea County, Centennial acquired approximately 820 net acres in two separate transactions from undisclosed third-parties for a combined purchase price of $26 million. These transactions increase Centennial’s working interests on its existing acreage and provide the opportunity to drill extended laterals. A portion of the acquired acreage increased Centennial's working interest in its recently drilled Cheddar 3BS Federal Com 1H well, which continues to produce at a strong rate and averaged 1,579 Boe/d (75% oil) for the initial 60-day period.

"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 September 30, 2018, Centennial had $59 million in cash on hand and $540 million of long-term debt, inclusive of $140 million outstanding under its revolving credit facility and $400 million of senior unsecured notes. Subsequent to quarter-end, Centennial completed its fall borrowing base redetermination process. The borrowing base increased by 25% to $1,000 million from $800 million previously, and Centennial increased its elected commitments to $800 million from $600 million. As of the date of the redetermination, after giving effect to the increase in elected commitments, Centennial's pro forma total liquidity was $718 million, based on its balance sheet position and letters of credit outstanding as of September 30, 2018.

Hedge Position

As of November 5, 2018, Centennial's crude oil hedge portfolio consisted only of basis swaps. For the period October to December 2018, Centennial’s crude oil basis swaps represent approximately 21% 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 swaps in place at a weighted average price of $(6.88) per barrel. In addition, Centennial has in place natural gas swaps and basis hedges for 2019. (For a summary table of Centennial’s derivative contracts as of September 30, 2018, please see the Appendix to this press release.)

“Through previously announced firm sales agreements, approximately half of Centennial’s 2019 expected crude oil volumes will receive Gulf Coast-linked pricing, protecting us from potential Mid-Cush basis volatility,” said Papa. “Furthermore, Centennial is one of the few mid-cap E&Ps to secure egress out of the Permian Basin for the majority of its expected crude oil and essentially all of its residue natural gas volumes.”

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 September 30, 2018, which is expected be filed with the U.S. Securities and Exchange Commission (“SEC”) on November 5, 2018.

Conference Call and Webcast

Centennial will host an investor conference call on Tuesday, November 6, 2018 at 8:00 a.m. Mountain (10:00 a.m. Eastern) to discuss third 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: 2186036) 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: 2186036) 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;
  
• 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.

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

Centennial Resource Development, Inc.
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.

Centennial Resource Development, Inc.
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

Centennial Resource Development, Inc.
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.