Centennial Resource Development Announces Third Quarter 2019 Financial and Operational Results and Increases 2019 Production Targets

DENVER, November 4, 2019 (GLOBE NEWSWIRE) - Centennial Resource Development, Inc. (“Centennial” or the “Company”) (NASDAQ: CDEV) today announced financial and operational results for the third quarter 2019.

Financial and Operational Highlights:

• Reported 17 percent increase in daily oil and 21 percent increase in total equivalent production volumes year-over-year

• Increased 2019 oil and total company production growth targets to 22 percent, while maintaining original capital budget

• Reduced drilling and completion capital expenditures for the fourth consecutive quarter

• Continued to drive strong operational efficiencies

• Generated solid well results including multiple Third Bone Spring Sand and Upper Wolfcamp A

co-development projects in Texas

• Reduced operated rig count from six to five in September 2019

• Reaffirmed $1.2 billion borrowing base

Financial Results

For the third quarter 2019, Centennial reported a net loss of $3.6 million, or $0.01 per diluted share, compared to net income of $39.3 million, or $0.15 per diluted share, in the prior year period.

Average daily crude oil production increased 17 percent to 42,079 barrels of oil per day (“Bbls/d”) compared to the prior year period. Average total equivalent production increased 21 percent compared to the prior year period.

“Our team continues to do an outstanding job driving operational efficiencies, resulting in reduced cycle times and well costs. Year-to-date, we have meaningfully reduced both drilling and completion costs,” said Mark G. Papa, Chairman and Chief Executive Officer. “These cost reductions, combined with continued, above average well performance have allowed us for the second consecutive quarter to increase our full-year production targets without altering our original capital expenditure budget.”

Operational Update

Centennial has continued to optimize its Delaware Basin acreage position with multi-well pad co-development to drill extended laterals. During the quarter, Centennial reported strong well results from multiple intervals in both Texas and New Mexico. On the southeast portion of the Company’s Toyah acreage in Reeves County, Texas, the Barracuda unit (average 78% WI) was drilled with approximate 10,300-foot laterals and included one Third Bone Spring Sand well and two Upper Wolfcamp A wells. The wells averaged 1,918 barrels of oil equivalent per day (“Boe/d”), or 1,583 Bbls/d of oil, for the initial 30-day production period.

“The Barracuda wells represent another successful stacked, staggered test pairing the Third Bone Spring Sand and Upper Wolfcamp A intervals. The three-well pad generated robust results, producing over 215,000 barrels of oil during its first sixty days online,” Papa said.

Located in the southwest portion of Centennial’s acreage, the three-well Doc Hudson pad (97% WI) consisted of two wells targeting the Upper Wolfcamp A interval and one well targeting the Third Bone Spring Sand interval. Drilled with an average lateral length of 5,700 feet, the wells achieved an average initial 30-day production rate of 1,562 Boe/d (79% oil), with 216 Bbls/d of oil per 1,000 foot of lateral per well.

“The Barracuda and Doc Hudson wells represent our southernmost wells drilled to-date targeting the Third Bone Spring Sand. These strong results provide us with even greater confidence that this high rate-of-return zone extends across the majority of our Reeves County position,” Papa said.

In Lea County, New Mexico, the two-well Asadero State Com pad (87% WI) was completed in the Second Bone Spring Sand with an average effective lateral length of 7,100 feet. The wells averaged 1,298 Boe/d (89% oil) for the initial 30-day production period, or 163 Bbls/d of oil per 1,000 foot of lateral per well.

“We are hitting our stride in Lea County, having transitioned to larger scale, extended lateral development across multiple horizons,” Papa said. “To further reduce costs, Centennial recently implemented a water recycling program in New Mexico. We expect to utilize this treatment process on a larger number of wells in the future.”

Total capital expenditures incurred for the quarter were $212.1 million. During the third quarter, drilling and completion capital expenditures incurred were $160.5 million. Centennial’s facilities, infrastructure and other totaled $40.6 million for the quarter, with an additional $11.0 million spent on land.

“During the quarter, we reduced our spud to rig release cycle times by twenty-six percent compared to last year, while increasing our completed stages per day by twenty-nine percent,” Papa said. “These operational efficiencies, in addition to service cost deflation, have resulted in lower drilling and completion costs. We will work to further drive down costs and increase efficiencies as we move into next year.”

Updated 2019 Operational Plans and Targets

Based on recent operational results, Centennial increased its 2019 oil growth target from 18% to 22% and total company growth target from 17% to 22%. The Company increased the number of completed wells expected this year, as a result of efficiencies gained to date. Centennial’s full-year capital budget remains unchanged.The Company also lowered its full-year 2019 guidance ranges for Cash G&A and DD&A, while increasing LOE on a per unit basis. (For a summary table of Centennial’s updated 2019 operational guidance, please see the Appendix to this press release.)

Capital Structure and Liquidity

Upon completion of its semi-annual borrowing base redetermination process, Centennial’s borrowing base remained unchanged at $1.2 billion. As of September 30, 2019, Centennial had $11 million in cash on hand, $120 million of borrowings under its revolving credit facility and $900 million of senior unsecured notes. This resulted in debt-to-book capitalization (GAAP) and net debt-to-book capitalization (non-GAAP) ratios of 24%. Centennial’s total liquidity was $690 million, based on $800 million of elected commitments under its revolving credit facility and letters of credit outstanding as of September 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 September 30, 2019, which is expected be filed with the U.S. Securities and Exchange Commission (“SEC”) on November 4, 2019.

Conference Call and Webcast

Centennial will host an investor conference call on Tuesday, November 5, 2019 at 9:00 a.m. Mountain (11:00 a.m. Eastern) to discuss third 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: 3066178) 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: 3066178) 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,” "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

ir@cdevinc.com

SOURCE Centennial Resource Development, Inc.

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)	68,000	—	75,000	72,250	—	77,250
Oil net average daily production (Bbls/d)	39,500	—	42,500	41,250	—	43,250
Production costs
Lease operating expenses ($/Boe)	$4.35	—	$4.95	$5.00	—	$5.60
Gathering, processing and transportation expenses ($/Boe)	$2.50	—	$2.80	$2.50	—	$2.80
Depreciation, depletion, and amortization ($/Boe)	$15.25	—	$17.25	$15.25	—	$16.35
Cash general and administrative ($/Boe)	$1.90	—	$2.30	$1.80	—	$2.20
Non-cash stock-based compensation ($/Boe)	$0.90	—	$1.10	$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	70	—	80
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 September 30,						For the Nine Months Ended September 30, 2019
	2019			2018			2019			2018
Net revenues (in thousands):
Oil sales	$	200,196		$	184,510		$	590,055		$	533,507
Natural gas sales	11,070			14,311			31,655			46,612
NGL sales	17,864			36,059			66,228			88,422
Oil and gas sales	$	229,130		$	234,880		$	687,938		$	668,541
Average sales prices:
Oil (per Bbl)	$	51.71		$	55.68		$	51.58		$	59.27
Effect of derivative settlements on average price (per Bbl)	(3.00		)	2.56			(1.15		)	1.50
Oil net of hedging (per Bbl)	$	48.71		$	58.24		$	50.43		$	60.77
Average NYMEX price for oil (per Bbl)	$	56.45		$	69.50		$	57.05		$	66.75
Oil differential from NYMEX	(4.74		)	(13.82		)	(5.47		)	(7.48		)
Natural gas (per Mcf)	$	0.96		$	1.83		$	1.04		$	2.02
Effect of derivative settlements on average price (per Mcf)	0.30			0.05			0.36			0.04
Natural gas net of hedging (per Mcf)	$	1.26		$	1.88		$	1.40		$	2.06
Average NYMEX price for natural gas (per Mcf)	$	2.33		$	2.93		$	2.57		$	2.95
Natural gas differential from NYMEX	(1.37		)	(1.10		)	(1.53		)	(0.93		)
NGL (per Bbl)	$	14.47		$	30.85		$	16.88		$	29.08
Net production:
Oil (MBbls)	3,872			3,314			11,440			9,002
Natural gas (MMcf)	11,491			7,837			30,409			23,092
NGL (MBbls)	1,234			1,169			3,923			3,040
Total (MBoe)(1)	7,021			5,790			20,431			15,891
Average daily net production:
Oil (Bbls/d)	42,079			36,027			41,903			32,973
Natural gas (Mcf/d)	124,896			85,180			111,388			84,585
NGL (Bbls/d)	13,417			12,706			14,371			11,137
Total (Boe/d)(1)	76,312			62,930			74,839			58,208

⁽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,
	2019		2018		2019		2018
Operating costs (in thousands):
Lease operating expenses	$	42,330	$	23,706	$	107,077	$	59,164
Severance and ad valorem taxes	12,213		14,410		45,519		42,791
Gathering, processing and transportation expenses	20,853		16,090		52,120		45,214
Operating costs per Boe:
Lease operating expenses	$	6.03	$	4.09	$	5.24	$	3.72
Severance and ad valorem taxes	1.74		2.49		2.23		2.69
Gathering, processing and transportation expenses	2.97		2.78		2.55		2.85

Centennial Resource Development, Inc.

Consolidated Statements of Operations (unaudited)

(in thousands, except per share data)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2019			2018			2019			2018
Operating revenues
Oil and gas sales	$	229,130		$	234,880		$	687,938		$	668,541
Operating expenses
Lease operating expenses	42,330			23,706			107,077			59,164
Severance and ad valorem taxes	12,213			14,410			45,519			42,791
Gathering, processing and transportation expenses	20,853			16,090			52,120			45,214
Depreciation, depletion and amortization	112,720			83,423			321,392			224,379
Impairment and abandonment expense	6,745			8,612			42,427			10,396
Exploration expense	2,869			2,712			9,246			8,026
General and administrative expenses	20,036			16,561			56,589			44,667
Total operating expenses	217,766			165,514			634,370			434,637
Net gain (loss) on sale of long-lived assets	(22		)	52			(15		)	(74		)
Income from operations	11,342			69,418			53,553			233,830
Other income (expense)
Interest expense	(15,246		)	(6,534		)	(39,843		)	(18,138		)
Net gain (loss) on derivative instruments	1,522			(9,571		)	(2,221		)	14,969
Other income (expense)	62			13			321			(4		)
Total other income (expense)	(13,662		)	(16,092		)	(41,743		)	(3,173		)
Income (loss) before income taxes	(2,320		)	53,326			11,810			230,657
Income tax expense	(1,393		)	(11,652		)	(5,058		)	(50,729		)
Net income (loss)	(3,713		)	41,674			6,752			179,928
Less: Net income (loss) attributable to noncontrolling interest	(128		)	2,386			572			11,009
Net income (loss) attributable to Class A Common Stock	$	(3,585	)	$	39,288		$	6,180		$	168,919
Income (loss) per share of Class A Common Stock:
Basic	$	(0.01	)	$	0.15		$	0.02		$	0.64
Diluted	$	(0.01	)	$	0.15		$	0.02		$	0.63

Non-GAAP Financial Measure

In addition to disclosing financial results calculated in accordance with U.S. generally accepted accounting principles (“GAAP”), our earnings release contains non-GAAP financial measures as described below.

Adjusted EBITDAX

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, stock-based compensation and gains and losses from the sale of assets. Adjusted EBITDAX is not a measure of net income as determined by 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)	2019			2018			2019		2018
Adjusted EBITDAX reconciliation to net income:
Net income (loss) attributable to Class A Common Stock	$	(3,585	)	$	39,288		$	6,180	$	168,919
Net income (loss) attributable to noncontrolling interest	(128		)	2,386			572		11,009
Interest expense	15,246			6,534			39,843		18,138
Income tax expense (benefit)	1,393			11,652			5,058		50,729
Depreciation, depletion and amortization	112,720			83,423			321,392		224,379
Impairment and abandonment expenses	6,745			8,612			42,427		10,396
Non-cash derivative (gain) loss	(9,740		)	18,437			14		(579		)
Stock-based compensation expense	7,357			4,888			19,317		13,006
Exploration expense	2,869			2,712			9,246		8,026
(Gain) loss on sale of long-lived assets	22			(52		)	15		74
Adjusted EBITDAX	$	132,899		$	177,880		$	444,064	$	504,097

Net Debt / Book Capitalization Ratio

Net debt / book capitalization ratio 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 net debt / book capitalization ratio as net debt divided by book capitalization (non-GAAP). Net debt is defined as long-term debt, net, plus unamortized debt discount and debt issuance costs on Senior Notes minus cash and cash equivalents. Book capitalization (non-GAAP) is defined as long-term debt, net, plus unamortized debt discount and debt issuance costs on Senior Notes plus total equity. Net debt / book capitalization ratio is not a measure calculated in accordance with GAAP.

Our management believes net debt / book capitalization ratio is useful as it allows them to more effectively evaluate our capital structure and liquidity and compare the results against our peers. Net debt / book capitalization ratio should not be considered as an alternative to, or more meaningful than, debt / book capitalization (GAAP) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Our computations of net debt / book capital ratio may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of our net debt / book capitalization ratio to our most directly comparable financial measure calculated and presented in accordance with GAAP:

(in thousands)	September 30, 2019			December 31, 2018
Total equity	$	3,253,814		$	3,243,869
Long-term debt, net	1,001,867			691,630
Unamortized debt discount and debt issuance costs on Senior Notes	18,133			8,370
Long-term debt	1,020,000			700,000
Less: cash and cash equivalents	(10,933		)	(18,157		)
Net debt (Non-GAAP)	1,009,067			681,843
Book capitalization (GAAP)(1)	$	4,255,681		$	3,935,499
Book capitalization (non-GAAP)(2)	$	4,273,814		$	3,943,869
Debt / book capitalization (GAAP)(3)	24		%	18		%
Net debt / book capitalization (non-GAAP)(4)	24		%	17		%

⁽¹⁾  Book capitalization (GAAP) is calculated as total equity plus long-term debt, net.

⁽²⁾ Book capitalization (non-GAAP) is calculated as total equity plus long-term debt.

⁽³⁾  Debt / book capitalization (GAAP) is calculated as long-term debt, net divided by book capitalization (GAAP).

⁽⁴⁾ Net debt / book capitalization (non-GAAP) is calculated as net debt divided by book capitalization (non-GAAP).

The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of September 30, 2019 and additional contracts entered into through October 31, 2019:

	Period	Volume (Bbls)	Volume (Bbls/d)	Weighted Average Differential ($/Bbl)(1)
Crude oil basis swaps	October 2019 - December 2019	920,000	10,000	$	(4.24	)
	January 2020 - March 2020	273,000	3,000	0.67
	April 2020 - June 2020	273,000	3,000	0.67
	July 2020 - September 2020	276,000	3,000	0.67
	October 2020 - December 2020	276,000	3,000	0.67

⁽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	October 2019 - December 2019	2,760,000	30,000	$	2.78
Natural Gas Swaps - West Texas WAHA	October 2019 - December 2019	1,380,000	15,000	1.61
	Period	Volume (MMBtu)	Volume (MMBtu/d)	Weighted Average Differential ($/MMBtu)(2)
Natural gas basis swaps	October 2019 - December 2019	3,220,000	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.