Exhibit

“Centennial’s well results from the Wolfcamp continue to outperform our original well forecasts and are responding positively to our latest completion designs. This allowed us once again to increase our full-year production targets while lowering DD&A,” said Mark G. Papa, Chairman and Chief Executive Officer. “Based on results year-to-date, we anticipate achieving an attractive full-cycle internal rate of return on our entire 2017 capital program, including indirect costs such as general and administrative expenses and organic leasing.”

Centennial reported a number of strong wells across multiple intervals in the Delaware Basin, including its best well to date. In the Southern Delaware Basin, Centennial completed the Matador 6-33 3H (72% WI) in the Upper Wolfcamp A, which achieved an initial 30-day production rate of 2,154 barrels of oil equivalent per day (“Boe/d”) (74% oil). The well had an effective lateral of approximately 4,300 feet with an initial 30-day production rate of 375 barrels of oil per day (“Bbls/d”) per 1,000 foot of lateral. Also in the Upper Wolfcamp A, the C.H. Knight 6H (95% WI) was drilled with an approximate 4,400 foot effective lateral and produced 1,620 Boe/d (73% oil) for the initial 30-day production period. On a per lateral foot basis, the well delivered an initial 30-day production rate of 271 Bbls/d per 1,000 foot of lateral.

“The Matador represents our most productive well to date on a per lateral foot basis and has produced over 100,000 barrels of oil during its first ninety days on production,” Papa said. “Our technical team is now in the late stages of frac optimization, including the effective implementation of proppant intensity and refining the number of clusters per stage. While only public for one year, Centennial’s technical team is the best among our mid-cap E&P peers as demonstrated by recent results.”

During the quarter, Centennial executed a long-term proppant supply agreement with a local sand provider. The Eady 4 59-60 1H and 2H were the first wells completed using the new in-basin proppant. Drilled on Centennial’s Silverback acreage in Reeves County, the wells were drilled using a stacked, staggered pattern in the Upper and Lower Wolfcamp A, respectively, with an average 6,800 foot effective lateral. The Eady A 4 59-60 1H (97% WI) achieved an initial 30-day production rate of 2,166 Boe/d (56% oil), with 1,222 Bbls/d of oil. The Eady B 4 59-60 2H (97% WI) achieved an initial 30-day production rate of 1,915 Boe/d (60% oil), with 1,142 Bbls/d of oil.

“The use of in-basin proppant will provide Centennial with meaningful cost and efficiency savings in the future,” Papa said. “With our current completion design, we estimate well cost savings of five to ten percent per well with this sand. The ability to source sand locally will also help minimize transportation and logistical delivery matters.”

Also in Reeves County, the Brooks 3H and 4H were completed on a two-well pad targeting the Lower and Upper Wolfcamp A intervals, respectively. The Brooks 3H (100% WI) was drilled with an approximate 9,600 foot effective lateral and produced 1,554 Boe/d (88% oil) for the initial 30-day production period. The Brooks 4H (100% WI) was drilled with an approximate 8,600 foot effective lateral and reported an initial 30-day production rate of 1,598 Boe/d (84% oil). The Roadrunner 5H (94% WI), completed in the Upper Wolfcamp A had an effective lateral length of approximate 9,500 feet and achieved 1,835 Boe/d (83% oil) for the initial 30-day production period.

“Consistent with our strategy of driving efficiencies and increasing economic returns, we shifted our drilling program from individual wells to pad drilling with longer laterals and have seen early successful results. During the quarter, the average completed lateral length increased approximately 20 percent from the previous quarter,” Papa said. “By combining the efficiencies of completion timing with pad drilling, Centennial completed thirteen wells during the third quarter, and we expect to complete approximately twenty-five wells in the fourth quarter of this year.”

Centennial also reported its first well from Lea County, New Mexico, in the heart of the Northern Delaware Basin. Targeting the 2^nd Bone Spring Sand, the Romeo 1H was drilled by the previous operator and completed by Centennial’s technical team. The well had an effective lateral of approximately 4,200 feet and delivered an initial 30-day production rate of 1,316 Boe/d (84% oil), with 1,105 Bbls/d of oil.

“In early September, we shifted one of our six operated rigs from Reeves County to our recently acquired GMT acreage in Lea County,” Papa said. “We are excited about our first well result which highlights the quality of this acreage and plan to test additional zones in Lea County.”

Centennial plans to operate a six rig drilling program for the remainder of the year. Plans are to further delineate its acreage across the recently acquired GMT and Silverback positions. In addition, Centennial will evaluate the potential for downspacing and test additional zones across its acreage blocks.

Based on recent operational results, Centennial increased its 2017 total company production growth target from 250% to 256% and raised its total oil production growth target from 213% to 216%. This represents an increase of 17% and 16% compared to Centennial’s total company and oil production guidance, respectively, provided subsequent to the GMT acquisition announcement in May 2017. Additionally, Centennial lowered its full-year 2017 guidance ranges for DD&A and severance and ad valorem taxes. Centennial also narrowed its full-year 2017 guidance ranges for G&A and operated wells spud. (For a summary table of Centennial’s updated 2017 operational guidance, please see the Appendix to this press release.)

“Our operations team has maintained the efficiencies gained during the first half of the year even in light of the current tight oilfield services market in the Permian Basin,” Papa said. “We were fortunate not to experience any material downtime or production impacts associated with Hurricane Harvey.”

As of September 30, 2017, Centennial had $165 million outstanding under its revolving credit facility and approximately $3 million in cash on hand. Subsequent to quarter end, Centennial completed its borrowing base redetermination process which resulted in a $225 million increase from $350 million to $575 million. As of September 30, 2017, after giving effect to credit agreement amendments associated with the redetermination, total liquidity would have been approximately $412 million.

“We are bullish on the macro crude oil environment and believe that oil prices are poised to trend higher as a result of continued tepid U.S. production growth, robust global demand and declining global inventories. Centennial is well positioned to benefit from any future increase in oil prices as our asset base has the ability to generate rapid oil growth and is located in the oil-window of the premier basin in the U.S.,” Papa said.

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, 2017, which is expected be filed with the U.S. Securities and Exchange Commission (“SEC”) on or before November 8, 2017.

Centennial will host an investor conference call on Tuesday, November 7, 2017 at 8:00 a.m. Mountain (10:00 a.m. Eastern) to discuss third quarter 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: 96043152) 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: 96043152) for a 14-day period following the call.

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.

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.

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.



	2017 FY Guidance (Prior)			2017 FY Guidance (Updated)
Net average daily production (Boe/d)	27,350	—	31,650	27,850	—	32,150
Oil net average daily production (Bbls/d)	17,100	—	18,900	17,300	—	19,100

Production costs
Lease operating expenses ($/Boe)	$(3.25)	—	$(3.55)	$(3.25)	—	$(3.55)
Gathering, processing and transportation expenses ($/Boe)	$(2.75)	—	$(3.25)	$(2.75)	—	$(3.25)
Depreciation, depletion, and amortization ($/Boe)	$(14.00)	—	$(16.00)	$(13.00)	—	$(15.00)
Cash general and administrative ($/Boe) ⁽¹⁾	$(3.00)	—	$(3.50)	$(3.10)	—	$(3.50)
Severance and ad valorem taxes (% of revenue)	6.0%	—	7.0%	5.5%	—	6.5%

Capital expenditure program ($MM)	$535	—	$625	$535	—	$625
Drilling and completion capital expenditure	$475	—	$540	$475	—	$540
Land	$50	—	$70	$50	—	$70
Facilities, seismic and other	$10	—	$15	$10	—	$15

Operated drilling program
Wells spud (gross)	65	—	75	72	—	78
Wells completed (gross)	65	—	75	65	—	75

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 (loss) 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, transaction costs and write-off of deferred offering costs. 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.



	Successor		Predecessor
(in thousands)	For the Three Months Ended September 30, 2017		For the Three Months Ended September 30, 2016
Adjusted EBITDAX reconciliation to net income:
Net income (loss) attributable to common shareholders	$	14,447	$	(5,134	)
Net income attributable to noncontrolling interest	1,813		—
Interest expense	1,015		1,983
Income tax expense (benefit)	8,233		—
Depreciation, depletion and amortization	42,387		18,454
Impairment and abandonment expenses	—		1,649
Non-cash portion of derivative (gain) loss	1,286		211
Stock-based compensation expense	3,360		—
Exploration expense	1,622		402
Transaction costs	42		1,180
Write-off of deferred offering costs	—		1,181
(Gain) loss on sale of oil and natural gas properties	141		(15		)
Adjusted EBITDAX	$	74,346	$	19,911



	Successor		Predecessor		Increase/(Decrease)
	For the Three Months Ended September 30, 2017		For the Three Months Ended September 30, 2016		$			%
Net revenues (in thousands):
Oil sales	$	87,286	$	23,388	$	63,898		273	%
Natural gas sales	12,852		2,629		10,223			389	%
NGL sales	11,473		1,304		10,169			780	%
Total net revenues	$	111,611	$	27,321	$	84,290		309	%

Average sales prices:
Oil (per Bbl)	$	44.95	$	41.69	$	3.26		8	%
Effect of derivative settlements on average price (per Bbl)	0.21		12.36		(12.15		)	(98	)%
Oil net of hedging (per Bbl)	$	45.16	$	54.05	$	(8.89	)	(16	)%

Average NYMEX price for oil (per Bbl)	$	48.17	$	45.00	$	3.17		7	%

Natural gas (per Mcf)	$	2.72	$	2.67	$	0.05		2	%
Effect of derivative settlements on average price (per Mcf)	—		—		—			—	%
Natural gas net of hedging (per Mcf)	$	2.72	$	2.67	$	0.05		2	%

Average NYMEX price for natural gas (per Mcf)	$	2.95	$	2.80	$	0.15		5	%

NGL (per Bbl)	$	24.83	$	14.02	$	10.81		77	%

Net production:
Oil (MBbls)	1,942		561		1,381			246	%
Natural gas (MMcf)	4,733		984		3,749			381	%
NGL (MBbls)	462		93		369			397	%
Total (MBoe) ⁽¹⁾	3,192		818		2,374			290	%

Average daily net production volume:
Oil (Bbls/d)	21,108		6,098		15,010			246	%
Natural gas (Mcf/d)	51,444		10,695		40,749			381	%
NGL (Bbls/d)	5,018		1,011		4,007			396	%
Total (Boe/d) ⁽¹⁾	34,700		8,891		25,809			290	%



	Successor		Predecessor		Increase/(Decrease)
	For the Three Months Ended September 30, 2017		For the Three Months Ended September 30, 2016		$			%
Operating expenses (in thousands):
Lease operating expenses	$	11,373	$	3,656	$	7,717		211	%
Severance and ad valorem taxes	6,448		1,432		5,016			350	%
Gathering, processing and transportation expenses	9,925		1,787		8,138			455	%
Production costs per Boe:
Lease operating expenses	$	3.56	$	4.47	$	(0.91	)	(20	)%
Severance and ad valorem taxes	2.02		1.75		0.27			15	%
Gathering, processing and transportation expenses	3.11		2.18		0.93			43	%



	Successor			Predecessor
	For the Three Months Ended September 30, 2017			For the Three Months Ended September 30, 2016
Net revenues
Oil sales	$	87,286		$	23,388
Natural gas sales	12,852			2,629
NGL sales	11,473			1,304
Total net revenues	111,611			27,321
Operating expenses
Lease operating expenses	11,373			3,656
Severance and ad valorem taxes	6,448			1,432
Gathering, processing and transportation expenses	9,925			1,787
Depreciation, depletion and amortization	42,387			18,454
Impairment and abandonment expenses	—			1,649
Exploration expense	1,622			402
General and administrative expenses	13,311			4,848
Total operating expenses	85,066			32,228
Total operating income (loss)	26,545			(4,907		)
Other income (expense)
Gain (loss) on sale of oil and natural gas properties	(141		)	15
Interest expense	(1,015		)	(1,983		)
Net gain (loss) on derivative instruments	(896		)	1,741
Other income	—			—
Other income (expense)	(2,052		)	(227		)
Income (loss) before income taxes	24,493			(5,134		)
Income tax (expense) benefit	(8,233		)	—
Net income (loss)	16,260			(5,134		)
Less: Net income attributable to noncontrolling interest	1,813			—
Net income (loss) attributable to common shareholders	$	14,447		$	(5,134	)
Income per share:
Basic	$	0.06
Diluted	$	0.06



	Period	Volume (Bbl)	Weighted Average Fixed Price/Differential ($/Bbl) ⁽¹⁾
Crude oil swaps	October 2017 - December 2017	170,200	$	50.41
	January 2018 - December 2018	36,500	$	55.95
Crude oil basis swaps	October 2017 - November 2017	21,350	$	(0.20	)

	Period	Volume (MMBtu)	Weighted Average Fixed Price/Differential ($/MMBtu) ⁽²⁾
Natural gas swaps	October 2017 - December 2017	368,000	$	2.94
Natural gas basis swaps	January 2018 - December 2018	1,825,000	$	(0.43	)
	January 2019 - December 2019	1,825,000	$	(0.43	)


•	Reported third quarter 21% crude oil and 17% total company daily production growth, respectively, compared to the second quarter 2017


•	Increased 2017 total company and oil production growth targets to 256% and 216%, respectively, and reduced full-year DD&A cost guidance for the second consecutive quarter


•	Delivered strong well results from the Northern and Southern Delaware Basins, including Centennial’s best oil well to date


•	Entered into a long-term proppant supply agreement with a local sand provider, reducing future completion costs


•	Completed first wells using in-basin proppant with strong production results


•	our drilling prospects, inventories, projects and programs;


•	our ability to replace the reserves we produce through drilling and property acquisitions;


•	our financial strategy, liquidity and capital required for our development program;


•	the timing and amount of our future production of oil, natural gas and NGLs;


•	our ability to obtain permits and governmental approvals;


•	our business strategy;


•	our competition and government regulations;


•	our pending legal or environmental matters;


⁽¹⁾	The oil swap contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude. The oil basis swap contracts are settled based on the difference between the arithmetic average of WTI MIDLAND ARGUS and WTI ARGUS during the relevant calculation period.


•	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, 2016, and any updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.


⁽¹⁾	Represents G&A expenses less equity based compensation expense. Centennial does not project its future stock-based compensation expense.


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


⁽²⁾	The natural gas swap contracts are settled based on the month’s average daily NYMEX price of Henry Hub Natural Gas. 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.