DENVER, Nov. 05, 2018 (GLOBE NEWSWIRE) -- PDC Energy, Inc. ("PDC" or the "Company") (NASDAQ: PDCE) today reported its 2018 third quarter operating and financial results.

Third Quarter 2018 Highlights

• Production of 10.1 million barrels of oil equivalent (“MMBoe”), or approximately 110,000 barrels of oil equivalent (“Boe”) per day, representing a year-over-year increase of 21 percent from Wattenberg and Delaware basin operations.
  
  
• Oil production of 4.3 million barrels (“MMBbls”), a 27 percent increase year-over-year from Wattenberg and Delaware basin operations.
  
  
• Delaware Basin oil price realizations equal to approximately 94 percent of NYMEX average pricing.

CEO Commentary

President and Chief Executive Officer, Bart Brookman commented, “The third quarter offered several positives, including a glimpse of our multi-basin strategy delivering the results and efficiencies needed to propel us through the next several years.  Our Wattenberg operating performance is beginning to improve, as production and costs are both trending in the right direction; however, our production continues to be curtailed by the shortfall in midstream capacity in the basin.  In the Delaware, our Grizzly Bear downspacing test has moved PDC one-step closer to unlocking the optimal approach to maximizing value through full-field development.  We are excited by the knowledge gained through this test and anxiously await the additional downspacing tests currently planned in 2019.”

Operations Update

Production for the third quarter of 2018 was 10.1 MMBoe, representing a year-over-year increase of 21 percent from Wattenberg and Delaware basin operations.  Daily production of approximately 110,000 Boe represents sequential growth of approximately six percent compared to the second quarter of 2018.  Oil production of approximately 4.3 MMBbls represents nearly 43 percent of total production and an increase of 27 percent from Wattenberg and Delaware basin operations compared to the third quarter of 2017 and nine percent from the second quarter of 2018.  The Company’s capital investment in its oil and natural gas properties, as well as other capital expenditures, before the change in accounts payable, was approximately $273 million.

In Wattenberg, the Company spud 43 wells and turned-in-line 22 wells in the third quarter.  In August 2018, the Company’s primary midstream service provider increased its processing capacity, resulting in modest improvements to line pressures in the Core Wattenberg.  Despite a slightly improved operating environment, ongoing system optimization and unplanned facility downtime continued to constrain certain PDC production in the third quarter beyond internal projections.  Despite these challenges, PDC grew Wattenberg production by approximately seven percent compared to the second quarter of 2018 to an estimated 84,000 Boe per day. 

In the Delaware basin, the Company spud eight wells and turned-in-line ten wells, consisting of one Central area well, the eight-well Grizzly Bear pad in its Block 4 area and an Eastern area well located outside of Block 4.  The Grizzly Bear pad includes six Wolfcamp A wells on a half-section, testing twelve wells per-section equivalent, a Wolfcamp B well and a Wolfcamp C well.  The Wolfcamp A wells are currently averaging approximately 75 percent crude oil and are showing minimal signs of communication through various choke management tests and casing pressure assessments.  Through initial flowback, the Wolfcamp C well has yet to reach the Company’s internal production expectations despite exceeding expectations in terms of percent oil at approximately 60 percent of total production.  All eight wells were turned-in-line late in the third quarter and have shown production performance consistent with expectations for the lower-GOR portion of Block 4.

Crude Oil and Natural Gas Production, Sales and Operating Cost Data

Crude oil, natural gas and natural gas liquids (“NGLs”) sales, excluding net settlements on derivatives, increased 60 percent to $372.4 million in the third quarter of 2018, compared to $232.7 million in the third quarter of 2017.  The increase in sales was due to the aforementioned increase in total production and an increase in the average sales price per Boe, excluding net settlements on derivatives, of 35 percent to $36.88 in the third quarter of 2018 from $27.35 in the comparable 2017 period.  Including the impact of net settlements on derivatives, combined revenues increased 34 percent between periods, to $324.3 million from $242.3 million.

The following table provides production by area, and weighted-average sales price for the three and nine months ended September 30, 2018 and 2017, excluding net settlements on derivatives:

	Three Months Ended September 30,											Nine Months Ended September 30,
	2018				2017				Percent Change			2018				2017				Percent Change
Crude oil (MBbls)
Wattenberg Field	3,254				2,943				10.6	%		9,076				7,883				15.1	%
Delaware Basin	1,042				436				139.0	%		2,918				1,075				171.4	%
Utica Shale	—				60				(100.0	)%		46				226				(79.6	)%
Total	4,296				3,439				24.9	%		12,040				9,184				31.1	%
Weighted-Average Sales Price	$	66.27			$	45.66			45.1	%		$	63.43			$	46.69			35.9	%
Natural gas (MMcf)
Wattenberg Field	16,808				15,788				6.5	%		48,169				44,694				7.8	%
Delaware Basin	4,957				2,781				78.2	%		13,457				6,052				122.4	%
Utica Shale	—				501				(100.0	)%		414				1,691				(75.5	)%
Total	21,765				19,070				14.1	%		62,040				52,437				18.3	%
Weighted-Average Sales Price	$	1.60			$	2.17			(26.3	)%		$	1.67			$	2.23			(25.1	)%
NGLs (MBbls)
Wattenberg Field	1,643				1,564				5.1	%		4,616				4,473				3.2	%
Delaware Basin	534				282				89.4	%		1,360				625				117.6	%
Utica Shale	—				46				(100.0	)%		34				151				(77.5	)%
Total	2,177				1,892				15.1	%		6,010				5,249				14.5	%
Weighted-Average Sales Price	$	24.35			$	18.11			34.5	%		$	22.71			$	17.24			31.7	%
Crude oil equivalent (MBoe)
Wattenberg Field	7,698				7,138				7.8	%		21,721				19,805				9.7	%
Delaware Basin	2,402				1,182				103.2	%		6,520				2,709				140.7	%
Utica Shale	—				189				(100.0	)%		149				658				(77.4	)%
Total	10,100				8,509				18.7	%		28,390				23,172				22.5	%
Weighted-Average Sales Price	$	36.88			$	27.35			34.8	%		$	35.35			$	27.45			28.8	%

Production costs for the third quarter of 2018, which include lease operating expenses (“LOE”), production taxes and transportation, gathering and processing expenses (“TGP”), were $66.2 million, or $6.55 per Boe, compared to $50.7 million, or $5.95 per Boe, for the comparable 2017 period. 

Wattenberg LOE per Boe in the third quarter of 2018 was $3.01 compared to $2.49 in the third quarter of 2017 and $3.29 in the second quarter of 2018.  The sequential decrease in Wattenberg LOE per Boe in 2018 was primarily due to increased production volumes related to the aforementioned midstream processing expansion.  In the Delaware Basin, LOE per Boe in the third quarter of 2018 was $4.09 compared to $6.07 per Boe in the third quarter of 2017 and $3.92 in the second quarter of 2018.  The sequential increase in Delaware basin LOE in 2018 was primarily due to minimal production contribution from the ten wells turned-in-line late in the third quarter.

The following table provides the components of production costs for the three and nine months ended September 30, 2018 and 2017 in millions of dollars and on a per Boe basis:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
Lease operating expenses	$	33.0			$	25.4			$	94.9			$	65.2
Production taxes	24.0				15.5				66.8				43.0
Transportation, gathering and processing expenses	9.2				9.8				25.5				22.2
Total	$	66.2			$	50.7			$	187.2			$	130.4

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
Lease operating expenses per Boe	$	3.27			$	2.98			$	3.34			$	2.81
Production taxes per Boe	2.37				1.82				2.35				1.85
Transportation, gathering and processing expenses per Boe	0.91				1.15				0.90				0.96
Total per Boe	$	6.55			$	5.95			$	6.59			$	5.62

Financial Results

Net loss for the third quarter of 2018 was $3.4 million, or $0.05 per diluted share, compared to net loss of $292.5 million, or $4.44 per diluted share, for the comparable period of 2017.  The year-over-year difference was primarily attributable to the $97.5 million difference in total revenues between periods and impairments recorded in the third quarter of 2017 of both unproved properties and goodwill totaling $327.9 million. 

Adjusted net income, a non-U.S. GAAP measure defined below, was $31.8 million, or $0.48 per diluted share in the third quarter of 2018 compared to adjusted net loss of $253.9 million, or $3.85 per diluted share for the comparable period of 2017. 

Net cash from operating activities was $197.0 million in the third quarter of 2018, compared to $148.2 million in the comparable 2017 period.  Adjusted cash flows from operations, a non-U.S. GAAP financial measure defined below, were $201.1 million in the third quarter of 2018, compared to $150.9 million in the comparable 2017 period.

General and administrative expense (“G&A”) was $48.2 million, or $4.78 per Boe for the third quarter of 2018 compared to $29.3 million or $3.44 per Boe in the third quarter of 2017.  The year-over-year difference is primarily due to an increase of approximately $8 million in legal related costs.  Excluding these costs would result in G&A per Boe of $3.99 in the third quarter of 2018.  Additional increases in G&A per Boe are attributable to increases in payroll and employee benefits due to total employee headcount, professional services and expenses related to government relations.

2018 Capital Investment Outlook and Financial Guidance

The Company has seen modest improvements to its Wattenberg production volumes and system-wide line pressures while maintaining its expected allocation of total system capacity from its primary midstream service provider in the Wattenberg Field.  However, due to the pace of ongoing third party midstream system optimization in Wattenberg and both planned and unplanned downtime in the third and fourth quarter, the Company now expects full-year 2018 production to be at the low end of its production guidance range, or approximately 40 MMBoe.  As a result of these midstream constraints negatively impacting production throughout the second half of the year, the Company expects its operating expenses per Boe to be at or slightly above the high-end of the provided guidance ranges in 2018.  The Company does not currently anticipate these midstream constraints to materially impact its 2019 production growth outlook of 25 to 35 percent.

The Company expects its 2018 capital investment for crude oil and natural gas properties to be in the middle of its previously disclosed guidance range.

The following table summarizes the Company’s 2018 financial guidance:

	Low				High
Production (MMBoe)	40.0				42.0
Capital Investment in Crude Oil and Natural Gas Properties (millions)	$	950			$	985
Operating Expenses
Lease operating expense ($/Boe)	$	3.00			$	3.15
Transportation, gathering and processing expenses ($/Boe)	$	0.80			$	0.90
Production taxes (% of Crude oil, natural gas & NGL sales)	6		%		8		%
General and administrative expense ($/Boe)*	$	3.40			$	3.70
Estimated Price Realizations (% of NYMEX) (excludes TGP)
Crude oil	91			%	95			%
Natural gas	55			%	60			%
NGLs	30			%	35			%

*G&A per Boe range excludes the previously described legal related costs of approximately $8 million in the third quarter.  Inclusion of this amount would result in G&A per Boe exceeding the top-end of the provided guidance range by approximately $0.25 per Boe.

Non-GAAP Financial Measures

PDC uses "adjusted cash flows from operations," "adjusted net income (loss)" and "adjusted EBITDAX," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, providing public guidance on possible future results. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP.  The non-U.S. GAAP financial measures that the Company uses may not be comparable to similarly titled measures reported by other companies.  Also, in the future, PDC may disclose different non-U.S. GAAP financial measures in order to help investors more meaningfully evaluate and compare future results of operations to previously reported results of operations. PDC strongly encourages investors to review its financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

The following tables provide reconciliations of adjusted cash flows from operations, adjusted net income (loss) and adjusted EBITDAX to their most comparable U.S. GAAP measures (in millions, except per share data):

Adjusted Cash Flows from Operations
	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
Adjusted cash flows from operations:
Net cash from operating activities	$	197.0			$	148.2			$	577.8			$	420.7
Changes in assets and liabilities	4.1				2.7				(2.5		)		(13.1		)
Adjusted cash flows from operations	$	201.1			$	150.9			$	575.3			$	407.6

Adjusted Net Income (Loss)
	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
Adjusted net income (loss):
Net loss	$	(3.4	)		$	(292.5	)		$	(176.8	)		$	(205.1	)
(Gain) loss on commodity derivative instruments	94.4				52.2				257.8				(86.5		)
Net settlements on commodity derivative instruments	(48.1		)		9.6				(90.5		)		22.2
Tax effect of above adjustments	(11.1		)		(23.2		)		(40.1		)		24.0
Adjusted net income (loss)	$	31.8			$	(253.9	)		$	(49.6	)		$	(245.4	)
Weighted-average diluted shares outstanding	66.1				65.9				66.0				65.8
Adjusted diluted earnings per share	$	0.48			$	(3.85	)		$	(0.75	)		$	(3.73	)

Adjusted EBITDAX
	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
Net loss to adjusted EBITDAX:
Net loss	$	(3.4	)		$	(292.5	)		$	(176.8	)		$	(205.1	)
(Gain) loss on commodity derivative instruments	94.4				52.2				257.8				(86.5		)
Net settlements on commodity derivative instruments	(48.1		)		9.6				(90.5		)		22.2
Non-cash stock-based compensation	5.6				4.8				16.4				14.6
Interest expense, net	17.4				18.8				52.2				56.9
Income tax expense (benefit)	(3.9		)		(122.4		)		(53.8		)		(71.5		)
Impairment of properties and equipment	1.5				252.7				194.2				282.5
Impairment of goodwill	—				75.1				—				75.1
Exploration, geologic and geophysical expense	1.0				41.9				4.6				43.9
Depreciation, depletion and amortization	147.5				125.2				410.0				360.6
Accretion of asset retirement obligations	1.2				1.5				3.8				4.9
Adjusted EBITDAX	$	213.2			$	166.9			$	617.9			$	497.6
Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities	$	197.0			$	148.2			$	577.8			$	420.7
Interest expense, net	17.4				18.8				52.2				56.9
Amortization of debt discount and issuance costs	(3.1		)		(3.2		)		(9.5		)		(9.6		)
Gain (loss) on sale of properties and equipment	(2.1		)		0.1				(3.2		)		0.8
Exploration, geologic and geophysical expense	1.0				41.9				4.6				43.9
Exploratory dry hole costs	—				(41.2		)		—				(41.2		)
Other	(1.1		)		(0.4		)		(1.5		)		39.2
Changes in assets and liabilities	4.1				2.7				(2.5		)		(13.1		)
Adjusted EBITDAX	$	213.2			$	166.9			$	617.9			$	497.6

PDC ENERGY, INC.
Condensed Consolidated Statements of Operations
(unaudited, in thousands, except per share data)

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
Revenues
Crude oil, natural gas and NGLs sales	$	372,439			$	232,733			$	1,003,597			$	636,027
Commodity price risk management gain (loss), net	(94,394		)		(52,178		)		(257,760		)		86,458
Other income	2,672				2,680				8,011				9,615
Total revenues	280,717				183,235				753,848				732,100
Costs, expenses and other
Lease operating expenses	33,046				25,353				94,942				65,170
Production taxes	23,984				15,516				66,757				42,957
Transportation, gathering and processing expenses	9,234				9,794				25,511				22,184
Exploration, geologic and geophysical expense	1,032				41,908				4,553				43,895
Impairment of properties and equipment	1,488				252,740				194,230				282,499
Impairment of goodwill	—				75,121				—				75,121
General and administrative expense	48,240				29,299				121,183				85,145
Depreciation, depletion and amortization	147,540				125,238				409,952				360,567
Accretion of asset retirement obligations	1,200				1,472				3,773				4,906
(Gain) loss on sale of properties and equipment	2,118				(62		)		3,199				(754		)
Provision for uncollectible note receivable	—				—				—				(40,203		)
Other expenses	2,711				2,947				8,187				10,365
Total costs, expenses and other	270,593				579,326				932,287				951,852
Income (loss) from operations	10,124				(396,091		)		(178,439		)		(219,752		)
Interest expense	(17,622		)		(19,275		)		(52,561		)		(58,359		)
Interest income	188				479				405				1,487
Loss before income taxes	(7,310		)		(414,887		)		(230,595		)		(276,624		)
Income tax benefit	3,876				122,350				53,765				71,483
Net loss	$	(3,434	)		$	(292,537	)		$	(176,830	)		$	(205,141	)
Earnings per share:
Basic	$	(0.05	)		$	(4.44	)		$	(2.68	)		$	(3.12	)
Diluted	$	(0.05	)		$	(4.44	)		$	(2.68	)		$	(3.12	)
Weighted-average common shares outstanding:
Basic	66,073				65,865				66,032				65,825
Diluted	66,073				65,865				66,032				65,825

PDC ENERGY, INC.
Condensed Consolidated Balance Sheets
(unaudited, in thousands, except share and per share data)

		September 30, 2018				December 31, 2017
Assets
Current assets:
Cash and cash equivalents		$	1,369			$	180,675
Accounts receivable, net		241,155				197,598
Fair value of derivatives		7,555				14,338
Prepaid expenses and other current assets		6,713				8,613
Total current assets		256,792				401,224
Properties and equipment, net		4,309,021				3,933,467
Assets held-for-sale, net		—				40,084
Fair value of derivatives		3,949				—
Other assets		31,462				45,116
Total Assets		$	4,601,224			$	4,419,891
Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable		$	251,081			$	150,067
Production tax liability		59,539				37,654
Fair value of derivatives		205,013				79,302
Funds held for distribution		104,259				95,811
Accrued interest payable		15,425				11,815
Other accrued expenses		39,260				42,987
Total current liabilities		674,577				417,636
Long-term debt		1,234,733				1,151,932
Deferred income taxes		138,963				191,992
Asset retirement obligations		72,707				71,006
Fair value of derivatives		61,013				22,343
Other liabilities		76,987				57,333
Total liabilities		2,258,980				1,912,242
Commitments and contingent liabilities
Stockholders' equity
Common shares - par value $0.01 per share, 150,000,000 authorized, 66,136,427 and 65,955,080 issued as of September 30, 2018 and December 31, 2017, respectively		661				659
Additional paid-in capital		2,514,861				2,503,294
Retained earnings (deficit)		(170,126		)		6,704
Treasury shares - at cost, 62,265 and 55,927 as of September 30, 2018 and December 31, 2017, respectively		(3,152		)		(3,008		)
Total stockholders' equity		2,342,244				2,507,649
Total Liabilities and Stockholders' Equity		$	4,601,224			$	4,419,891

PDC ENERGY, INC.
Condensed Consolidated Statements of Cash Flows
(unaudited, in thousands)

		Three Months Ended September 30,								Nine Months Ended September 30,
		2018				2017				2018				2017
Cash flows from operating activities:
Net loss		$	(3,434	)		$	(292,537	)		$	(176,830	)		$	(205,141	)
Adjustments to net loss to reconcile to net cash from operating activities:
Net change in fair value of unsettled commodity derivatives		46,298				61,763				167,218				(64,307		)
Depreciation, depletion and amortization		147,540				125,238				409,952				360,567
Impairment of properties and equipment		1,488				252,740				194,230				282,499
Impairment of goodwill		—				75,121				—				75,121
Exploratory dry hole costs		—				41,187				—				41,187
Provision for uncollectible notes receivable		—				—				—				(40,203		)
Accretion of asset retirement obligations		1,200				1,472				3,773				4,906
Non-cash stock-based compensation		5,578				4,761				16,357				14,587
(Gain) loss on sale of properties and equipment		2,118				(62		)		3,199				(754		)
Amortization of debt discount and issuance costs		3,082				3,229				9,454				9,628
Deferred income taxes		(2,848		)		(122,296		)		(53,029		)		(71,529		)
Other		51				316				1,025				986
Changes in assets and liabilities		(4,096		)		(2,727		)		2,485				13,105
Net cash from operating activities		196,977				148,205				577,834				420,652
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties		(252,914		)		(194,444		)		(685,549		)		(528,850		)
Capital expenditures for other properties and equipment		(1,289		)		(1,441		)		(3,739		)		(3,740		)
Acquisition of crude oil and natural gas properties, including settlement adjustments		(520		)		(19,854		)		(181,572		)		(14,482		)
Proceeds from sale of properties and equipment		661				2,029				2,443				3,322
Proceeds from divestiture		4,470				—				43,493				—
Sale of promissory note		—				—				—				40,203
Restricted cash		—				—				1,249				(9,250		)
Sale of short-term investments		—				—				—				49,890
Purchases of short-term investments		—				—				—				(49,890		)
Net cash from investing activities		(249,592		)		(213,710		)		(823,675		)		(512,797		)
Cash flows from financing activities:
Proceeds from revolving credit facility		396,000				—				629,000				—
Repayment of revolving credit facility		(343,000		)		—				(554,000		)		—
Payment of debt issuance costs		(26		)		—				(4,086		)		—
Purchases of treasury stock		(206		)		(51		)		(4,700		)		(5,325		)
Other		(209		)		(306		)		(928		)		(951		)
Net cash from financing activities		52,559				(357		)		65,286				(6,276		)
Net change in cash, cash equivalents and restricted cash		(56		)		(65,862		)		(180,555		)		(98,421		)
Cash, cash equivalents and restricted cash, beginning of period		9,426				211,541				189,925				244,100
Cash, cash equivalents and restricted cash, end of period		$	9,370			$	145,679			$	9,370			$	145,679

2018 Third Quarter Teleconference and Webcast

The Company invites you to join Bart Brookman, President and Chief Executive Officer; Scott Meyers, Chief Financial Officer; Lance Lauck, Executive Vice President Corporate Development and Strategy; and Scott Reasoner, Chief Operating Officer, for a conference call on Tuesday, November 6, 2018 to discuss its 2018 third quarter results.  The related slide presentation will be available on PDC’s website at www.pdce.com. 

Conference Call and Webcast:
Date/Time: Tuesday, November 6, 2018, 11:00 a.m. ET
Webcast available at: www.pdce.com
Domestic (toll free): 877-312-5520
International: 253-237-1142
Conference ID: 6294656

Replay Numbers:
Domestic (toll free): 855-859-2056
International: 404-537-3406
Conference ID: 6294656

The replay of the call will be available for six months on PDC's website at www.pdce.com. 

Upcoming Investor Presentations

PDC is scheduled to present at the Bank of America Energy Conference in Miami on Thursday, November 15, 2018.  Webcast information will be posted to the Company’s website, www.pdce.com, prior to the start of the conference, along with any presentation materials.

About PDC Energy, Inc.

PDC Energy, Inc. is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in Reeves and Culberson Counties, Texas.  PDC’s operations are focused in the horizontal Niobrara and Codell plays in the Wattenberg Field and in the Wolfcamp zones in the Delaware Basin.

NOTE REGARDING FORWARD-LOOKING STATEMENTS

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act"), Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") and the United States ("U.S.") Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are "forward-looking statements." Words such as expect, anticipate, intend, plan, believe, seek, estimate and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: production, costs and cash flows; drilling locations, zones and growth opportunities; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed; management of lease expiration issues; financial ratios and compliance with covenants in our revolving credit facility; impacts of certain accounting and tax changes; midstream capacity and related curtailments; impacts of Proposition 112 and other Colorado political matters; ability to meet our volume commitments to midstream providers; ongoing compliance with our consent decree; reclassification of the Denver Metro/North Front Range NAA ozone classification to serious; and timing and adequacy of infrastructure projects of our midstream providers, including the impact of having a new plant come online during the third quarter of 2018.

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the term “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or our industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

• changes in worldwide production volumes and demand, including economic conditions that might impact demand and prices for the products we produce;
• volatility of commodity prices for crude oil, natural gas and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices;
• volatility and widening of differentials;
• reductions in the borrowing base under our revolving credit facility;
• impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement of those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations;
• declines in the value of our crude oil, natural gas and NGLs properties resulting in impairments;
• changes in estimates of proved reserves;
• inaccuracy of reserve estimates and expected production rates;
• potential for production decline rates from our wells being greater than expected;
• timing and extent of our success in discovering, acquiring, developing and producing reserves;
• availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production;
• timing and receipt of necessary regulatory permits;
• risks incidental to the drilling and operation of crude oil and natural gas wells;
• difficulties in integrating our operations as a result of any significant acquisitions and acreage exchanges;
• increases or changes in costs and expenses;
• availability of supplies, materials, contractors and services that may delay the drilling or completion of our wells;
• potential losses of acreage due to lease expirations or otherwise;
• increases or adverse changes in construction and procurement costs associated with future build out of midstream-related assets;
• future cash flows, liquidity and financial condition;
• competition within the oil and gas industry;
• availability and cost of capital;
• our success in marketing crude oil, natural gas and NGLs;
• effect of crude oil and natural gas derivative activities;
• impact of environmental events, governmental and other third-party responses to such events and our ability to insure adequately against such events;
• cost of pending or future litigation;
• effect that acquisitions we may pursue have on our capital requirements;
• our ability to retain or attract senior management and key technical employees; and
• success of strategic plans, expectations and objectives for our future operations.

Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under the heading "Risk Factors," made in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2017 filed with the U.S. Securities and Exchange Commission ("SEC") on February 27, 2018 and as amended on May 1, 2018 (the "2017 Form 10-K"), and our other filings with the SEC for further information on risks and uncertainties that could affect our business, financial condition, results of operations and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.

Contacts:            

Michael Edwards
Senior Director Investor Relations
303-860-5820
michael.edwards@pdce.com 

Kyle Sourk
Manager Investor Relations
303-318-6150
kyle.sourk@pdce.co