DENVER, Aug. 08, 2018 (GLOBE NEWSWIRE) -- PDC Energy, Inc. ("PDC" or the "Company") (NASDAQ: PDCE) today reported its 2018 second quarter operating and financial results, as well as updated its full-year 2018 production and financial guidance.

Second Quarter 2018 Highlights

  • Production of 9.4 million barrels of oil equivalent (“MMBoe”), or approximately 103,000 barrels of oil equivalent (“Boe”) per day, representing a year-over-year increase of 20 percent from Wattenberg and Delaware basin operations.

  • Oil production of 3.9 million barrels (“MMBbls”), a 25 percent increase year-over-year from Wattenberg and Delaware basin operations.

  • Delaware basin production averaged approximately 25,000 Boe per day, a sequential increase of approximately 20 percent from the first quarter of 2018.

Updated Full-Year 2018 Guidance Highlights

  • Increased midpoint of total production to 41 MMBoe with an updated range of 40 to 42 MMBoe, primarily as a result of Delaware basin outperformance.

  • Improved Wattenberg drilling and completion efficiencies resulting in an increase in 2018 estimated spuds and completion stages per well.

  • Anticipated capital investment of $950 to $985 million with an expected outspend of $75 to $100 million.  The Company expects to generate free cash flow in the second half of 2018.

CEO Commentary

President and Chief Executive Officer, Bart Brookman commented, “Our second quarter results were a great testament to our long-term strategy of being a premier multi-basin operator.  We’ve been dealt an incredibly difficult hand to play over the past year in terms of the Wattenberg midstream constraints.  Our entire team, from pumpers to asset planners to our midstream team, have done a tremendous job of not only managing our production through these times, but also continuing to capture increased operational efficiencies.  We are incredibly excited to be on the doorstep of truly unlocking the potential of our Core Wattenberg position with the recent start-up of DCP’s Plant 10.

Meanwhile, the strides made from our Delaware team have helped make up for our Wattenberg constraints.  Consistent well results and consecutive quarters of outperformance have quickly led our Delaware production to account for approximately 25% of our corporate volumes.  I’m extremely pleased with the team’s ability to improve our margins while managing through a challenging service cost and netback price environment.”

Operations Update

Production for the second quarter of 2018 was 9.4 MMBoe, representing year-over-year increase of 20 percent from Wattenberg and Delaware basin operations.  Daily production of approximately 103,000 Boe represents sequential growth from Wattenberg and Delaware basin operations of approximately six percent compared to the first quarter of 2018.  Oil production of approximately 3.9 MMBbls represents 42 percent of total production and a volumetric increase of 25 percent from the second quarter of 2017 and four percent from the first quarter of 2018.  The Company’s capital investment in the development of its oil and natural gas properties, as well as other capital expenditures, before the change in accounts payable, was in line with internal expectations at approximately $260 million.

In the Delaware basin, the Company spud six wells and turned-in-line (“TIL”) five wells, consisting of two Central area wells and three Eastern area wells.  Among the Eastern area TILs were two wells located in the Company’s Block 4 focus area, the Elkhead and Kenosha, which had peak 30-day IP rates averaging approximately 290 Boe per day per thousand feet and more than 60 percent crude oil.  Year-to-date, the Company has seven Central area TILs averaging peak 30-day IP rates of approximately 220 Boe per day per thousand feet and 53 percent crude oil, both of which are above internal expectations.  In June 2018, the Company sold initial crude oil volumes under its previously announced five and half year firm transportation agreement to the Gulf Coast.  Average price realizations for all Delaware oil volumes in June, including volumes not covered by the new agreement, were approximately 92 percent of NYMEX.

In Wattenberg, the Company spud 43 wells and TIL 48 wells.  The Company faced difficult operating conditions throughout the second quarter as a lack of spare gas processing capacity, high line pressures, planned and unplanned gas processing downtime and hotter than average temperatures negatively impacted production volumes and operating costs.  With the recent start-up of additional processing capacity in the field, the Company anticipates production in the second half of 2018 to materially benefit from an expected field-wide reduction in line pressures.

Oil and Gas Production, Sales and Operating Cost Data

Crude oil, natural gas and NGLs sales, excluding net settlements on derivatives, increased 53% to $325.9 million in the second quarter of 2018, compared to $213.6 million in the second quarter of 2017.  The increase in sales was due to the aforementioned increase in total production and an increase in the sales price per Boe, excluding net settlements on derivatives, of 30% to $34.74 in the second quarter of 2018 from $26.65 in the comparable 2017 period.  Including the impact of net settlements on derivatives, combined revenues decreased 23% between periods, to $212.5 million from $275.2 million.

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

 Three Months Ended June 30, Six Months Ended June 30,
 2018 2017 Percent Change 2018 2017 Percent Change
Crude oil (MBbls)           
Wattenberg Field2,943  2,798  5.2% 5,823  4,940  17.9%
Delaware Basin1,005  364  176.1% 1,876  639  193.6%
Utica Shale  75  (100.0)% 46  166  (72.3)%
Total3,948  3,237  22.0% 7,745  5,745  34.8%
Weighted-Average Sales Price$63.99  $45.97  39.2% $61.85  $47.31  30.7%
Natural gas (MMcf)           
Wattenberg Field15,836  15,192  4.2% 31,360  28,906  8.5%
Delaware Basin4,851  2,025  139.6% 8,500  3,271  159.9%
Utica Shale  566  (100.0)% 414  1,190  (65.2)%
Total20,687  17,783  16.3% 40,274  33,367  20.7%
Weighted-Average Sales Price$1.46  $2.16  (32.4)% $1.71  $2.26  (24.3)%
NGLs (MBbls)           
Wattenberg Field1,544  1,551  (0.5)% 2,973  2,909  2.2%
Delaware Basin443  212  109.0% 826  343  140.8%
Utica Shale  51  (100.0)% 34  105  (67.6)%
Total1,987  1,814  9.5% 3,833  3,357  14.2%
Weighted-Average Sales Price$21.76  $14.59  49.1% $21.78  $16.75  30.0%
Crude oil equivalent (MBoe)           
Wattenberg Field7,126  6,882  3.5% 14,023  12,667  10.7%
Delaware Basin2,256  914  147.0% 4,118  1,527  169.6%
Utica Shale  219  (100.0)% 149  469  (68.2)%
Total9,382  8,015  17.1% 18,290  14,663  24.7%
Weighted-Average Sales Price$34.74  $26.65  30.4% $34.51  $27.50  25.5%

Production costs for the second quarter of 2018, which include lease operating expenses (“LOE”), production taxes and transportation, gathering and processing expenses (“TGP”), were $63.9 million, or $6.81 per Boe, compared to $41.5 million, or $5.19 per Boe, for the comparable 2017 period.  Wattenberg LOE per Boe in the second quarter of 2018 was $3.29 compared to $2.22 in the second quarter of 2017 and $3.02 in the first quarter of 2018.  The increase in LOE per Boe between periods is primarily due to the aforementioned midstream related operating conditions in Wattenberg negatively impacting both operating costs and production volumes.  In the Delaware basin, increased production volumes as well as transporting effectively all produced water via pipe drove material improvements in LOE per Boe to $3.92 in the second quarter of 2018 compared to $4.88 in the comparable 2017 period and $4.44 in the first quarter of 2018.

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

 Three Months Ended June 30, Six Months Ended June 30,
 2018 2017 2018 2017
Lease operating expenses$32.3  $20.0  $61.9  $39.8 
Production taxes22.6  15.0  42.8  27.4 
Transportation, gathering and processing expenses9.0  6.5  16.3  12.4 
Total$63.9  $41.5  $121.0  $79.6 

 Three Months Ended June 30, Six Months Ended June 30,
 2018 2017 2018 2017
Lease operating expenses per Boe$3.44  $2.50  $3.38  $2.72 
Production taxes per Boe2.41  1.88  2.34  1.87 
Transportation, gathering and processing expenses per Boe0.96  0.81  0.89  0.84 
Total per Boe$6.81  $5.19  $6.61  $5.43 

Financial Results

Net loss for the second quarter of 2018 was $160.3 million, or $2.43 per diluted share, compared to net income of $41.3 million, or $0.62 per diluted share, for the comparable period of 2017.  The year-over-year difference was primarily attributable to a $112.3 million increase in crude oil, natural gas and NGLs sales being offset by $174.1 million difference in commodity price risk management between periods.  Additionally, as a result of widening gas differentials, increased well costs and the timing of lease expirations, the Company recorded an impairment of $159.5 million to select higher-GOR, non-focus area acreage.  This impairment is not expected to impact the Company’s estimated focus area drilling inventory of approximately 450 mid-reach lateral equivalent locations.

Adjusted net loss, a non-GAAP measure defined below, was $84.5 million, or $1.28 per diluted share in the second quarter of 2018 compared to adjusted net income of $12.5 million, or $0.19 per diluted share for the comparable period of 2017.  Excluding the aforementioned impairment expense and related tax impacts would have led to an adjusted net income of $36.8 million, or $0.56 per diluted share in the second quarter of 2018.

Net cash from operating activities was $175.7 million in the second quarter of 2018, compared to $132.9 million in the comparable 2017 period.  Adjusted cash flows from operations, a non-GAAP financial measure defined below, were $199.3 million in the second quarter of 2018, compared to $142.9 million in the comparable 2017 period.

2018 Updated Capital Investment Outlook and Financial Guidance

The Company increased its full-year 2018 production range to 40 to 42 MMBoe. The one MMBoe increase to the mid-point of the range compared to that of prior guidance is largely driven by Delaware basin outperformance.  The Company increased its expected December 2018 exit rate to be approximately 135,000 Boe per day.  As with the Company’s previous guidance, the potential positive impact from flush production associated with the recent midstream processing expansions in the Wattenberg Field is not included.  For the full-year, the Company reaffirms its production mix ranges of 42-45% crude oil, 19-22% NGLs and 32-35% natural gas.

In Wattenberg, the Company now projects to spud between 150 to 165 wells in 2018, an increase from the previous range of 135 to 150, due to drilling efficiency gains realized through the first half of the year.  Additionally, as a result of prior acreage trades leading to a more consolidated position, the Company has been able to modify its drilling and completion techniques to more effectively contact and stimulate the heels and toes of its laterals.  This has led to an increase of approximately ten percent in anticipated completion stages per well throughout 2018.  The Company expects the cost of additional stages, when combined with modest service cost inflation, and partially offset by faster drilling, to increase its Wattenberg per well costs in the second half of 2018 to between $3 and $5 million, depending on lateral length.

In the Delaware basin, the Company expects to spud and TIL 25 to 30 wells in 2018.  In an effort to test the impact to production and reserves of various completion designs, as well as to manage well costs, the Company anticipates using approximately 25% fewer completion stages than in its original budget.  As a result of service cost inflation, specifically due to a tight labor market and increased steel costs, the Company anticipates its Delaware basin well costs to increase approximately $1 million per well, to $10 and $15 million, depending on lateral length and target zone.

The Company now expects to invest between $950 and $985 million in 2018 as a result of the efficiency gains and updated well costs described above.  For the full-year, the Company anticipates its capital investments will exceed its operating cash flows by approximately $75 to $100 million; however, the Company anticipates to generate free cash flow from its operations in the second half of 2018 and exit 2018 undrawn on its revolver.

The following table summarizes the updated 2018 financial guidance:

Production (MMBoe)40.0 42.0 
Capital Expenditures (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 oil91%95%
Natural gas55%60%

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 June 30, Six Months Ended June 30,
 2018 2017 2018 2017
Adjusted cash flows from operations:       
Net cash from operating activities$175.7  $132.9  $380.9  $272.4 
Changes in assets and liabilities23.6  10.0  (6.6) (15.8)
Adjusted cash flows from operations$199.3  $142.9  $374.3  $256.6 

Adjusted Net Income (Loss)
 Three Months Ended June 30, Six Months Ended June 30,
 2018 2017 2018 2017
Adjusted net income (loss):       
Net income (loss)$(160.3) $41.2  $(173.4) $87.4 
(Gain) loss on commodity derivative instruments116.1  (57.9) 163.4  (138.6)
Net settlements on commodity derivative instruments(16.4) 12.0  (42.4) 12.5 
Tax effect of above adjustments(23.9) 17.2  (29.0) 47.2 
Adjusted net income (loss)$(84.5) $12.5  $(81.4) $8.5 
Weighted-average diluted shares outstanding66.1  66.0  66.0  66.1 
Adjusted diluted earnings per share$(1.28) $0.19  $(1.23) $0.13 

Adjusted EBITDAX
 Three Months Ended June 30, Six Months Ended June 30,
 2018 2017 2018 2017
Net income (loss) to adjusted EBITDAX:       
Net income (loss)$(160.3) $41.2  $(173.4) $87.4 
(Gain) loss on commodity derivative instruments116.1  (57.9) 163.4  (138.6)
Net settlements on commodity derivative instruments(16.4) 12.0  (42.4) 12.5 
Non-cash stock-based compensation5.5  5.4  10.8  9.8 
Interest expense, net17.3  18.9  34.7  38.1 
Income tax expense (benefit)(45.3) 24.5  (49.9) 50.9 
Impairment of properties and equipment159.5  27.6  192.7  29.8 
Exploration, geologic and geophysical expense0.9  1.0  3.5  2.0 
Depreciation, depletion and amortization135.6  126.0  262.4  235.3 
Accretion of asset retirement obligations1.4  1.7  2.6  3.4 
Adjusted EBITDAX$214.3  $200.4  $404.4  $330.6 
Cash from operating activities to adjusted EBITDAX:       
Net cash from operating activities$175.7  $132.9  $380.9  $272.4 
Interest expense, net17.3  18.9  34.7  38.1 
Amortization of debt discount and issuance costs(3.1) (3.2) (6.4) (6.4)
Gain (loss) on sale of properties and equipment0.4  0.5  (1.1) 0.7 
Exploration, geologic and geophysical expense0.9  1.0  3.5  2.0 
Other(0.5) 40.3  (0.6) 39.6 
Changes in assets and liabilities23.6  10.0  (6.6) (15.8)
Adjusted EBITDAX$214.3  $200.4  $404.4  $330.6 

Condensed Consolidated Statements of Operations
(unaudited, in thousands, except per share data)

 Three Months Ended June 30, Six Months Ended June 30,
 2018 2017 2018 2017
Crude oil, natural gas and NGLs sales$325,933  $213,602  $631,158  $403,294 
Commodity price risk management gain (loss), net(116,126) 57,932  (163,366) 138,636 
Other income2,724  3,624  5,339  6,935 
Total revenues212,531  275,158  473,131  548,865 
Costs, expenses and other       
Lease operating expenses32,260  20,028  61,896  39,817 
Production taxes22,604  15,042  42,773  27,441 
Transportation, gathering and processing expenses8,964  6,488  16,277  12,390 
Exploration, geologic and geophysical expense875  1,033  3,521  1,987 
Impairment of properties and equipment159,554  27,566  192,742  29,759 
General and administrative expense37,247  29,531  72,943  55,846 
Depreciation, depletion and amortization135,624  126,013  262,412  235,329 
Accretion of asset retirement obligations1,285  1,666  2,573  3,434 
(Gain) loss on sale of properties and equipment(351) (532) 1,081  (692)
Provision for uncollectible note receivable  (40,203)   (40,203)
Other expenses2,708  3,890  5,476  7,418 
Total costs, expenses and other400,770  190,522  661,694  372,526 
Income (loss) from operations(188,239) 84,636  (188,563) 176,339 
Interest expense(17,410) (19,617) (34,939) (39,084)
Interest income69  768  217  1,008 
Income (loss) before income taxes(205,580) 65,787  (223,285) 138,263 
Income tax (expense) benefit45,323  (24,537) 49,889  (50,867)
Net income (loss)$(160,257) $41,250  $(173,396) $87,396 
Earnings per share:       
Basic$(2.43) $0.63  $(2.63) $1.33 
Diluted$(2.43) $0.62  $(2.63) $1.32 
Weighted-average common shares outstanding:       
Basic66,066  65,859  66,012  65,804 
Diluted66,066  66,019  66,012  66,066 

Condensed Consolidated Balance Sheets
(unaudited, in thousands, except share and per share data)

  June 30, 2018 December 31, 2017
Current assets:    
Cash and cash equivalents $1,425  $180,675 
Accounts receivable, net 195,317  197,598 
Fair value of derivatives 14,817  14,338 
Prepaid expenses and other current assets 6,744  8,613 
Total current assets 218,303  401,224 
Properties and equipment, net 4,192,608  3,933,467 
Assets held-for-sale, net   40,084 
Other assets 31,243  45,116 
Total Assets $4,442,154  $4,419,891 
Liabilities and Stockholders' Equity    
Current liabilities:    
Accounts payable $215,150  $150,067 
Production tax liability 56,766  37,654 
Fair value of derivatives 186,605  79,302 
Funds held for distribution 102,354  95,811 
Accrued interest payable 12,561  11,815 
Other accrued expenses 35,888  42,987 
Total current liabilities 609,324  417,636 
Long-term debt 1,179,117  1,151,932 
Deferred income taxes 141,811  191,992 
Asset retirement obligations 73,549  71,006 
Fair value of derivatives 36,430  22,343 
Other liabilities 61,617  57,333 
Total liabilities 2,101,848  1,912,242 
Commitments and contingent liabilities    
Stockholders' equity    
Common shares - par value $0.01 per share, 150,000,000 authorized, 66,133,025 and 65,955,080 issued as of June 30, 2018 and December 31, 2017, respectively 661  659 
Additional paid-in capital 2,509,693  2,503,294 
Retained earnings (deficit) (166,692) 6,704 
Treasury shares - at cost, 67,169 and 55,927
 as of June 30, 2018 and December 31, 2017, respectively
 (3,356) (3,008)
Total stockholders' equity 2,340,306  2,507,649 
Total Liabilities and Stockholders' Equity $4,442,154  $4,419,891 

Condensed Consolidated Statements of Cash Flows
(unaudited, in thousands)

  Three Months Ended June 30, Six Months Ended June 30,
  2018 2017 2018 2017
Cash flows from operating activities:        
Net income (loss) $(160,257) $41,250  $(173,396) $87,396 
Adjustments to net income (loss) to reconcile to net cash from operating activities:        
Net change in fair value of unsettled commodity derivatives 99,718  (45,917) 120,920  (126,070)
Depreciation, depletion and amortization 135,624  126,013  262,412  235,329 
Impairment of properties and equipment 159,554  27,566  192,742  29,759 
Provision for uncollectible notes receivable   (40,203)   (40,203)
Accretion of asset retirement obligations 1,285  1,666  2,573  3,434 
Non-cash stock-based compensation 5,518  5,372  10,779  9,826 
(Gain) loss on sale of properties and equipment (351) (532) 1,081  (692)
Amortization of debt discount and issuance costs 3,126  3,215  6,372  6,399 
Deferred income taxes (45,372) 24,487  (50,181) 50,767 
Other 459  (52) 974  670 
Changes in assets and liabilities (23,596) (9,918) 6,581  15,832 
Net cash from operating activities 175,708  132,947  380,857  272,447 
Cash flows from investing activities:        
Capital expenditures for development of crude oil and natural gas properties (235,718) (204,580) (432,635) (334,406)
Capital expenditures for other properties and equipment (1,384) (1,478) (2,450) (2,299)
Acquisition of crude oil and natural gas properties, including settlement adjustments (227) (809) (181,052) 5,372 
Proceeds from sale of properties and equipment 1,762  556  1,782  1,293 
Proceeds from divestiture     39,023   
Sale of promissory note   40,203    40,203 
Restricted cash   (9,250) 1,249  (9,250)
Sale of short-term investments   49,890    49,890 
Purchases of short-term investments       (49,890)
Net cash from investing activities (235,567) (125,468) (574,083) (299,087)
Cash flows from financing activities:        
Proceeds from revolving credit facility 198,000    233,000   
Repayment of revolving credit facility (176,000)   (211,000)  
Payment of debt issuance costs (4,060)   (4,060)  
Purchases of treasury stock (2,239) (3,257) (4,494) (5,274)
Other (340) (305) (719) (645)
Net cash from financing activities 15,361  (3,562) 12,727  (5,919)
Net change in cash, cash equivalents and restricted cash (44,498) 3,917  (180,499) (32,559)
Cash, cash equivalents and restricted cash, beginning of period 53,924  207,624  189,925  244,100 
Cash, cash equivalents and restricted cash, end of period $9,426  $211,541  $9,426  $211,541 

2018 Second 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 Thursday, August 9, 2018 to discuss its 2018 second quarter results.  The related slide presentation will be available on PDC’s website at

Conference Call and Webcast:
Date/Time: Thursday, August 9, 2018, 11:00 a.m. ET
Webcast available at:
Domestic (toll free): 877-312-5520
International: 253-237-1142
Conference ID: 53186183

Replay Numbers:
Domestic (toll free): 855-859-2056
International: 404-537-3406
Conference ID: 53186183

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

Upcoming Investor Presentations

PDC is scheduled to present at the following conferences: EnerCom's The Oil and Gas Conference in Denver on Tuesday, August 21, 2018; Barclay’s CEO Energy-Power Conference in New York on Wednesday, September 5, 2018; and to attend the Johnson Rice Energy Conference in New Orleans on Tuesday, September 25, 2018.  Webcast information will be posted to the Company’s website,, prior to the start of each conference, along with any presentation materials.

About PDC Energy, Inc.

PDC Energy, Inc. is a domestic independent exploration and production company that produces, develops, and explores for crude oil, natural gas, and NGLs, with primary 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.


This Quarterly Report on Form 10-Q 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 and 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; the impact of potential ballot initiatives and other Colorado political matters; ability to meet our volume commitments to midstream providers; ongoing compliance with our consent decree; timing and likelihood that the Denver Metro/North Front Range NAA ozone classification will be reclassified to serious; and timing and adequacy of infrastructure projects of our midstream providers.

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 derivatives 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
 Kyle Sourk
 Manager Investor Relations