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Oct 15, 2018

PDC Energy Announces 2018 Second Quarter Operating and Financial Results Including Total Production of 9.4 Million Barrels of Oil Equivalent; Updates 2018 Production and Financial Guidance

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 Field 2,943     2,798     5.2 %   5,823     4,940     17.9 %
Delaware Basin 1,005     364     176.1 %   1,876     639     193.6 %
Utica Shale     75     (100.0 )%   46     166     (72.3 )%
Total 3,948     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 Field 15,836     15,192     4.2 %   31,360     28,906     8.5 %
Delaware Basin 4,851     2,025     139.6 %   8,500     3,271     159.9 %
Utica Shale     566     (100.0 )%   414     1,190     (65.2 )%
Total 20,687     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 Field 1,544     1,551     (0.5 )%   2,973     2,909     2.2 %
Delaware Basin 443     212     109.0 %   826     343     140.8 %
Utica Shale     51     (100.0 )%   34     105     (67.6 )%
Total 1,987     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 Field 7,126     6,882     3.5 %   14,023     12,667     10.7 %
Delaware Basin 2,256     914     147.0 %   4,118     1,527     169.6 %
Utica Shale     219     (100.0 )%   149     469     (68.2 )%
Total 9,382     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 taxes 22.6     15.0     42.8     27.4  
Transportation, gathering and processing expenses 9.0     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 Boe 2.41     1.88     2.34     1.87  
Transportation, gathering and processing expenses per Boe 0.96     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:

  Low High
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 oil 91 % 95 %
Natural gas 55 % 60 %
NGLs 30 % 35 %

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 liabilities 23.6     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 instruments 116.1     (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 outstanding 66.1     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 instruments 116.1     (57.9 )   163.4     (138.6 )
Net settlements on commodity derivative instruments (16.4 )   12.0     (42.4 )   12.5  
Non-cash stock-based compensation 5.5     5.4     10.8     9.8  
Interest expense, net 17.3     18.9     34.7     38.1  
Income tax expense (benefit) (45.3 )   24.5     (49.9 )   50.9  
Impairment of properties and equipment 159.5     27.6     192.7     29.8  
Exploration, geologic and geophysical expense 0.9     1.0     3.5     2.0  
Depreciation, depletion and amortization 135.6     126.0     262.4     235.3  
Accretion of asset retirement obligations 1.4     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, net 17.3     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 equipment 0.4     0.5     (1.1 )   0.7  
Exploration, geologic and geophysical expense 0.9     1.0     3.5     2.0  
Other (0.5 )   40.3     (0.6 )   39.6  
Changes in assets and liabilities 23.6     10.0     (6.6 )   (15.8 )
Adjusted EBITDAX $ 214.3     $ 200.4     $ 404.4     $ 330.6  
 

PDC ENERGY, INC.
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
               
Revenues              
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 income 2,724     3,624     5,339     6,935  
Total revenues 212,531     275,158     473,131     548,865  
Costs, expenses and other              
Lease operating expenses 32,260     20,028     61,896     39,817  
Production taxes 22,604     15,042     42,773     27,441  
Transportation, gathering and processing expenses 8,964     6,488     16,277     12,390  
Exploration, geologic and geophysical expense 875     1,033     3,521     1,987  
Impairment of properties and equipment 159,554     27,566     192,742     29,759  
General and administrative expense 37,247     29,531     72,943     55,846  
Depreciation, depletion and amortization 135,624     126,013     262,412     235,329  
Accretion of asset retirement obligations 1,285     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 expenses 2,708     3,890     5,476     7,418  
Total costs, expenses and other 400,770     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 income 69     768     217     1,008  
Income (loss) before income taxes (205,580 )   65,787     (223,285 )   138,263  
Income tax (expense) benefit 45,323     (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:              
Basic 66,066     65,859     66,012     65,804  
Diluted 66,066     66,019     66,012     66,066  
 

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

    June 30, 2018   December 31, 2017
Assets        
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        
Liabilities        
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  
         

PDC ENERGY, INC.
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 www.pdce.com.

Conference Call and Webcast:
Date/Time: Thursday, August 9, 2018, 11:00 a.m. ET
Webcast available at: www.pdce.com
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 www.pdce.com.

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, www.pdce.com, 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.

NOTE REGARDING FORWARD-LOOKING STATEMENTS

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
  303-860-5820
  michael.edwards@pdce.com
   
  Kyle Sourk
  Manager Investor Relations
  303-318-6150
  kyle.sourk@pdce.co

 

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Source: PDC Energy, Inc.