PDC Energy Announces 2017 Second Quarter Results With 54% Production Increase to 8.0 Million Barrels of Oil Equivalent

DENVER, Aug. 08, 2017 (GLOBE NEWSWIRE) -- PDC Energy, Inc. ("PDC" or the "Company") (NASDAQ:PDCE) today reported its 2017 second quarter operating and financial results.

Second Quarter 2017 Highlights

  • Production of 8.0 million barrels of oil equivalent (“MMBoe”), a 54 percent increase year-over-year; daily production of approximately 88,100 barrels of oil equivalent (“Boe”).
  • Oil production of 3.2 million barrels (“MMBbls”), a 62 percent increase year-over-year and 29 percent increase compared to the first quarter of 2017.
  • Delaware basin production averaged 10,047 Boe per day.
  • Wattenberg drilling efficiency increased approximately 15 percent.
  • Lease operating expenses (“LOE”) of $2.50 per Boe, a 16 percent decrease compared to the first quarter of 2017.
  • Liquidity of approximately $900 million, including $202 million of cash, resulting in a leverage ratio of 1.9 times, as defined by the Company’s credit agreement.

CEO Commentary

President and Chief Executive Officer, Bart Brookman commented, “Our quarterly production results demonstrate improved capital efficiencies and completion enhancements in Wattenberg, as well as the momentum we are building in the Delaware Basin. In Wattenberg, we further reduced drilling times, which will allow us to drop our rig count to three this October and maintain a similar pace of development. We have great operational flexibility in both basins to increase or decrease our rig counts depending on market conditions. Lastly, we are excited by the work of our operating teams in not only delivering strong recent well results in the Delaware Basin, but improving our operating cost structure in the quarter. ”

Operating Update and Results

The Company turned-in-line six wells in the Delaware Basin in the second quarter of 2017 and had average daily production of 10,047 Boe. Production from the Kenosha well, a Wolfcamp A well in the Eastern acreage block, is strong with an average 30-day peak production rate of approximately 2,300 Boe per day. The Kenosha, which was turned-in-line in the first quarter of 2017, is the Company’s first extended-reach lateral well in the basin and has been producing more than 2,000 Boe per day for the past 100 days. In the Central acreage block, PDC drilled and turned-in-line the Greenwich 4H well testing the Wolfcamp A. Performance from the 7,500 foot lateral is exceeding type curve expectations and had an average 30-day peak production rate of 1,425 Boe per day with approximately 55 percent oil. The Company’s two wells in the Western acreage block were turned-in-line in the second quarter, but have taken longer to clean up and generally have underperformed internal expectations. The Company currently plans to operate three drilling rigs for the remainder of the year, with much of the anticipated activity focused on additional extended-reach lateral wells in the Eastern area. Concentrating on cost management and operational efficiencies in the current aggressive service cost market remains a key priority.

In Wattenberg, PDC spud 44 wells and had 32 turn-in-lines in the second quarter with average daily production of 75,621 Boe. Throughout the first half of the year, the Company continued to realize increased drilling efficiencies on its standard-, mid- and extended-reach lateral wells resulting in more than 15 percent average improvements in spud-to-spud drill times. Due to these improvements, the Company has elected to return to a three rig program in the fourth quarter of 2017, helping to manage the overall capital program. Because of the increased efficiencies and adjusted timing of completions, the Company now expects to spud approximately 155 wells and turn-in-line approximately 133 wells for the full-year in the Wattenberg Field, compared to an estimated 139 spuds and 139 turn-in-lines previously.

Oil and Gas Production, Sales and Operating Cost Data

The following table provides production by area, and weighted-average sales price for the three and six months ended June 30, 2017 and 2016, excluding net settlements on derivatives:

Three Months Ended
June 30,
Six Months Ended
June 30,
2017 2016 Percent 2017 2016 Percent
Crude oil (MBbls)
Wattenberg Field2,798 1,894 47.7% 4,940 3,712 33.1%
Delaware Basin364 * 639 *
Utica Shale75 99 (24.4)% 166 188 (12.1)%
Total3,237 1,993 62.4% 5,745 3,900 47.3%
Weighted-Average Sales Price$45.97 $40.37 13.9% $47.31 $34.46 37.3%
Natural gas (MMcf)
Wattenberg Field15,192 12,098 25.6% 28,906 22,268 29.8%
Delaware Basin2,025 * 3,271 *
Utica Shale566 575 (1.6)% 1,190 1,083 9.9%
Total17,783 12,673 40.3% 33,367 23,351 42.9%
Weighted-Average Sales Price$2.16 $1.37 57.7% $2.26 $1.38 63.8%
NGLs (MBbls)
Wattenberg Field1,551 1,047 48.1% 2,909 1,888 54.1%
Delaware Basin212 * 343 *
Utica Shale51 45 11.9% 105 87 19.8%
Total1,814 1,092 66.1% 3,357 1,975 70.0%
Weighted-Average Sales Price$14.59 $11.93 22.3% $16.75 $9.89 69.4%
Crude oil equivalent (MBoe)
Wattenberg Field6,882 4,957 38.8% 12,667 9,311 36.0%
Delaware Basin914 * 1,527 *
Utica Shale219 240 (8.5)% 469 456 2.8%
Total8,015 5,197 54.2% 14,663 9,767 50.1%
Weighted-Average Sales Price $26.65 $21.33 24.9% $27.50 $19.07 44.2%


The following table provides the components of production costs for the three and six months ended June 30, 2017 and 2016 in terms of total dollars and on a per Boe basis:


Three Months Ended
June 30,
Six Months Ended
June 30,
2017 2016 2017 2016
Lease operating expenses$20.0 $13.7 $39.8 $29.0
Production taxes15.0 6.0 27.4 10.1
Transportation, gathering and processing expenses 6.5 4.5 12.4 8.5
Total$41.6 $24.2 $79.6 $47.6


Three Months Ended
June 30,
Six Months Ended
June 30,
2017 2016 2017 2016
Lease operating expenses per Boe$2.50 $2.63 $2.72 $2.97
Production taxes per Boe1.88 1.16 1.87 1.04
Transportation, gathering and processing expenses per
Boe
0.81 0.86 0.84 0.87
Total per Boe$5.19 $4.65 $5.43 $4.88


Financial Results

Net income for the second quarter of 2017 was $41.3 million, or $0.62 per diluted share, compared to net loss of $95.5 million, or $2.04 per diluted share, for the comparable period of 2016. The year-over-year difference was primarily attributable to a $102.8 million increase in crude oil, natural gas and NGLs sales in 2017, as well as the impact of the change in the fair value of derivatives during the quarters. Adjusted net income, a non-GAAP measure defined below, was $12.5 million, or $0.19 per diluted share in the second quarter of 2017 compared to adjusted net loss of $5.0 million, or $0.11 per diluted share for the comparable period of 2016.

Net cash from operating activities was $123.7 million in the second quarter of 2017, compared to $96.6 million in the second quarter of 2016. The increase in 2017 cash flows was a result of increases to both production volumes and realized sales prices compared to the prior year. Adjusted cash flows from operations, a non-GAAP financial measure defined below, were $142.9 million for the second quarter of 2017, compared to $112.6 million in the comparable period of 2016.

Crude oil, natural gas and NGLs sales, excluding net settlements on derivatives, increased 93 percent to $213.6 million in the second quarter of 2017, compared to $110.8 million in the second quarter of 2016. The sales price per Boe, excluding net settlements on derivatives, improved to $26.65 in the second quarter of 2017 compared to $21.33 in the second quarter of 2016. Including commodity price risk management gain and other income, crude oil, natural gas and NGLs revenues were $275.2 million in the second quarter of 2017 compared to $20.1 million in the second quarter of 2016.

Net commodity price risk management activities for the second quarter of 2017 resulted in a gain of $57.9 million compared to a loss of $92.8 million in the comparable period of 2016. The second quarter 2017 gain was comprised of $45.9 million in net change in fair value of unsettled derivatives and $12.0 million of net settlement gains. Net settlements in the second quarter of 2016 were $53.3 million with a decrease in fair value of unsettled derivatives of $146.1 million.

Production costs, which include LOE, production taxes, and transportation, gathering and processing expenses (“TGP”), for the second quarter of 2017 were $41.5 million, or $5.19 per Boe. In the second quarter of 2016, production costs were $24.2 million, or $4.65 per Boe. LOE in the second quarter of 2017 decreased five percent to $2.50 per Boe compared to $2.63 per Boe in the similar 2016 period primarily due to increased production volumes offsetting higher LOE costs associated with operations in the Delaware Basin.

Depreciation, depletion and amortization expense ("DD&A") related to crude oil and natural gas properties was $124.4 million, or $15.51 per Boe in the second quarter of 2017, compared to $106.1 million, or $20.41 per Boe in the second quarter of 2016. The decrease in weighted-average DD&A rate between periods was due to the increases in proven reserves attributable to our operations outpacing production growth, even with a robust capital program.

The Company’s capital investment in the development of oil and natural gas properties and other capital expenditures, before the change in accounts payable, was $218.3 million during the second quarter of 2017 compared to $107.5 million for the same 2016 period. The increase in capital investment was primarily attributable to investments made in Delaware Basin drilling, completions and midstream infrastructure in the second quarter of 2017.

2017 Capital Investment Outlook and Financial Guidance

Senior Vice President and Chief Financial Officer, David Honeyfield, commented, “As we manage the capital investment program, we are also adjusting the timing of completions, resulting in full-year estimated production towards the bottom of our 32 to 33 MMBoe range. This production outlook takes into account our updated turn-in-line schedule, anticipated midstream constraints in Wattenberg, and our updated production forecast from our Delaware assets. In terms of capital investment, we are committed to prioritizing the strength of our balance sheet while delivering highly economic rates-of-return on our capital program. After adjusting for the timing of drilling and certain completions and increased well costs in the Delaware, we expect full-year capital to be approximately $800 million. This should set us up to exit 2017 with more than $100 million of cash on the balance sheet together with the undrawn $700 million commitment level on our current bank revolving credit facility."

The following table provides additional 2017 financial guidance:


LowHigh
Operating Expenses
Lease operating expense ($/Boe)$2.65 $3.00
Transportation, gathering and processing expenses ($/Boe)$0.70 $0.90
Production taxes (% of Crude Oil, Natural Gas & NGL sales)6%8%
General and administrative expense ($/Boe)$3.25 $3.60
Depreciation, depletion and amortization ($/Boe)$15.00 $16.50
Exploration, geologic and geophysical expense (millions)$5.0 $10.0
Estimated Price Realizations (% of NYMEX) (excludes TGP)
Oil92%94%
Gas70%72%
NGLs27%31%


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 when providing public guidance on possible future results. Beginning in 2017, the Company has included non-cash stock-based compensation and exploration, geologic and geophysical expenses to its adjusted EBITDAX calculation. All prior periods have been reconciled to match accordingly. PDC believes that each of these measures is useful in providing transparency with respect to certain aspects of its operations. Each of these measures is calculated by adjusting for the items set forth in the relevant table below from the most closely comparable U.S. GAAP measure. See Management's Discussion and Analysis of Financial Condition and Results of Operation - Reconciliation of Non-U.S. GAAP Financial Measures in PDC's Annual Report on Form 10-K for the year ended December 31, 2016, and other subsequent filings with the SEC, for additional disclosure concerning these non-U.S. GAAP measures. These are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income, cash flows from operations, investing or financing activities or other U.S. GAAP financial measures, 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 PDC 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 its investors more meaningfully evaluate and compare its future results of operations to its previously reported results of operations. PDC strongly encourages users of financial information to review the Company's financial statements and publicly filed reports in their entirety and not to 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 net income and adjusted EBITDAX in the three and six months ended June 30, 2017, includes the $40.2 million of proceeds from the sale of the Company’s MK Promissory Note:

Adjusted Cash Flows from Operations
Three Months Ended
June 30,
Six Months Ended
June 30,
2017 2016 2017 2016
Adjusted cash flows from operations:
Net cash from operating activities$123.7 $96.6 $263.2 $197.8
Changes in assets and liabilities19.2 16.0 (6.6) 5.8
Adjusted cash flows from operations$142.9 $112.6 $256.6 $203.6
Adjusted Net Income (Loss)
Three Months Ended
June 30,
Six Months Ended
June 30,
2017 2016 2017 2016
Adjusted net income (loss):
Net income (loss)$41.3 $(95.5) $87.4 $(167.0)
(Gain) loss on commodity derivative instruments(57.9) 92.8 (138.6) 81.7
Net settlements on commodity derivative instruments12.0 53.3 12.5 120.2
Tax effect of above adjustments17.2 (55.6) 47.2 (76.8)
Adjusted net income (loss)$12.5 $(5.0) $8.5 $(41.9)
Weighted-average diluted shares outstanding66.0 46.7 66.1 44.2
Adjusted diluted earnings per share$0.19 $(0.11) $0.13 $(0.95)


Adjusted EBITDAX
Three Months Ended
June 30,
Six Months Ended
June 30,
2017 2016 2017 2016
Net income (loss) to adjusted EBITDAX:
Net income (loss)$41.3 $(95.5) $87.4 $(167.0)
(Gain) loss on commodity derivative instruments(57.9) 92.8 (138.6) 81.7
Net settlements on commodity derivative instruments12.0 53.3 12.5 120.2
Non-cash stock-based compensation5.4 6.4 9.8 11.1
Interest expense, net18.9 10.5 38.1 20.8
Income tax expense (benefit)24.5 (58.3) 50.9 (100.2)
Impairment of properties and equipment27.6 4.2 29.8 5.2
Exploration, geologic, and geophysical expense1.0 0.2 2.0 0.4
Depreciation, depletion, and amortization126.0 107.0 235.3 204.4
Accretion of asset retirement obligations1.7 1.8 3.4 3.6
Adjusted EBITDAX$200.4 $122.4 $330.6 $180.2
Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities$123.7 $96.6 $263.2 $197.8
Interest expense, net18.9 10.5 38.1 20.8
Amortization of debt discount and issuance costs(3.2) (1.3) (6.4) (3.1)
Gain (loss) on sale of properties and equipment0.5 (0.3) 0.7 (0.2)
Exploration, geologic, and geophysical expense1.0 0.2 2.0 0.4
Other(1)40.3 0.7 39.6 (41.3)
Changes in assets and liabilities19.2 16.0 (6.6) 5.8
Adjusted EBITDAX$200.4 $122.4 $330.6 $180.2

(1) Other includes the impact of provisions for the uncollectible notes receivable in the three and six months ended June 30, 2017, and the six months ended June 30, 2016.


PDC ENERGY, INC.
Consolidated Statements of Operations
(unaudited, in thousands, except per share data)
Three Months Ended
June 30,
Six Months Ended
June 30,
2017 2016 2017 2016
Revenues
Crude oil, natural gas, and NGLs sales$213,602 $110,841 $403,294 $186,208
Commodity price risk management gain (loss), net of settlements57,932 (92,801) 138,636 (81,745)
Other income3,624 2,057 6,935 6,465
Total revenues275,158 20,097 548,865 110,928
Costs, expenses and other
Lease operating expenses20,028 13,675 39,817 29,005
Production taxes15,042 6,043 27,441 10,114
Transportation, gathering and processing expenses6,488 4,465 12,390 8,506
General and administrative expense29,531 23,579 55,846 46,358
Exploration, geologic, and geophysical expense1,033 237 1,987 447
Depreciation, depletion and amortization126,013 107,014 235,329 204,402
Impairment of properties and equipment27,566 4,170 29,759 5,171
Accretion of asset retirement obligations1,666 1,811 3,434 3,623
(Gain) loss on sale of properties and equipment(532) 260 (692) 176
Provision for uncollectible notes receivable(40,203) (40,203) 44,738
Other expenses3,890 2,125 7,418 4,703
Total costs, expenses and other190,522 163,379 372,526 357,243
Income (loss) from operations84,636 (143,282) 176,339 (246,315)
Interest expense(19,617) (10,672) (39,084) (22,566)
Interest income768 177 1,008 1,735
Income (loss) before income taxes65,787 (153,777) 138,263 (267,146)
Income tax (expense) benefit(24,537) 58,327 (50,867) 100,166
Net income (loss)$41,250 $(95,450) $87,396 $(166,980)
Earnings per share:
Basic$0.63 $(2.04) $1.33 $(3.78)
Diluted$0.62 $(2.04) $1.32 $(3.78)
Weighted-average common shares outstanding:
Basic65,859 46,742 65,804 44,175
Diluted66,019 46,742 66,066 44,175



PDC ENERGY, INC.
Consolidated Balance Sheets
(unaudited, in thousands, except share and per share data)
June 30, 2017 December 31, 2016
Assets
Current assets:
Cash and cash equivalents $202,291 $244,100
Accounts receivable, net 135,203 143,392
Fair value of derivatives 52,105 8,791
Prepaid expenses and other current assets 6,619 3,542
Total current assets 396,218 399,825
Properties and equipment, net 4,165,572 4,008,266
Fair value of derivatives 16,397 2,386
Goodwill 56,331 62,041
Other assets 22,410 13,324
Total Assets $4,656,928 $4,485,842
Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable $152,492 $66,322
Production tax liability 35,296 24,767
Fair value of derivatives 10,138 53,595
Funds held for distribution 86,846 71,339
Accrued interest payable 15,955 15,930
Other accrued expenses 29,939 38,625
Total current liabilities 330,666 270,578
Long-term debt 1,049,004 1,043,954
Deferred income taxes 452,028 400,867
Asset retirement obligations 77,867 82,612
Fair value of derivatives 2,311 27,595
Other liabilities 30,610 37,482
Total liabilities 1,942,486 1,863,088
Commitments and contingent liabilities
Stockholders' equity
Common shares - par value $0.01 per share, 150,000,000 authorized,
65,927,104 and 65,704,568 issued as of June 30, 2017 and
December 31, 2016, respectively
659 657
Additional paid-in capital 2,495,940 2,489,557
Retained earnings 221,604 134,208
Treasury shares - at cost, 64,024 and 28,763 as of June 30, 2017 and
December 31, 2016, respectively
(3,761) (1,668)
Total stockholders' equity 2,714,442 2,622,754
Total Liabilities and Stockholders' Equity (Deficit) $4,656,928 $4,485,842



PDC ENERGY, INC.
Consolidated Statements of Cash Flows
(unaudited, in thousands)
Three Months Ended
June 30,
Six Months Ended
June 30,
2017 2016 2017 2016
Cash flows from operating activities:
Net income (loss) 41,250 (95,450) $87,396 $(166,980)
Adjustments to net income (loss) to reconcile to net cash from
operating activities:
Net change in fair value of unsettled commodity derivatives (45,917) 146,055 (126,070) 201,825
Depreciation, depletion and amortization 126,013 107,014 235,329 204,402
Impairment of properties and equipment 27,566 4,170 29,759 5,171
Provision for uncollectible notes receivable (40,203) (40,203) 44,738
Accretion of asset retirement obligation 1,666 1,811 3,434 3,623
Non-cash stock-based compensation 5,372 6,444 9,826 11,126
(Gain) loss on sale of properties and equipment (532) 260 (692) 176
Amortization of debt discount and issuance costs 3,215 1,323 6,399 3,077
Deferred income taxes 24,487 (58,947) 50,767 (102,319)
Other (52) (85) 670 (1,287)
Changes in assets and liabilities (19,168) (15,947) 6,582 (5,754)
Net cash from operating activities 123,697 96,648 263,197 197,798
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas
properties
(204,580) (112,368) (334,406) (234,677)
Capital expenditures for other properties and equipment (1,478) (580) (2,299) (1,030)
Acquisition of crude oil and natural gas properties, including
settlement adjustments
(809) 5,372
Proceeds from sale of properties and equipment, net 556 4,813 1,293 4,903
Sale of promissory note 40,203 40,203
Restricted cash (9,250) (9,250)
Sale of short-term investments 49,890 49,890
Purchases of short-term investments (49,890)
Net cash from investing activities (125,468) (108,135) (299,087) (230,804)
Cash flows from financing activities:
Proceeds from issuance of equity, net of issuance cost (3) 296,575
Proceeds from revolving credit facility 85,000
Repayment of revolving credit facility (122,000)
Redemption of convertible notes (115,000) (115,000)
Purchase of treasury shares (3,257) (2,853) (5,274) (4,055)
Other (305) (103) (645) 735
Net cash from financing activities (3,562) (117,959) (5,919) 141,255
Net change in cash and cash equivalents (5,333) (129,446) (41,809) 108,249
Cash and cash equivalents, beginning of period 207,624 238,545 244,100 850
Cash and cash equivalents, end of period $202,291 $109,099 $202,291 $109,099


2017 Second Quarter Teleconference and Webcast

The Company invites you to join Bart Brookman, President and Chief Executive Officer; David Honeyfield, Senior Vice President Chief Financial Officer; Lance Lauck, Executive Vice President Corporate Development and Strategy; and Scott Reasoner, Chief Operating Officer, for a conference call on Tuesday, August 8, 2017 to discuss its 2017 second quarter results. The related slide presentation will be available on PDC’s website at www.pdce.com.

Conference Call and Webcast:
Date/Time: Tuesday, August 8, 2017, 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 Monday, August 14, 2017; Barclay’s CEO Energy-Power Conference in New York on Wednesday, September 6, 2017; The Johnson Rice Energy Conference in New Orleans on Tuesday, September 26, 2017 and IPAA OGIS-Chicago on Tuesday, October 3, 2017. 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. The Company also has operations in the Utica Shale in Southeastern Ohio, which it plans to divest. 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 expects, anticipates, intends, plans, believes, seeks, estimates, outlook, targets, and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements may include, among other things, statements regarding future: reserves, production, costs, cash flows, and earnings; drilling locations and growth opportunities; capital investments and projects, including expected lateral lengths of wells, drill times and number of rigs employed; rates of return; operational enhancements and efficiencies; management of lease expiration issues; financial ratios; and midstream capacity and related curtailments.

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this press release reflect the Company’s good faith judgment, such statements can only be based on facts and factors currently known to it. 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 press release or accompanying materials, the Company may use the terms “projection” or similar terms or expressions, or indicate that it has “modeled” certain future scenarios. PDC typically uses these terms to indicate its current thoughts on possible outcomes relating to its business or the 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 it produces;
  • volatility of commodity prices for crude oil, natural gas, and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices;
  • reductions in the borrowing base under its 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 its crude oil, natural gas, and NGLs properties resulting in further impairments;
  • changes in estimates of proved reserves;
  • inaccuracy of reserve estimates and expected production rates;
  • potential for production decline rates from its wells being greater than expected;
  • timing and extent of its success in discovering, acquiring, developing, and producing reserves;
  • availability of sufficient pipeline, gathering, and other transportation facilities and related infrastructure to process and transport its production and the impact of these facilities and regional capacity on the prices received for production;
  • timing and receipt of necessary regulatory permits;
  • risks incidental to the drilling and operation of crude oil and natural gas wells;
  • losses from its gas marketing business exceeding its expectations;
  • difficulties in integrating its operations as a result of any significant acquisitions, including its recent acquisitions in the Delaware Basin;
  • increases or changes in operating costs, severance and ad valorem taxes, and increases or changes in drilling, completion, and facilities costs;
  • potential losses in acreage due to expiration or otherwise;
  • increases or adverse changes in construction costs 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;
  • 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 its ability to insure adequately against such events;
  • cost of pending or future litigation, including recent environmental litigation;
  • effect that acquisitions it may pursue has on its capital investments;
  • its ability to retain or attract senior management and key technical employees; and
  • success of strategic plans, expectations, and objectives for its future operations.

Further, PDC urges you to carefully review and consider the cautionary statements and disclosures, specifically those under the heading "Risk Factors," made in its Quarterly Report on Form 10-Q, its Annual Report on Form 10-K for the year ended December 31, 2016 (the "2016 Form 10-K"), filed with the U.S. Securities and Exchange Commission ("SEC") on February 28, 2017, and other filings with the SEC for further information on risks and uncertainties that could affect the Company’s business, financial condition, results of operations, and prospects, which are incorporated by this reference as though fully set forth herein.

PDC cautions you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. The Company undertakes 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.com

Source:PDC Energy