PDC Energy Announces 2016 Full-Year and Fourth Quarter Operating and Financial Results; Production Increase of 44 Percent to 22.2 MMBoe

February 28, 2017 at 8:00 AM EST

DENVER, Feb. 28, 2017 (GLOBE NEWSWIRE) -- PDC Energy, Inc. ("PDC" or the "Company") (NASDAQ:PDCE) today reported its 2016 full-year and fourth quarter operating and financial results.

2016 Highlights

  • Closed on the transformative acquisitions ("the Acquisitions") of approximately 62,500 net acres in the Core Delaware Basin in Reeves and Culberson Counties, Texas.
  • Increase in proved reserves of 25% to 341 million barrels of oil equivalent ("MMBoe"), with all-sources reserve replacement of 409%, driven in large part by the strategic acreage trade in Wattenberg.    
  • Full-year capital investments, including Delaware Basin activity, of $399.9 million, a 28% decrease compared to 2015.
  • Year-end liquidity of $932.4 million, including $244.1 million of cash on hand as of December 31, 2016, delivering a debt to EBITDAX ratio, as defined by its revolving credit agreement, of 2.1 times.
  • Lease operating expenses ("LOE") of $2.70 per barrel of oil equivalent ("Boe"), a decrease of 27% per Boe compared to 2015.

CEO Commentary

President and Chief Executive Officer, Bart Brookman commented, "Our strong performance in 2016 highlights our ability to fulfill our strategic initiative of positioning the Company for growth in two premier basins.  I am extremely proud that we have delivered top-tier, value-driven production growth while simultaneously completing our large-scale Delaware Basin acquisition and Core Wattenberg acreage trade.  Throughout the year, we were extremely focused on improving our cost structure and increasing our operational efficiencies.   By these standards, 2016 was a resounding success.

"In 2017, we have an intense operational and technical focus on unlocking the tremendous value of our Delaware Basin asset.   The ongoing, reliable growth of the Wattenberg continues to serve as the foundation of the Company, and will continue to benefit from the pursuit of improved application of technology by our operating teams.  We remain confident that our sizeable core positions, the strength of our balance sheet, and our dedicated and talented employees will enable us to continue our success moving forward."

Financial Results

Oil and Gas Production, Sales and Operating Cost Data

The following table provides production and weighted-average sales price, by area, for the three and twelve months ended December 31, 2016 and 2015, excluding net settlements on derivatives and transportation, gathering and processing expenses ("TGP"):

 Three Months Ended
 December 31,
 Twelve Months Ended
December 31,
 2016 2015 Percent 2016 2015 Percent
Crude oil (MBbls)           
Wattenberg Field2,301.2  1,980.9  16.2%  8,229.7  6,490.4  26.8%
Delaware Basin79.5    *   79.5    * 
Utica Shale107.4  107.0  *   419.1  493.4  (15.1)%
Total2,488.1  2,087.9  19.2%  8,728.3  6,983.8  25.0%
Weighted-Average Sales Price$ 46.54  $35.26  32.0%  $39.96  $40.14  (0.4)%
Natural gas (MMcf)              
Wattenberg Field13,920.9  9,712.1  43.3%  48,889.1  30,752.8  59.0%
Delaware Basin373.3     *   373.3    * 
Utica Shale667.8  592.6  *   2,467.8  2,548.9  (3.2)%
Total14,962.0  10,304.7  45.2%  51,730.2  33,301.7  55.3%
Weighted-Average Sales Price$2.14  $1.81  18.2%  $1.77  $2.04  (13.2)%
NGLs (MBbls)              
Wattenberg Field1,327.1  923.4  43.7%  4,567.5  2,615.9  74.6%
Delaware Basin36.1    *   36.1    * 
Utica Shale59.8  53.4  *   222.2  219.4  1.3%
Total1,423.0  976.8  45.7%  4,825.8  2,835.3  70.2%
Weighted-Average Sales Price$15.11  $ 11.26  34.2%  $11.80  $10.72  10.1%
Crude oil equivalent (MBoe)              
Wattenberg Field5,948.5  4,522.9  31.5%  20,945.4  14,231.7  47.2%
Delaware Basin177.8    *   177.8    * 
Utica Shale278.6  259.2  7.5%  1,052.7  1,137.7  (7.5)%
Total6,404.9  4,782.1  33.9%  22,175.9  15,369.4  44.3%
Weighted-Average Sales Price$26.44  $21.58  22.5%  $22.43  $24.64  (9.0)%

The following table provides the components of production costs for the three and twelve months ended December 31, 2016 and 2015:

 Three Months Ended
December 31,
 Twelve Months Ended
December 31,
 2016 2015 2016 2015
Lease operating expenses$16.9  $14.2  $60.0  $57.0 
Production taxes11.7  5.2  31.4  18.4 
Transportation, gathering and processing expenses4.9  3.6  18.4  10.2 
Total$33.5  $23.0  $109.8  $85.6 
Lease operating expenses per Boe$2.65  $2.97  $2.70  $3.71 

Full Year 2016 Results

Net loss for 2016 was $245.9 million, or $5.01 per diluted share, compared to net loss of $68.3 million, or $1.74 per diluted share, for 2015.  The year-over-year difference was primarily attributable to a decrease in fair value of unsettled derivatives and the allowance for uncollectible notes receivable of $44.0 million recorded in the first quarter 2016.  Adjusted net loss, a non-GAAP measure defined below, was $37.0 million, or $0.75 per diluted share in 2016 compared to $46.1 million, or $1.18 per diluted share in 2015.

Net cash from operating activities was $486.3 million for 2016, compared to $411.1 million for 2015.  Adjusted cash flows from operations, a non-GAAP financial measure defined below, were $466.8 million for 2016, compared to $420.8 million in 2015.  The increase in 2016 cash flows was primarily a result of increased production volumes more than offsetting the lower average oil prices as compared to the prior year.

Crude oil, natural gas and NGLs sales, excluding net settlements on derivatives, increased 31% to $497.4 million in 2016, compared to $378.7 million in 2015.  The sales price per Boe, excluding net settlements on derivatives, was $22.43 in 2016 compared to $24.64 in 2015.  Including the net settlements on derivatives, crude oil, natural gas and NGLs revenues increased 14% to $705.4 million in 2016 from $617.6 million in 2015.

Net commodity price risk management activities for 2016 resulted in a loss of $125.7 million compared to a gain of $203.2 million in 2015.  The 2016 loss was comprised of $208.1 million in net settlement gains and a $333.8 million decrease in the fair value of commodity derivatives.  Net settlements in 2015 were $238.9 million with a decrease in fair value associated with commodity derivatives of $35.7 million.

Production costs for 2016, which include LOE, production taxes and TGP, were $109.8 million, or $4.95 per Boe, approximately 11% less on a per Boe basis compared to $85.6 million, or $5.57 per Boe, for 2015.  LOE per Boe was $2.70 for 2016, approximately 27% less than 2015 levels of $3.71.  The decrease in both production costs and LOE on a per Boe basis in 2016 was primarily due to increased production volumes.

General and administrative expense ("G&A") was $112.5 million for 2016 compared to $90.0 million in 2015.  The increase in G&A in 2016 includes $12.2 million of fees and expenses related to the Acquisitions.  G&A per Boe, net of one-time Acquisitions related fees, decreased 23% to $4.52 for 2016, compared to $5.85 for 2015, due to the increase in production volumes.

Depreciation, depletion and amortization expense ("DD&A") related to crude oil and natural gas properties was $413.1 million, or $18.63 per Boe in 2016, compared to $298.8 million, or $19.44 per Boe in 2015.  The decrease in weighted-average DD&A rate in 2016 compared to 2015 was due to increased production more than offsetting the increase in total DD&A.  DD&A from all sources, including gas marketing, was $416.9 million in 2016 compared to $303.3 million in 2015.

Driven by the issuance of the 6.125% 2024 Senior Notes and the 1.125% 2021 Convertible Senior Notes that helped fund the Acquisitions, interest expense increased in 2016.  Interest expense for 2016 was $62.0 million compared to $47.6 million for 2015.  The increase in interest expense was primarily related to the $9.3 million bridge loan commitment charge and incremental issuance from the new debt issuances of $5.2 million.

PDC's available liquidity as of December 31, 2016 was $932.4 million, compared to $652.2 million as of December 31, 2015.  In October 2016, the Company elected to increase the aggregate commitment on its revolving credit facility from $450 million to $700 million

The Company's capital investment in the development of oil and natural gas properties and other capital expenditures, net of changes to accounts payable, was $399.9 million during 2016 compared to $559.4 million in 2015.  The 28% decrease in capital investment was primarily attributable to a decrease in Wattenberg rig count as well as the decreases in drilling and completion costs realized in 2016.

Fourth Quarter 2016 Results

Net loss for the fourth quarter of 2016 was $55.6 million, or $0.94 per diluted share, compared to net income of $3.0 million, or $0.07 per diluted share, for the fourth quarter of 2015.  The difference between quarterly net loss in 2016 and net income in 2015 was attributable to the combination of an increase in production and revenues in 2016, as described below, and an expense related to the difference in fair value of commodity derivatives of $89.1 million between the two periods.  Adjusted net income, a non-U.S. GAAP financial measure defined below, was $10.7 million for the fourth quarter of 2016, compared to $12.0 million for the same 2015 period.

Net cash from operating activities was $125.4 million in the fourth quarter of 2016, compared to $128.1 million in the fourth quarter of 2015.  The year-over-year decrease in net cash from operating activities was primarily due to a decrease in net working capital as compared between periods.  Adjusted cash flows from operations were $140.5 million in the fourth quarter of 2016, compared to $127.2 million in the same 2015 period.

Fourth quarter 2016 production increased 34% to 69,620 Boe/d, compared to 51,980 Boe/d in the fourth quarter of 2015, and increased 7% compared to 65,265 Boe/d in the third quarter of 2016. The increase in fourth quarter 2016 production was due to ongoing successful horizontal drilling in the Wattenberg Field and the inclusion of 0.2 MMBoe of production in December from the Delaware Basin.

Crude oil, natural gas and NGLs sales were $169.3 million in the fourth quarter of 2016, compared to $103.2 million in the fourth quarter of 2015.  The average sales price, excluding net settlements on derivatives, improved to $26.44 per Boe for the fourth quarter of 2016, compared to $21.58 per Boe for the same 2015 period.

Net commodity price risk management activities for the fourth quarter of 2016 resulted in a loss of $63.3 million, which was comprised of $40.3 million of net settlement gains on derivatives and a decrease of $103.7 million in fair value of commodity derivatives, resulting in a net liability of $70.0 million as of December 31, 2016.

Production costs in the quarter were $33.5 million, or $5.23 per Boe, compared to $23.0 million, or $4.82 per Boe, for the fourth quarter of 2015.  LOE per Boe was $2.65 for the fourth quarter of 2016, approximately 11% less than 2015 levels of $2.97.  The decrease in both production costs and LOE on a per Boe basis in 2016 was due to increased production volumes.

G&A was $33.6 million for the fourth quarter of 2016, an increase from $27.9 million for the fourth quarter of 2015, primarily due to increases in incentive compensation and a 9% increase in personnel over the course of 2016. G&A on a per Boe basis was $5.25 for the fourth quarter of 2016, a decrease of 10% from the 2015 level of $5.84.

DD&A per Boe decreased to $15.41 in the fourth quarter of 2016, compared to $19.91 per Boe in the fourth quarter of 2015 driven by the increase in the Company's proved reserves.  DD&A from all sources in the fourth quarter were $99.5 million and $96.4 million in 2016 and 2015, respectively.

Interest expense for the fourth quarter of 2016 was $19.2 million compared to $12.2 million for the fourth quarter of 2015. The increase in interest expense was primarily related to interest accrued on the Senior Notes and Senior Convertible Notes issued in the third quarter of 2016.

Operations Update

The Company turned-in-line to sales its first Delaware operated well, the Argentine, in December 2016.  Early performance from the 4,600 foot lateral Wolfcamp A well, located in its Eastern acreage block, is encouraging, with an average 30-day initial peak production rate of approximately 1,185 Boe per day with approximately 72% oil.  Early production from the Argentine, as well as the Keyhole, Sugarloaf and Hanging H wells, continue to outperform the Company's 1,000 MBoe one-mile type curve associated with its Eastern acreage block Wolfcamp A wells.

In the Wattenberg, the Company's recently completed extended-reach lateral wells on the Connie and Bihain pads are performing above the 850 MBoe type curve, while the mid-reach lateral wells on the Cockroft pad continue to exceed its 685 MBoe type curve.  Completion spacing on all three pads averaged approximately 170 feet between stages.

2017 Capital Investment Outlook and Financial Guidance

The Company has accelerated its drilling in the Delaware Basin by adding a third drilling rig late in February, instead of the fourth quarter, as was previously planned.  As a result, the number of planned spuds, expected turn-in-lines and associated midstream capital expenditures have all increased from its original budget.  Additionally, given recent service cost increases in the Delaware Basin, the Company is increasing its previously disclosed projected well costs by approximately ten percent in the basin. The Company continues to place a high priority on executing its HBP strategy in the Delaware and maintains the flexibility to adjust its 2017 capital program if needed. 

By balancing the current priorities, the Company has elected to manage its total projected 2017 level of capital investment by slightly adjusting its Wattenberg drilling and completion schedule and deferring Utica drilling in 2017 while it considers various strategic options with the Utica asset.  The full-year capital investment is now expected to be at the top-end of the Company's previously announced range of $725 million to $775 million.  Full-year production guidance is unchanged at 30 to 33 MMBoe as the incremental turn-in-lines will be late in the year with limited contribution to 2017 volumes.

The following table provides projected 2017 financial guidance:

  Low High 
Production (MMBoe)   30.0    33.0  
Capital Expenditures (millions)  $725   $775  
Operating Expenses         
Lease operating expense ($/Boe)  $2.80   $3.10  
Transportation, gathering & processing expense ($/Boe)  $0.85   $0.95  
Production taxes (% of Crude Oil, Natural Gas & NGL Sales)   6%    8%  
General & Administrative expense ($/Boe)  $3.25   $3.60  
Depreciation, depletion and amortization ($/Boe)  $15.10   $16.65  
Estimated Price Realizations (% of NYMEX) (excludes TGP)       
Gas  72-74% 
NGLs  28-30% 

Non-GAAP Financial Measures

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

Adjusted Cash Flows from Operations
 Three Months Ended
December 31,
 Twelve Months Ended
December 31,
 2016 2015 2016 2015
Adjusted cash flows from operations:       
Net cash from operating activities$125.5  $128.1  $486.3  $411.1 
Changes in assets and liabilities15.1  (0.9) (19.5) 9.7 
Adjusted cash flows from operations$140.6  $127.2  $466.8  $420.8 

Adjusted Net Income (Loss)
 Three Months Ended
December 31,
 Twelve Months Ended
December 31,
 2016 2015 2016 2015
Adjusted net income (loss):       
Net income (loss)$(55.6)  $3.0  $(245.9) $(68.3)
Gain (loss) on commodity derivative instruments63.3  (62.0) 125.6  (203.2)
Net settlement gain (loss) on commodity derivative instruments instruments40.3  76.5  208.2  239.0 
Tax effect of above adjustments(37.3) (5.5) (124.9) (13.6)
Adjusted net income (loss)$10.7  $12.0  $(37.0) $(46.1)
Weighted-average diluted shares outstanding58.9  41.3  49.1  39.2 
Adjusted diluted net income (loss) per share$0.18  $0.29  $(0.75) $(1.18)

Adjusted EBITDA
 Three Months Ended
December 31,
 Twelve Months Ended
December 31,
 2016 2015 2016 2015
Net income (loss) to adjusted EBITDA:       
Net income (loss)$(55.6) $3.0  $(245.9) $(68.3)
Gain (loss) on commodity derivative instruments, including net settlements63.3  (62.0) 125.6  (203.2)
Net settlement gain (loss) on commodity derivative instruments40.3  76.5  208.2  239.0 
Interest expense, net20.1  11.0  61.0  42.8 
Income tax provision (benefit)(35.0) 2.3  (147.2) (38.3)
Impairment of properties and equipment3.9  0.4  10.0  161.6 
Depreciation, depletion and amortization99.5  96.4  416.9  303.3 
Accretion of asset retirement obligations1.7  1.5  7.0  6.3 
Adjusted EBITDA$138.2  $129.1  $435.6  $443.2 
Cash from operating activities to adjusted EBITDA:       
Net cash from operating activities$125.5  $128.1  $486.3  $411.1  
Interest expense, net20.1  11.0  61.0  42.8 
Stock-based compensation(4.3) (5.8) (19.5) (20.1)
Amortization of debt discount and issuance costs(3.2)  (1.7) (16.2) (7.0)
Gain on sale of properties and equipment  0.1    0.4 
Other(15.0) (1.7) (56.5) 6.3 
Changes in assets and liabilities15.1  (0.9) (19.5) 9.7 
Adjusted EBITDA$138.2  $129.1  $435.6  $443.2 

Consolidated Statements of Operations
(unaudited, in thousands, except per share data)
 Three Months Ended
December 31,
 Twelve Months Ended
December 31,
 2016 2015 2016 2015
Crude oil, natural gas, and NGLs sales$169,340  $103,193  $497,353  $378,713 
Sales from gas marketing1,997  2,584  8,725  10,920 
Commodity price risk management gain (loss), net of settlements(63,333) 62,013  (125,681) 203,183 
Other income93  844  2,518  2,510 
Total revenues108,097  168,634  382,915  595,326 
Costs, expenses and other       
Lease operating expenses16,944  14,244  59,950  56,992 
Production taxes11,728  5,237   31,410  18,443 
Transportation, gathering and processing expenses4,861  3,567  18,415  10,151 
Cost of gas marketing2,398  2,842  10,193  11,717 
Exploration expense3,981  290  4,669  1,102 
Impairment of properties and equipment3,869  413  9,973  161,620 
General and administrative expense33,602  27,908  112,470  89,959 
Depreciation, depletion and amortization99,545  96,385  416,874  303,258 
Provision for uncollectible notes receivable    44,038   
Accretion of asset retirement obligations1,680  1,551  7,080  6,293 
(Gain) loss on sale of properties and equipment  (83 ) (43) (385)
Total cost, expenses and other178,608  152,354  715,029  659,150 
Income (loss) from operations(70,511) 16,280  (332,114) (63,824)
Interest expense(19,213) (12,187 ) (61,972) (47,571)
Interest income(912) 1,181   963  4,807 
Income (loss) before income taxes(90,636) 5,274   (393,123) (106,588)
Income tax benefit (expense)34,997  (2,252) 147,195  38,308 
Net income (loss)$(55,639) $3,022  $(245,928) $(68,280)
Earnings per share:       
Basic$(0.94) $0.08  $(5.01 ) $(1.74)
Diluted$(0.94) $0.07  $(5.01) $(1.74)
Weighted-average common shares outstanding:       
Basic58,914  40,094  49,052  39,153 
Diluted58,914  41,264  49,052  39,153 

Consolidated Balance Sheets
(unaudited, in thousands)
As of December 31, 2016 2015
Current assets:    
Cash and cash equivalents $244,100  $850 
Accounts receivable, net 143,392  104,274 
Fair value of derivatives 8,791  221,659 
Prepaid expenses and other current assets 3,542  5,266 
Total current assets 399,825  332,049 
Properties and equipment, net 4,008,266   1,940,552 
Fair value of derivatives 2,386  44,387 
Goodwill 62,041  - 
Other assets 13,324  53,555 
Total Assets $4,485,842  $2,370,543 
Liabilities and Stockholders' Equity    
Current liabilities:    
Accounts payable $66,322  $92,613 
Production tax liability 24,767  26,524 
Fair value of derivatives 53,595  1,595 
Funds held for distribution 71,339  29,894 
Current portion of long-term debt   112,940 
Accrued interest payable 15,930  9,057 
Other accrued expenses 38,625  28,709 
Total current liabilities 270,578  301,332 
Long-term debt 1,043,954  529,437 
Deferred income taxes 400,867  143,452 
Asset retirement obligations 82,612  84,032 
Fair value of derivatives 27,595  695 
Other liabilities 37,482   24,398 
Total liabilities 1,863,088  1,083,346 
Commitments and contingent liabilities    
Stockholders' equity    
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,704,568 and 40,174,776 issued as of December 31, 2016 and 2015, respectively 657  402 
Additional paid-in capital 2,489,557   907,382 
Retained earnings 134,208  380,422 
Treasury shares - at cost, 28,763 and 20,220 as of December 31, 2016 and 2015, respectively (1,668) (1,009)
Total stockholders' equity 2,622,754  1,287,197 
Total Liabilities and Stockholders' Equity $4,485,842  $2,370,543 

Consolidated Statements of Cash Flows
(unaudited, in thousands)
 Three Months Ended
December 31,

 Twelve Months Ended
December 31,
 2016 2015
Cash flows from operating activities:         
Net income (loss)$(55,639) $3,022  $(245,928) $(68,280)
Adjustments to net income (loss) to reconcile to net cash from operating activities:         
Net change in fair value of unsettled commodity derivatives 103,593   14,469   333,770  35,791 
Depreciation, depletion and amortization 99,545   96,385  416,874  303,258 
Provision for uncollectible notes receivable      44,038   
Impairment of properties and equipment 3,869   413  9,973  161,620 
Accretion of asset retirement obligation 1,680   1,551  7,080  6,293 
Stock-based compensation 4,297   5,790  19,502  20,068 
Excess tax benefits from stock-based compensation 1,062   (129)   (1,361)
Gain from sale of properties and equipment    (83) (43) (385)
Amortization of debt discount and issuance costs 3,216   1,732  16,167  7,040 
Deferred income taxes (23,113)  3,355  (137,249) (41,415)
Other 2,067   711  2,603  (1,855)
Total adjustments to net income (loss) to reconcile to net cash from operating activities: 196,216   124,194  712,715  489,054 
Changes in assets and liabilities:         
Accounts receivable (36,460)  1,219  (32,627) 24,769 
Other assets 1,424   (46) 2,303  (2,264)
Restricted cash        46 
Production tax liability  13,114   6,212  9,223  (1,629)
Accounts payable and accrued expenses (3,755)  6,575  (162) (30,310)
Funds held for future distribution  15,167   (2,882) 36,510  2,699 
Other liabilities (4,635 )  (10,227) 4,229  (3,012)
Total changes in assets and liabilities (15,145)  851  19,476  (9,701)
Net cash from operating activities 125,432   128,067  486,263  411,073 
Cash flows from investing activities:         
Capital expenditures for development of crude oil and natural gas properties (84,671)  (112,066) (436,884)  (599,546)
Capital expenditures for other properties and equipment (1,955)  (3,566) (3,464) (5,122)
Acquisition of crude oil and natural gas properties, net of cash acquired (973,723)    (1,073,723 )  
Proceeds from sale of properties and equipment, net    86  4,945  405 
Net cash from investing activities (1,060,349)  (115,546) (1,509,126) (604,263)
Cash flows from financing activities:         
Proceeds from sale of equity, net of issuance costs 2     855,074  202,851 
Proceeds from senior notes, net of issuance costs (78)    392,172   
Proceeds from convertible senior notes, net of issuance costs (44)    193,935   
Proceeds from revolving credit facility    72,000  85,000  397,000 
Repayment of revolving credit facility    (85,000) (122,000) (416,000)
Redemption of convertible notes      (115,000)  
Payment of debt issuance costs (15,502)  (924) (15,556) (974)
Excess tax benefits from stock-based compensation (1,062)  129    1,361 
Purchase of treasury shares (1,829)  (1,480) (6,935) (6,056)
Other (162)  (86) (577) (208)
Net cash from financing activities (18,675)  (15,361) 1,266,113  177,974 
Net change in cash and cash equivalents  (953,592)  (2,840) 243,250  (15,216)
Cash and cash equivalents, beginning of year 1,197,692   3,690  850  16,066 
Cash and cash equivalents, end of year$244,100  $850  $244,100  $850 

2016 Year-End and Fourth 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, Senior Vice President Chief Operating Officer, for a conference call on Tuesday, February 28, 2017, to discuss its 2016 year-end and fourth quarter results. The related slide presentation will be available on PDC's website at www.pdce.com.

Conference Call and Webcast:
Date/Time: Tuesday, February 28, 2017, 11:00 a.m. ET
Webcast available at: www.pdce.com
Domestic (toll free): 877-312-5520
International: 253-237-1142
Conference ID: 51808845

Replay Numbers:
Domestic (toll free): 855-859-2056
International: 404-537-3406
Conference ID: 51808845

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: Scotia Howard Weil Energy Conference in New Orleans on Tuesday, March 28, 2017 and IPAA New York on Tuesday, April 4, 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 acquires, produces, develops, and explores for crude oil, natural gas and NGLs with operations in the Wattenberg Field in Colorado, in the Delaware Basin in West Texas and in the Utica Shale in Southeastern Ohio. Its operations are focused on the liquid-rich horizontal Niobrara and Codell plays in the Wattenberg Field, the liquid-rich Wolfcamp zones in the Delaware Basin, and the condensate and wet gas portion of the Utica Shale play.


This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding PDC's business, financial condition, results of operations, and prospects. All statements other than statements of historical facts included in this press release are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates, guidance 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: reserves, production, costs, cash flows and earnings; drilling locations and growth opportunities; levels of capital investment and project details, 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 PDC's good faith judgment, such statements can only be based on facts and factors currently known to the Company.  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 certain future scenarios have been "modeled".  PDC typically uses these terms to indicate the 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;
  • volatility of commodity prices for crude oil, natural gas, and NGLs and the risk of an extended period of depressed prices;
  • reductions in the borrowing base under the Company's revolving credit facility;
  • impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder, and the costs to comply with those laws and regulations;
  • declines in the value of crude oil, natural gas, and NGLs properties resulting in further impairments;
  • changes in estimates of proved reserves;
  • inaccuracy of estimated reserves and production rates;
  • potential for production decline rates from the Company's wells being greater than expected;
  • timing and extent of PDC's success in discovering, acquiring, developing, and producing reserves;
  • availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport 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 segment exceeding expectations;
  • difficulties in integrating operations as a result of any significant acquisitions, including the 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;
  • increases or adverse changes in construction costs and procurement costs associated with future build out of mid-stream 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 PDC's ability to insure adequately against such events;
  • cost of pending or future litigation;
  • effect that acquisitions that the Company may pursue have on capital investments;
  • PDC's ability to retain or attract senior management and key technical employees; and
  • success of strategic plans, expectations and objectives for future operations.

Further, PDC urges you to carefully review and consider the cautionary statements and disclosures made in this press release and specifically those under Item 1A, Risk Factors, found in its filings with the U.S. Securities and Exchange Commission ("SEC") for further information on risks and uncertainties that could affect its business, financial condition, results of operations and cash flows.  The Company cautions you not to place undue reliance on forward-looking statements, which speak only as of the date of this press release.  PDC undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this press release 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.



Michael Edwards

Senior Director Investor Relations



Kyle Sourk

Manager Investor Relations



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Source: PDC Energy

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