CDN NEWS | 
US NEWS 
DENVER, Feb. 27, 2019 (GLOBE NEWSWIRE) — PDC Energy, Inc. (“PDC” or the “Company”) (NASDAQ: PDCE) today reported its 2018 full-year and fourth quarter operating and financial results and provided detailed 2019 guidance and preliminary 2020 outlook.
2018 Highlights
- Full-year net cash from operating activities of approximately $890 million, a 49 percent increase compared to 2017.
- Year-over-year production increase of 26 percent to 40.2 million barrels of oil equivalent (“MMBoe”) or approximately 110,000 Boe per day with a December exit rate of approximately 130,000 Boe per day.
- Oil production of 17.0 million barrels (“MMBbls”), representing 42 percent of total production and a 32 percent increase from 2017.
- Strengthened financial position including 2018 year-end liquidity of approximately $1.3 billion and a year-end leverage ratio, as defined by the Company’s revolving credit agreement, of 1.4 times compared to 1.9 times at year-end 2017.
- Increase in year-end proved reserves of approximately 20 percent to 545 MMBoe, with all-sources reserve replacement of approximately 330 percent.
- Added high-value Kersey inventory and consolidated Prairie Area of the Wattenberg Field through a strategic acreage trade that significantly enhances operational efficiencies through increased working interests and longer-laterals while reducing anticipated surface footprint.
CEO Commentary
President and Chief Executive Officer, Bart Brookman commented, “I’m very pleased with our team’s ability to exit 2018 on such a strong note and deliver a great fourth quarter. Our operating results underscore the value and potential of our high-quality portfolio. We have built tremendous momentum and established the foundation needed to execute upon what we deem to be a tremendous multi-year outlook.
“Our board and management remain aligned and focused on creating long-term shareholder value through capital discipline, free cash flow generation and returns-based investment, as seen in our approximate $150 million, or 15 percent reduction in capital investments in our 2019 capital plan compared to 2018. Our entire team is firmly committed to this operating philosophy and we expect to generate substantial free cash flow in excess of $100 million in 2020 in a $50 WTI environment. Further, we plan improvements to our executive compensation plan to reflect these corporate priorities through the institution of two new corporate metrics: cash flow per debt-adjusted share and free cash flow as a percent of total capital investment. These metrics, coupled with our existing capital efficiency, LOE and G&A per Boe and production metrics, will help us remain laser-focused on cost management while running a sustainable business model designed to create maximum long-term value for our shareholders.”
Operations Update
Production for 2018 was 40.2 MMBoe, or approximately 110,000 Boe per day, an increase of 26 percent from 2017. Oil production of 17.0 MMBbls in 2018 represents 42 percent of total production and was an increase of 32 percent compared to 2017 volumes. In the fourth quarter of 2018, production was approximately 11.8 MMBoe, an increase of 36 percent from the fourth quarter of 2017 and 17 percent from the third quarter of 2018. Oil production in the fourth quarter of 2018 was 4.9 MMBbls, representing 42 percent of total production and an increase of 32 percent compared to the fourth quarter of 2017.
The Company’s capital investment in the development of oil and natural gas properties, before the change in accounts payable and excluding corporate capital, was approximately $985 million and $207 million for the full-year and fourth quarter of 2018, respectively.
In Wattenberg, the Company spud 161 wells and turned-in-line (“TIL”) 139 wells in 2018, including 40 spuds and 40 TILs in the fourth quarter. Production for the year averaged approximately 84,000 Boe per day and benefited from third-party midstream expansions in the latter half of the year as second half production of approximately 90,000 Boe per day represented a 17 percent increase compared to first half production of approximately 77,500 Boe per day.
In the Delaware Basin, the Company spud 31 wells and TIL’d 26 wells in 2018, including nine spuds and four TILs in the fourth quarter. Production from the basin averaged approximately 26,000 Boe per day in 2018 and steadily increased from approximately 21,000 Boe per day in the first quarter to nearly 31,000 Boe per day in the fourth quarter, which included a full-quarter’s worth of production from the Company’s eight-well Grizzly Pad. This pad was placed on artificial lift late in the fourth quarter and has since seen the production profile stabilize.
2019 Capital Investment Outlook, Financial Guidance and Transactions Update
As previously disclosed in the Company’s capital budget release on February 11, 2019, the Company has prepared a 2019 budget which balances long-term sustainable free cash flow generation with profitable growth under a $50 WTI oil price and $3 NYMEX gas price environment. The Company’s 2019 anticipated capital investment range of $810 million and $870 million, excluding corporate capital of $20 million, reflects a reduction of approximately $150 million, or 15 percent, compared to 2018 levels. PDC expects to generate adjusted cash flows from operations of approximately $25 million in excess of this investment, assuming $50 per barrel WTI. If oil were to average $55 per barrel WTI, the Company would expect its adjusted cash flows to exceed its capital investments by approximately $65 million.
Production for 2019 is expected to increase 20 percent over 2018 levels to a range of 46 to 50 MMBoe, or approximately 126,000 to 137,000 Boe per day. The 2019 commodity mix is expected to be 41 to 45 percent crude oil, 21 to 23 percent NGLs and 33 to 37 percent natural gas. Furthermore, the Company expects its daily production in the fourth quarter of 2019 to increase five to ten percent compared to the fourth quarter rate of 2018, which was approximately 128,000 Boe per day.
PDC expects to spend approximately 60 percent of its total capital in Wattenberg to spud 135 to 150 wells and TIL 110 to 125 wells with average working interest of approximately 93 percent. Recent strategic acreage trades have enabled the Company to increase the expected average lateral length of its TIL program by more than 25 percent to approximately 8,000 feet in 2019 compared to approximately 6,300 feet in 2018. Anticipated well costs for 2019 are expected to remain unchanged at $3 million to $5 million depending on lateral length. Similar to 2018, 2019 guidance contemplates a multi-month easing of field-wide line pressures that coincides with third-party midstream processing expansions. The Company expects that the benefits of third-party midstream processing expansions will begin to be realized in June 2019.
Approximately 40 percent of 2019 capital is expected to be invested in the Delaware Basin to spud 25 to 30 wells and TIL 20 to 25 wells with average working interest of approximately 93 percent. The Company plans to operate at a two and half rig pace throughout the year while utilizing a part-time completion crew. In an effort to enhance efficiencies and improve returns, PDC expects to increase the length of its average Delaware Basin TILs by more than 25 percent compared to 2018 to a length of approximately 9,200 feet. Additionally, the Company plans to modify its completion design by slightly reducing the amount of proppant per foot while increasing the average distance between completion stages. These modifications have resulted in a decrease in expected well costs to an estimated $11.5 million to $13 million for mid- and extended-reach laterals. There are no standard-reach lateral wells planned in 2019.
As previously announced, the Company continues to work towards the monetization of its Delaware Basin midstream assets which is expected to be executed in the first half of 2019.
The following table provides projected 2019 financial guidance:
| Low | High | |||||||||||||
| Production (MMBoe) | 46.0 | 50.0 | ||||||||||||
| Capital Investments(1) (millions) | $ | 810 | $ | 870 | ||||||||||
| Operating Expenses | ||||||||||||||
| Lease operating expenses (“LOE”)($/Boe) | $ | 2.85 | $ | 3.15 | ||||||||||
| Transportation, gathering & processing expense (“TGP”)($/Boe) | $ | 0.80 | $ | 1.00 | ||||||||||
| Production taxes (% of Crude oil, natural gas & NGLs sales) | 6 | % | 7 | % | ||||||||||
| General and administrative expense ($/Boe) | $ | 3.00 | $ | 3.40 | ||||||||||
| Estimated Price Realizations (% of NYMEX) (excludes TGP) | ||||||||||||||
| Crude Oil | 90 | % | 95 | % | ||||||||||
| Natural Gas | 50 | % | 55 | % | ||||||||||
| NGLs | 30 | % | 35 | % | ||||||||||
(1) Excludes corporate capital of approximately $20 million
In 2020, the Company is currently contemplating continuation of its second half 2019 five rig program. Utilizing a $50 WTI oil price and $3 NYMEX gas price, and holding all differentials and well costs constant, the Company expects its preliminary 2020 outlook to deliver improved levels of financial performance with anticipated free cash flow in excess of $100 million and LOE and G&A costs of less than $3 per Boe, respectively, with production growth of approximately 10 to 15 percent.
Oil and Gas Production, Sales and Operating Cost Data
Crude oil, natural gas and NGLs sales, excluding net settlements on derivatives, increased 52 percent to $1,390.0 million in 2018, compared to $913.1 million in 2017. The increase in sales was due to a 26 percent increase in total production and an increase in the sales price per Boe, excluding net settlements on derivatives, of 21 percent to $34.61 in 2018 from $28.69 in 2017. Including the impact of commodity price risk management, revenues increased 68 percent to $1,548.7 million in 2018 from $921.6 million in 2017.
In the fourth quarter of 2018, crude oil, natural gas and NGLs sales were $386.4 million, compared to $277.1 million in the fourth quarter of 2017. The average sales price, excluding net settlements on derivatives, improved to $32.83 per Boe for the fourth quarter of 2018, compared to $32.00 per Boe for the same 2017 period.
The following table provides production and weighted-average sales price, by area, for the three and twelve months ended December 31, 2018 and 2017, excluding net settlements on derivatives and TGP:
| Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||
| 2018 | 2017 | Percent Change |
2018 | 2017 | Percent Change |
||||||||||||||||
| Crude oil (MBbls) | |||||||||||||||||||||
| Wattenberg Field | 3,733 | 3,039 | 22.8 | % | 12,809 | 10,922 | 17.3 | % | |||||||||||||
| Delaware Basin | 1,190 | 624 | 90.7 | % | 4,108 | 1,699 | 141.8 | % | |||||||||||||
| Utica Shale(1) | — | 55 | (100.0 | )% | 46 | 281 | (83.6 | )% | |||||||||||||
| Total | 4,923 | 3,718 | 32.4 | % | 16,963 | 12,902 | 31.5 | % | |||||||||||||
| Weighted-Average Sales Price | $ | 55.71 | $ | 52.79 | 5.5 | % | $ | 61.19 | $ | 48.45 | 26.3 | % | |||||||||
| Natural gas (MMcf) | |||||||||||||||||||||
| Wattenberg Field | 20,157 | 15,412 | 30.8 | % | 68,326 | 60,106 | 13.7 | % | |||||||||||||
| Delaware Basin | 5,820 | 3,358 | 73.3 | % | 19,277 | 9,410 | 104.9 | % | |||||||||||||
| Utica Shale(1) | — | 482 | (100.0 | )% | 414 | 2,173 | (80.9 | )% | |||||||||||||
| Total | 25,977 | 19,252 | 34.9 | % | 88,017 | 71,689 | 22.8 | % | |||||||||||||
| Weighted-Average Sales Price | $ | 2.30 | $ | 2.16 | 6.5 | % | $ | 1.85 | $ | 2.21 | (16.3 | )% | |||||||||
| NGLs (MBbls) | |||||||||||||||||||||
| Wattenberg Field | 1,839 | 1,403 | 31.1 | % | 6,455 | 5,876 | 9.9 | % | |||||||||||||
| Delaware Basin | 678 | 292 | 132.2 | % | 2,038 | 917 | 122.2 | % | |||||||||||||
| Utica Shale(1) | — | 37 | (100.0 | )% | 34 | 188 | (81.9 | )% | |||||||||||||
| Total | 2,517 | 1,732 | 45.3 | % | 8,527 | 6,981 | 22.1 | % | |||||||||||||
| Weighted-Average Sales Price | $ | 20.79 | $ | 22.68 | (8.3 | )% | $ | 22.14 | $ | 18.59 | 19.1 | % | |||||||||
| Crude oil equivalent (MBoe) | |||||||||||||||||||||
| Wattenberg Field | 8,931 | 7,010 | 27.4 | % | 30,652 | 26,815 | 14.3 | % | |||||||||||||
| Delaware Basin | 2,839 | 1,475 | 92.5 | % | 9,359 | 4,184 | 123.7 | % | |||||||||||||
| Utica Shale(1) | — | 173 | (100.0 | )% | 149 | 831 | (82.1 | )% | |||||||||||||
| Total | 11,770 | 8,658 | 35.9 | % | 40,160 | 31,830 | 26.2 | % | |||||||||||||
| Weighted-Average Sales Price | $ | 32.83 | $ | 32.00 | 2.6 | % | $ | 34.61 | $ | 28.69 | 20.6 | % | |||||||||
(1) In March 2018, the Company completed the disposition of its Utica Shale properties.
Production costs for 2018, which include LOE, production taxes and TGP, were $258.8 million, or $6.44 per Boe, compared to $183.5 million, or $5.77 per Boe, for 2017. LOE per Boe was $3.26 for 2018 compared to $2.82 per Boe in 2017. The increase in LOE per Boe is primarily due to the negative impact third party processing limitations and associated high line pressures had on both Wattenberg production volumes and costs. In the fourth quarter of 2018, production costs were $71.5 million, or $6.08 per Boe, compared to $53.3 million or $6.15 per Boe in the comparable 2017 period.
The following table provides the components of production costs for the three and twelve months ended December 31, 2018 and 2017:
| Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||
| 2018 | 2017 | 2018 | 2017 | ||||||||||||
| Lease operating expenses | $ | 36.0 | $ | 24.5 | $ | 131.0 | $ | 89.6 | |||||||
| Production taxes | 23.6 | 17.8 | 90.4 | 60.7 | |||||||||||
| Transportation, gathering and processing expenses | 11.9 | 11.0 | 37.4 | 33.2 | |||||||||||
| Total | $ | 71.5 | $ | 53.3 | $ | 258.8 | $ | 183.5 | |||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||
| 2018 | 2017 | 2018 | 2017 | ||||||||||||
| Lease operating expenses per Boe | $ | 3.06 | $ | 2.83 | $ | 3.26 | $ | 2.82 | |||||||
| Production taxes per Boe | 2.01 | 2.05 | 2.25 | 1.91 | |||||||||||
| Transportation, gathering and processing expenses per Boe | 1.01 | 1.27 | 0.93 | 1.04 | |||||||||||
| Total per Boe | $ | 6.08 | $ | 6.15 | $ | 6.44 | $ | 5.77 | |||||||
Financial Results and Liquidity
Net income for 2018 was $2.0 million, or $0.03 per diluted share, compared to net loss of $127.5 million, or $1.94 per diluted share, in 2017. The year-over-year difference is primarily attributable to the increase in revenues between periods outweighing the year-over-year increase in impairment of properties and equipment. Adjusted net loss, a non-GAAP financial measure defined below, was $196.3 million, or $2.96 per diluted share, in 2018 compared to an adjusted net loss of $114.4 million, or $1.74 per diluted share in 2017.
Net income for the fourth quarter of 2018 was $178.9 million, or $2.71 per diluted share, and includes a fourth quarter impairment of $264.2 million related to non-focus area Delaware Basin leaseholds. These leaseholds typically feature a higher gas-to-oil ratio and are more geologically complex than the Company’s other Delaware Basin properties. Net income in the fourth quarter of 2017 was $77.6 million, or $1.17 per diluted share. The difference between periods was due to the increase in fair value of derivatives more than offsetting the impairment. Adjusted net loss for the fourth quarter of 2018 was $146.7 million, or $2.22 per diluted share, compared to adjusted net income of $130.9 million, or $1.98 per diluted share, for the same 2017 period.
Net cash from operating activities was $889.3 million for 2018, compared to $597.8 million for 2017. Adjusted cash flows from operations, a non-GAAP financial measure defined below, were $808.4 million for 2018, compared to $582.1 million in 2017. Net cash from operating activities in the fourth quarter of 2018 was $311.5 million, compared to $177.2 million in the fourth quarter of 2017. Adjusted cash flows from operations were $233.1 million for the fourth quarter of 2018, compared to $174.6 million in the same 2017 period. The increase in cash flows between comparable periods was a result of more production volumes coupled with a higher average oil prices as compared to the prior year.
General and administrative expense (“G&A”), which includes cash and non-cash compensation expense, was $170.5 million, or $4.25 per Boe in 2018 compared to $120.4 million, or $3.78 per Boe in 2017. The twelve percent increase in G&A per Boe between periods includes $16.5 million in legal-related expense and $13.0 million in government relations expense in 2018.
PDC’s available liquidity as of December 31, 2018 was approximately $1.3 billion, compared to approximately $881 million as of December 31, 2017. In October 2018, the Company increased the commitment level on its revolving credit facility from $700 million to $1.3 billion.
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 we use 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 our financial statements and publicly filed reports in their entirety and not rely on any single financial measure.
The following three 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 December 31, |
Twelve Months Ended December 31, |
||||||||||||||
| 2018 | 2017 | 2018 | 2017 | ||||||||||||
| Adjusted cash flows from operations: | |||||||||||||||
| Net cash from operating activities | $ | 311.5 | $ | 177.2 | $ | 889.3 | $ | 597.8 | |||||||
| Changes in assets and liabilities | (78.4 | ) | (2.6 | ) | (80.9 | ) | (15.7 | ) | |||||||
| Adjusted cash flows from operations | $ | 233.1 | $ | 174.6 | $ | 808.4 | $ | 582.1 | |||||||
| Adjusted Net Income (Loss) | |||||||||||||||
| Three Months Ended December 31, |
Twelve Months Ended December 31, |
||||||||||||||
| 2018 | 2017 | 2018 | 2017 | ||||||||||||
| Adjusted net income (loss): | |||||||||||||||
| Net income (loss) | $ | 178.9 | $ | 77.6 | $ | 2.0 | $ | (127.5 | ) | ||||||
| (Gain) loss on commodity derivative instruments | (403.0 | ) | 90.4 | (145.2 | ) | 3.9 | |||||||||
| Net settlements on commodity derivative instruments | (25.0 | ) | (8.9 | ) | (115.5 | ) | 13.3 | ||||||||
| Tax effect of above adjustments | 102.4 | (28.2 | ) | 62.4 | (4.1 | ) | |||||||||
| Adjusted net income (loss) | $ | (146.7 | ) | $ | 130.9 | $ | (196.3 | ) | $ | (114.4 | ) | ||||
| Weighted-average diluted shares outstanding | 66.2 | 66.1 | 66.3 | 65.8 | |||||||||||
| Adjusted diluted earnings per share | $ | (2.22 | ) | $ | 1.98 | $ | (2.96 | ) | $ | (1.74 | ) | ||||
| Adjusted EBITDAX | |||||||||||||||
| Three Months Ended December 31, |
Twelve Months Ended December 31, |
||||||||||||||
| 2018 | 2017 | 2018 | 2017 | ||||||||||||
| Net income (loss) to adjusted EBITDAX: | |||||||||||||||
| Net income (loss) | $ | 178.9 | $ | 77.6 | $ | 2.0 | $ | (127.5 | ) | ||||||
| (Gain) loss on commodity derivative instruments | (403.0 | ) | 90.4 | (145.2 | ) | 3.9 | |||||||||
| Net settlements on commodity derivative instruments | (25.0 | ) | (8.9 | ) | (115.5 | ) | 13.3 | ||||||||
| Non-cash stock-based compensation | 5.4 | 4.8 | 21.8 | 19.4 | |||||||||||
| Interest expense, net | 18.1 | 19.6 | 70.3 | 76.4 | |||||||||||
| Income tax expense (benefit) | 59.1 | (140.4 | ) | 5.4 | (211.9 | ) | |||||||||
| Impairment of properties and equipment | 264.2 | 3.4 | 458.4 | 285.9 | |||||||||||
| Impairment of goodwill | — | — | — | 75.1 | |||||||||||
| Exploration, geologic and geophysical expense | 1.6 | 3.4 | 6.2 | 47.3 | |||||||||||
| Depreciation, depletion and amortization | 149.8 | 108.5 | 559.8 | 469.1 | |||||||||||
| Accretion of asset retirement obligations | 1.3 | 1.4 | 5.1 | 6.4 | |||||||||||
| Loss on extinguishment of debt | — | 24.7 | — | 24.7 | |||||||||||
| Adjusted EBITDAX | $ | 250.4 | $ | 184.5 | $ | 868.3 | $ | 682.1 | |||||||
| Cash from operating activities to adjusted EBITDAX: | |||||||||||||||
| Net cash from operating activities | $ | 311.5 | $ | 177.2 | $ | 889.3 | $ | 597.8 | |||||||
| Interest expense, net | 18.1 | 19.6 | 70.3 | 76.4 | |||||||||||
| Amortization of debt discount and issuance costs | (3.3 | ) | (3.3 | ) | (12.8 | ) | (12.9 | ) | |||||||
| Gain (loss) on sale of properties and equipment | 2.8 | — | (0.4 | ) | 0.7 | ||||||||||
| Exploration, geologic and geophysical expense | 1.6 | 3.4 | 6.2 | 47.3 | |||||||||||
| Exploratory dry hole costs | (0.1 | ) | (0.1 | ) | (0.1 | ) | (41.3 | ) | |||||||
| Other | (1.8 | ) | (9.7 | ) | (3.3 | ) | 29.8 | ||||||||
| Changes in assets and liabilities | (78.4 | ) | (2.6 | ) | (80.9 | ) | (15.7 | ) | |||||||
| Adjusted EBITDAX | $ | 250.4 | $ | 184.5 | $ | 868.3 | $ | 682.1 | |||||||
PDC ENERGY, INC.
Consolidated Statements of Operations
(unaudited, in thousands, except per share data)
| Three Months Ended December 31, |
Twelve Months Ended December 31, |
||||||||||||||
| 2018 | 2017 | 2018 | 2017 | ||||||||||||
| Revenues | |||||||||||||||
| Crude oil, natural gas and NGLs sales | $ | 386,364 | $ | 277,057 | $ | 1,389,961 | $ | 913,084 | |||||||
| Commodity price risk management gain (loss), net | 402,997 | (90,394 | ) | 145,237 | (3,936 | ) | |||||||||
| Other income | 5,450 | 2,853 | 13,461 | 12,468 | |||||||||||
| Total revenues | 794,811 | 189,516 | 1,548,659 | 921,616 | |||||||||||
| Costs, expenses and other | |||||||||||||||
| Lease operating expenses | 36,015 | 24,471 | 130,957 | 89,641 | |||||||||||
| Production taxes | 23,600 | 17,760 | 90,357 | 60,717 | |||||||||||
| Transportation, gathering and processing expenses | 11,892 | 11,036 | 37,403 | 33,220 | |||||||||||
| Exploration, geologic and geophysical expense | 1,651 | 3,439 | 6,204 | 47,334 | |||||||||||
| Impairment of properties and equipment | 264,167 | 3,388 | 458,397 | 285,887 | |||||||||||
| Impairment of goodwill | — | — | — | 75,121 | |||||||||||
| General and administrative expense | 49,321 | 35,225 | 170,504 | 120,370 | |||||||||||
| Depreciation, depletion and amortization | 149,841 | 108,517 | 559,793 | 469,084 | |||||||||||
| Accretion of asset retirement obligations | 1,302 | 1,400 | 5,075 | 6,306 | |||||||||||
| (Gain) loss on sale of properties and equipment | (2,805 | ) | (12 | ) | 394 | (766 | ) | ||||||||
| Provision for uncollectible notes receivable | — | — | — | (40,203 | ) | ||||||||||
| Other expenses | 3,642 | 2,792 | 11,829 | 13,157 | |||||||||||
| Total costs, expenses and other | 538,626 | 208,016 | 1,470,913 | 1,159,868 | |||||||||||
| Income (loss) from operations | 256,185 | (18,500 | ) | 77,746 | (238,252 | ) | |||||||||
| Loss on extinguishment of debt | — | (24,747 | ) | — | (24,747 | ) | |||||||||
| Interest expense | (18,169 | ) | (20,335 | ) | (70,730 | ) | (78,694 | ) | |||||||
| Interest income | 8 | 774 | 413 | 2,261 | |||||||||||
| Income (loss) before income taxes | 238,024 | (62,808 | ) | 7,429 | (339,432 | ) | |||||||||
| Income tax (expense) benefit | (59,171 | ) | 140,445 | (5,406 | ) | 211,928 | |||||||||
| Net income (loss) | $ | 178,853 | $ | 77,637 | $ | 2,023 | $ | (127,504 | ) | ||||||
| Earnings per share: | |||||||||||||||
| Basic | $ | 2.71 | $ | 1.18 | $ | 0.03 | $ | (1.94 | ) | ||||||
| Diluted | $ | 2.71 | $ | 1.17 | $ | 0.03 | $ | (1.94 | ) | ||||||
| Weighted-average common shares outstanding: | |||||||||||||||
| Basic | 66,104 | 65,875 | 66,059 | 65,837 | |||||||||||
| Diluted | 66,232 | 66,085 | 66,303 | 65,837 | |||||||||||
PDC ENERGY, INC.
Consolidated Balance Sheets
(unaudited, in thousands, except share and per share data)
| December 31, 2018 | December 31, 2017 | |||||||
| Assets | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 1,398 | $ | 180,675 | ||||
| Accounts receivable, net | 181,434 | 197,598 | ||||||
| Fair value of derivatives | 84,492 | 14,338 | ||||||
| Prepaid expenses and other current assets | 7,136 | 8,613 | ||||||
| Total current assets | 274,460 | 401,224 | ||||||
| Properties and equipment, net | 4,002,862 | 3,933,467 | ||||||
| Assets held-for-sale | 140,705 | 40,583 | ||||||
| Fair value of derivatives | 93,722 | — | ||||||
| Other assets | 32,396 | 45,116 | ||||||
| Total Assets | $ | 4,544,145 | $ | 4,420,390 | ||||
| Liabilities and Stockholders’ Equity | ||||||||
| Liabilities | ||||||||
| Current liabilities: | ||||||||
| Accounts payable | $ | 181,864 | $ | 150,067 | ||||
| Production tax liability | 60,719 | 37,654 | ||||||
| Fair value of derivatives | 3,364 | 79,302 | ||||||
| Funds held for distribution | 105,784 | 95,811 | ||||||
| Accrued interest payable | 14,150 | 11,815 | ||||||
| Other accrued expenses | 75,133 | 42,987 | ||||||
| Total current liabilities | 441,014 | 417,636 | ||||||
| Long-term debt | 1,194,876 | 1,151,932 | ||||||
| Deferred income taxes | 198,096 | 191,992 | ||||||
| Asset retirement obligations | 85,312 | 71,006 | ||||||
| Liabilities held-for-sale | 4,111 | 499 | ||||||
| Fair value of derivatives | 1,364 | 22,343 | ||||||
| Other liabilities | 92,664 | 57,333 | ||||||
| Total liabilities | 2,017,437 | 1,912,741 | ||||||
| Commitments and contingent liabilities | ||||||||
| Stockholders’ equity | ||||||||
| Common shares – par value $0.01 per share, 150,000,000 authorized, 66,148,609 and 65,955,080 issued as of December 31, 2018 and 2017, respectively | 661 | 659 | ||||||
| Additional paid-in capital | 2,519,423 | 2,503,294 | ||||||
| Retained earnings | 8,727 | 6,704 | ||||||
| Treasury shares – at cost, 45,220 and 55,927 as of December 31, 2018 and 2017, respectively | (2,103 | ) | (3,008 | ) | ||||
| Total stockholders’ equity | 2,526,708 | 2,507,649 | ||||||
| Total Liabilities and Stockholders’ Equity | $ | 4,544,145 | $ | 4,420,390 | ||||
PDC ENERGY, INC.
Consolidated Statements of Cash Flows
(unaudited, in thousands)
| Three Months Ended December 31, |
Twelve Months Ended December 31, |
|||||||||||||||
| 2018 | 2017 | 2018 | 2017 | |||||||||||||
| Cash flows from operating activities: | ||||||||||||||||
| Net income (loss) | $ | 178,853 | $ | 77,637 | $ | 2,023 | $ | (127,504 | ) | |||||||
| Adjustments to net income (loss) to reconcile to net cash from operating activities: | ||||||||||||||||
| Net change in fair value of unsettled commodity derivatives | (427,993 | ) | 81,567 | (260,775 | ) | 17,260 | ||||||||||
| Depreciation, depletion and amortization | 149,841 | 108,517 | 559,793 | 469,084 | ||||||||||||
| Impairment of properties and equipment | 264,167 | 3,388 | 458,397 | 285,887 | ||||||||||||
| Impairment of goodwill | — | — | — | 75,121 | ||||||||||||
| Exploratory dry hole costs | 113 | 110 | 113 | 41,297 | ||||||||||||
| Provision for uncollectible notes receivable | — | — | — | (40,203 | ) | |||||||||||
| Loss on extinguishment of debt | — | 24,747 | — | 24,747 | ||||||||||||
| Accretion of asset retirement obligations | 1,302 | 1,400 | 5,075 | 6,306 | ||||||||||||
| Non-cash stock-based compensation | 5,425 | 4,766 | 21,782 | 19,353 | ||||||||||||
| (Gain) loss on sale of properties and equipment | (2,805 | ) | (12 | ) | 394 | (766 | ) | |||||||||
| Amortization of debt discount and issuance costs | 3,315 | 3,279 | 12,769 | 12,907 | ||||||||||||
| Deferred income taxes | 59,134 | (132,156 | ) | 6,105 | (203,685 | ) | ||||||||||
| Other | 1,738 | 1,279 | 2,763 | 2,265 | ||||||||||||
| Changes in assets and liabilities | 78,378 | 2,639 | 80,863 | 15,744 | ||||||||||||
| Net cash from operating activities | 311,468 | 177,161 | 889,302 | 597,813 | ||||||||||||
| Cash flows from investing activities: | ||||||||||||||||
| Capital expenditures for development of crude oil and natural gas properties | (260,801 | ) | (208,358 | ) | (946,350 | ) | (737,208 | ) | ||||||||
| Capital expenditures for other properties and equipment | (7,316 | ) | (1,354 | ) | (11,055 | ) | (5,094 | ) | ||||||||
| Acquisition of crude oil and natural gas properties | 1,546 | (1,146 | ) | (180,026 | ) | (15,628 | ) | |||||||||
| Proceeds from sale of properties and equipment | 1,119 | 6,669 | 3,562 | 9,991 | ||||||||||||
| Proceeds from divestiture | 1,200 | — | 44,693 | — | ||||||||||||
| Sale of promissory note | — | — | — | 40,203 | ||||||||||||
| Restricted cash | — | — | 1,249 | (9,250 | ) | |||||||||||
| Sale of short-term investments | — | — | — | 49,890 | ||||||||||||
| Purchase of short-term investments | — | — | — | (49,890 | ) | |||||||||||
| Net cash from investing activities | (264,252 | ) | (204,189 | ) | (1,087,927 | ) | (716,986 | ) | ||||||||
| Cash flows from financing activities: | ||||||||||||||||
| Proceeds from revolving credit facility | 443,500 | — | 1,072,500 | — | ||||||||||||
| Repayment of revolving credit facility | (486,000 | ) | — | (1,040,000 | ) | — | ||||||||||
| Proceeds from issuance of senior notes | — | 592,366 | — | 592,366 | ||||||||||||
| Redemption of senior notes | — | (519,375 | ) | — | (519,375 | ) | ||||||||||
| Payment of debt issuance costs | (3,618 | ) | (50 | ) | (7,704 | ) | (50 | ) | ||||||||
| Purchase of treasury shares | (447 | ) | (1,347 | ) | (5,147 | ) | (6,672 | ) | ||||||||
| Other | (622 | ) | (320 | ) | (1,550 | ) | (1,271 | ) | ||||||||
| Net cash from financing activities | (47,187 | ) | 71,274 | 18,099 | 64,998 | |||||||||||
| Net change in cash, cash equivalents and restricted cash | 29 | 44,246 | (180,526 | ) | (54,175 | ) | ||||||||||
| Cash, cash equivalents and restricted cash, beginning of year | 9,370 | 145,679 | 189,925 | 244,100 | ||||||||||||
| Cash, cash equivalents and restricted cash, end of year | $ | 9,399 | $ | 189,925 | $ | 9,399 | $ | 189,925 | ||||||||
2018 Year-End and Fourth 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, Senior Vice President Chief Operating Officer, for a conference call on Thursday, February 28, 2019, to discuss its 2018 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: Thursday, February 28, 2019, 11:00 a.m. ET
Webcast available at: www.pdce.com
Domestic (toll free): 877-312-5520
International: 253-237-1142
Conference ID: 6887989
Replay Numbers:
Domestic (toll free): 855-859-2056
International: 404-537-3406
Conference ID: 6887989
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 26, 2019 and IPAA New York on Monday, April 8, 2019. 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. 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.
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”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) 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 release are “forward-looking statements.” Words such as expect, anticipate, intend, plan, believe, seek, estimate, schedule and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: production, costs and cash flows; drilling locations, zones and growth opportunities; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed, and that cash flows from operations will exceed expected capital investments in crude oil and natural gas properties in 2019 and 2020; management of lease expiration issues and financial ratios relating to our revolving credit facility midstream capacity and related curtailments; number of wells spud and TIL’d; average percentage working interest of wells; well costs; and average lateral lengths.
The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this release 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 release or accompanying materials, we may use the term “projection”, “outlook” 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 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 global production volumes and demand, including economic conditions that might impact demand and prices for products we produce;
- volatility of commodity prices for crude oil, natural gas and natural gas liquids (“NGLs”) and the risk of extended periods 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 related to 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 estimated reserves and 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;
- 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 changes in costs and expenses;
- future cash flows, liquidity and financial condition;
- possibility that one or more sales of our Delaware Basin midstream assets will not close as expected;
- 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, natural gas and NGLs 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 Item 1A, Risk Factors, made in our Annual Report on Form 10-K and our filings with the U.S. Securities and Exchange Commission (“SEC”) for further information on risks and uncertainties that could affect our business, financial condition, results of operations and cash flows. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this release. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this 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.
Contacts:
Michael Edwards
Senior Director Investor Relations
303-860-5820
[email protected]
Kyle Sourk
Manager Investor Relations
303-318-6150
[email protected]
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