DENVER, Feb 26, 2020 (GLOBE NEWSWIRE via COMTEX) -- PDC Energy, Inc. ("PDC" or the "Company") /zigman2/quotes/202777853/composite PDCE +5.63% today announced its 2019 full-year and fourth quarter operating and financial results. The Company also provided detailed 2020 guidance and a preliminary 2021 outlook.
-- Net cash from operating activities of approximately $858 million, adjusted cash flows from operations, a non-U.S. GAAP metric defined below, of approximately $825 million and oil and gas capital investments of approximately $788 million.
-- Approximately $38 million of free cash flow, a non-U.S. GAAP metric defined as net cash flows from operating activities, excluding changes in working capital, less oil and gas capital investments.
-- Total production of 49.4 million barrels of oil equivalent ("MMBoe"), or approximately 135,000 barrels of oil equivalent ("Boe") per day, a 23 percent increase compared to 2018.
-- Oil production of 19.2 million barrels ("MMBbls"), or approximately 52,500 Bbls per day, a 13 percent increase compared to 2018.
-- Increase in year-end proved reserves of 12 percent to 611 MMBoe, with all-source reserve replacement of 235 percent.
2020 Guidance Highlights:
-- Oil and gas capital investments expected between $1.0 and $1.1 billion, representing a decrease of approximately 15 percent compared to the combined 2019 capital investments of PDC and SRC Energy Inc. ("SRC").
-- Anticipate generating approximately $250 million of free cash flow assuming $52.50 WTI oil and $2 NYMEX natural gas prices.
-- Total production expected between 205 to 215 MBoe per day, a six percent increase compared to the combined PDC and SRC 2019 production.
-- Anticipated oil production between 78 and 82 MBbls per day. The Company expects its fourth quarter 2020 oil production to reflect an increase of ten to 15 percent compared to the combined PDC and SRC fourth quarter 2019 volumes.
President and CEO Bart Brookman commented, "I'm incredibly proud of our team for not only having achieved significant cost savings and operational efficiencies throughout 2019, but more importantly, doing so in what we deem to be a stellar year from a safety perspective. Further, we were able to deliver on several key strategic initiatives, including divesting our Delaware Basin midstream assets, instituting a stock repurchase plan and announcing a merger with SRC Energy, each of which we expect to deliver significant, long-term shareholder value."
"As we demonstrated in 2019 through mid-year adjustments to our capital program, PDC is committed to generating free cash flow. Through a continued and deliberate focus on operational execution combined with a peer-leading cost structure, we anticipate generating approximately $650 million of free cash flow through 2021, which enables us to not only complete our $525 million share repurchase program, but also to retire debt and further improve our already top-tier leverage metrics. These attributes position PDC to differentiate itself against not only the E&P sector, but the broader market as well."
In 2019, the Company invested approximately $788 million in the development of crude oil and natural gas properties and produced 49.4 MMBoe, or approximately 135,000 Boe per day, an increase of 23 percent compared to 2018. Oil production of 19.2 MMBbls in 2019 represents 39 percent of 2019 total volumes and an increase of 13 percent compared to 2018 oil volumes. In the fourth quarter, the Company's oil and gas capital investment of approximately $65 million contributed to total production of 13.1 MMBoe and oil production of 4.9 MMBbls.
In the Wattenberg Field, the Company invested approximately $455 million to spud 126 wells and turn-in-line ("TIL") 114 wells, including 19 spuds and 12 TILs in the fourth quarter. Production for the year averaged approximately 104,000 Boe per day and was negatively impacted by elevated line pressures into the fourth quarter. Beginning in October 2019, the Company saw reduced line pressures and an improved operating environment resulting in fourth quarter production of approximately 108,000 Boe per day, a four percent sequential increase from the third quarter.
In the Delaware Basin, the Company invested approximately $335 million to spud 33 wells and TIL 21 wells, including nine spuds in the fourth quarter. Production for the year averaged approximately 31,300 Boe per day, including fourth quarter production of approximately 34,000 Boe per day, which represents a two percent sequential decrease from the third quarter. Throughout the year, the Company realized both drilling and completion efficiencies, resulting in an 18 percent decrease in average spud-to-rig release drill times to 27 days and average drilling and completion costs per foot of approximately $1,200, an improvement of approximately 20 percent from 2018 levels.
Oil and Gas Production, Sales and Operating Cost Data
Crude oil, natural gas and NGLs sales, excluding net settlements on derivatives, decreased six percent to $1.3 billion from $1.4 billion in 2018. The decrease in sales between periods was due to a reduction in sales price per Boe of 24 percent to $26.46 in 2019 from $34.61 in 2018 more than offsetting the 23 percent increase in year-over-year production. The decrease in sales price per Boe was driven by 13 percent, 30 percent and 44 percent decreases in weighted-average realized oil, natural gas and NGL prices, respectively. The combined revenue from crude oil, natural gas and NGLs sales and net settlements received on our commodity derivative instruments was $1.3 billion in both 2019 and 2018.
In the fourth quarter, crude oil, natural gas and NGLs sales decreased 12 percent to $340 million from $386 million in the fourth quarter of 2018. The decrease in sales was driven by a 21 percent decrease in average sales price per Boe due to decreases of five percent, 44 percent and 34 percent in weighted-average realized oil, natural gas and NGL prices, respectively.
The following table provides weighted-average sales price, by area, for the three and twelve months ended December 31, 2019 and 2018, excluding net settlements on derivatives and transportation, gathering and processing expenses ("TGP"):
Three Months Ended December 31, Twelve Months Ended December 31, 2019 2018 Percent 2019 2018 Percent Change Change Crude oil (MBbls) Wattenberg Field 3,712 3,733 (0.6)% 14,489 12,809 13.1% Delaware Basin 1,177 1,190 (1.1)% 4,677 4,108 13.9% Utica Shale -- -- * -- 46 * Total 4,889 4,923 (0.7)% 19,166 16,963 13.0% Weighted-Average Sales Price $ 53.13 $ 55.71 (4.6)% $ 53.26 $ 61.19 (13.0)% Natural gas (MMcf) Wattenberg Field 24,646 20,157 22.3% 91,785 68,326 34.3% Delaware Basin 7,388 5,820 26.9% 24,165 19,277 25.4% Utica Shale -- -- * -- 414 * Total 32,034 25,977 23.3% 115,950 88,017 31.7% Weighted-Average Sales Price $ 1.28 $ 2.30 (44.3)% $ 1.30 $ 1.85 (29.7)% NGLs (MBbls) Wattenberg Field 2,112 1,839 14.8% 8,198 6,455 27.0% Delaware Basin 720 678 6.2% 2,725 2,038 33.7% Utica Shale -- -- * -- 34 * Total 2,832 2,517 12.5% 10,923 8,527 28.1% Weighted-Average Sales Price $ 13.82 $ 20.79 (33.5)% $ 12.41 $ 22.14 (43.9)% Crude oil equivalent (MBoe) Wattenberg Field 9,931 8,931 11.2% 37,984 30,652 23.9% Delaware Basin 3,129 2,839 10.2% 11,430 9,359 22.1% Utica Shale -- -- * -- 149 * Total 13,060 11,770 11.0% 49,414 40,160 23.0% Weighted-Average Sales Price $ 26.02 $ 32.83 (20.7)% $ 26.46 $ 34.61 (23.5)%
Production costs for 2019, which include lease operating expense ("LOE"), production taxes and TGP, were $269 million, or $5.45 per Boe, compared to $259 million, or $6.44 per Boe, in 2018. In the fourth quarter of 2019, production costs totaled $71 million, or $5.42 per Boe, compared to $72 million, or $6.08 per Boe, in the comparable 2018 period. LOE per Boe improved nine and 12 percent for the comparable fourth quarter and full-year periods, respectively, as increased production volumes outweighed increases in costs.
The following table provides the components of production costs for the three and twelve months ended December 31, 2019 and 2018:
Three Months Ended Twelve Months Ended December 31, December 31, 2019 2018 2019 2018 (in millions) Lease operating expenses $ 36.2 $ 36.0 $ 142.2 $ 131.0 Production taxes 22.9 23.6 80.8 90.4 Transportation, gathering and processing expenses 11.7 11.9 46.4 37.4 Total $ 70.8 $ 71.5 $ 269.4 $ 258.8
Three Months Ended Twelve Months Ended December 31, December 31, 2019 2018 2019 2018 Lease operating expenses per Boe $ 2.77 $ 3.06 $ 2.88 $ 3.26 Production taxes per Boe 1.75 2.01 1.63 2.25 Transportation, gathering and processing expenses per Boe 0.90 1.01 0.94 0.93 Total per Boe $ 5.42 $ 6.08 $ 5.45 $ 6.44
Financial Results and Liquidity
Net loss for 2019 was $57 million, or $0.89 per diluted share, compared to net income of $2 million, or $0.03 per diluted share in 2018. The year-over-year change was due to the aforementioned decrease in total revenues offsetting a 22 percent decrease in total costs and expenses between periods. Adjusted net income, a non-U.S. GAAP financial measure defined below, was $53 million in 2019 compared to an adjusted net loss of $196 million in 2018. Net loss in the fourth quarter of 2019 was approximately $21 million compared to net income of $179 million in the fourth quarter of 2018. Adjusted net income in the fourth quarter of 2019 was $37 million compared to an adjusted net loss of $147 million in the comparable 2018 period. The difference between net income and adjusted net income in all periods was primarily attributable to changes in the value of settled and unsettled commodity derivative instruments.
Net cash from operating activities in 2019 was $858 million compared to $889 million in 2018. Adjusted cash flows from operations, a non-U.S. GAAP metric defined below, were $825 million in 2019 compared to $808 million in 2018. Net cash from operating activities in the fourth quarter of 2019 were $183 million compared to $311 million in the comparable 2018 period. Adjusted cash flows from operations were $224 million and $233 million in the fourth quarter of 2019 and 2018, respectively. The decreases in cash flows between periods is primarily attributable to decreased average commodity prices compared to the prior year outweighing increased production.
General and administrative expense ("G&A"), which includes cash and non-cash expense, was $162 million, or $3.27 per Boe, in 2019 compared to $171 million, or $4.25 per Boe, in 2018. In 2019, the Company incurred $12 million of net G&A expense related to shareholder activism, its Delaware midstream asset divestiture, the SRC merger and partnership-related settlements. Excluding these items would have resulted in full-year G&A of $3.03 per Boe, representing a decrease of 14 percent compared to 2018 G&A per Boe, excluding legal-related and government-related expense, of approximately $3.51 per Boe.
G&A in the fourth quarter of 2019 was $38 million, or $2.93 per Boe, compared to $49 million, or $4.19 per Boe in the fourth quarter of 2018. Adjusting for the aforementioned non-recurring expenses, which totaled $3 million in the fourth quarter of 2019, would have resulted in G&A of $2.72 per Boe.
PDC's available liquidity and leverage ratio as of December 31, 2019 were approximately $1.3 billion and 1.4 times, respectively, and are both materially unchanged from 2018 levels.
PDC and SRC Combined
On January 14, 2020, the Company merged with SRC Energy in a transaction valued at $1.7 billion, inclusive of SRC's net debt. The Company's pro forma December 31, 2019 liquidity was $1.6 billion. Upon expiration on February 18, 2020, of the Company's offer to repurchase SRC's senior notes, holders of approximately $448 million of outstanding SRC Senior Notes accepted the redemption offer. The Company funded the total redemption price of approximately $452 million, plus an estimated $6 million in accrued and unpaid interest, using its revolving credit facility, resulting in total liquidity of approximately $1.1 billion.
The following table presents select PDC, SRC and Combined Company operating and financial results for the year ended December 31, 2019:
PDC SRC Combined Production: Crude oil (MBbls) 19,166 9,813 28,979 Natural gas (MMcf) 115,950 49,471 165,421 NGLs (MBbls) 10,923 4,526 15,449 Crude oil equivalent (MBoe) 49,414 22,584 71,998 Average Boe per day (Boe) 135,381 61,874 197,255 Financial Measurements: Adjusted Cash Flows from Operations $ 825 $ 505 $ 1,330 (millions) Capital investments in crude oil and natural $ 788 $ 462 $ 1,250 gas properties (millions) Free cash flows (millions) $ 38 $ 42 $ 80 Leverage ratio 1.4x 1.4x 1.4x
-- Adjusted Cash Flows is a non-U.S. GAAP metric.
-- Free cash flow is a non-U.S. GAAP metric defined as net cash from operating activities before changes to working capital, less oil and gas capital investments. Due to differences in successful-effort and full-cost accounting, SRCs free cash flow is approximated and reflects certain capitalized expenses.
2020 Capital Investment and Financial Guidance
PDC's 2020 capital budget is based on $52.50 per Bbl WTI oil and $2.00 per Mcf NYMEX natural gas with NGL realizations of approximately $11 per barrel. All year-over-year comparisons henceforth should be considered against PDC and SRC combined 2019 performance and results. Additionally, full-year and first quarter 2020 commentary reflects a mid-January closing of the SRC merger which resulted in nearly half a month of results from PDC on a standalone basis.
In 2020, the Company's capital investment range of $1.0 billion to $1.1 billion represents a year-over-year decrease of approximately 15 percent at the mid-point and is approximately $250 million below the mid-point of its August 2019 outlook of $1.2 billion to $1.4 billion for PDC and SRC on a combined basis. The decrease in capital investments is expected to be realized through anticipated reductions to drilling and completion costs, as well as less than originally planned development activity in each basin.
Production for 2020 is expected to increase approximately six percent to a range of 205,000 to 215,000 Boe per day, with anticipated oil production of 78,000 to 82,000 Bbls per day. Anticipated average daily oil production in 2020 would represent an increase of one percent compared to 2019; however, the Company expects its fourth quarter 2020 oil production to reflect a ten to 15 percent increase compared to the fourth quarter of 2019.
PDC expects to have the ability to execute a substantial portion of its remaining share repurchase program and pay down debt through the utilization of approximately $250 million of anticipated free cash flow and $82 million of proceeds expected to be received in June 2020 relating to the 2019 divestiture of the Company's Delaware midstream assets. PDC currently projects to outspend cash flow in the first quarter before generating an increasing level of quarterly free cash flow through the remainder of the year. Keeping percentage realizations constant, the Company projects commodity price fluctuations to change its estimate adjusted cash flows from operations as follows:
2020e Commodity Price Sensitivity Commodity Price Change: Adj. Cash Flows from Operations Change: (millions) $2.50 change in NYMEX crude oil price $ 30 $0.25 change in NYMEX natural gas price $ 20 $1.00 change in composite NGLs price $ 20
Additional basin-level activity and well costs details have been provided in the Company's investor presentation and can be found at www.pdce.com . The table below provides projected 2020 financial guidance:
Low High Production (MBoe/d) 205 215 Capital Investments (millions) $ 1,000 $ 1,100 Operating Expenses LOE ($/Boe) $ 2.70 $ 2.90 TGP ($/Boe) $ 0.95 $ 1.15 Production taxes (% of Crude oil, natural gas & NGLs sales) 6.5 % 7.5 % G&A ($/Boe) $ 1.90 $ 2.10 Estimated Price Realizations (excludes TGP) Crude oil (% of NYMEX) 93% 97% Natural gas (% of NYMEX) 50% 55% NGLs ($/Bbl) $10.00 $12.00
-- G&A does not include approximately $30 million of expected deal costs associated with the SRC merger that were originally expected to be incurred in 2019. Approximately $10 million of G&A associated with the integration of SRC is included and split relatively evenly between the first and second quarters of 2020.
Due to reduced levels of completion activity at the end of 2019, the Company projects sequential decreases to first quarter total Boe and oil production of ten to 15 percent compared to the fourth quarter of 2019. Additionally, the Company expects to invest 25 to 30 percent of its full-year budget in the first quarter while outspending adjusted cash flows from operations by $25 to $50 million.
2021 Preliminary Outlook
The Company's preliminary 2021 Outlook contemplates total capital investment between $1.1 billion and $1.2 billion with approximately $400 million of projected free cash flow assuming $55 per Bbl WTI oil, $2.50 per Mcf NYMEX natural gas, including modest improvements to net gas realizations, and NGL realizations of approximately $11 per barrel. Additionally, the Company projects the ability to grow both total and oil production by five to ten percent compared to 2020 while considerably improving its cash margin through continued reductions to its per Boe cost structure.
Additional details can be found in the Company's investor presentation at www.pdce.com
2020 Governance and Executive Compensation Key Changes
In February 2020, PDC's Board of Directors proposed several key modifications to its corporate governance structure, and made substantial improvements to its executive compensation program for 2020. These changes were made in response to the Company's desire to maintain best practices while giving consideration to input from the Company's key stakeholders. The Company plans to post a presentation to its website, www.pdce.com , on Friday, February 28, 2020, providing additional details regarding the highlighted changes below:
-- Mark E. Ellis named as the new Non-Executive Chairman of the Board, effective February 20, 2020;
-- Former Chairman, Jeffrey C. Swoveland, notified the Company of his intent not to stand for re-election in May 2020 at the Company's Annual Meeting of Stockholders, and further agreed to serve one year as a non-voting Director Emeritus to help ensure the successful transition;
-- Pursuant to the change above, the Company intends to decrease its Board from nine to eight members at its Annual Meeting;
-- At the Company's Annual Meeting, the Company plans to seek stockholder approval to amend its charter to de-stagger the Board, which if approved, would provide for immediate de-classification, with all directors to serve one year terms.
-- Increased weighting of quantitative performance from 50 percent to 75 percent of the short-term incentive payout;
-- The addition of a quantitative metric to the short-term incentive program focused on a composite score of three key environmental, health and safety measurements;
-- The addition of Cash Return on Capital Invested ("CROCI") as a quantitative metric to the short-term incentive program;
-- Adoption of an absolute performance modifier to the relative total shareholder return calculation for the long-term incentive program and;
-- Increased weighting of performance shares compared to restricted shares for the CEO.
Reconciliation of Non-U.S. GAAP Financial Measures
We use "adjusted cash flows from operations," "free cash flow (deficit)," "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, in providing public guidance on possible future results. In addition, we believe these are measures of our fundamental business and can be useful to us, investors, lenders and other parties in the evaluation of our performance relative to our peers and in assessing acquisition opportunities and capital expenditure projects. These supplemental 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. In the future, we may disclose different non-U.S. GAAP financial measures in order to help us and our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure.
Adjusted cash flows from operations and free cash flow (deficit). We believe adjusted cash flows from operations can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe free cash flow (deficit) provides additional information that may be useful in an analysis of our ability to generate cash to fund exploration and development activities and to return capital to stockholders.
We are unable to present a reconciliation of forward-looking free cash flow because components of the calculation, including fluctuations in working capital accounts, are inherently unpredictable. Moreover, estimating the most directly comparable GAAP measure with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort. We believe that forward-looking estimates of free cash flow are important to investors because they assist in the analysis of our ability to generate cash from our operations in excess of capital investments in crude oil and natural gas properties.
Adjusted net income (loss). We believe that adjusted net income (loss) provides additional transparency into operating trends, such as production, realized sales prices, operating costs and net settlements on commodity derivative contracts, because it disregards changes in our net income (loss) from mark-to-market adjustments resulting from net changes in the fair value of our unsettled commodity derivative contracts, and these changes are not directly reflective of our operating performance.
Adjusted EBITDAX. We believe that adjusted EBITDAX provides additional transparency into operating trends because it reflects the financial performance of our assets without regard to financing methods, capital structure, accounting methods or historical cost basis. In addition, because adjusted EBITDAX excludes certain non-cash expenses, we believe it is not a measure of income, but rather a measure of our liquidity and ability to generate sufficient cash for exploration, development, acquisitions and to service our debt obligations.
Beginning in the third quarter of 2019, we included a reconciling item for gains or losses on the sale of properties and equipment when calculating adjusted EBITDAX, thereby no longer including such gains or losses in our reported adjusted EBITDAX. We believe this methodology for calculating adjusted EBITDAX will enable greater comparability to our peers, as well as consistent treatment of adjustments for impairment and gains or losses on the sale of properties and equipment. For comparability, all prior periods presented have been conformed to the aforementioned methodology.
PV-10. We define PV-10 as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10 percent discount rate. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts, investors and other users of our financial statements may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating us and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves.