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News
For Immediate Release
EP Energy Announces Fourth Quarter and Full Year 2016 Results; Improving Value with Increased Performance
HOUSTON, TEXAS, March 1, 2017—EP Energy Corporation (NYSE:EPE) today reported fourth quarter and year-end 2016 financial and operational results for the company.
Key highlights include:
2016 Full Year Results
• | 87.6 thousand barrels of oil equivalent per day (MBoe/d), including 46.6 thousand barrels of oil production per day (MBbls/d) |
• | $488 million of oil and gas expenditures — lower than company estimates |
• | 98 completed wells — higher than company estimates |
• | $27 million net loss / $1,039 million Adjusted EBITDAX |
• | Improved well returns and asset value in all programs |
• | Reduced debt by approximately $1 billion |
• | $1.1 billion of liquidity at 12/31/16 |
2016 Proved Reserves and Future Drilling Inventory
• | Proved reserves of 432.4 million barrels of oil equivalent (MMBoe) |
• | 64 MMBoe of reserve additions |
• | 51 percent oil and 72 percent liquids |
• | 5,156 identified drilling locations |
2017 Outlook
• | $630 million to $730 million of oil and gas expenditures |
• | 75 MBoe/d to 82 MBoe/d of total equivalent production |
• | 45 MBbls/d to 49 MBbls/d of oil production |
• | 175 to 190 gross well completions with primary focus in the Wolfcamp program |
• | Approximately 75 percent of 2017 estimated oil production volumes hedged at an average price of $61.66 per barrel of oil1 |
• | Approximately 76 percent of 2017 estimated natural gas production volumes hedged at an average price of $3.28 per MMBtu1 |
“In 2016 our teams executed well and successfully increased efficiencies, lowered costs and improved well performance in all asset areas,” said Brent Smolik, chairman, president and chief executive officer of EP Energy Corporation. “We reduced debt by $1 billion and significantly extended debt maturities. We also generated significant free cash flow in 2016 and increased liquidity in the second half of the year. Looking ahead, we are shifting our focus to growth, driven by our Permian Basin Wolfcamp asset, while maintaining our focus on balance sheet improvement. So, we enter 2017 much better positioned to capitalize on our high quality assets."
1 Percent hedged based on midpoint of 2017 guidance
2016 Financial Results
Fourth Quarter 2016
For the quarter ended December 31, 2016, EP Energy reported a $0.57 diluted net loss per share and $0.12 adjusted earnings per share (Adjusted EPS). The reported net loss for the fourth quarter of 2016 was $140 million, down from a $3,731 million net loss in the same 2015 period. The 2015 period included an after tax impairment of $2,755 million. Adjusted EBITDAX for the fourth quarter 2016 was $255 million, down from $425 million in the fourth quarter of 2015, due primarily to lower oil and natural gas production volumes and lower realized prices, including hedge impacts, partially offset by lower operating costs.
The company ended the year with fourth quarter operating expenses of $247 million, down from $4,688 million in the fourth quarter of 2015. The 2015 period included the before tax effects of the impairment of $4,299 million. Adjusted cash operating costs were $111 million for the fourth quarter 2016, down from $132 million in the same 2015 period. Adjusted cash operating costs were $14.80 per barrel of oil equivalent (Boe) for the fourth quarter 2016, up from $12.79 per Boe in the same 2015 period due to lower production volumes in 2016.
Full Year 2016
For the year ended December 31, 2016, EP Energy reported an $0.11 diluted net loss per share and Adjusted EPS of $0.62. Reported net loss was $27 million for the year 2016, down from $3,748 million in the same 2015 period. The 2015 period included after tax impairment charges of $2,755 million. Adjusted EBITDAX for the year 2016 was $1,039 million, down from $1,641 million in 2015 due primarily to lower production volumes and lower realized pricing, including hedges, partially offset by lower operating costs for the year.
Total operating expenses for the year ended December 31, 2016 were $865 million, down from $5,863 million in the same 2015 period. The 2015 period included the before tax effects of the impairment of $4,299 million. Adjusted cash operating costs were $440 million for the year 2016, down from $542 million in the same 2015 period. In addition, adjusted cash operating costs were $13.77 per Boe for the year 2016, up slightly from $13.56 per Boe in the same 2015 period due primarily to lower production volumes in 2016.
2016 capital expenditures were $488 million, down from $1,324 million in the same period 2015. In 2016 the company completed 98 wells, which was about half as many as EP Energy completed in 2015. Beginning in the second half of 2016, the company focused much of its investment in the Wolfcamp program. In 2016, the company spent $233 million in the Wolfcamp program, $175 million in the Eagle Ford program and $76 million in the Altamont program.
Note: See Disclosure of Non-GAAP Financial Measures section of this release for applicable definitions and reconciliations to GAAP terms.
Financial Position and Liquidity
During the year 2016, EP Energy accomplished several significant milestones which improved the company's financial position. The company successfully reduced its debt by approximately $1 billion, utilizing free cash flow from operations and asset sales proceeds to conduct opportunistic open market repurchases of its debt at a discount and partially repay amounts outstanding under its reserve-based loan facility (RBL Facility).
At December 31, 2016, EP Energy’s balance sheet included approximately $20 million of cash and cash equivalents and $3.9 billion of total debt. In addition, EP Energy successfully exchanged nearly all of its term loans due 2018 and 2019 for new term loans with an extended maturity in 2021, which eliminated the potential springing maturity of the RBL Facility in 2017. The company has no significant near-term debt maturities with the RBL facility maturing in May 2019 and the next note maturing in 2020.
For the year ended December 31, 2016, cash flow from operations was $784 million and cash capital expenditures were $533 million. In 2016, EP Energy generated $251 million of positive free cash flow.
EP Energy maintains a significant liquidity position of approximately $1.1 billion at year-end 2016, which is supported by the company's RBL Facility.
Additionally, in February 2017 the company issued $1 billion of notes due in 2025, to repay, in full, the $580 million notes due 2021, repurchase $250 million of notes due 2020 in the open market, and repay $111 million of the amounts outstanding under its RBL Facility.
Balance sheet improvement and the extension of its liquidity position remain priorities for the company going forward.
Operations
For the year ended December 31, 2016, average daily production was 87.6 MBoe/d, including 46.6 MBbls/d of oil. Fourth quarter 2016 average daily production was 82.5 MBoe/d, including 45.7 MBbls/d of oil.
During the fourth quarter and the second half of 2016, the company increased its completion activity. As a result, the fourth quarter reflected a return to sequential quarterly production growth in all commodities.
Wolfcamp Program
In 2016, the company completed 44 wells in its Wolfcamp program and produced 21.4 MBoe/d, an 8 percent increase from 2015. Total completions in 2016 were up from 36 in 2015, a 22 percent increase. In the fourth quarter of 2016, the company completed 21 wells, up from one completed well in the same 2015 period, and produced 27.4 MBoe/d, a 29 percent increase from the fourth quarter of 2015.
Total well costs in the Wolfcamp program averaged $4.6 million in 2016 which was approximately 13 percent lower than 2015 average well costs of $5.3 million. This cost reduction was realized even as the company applied enhanced completion designs with longer laterals in 2016.
Also in 2016, EP Energy amended its existing development agreement with its royalty owner, University Lands (UL). This amendment provided the company flexibility to extend its leasehold timeframe to 2021, and most importantly added a sliding scale royalty framework that improves well returns in the current price environment. Coupled with the recently announced joint venture in the Wolfcamp, these actions served to significantly increase the value and return profile of the Wolfcamp asset.
Eagle Ford Program
In 2016, the company completed 39 wells in its Eagle Ford program and production was 43.5 MBoe/d, a 25 percent decrease from 2015. Total completions in 2016 were down from 118 in 2015, a 67 percent decrease. During the fourth quarter of 2016, the company completed five wells and produced 37.7 MBoe/d, a 33 percent decrease from the fourth quarter of 2015.
EP Energy continued to reduce well costs in its Eagle Ford program. The average 2016 well cost was approximately $4.2 million, almost 28 percent lower than 2015 average well cost of $5.8 million.
The company continued to execute efficiently in the Eagle Ford in 2016. EP Energy has one rig currently running with the expectation of increasing completion activity.
Altamont Program
The company continued to efficiently develop its Altamont program, with the highest returns achieved in its recompletion program. In 2016, the company completed 15 new wells and performed 52 recompletions. Full year production was 16.5 MBoe/d, 4 percent lower than 2015. In the fourth quarter 2016, the company completed four wells and had production volumes of 17.4 MBoe/d.
The company is continuing to benefit from improved realized pricing relative to WTI oil prices. Along with these higher price realizations, the company also realized higher returns with its drilling joint venture.
Hedge Program Update
In 2016, EP Energy realized $639 million from settlements on financial derivatives. At year-end 2016, the MTM value of the company's hedge positions was approximately $57 million. For 2017, EP Energy has effectively hedged approximately 75 percent of its expected oil production at an average price of $61.66 per barrel, and hedged approximately 76 percent of its expected natural gas production at an average price of $3.28 per MMBtu.
A summary of the company’s 2017 and 2018 hedge positions is listed below:
2017 | 2018 | ||||||
Total Fixed Price Hedges | |||||||
Oil volumes (MMBbls) | 12.8 | 3.3 | |||||
Average floor price ($/Bbl) | $ | 61.66 | $ | 60.00 | |||
Natural gas volumes (TBtu) | 32.0 | 11.0 | |||||
Average floor prices ($/MMBtu) | $ | 3.28 | $ | 3.11 | |||
Note: Positions are as of February 27, 2017 (Contract months: January 2017 - Forward) and the table includes WTI three-way collars of 8.8 MMBbls and 3.3 MMBbls in 2017 and 2018, respectively.
2016 Proved Reserves
EP Energy’s proved oil and natural gas reserves were 432.4 MMBoe as of December 31, 2016, a 21 percent decrease compared to proved reserves at December 31, 2015 of 546.0 MMBoe. Proved developed reserves in 2016 were 47 percent of total proved reserves and 53 percent oil.
2016 proved reserves were lower than 2015 due to the Haynesville asset divestiture, lower average SEC prices, and the impact of the SEC's five-year development rule after our reduction in estimated capital in the company's long-range development plan.
The company operates 91 percent of its producing wells and has operational control over approximately 98 percent of its drilling inventory as of December 31, 2016.
The SEC first-day-of-the-month 12-month average prices for reserves as of December 31, 2016 were $42.75 per Bbl for oil, $2.48 per MMBtu for natural gas and $16.47 per Bbl for NGL, down from $50.28 per Bbl for oil, $2.59 per MMBtu for natural gas and $16.64 per Bbl for NGL in the prior 12-month period.
Future Drilling Inventory
At year-end 2016, EP Energy’s estimated future drilling inventory, which includes proved undeveloped reserves and unproven resources, totaled 5,156 identified locations — 894 in the Eagle Ford, 2,937 in the Wolfcamp, and 1,325 in the Altamont.
2017 Outlook
2017 Capital Program
In 2017, EP Energy expects capital spending to range from $630 million to $730 million. The company maintains flexibility with regard to its spending range which is driven by the timing of an additional drilling rig in its Wolfcamp program.
Equivalent production in 2017 is expected to range from 75 MBoe/d to 82 MBoe/d with 45 MBbls/d to 49 MBbls/d of oil production. The company expects to grow Wolfcamp production, primarily in the second half of 2017, while holding Eagle Ford and Altamont production volumes flat from the second half of 2016.
Going forward, EP Energy expects to allocate excess cash flow generated by its Eagle Ford and Altamont programs to provide funds for its growing Wolfcamp program.
Operations
For the full year 2017, the company expects to complete 175 to 190 gross wells, with the majority in its Wolfcamp program in the Permian Basin.
In its Wolfcamp program, the company is expanding its development across Reagan and Crockett counties in each of the A, B and C benches. In 2017, the company expects to have two joint venture drilling rigs active for the full year, and plans to add a third drilling rig at mid-year. The company plans to drill longer laterals in 2017, with average lateral lengths greater than 9,000 feet, and average well cost of approximately $4.9 million, compared with average lateral lengths of approximately 8,400 feet, and an average well cost of $4.6 million in 2016. The slight increase in costs is driven by longer lateral wells, which on average are more than 7 percent longer than the previous year.
The company expects to maintain a one-rig drilling program in its Eagle Ford program in 2017 and remains focused on reducing base decline rates, increasing efficiencies and generating high returns in this program. Average well cost in 2017 is expected to be $4.3 million compared with an average well cost of $4.2 million in 2016.
In its Altamont program, the company expects to average two rigs in 2017. The company will also continue its high return recompletion program in 2017. Average well cost in 2017 is expected to be $4.4 million compared with an average well cost of $4.1 million in 2016. The company expects to drill deeper wells in 2017 which contributes to the higher cost.
The table below summarizes the company’s operational and financial guidance for 2017 compared with 2016 results, including pro forma 2016 for the Haynesville Shale asset sale completed in May 2016.
2017 | 2016 | Pro-forma 20164 | ||||
Oil production (MBbls/d) | 45 – 49 | 46.6 | 46.6 | |||
Total production (MBoe/d) | 75 – 82 | 87.6 | 81.4 | |||
Oil & Gas capital ($ million)1,2 | ||||||
Wolfcamp | $245 – $325 | $233 | $233 | |||
Eagle Ford | $260 – $270 | $175 | $175 | |||
Altamont | $125 – $135 | $76 | $76 | |||
Total capital program ($ million) | $630 – $730 | $484 | $484 | |||
Gross well completions | ||||||
Wolfcamp3 | 90 – 105 | 44 | 44 | |||
Eagle Ford | ~60 | 39 | 39 | |||
Altamont | ~25 | 15 | 15 | |||
Total | 175 – 190 | 98 | 98 | |||
1 Includes 20 - 25 percent non-drill capital
2 2016 excludes approximately $1 million of other capital
3 Includes completions which are within the DrillCo joint venture with 40 percent of total well costs to EP Energy
4 Excludes the impact of the sale of the Haynesville Shale asset which closed on May 3, 2016
Webcast Information
EP Energy has scheduled a webcast at 10 a.m. Eastern Time, 9 a.m. Central Time, on March 2, to discuss its fourth quarter and full year financial and operational results. The webcast may be accessed online through the company’s website at epenergy.com in the Investor Center. Materials to be discussed during the webcast will be available in the Investor Center one hour prior to the webcast. A limited number of telephone lines will be available to participants by dialing 888-317-6003 (conference ID# 9258957) 10 minutes prior to the start of the webcast. A replay of the webcast will be available through April 2, 2017 on the company’s website in the Investor Center (conference ID# 10101279).
About EP Energy
The EP Energy team has a passion for finding and producing the oil and natural gas that enriches people’s lives. As a leading independent North American oil and natural gas producer, EP Energy has a proven strategy, a significant reserve base, multi-year drilling opportunities, and a strategic presence in fast-emerging unconventional resource areas. EP Energy is active in all phases of the E&P value chain—exploring for, acquiring, developing and producing oil and natural gas. For more information about EP Energy, visit epenergy.com.
Disclosure of Non-GAAP Financial Measures
The Securities and Exchange Commission’s Regulation G applies to any public disclosure or release of material information that includes a non-GAAP financial measure. In the event of such a disclosure or release, Regulation G requires (i) the presentation of the most directly comparable financial measure calculated and presented in accordance with GAAP and (ii) a reconciliation of the differences between the non-GAAP financial measure presented and the most directly comparable financial measure calculated and presented in accordance with GAAP.
Non-GAAP Terms
EBITDAX is defined as net income (loss) plus interest and debt expense, income taxes, depreciation, depletion and amortization and exploration expense. Adjusted EBITDAX is defined as EBITDAX, adjusted as applicable in the relevant period for the net change in the fair value of derivatives (mark-to-market effects of financial derivatives, net of cash settlements and cash premiums related to these derivatives), the non-cash portion of compensation expense (which represents non-cash compensation expense under these programs adjusted for cash payments made under these plans), transition, restructuring and other costs that affect comparability, gains and losses on extinguishment of debt, gains and/or losses on sale of assets and impairment charges. Adjusted EBITDAX Per Unit is calculated using Adjusted EBITDAX divided by equivalent volumes.
Below is a reconciliation of our consolidated net loss to EBITDAX and Adjusted EBITDAX:
Quarter ended December 31, | Year ended December 31, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
($ in millions, except equivalent volumes and per unit) | |||||||||||||||
Net loss | $ | (140 | ) | $ | (3,731 | ) | $ | (27 | ) | $ | (3,748 | ) | |||
Income tax (benefit) expense | — | (565 | ) | 1 | (578 | ) | |||||||||
Interest expense, net of capitalized interest | 81 | 81 | 312 | 330 | |||||||||||
Depreciation, depletion and amortization | 120 | 246 | 462 | 983 | |||||||||||
Exploration expense | 2 | 6 | 5 | 18 | |||||||||||
EBITDAX | 63 | (3,963 | ) | 753 | (2,995 | ) | |||||||||
Mark-to-market on financial derivatives(1) | 53 | (209 | ) | 73 | (667 | ) | |||||||||
Cash settlements and cash premiums on financial derivatives(2) | 125 | 293 | 639 | 942 | |||||||||||
Non-cash portion of compensation expense(3) | 7 | 5 | 19 | 13 | |||||||||||
Transition, restructuring and other costs(4) | 5 | — | 15 | 8 | |||||||||||
Gain on sale of assets | — | — | (78 | ) | — | ||||||||||
(Gain) loss on extinguishment of debt | — | — | (384 | ) | 41 | ||||||||||
Impairment charges | 2 | 4,299 | 2 | 4,299 | |||||||||||
Adjusted EBITDAX | $ | 255 | $ | 425 | $ | 1,039 | $ | 1,641 | |||||||
Total equivalent volumes (MBoe) | 7,594 | 10,362 | 32,077 | 40,033 | |||||||||||
Adjusted EBITDAX Per Unit (MBoe)(5) | $ | 33.53 | $ | 40.94 | $ | 32.39 | $ | 40.98 | |||||||
(1) Represents the income statement impact of financial derivatives.
(2) | Represents actual cash settlements related to financial derivatives. No cash premiums were received or paid for the periods presented. |
(3) | Cash payments for the quarter and year ended December 31, 2016 were less than $1 million and $3 million, respectively. Cash payments for the quarter and year ended December 31, 2015 were less than $1 million and $8 million, respectively. |
(4) Reflects transition and severance costs related to workforce reductions.
(5) Adjusted EBITDAX Per Unit is based on actual amounts rather than the rounded totals presented.
Adjusted EPS is defined as diluted earnings per share adjusted for certain items that EP Energy considers to be significant to understanding our underlying performance for a given period. Adjusted EPS is useful in analyzing the Company’s ongoing earnings potential and understanding certain significant items impacting the comparability of EP Energy’s results. Adjusted EPS is calculated as net income (loss) per common share adjusted for the impact of financial derivatives (mark-to-market effects of financial derivatives, net of cash settlements and cash premiums related to these derivatives), gains and losses on extinguishment of debt, gains and losses on sale of assets, impairment charges, other costs that affect comparability, including transition and restructuring charges and changes in the valuation allowance on deferred tax assets.
Below is a reconciliation of consolidated diluted net loss per share to Adjusted EPS:
Quarter ended December 31, 2016 | |||||||||||
Pre-Tax | After-Tax | Diluted EPS(1) | |||||||||
($ in millions, except earnings per share amounts) | |||||||||||
Net loss | $ | (140 | ) | $ | (0.57 | ) | |||||
Adjustments(2) | |||||||||||
Impact of financial derivatives(3) | $ | 178 | $ | 115 | $ | 0.47 | |||||
Transition, restructuring and other costs(4) | 5 | 4 | 0.01 | ||||||||
Impairment charges | 2 | 1 | — | ||||||||
Valuation allowance on deferred tax assets | 52 | 0.21 | |||||||||
Total adjustments | $ | 185 | $ | 172 | $ | 0.69 | |||||
Adjusted EPS | $ | 0.12 | |||||||||
Diluted weighted average shares(5) | 247 | ||||||||||
Year ended December 31, 2016 | |||||||||||
Pre-Tax | After-Tax | Diluted EPS(1) | |||||||||
($ in millions, except earnings per share amounts) | |||||||||||
Net loss | $ | (27 | ) | $ | (0.11 | ) | |||||
Adjustments(2) | |||||||||||
Impact of financial derivatives(3) | $ | 712 | $ | 457 | $ | 1.86 | |||||
Gain on extinguishment of debt | (384 | ) | (246 | ) | (1.00 | ) | |||||
Gain on sale of assets | (79 | ) | (51 | ) | (0.21 | ) | |||||
Transition, restructuring and other costs(4) | 15 | 10 | 0.04 | ||||||||
Impairment charges | 2 | 1 | — | ||||||||
Valuation allowance on deferred tax assets | 9 | $ | 0.04 | ||||||||
Total adjustments | $ | 266 | $ | 180 | $ | 0.73 | |||||
Adjusted EPS | $ | 0.62 | |||||||||
Diluted weighted average shares(5) | 246 | ||||||||||
(1) Diluted per share amounts are based on actual amounts rather than the rounded totals presented.
(2) All individual adjustments for all periods presented assume a statutory federal and blended state tax rate, as well as any other income tax effects
specifically attributable to that item.
(3) Represents mark-to-market impact net of cash settlements and cash premiums related to financial derivatives. There were no cash premiums received or paid for the periods presented.
(4) Reflects transition and severance costs related to workforce reductions.
(5) Diluted shares include certain restricted stock and performance unit awards.
Free Cash Flow is defined as net cash provided by operating activities less cash paid for capital expenditures. Below is a reconciliation of our net cash provided by operating activities to Free Cash Flow:
Year ended December 31, | |||
2016 | |||
($ in millions) | |||
Net cash provided by operating activities | $ | 784 | |
Cash paid for capital expenditures | 533 | ||
Free Cash Flow | $ | 251 | |
Net cash used in investing activities | $ | (144 | ) |
Net cash used in financing activities | $ | (646 | ) |
Adjusted cash operating costs is a non-GAAP measure that is defined as total operating expenses, excluding depreciation, depletion and amortization expense, exploration expense, impairment charges, gains and/or losses on sales of assets, the non-cash portion of compensation expense (which represents compensation expense under our long-term incentive programs adjusted for cash payments made under these plans) and transition, restructuring and other costs that affect comparability. We use this measure to describe the costs required to directly or indirectly operate our existing assets and produce and sell our oil and natural gas, including the costs associated with the delivery and purchases and sales of produced commodities. Accordingly, we exclude depreciation, depletion, and amortization and impairment charges as such costs are non-cash in nature. We exclude exploration expense from our measure as it is substantially non-cash in nature and is not related to the costs to operate our existing assets. Similarly, gains and losses on the sale of assets are excluded as they are unrelated to the operation of our assets. We exclude the non-cash portion of compensation expense as well as transition, restructuring and other costs that affect comparability, as we believe such adjustments allow investors to evaluate our costs against others in our industry and these items can vary across companies due to different ownership structures, compensation objectives or the occurrence of transactions.
Below is a reconciliation of our GAAP operating expenses to non-GAAP adjusted cash operating costs:
Quarter Ended December 31, | ||||||||||||
2016 | 2015 | |||||||||||
Total ($MM) | Per Unit ($/Boe)(1) | Total ($MM) | Per Unit ($/Boe)(1) | |||||||||
Oil and natural gas purchases | 1 | 0.17 | 7 | 0.73 | ||||||||
Transportation costs | 28 | 3.71 | 34 | 3.19 | ||||||||
Lease operating expense | 42 | 5.59 | 47 | 4.53 | ||||||||
General and administrative | 45 | 5.85 | 34 | 3.30 | ||||||||
Depreciation, depletion and amortization | 120 | 15.78 | 246 | 23.73 | ||||||||
Impairment charges | 2 | 0.21 | 4,299 | 414.84 | ||||||||
Exploration and other expense | 2 | 0.23 | 6 | 0.57 | ||||||||
Taxes, other than income taxes | 7 | 1.08 | 15 | 1.50 | ||||||||
Total operating expenses | 247 | 32.62 | 4,688 | 452.39 | ||||||||
Adjustments: | ||||||||||||
Depreciation, depletion and amortization | (120 | ) | (15.78 | ) | (246 | ) | (23.73 | ) | ||||
Impairment charges | (2 | ) | (0.21 | ) | (4,299 | ) | (414.84 | ) | ||||
Exploration expense | (2 | ) | (0.23 | ) | (6 | ) | (0.53 | ) | ||||
Non-cash portion of compensation expense | (7 | ) | (0.89 | ) | (5 | ) | (0.50 | ) | ||||
Transition, restructuring and other costs | (5 | ) | (0.71 | ) | — | — | ||||||
Adjusted cash operating costs and per unit adjusted cash costs | 111 | 14.80 | 132 | 12.79 | ||||||||
Total consolidated equivalent volumes (MBoe) | 7,594 | 10,362 | ||||||||||
Year Ended December 31, | ||||||||||||
2016 | 2015 | |||||||||||
Total ($MM) | Per-Unit ($/Boe)(1) | Total ($MM) | Per-Unit ($/Boe)(1) | |||||||||
Oil and natural gas purchases | 10 | 0.32 | 31 | 0.79 | ||||||||
Transportation costs | 109 | 3.41 | 116 | 2.88 | ||||||||
Lease operating expense | 159 | 4.97 | 186 | 4.64 | ||||||||
General and administrative | 146 | 4.54 | 148 | 3.71 | ||||||||
Depreciation, depletion and amortization | 462 | 14.40 | 983 | 24.54 | ||||||||
Gain on sale of assets | (78 | ) | (2.44 | ) | — | — | ||||||
Impairment charges | 2 | 0.05 | 4,299 | 107.38 | ||||||||
Exploration and other expense | 5 | 0.16 | 20 | 0.50 | ||||||||
Taxes, other than income taxes | 50 | 1.58 | 80 | 2.00 | ||||||||
Total operating expenses | 865 | 26.99 | 5,863 | 146.44 | ||||||||
Adjustments: | ||||||||||||
Depreciation, depletion and amortization | (462 | ) | (14.40 | ) | (983 | ) | (24.54 | ) | ||||
Impairment charges | (2 | ) | (0.05 | ) | (4,299 | ) | (107.38 | ) | ||||
Gain on sale of assets | 78 | 2.44 | — | — | ||||||||
Exploration expense | (5 | ) | (0.16 | ) | (18 | ) | (0.44 | ) | ||||
Non-cash portion of compensation expense | (19 | ) | (0.58 | ) | (13 | ) | (0.32 | ) | ||||
Transition, restructuring and other costs | (15 | ) | (0.47 | ) | (8 | ) | (0.20 | ) | ||||
Adjusted cash operating costs and per-unit adjusted cash costs | 440 | 13.77 | 542 | 13.56 | ||||||||
Total consolidated equivalent volumes (MBoe) | 32,077 | 40,033 | ||||||||||
(1) Per unit costs are based on actual amounts rather than the rounded totals presented.
EBITDAX, Adjusted EBITDAX and Adjusted EBITDAX Per Unit are used by management and we believe provide investors with additional information (i) to evaluate our ability to service debt adjusting for items required or permitted in calculating covenant compliance under our debt agreements, (ii) to provide an important supplemental indicator of the operational performance of our business without regard to financing methods and capital structure, (iii) for evaluating our performance relative to our peers, (iv) to measure our liquidity (before cash capital requirements and working capital needs) and (v) to provide supplemental information about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted EPS is used by management and we believe is a valuable measure of operating performance. Free Cash Flow is used by management and we believe provides investors with useful information for analysis of the company's ability to internally fund capital expenditures and to service or incur additional debt. Adjusted Cash Operating Costs is used by management as a performance measure, and we believe provides investors valuable information related to our operating performance and our operating efficiency relative to other industry participants and comparatively over time across our historical results. In addition, the company believes that these measures are widely used by professional research analysts and others in the valuation, comparison and investment recommendations of companies in the oil and gas exploration and production industry.
Adjusted EPS, EBITDAX, Adjusted EBITDAX, Adjusted EBITDAX Per Unit, Free Cash Flow and Adjusted Cash Operating Costs have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under U.S. GAAP. Adjusted EPS should not be used as an alternative to earnings (loss) per share or other measure of financial performance presented in accordance with GAAP. EBITDAX, Adjusted EBITDAX, Adjusted EBITDAX Per Unit should not be used as an alternative to net income (loss), operating income (loss), operating cash flows or other measures of financial performance or liquidity presented in accordance with GAAP. Free Cash Flow should not be used as an alternative to operating or investing cash flows or other measures of financial performance or liquidity presented in accordance with GAAP. Adjusted Cash Operating Costs should not be used as an alternative to operating expenses, operating cash flows or other
measures of financial performance or liquidity presented in accordance with GAAP. For example, our presentation of Adjusted EPS, EBITDAX, Adjusted EBITDAX, Adjusted EBITDAX Per Unit, Free Cash Flow and Adjusted Cash Operating Costs may not be comparable to similarly titled measures used by other companies in our industry. Furthermore, our presentation of Adjusted EPS, EBITDAX, Adjusted EBITDAX, Adjusted EBITDAX Per Unit, Free Cash Flow and Adjusted Cash Operating Costs should not be construed as an inference that our future results will be unaffected by the items noted above or what we believe to be other unusual items, or that in the future we may not incur expenses that are the same as or similar to some of the adjustments in this presentation.
Cautionary Statement Regarding Forward-Looking Statements
This release includes certain forward-looking statements and projections of EP Energy. We have made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable, and complete. However, a variety of factors could cause actual results to differ materially from the projections, anticipated results or other expectations expressed, including, without limitation, the volatility of and sustained low oil, natural gas, and NGL prices; the supply and demand for oil, natural gas and NGLs; the company’s ability to meet production volume targets; changes in commodity prices and basis differentials for oil and natural gas; the uncertainty of estimating proved reserves and unproved resources; the future level of service and capital costs; the availability and cost of financing to fund future exploration and production operations; the success of drilling programs with regard to proved undeveloped reserves and unproved resources; the company’s ability to comply with the covenants in various financing documents; the company’s ability to obtain necessary governmental approvals for proposed E&P projects and to successfully construct and operate such projects; actions by the credit rating agencies; credit and performance risk of our lenders, trading counterparties, customers, vendors, suppliers and third party operators; general economic and weather conditions in geographic regions or markets served by the company, or where operations of the company are located, including the risk of a global recession and negative impact on oil and natural gas demand; the uncertainties associated with governmental regulation, including any potential changes in federal and state tax laws and regulations; competition; and other factors described in the company’s Securities and Exchange Commission filings. While the company makes these statements and projections in good faith, neither the company nor its management can guarantee that anticipated future results will be achieved. Reference must be made to those filings for additional important factors that may affect actual results. EP Energy assumes no obligation to publicly update or revise any forward-looking statements made herein or any other forward-looking statements made by EP Energy, whether as a result of new information, future events, or otherwise.
Contact
Investor and Media Relations
Bill Baerg
713-997-2906
bill.baerg@epenergy.com