EP Energy Announces Fourth Quarter and Full Year 2017 Results

Feb 28, 2018

HOUSTON, Feb. 28, 2018 /PRNewswire/ -- EP Energy Corporation (NYSE:EPE) today reported fourth quarter and year-end 2017 financial and operational results for the company.

EP Energy Corporation. (PRNewsFoto/EP Energy Corporation)

Key highlights include:

2017 Full Year Results

  • New leadership team in place
  • 82.3 thousand barrels of oil equivalent per day (MBoe/d), including 46.1 thousand barrels of oil production per day (MBbls/d)
  • $587 million of oil and gas expenditures, including acquisitions of $29 million
  • 149 completed wells
  • $194 million net loss / $691 million Adjusted EBITDAX
  • Entered into Eagle Ford acquisition and Altamont acreage divestiture - closed 1Q'18
  • Improved financial flexibility with extended debt maturity profile

2017 Proved Reserves

  • Proved reserves of 392.1 million barrels of oil equivalent (MMBoe) - down nine percent from 2016
  • Pro-forma for divestitures and ownership changes, total proved reserves essentially flat to 2016
  • 52 percent oil and 72 percent liquids
  • Proved developed reserves of 218.3 MMBoe - up seven percent from 2016
  • 13 year reserve to production ratio (based on 2017 annual production)

"We have been making meaningful progress on multiple fronts since coming on board in November last year," said Russell Parker, president and chief executive officer of EP Energy Corporation.  "The organization has been restructured to increase the speed of execution and decision making.  In each operating area we are blending in new concepts to improve asset performance, increase capital efficiency and reduce operating costs.  So far in 2018, we have improved our financial flexibility by extending $1.2 billion of near term maturities, and we enhanced our portfolio of capital efficient projects with the completion of two successful A&D transactions.  We are pleased with our progress so far, but we are even more excited about executing on the opportunities ahead that will drive us toward cash flow neutrality and reduced leverage."

2017 Financial Results

Fourth Quarter 2017

For the quarter ended December 31, 2017, EP Energy reported a $0.29 diluted net loss per share and $0.07 adjusted loss per share. The reported net loss for the fourth quarter of 2017 was $72 million, versus a $140 million net loss in the same 2016 period, due to higher realized pricing on oil and NGL volumes and lower reported general and administrative costs.  Adjusted EBITDAX for the fourth quarter 2017 was $181 million, down from $255 million in the fourth quarter of 2016, due to $118 million less of hedge settlements and lower total equivalent and oil volumes in 2017 versus 2016, partially offset by higher realized pricing on physical sales.

The company ended the year with fourth quarter operating expenses of $217 million, down from $247 million in the fourth quarter of 2016 due to lower reported general and administrative costs.  Adjusted cash operating costs were $101 million for the fourth quarter 2017, down from $111 million in the same 2016 period. Adjusted cash operating costs were $13.65 per barrel of oil equivalent (Boe) for the fourth quarter 2017, down from $14.80 per Boe in the same 2016 period mainly due to lower adjusted general and administrative costs, partially offset by higher production taxes from higher pricing in 2017.  

Capital expenditures in the fourth quarter 2017 were $145 million, up from $116 million in the same period 2016, due to increased drilling activity in the Eagle Ford in 2017.  The company spent $92 million in the Eagle Ford, $28 million in the Permian and $25 million in the Altamont.  In the fourth quarter 2017, the company completed 30 gross wells, 14 of which were in the Eagle Ford, seven in the Permian as part of the company's drilling joint venture and nine in the Altamont drilling joint venture.

Full Year 2017

For the year ended December 31, 2017, EP Energy reported $0.79 diluted net loss per share and $0.39 adjusted loss per share. Reported net loss was $194 million for the year 2017, compared to a $27 million net loss in the same 2016 period, which included approximately $450 million of gains on extinguishment of debt and asset sales in 2016.  Adjusted EBITDAX for the year 2017 was $691 million, down from $1,039 million in 2016 due primarily to $546 million in lower hedge settlements offset by higher realized pricing on oil and NGL volumes in 2017.

Total operating expenses for the year ended December 31, 2017 were $927 million, up from $865 million in the same 2016 period.  The difference was driven by a $78 million gain on the sale of the Haynesville assets in 2016.  Adjusted cash operating costs were $427 million for the year 2017, down from $440 million in the same 2016 period. Adjusted cash operating costs per unit were $14.23 per Boe for the year 2017, up slightly from $13.77 per Boe in the same 2016 period due to lower volumes and higher production taxes resulting from higher pricing in 2017.

Capital expenditures in 2017 were $587 million, up from $488 million in the same period 2016.  In 2017, the company spent $227 million in the Eagle Ford, $267 million in the Permian (including $29 million of acquisitions) and $93 million in the Altamont.  In 2017, the company completed 149 gross wells, which was approximately 50 more than EP Energy completed in 2016.  In 2017, the company completed 53 wells in the Eagle Ford, 71 wells in the Permian, including 58 wells in the drilling joint venture and 25 wells in the Altamont.

Note: See Disclosure of Non-GAAP Financial Measures section of this release for applicable definitions and reconciliations to GAAP terms.

Financial Position and Liquidity

At December 31, 2017, EP Energy's balance sheet included $4.1 billion of total debt and approximately $27 million of cash and cash equivalents. 

In January 2018, EP Energy successfully exchanged and extended the maturity on approximately $1.1 billion of senior unsecured notes maturing in 2020, 2022 and 2023 for new senior secured notes maturing in 2024.  The company has no significant near-term debt maturities with the Reserve-Based Loan Facility (RBL Facility) maturing in May 2019 and a manageable level of approximately $275 million in maturities over the next four years.  The company plans to address the extension of the RBL Facility by the end of the second quarter 2018.

As of December 31, 2017, the company had approximately $800 million of total liquidity.  Pro-forma for the January 2018 debt exchange, the company had approximately $700 million of liquidity at year-end 2017.  The company remains focused on balance sheet improvement and maintaining strong financial flexibility.  The company expects to reduce its net debt to adjusted EBITDAX ratio in 2018.

Operations

For the year ended December 31, 2017, average daily production was 82.3 MBoe/d, including 46.1 MBbls/d of oil.  Fourth quarter 2017 average daily production was 80.6 MBoe/d, including 43.6 MBbls/d of oil.  The decrease in the third and fourth quarter production is due to the timing of Eagle Ford activity that was focused early in 2017.

Eagle Ford Program

In 2017, the company completed 53 wells in its Eagle Ford program and production was 35.7 MBoe/d, an 18 percent decrease from 2016 due to reduced capital spending since 2015.  During the fourth quarter of 2017, the company completed 14 wells and produced 30.6 MBoe/d, a 19 percent decrease from the fourth quarter of 2016.  In 2018, the company expects to significantly increase year over year annual production for the first time since 2015.

EP Energy expanded its Eagle Ford horizontal shale inventory by approximately 200 future drilling locations with the acquisition of producing properties and undeveloped acreage from Carrizo Oil & Gas, Inc., which closed in January 2018.

In the Eagle Ford, the company has increased the current oil field production rate by 20 percent compared with the fourth quarter 2017 average.  Half of the increase was driven by performance from new wells and half of the increase was due to the acquisition.  Included in these results are four Ritchie Farms in-fill pad child wells that have been on-line for 25 days with cumulative production six percent higher than the parent well.  The company also completed four new Volatile Oil wells in December and January that had a 60-day oil rate 30 percent higher than the company's type curve.

EP Energy continues to test initiatives for optimal field development and well design to increase production rates, cash flow and asset value.

Permian Program

In 2017, the company completed 71 wells in its Permian program and produced 28.7 MBoe/d, a 34 percent increase from 2016.  In the fourth quarter of 2017, the company completed seven wells, down from 21 completed wells in the same 2016 period, and produced 32.1 MBoe/d, a 17 percent increase from the fourth quarter of 2016. 

Also in 2017, EP Energy completed several bolt-on acquisitions in Upton County which added current production and future drilling locations.  These acquisitions totaled approximately $29 million and included approximately 3,600 net acres in Upton County with gross oil production of 300 Bbls/d.  The transactions added approximately 60 future drilling locations and enabled the company to extend approximately 20 short lateral locations to long lateral locations.

In the Permian, the company is focused on reducing operating costs with enhanced water handling facilities, further optimizing its development program and maintaining its drilling commitments for 2018.

Altamont Program

The company continued to efficiently develop its Altamont program, with the highest returns achieved in its recompletion program.  In 2017, the company completed 25 wells and performed 59 recompletions.  The company benefits from a significant inventory of recompletion opportunities, which generate some of the highest project returns in the portfolio.

Full year production was 17.9 MBoe/d, eight percent higher than 2016 driven by improved performance and higher activity levels of the company's drilling and recompletion programs.  In the fourth quarter 2017, the company completed nine wells and had production volumes of 17.9 MBoe/d.

During the year, the company benefited from improved realized pricing relative to WTI oil prices and higher returns with its drilling joint venture.

Hedge Program Update

In 2017, EP Energy realized $93 million from settlements on financial derivatives.  At year-end 2017, the mark-to-market value of the company's hedge positions was approximately $5 million.  For 2018, EP Energy has effectively hedged approximately 89 percent of its expected oil production at an average price of $58.47 per barrel, and hedged approximately 56 percent of its expected natural gas production at an average price of $3.04 per MMBtu.  Importantly, the company also has the ability to participate in upside pricing movements on two-thirds of its anticipated 2018 production as a result of having a collar structure on a portion of its derivatives.

A summary of the company's 2018 and 2019 hedge positions is listed below:


2018


2019

Total Fixed Price Hedges




Oil volumes (MMBbls)

14.9



1.8


Average floor price ($/Bbl)

$

58.47



$

55.35






Natural gas volumes (TBtu)

25.6



7.3


Average floor prices ($/MMBtu)

$

3.04



$

2.97



Note:  Positions are as of January 31, 2018 (Contract months: January 2018 - Forward) and the table includes WTI three-way collars of 8.9 MMBbls and 1.1 MMBbls in 2018 and 2019, respectively, and WTI collars of 1.0 MMBbls in 2018.

2017 Proved Reserves

EP Energy's proved oil and natural gas reserves were 392.1 MMBoe as of December 31, 2017, a nine percent decrease compared to proved reserves at December 31, 2016 of 432.4 MMBoe.  Proved developed reserves increased seven percent from 204.6 MMBoe in 2016 to 218.3 MMBoe in 2017.  In 2017, proved developed reserves were 56 percent of total proved reserves and 52 percent oil.

2017 proved reserves were lower than 2016 primarily due to divestitures relating to the company's two drilling joint ventures and ownership changes, resulting from higher WTI prices under the variable royalty rates agreement with University Lands.  Excluding the impact of the divestitures and ownership changes 2017 proved reserves were essentially flat to 2016.  Importantly, proved developed reserves increased to 56 percent of the company's total reserves, up from 47 percent in 2016.

The SEC first-day-of-the-month 12-month average prices for reserves as of December 31, 2017 were $51.34 per Bbl for oil and $2.98 per MMBtu for natural gas, up from $42.75 per Bbl for oil and $2.48 per MMBtu for natural gas in the prior 12-month period.

2018 Outlook

EP Energy is reaffirming its previously provided operational and financial guidance for full year 2018.  In addition, the company is providing production and capital guidance for the first quarter of 2018.



1Q'18

2018





Oil production (MBbls/d)


43 - 44

46 - 50

Total production (MBoe/d)


77 - 79

81 - 87





Oil & Gas Expenditures ($ million)1,2


$210 - $220

$600 - $650

   Eagle Ford



~50%

   Permian



~30%

   Altamont



~20%





Average gross drilling rigs




   Eagle Ford



1 - 2

   Permian



1

   Altamont



2





Operating Costs




Lease operating expense ($/Boe)



$5.00 - $5.70

G&A expense ($/Boe)



$2.90 - $3.25

Adjusted G&A expense ($/Boe)3



$2.30 - $2.60

Transportation and commodity purchases ($/Boe)



$3.15 - $3.45

Taxes, other than income ($/Boe)4



$2.50 - $2.60

DD&A ($/Boe)



$16.50 - $17.50





1 Includes ~$135 million non-drill capital including; ~$55 million for general equipment, ~$30 million for capitalized G&A and interest, ~$25 million for enhanced facility projects, ~$10 million for enhanced oil recovery projects, and ~$15 million for leasing and seismic, and excludes net acquisition costs and divestiture proceeds of ~$57 million.


2 Altamont capital includes ~100 recompletions for $50 million.


3 Adjusted G&A represents G&A expense less approximately $0.60 - $0.65 per Boe of non-cash compensation expense.


4 Severance taxes are based on $55/Bbl WTI.

Webcast Information

EP Energy has scheduled a webcast at 10 a.m. Eastern Time, 9 a.m. Central Time, on March 1, 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# 1387932) 10 minutes prior to the start of the webcast.  A replay of the webcast will be available through April 5, 2018 on the company's website in the Investor Center or by dialing 877-344-7529 (conference ID# 10117505).

About EP Energy

The EP Energy team is driven to deliver superior returns for our investors by developing the oil and natural gas that feeds America's growing energy needs. The company focuses on enhancing the value of its high quality asset portfolio, increasing capital efficiency, maintaining financial flexibility, and pursuing accretive acquisitions and divestitures.  EP Energy is working to set the standard for efficient development of hydrocarbons in the U.S.  Learn more at 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 our long-term incentive programs adjusted for cash payments made under these plans), transition, severance and other costs that affect comparability, fees paid to the Sponsors, 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,


2017


2016


2017


2016


($ in millions, except equivalent volumes and per unit)

Net loss

$

(72)



$

(140)



$

(194)



$

(27)


Income tax (benefit) expense

(2)





(9)



1


Interest expense, net of capitalized interest

81



81



326



312


Depreciation, depletion and amortization

119



120



487



462


Exploration expense

2



2



9



5


EBITDAX

128



63



619



753


Mark-to-market on financial derivatives(1)

51



53



(41)



73


Cash settlements and cash premiums on financial derivatives(2)

7



125



93



639


Non-cash portion of compensation expense(3)

(29)



7



(22)



19


Transition, severance and other costs(4)

19



5



19



15


Fees paid to Sponsors(5)

5





5




Gain on sale of assets







(78)


Loss (gain) on extinguishment of debt





16



(384)


Impairment charges



2



2



2


Adjusted EBITDAX

$

181



$

255



$

691



$

1,039










Total equivalent volumes (MBoe)

7,412



7,594



30,024



32,077










Adjusted EBITDAX Per Unit (MBoe)(6)

$

24.43



$

33.53



$

23.03



$

32.39











(1)

Represents the income statement impact of financial derivatives.



(2)

Represents actual cash settlements related to financial derivatives. There were no cash premiums received or paid for the periods presented.



(3)

Non-cash portion of compensation expense represents compensation expense (net of forfeitures) under our long-term incentive programs adjusted for cash payments made under these plans.



(4)

Reflects transition and severance costs related to workforce reductions.



(5)

Represents fees paid in connection with the release of members of the new leadership team from a portfolio company of funds managed by Apollo Global Management LLC and payment of certain legal expenses.



(6)

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/or losses on sale of assets, impairment charges, other costs that affect comparability, including transition, severance and other costs and associated LTI forfeitures, fees paid to the Sponsors 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, 2017


Pre-Tax


After-Tax


Diluted EPS(1)


($ in millions, except earnings per share amounts)

Net loss



$

(72)



$

(0.29)








Adjustments(2)






 Impact of financial derivatives(3)

$

58



$

37



$

0.15


Transition, severance and other costs






  Severance and other costs(4)

19



12



$

0.05


  Fees paid to Sponsors(5)

5



3



$

0.01


  Long-term incentive forfeitures

(33)



(31)



$

(0.13)


Valuation allowance on deferred tax assets



33



0.14


Total adjustments

$

49



$

54



$

0.22








Adjusted EPS





$

(0.07)








Diluted weighted average shares(6)





246


 


Year ended December 31, 2017


Pre-Tax


After-Tax


Diluted EPS(1)


($ in millions, except earnings per share amounts)

Net loss



$

(194)



$

(0.79)








Adjustments(2)






 Impact of financial derivatives(3)

$

52



$

33



$

0.14


Transition, severance and other costs






  Severance and other costs(4)

19



12



0.05


  Fees paid to Sponsors(5)

5



3



0.01


  Long-term incentive forfeitures

(33)



(31)



(0.13)


Loss on extinguishment/modification of debt

16



11



0.04


Impairment charges

2






Valuation allowance on deferred tax assets



69



$

0.29


Total adjustments

$

61



$

97



$

0.40








Adjusted EPS





$

(0.39)








Diluted weighted average shares(6)





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 of approximately 36%, as well as any other income tax effects specifically attributable to that item. Taxes associated with certain LTI forfeitures related to the change in management are generally not deductible for tax purposes.



(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)

Represents fees paid in connection with the release of members of the new leadership team from a portfolio company of funds managed by Apollo Global Management LLC and payment of certain legal expenses.



(6)

Diluted shares include certain restricted stock and performance unit awards.


Adjusted general and administrative expenses are defined as general and administrative expenses excluding the non-cash portion of compensation expense which represents compensation expense (net of forfeitures) under our long-term incentive programs adjusted for cash payments under these plans, transition, severance and other costs and fees paid to the Sponsors.

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), transition, severance and other costs that affect comparability and fees paid to the Sponsors. 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, severance and other costs that affect comparability and fees paid to the Sponsors, 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,



2017


2016



Total
($MM)


Per Unit
($/Boe)(1)


Total
($MM)


Per Unit
($/Boe)(1)

Oil and natural gas purchases


$



$



$

1



$

0.17


Transportation costs


29



3.92



28



3.71


Lease operating expense


42



5.60



42



5.59


General and administrative


10



1.35



45



5.85


Depreciation, depletion and amortization


119



16.01



120



15.78


Impairment charges






2



0.21


Exploration and other expense


2



0.20



2



0.23


Taxes, other than income taxes


15



2.08



7



1.08


Total operating expenses


$

217



$

29.16



$

247



$

32.62


Adjustments:









Depreciation, depletion and amortization


$

(119)



$

(16.01)



$

(120)



$

(15.78)


Impairment charges






(2)



(0.21)


Exploration expense


(2)



(0.20)



(2)



(0.23)


Non-cash portion of compensation expense(2)


29



3.95



(7)



(0.89)


Transition, severance and other costs(2)


(19)



(2.56)



(5)



(0.71)


Fees paid to Sponsors(2)


(5)



(0.69)






Adjusted cash operating costs and per unit adjusted cash costs


$

101



$

13.65



$

111



$

14.80











Total consolidated equivalent volumes (MBoe)




7,412





7,594


 



Year Ended December 31,



2017


2016



Total
($MM)


Per-Unit
($/Boe)(1)


Total
($MM)


Per-Unit
($/Boe)(1)

Oil and natural gas purchases


$

2



$

0.07



$

10



$

0.32


Transportation costs


115



3.83



109



3.41


Lease operating expense


163



5.42



159



4.97


General and administrative


81



2.69



146



4.54


Depreciation, depletion and amortization


487



16.22



462



14.40


Gain on sale of assets






(78)



(2.44)


Impairment charges


2



0.04



2



0.05


Exploration and other expense


12



0.40



5



0.16


Taxes, other than income taxes


65



2.19



50



1.58


Total operating expenses


$

927



$

30.86



$

865



$

26.99


Adjustments:









Depreciation, depletion and amortization


$

(487)



$

(16.22)



$

(462)



$

(14.40)


Impairment charges


(2)



(0.04)



(2)



(0.05)


Gain on sale of assets






78



2.44


Exploration expense


(9)



(0.30)



(5)



(0.16)


Non-cash portion of compensation expense(2)


22



0.75



(19)



(0.58)


Transition, restructuring and other costs(2)


(19)



(0.64)



(15)



(0.47)


Fees paid to Sponsors(2)


(5)



(0.18)






Adjusted cash operating costs and per-unit adjusted cash costs


$

427



$

14.23



$

440



$

13.77











Total consolidated equivalent volumes (MBoe)




30,024





32,077











(1)

Per unit costs are based on actual amounts rather than the rounded totals presented.



(2)

Amounts are excluded in the calculation of adjusted general and administrative expense.

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.  Adjusted Cash Operating Costs per unit 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.  Adjusted General and Administrative Expense is used by management and investors as additional information.  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, Adjusted General and Administrative Expense 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.  Adjusted General and Administrative Expense should not be used as an alternative to GAAP general and administrative expense.  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.  Our presentation of Adjusted EPS, EBITDAX, Adjusted EBITDAX, Adjusted EBITDAX Per Unit, Adjusted General and Administrative Expense 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, Adjusted General and Administrative Expense 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

 

SOURCE EP Energy Corporation


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