EP Energy Reports Second Quarter 2015 Results -- Raising 2015 Production Guidance Due to Well Performance Improvement, Total Capital Unchanged, Increasing Wolfcamp Activities, Announces Eagle Ford Acquisition

Jul 29, 2015

HOUSTON, July 29, 2015 /PRNewswire/ -- EP Energy Corporation (NYSE:EPE) today reported second quarter 2015 financial and operational results for the company.

EP Energy Corporation.

Key second quarter 2015 highlights include:

  • 63.4 thousand barrels of oil production per day (MBbls/d) — a 19 percent increase from 2Q'14
  • $404 million Adjusted EBITDAX — a 9 percent increase from 2Q'14
  • $0.17 adjusted earnings per share (Adjusted EPS)
  • $1.36 Discretionary Cash Flow Per Share
  • Improved well performance in all programs
  • Continued reduction in well costs and operating costs
  • Strong liquidity of $1.6 billion at 6/30/15
  • Substantial multi-year hedges protect cash flows from low commodity prices
  • Announced agreement for Eagle Ford bolt-on acquisition in July

"We executed well in the quarter with further improvements in all phases of our business," said Brent Smolik, chairman, president, and chief executive officer of EP Energy Corporation. "During the quarter, our cash flow and production volumes were up and our well costs and operating costs were down.  Overall capital expenditures were in line with our quarterly and annual expectations.  Given our second quarter results, we are updating 2015 guidance by increasing estimated production and lowering estimated cash costs.  We expect more Wolfcamp activities than we had previously planned as a result of increased efficiencies and shifting capital between our programs.  Our business has been performing better than expected, which is positive for the rest of the year and for 2016."

EP Energy reported $0.17 Adjusted EPS and $1.36 Discretionary Cash Flow Per Share for the second quarter 2015.  Adjusted EBITDAX for the second quarter of 2015 was $404 million, up from $372 million in the second quarter of 2014, due primarily to higher oil volumes and lower operating costs.  Total adjusted cash operating costs for the quarter ended June 30, 2015 were $10.74 per barrel of oil equivalent (Boe), well below $14.88 per Boe for the second quarter 2014, due primarily to operational efficiencies and cost reductions resulting in lower lifting and labor costs along with lower production taxes.

The company continues to benefit from significant capital cost savings and expects to now capture 20 to 25 percent well cost reductions in 2015 compared with 2014.  Lower costs are a result of both third party service cost reductions as well as operational efficiency gains.  Total capital expenditures in the second quarter 2015 were $358 million with more than $200 million invested in the company's Eagle Ford program.

During the second quarter of 2015, the company completed 63 wells and average daily oil production increased 19 percent to 63.4 MBbls/d of oil, up from 53.3 MBbls/d in the second quarter of 2014.  Total equivalent production grew to 109.0 thousand barrels of oil equivalent per day (MBoe/d), up from 96.7 MBoe/d in the same period last year.

Note: See Disclosure of Non-GAAP Financial Measures section of this release for applicable definitions and reconciliations of Adjusted EPS, EBITDAX, Adjusted EBITDAX, Adjusted EBITDAX Margin Per Unit, Discretionary Cash Flow, Discretionary Cash Flow Per Share, Cash Operating Costs and Adjusted Cash Operating Costs to GAAP terms.

Eagle Ford Program

In the second quarter of 2015, the company completed 42 wells across its Eagle Ford program and grew oil production to 41.5 MBbls/d, a 23 percent increase compared with the same period in 2014.  Results were driven by timing of completions and well performance above expectations. Total equivalent production was 60.4 MBoe/d, a 20 percent increase compared with the same period in 2014.

EP Energy continues to be encouraged by the performance of its enhanced completion designs which generated 90-day cumulative production 13 percent higher than the company's type curve.

In July, the company entered into an agreement to acquire approximately 12,000 net acres adjacent to its current Eagle Ford operations for $118 million, before customary closing adjustments.  The assets averaged production of approximately 2,950 barrels of oil equivalent per day (Boe/d) in May with a production mix of approximately 80 percent liquids.  The transaction is expected to add an average of approximately 2,200 Boe/d of production to the last four months of 2015 and 164 future drilling locations to the company's drilling inventory.  The company expects to manage the development capital for the acquired properties within its current 2015 capital guidance.

"I'm pleased with this transaction," said Smolik.  "We think that the valuation is compelling for current production and also adds over a year of future drilling locations to our highest return program.  We are a disciplined acquirer with a low-cost operating structure and have a strong track record of value enhancing acquisitions."

Wolfcamp Program

In the second quarter of 2015, the company completed 9 wells in its Wolfcamp program and produced 9.0 MBbls/d of oil, a 14 percent increase compared with the same period in 2014. Total equivalent production of 19.1 MBoe/d was 35 percent higher than the same period in 2014, driven by improved drilling and completion designs as well as improved lateral placement. 

In the second quarter, EP Energy reported several wells which were among the highest initial production rate wells in the entire Midland Basin and had 200-day cumulative production from wells drilled and completed with current techniques that continued to perform significantly better than the company's current type.

Well returns have continued to improve as the company has advanced its extensive Wolfcamp earth model, and EP Energy has shifted capital from other programs so it can drill 10 to 15 additional Wolfcamp completions in 2015.

Altamont Program

The company's Altamont program delivered the highest quarterly production to date and added another all-time best well.   In the second quarter of 2015, EP Energy completed 12 wells as it continued to optimize well completions and increase drilling efficiencies in its resource-rich program. Second quarter 2015 oil production was 12.9 MBbls/d, a 10 percent increase compared with the same period in 2014.  Total equivalent production was 17.5 MBoe/d, an 11 percent increase compared with the same period in 2014.  Second quarter activities remained focused in the southwestern portion of its acreage.

Realized pricing for the second quarter improved with lower differentials, supported by refinery expansions in the Salt Lake City area.

Haynesville Program

In the second quarter, EP Energy drilled its first two new Haynesville wells since the first quarter of 2012. The company is encouraged with the early results of these 4,500 foot lateral wells completed with current completion designs, which have evolved since the company was last active in the program.  The company has also successfully completed four refracs of existing wells. Initial results have been quite positive with average initial uplift production of 3.4 million cubic feet per day which is approximately seven times the base production rate.  The company expects to complete its 2015 Haynesville capital program by testing two 7,500 foot lateral completions in the second half of 2015.

Multi-year Commodity Hedge Program

EP Energy continues to benefit from its sector leading hedge program with substantial commodity price protection for the remainder of 2015 and 2016 and is building a position in 2017.  As a result, EP Energy's cash flows are not sensitive to changes in near-term commodity prices.  A summary of the company's hedge positions is listed below:

Total Fixed Price Hedges


2015


2016


2017

Oil volumes (MMBbls)


11.1



18.0



5.1


Average floor price ($/Bbl)


$

91.11



$

80.29



$

65.87


Percent hedged(1)


97

%


79

%


23

%








Natural gas volumes (TBtu)


31.3



7.3




Average floor price ($/MMBtu)


$

4.26



$

4.20



$


Percent hedged(1)


91

%


11

%




Note: Positions are as of June 30, 2015 (Contract months: July 2015 - Forward).

(1)

 Percent hedged volumes are based on the midpoint of the company's updated 2015 production guidance.

Liability Management and Liquidity
In May, EP Energy successfully redeemed and discharged all of its $750 million secured notes, which were replaced with the issuance of lower cost unsecured notes that mature in 2023.  Also in the second quarter of 2015, the company reaffirmed the value of its RBL Facility borrowing base at $2.75 billion and extended the maturity to May 2019, provided that the 2018 and 2019 secured term loans are retired or refinanced six months prior to the loans maturity.  As of June 30, 2015, the company had $1.6 billion of available liquidity.

Updated 2015 Outlook

As a result of continued well performance improvements and operational efficiency gains, the company updated its full year production, cost estimates, and completion counts for 2015.  EP Energy now expects oil production for the year of 60.5 MBbls/d to 63.5 MBbls/d and equivalent production for the year of 102.25 MBoe/d to 110.25 MBoe/d.  Total well completions now reflect 165 to 195 gross wells completed for the year and due to drilling efficiencies, cost savings and shifting capital within its programs will provide for 10 to 15 additional Wolfcamp well completions in 2015.

The company also lowered its expected cash costs for the year primarily due to decreased lease operating and labor costs and lower production taxes.  EP Energy expects development capital in the second half of 2015 to be approximately $300 million lower than the first half of 2015.  The lower capital combined with the benefit of the company's commodity hedges and lower costs is expected to reduce net debt by the end of 2015.  Net debt was $4.86 billion at June 30, 2015.


Original Guidance (02/19/15)

Previous Guidance (04/30/15)

Current Guidance (07/30/15)

Capital program ($ billion)

$1.2 - $1.3

$1.2 - $1.25

$1.2 - $1.25

Acquisition cost ($ billion)



$0.1





Production 1




Total production (MBoe/d)

94.5 - 109.5

97.0 - 107.0

102.25 - 110.25

Oil production (MBbls/d)

56 - 64

57 - 63

60.5 - 63.5





Average Drilling Rigs



Rest of 2015

Eagle Ford

3 - 4


3

Wolfcamp

1


1

Altamont

1


1

Haynesville

1


0.5





Wells Completed




Eagle Ford

115 - 130


115 - 125

Wolfcamp

15 - 20


25 - 35

Altamont

25 - 30


25 - 30

Haynesville

5 - 10


<5

   Total

160 - 190


165 - 195





Per-unit adjusted cash cost (per Boe)

$10.50 - $13.50

$10.50 - $12.00

$10.25 - $11.25

Transportation cost (per Boe)

$2.90 - $3.35

$2.95 - $3.15

$2.60 - $2.90

DD&A rate (per Boe)

$25.00 - $27.00


$24.50 - $26.50



1 Current guidance assumes the impact of 750 barrels of oil equivalents per day and 500 barrels of oil per day from the recently announced Eagle Ford acquisition and assumes an early September 2015 closing date.

Detailed financial and operational information for the company will be posted at www.epenergy.com in the Investor Center section.

Webcast Information

EP Energy has scheduled a webcast at 10:00 a.m. Eastern Time, 9:00 a.m. Central Time, on July 30, to discuss its second quarter 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# 0715840) 10 minutes prior to the start of the webcast.  A replay of the webcast will be available through Friday, August 28, 2015 on the company's website in the Investor Center (conference ID# 10069063).

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 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 a number of the country's leading 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
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 income (loss) per common share from continuing operations adjusted for the impact of financial derivatives (mark-to-market effects of financial derivatives, net of cash settlements and premiums paid or received related to these derivatives), management and other fees paid to affiliates of Apollo Global Management LLC, Riverstone Holdings LLC, Access Industries and Korea National Oil Corporation, collectively the Sponsors (which ended in 2014), losses on extinguishment of debt, and other non-recurring costs, including transition and restructuring charges.

Below is a reconciliation of Adjusted EPS to our consolidated diluted net loss per share:


Quarter ended June 30, 2015


Pre Tax


After Tax


Diluted EPS


($ in millions, except earnings per share amounts)

Net loss



$

(212)



$

(0.87)








Adjustments(1)






Impact of financial derivatives(2)

$

356



$

228



$

0.93


Loss on extinguishment of debt

41



26



0.11


Total adjustments

$

397



$

254



$

1.04








Adjusted EPS





$

0.17








Diluted weighted average shares





245





Quarter ended June 30, 2014


Pre Tax


After Tax


Diluted EPS


($ in millions, except earnings per share amounts)

Net loss



$

(118)



$

(0.49)


Loss from discontinued operations, net of tax



6



0.03


Loss from continuing operations



$

(112)



(0.46)








Adjustments(1)






Impact of financial derivatives(2)

$

258



$

163



$

0.67


Total adjustments

$

258



$

163



$

0.67








Adjusted EPS





$

0.21








Diluted weighted average shares





244





Six months ended June 30, 2015


Pre Tax


After Tax


Diluted EPS


($ in millions, except earnings per share amounts)

Net loss



$

(193)



$

(0.79)








Adjustments(1)






Impact of financial derivatives(2)

$

367



$

235



$

0.96


Transition, restructuring and other costs(3)

8



5



0.02


Loss on extinguishment of debt

41



26



0.11


Total adjustments

$

416



$

266



$

1.09








Adjusted EPS





$

0.30








Diluted weighted average shares





244





Six months ended June 30, 2014


Pre Tax


After Tax


Diluted EPS


($ in millions, except earnings per share amounts)

Net loss



$

(208)



$

(0.87)


Income from discontinued operations, net of tax



(4)



(0.01)


Loss from continuing operations



$

(212)



(0.88)








Adjustments(1)






Impact of financial derivatives(2)

$

368



$

233



$

0.97


Transition, restructuring and other costs(3)

1



1




Fees paid to Sponsors(4)

90



62



0.26


Loss on extinguishment of debt

17



11



0.04


Total adjustments

$

476



$

307



$

1.27








Adjusted EPS





$

0.39








Diluted weighted average shares





240




(1)

All individual adjustments presented assume a statutory federal and blended state tax rate, as well as any other income tax effects specifically attributable to that item. 

(2)

Represents mark-to-market impact, cash settlements and premiums related to financial derivatives.

(3)

Reflects transition and severance costs related to restructuring activities.

(4)

Represents transaction, management and other fees paid to the Sponsors in 2014.

EBITDAX is defined as income (loss) from continuing operations 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 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 our long-term incentive plans), transition, restructuring and other non-recurring costs, management and other fees paid to the Sponsors (which ended in 2014) and losses on extinguishment of debt.  Adjusted EBITDAX Margin Per Unit is calculated using Adjusted EBITDAX divided by equivalent volumes.

Below is a reconciliation of our EBITDAX and Adjusted EBITDAX to our consolidated net loss:


Quarters ended
 June 30,


Six months ended
 June 30,


2015


2014


2015


2014


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

Net loss

$

(212)



$

(118)



$

(193)



$

(208)


Loss (income) from discontinued operations, net of tax



6





(4)


Loss from continuing operations

(212)



(112)



(193)



(212)


Income tax benefit

(118)



(68)



(108)



(124)


Interest expense, net of capitalized interest

81



80



165



159


Depreciation, depletion and amortization

253



214



477



406


Exploration expense(1)

5



5



10



13


EBITDAX

9



119



351



242


Mark-to-market on financial derivatives(2)

179



290



(24)



425


Cash settlements and premiums on financial derivatives(3)

177



(32)



391



(57)


Non-cash portion of compensation expense(4)

(2)



(5)



3



4


Restructuring and other costs(5)





8



1


Fees paid to Sponsors(6)







90


Loss on extinguishment of debt

41





41



17


Adjusted EBITDAX(7)

$

404



$

372



$

770



$

722










Total equivalent volumes (MBoe)

9,920



8,804



19,138



16,970










Adjusted EBITDAX Margin Per Unit (MBoe)(8)

$

40.75



$

42.25



$

40.28



$

42.55




(1)

Represents exploration expense only.

(2)

Represents the income statement impact of financial derivatives.

(3)

Represents actual cash settlements received/(paid) related to financial derivatives, including cash premiums. No cash premiums were received or paid for the quarter and six months ended June 30, 2015. For both the quarter and six months ended June 30, 2014, we received approximately $1 million of cash premiums.

(4)

For both the quarter and six ended June 30, 2015, cash payments were approximately $7 million. For both the quarter and six months ended June 30, 2014, cash payments were approximately $12 million.

(5)

Reflects transition and severance costs related to restructuring activities.

(6)

Represents transaction, management and other fees paid to the Sponsors in 2014.

(7)

The quarter and six months ended June 30, 2014 do not include $3 million and $11 million, respectively, of Adjusted EBITDAX related to Arklatex and South Louisiana Wilcox classified as discontinued operations.

(8)

Adjusted EBITDAX Margin Per Unit is based on actual total amounts rather than the rounded totals presented.

Discretionary Cash Flow and Discretionary Cash Flow Per Share are non-GAAP measures calculated using income (loss) from continuing operations adjusted for certain items including depreciation, depletion and amortization, the impact of financial derivatives (mark-to-market effects of financial derivatives, net of cash settlements and premiums paid or received related to these derivatives), transition, restructuring and other non-recurring costs, management and other fees paid to the Sponsors (which ended in 2014), deferred income taxes, non-cash exploration expense, and other non-cash income items.  The table below reconciles Discretionary Cash Flow to net cash provided by operating activities under GAAP.

Below is a reconciliation of Discretionary Cash Flow to our consolidated net loss and operating cash flow:


Quarters ended
June 30,


Six months ended
 June 30,


2015


2014


2015


2014

Net loss

$

(212)



$

(118)



$

(193)



$

(208)


Loss (income) from discontinued operations, net of tax



6





(4)


Loss from continuing operations

(212)



(112)



(193)



(212)


Depreciation, depletion and amortization

253



214



477



406


Impact of financial derivatives(1)

356



258



367



368


Transition, restructuring and other costs(2)





8



1


Fees paid to Sponsors(3)







90


Deferred income taxes

(119)



(81)



(109)



(138)


Non-cash exploration expense

3



4



7



11


Other non-cash income items

51



8



61



39


Discretionary Cash Flow

$

332



$

291



$

618



$

565










Discretionary Cash Flow Per Share(4)(5)

$

1.36



$

1.19



$

2.53



$

2.35










Discretionary Cash Flow

$

332



$

291



$

618



$

565


Transition, restructuring and other costs(2)





(8)



(1)


Fees paid to Sponsors(3)







(90)


Working capital and other changes

(59)



(25)



(46)



15


Net cash provided by operating activities

$

273



$

266



$

564



$

489




(1)

Represents mark-to-market impact, cash settlements and premiums related to financial derivatives.

(2)

Reflects transition and severance costs related to restructuring activities.

(3)

Represents transaction, management and other fees paid to the Sponsors in 2014.

(4)

Reflects basic and fully diluted weighted average shares of approximately 245 million and 244 million, respectively, for the quarter and six months ended June 30, 2015 and approximately 244 million and 240 million, respectively, for the quarter and six months ended June 30, 2014.

(5)

The quarter and six months ended June 30, 2014 do not include $0.07 and $0.12, respectively, of Discretionary Cash Flow Per Share related to discontinued operations.

Cash operating costs is a non-GAAP measure calculated on a per Boe basis and includes total operating expenses less depreciation, depletion and amortization expense, transportation costs, exploration expense, natural gas purchases, and other expenses. Adjusted cash operating costs is a non-GAAP measure and is defined as cash operating costs less transition, restructuring and other non-recurring costs, management and other fees paid to the Sponsors (which ended in 2014), and the non-cash portion of compensation expense (which represents compensation expense under our long-term incentive programs adjusted for cash payments made under our long-term incentive plans).  Net debt is defined as long-term debt less cash and cash equivalents and provides useful information to investors for analysis of the company's debt position net of cash that can be immediately available to reduce such balances.  At June 30, 2015 the company's long-term debt was $4,893 million and cash and cash equivalents was $29 million.

Below is a reconciliation of our cash operating costs and adjusted cash operating costs to our operating expenses:



Quarters ended June 30,



2015


2014



Total


Per-Unit(1)


Total


Per-Unit(1)



($ in millions, except per unit costs)

Total continuing operating expenses


$

397



$

39.96



$

376



$

42.68


Depreciation, depletion and amortization


(253)



(25.46)



(214)



(24.31)


Transportation costs


(25)



(2.56)



(26)



(2.93)


Exploration expense(2)


(5)



(0.59)



(5)



(0.53)


Natural gas purchases


(8)



(0.78)



(5)



(0.49)


Total continuing cash operating costs and per-unit cash costs


$

106



$

10.57



$

126



$

14.42


Transition/restructuring costs, non-cash portion of compensation expense and other(3)


1



0.17



5



0.46


Total adjusted cash operating costs and adjusted per-unit cash operating costs


$

107



$

10.74



$

131



$

14.88











Total equivalent volumes (MBoe)




9,920





8,804







Six months ended June 30,



2015


2014



Total


Per-Unit(1)


Total


Per-Unit(1)



($ in millions, except per unit costs)

Total continuing operating expenses


$

777



$

40.59



$

812



$

47.83


Depreciation, depletion and amortization


(477)



(24.90)



(406)



(23.90)


Transportation costs


(52)



(2.73)



(49)



(2.89)


Exploration expense(2)


(10)



(0.55)



(13)



(0.75)


Natural gas purchases


(15)



(0.75)



(8)



(0.46)


Total continuing cash operating costs and per-unit cash costs


$

223



$

11.66



$

336



$

19.83


Transition/restructuring costs, non-cash portion of compensation expense and other(3)


(11)



(0.58)



(95)



(5.62)


Total adjusted cash operating costs and adjusted per-unit cash operating costs


$

212



$

11.08



$

241



$

14.21











Total equivalent volumes (MBoe)




19,138





16,970




(1)

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

(2)

Represents exploration expense only

(3)

For the quarter ended June 30, 2015, amount includes approximately $2 million of non-cash compensation expense, adjusted for cash payments made of approximately $7 million. For the six months ended June 30, 2015, amount includes approximately $8 million of transition and severance costs related to restructuring and $3 million of non-cash compensation expense. For the quarter ended June 30, 2014, amount includes $7 million of non-cash compensation expense, adjusted for cash payments made of approximately $12 million. For the six months ended June 30, 2014, amount includes $90 million of transaction, management and other fees paid to the Sponsors, $4 million of non-cash compensation expense and $1 million of transition and severance costs related to restructuring

The table below displays the average cash operating costs and adjusted cash operating costs per equivalent unit:


Quarters ended
June 30,


Six months ended
 June 30,


2015


2014


2015


2014

Average cash operating costs ($/Boe)








Lease operating expenses

$

4.72



$

5.69



$

4.91



$

5.56


Production taxes(1)

2.05



3.61



2.09



3.66


General and administrative expenses(2)

3.56



4.86



4.30



10.34


Taxes, other than production and income taxes

0.24



0.26



0.26



0.27


Other expenses(3)





0.10




Total continuing cash operating costs

$

10.57



$

14.42



$

11.66



$

19.83


Transition/restructuring costs, non-cash portion of compensation expense and other(2)

0.17



0.46



(0.58)



(5.62)


Total adjusted cash operating costs

$

10.74



$

14.88



$

11.08



$

14.21




(1)

Production taxes include ad valorem and severance taxes.

(2)

For additional detail of items included in general and administrative expenses, refer to the reconciliation of cash operating costs and adjusted cash operating costs above.

(3)

Includes early rig termination fees of $2 million incurred during the first quarter of 2015.

We believe that the presentation of Adjusted EPS, EBITDAX, Adjusted EBITDAX and Adjusted EBITDAX Margin Per Unit is important to provide management and 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, (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.  We believe that the presentation of Discretionary Cash Flow and Discretionary Cash Flow Per Share is important because it provides management and investors with useful additional information for analysis of the company's ability to internally generate funds for exploration, development and acquisitions as well as adjusting net income (loss) for unusual items to allow for a more consistent comparison from period to period. We believe that the presentation of Cash Operating Costs and Adjusted Cash Operating Costs per unit provides management and investors valuable measures of operating performance and efficiency. 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 Margin Per Unit, Discretionary Cash Flow, Discretionary Cash Flow Per Share, Cash Operating Costs, Adjusted Cash Operating Costs and Net Debt 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 or as an alternative to net income (loss), income (loss) from continuing operations, operating income (loss), earnings (loss) per share, 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 Margin Per Unit, Discretionary Cash Flow, Discretionary Cash Flow Per Share, Cash Operating Costs, Adjusted Cash Operating Costs and Net Debt 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 Margin Per Unit, Discretionary Cash Flow, Discretionary Cash Flow Per Share, Cash Operating Costs, 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 or non-recurring 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 supply and demand for oil, natural gas and NGLs; changes in commodity prices and basis differentials for oil and natural gas; the company's ability to meet production volume targets; 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 and suppliers; 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; 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

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SOURCE EP Energy Corporation


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