EP Energy Reports Third Quarter 2015 Results -- Improved Well Performance And Lower Costs

Oct 28, 2015

HOUSTON, Oct. 28, 2015 /PRNewswire/ -- EP Energy Corporation (NYSE:EPE) today reported third quarter 2015 financial and operational results.

EP Energy Corporation.

Key third quarter 2015 highlights include:

  • 62.1 thousand barrels of oil production per day (MBbls/d) — up 9 percent from 3Q'14
  • $446 million Adjusted EBITDAX — up 6 percent from 3Q'14
  • $0.26 adjusted earnings per share (Adjusted EPS) — up 8 percent from 3Q'14
  • $1.50 Discretionary Cash Flow Per Share — up 3 percent from 3Q'14
  • Adjusted unit cash cost of $8.72 per Boe — down 32 percent from 3Q'14
  • Wolfcamp completions drive a 30 percent increase in type curve
  • Enhanced Haynesville drilling and completion designs improved performance
  • Successfully closed Eagle Ford acquisition
  • Maintained significant liquidity of $1.6 billion at 9/30/15
  • $649 million from settlements on financial derivatives year-to-date through 3Q'15

"In the third quarter, we delivered outstanding well results in all four of our capital programs, while substantially reducing costs," said Brent Smolik, chairman, president, and chief executive officer of EP Energy Corporation. "We grew total oil volumes by nine percent compared with third quarter 2014, despite lower activity levels.  We remain on track to meet our financial and operational goals for the year.  During the quarter, we successfully closed the Eagle Ford bolt-on acquisition which expands drilling inventory in our highest return oil program. Our 2015 and 2016 hedge position is one of the best in the industry. Going forward, we will continue to focus on efficient execution, our core capability. We are equally committed to further strengthening our balance sheet, and we expect to continue to generate free cash flow the rest of this year."

EP Energy reported $0.26 Adjusted EPS and $1.50 Discretionary Cash Flow Per Share for the third quarter of 2015.  Adjusted EBITDAX for the third quarter of 2015 was $446 million, up from $419 million in the third quarter of 2014, due primarily to higher production volumes and lower operating costs.  Total adjusted cash operating costs for the quarter ended September 30, 2015 were $8.72 per barrel of oil equivalent (Boe), well below $12.85 per Boe for the third quarter of 2014, due primarily to operational efficiencies and cost reductions resulting in lower lifting costs, lower G&A costs, and lower production taxes. The company expects full year 2015 adjusted cash operating costs to be at the low end of guidance.

The company continued to drive well costs lower.  Total capital expenditures in the third quarter of 2015 were $258 million, excluding acquisition capital, with more than half invested in the company's Eagle Ford program.  During the third quarter of 2015, the company completed 49 wells.  Average daily oil production increased 9 percent to 62.1 MBbls/d of oil, up from 57.1 MBbls/d in the third quarter of 2014.  Total equivalent production grew to 114.5 thousand barrels of oil equivalent per day (MBoe/d), up from 100.9 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.

Eagle Ford Program

In the third quarter of 2015, the company completed 24 wells across its Eagle Ford program and grew oil production to 39.9 MBbls/d, an 11 percent increase compared with the third quarter of 2014. In both periods, the company completed 24 wells, but grew production in the third quarter of 2015 as a result of optimizing completions and improved landing zone accuracy. Total equivalent production grew to 61.4 MBoe/d.

EP Energy continues to be encouraged by the performance of its enhanced completion designs which in the third quarter generated an initial 30 day production rate of 856 barrels of oil per day (BOPD), a 21 percent increase over third quarter 2014 results.

On September 4, 2015, the company closed its previously announced asset acquisition in the Eagle Ford.  The company estimates that the newly acquired assets will add up to 164 future drilling locations.

Wolfcamp Program

In the third quarter of 2015, the company completed 16 wells in its Wolfcamp program and produced 9.5 MBbls/d of oil, up 1 percent from the same period in 2014 despite completing nearly 40 percent fewer wells in the current quarter compared with the same 2014 period. Results were driven by improved drilling and completion designs and improved lateral placement. Total equivalent production grew to 21.1 MBoe/d.

Year-to-date, EP Energy reported average initial 24 hour oil production rates of approximately 800 BOPD per well, which is among the highest rates reported by any operator in the entire Midland Basin.  Initial 30 day oil production rates continue to improve, averaging 530 BOPD in the third quarter.

The company updated its type curve EUR for the next 700-800 wells it plans to drill on its Wolfcamp acreage to 600 MBoe, a 30 percent increase from the previous 461 MBoe type curve. The company now estimates that initial 30 day oil production rates will average 520 BOPD, up more than 40 percent from the previous type curve.

Altamont Program

In the third quarter of 2015, EP Energy completed 7 wells as it continued to optimize well completions and increase drilling efficiencies in this resource-rich program. Third quarter 2015 oil production was 12.7 MBbls/d, an 8 percent increase compared with the same period in 2014. Results during the quarter included another well with production rates in the top ten all-time best EP Energy wells in the program.  Total equivalent production grew to 17.7 MBoe/d. 

Altamont realized pricing in the third quarter continued to improve due to lower basin-wide production and higher refinery capacity in the Salt Lake City area.

Haynesville Program

In the third quarter of 2015, EP Energy completed its first two Haynesville wells since the second quarter of 2012. The company is encouraged with the early results of these 4,500 foot lateral wells.  Initial 30 day production rates averaged about 12 million cubic feet per day of natural gas production. The new wells were completed with modern higher density designs, which have evolved since the company was last active in the program.  During the quarter, the company also drilled two 7,500 foot lateral wells, which were completed in October, and early production results are exceeding 20 MMcf/d per well.

Multi-year Commodity Hedge Program

EP Energy continues to benefit from its sector-leading hedge program, which provides substantial commodity price protection for the remainder of 2015 and 2016. Year-to-date through the third quarter, the company has realized $649 million of settlements on its financial derivatives. At September 30, the mark-to-market value of open contracts was approximately $850 million. A summary of the company's hedge positions is listed below:

Total Fixed Price Hedges


2015


2016


2017

Oil volumes (MMBbls)


5.6



18.0



5.1


Average floor price ($/Bbl)


$

91.11



$

80.29



$

65.87


Percent hedged(1)


97

%


79

%


23

%








Natural gas volumes (TBtu)


15.6



7.3




Average floor price ($/MMBtu)


$

4.26



$

4.20



$


Percent hedged(1)


89

%


11

%




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

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

Liability Management and Liquidity

In the third quarter of 2015, the company's cash flows exceeded capital spending excluding acquisitions, a trend EP Energy expects to maintain for the remainder of 2015. As of September 30, 2015, the company had approximately $1.6 billion of available liquidity, which is supported by the company's $2.75 billion reserve-based loan facility and borrowing base. The company's next borrowing base redetermination is scheduled to be completed in November 2015, and the company currently expects to maintain its borrowing base value at $2.75 billion.

EP Energy is well positioned for future success with no debt maturities over the next two years, strong cash flows from high quality assets and an industry-leading hedge program.

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 October 29, to discuss its third 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# 2041851) 10 minutes prior to the start of the webcast.  A replay of the webcast will be available through Monday, November 30, 2015 on the company's website in the Investor Center (conference ID# 10074473).

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 settlements and cash 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, impairment charges, and other non-recurring costs, including transition and restructuring charges.

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



Quarter ended September 30, 2015


Pre Tax


After Tax


Diluted EPS


($ in millions, except earnings per share amounts)

Net income



$

176



$

0.72








Adjustments(1)






Impact of financial derivatives(2)

$

(176)



$

(112)



$

(0.46)


Total adjustments

$

(176)



$

(112)



$

(0.46)








Adjusted EPS





$

0.26








Diluted weighted average shares





244







Quarter ended September 30, 2014


Pre Tax


After Tax


Diluted EPS


($ in millions, except earnings per share amounts)

Net income



$

305



$

1.25


Loss from discontinued operations, net of tax



1




Income from continuing operations



$

306



1.25








Adjustments(1)






Impact of financial derivatives(2)

$

(384)



$

(244)



$

(1.00)


Transition, restructuring and other costs(3)

(6)



(4)



(0.01)


Impairment charges

1






Total adjustments

$

(389)



$

(248)



$

(1.01)








Adjusted EPS





$

0.24








Diluted weighted average shares





244







Nine months ended September 30, 2015


Pre Tax


After Tax


Diluted EPS


($ in millions, except earnings per share amounts)

Net loss



$

(17)



$

(0.07)








Adjustments(1)






Impact of financial derivatives(2)

$

191



$

122



$

0.50


Transition, restructuring and other costs(3)

8



5



0.02


Loss on extinguishment of debt

41



26



0.11


Total adjustments

$

240



$

153



$

0.63








Adjusted EPS





$

0.56








Diluted weighted average shares





244







Nine months ended September 30, 2014


Pre Tax


After Tax


Diluted EPS


($ in millions, except earnings per share amounts)

Net income



$

97



$

0.40


Income from discontinued operations, net of tax



(3)



(0.01)


Income from continuing operations



$

94



0.39








Adjustments(1)






Impact of financial derivatives(2)

$

(16)



$

(11)



$

(0.04)


Transition, restructuring and other costs(3)

(5)



(3)



(0.01)


Fees paid to Sponsors(4)

90



62



0.26


Loss on extinguishment of debt

17



11



0.04


Impairment charges

1






Total adjustments

$

87



$

59



$

0.25








Adjusted EPS





$

0.64








Diluted weighted average shares





241




(1)

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. 

(2)

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

(3)

Reflects transition and severance costs related to restructuring for the nine months ended September 30, 2015. Reflects an $11 million insurance settlement and $5 million of acquisition costs in the third quarter of 2014 as well as 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 settlements and cash premiums paid or received 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), losses on extinguishment of debt, and impairment charges.  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 income (loss):


Quarters ended
 September 30,


Nine months ended
 September 30,


2015


2014


2015


2014


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

Net income (loss)

$

176



$

305



$

(17)



$

97


Loss (income) from discontinued operations, net of tax



1





(3)


Income (loss) from continuing operations

176



306



(17)



94


  Income tax expense (benefit)

95



191



(13)



67


  Interest expense, net of capitalized interest

84



76



249



235


  Depreciation, depletion and amortization

260



228



737



634


  Exploration expense

2



5



12



18


  EBITDAX

617



806



968



1,048


  Mark-to-market on financial derivatives(1)

(434)



(381)



(458)



44


  Settlements and cash premiums on financial derivatives(2)

258



(3)



649



(60)


  Non-cash portion of compensation expense(3)

5



2



8



6


  Transition, restructuring and other costs(4)



(6)



8



(5)


  Fees paid to Sponsors(5)







90


  Loss on extinguishment of debt





41



17


  Impairment charges



1





1


  Adjusted EBITDAX(6)

$

446



$

419



$

1,216



$

1,141










  Total equivalent volumes (MBoe)

10,533



9,286



29,671



26,256










  Adjusted EBITDAX Margin Per Unit (MBoe)(7)

$

42.38



$

45.12



$

41.00



$

43.46




(1)

Represents the income statement impact of financial derivatives.

(2)

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

(3)

For the quarter and nine months ended September 30, 2015, cash payments were less than $1 million and approximately $8 million, respectively. For the quarter and nine months ended September 30, 2014, cash payments were less than $1 million and approximately $13 million, respectively.

(4)

Reflects transition and severance costs related to restructuring for the nine months ended September 30, 2015. Reflects an $11 million insurance settlement and $5 million of acquisition costs in the third quarter of 2014 as well as transition and severance costs related to restructuring activities.

(5)

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

(6)

The nine months ended September 30, 2014 does not include $11 million of Adjusted EBITDAX related to Arklatex and South Louisiana Wilcox classified as discontinued operations.

(7)

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 settlements and cash 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.

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


Quarters ended
September 30,


Nine months ended
 September 30,


2015


2014


2015


2014

Net income (loss)

$

176



$

305



$

(17)



$

97


Loss (income) from discontinued operations, net of tax



1





(3)


Income (loss) from continuing operations

176



306



(17)



94


Depreciation, depletion and amortization

260



228



737



634


Impact of financial derivatives(1)

(176)



(384)



191



(16)


Transition, restructuring and other costs(2)



(6)



8



(5)


Fees paid to Sponsors(3)







90


Deferred income taxes

95



197



(14)



59


Non-cash exploration expense

3



4



10



15


Other non-cash income items

8



7



69



46


Discretionary Cash Flow

$

366



$

352



$

984



$

917










Discretionary Cash Flow Per Share(4)(5)

$

1.50



$

1.45



$

4.03



$

3.80










Discretionary Cash Flow

$

366



$

352



$

984



$

917


Transition, restructuring and other costs(2)



6



(8)



5


Fees paid to Sponsors(3)







(90)


Working capital and other changes

109



59



63



74


Net cash provided by operating activities

$

475



$

417



$

1,039



$

906




(1)

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

(2)

Reflects transition and severance costs related to restructuring for the nine months ended September 30, 2015. Reflects an $11 million insurance settlement and $5 million of acquisition costs in the third quarter of 2014 as well as 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 244 million for both the quarter and nine months ended September 30, 2015 and approximately 244 million and 241 million, respectively, for the quarter and nine months ended September 30, 2014.

(5)

The quarter and nine months ended September 30, 2014 do not include $(0.07) and $0.05, 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 September 30, 2015 the company's long-term debt was $4,931 million and cash and cash equivalents was $28 million.

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



Quarters ended September 30,



2015


2014



Total


Per-Unit(1)


Total


Per-Unit(1)



($ in millions, except per unit costs)

Total continuing operating expenses


$

398



$

37.78



$

380



$

40.94


Depreciation, depletion and amortization


(260)



(24.69)



(228)



(24.56)


Transportation costs


(30)



(2.87)



(22)



(2.42)


Exploration expense


(2)



(0.16)



(5)



(0.54)


Natural gas purchases


(9)



(0.90)



(8)



(0.92)


Impairment charges






(1)



(0.07)


Total continuing cash operating costs and per-unit cash costs


$

97



$

9.16



$

116



$

12.43


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


(5)



(0.44)



3



0.42


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


$

92



$

8.72



$

119



$

12.85











Total equivalent volumes (MBoe)




10,533





9,286


 



Nine months ended September 30,



2015


2014



Total


Per-Unit(1)


Total


Per-Unit(1)



($ in millions, except per unit costs)

Total continuing operating expenses


$

1,175



$

39.59



$

1,192



$

45.40


Depreciation, depletion and amortization


(737)



(24.83)



(634)



(24.14)


Transportation costs


(82)



(2.78)



(71)



(2.72)


Exploration expense


(12)



(0.41)



(18)



(0.68)


Natural gas purchases


(24)



(0.80)



(16)



(0.62)


Impairment charges






(1)



(0.02)


Total continuing cash operating costs and per-unit cash costs


$

320



$

10.77



$

452



$

17.22


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


(15)



(0.52)



(92)



(3.49)


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


$

305



$

10.25



$

360



$

13.73











Total equivalent volumes (MBoe)




29,671





26,256




(1)

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

(2)

For the quarter ended September 30, 2015, amount includes approximately $5 million of non-cash compensation expense, adjusted for cash payments of less than $1 million.  For the nine months ended September 30, 2015, amount includes approximately $8 million of transition and severance costs related to restructuring and $8 million of non-cash compensation expense, adjusted for cash payments made of approximately $8 million. For the quarter ended September 30, 2014, amount includes $11 million of cash received from an insurance settlement, $5 million of acquisition costs and $2 million of non-cash compensation expense, adjusted for cash payments of less than $1 million. For the nine months ended September 30, 2014, amount includes $90 million of transaction, management and other fees paid to the Sponsors, $11 million of cash received from an insurance settlement, $5 million of acquisition costs, $6 million of non-cash compensation expense, adjusted for cash payments made of approximately $13 million, as well as 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
September 30,


Nine months ended
 September 30,


2015


2014


2015


2014

Average cash operating costs ($/Boe)








Lease operating expenses

$

4.25



$

5.12



$

4.67



$

5.41


Production taxes(1)

1.81



3.60



1.99



3.64


General and administrative expenses(2)

3.02



3.52



3.84



7.93


Taxes, other than production and income taxes

0.08



0.19



0.20



0.24


Other expenses(3)





0.07




Total continuing cash operating costs

$

9.16



$

12.43



$

10.77



$

17.22


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

(0.44)



0.42



(0.52)



(3.49)


Total adjusted cash operating costs

$

8.72



$

12.85



$

10.25



$

13.73




(1)

Production taxes include ad valorem and severance taxes.

(2)

For additional detail of adjusted 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

Logo - http://photos.prnewswire.com/prnh/20140205/DA59609LOGO

 

SOURCE EP Energy Corporation


print email rss