EP Energy Reports Third Quarter 2014 Results - Strong Execution Drives Efficient Growth

Nov 4, 2014

HOUSTON, Nov. 4, 2014 /PRNewswire/ -- EP Energy Corporation (NYSE: EPE, "EP Energy") today reported third quarter 2014 financial and operational results for the company.

EP Energy Corporation.

Key third quarter 2014 highlights include:
– Record oil production of 57.1 thousand barrels per day (MBbls/d) — a 45 percent increase in oil production from 3Q'13
$419 million Adjusted EBITDAX — a 36 percent increase from 3Q'13
$0.24 adjusted earnings per share (Adjusted EPS)
$1.45 Discretionary Cash Flow Per Share
– Increased reserve-based loan (RBL) Facility from $2.5 billion to $2.75 billion
– Higher initial production rates in all three oil programs from continued completion and production optimization

"We are pleased with another quarter of solid execution that has delivered results ahead of expectations," said Brent Smolik, chairman, president, and chief executive officer of EP Energy Corporation. "During the quarter we continued to grow volumes at a record pace, increase unit margins and add value. Our business is built to succeed through cycles, supported by our asset strength, operational efficiency, financial flexibility, and management experience. We believe that our repeatable, high margin asset programs, and proven ability to deliver operational improvements will drive efficient growth."

EP Energy reported $0.24 Adjusted EPS and $1.45 Discretionary Cash Flow Per Share for the third quarter 2014. Adjusted EBITDAX for the third quarter of 2014 was $419 million, up significantly from $309 million in the third quarter of 2013 due primarily to higher oil volumes which also contributed to approximately 13 percent higher Adjusted EBITDAX Margin Per Unit for the third quarter of 2014.

During the third quarter of 2014, the company completed 64 wells and average daily oil production increased 45 percent to 57.1 MBbls/d of oil, up from 39.3 MBbls/d in the third quarter of 2013. All three of the company's oil programs contributed to this growth. Total equivalent production grew to 100.9 thousand barrels of oil equivalent per day (Mboe/d), up from 83.4 Mboe/d in the same period last year.

Note: Data throughout this release has been adjusted to exclude completed domestic and international asset sales prior to September 30, 2014, and the sale of the company's equity interest in Four Star Oil & Gas Company (Four Star) completed in 2013. 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, and Discretionary Cash Flow Per Share to GAAP terms.

Eagle Ford Program
In the third quarter of 2014, the company completed 24 wells across its Eagle Ford program and grew oil production to a record 35.9 MBbls/d, a 38 percent increase compared with the same period in 2013 due to improved completion design and production optimization. Total equivalent production was 52.2 Mboe/d, a 30 percent increase compared with the same period in 2013.

The company continues to be encouraged by the early performance of its 40-acre down-spacing tests on its acreage and expects to have results late this year.

Wolfcamp Program
In the third quarter of 2014, the company completed 26 wells in its Wolfcamp program and produced a record 9.4 MBbls/d of oil in the third quarter of 2014, a 119 percent increase compared with the same period in 2013. Total equivalent production of 17.7 MBoe/d was 177 percent higher than the third quarter of 2013, continuing the program's significant growth driven by improved completion designs and production optimization.

The company continues to optimize completion design and improve well productivity. Its Crockett Country acreage has the benefit of the highest number of wells and the greatest amount of infrastructure and completion knowledge, and recent results reflect the continuous improvement being applied to this large, repeatable drilling inventory.  Average IP 30 rates for its most recent wells exceeded the company's type curve for oil and total equivalent production of 369 BOPD and 521 Boe/d.

EP Energy continues to make good progress on its Wolfcamp A development and expects to have results late this year.

Altamont Program
In the third quarter of 2014, the company completed 14 wells as it continued to optimize well completions with increased drilling efficiencies in its Altamont program. Third quarter 2014 record oil production was 11.8 MBbls/d, a 33 percent increase compared with the same period in 2013.  Total equivalent production was a record 16.1 Mboe/d, a 33 percent increase compared with the same period in 2013.

In October 2014, the Utah Board of Oil, Gas and Mining provisionally approved 80-acre well density on an approximately 50,000 net acre portion of the company's acreage in the Altamont field with the potential to extend this density across the entire position.  The company estimates that the impact of developing the approved acreage would allow for the drilling of up to 350 future locations.

Also during the quarter, the company continued to increase its take-away capacity from the Uinta Basin adding 2,500 barrels per day of sales capacity in the third quarter.

Multi-year Commodity Hedge Program
EP Energy continues to manage a sector leading hedge program with significant commodity price protection for the remainder of 2014, and for 2015 and 2016. As a result, EP Energy's cash flows do not have significant near term commodity price sensitivity.  A summary of the company's hedge positions is listed below:



2014

2015

2016

Total Fixed Price Hedges




Oil volumes (MMBbls)

5.0

21.0

16.9

Average floor price ($/Bbl)

$98.23

$91.19

$90.89

Percent hedged1

~97%

+100%

~84%





Natural gas volumes (TBtu)

17.3

62.1

7.3

Average floor prices ($MMBtu)

$4.02

$4.26

$4.20

Percent hedged1

+100%

~90%

~11%


Note: Positions are as of September 30, 2014 (Contract months: October 2014 - Forward). Volumes presented are MMBbls for oil and TBtu for natural gas and prices presented are per Bbl of oil and MMBtu of natural gas.


Percent hedged volumes based on midpoint of the company's 2014 production outlook.

Increased Borrowing Base
Upon completion of the latest semi-annual borrowing base redetermination, bank commitments to its RBL Facility have increased from $2.5 billion to $2.75 billion. The increase was unanimously approved by the lender group which is comprised of 28 leading financial institutions. The facility, which has $2.1 billion of undrawn capacity, proforma for this increase, provides greater financial flexibility and ample capacity to fund the company's capital program into the foreseeable future.

Consistent 2014 Outlook
For the full year 2014, EP Energy expects capital expenditures of approximately $2 billion, well completions between 270 and 280, average daily production of 96 MBoe/d to 100 MBoe/d including average daily oil production volumes of 54 MBbls/d to 56 MBbls/d, per unit adjusted cash operating costs for the year of $12.90 to $13.90 per Boe, transportation costs of $3.00 to $3.25 per Boe, and per unit depreciation, depletion, and amortization rate for the year of $24.35 to $25.35 per Boe.

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

Webcast Information
EP Energy has scheduled a webcast at noon Eastern Time, 11 a.m. Central Time, on November 5, 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# 2594924) 10 minutes prior to the start of the webcast.  A replay of the webcast will be available through Friday, December 5, 2014 on the company's website in the Investor Center (conference ID# 10053352).

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 fast‐emerging unconventional resource areas. EP Energy is active in all phases of the E&P value chain—exploring for, acquiring, developing and producing oil and natural gas. For more information about EP Energy, visit epenergy.com.

Disclosure of Non-GAAP Financial Measures
The Securities and Exchange Commission's Regulation G applies to any public disclosure or release of material information that includes a non-GAAP financial measure. In the event of such a disclosure or release, Regulation G requires (i) the presentation of the most directly comparable financial measure calculated and presented in accordance with GAAP and (ii) a reconciliation of the differences between the non-GAAP financial measure presented and the most directly comparable financial measure calculated and presented in accordance with GAAP.

Non-GAAP Terms
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 on-going 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), transition, restructuring and other non-recurring costs, 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, and losses on extinguishment of debt.

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










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






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)

Total adjustments


$

(390)


$

(248)


$

(1.01)








Adjusted EPS






$

0.24








    Basic and fully diluted weighted average shares







244


(1) All individual adjustments presented assume a 36.5% 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 an $11 million insurance settlement and $5 million of acquisition costs in the third quarter of 2014.




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






(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

Total adjustments


$

86


$

59


$

0.25








Adjusted EPS






$

0.64








    Basic and fully diluted weighted average shares







241


(1) All individual adjustments presented assume a 36.5% 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 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. 

(4) Represents transaction, management and other fees paid to Sponsors.


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 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 our Sponsors, losses on extinguishment of debt, equity earnings from Four Star prior to its sale in 2013, and impairment charges.  Adjusted EBITDAX Margin Per Unit is calculated using Adjusted EBITDAX divided by consolidated equivalent volumes. 

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




Quarters ended
September 30,


Nine months ended
September 30,



2014


2013


2014


2013



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

   Net income


$

305


$

310


$

97


$

397

   Loss (income) from discontinued operations, net of tax


1


(456)


(3)


(495)

     Income (loss) from continuing operations


306


(146)


94


(98)

Income tax expense


191


30


67


30

Interest expense, net of capitalized interest


76


91


235


269

Depreciation, depletion and amortization


228


164


634


417

Exploration expense


5


12


18


37

EBITDAX


806


151


1,048


655

Mark-to-market on financial derivatives(1) 


(381)


142


44


107

Cash settlements and premiums on financial derivatives(2) 


(3)


(25)


(60)


(2)

Non-cash portion of compensation expense(3) 


2


8


6


22

Transition, restructuring and other costs(4) 


(6)



(5)


7

Fees paid to Sponsors(5)



6


90


19

Loss on extinguishment of debt



6


17


9

    Loss from unconsolidated affiliate




19



13

    Impairment charges



1


2


1


2

Adjusted EBITDAX(6)


$

419


$

309


$

1,141


$

832














Total consolidated equivalent volumes (MBoe)(7)


9,286


7,674


26,256


22,012














Adjusted EBITDAX Margin Per Unit (MBoe)(8)


$

45.12


$

40.09


$

43.46


$

37.74














(1)

Represents the income statement impact of financial derivatives.

(2)

Represents actual cash settlements received/(paid) related to financial derivatives, including cash premiums. No cash premiums were received for the quarter ended September 30, 2014. For the quarter ended September 30, 2013 we received approximately $1 million of cash premiums. For the nine months ended September 30, 2014 and 2013, we received approximately $1 million and approximately $9 million, respectively, of cash premiums.

(3)

For the quarter and nine months ended September 30, 2014, cash payments were less than $1 million and approximately $13 million, respectively, and for the nine months ended September 30, 2013, cash payments were approximately $10 million.

(4)

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. 

(5)

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

(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. The quarter and nine months ended September 30, 2013 do not include $7 million and $34 million, respectively, of Adjusted EBITDAX related to Arklatex and South Louisiana Wilcox classified as discontinued operations.

(7)

Excludes volumes associated with our equity investment in Four Star sold in September 2013.

(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 our Sponsors, 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 income and operating cash flow:


Quarter ended
September 30, 2014


Nine months ended
September 30, 2014

Net income

$

305


$

97

Loss (income) from discontinued operations, net of tax

1


(3)

Income from continuing operations

306


94

Depreciation, depletion and amortization

228


634

Impact of financial derivatives (1)

(384)


(16)

Transition, restructuring and other costs (2)

(6)


(5)

Fees paid to Sponsors (3)


90

Deferred income taxes

197


59

Non-cash exploration expense

4


15

Other non-cash income items

7


46

   Discretionary Cash Flow

$

352


$

917





Discretionary Cash Flow Per Share (4) (5)

$

1.45


$

3.80





Discretionary Cash Flow

$

352


$

917

Transition, restructuring and other costs (2)

6


5

Fees paid to Sponsors (3)


(90)

Working capital and other changes

59


74

   Net cash provided by operating activities

$

417


$

906


(1)

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

(2)

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. 

(3)

Represents transaction, management and other fees paid to Sponsors.

(4)

Reflects basic and fully diluted weighted average shares of approximately 244 million for the quarter ended September 30, 2014 and approximately 241 million for the 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.



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. 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 and Discretionary Cash Flow Per Share 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 and Discretionary Cash Flow Per Share 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 and Discretionary Cash Flow Per Share 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 forwardlooking 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; 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; changes in commodity prices and basis differentials for oil and natural gas; 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 forwardlooking statements made herein or any other forwardlooking 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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