EP Energy Reports First Quarter 2015 Results - Continued Execution Drives Operational Outperformance

Apr 29, 2015

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

EP Energy Corporation.

Key first quarter 2015 highlights include:

  • 60.0 thousand barrels of oil production per day (MBbls/d) — a 23 percent increase from 1Q'14
  • $366 million Adjusted EBITDAX — a 5 percent increase from 1Q'14
  • $0.13 adjusted earnings per share (Adjusted EPS)
  • $1.17 Discretionary Cash Flow Per Share
  • Lower capital and cash costs
  • Increased well performance from enhanced completion designs, primarily from the Wolfcamp program
  • Extended maturity of reserve-based loan (RBL) facility and reaffirmed borrowing base at $2.75 billion
  • Substantial hedges protect cash flows from low commodity prices

"We are off to a great start this year with another successful quarter of operational improvements," said Brent Smolik, chairman, president, and chief executive officer of EP Energy Corporation. "During the quarter, we reduced capital and cash costs more quickly than expected which increases project returns and improves cash margins.  In our Wolfcamp program we are seeing meaningful improvements in well performance driven by a growing knowledge base and enhanced drilling and completion designs.  We expect that additional cost savings and increased well productivity in all capital programs will further improve financial and operational results as we move through the year.  We are well positioned to build value and execute our strategy into the future."

EP Energy reported $0.13 Adjusted EPS and $1.17 Discretionary Cash Flow Per Share for the first quarter 2015. Adjusted EBITDAX for the first quarter of 2015 was $366 million, up from $350 million in the first quarter of 2014, due primarily to higher oil volumes.  Total adjusted cash operating costs for the quarter ended March 31, 2015 was $11.44 per Boe, which was well below $13.46 per Boe for the first quarter 2014. 

The company now expects to realize approximately 20 percent in capital cost reductions in 2015 compared with 2014, which is ahead of original estimates.  Total capital expenditures in the first quarter 2015 were $415 million with nearly $288 million invested in the company's Eagle Ford program.

During the first quarter of 2015, the company completed 57 wells and average daily oil production increased 23 percent to 60.0 MBbls/d of oil, up from 48.6 MBbls/d in the first quarter of 2014. All three of the company's oil programs contributed to this growth. Total equivalent production grew to 102.4 thousand barrels of oil equivalent per day (MBoe/d), up from 90.7 MBoe/d in the same period last year.

Note: Data throughout this release has been adjusted to exclude domestic and international asset sales completed in 2014. 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 first quarter of 2015, the company completed 38 wells across its Eagle Ford program and grew oil production to 38.0 MBbls/d, a 20 percent increase compared with the same period in 2014, due to improved completion design and production optimization. Total equivalent production was 54.7 MBoe/d, an 18 percent increase compared with the same period in 2014.

The company continues to be encouraged by the performance of its enhanced completion designs which generated 90-day cumulative production rates which were 14 percent higher than the company's type curve. The company has continued to improve well performance while significantly lowering well costs each year since it commenced operations in late 2009.

Wolfcamp Program

In the first quarter of 2015, the company completed 10 wells in its Wolfcamp program and produced a record 9.5 MBbls/d of oil, a 32 percent increase compared with the same period in 2014. Total equivalent production of 17.9 MBoe/d was 50 percent higher than the same period in 2014, continuing the program's significant growth driven by improved drilling and completion designs.

Across its Wolfcamp acreage position, EP Energy maintains an extensive 3-D seismic database that covers approximately 1,000 square miles.  The seismic information increases the company's subsurface knowledge and ability to identify, and stay within, the targeted horizontal landing zones.

The company's operations during the quarter were focused primarily in Crockett County areas with the most existing infrastructure. The most recent wells benefited from enhanced completions and improved lateral placement. In the first quarter of 2015, EP Energy reported several wells which were among the highest initial production rate wells in the entire Midland Basin and, 120-day cumulative production from all wells drilled in the first quarter was 68 percent higher than the current type curve.

Altamont Program

In the first quarter of 2015, the company completed 9 wells as it continued to optimize well completions and increase drilling efficiencies in its Altamont program. First quarter 2015 oil production was 12.5 MBbls/d, a 28 percent increase compared with the same period in 2014.  Total equivalent production was 17.1 MBoe/d, a 28 percent increase compared with the same period in 2014.

The company continued to focus activities in the southwestern portion of its acreage position during the quarter.  Looking ahead, the company expects to benefit from higher realized pricing due to expanding Salt Lake City refinery capacity.

Multi-year Commodity Hedge Program

EP Energy continues to benefit from its sector leading hedge program with significant commodity price protection for the remainder of 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:

Total Fixed Price Hedges


2015


2016


2017

Oil volumes (MMBbls)


16.1



18.0



4.0


Average floor price ($/Bbl)


$

91.16



$

80.29



$

66.11


Percent hedged1


96

%


82

%


18

%








Natural gas volumes (TBtu)


46.8



7.3



-

Average floor price ($/MMBtu)


$

4.26



$

4.20



-

Percent hedged1


95

%


11

%


-



























Note:

Positions are as of April 24, 2015 (Contract months: April 2015 - Forward).

(1)

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

 

RBL Facility

In April, EP Energy extended the maturity of its RBL Facility to May 2019 while reaffirming the value of its borrowing base at $2.75 billion2. The extension was unanimously approved by the lender group which is comprised of 27 leading financial institutions. The facility, which has $1.7 billion of undrawn capacity, provides significant financial flexibility and liquidity and is supported by the company's growing oil and natural gas reserves.

Updated 2015 Outlook

As a result of lower realized costs, the company updated its full year capital and cost estimates for 2015.  EP Energy now expects capital expenditures of approximately $1.2 billion to $1.25 billion, per unit adjusted cash operating costs for the year of $10.50 to $12.00 per Boe, transportation costs of $2.95 to $3.15 per Boe.

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

(2)

Maturity date extended to May 2019, provided that the 2018 and 2019 secured term loans and senior notes are retired or refinanced six months prior to maturity.

Webcast Information

EP Energy has scheduled a webcast at 10:00 a.m. Eastern Time, 9:00 a.m. Central Time, on April 30, to discuss its first 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# 0057576) 10 minutes prior to the start of the webcast.  A replay of the webcast will be available through Friday, May 29, 2015 on the company's website in the Investor Center (conference ID# 10063331).

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 income (loss) per share:


Quarter ended March 31, 2015


Pre Tax


After Tax


Diluted EPS


($ in millions, except earnings per share amounts)

Net income



$

19



$

0.08








Adjustments(1)






Impact of financial derivatives(2)

$

11



$

7



$

0.03


Transition, restructuring and other costs(3)

8



5



0.02


Total adjustments

$

19



$

12



$

0.05








Adjusted EPS





$

0.13








Basic and fully diluted weighted average shares





244





Quarter ended March 31, 2014


Pre Tax


After Tax


Diluted EPS


($ in millions, except earnings per share amounts)

Net loss



$

(90)



$

(0.38)


Income from discontinued operations, net of tax



(10)



(0.04)


Loss from continuing operations



$

(100)



(0.42)








Adjustments(1)






Impact of financial derivatives(2)

$

110



$

70



$

0.30


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

$

218



$

144



$

0.60








Adjusted EPS





$

0.18








Basic and fully diluted weighted average shares





238











(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 our 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 income (loss):


Quarters ended
March 31,



2015


2014



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

Net income (loss)

$

19



$

(90)



Income from discontinued operations, net of tax



(10)



Income (loss) from continuing operations

19



(100)



Income tax expense (benefit)

10



(56)



Interest expense, net of capitalized interest

84



79



Depreciation, depletion and amortization

224



192



Exploration expense(1)

5



8



EBITDAX

342



123



Mark-to-market on financial derivatives(2)

(203)



135



Cash settlements and premiums on financial derivatives(3)

214



(25)



Non-cash portion of compensation expense(4)

5



9



Transition, restructuring and other costs(5)

8



1



Fees paid to Sponsors(6)



90



Loss on extinguishment of debt



17



Adjusted EBITDAX(7)

$

366



$

350








Total equivalent volumes (MBoe)

9,218



8,166








Adjusted EBITDAX Margin Per Unit (MBoe)(8)

$

39.73



$

42.81














(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 ended March 31, 2015. For the quarter ended March 31, 2014 we received less than $1 million of cash premiums.



(4)

For the quarters ended March 31, 2015 and 2014, cash payments were less than $1 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 ended March 31, 2014 does not include $8 million 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 our 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 income (loss) and operating cash flow:


Quarters ended
March 31,


2015


2014

Net income (loss)

$

19



$

(90)


Income from discontinued operations, net of tax



(10)


Income (loss) from continuing operations

19



(100)


Depreciation, depletion and amortization

224



192


Impact of financial derivatives(1)

11



110


Transition, restructuring and other costs(2)

8



1


Fees paid to Sponsors(3)



90


Deferred income taxes

10



(57)


Non-cash exploration expense

4



7


Other non-cash income items

10



31


Discretionary Cash Flow

$

286



$

274






Discretionary Cash Flow Per Share(4)(5)

$

1.17



$

1.15






Discretionary Cash Flow

$

286



$

274


Transition, restructuring and other costs(2)

(8)



(1)


Fees paid to Sponsors(3)



(90)


Working capital and other changes

13



40


Net cash provided by operating activities

$

291



$

223












(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 244 million for the quarter ended March 31, 2015 and approximately 238 million for the quarter ended March 31, 2014.



(5)

The quarter ended March 31, 2014 does not include $0.05 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).

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



Quarters ended March 31,



2015


2014



Total

Per-Unit(1)


Total

Per-Unit(1)










($ in millions, except per unit costs)

Total operating expenses


$

380


$

41.27



$

436


$

53.40


Depreciation, depletion and amortization


(224)


(24.30)



(192)


(23.47)


Transportation costs


(27)


(2.90)



(23)


(2.85)


Exploration expense(2)


(5)


(0.51)



(8)


(0.99)


Natural gas purchases


(7)


(0.74)



(3)


(0.43)


Total cash operating costs and per-unit cash costs


$

117


$

12.82



$

210


$

25.66


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


(12)


(1.38)



(100)


(12.20)


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


$

105


$

11.44



$

110


$

13.46









Total equivalent volumes (MBoe)



9,218




8,166


(1)

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



(2)

Represents exploration expense only.



(3)

The quarter ended March 31, 2015, includes $5 million of non-cash compensation expense and $8 million of restructuring charges. The quarter ended March 31, 2014, includes $90 million of transaction, management and other fees paid to our Sponsors, $9 million of non-cash compensation expense and $1 million of restructuring charges.

 

In the table below is the average cash operating costs and adjusted cash operating costs per equivalent unit:


Quarters ended
March 31,


2015


2014

Average cash operating costs ($/Boe)




Lease operating expenses

$

5.12



$

5.42


Production taxes(1)

2.13



3.72


General and administrative expenses(2)

5.09



16.24


Taxes, other than production and income taxes

0.28



0.28


Other expense(3)

0.20




Total cash operating costs

$

12.82



$

25.66


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

(1.38)



(12.20)


Total adjusted cash operating costs

$

11.44



$

13.46




(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 for the quarter ended March 31, 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, 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 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, 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 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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