EP Energy Provides 2015 Outlook Estimates Supported by High Quality Assets, Efficient Operations and Strong Hedge Positions

Feb 18, 2015

HOUSTON, Feb. 18, 2015 /PRNewswire/ -- EP Energy Corporation (NYSE:EPE) today announced its 2015 capital budget, estimates for production volume growth and an update on its multi-year commodity hedges. 

EP Energy Corporation

2015 Outlook Key Highlights:

  • Targeting $1.2 to $1.3 billion oil and gas expenditures – a more than 40 percent reduction from 2014
  • Expect to be cash flow neutral, with capital expenditures in line with estimated operating cash flow including hedge settlements
  • Substantially all of 2015 estimated oil and natural gas production volumes hedged at an average price of $91.19 per barrel of oil and $4.26 per MMBtu of natural gas
  • 94.5 to 109.5 thousand barrels of oil equivalent per day (MBoe/d) total production – up 4 percent at the mid-point from 2014
  • 56,000 to 64,000 barrels of oil per day – mid-point is 10 percent higher than 2014
  • 160 - 190 well completions – compared with 273 in 2014
  • Expecting full year average well costs to be approximately 15 percent lower than 2014 across all its programs
  • Adjusted cash costs per unit of $10.50 to $13.50 expected to be approximately 10 percent lower than in 2014
  • Added more than 500 future locations to drilling inventory since the end of 2013 with nearly 5,700 identified drilling locations – more than 30 years of drilling inventory at 2015 activity levels

"We have strong execution capabilities and an efficient business, which is well-positioned for 2015," said Brent Smolik, chairman, president and chief executive officer of EP Energy Corporation.  "Given the recent decline in commodity prices we believe it's appropriate to reduce capital spending, focus on our highest-return opportunities and strengthen our financial position.  In 2014, we grew oil production more than 50 percent.  In 2015, we expect to grow oil production approximately 10 percent while living within our cash flow.  We control nearly all of our operations which provides significant flexibility for capital allocation and in the pace of development across our asset portfolio as we move through the year. 

"We've built a high-quality asset base which we continue to improve and an organization that operates very efficiently.  We continue to drive down costs within our business and expect approximately 15 percent reductions in overall service costs for the year.  To date, we already have agreements in place which secure at least a 10 percent cost reduction and we expect to realize further savings throughout the year.  We look to maintain our financial strength with significant liquidity supported by our $2.75 billion revolving credit facility and an excellent multi-year hedge program."

Capital Program

EP Energy's 2015 capital spend is expected to be $1.2 billion to $1.3 billion, a reduction of over 40 percent from 2014 including acquisitions.  The company expects over 85 percent of the capital spend to be directed to drilling and completions which is in line with capital spent in 2014. 

The company's 2015 activities will be focused on its highest-return opportunities primarily in the Eagle Ford program and the most efficient areas of the Altamont, Wolfcamp and Haynesville programs.  EP Energy expects to operate an average of six to seven total drilling rigs in its four core programs, completing 160 to 190 wells in 2015.  Equivalent production in 2015 is expected to be 94.5 MBoe/d to 109.5 MBoe/d with 56 to 64 MBbls/d of oil production, up four percent and 10 percent, at the respective mid-points, compared with 2014 production volumes. 


The company will focus significant activity in its Eagle Ford program with approximately 66 percent of its budget allocated to its most efficient, highest-return program where it expects to maintain a three to four rig program during 2015 and complete 115 to 130 wells.  The company expects average well cost of $6.1 million in 2015 compared with an average well cost of $7.2 million in 2014.

In the Wolfcamp, EP Energy is targeting 15 to 20 completed wells in 2015 with approximately  15 percent of the company's capital budget and a one rig program.  The company is encouraged by continuous improvements in its Wolfcamp program as recent wells are benefitting from increased knowledge of well landing zones and enhanced completion designs.   Average well cost in 2015 is expected to be $5.1 million compared with an average well cost of $6.2 million in 2014.

In the Altamont, the company is allocating approximately 11 percent of its capital budget and expects to complete 25 to 30 wells during the year incorporating the 2014 improved completion design.  The company expects to lower average well cost in 2015 to $4.4 million compared with an average well cost of $5.2 million in 2014.     

In the Haynesville, the company maintains approximately 38,000 acres in the core of the play.  The program competes favorably with the company's oil programs in the current price environment. EP Energy expects to re-start drilling operations mid-year 2015 with a one rig program, and is allocating approximately eight percent of its capital to this program.  The company expects to complete 5 to 10 wells in 2015 with an average well cost of $9.1 million for 4,500 to 7,500 foot lateral length wells.  The Haynesville program is expected to benefit from increased well productivity since the company was last active in early 2012.  Since that time, EP Energy has realized step-change improvements in its operational efficiencies and completion design across its horizontal shale drilling programs. 

The company is focused on maintaining efficient operations while driving down cash costs.  In 2015, EP Energy expects adjusted cash costs of $10.50 to $13.50 per Boe, approximately 10 percent less than 2014.

The table below summarizes the company's operational and financial guidance for 2015 compared with 2014 results. 



Capital Investment ($ billion)

Drilling and completion 



Facilities, lease and seismic



G&A, interest and other



Total before acquisitions

$1.2 - $1.3





$1.2 - $1.3



Total production (MBoe/d)

94.5 – 109.5


Oil production (MBbls/d)

56 – 64


Average Drilling Rigs

Eagle Ford

3 – 4











Wells Completed

Eagle Ford

115 – 130



15 – 20



25 – 30



5 – 10



160 – 190


Average Well Cost ($ million)

Eagle Ford












Per-unit adjusted cash cost (per Boe)

$10.50 - $13.50


Transportation cost (per Boe)

$2.90 - $3.35


DD&A rate (per Boe)

$25.00 - $27.00


1 Average well cost includes a combination of wells with between 4,500' to 7,500' lateral lengths in 2015

Multi-year Commodity Hedge Program

EP Energy continues to benefit from a sector-leading hedge program with significant commodity price protection 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 2015 and 2016 hedge positions is listed below:



Total Fixed Price Hedges

Oil volumes (MMBbls)



Average floor price ($/Bbl)



Percent hedged1



Natural gas volumes (TBtu)



Average floor prices ($MMBtu)



Percent hedged1



Note:  Positions are as of February 10, 2015 (Contract months: January 2015 - Forward). 

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


At year end 2014, EP Energy's estimated future drilling inventory, which includes proved undeveloped reserves and unproven resources, included 5,673 identified future drilling locations with 872 in Eagle Ford, 3,300 in Wolfcamp, 1,304 in Altamont and 197 in Haynesville.

Operating Area

YE 2013

2014 Drilling

Acquisitions and


YE 2014

Eagle Ford























Total operating area






Webcast Information

EP Energy has scheduled a webcast at 11 a.m. Eastern Time, 10 a.m. Central Time, on February 19, to discuss its fourth quarter and full year financial and operational results.  The webcast may be accessed online through the company's website at epenergy.com in the Investor Center.  Materials to be discussed during the webcast will be available in the Investor Center one hour prior to the webcast.  A limited number of telephone lines will be available to participants by dialing 888-317-6003 (conference ID# 3592620) 10 minutes prior to the start of the webcast.  A replay of the webcast will be available through March 19, 2015 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

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, impairment charges 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, 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:

Year ended
December 31,



Per Unit(1)

($ in millions, except per unit costs)

Total operating expenses





Depreciation, depletion and amortization



Transportation costs



Exploration expense(2)



Natural gas purchases



Impairment charges



Total cash operating costs



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



Total adjusted cash operating costs and adjusted per-unit cash costs(3) 





Total equivalent volumes (MBoe)



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


For the year ended December 31, 2014, amount does not include approximately $3 million recorded in conjunction with early rig termination fees included in exploration and other expense on our consolidated income statement.


The year ended December 31, 2014 amount includes $90 million of transaction, management and other fees paid to our Sponsors, $11 million of cash received from an insurance settlement, $5 million of acquisition costs, $9 million of non-cash compensation expense and $2 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:

Year ended
December 31,


Average cash operating costs ($/Boe)

Lease operating expenses



Production taxes(1)


General and administrative expenses(2)


Taxes, other than production and income taxes


    Other expense(3)


Total cash operating costs


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


Total adjusted cash operating costs and adjusted per-unit cash costs(2) 




Production taxes include ad valorem and severance taxes.


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.


Recorded in conjunction with early rig termination fees.


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.

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 operating expenses, operating cash flows or other measures of financial performance or liquidity presented in accordance with GAAP. For example, our presentation of 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 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 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; changes in commodity prices and basis differentials for oil and natural gas; the uncertainty of estimating proved reserves and unproved resources; the future level of service and capital costs; the availability and cost of financing to fund future exploration and production operations; the success of drilling programs with regard to proved undeveloped reserves and unproved resources; the company's ability to comply with the covenants in various financing documents; the company's ability to obtain necessary governmental approvals for proposed E&P projects and to successfully construct and operate such projects; actions by the credit rating agencies; credit and performance risk of our lenders, trading counterparties, customers, vendors 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; 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.

Investor and Media Relations
Bill Baerg

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SOURCE EP Energy Corporation