Exhibit 99.1

News
For Immediate Release

EP Energy Announces Fourth Quarter and Full Year 2014 Results and Strong Growth In 2014 Proved Reserves — Met Expectations Twice Raised in 2014

HOUSTON, TEXAS, February 18, 2015—EP Energy Corporation (NYSE:EPE) today reported year end 2014 proved reserves and 2014 financial and operational results for the company.

Key highlights include:

2014 Full Year Results

·            Record annual production of 97.7 thousand barrels of oil equivalent per day (MBoe/d), including 54.8 thousand barrels per day (MBbls/d) of oil — a 51 percent increase in oil production from 2013

·            Adjusted earnings before interest and debt expense, income taxes, depreciation, depletion and amortization and exploration expenses (Adjusted EBITDAX) of $1,547 million — a 36 percent increase from 2013

·            $0.86 adjusted earnings per share (Adjusted EPS)

·            $5.19 Discretionary Cash Flow Per Share

·            273 completed wells — in line with company estimates

2014 Drilling Inventory and Proved Reserves

·            Added more than 500 future locations to drilling inventory since the end of 2013 and now hold nearly 5,700 drilling locations

·            Proved reserves of  622 million barrels of oil equivalent (MMBoe), up 18 percent from year end 2013 excluding 21 MMBoe from assets sold

·            Replaced 343 percent of 2014 production at $16.93 per Boe

“We are proud of our 2014 results with strong growth in EBITDAX and oil volumes and increasing operational efficiencies,” said Brent Smolik, chairman, president and chief executive officer of EP Energy Corporation.  “We improved execution in each of our programs, increased

production volumes and optimized production operations.  We once again met or exceeded our key objectives.  We improved horizontal well lateral placement, enhanced completion designs and reduced down time.  We have a strong liquidity position which is supported by our $2.75 billion revolving credit facility, and we maintain excellent commodity price protection with a significant multi-year hedge program.”

2014 Financial Results

Fourth Quarter 2014

For the quarter ended December 31, 2014, EP Energy reported $0.22 Adjusted EPS and $1.38 Discretionary Cash Flow Per Share.  Adjusted EBITDAX for the fourth quarter 2014 was $406 million, up significantly from $307 million in the fourth quarter of 2013 due primarily to higher oil volumes which also contributed to higher Adjusted EBITDAX Margin Per Unit.

Full Year 2014

For the year ended December 31, 2014, EP Energy reported $0.86 Adjusted EPS and $5.19 Discretionary Cash Flow Per Share.  Adjusted EBITDAX for the year 2014 was $1,547 million, up significantly from $1,139 million in 2013.

Total adjusted cash operating costs for the year ended December 31, 2014 was $13.27 per Boe, which was below the mid-point of company estimates for 2014.  The company ended the year with fourth quarter adjusted cash operating costs of $12.00 per Boe, well below the low end of company estimates.

2014 capital expenditures were $2.2 billion, including acquisitions of $165 million during the year.  EP Energy focused investments in its core programs, spending $1,087 million, $822 million and $283 million in Eagle Ford, Wolfcamp and Altamont, respectively.

Note: Data throughout this release has been adjusted to exclude completed domestic and international asset sales prior to December 31, 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, Discretionary Cash Flow Per Share, Cash Operating Costs and Adjusted Cash Operating Costs to GAAP terms.

Operations

For the year ended December 31, 2014, average daily production was 97.7 MBoe/d, including 54.8 MBbls/d of oil.  Production volumes increased throughout the year and fourth quarter 2014 average daily production was 102.4 MBoe/d, including 59.8 MBbls/d of oil.

Eagle Ford Program

In 2014, the company completed 136 wells in its Eagle Ford program and grew production to a record 50.9 MBoe/d, a 39 percent increase compared with 2013.  During the fourth quarter 2014, the company completed 43 wells and produced 54.4 MBoe/d, a 35 percent increase from the fourth quarter of 2013.

EP Energy continued to lower well costs in its Eagle Ford program with an average well cost of approximately $7.2 million which was approximately three percent lower than 2013 average well cost of $7.4 million.  The company improved efficiencies by drilling multi-well pads, optimizing well and completion designs and refining lateral placement.  The design improvements continue to improve initial well production, which increased significantly in 2014.

In the fourth quarter of 2014, the company divested its non-core acreage position in northern Atascosa County for approximately $28 million.  The divestiture allows EP Energy to focus future capital on the higher return acreage in its Eagle Ford program.

In its Eagle Ford program, EP Energy successfully completed an increased well density pilot program on a portion of its acreage and will move from developing on 60-acre spacing to 40-acre spacing on approximately half of its undeveloped LaSalle County position.  The shift in the development plan will add approximately 220 additional drilling locations in that area.  The company will continue to evaluate the balance of its LaSalle County acreage position for increased density development.

Wolfcamp Program

In 2014, the company completed 90 wells in its Wolfcamp program and produced 15.3 MBoe/d, a 178 percent increase from 2013.  In the fourth quarter of 2014, the company completed 21 wells, continuing the program’s evolution with improved completion designs and production optimization and volumes of 17.2 MBoe/d, a 98 percent increase from the fourth quarter of 2013.

During the fourth quarter of 2014, the company reduced the pace of completions in its Wolfcamp program in order to build a completion backlog enabling increased operational flexibility and more efficient completions going forward.  This was offset by increased completions in the company’s Eagle Ford and Altamont programs.

Total well costs in the Wolfcamp program averaged $6.2 million in 2014 which was up slightly from $5.6 million in 2013 as the company applied enhanced completion designs which included more proppant per well and increased number of frac stages per well.

In 2014, the company continued its combined B and C well development and successfully completed its initial A bench pilot.  Well performance in the program continues to improve with increased knowledge of optimal well lateral landing zones, completion designs and operating efficiencies.  The company is encouraged with improvements in its evolving program, as newer design wells delivered higher production volumes with average 30-day initial production rates of 546 barrels of oil per day from its most recent 6 wells in Crockett County which is nearly 50 percent above current type curve.

Altamont Program

In 2014, the company continued to outperform expectations in its Altamont program with improved operating efficiency and enhanced completion design.  In 2014, the company completed 47 wells and continued to grow production with record full year volumes of 15.5 MBoe/d, 30 percent higher than 2013.  In the fourth quarter 2014, the company completed 11 wells and had production volumes of 16.6 MBoe/d, a 29 percent increase from 2013.

The company continued to reduce well costs in its Altamont program with an average cost of $5.2 million which was approximately four percent below the 2013 average well cost of $5.4 million.

The company has significant Uinta Basin take-away capacity with both local refinery markets and rail options to accommodate its oil production.  EP Energy actively manages markets for its volumes in the region, and in the fourth quarter successfully negotiated a new marketing contract which is expected to narrow basis differentials on a significant percentage of future production.

EP Energy continues to maintain efficient operations in the basin with a current development design based on a vertical well program with 160-acre spacing.  In the fourth quarter, the company received approval for 80-acre well density on approximately 30 percent of its net acreage position in the Altamont field, adding 522 drilling locations, while removing 327 horizontal locations.  The company will continue to review potential to extend this density across the entire position.

2014 Proved Reserves and Inventory

EP Energy’s proved oil and natural gas reserves were 622 MMBoe as of December 31, 2014, which is an 18 percent increase from 2013 excluding 21 MMBoe from assets sold. Total reserve replacement costs were $16.93 per Boe, including price revisions. The company reported that 52 percent of its total reserves in 2014 were oil and 67 percent were liquids.

Below is a reconciliation of proved reserves from December 31, 2013 to December 31, 2014.

(1) Equivalent units are based on a six to one ratio of natural gas to oil. December 31, 2014 reserve estimates are based on the first day 12-month average prices of $94.99 per barrel of oil (WTI) and $4.34 per MMBtu of natural gas (Henry Hub). For comparison, 2013 first day 12-month average prices were $96.94 per barrel of oil (WTI) and $3.67 per MMBtu of natural gas (Henry Hub).

(2) Includes 2 MMBoe from assets sold.

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.

Hedge Program Update

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:

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.

Financial Position and Liquidity

At December 31, 2014, EP Energy’s balance sheet included approximately $22 million of cash and cash equivalents and $4.6 billion of total long-term debt.  The company maintains a significant liquidity position of $1.8 billion at year end 2014.  EP Energy has a $2.75 billion revolving credit facility which is supported by the company’s growing proved reserve base.  The company has no near-term debt maturities with its first significant maturity due in 2017, when amounts outstanding under its revolving credit facility mature.

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 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# 10058623).

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 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, losses on extinguishment of debt, impairment charges and other non-recurring costs, including incremental taxes on organizational restructuring and transition and restructuring charges.

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

(1)         All individual adjustments 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.

(1)         All individual adjustments 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)         Represents transaction, management and other fees paid to Sponsors.

(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.

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:

(1)         Represents exploration expenses only and does not include $3 million of other expense recorded in the fourth quarter of 2014.

(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 for the quarters ended December 31, 2014 and 2013. For the years ended December 31, 2014 and 2013, we received approximately $1 million and $9 million, respectively, of cash premiums.

(4)         No cash payments were made for the quarters ended December 31, 2014 and 2013. For the years ended December 31, 2014 and 2013, cash payments were approximately $13 million and $10 million, respectively.

(5)         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.

(6)         Represents the transaction, management and other fees paid to the Sponsors. Our transaction and management fee agreements with our Sponsors terminated with the completion of our initial public offering in January 2014.

(7)         The year ended December 31, 2014 does not include $11 million of Adjusted EBITDAX related to Arklatex and South Louisiana Wilcox classified as discontinued operations. The quarter and year ended December 31, 2013 does not include $6 million and $34 million, respectively, of Adjusted EBITDAX related to Arklatex and South Louisiana Wilcox classified as discontinued operations.

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

(9)         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:

(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 the transaction, management and other fees paid to the Sponsors. Our transaction and management fee agreements with our Sponsors terminated with the completion of our initial public offering in January 2014.

(4)         Reflects basic and fully diluted weighted average shares of approximately 244 million and 242 million for the quarter and year ended December 31, 2014, respectively.

(5)         The quarter and year ended December 31, 2014 do not include $0.01 and $0.06, 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, 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:

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

(2)                                 For the quarter and 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.

(3)                                 The quarter ended December 31, 2014, includes $3 million of non-cash compensation expense adjusted for cash receipts of less than $1 million and $1 million of restructuring charges.   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:

(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)                                 Recorded in conjunction with early rig termination fees.

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 expenses, 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; 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 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