EP Energy Reports 3Q'18 Results - Drilled the Most Productive Oil Well in Company History and Demonstrated Financial Discipline

Nov 7, 2018

HOUSTON, Nov. 7, 2018 /PRNewswire/ -- EP Energy Corporation (NYSE:EPE) today reported third quarter 2018 financial and operational results.

EP Energy Corporation. (PRNewsFoto/EP Energy Corporation)

3Q'18 Updates - Continuing to Execute Strategy with Focus on Value Creation and De-levering the Business

  • Drilled and completed most productive oil well in company history in Northeastern Utah (NEU), formerly Altamont
  • Drilled most productive Eagle Ford oil well and second most productive Permian oil well in company history
  • Improved capital efficiency in all three assets
  • Operating cash flows $163MM, investing cash flows ($205MM), and financing cash flows of ($1MM)
  • Free cash flow positive of $4MM (excluding hedges) for the first quarter in company history
  • Initiated third Eagle Ford enhanced oil recovery (EOR) pilot project in October
  • Drilled and completed two horizontal wells in NEU and currently have 57 horizontal permits in process
  • Equivalent production of 80.4 MBoe/d
  • Oil production of 46.4 MBbls/d
  • Net loss of $44MM
  • Adjusted EBITDAX of $214MM
  • Oil and gas expenditures of $201MM including $46MM acquisition capital
  • Adjusted oil and gas expenditures of $133MM
  • Completed (based on wells fracture stimulated or frac'd) 31 gross wells
  • G&A expense of $2.91 per Boe, Adjusted G&A expense of $2.05 per Boe
  • Reaffirmed the RBL Facility borrowing base in November and ended the quarter with $666MM of liquidity- $56MM of cash and 100% undrawn RBL Facility capacity
  • Net debt to annualized adjusted EBITDAX improved one full turn from 3Q'17 to 3Q'18

3Q'18 Demonstrating Capital Discipline and Improvement in Leverage Metrics

The third quarter of 2018 was the first quarter in the company's history to be free cash flow positive excluding hedging settlements. This was driven by a combination of improved capital efficiency, reduced costs, and higher oil prices.

3Q'18 Operating and Financial Performance Demonstrate Strong Execution

Below is a summary of third quarter 2018 results compared to the third quarter 2017:


3Q'17

3Q'18

3Q'18

vs. 3Q'17

Oil Production (MBbls/d)

45.1

46.4

+ 3%

Equivalent Production (MBoe/d)

81.0

80.4

- 1%

Percent Oil (%)

55.7

57.7

+ 4%

Produced Volumes (MBoe/d)1

81.0

81.7

+ 1%

LOE per Unit ($/Boe)

5.66

6.16

+ 9%

Adjusted LOE per Unit ($/Boe)2,3

 

5.66

5.88

+ 4%

Lease Operating Expense ($MM)

42.2

45.6

+ 8%

Adjusted Lease Operating Expense ($MM)2,3

42.2

43.5

+ 3%

Adjusted G&A expense per Unit ($/Boe)2

2.63

2.05

- 22%

Net (Loss) ($MM)

(72)

(44)

+ 39%

Adjusted EBITDAX ($MM)2

159

214

+ 35%

Oil and Gas Expenditures ($MM)

162

201

+ 24%

Adjusted Oil and Gas Expenditures (excl. Acquisitions and Other ) ($MM)2

133

133

0%



1

Produced volumes include 8 MMcf/d of reinjected gas volumes used in operations during the 3Q'18.

2 

See Disclosure of Non-GAAP Financial Measures for applicable definitions and reconciliations to GAAP terms.

3

Does not include approximately $2 million or $0.28 per Boe for the quarter ended September 30, 2018 of adjustments under a joint venture agreement.

Unlocking Value in Utah - First Horizontal Well Delivers Most Productive Well in Company History

The company has renamed its position in the Uinta Basin to Northeastern Utah or NEU.  In the third quarter of 2018, the company produced 17.5 MBoe/d, including 12.0 MBbls/d of oil, a four percent decrease from the third quarter of 2017, respectively.  EP Energy operated two joint venture drilling rigs and completed (frac'd) six gross wells and two net wells in the third quarter of 2018.  Total capital invested in NEU in the third quarter of 2018 was $35 million excluding acquisitions.

In the third quarter of 2018, the company completed its first two horizontal wells in NEU.  The Duchesne City 1-25-26-C5-2H well was drilled to a lateral length of approximately 9,800 feet and has produced 110,000 barrels of oil after 78 days, making it the most productive oil well completed in the company's history.  The second well, Duchesne City 1-25-26-C5-1H, was drilled to a lateral length of 7,900 feet and has produced 60,000 barrels of oil after 78 days and is in the top 6% of oil producing wells for the company.

In the fourth quarter of 2018, the company plans to take core samples to assess the potential of horizontal development over the company's entire 159,000 net acres across multiple benches.  Additionally, the company has 57 horizontal permits in process and will focus on NEU horizontal wells in 2019 due to their strong productivity.

Eagle Ford: Significant Oil Growth and Progress on Capital Efficiency Initiatives

The company produced 35.8 MBoe/d, including 25.6 MBbls/d of oil in the third quarter of 2018, a nine percent and 28% increase from the third quarter of 2017, respectively. EP Energy averaged approximately three drilling rigs, invested $92 million excluding acquisition capital and completed (frac'd) 22 gross and 10 net wells in the third quarter of 2018.

EP Energy continued to increase the scale of EOR operations in the third quarter and into the fourth quarter of 2018. In our first EOR pilot, we completed two injection cycles and expect to complete 2-3 more cycles across the three pilot areas by year-end. In August, the company operationalized its second pilot in the north end of its La Salle acreage. In October, the third EOR pilot became operational in the retrograde condensate window in the southern end of its acreage position.  In total, the company recycled approximately 8 MMcfe/d of gas in the third quarter of 2018. The goal for the EOR projects is to significantly increase recoverable reserves and lower finding and development (F&D) costs.

Wells drilled in 2018 with new completion designs have exceeded pre-2018 offset wells by eight percent on net revenue per investment (RPI) as of 160 days. This group of wells are expected to outperform their offsets by 20% based on RPI. In addition, the company completed its two longest Eagle Ford laterals in company history. Both wells are currently in flow back, and we expect to provide a performance update in 4Q'18. The company continues to modify completion designs, lateral lengths and spacing for each pad to maximize returns and minimize F&D costs.

In the fourth quarter of 2018, the company plans to run three rigs and complete 21 wells focused on development in the southern and eastern portion of the La Salle acreage.

Permian: Optimizations Lead to Second Most Productive Well Since Program Inception

In the third quarter of 2018, the company produced 27.1 MBoe/d, including 8.8 MBbls/d of oil, a nine percent and 30% decrease from the third quarter of 2017, respectively. In the third quarter of 2018, the company invested $7 million (excluding drilling JV adjustments) and completed (frac'd) three gross and two net wells.

In 2018, the company applied a new completion design that resulted in the second most productive oil well in program history. Two additional wells with the enhanced design, which came online in September, are currently performing in-line with the improvement.

The company maintains ample take-away capacity out of the basin through contractual agreements with third-party processors and marketing companies.  In addition, the company has 100% of its Midland to Cushing basis exposure hedged in 2018 at -$1.02 per barrel and approximately one-third of its Midland to Cushing basis exposure hedged in 2019 at -$6.47 per barrel.

Multi-year Commodity Hedge Program: Well Positioned in 2018 and ~60 Percent Hedged in 20191

EP Energy maintains a solid hedge program, which provides continued commodity price protection.  A summary of the company's current open hedge positions is listed below: 



2018


2019

Total Fixed Price Hedges





Oil volumes (MMBbls)2


3.8



9.7


Average ceiling price ($/Bbl)


$

63.96



$

67.82


Average floor price ($/Bbl)


$

58.45



$

58.09







Natural Gas volumes (TBtu)


7.0



7.0


Average price ($/MMBtu)


$

3.04



$

2.97



Note: Positions are as of October 22, 2018 (Contract months: September 1, 2018 - Forward)


1

Percentage based on mid-point of 2018 production guidance

2

2018 and 2019 positions include WTI three way collars of 2.2 MMBbls and 7.3 MMBbls, respectively, and WTI collars of 0.3 MMBbls in 2018 and 1.6 MMBbls in 2019.

Liquidity - Financial Flexibility Continues to Improve with Successful Redetermination of RBL Facility  

The company ended the quarter with $56 million in cash and zero borrowings on the RBL Facility, resulting in $666 million of available liquidity and $4.3 billion of net debt (total debt of $4.4 billion less cash of $56 million). In November 2018, the banks reaffirmed the current borrowing base of $1.4 billion and commitments of $629 million.

2018 Outlook Maintained

The table below summarizes the company's current operational and financial guidance for the full year 2018.



3Q'18 YTD
Actuals


FY 2018

Estimate











Production Volumes





Oil production (MBbls/d)


46.4


45 – 47

Total production (MBoe/d)


81.0


79 – 82






Oil & Gas Expenditures ($ million)


$545


$630 – $6701

Eagle Ford


$349


~65%

Permian


$98


~15%

NEU


$98


~20%2






Average Gross Drilling Rigs





Eagle Ford


2.8


3

Permian


0.4


-

NEU


2.0


2






Operating Costs





Lease operating expense ($/Boe)


$5.53


$5.00 – $5.70

Reported G&A expense ($/Boe)


$3.09


$2.90 – $3.25

Adjusted G&A expense ($/Boe)3,5


$2.33


$2.30 – $2.60

Transportation ($/Boe)


$3.44


$3.15 – $3.45

Taxes, other than income ($/Boe)4


$2.86


$2.75 – $2.85

DD&A ($/Boe)


$17.00


$17.00 – $17.50



1

Full year 2018 includes ~$120 million non-drill capital including: ~$55 million for general equipment, ~$20 million for capitalized G&A and interest, ~$20 million for enhanced facility projects, ~$15 million for EOR projects, and ~$10 million for leasing and seismic, and does not include acquisition costs or $22 million drilling joint venture adjustment

Full year 2018 NEU capital includes ~81 recompletions for $47 million.

3

Adjusted G&A represents G&A expense less approximately $0.44 per Boe of non-cash compensation expense and $0.32 per Boe in transition, severance and other costs in YTD 3Q'18 reported G&A and $0.60 - $0.65 per Boe of non-cash compensation expense in FY 2018 Estimate.

4

Severance taxes estimates are based on current WTI prices.

5

See Disclosure of Non-GAAP Financial Measures for applicable definitions and reconciliations to GAAP terms.

Webcast Information

EP Energy has scheduled a webcast at 10:00 a.m. Eastern Time, 9:00 a.m. Central Time, on November 8, 2018, 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 relating to the webcast will be available in the Investor Center.  A limited number of telephone lines will be available to participants by dialing 888-317-6003 (conference ID#8791565) 10 minutes prior to the start of the webcast.  A replay of the webcast will be available through December 15, 2018 on the company's website in the Investor Center or by dialing 877-344-7529 (conference ID#10124370).

About EP Energy

The EP Energy team is driven to deliver superior returns for our investors by developing the oil and natural gas that feeds America's growing energy needs. The company focuses on enhancing the value of its high quality asset portfolio, increasing capital efficiency, maintaining financial flexibility, and pursuing accretive acquisitions and divestitures. EP Energy is working to set the standard for efficient development of hydrocarbons in the U.S. Learn more at epenergy.com.

The following table provides the company's production results, average realized prices, results of operations and certain non-GAAP financial measures for the periods presented.  See Disclosure of Non-GAAP Financial Measures for applicable definitions and reconciliations to GAAP terms.


Quarter ended September 30,


2018


2017

Oil Sales Volumes (MBbls/d)




Eagle Ford

25.6



20.0


Permian

8.8



12.6


NEU

12.0



12.5


Total Oil Sales Volumes

46.4



45.1


Natural Gas Sales Volumes (MMcf/d)




Eagle Ford

30



37


Permian

58



55


NEU

33



34


Total Natural Gas Sales Volumes

121



126


NGLs Sales Volumes (MBbls/d)




Eagle Ford

5.2



6.7


Permian

8.7



8.2


NEU




Total NGLs Sales Volumes

13.9



14.9


Equivalent Sales Volumes (MBoe/d)




Eagle Ford

35.8



32.9


Permian

27.1



29.9


NEU

17.5



18.2


Total Equivalent Sales Volumes

80.4



81.0






Net loss ($ in millions)

(44)



(72)


Adjusted EBITDAX ($ in millions)

214



159


Basic and diluted net loss per common share ($)

(0.18)



(0.29)


Adjusted EPS ($)

(0.04)



(0.12)


Capital Expenditures ($ in millions)(1)

201



162


Adjusted Capital Expenditures ($ in millions)

133



133


Total Operating Expenses ($/Boe)

33.13



31.79


Adjusted Cash Operating Costs ($/Boe)

15.20



14.73


Depreciation, depletion and amortization rate ($/Boe)

17.11



15.92


Average realized prices(2)




Oil price on physical sales ($/Bbl)

66.61



45.49


Oil, including financial derivatives ($/Bbl)(3)

63.37



51.75


Natural gas price on physical sales ($/Mcf)

1.34



2.26


Natural gas, including financial derivatives ($/Mcf)(3)

1.69



2.49


NGLs price on physical sales ($/Bbl)

27.74



18.98


NGLs, including financial derivatives ($Bbl)(3)

24.79



18.45










(1)

The quarter ended September 30, 2018 includes $46 million and $22 million, respectively, of acquisition capital and capital adjustments under a joint venture agreement. The quarter ended September 30, 2017 includes $29 million of acquisition capital.

(2)

Oil and natural gas prices on physical sales reflect operating revenues for oil and natural gas reduced by oil and natural gas purchases associated with managing our physical sales.

(3)

Prices per unit are calculated using total financial derivative cash settlements.


 

EP ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In millions)

(Unaudited)



Quarter ended September 30,


2018


2017

Operating revenues




Oil

$

287



$

189


Natural gas

15



27


NGLs

36



26


Financial derivatives

(44)



(23)


Total operating revenues

294



219






Operating expenses




Oil and natural gas purchases

3




Transportation costs

25



29


Lease operating expense

46



42


General and administrative

21



25


Depreciation, depletion and amortization

127



118


Gain on sale of assets

(1)




Impairment charges



1


Exploration and other expense

2



6


Taxes, other than income taxes

22



16


Total operating expenses

245



237






Operating income (loss)

49



(18)






Other income

2




Gain on extinguishment/modification of debt



24


Interest expense

(95)



(80)


Loss before income taxes

(44)



(74)


Income tax benefit



2


Net loss

$

(44)



$

(72)



 

EP ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)



September 30, 2018



December 31, 2017

ASSETS





Current assets(1)

$

315




$

466


Property, plant and equipment, net(2)


4,913





4,422


Other non-current assets


11





12


Total assets

$

5,239




$

4,900







LIABILITIES AND EQUITY





Current liabilities

$

563




$

448


Long-term debt, net of debt issue costs

4,295




4,022


Other non-current liabilities

64




38


Total stockholders' equity

317




392


Total liabilities and equity

$

5,239




$

4,900










(1)

Balance as of December 31, 2017 includes $172 million of assets held for sale.

(2)

Balance is net of accumulated depreciation, depletion and amortization of $3,554 million and $3,179 million as of September 30, 2018 and December 31, 2017, respectively.


 

EP ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)



Nine months ended September 30,


2018


2017

Net loss

$

(84)



$

(122)


Adjustments to reconcile net loss to net cash provided by operating activities




Non-cash expenses

349



410


Asset and liability changes

115



10


Net cash provided by operating activities

380



298


Net cash used in investing activities

(659)



(434)


Net cash provided by financing activities

290



137








Change in cash, cash equivalents and restricted cash

11



1






Cash, cash equivalents and restricted cash - beginning of period

45



20


Cash, cash equivalents and restricted cash - end of period

$

56



$

21


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 calculated as net income (loss) per common share adjusted for the impact of financial derivatives (mark-to-market effects of financial derivatives, net of cash settlements and cash premiums related to these derivatives), gains and losses on extinguishment/modification of debt, impairment charges, other costs that affect comparability, including transition, severance and other costs and changes in the valuation allowance on deferred tax assets.

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


Quarter ended September 30, 2018


Pre Tax


After Tax


Diluted

EPS(1)


($ in millions, except earnings per share amounts)

Net loss



$

(44)



$

(0.18)








Adjustments(2)






Impact of financial derivatives(3)

$

30



$

23



$

0.09


Transition, severance and other costs

1



1



0.01


Valuation allowance on deferred tax assets



10



0.04


Total adjustments

$

31



$

34



$

0.14








Adjusted EPS





$

(0.04)








Diluted weighted average shares





248





Quarter ended September 30, 2017


Pre Tax


After Tax


Diluted

EPS(1)


($ in millions, except earnings per share amounts)

Net loss



$

(72)



$

(0.29)








Adjustments(2)






Impact of financial derivatives(3)

$

50



$

32



$

0.13


Gain on extinguishment of debt

(24)



(15)



(0.06)


Impairment charges

1






Valuation allowance on deferred tax assets



24



0.10


Total adjustments

$

27



$

41



$

0.17








Adjusted EPS





$

(0.12)








Diluted weighted average shares





246










(1)

Diluted per share amounts are based on actual amounts rather than the rounded totals presented.

(2)

All individual adjustments for all periods presented assume a statutory federal and blended state tax rate, as well as any other income tax effects specifically attributable to that item.

(3)

Represents mark-to-market impact net of cash settlements and cash premiums related to financial derivatives. There were no cash premiums received or paid for the periods presented.

Free Cash Flow is defined as Adjusted EBITDAX less hedge settlements, adjusted oil and gas expenditures, and cash interest calculated on an annualized basis. Below is a reconciliation of our net cash provided by operating activities to Free Cash Flow:



Quarter ended
September 30, 2018



($ in millions)

Net cash provided by operating activities(1)


$

163

Interest expense, net


95

Working capital and other


(44)

Adjusted EBITDAX


$

214

  Less: Hedge settlements


14

  Less: Adjusted oil and gas expenditures(2)


(133)

  Less: One quarter of annualized cash interest


(91)

     Free Cash Flow


$

4




Net cash used in investing activities(1)


$

(205)

Net cash used in financing activities(1)


$

(1)









(1)

Calculated as the difference between YTD September 30, 2018 and YTD June 30, 2018 GAAP Statement of Cash Flow amounts.

(2)

Adjusted oil and gas expenditures excludes $46 million of acquisition capital and $22 million of capital adjustments under a joint venture agreement.

EBITDAX is defined as net income (loss) 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 cash 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 these plans), transition, severance and other costs that affect comparability, gains and losses on extinguishment/modification of debt, gains and/or losses on sale of assets and impairment charges.

Below is a reconciliation of our consolidated net income (loss) to EBITDAX and Adjusted EBITDAX:



Quarter ended September 30,



2018


2017



($ in millions)

Net loss


$

(44)



$

(72)


Income tax benefit




(2)


Interest expense, net of capitalized interest


95



80


Depreciation, depletion and amortization


127



118


Exploration expense


1



3


EBITDAX


179



127


Mark-to-market on financial derivatives(1)


44



23


Cash settlements and cash premiums on financial derivatives(2)


(14)



27


Non-cash portion of compensation expense(3)


5



5


Transition, severance and other costs(4)


1




Gain on sale of assets


(1)




Gain on extinguishment/modification of debt




(24)


Impairment charges




1


Adjusted EBITDAX


$

214



$

159










(1)

Represents the income statement impact of financial derivatives.

(2)

Represents actual cash settlements related to financial derivatives. There were no cash premiums received or paid for the periods presented.

(3)

Non-cash portion of compensation expense represents compensation expense (net of forfeitures) under long-term incentive programs adjusted for cash payments made under these plans.

(4)

Reflects transition and severance costs related to workforce reductions.


Adjusted cash operating costs is a non-GAAP measure that is defined as total operating expenses, excluding depreciation, depletion and amortization expense, exploration expense, impairment charges, gains/losses on sale of assets, the non-cash portion of compensation expense (which represents compensation expense under our long-term incentive programs adjusted for cash payments made under these plans) and transition, severance and other costs that affect comparability.  We use this measure to describe the costs required to directly or indirectly operate our existing assets and produce and sell our oil and natural gas, including the costs associated with the delivery and purchases and sales of produced commodities. Accordingly, we exclude depreciation, depletion, and amortization and impairment charges as such costs are non-cash in nature. We exclude exploration expense from our measure as it is substantially non-cash in nature and is not related to the costs to operate our existing assets. Similarly, gains and losses on the sale of assets are excluded as they are unrelated to our existing assets. We exclude the non-cash portion of compensation expense as well as transition, severance and other costs that affect comparability, as we believe such adjustments allow investors to evaluate our costs against others in our industry and this item can vary across companies due to different ownership structures, compensation objectives or the occurrence of transactions.

Below is a reconciliation of our GAAP operating expenses to non-GAAP adjusted cash operating costs:



Quarter ended September 30,



2018


2017



Total


Per-Unit(1)


Total


Per-Unit(1)



($ in millions, except per unit costs)

Oil and natural gas purchases


$

3



$

0.36



$



$


Transportation costs


25



3.41



29



3.91


Lease operating expense


46



6.16



42



5.66


General and administrative


21



2.91



25



3.28


Depreciation, depletion and amortization


127



17.11



118



15.92


Impairment charges






1



0.09


Gain on sale of assets


(1)



(0.13)






Exploration and other expense


2



0.29



6



0.83


 Taxes, other than income taxes


22



3.02



16



2.10


Total operating expenses


$

245



$

33.13



$

237



$

31.79


Adjustments:









Depreciation, depletion and amortization


$

(127)



$

(17.11)



$

(118)



$

(15.92)


Impairment charges






(1)



(0.09)


Exploration expense


(1)



(0.09)



(3)



(0.40)


Gain on sale of assets


1



0.13






Non-cash portion of compensation expense(2)


(5)



(0.70)



(5)



(0.65)


Transition, severance and other costs(2)


(1)



(0.16)






Adjusted cash operating costs and per-unit adjusted cash costs


$

112



$

15.20



$

110



$

14.73











Total consolidated equivalent volumes (MBoe)




7,401





7,456










(1)

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

(2)

Amounts are excluded in the calculation of adjusted general and administrative expense.

Adjusted general and administrative expenses are defined as general and administrative expenses excluding the non-cash portion of compensation expense which represents compensation expense (net of forfeitures) under our long-term incentive programs adjusted for cash payments under these plans and transition, severance and other costs. Adjusted cash general and administrative expense are defined as Adjusted general and administrative expenses including capitalized labor.

Below is a reconciliation of our GAAP general and administrative expense to non-GAAP adjusted general and administrative expense and non-GAAP adjusted cash general and administrative expense:


Actuals


FY 2018 Estimate



Quarter ended September 30,



2018


2017


Low


High


Total


($/Boe)


Total


($/Boe)


($/Boe)


($/Boe)


($ in millions, except per Boe costs)

GAAP general and administrative expense

$

21



$

2.91



$

25



$

3.28



$

2.90



$

3.25


Less non-cash compensation expense

5



0.70



5



0.65



0.60



0.65


Less transition, severance and other costs

1



0.16










Adjusted general and administrative expense

$

15



$

2.05



$

20



$

2.63



$

2.30



$

2.60


  Capitalized labor

4



0.47



6



0.79






Adjusted cash general and administrative expense

$

19



$

2.52



$

26



$

3.42














(1)

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

Net Debt is a non-GAAP measure defined as long-term debt less cash and cash equivalents.

EBITDAX and Adjusted EBITDAX are used by management and we believe provide 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 without regard to financing methods and capital structure, (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. Free Cash Flow is used by management and we believe provides investors with useful information for analysis of the company's ability to internally fund capital expenditure and to service or incur additional debt. Adjusted Cash Operating Costs ($ and per unit) and Adjusted Lease Operating Expense ($ and per unit) are used by management as a performance measure, and we believe provides investors valuable information related to our operating performance and our operating efficiency relative to other industry participants and comparatively over time across our historical results.  Adjusted General and Administrative expense, Adjusted Cash General and Administrative expense and related per unit measures as well as Adjusted Oil and Gas Expenditures are used by management and investors as additional information as noted above. Net Debt is used by management for analysis of the company's financial position and/or liquidity. 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 Cash Operating Costs, Adjusted Oil and Gas Expenditures, Adjusted Lease Operating Expense, Free Cash Flow, Adjusted General and Administrative expense, Adjusted Cash General and Administrative expense and Net Debt have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under U.S. GAAP. Adjusted EPS should not be used as an alternative to earnings (loss) per share or other measure of financial performance presented in accordance with GAAP. EBITDAX and Adjusted EBITDAX should not be used as an alternative to net income (loss), operating income (loss), operating cash flows or other measures of financial performance or liquidity presented in accordance with GAAP. Adjusted Cash Operating Costs and Adjusted Lease Operating Expense should not be used as an alternative to operating expenses, operating cash flows or other measures of financial performance or liquidity presented in accordance with GAAP. Adjusted General and Administrative expense and Adjusted Cash General and Administrative expense should not be used as an alternative to GAAP general and administrative expense. Free Cash Flow and Adjusted Oil and Gas Expenditures should not be used as an alternative to operating, investing and/or financing cash flows, oil and gas capital expenditures or other measures of liquidity presented in accordance with GAAP. Our presentation of Adjusted EPS, EBITDAX, Adjusted EBITDAX, Adjusted Cash Operating Costs, Adjusted Lease Operating Expense, Adjusted Oil and Gas Expenditures, Adjusted General and Administrative expense, Adjusted Cash General and Administrative expense, Free Cash Flow and Net Debt may not be comparable to similarly titled measures used by other companies in our industry. Furthermore, our presentation of Adjusted EPS, EBITDAX, Adjusted EBITDAX, Adjusted Cash Operating Costs, Adjusted Lease Operating Expense, Adjusted Oil and Gas Expenditures, Adjusted General and Administrative expense, Adjusted Cash General and Administrative expense, Free Cash Flow and Net Debt 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 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 volatility of and potential for sustained low oil, natural gas and NGL prices; 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 operating 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, suppliers and third party operators; 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
Jordan Strauss
713-997-6791
jordan.strauss@epenergy.com

SOURCE EP Energy Corporation