Search the web
Welcome, Guest
[Sign Out, My Account]
EDGAR_Online

Quotes & Info
Enter Symbol(s):
e.g. YHOO, ^DJI
Symbol Lookup | Financial Search
EPE > SEC Filings for EPE > Form 10-Q on 7-Aug-2014All Recent SEC Filings

Show all filings for EP ENERGY CORP

Form 10-Q for EP ENERGY CORP


7-Aug-2014

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

Our Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") should be read in conjunction with the financial statements and the accompanying notes presented in Item 1 of Part I of this Quarterly Report on Form 10-Q. This discussion contains forward-looking statements and involves numerous risks and uncertainties, including, but not limited to, those described in the "Risk Factors" section of our 2013 Annual Report on Form 10-K. Actual results may differ materially from those contained in any forward-looking statements. All periods included in these interim financial statements present our Brazil operations and certain domestic natural gas assets sold as discontinued operations. Unless otherwise indicated or the context otherwise requires, references in this MD&A section to "we", "our", "us" and "the Company" refer to EP Energy Corporation and each of its consolidated subsidiaries.

Our Business

Overview. We are an independent exploration and production company engaged in the acquisition and development of unconventional onshore oil and natural gas properties in the United States. We are focused on creating shareholder value through the development of our low-risk drilling inventory located in four areas: the Eagle Ford Shale (South Texas), the Wolfcamp Shale (Permian Basin in West Texas), the Altamont field in the Uinta Basin (Northeastern Utah) and the Haynesville Shale (North Louisiana). Further information regarding each of our programs is below:

Eagle Ford Shale. The Eagle Ford Shale continues to provide the highest economic returns in our portfolio. We currently are running five rigs in this program.

Wolfcamp Shale. In our Wolfcamp Shale program, we are focused on optimizing our drilling, completion and artificial lift systems. We currently are running four rigs in this program.

Altamont. In Altamont, we are gaining operational efficiencies as we develop this oil-based field. Most of our acreage in this area is held-by-production. We are currently running three rigs in this program.

Haynesville Shale. The Haynesville Shale generates positive cash flow and remains a core natural gas option for us when natural gas prices return to more economic levels in the future. Our acreage in the Haynesville Shale is predominately held-by-production.

We evaluate growth opportunities that are aligned with our core competencies and that are in areas that can provide a competitive advantage. Strategic acquisitions of leasehold acreage or producing assets can provide us with opportunities to achieve our long-term goals by leveraging existing expertise in each of our operating areas, balancing our exposure to regions, basins and commodities, helping us to achieve risk-adjusted returns competitive with those available within our existing drilling programs and by increasing our reserves.

On April 30, 2014, we acquired approximately 37,000 net acres of certain producing properties and undeveloped acreage in the Southern Midland Basin adjacent to our existing Wolfcamp Shale position for an aggregate cash purchase price of $152 million. The acquisition represents an approximate 25 percent expansion of our current Wolfcamp acreage. The acquired properties are 100 percent operated with net production of approximately 1,000 Boe/d which is 75 percent liquids. We are integrating the acquired properties into our existing development program with minimal additional capital.

Additionally, on May 30, 2014, we completed the sale of certain non-core assets in the Arklatex area and in our South Louisiana Wilcox area (approximately 78,000 net acres) for $150 million of cash proceeds, with the buyer also assuming a transportation commitment of approximately $20 million. Net estimated annual production associated with the divested properties is approximately 21 MMcfe/d, approximately 85 percent of which is natural gas.


Table of Contents

We have reflected as discontinued operations in all periods presented certain non-core assets sold or in the process of being sold including (i) certain domestic natural gas assets in our Arklatex area and those in our South Louisiana Wilcox areas sold in May 2014, (ii) domestic natural gas assets sold in June 2013 (including CBM properties located in the Raton, Black Warrior and Arkoma basins; Arklatex conventional natural gas assets located in East Texas and North Louisiana, and legacy South Texas conventional natural gas assets) and
(iii) our Brazilian operations which are under contract to be sold. We expect the sale of our Brazilian operations (which represents the sale of our remaining international assets) to close in 2014, subject to Brazilian regulatory approval and certain other customary closing conditions.

Factors Influencing Our Profitability. Our profitability is dependent on the prices we receive for our oil, natural gas and NGLs, the costs to explore, develop, and produce our oil, natural gas and NGLs, and the volumes we are able to produce, among other factors. Our long-term profitability will be influenced primarily by:

growing our proved reserve base and production volumes through the successful execution of our drilling programs or through acquisitions;

finding and producing oil and natural gas at reasonable costs;

managing cash costs; and

managing commodity price risks on our oil and natural gas production.

In addition to these factors, our future profitability and performance will be affected by volatility in the financial and commodity markets, changes in the cost of drilling and oilfield services, operating and capital costs, and our debt level and related interest costs. Additionally, we may be impacted by weather events, or domestic or regulatory issues in Brazil or other third party actions outside of our control (e.g., oil spills).

To the extent possible, we attempt to mitigate certain of these risks through actions such as entering into longer term contractual arrangements to control costs and entering into derivative contracts to stabilize cash flows and reduce the financial impact of downward commodity price movements on commodity sales. In addition, because we apply mark-to-market accounting, our reported results of operations and financial position can be impacted significantly by commodity price movements from period to period. Adjustments to our strategy and the decision to enter into new positions or to alter existing positions are made based on the goals of the overall company.

Derivative Instruments. Our realized prices from the sale of our oil, natural gas and NGLs are affected by (i) commodity price movements, including locational or basis price differences that exist between the commodity index price (e.g., WTI) and the actual price at which we sell our oil, natural gas, or NGLs, and
(ii) other contractual pricing adjustments contained in the underlying sales contract. In order to stabilize cash flows and protect the economic assumptions associated with our capital investment programs, we enter into financial derivative contracts to reduce the financial impact of unfavorable commodity price movements and locational price differences. During the six months ended June 30, 2014, we (i) settled commodity index hedges on approximately 89% of our liquids (oil and NGLs) production and 99% of our natural gas production at average floor prices of $97.97 per barrel of oil and $4.02 per MMBtu, respectively and (ii) settled basis hedges on approximately 61% of our estimated Eagle Ford oil production. To the extent our oil, natural gas, and NGLs production is unhedged, either from a commodity index price or locational price perspective, our financial results will be impacted from period to period as further described in Operating Revenues. The following table reflects the contracted volumes and the prices we will receive under derivative contracts we held as of June 30, 2014.


Table of Contents

                                     2014                     2015                     2016
                                          Average                  Average                  Average
                            Volumes(1)   Price(1)    Volumes(1)   Price(1)    Volumes(1)    Price(1)
Oil
Fixed Price Swaps
WTI                              6,431   $   97.06       17,373   $   89.34        5,216   $    85.25
Brent                            1,840   $  102.47        2,555   $  100.01        4,026   $    95.01
LLS                                  -   $       -            -   $       -        6,222   $    92.22
Ceilings                           766   $  100.92        1,095   $  100.00            -   $        -
Three Way Collars
Ceiling - WTI                    1,472   $  103.76            -   $       -            -   $        -
Floors - WTI(2)                  1,472   $   95.00            -   $       -            -   $        -
Ceiling - Brent                      -   $       -        1,095   $  110.02            -   $        -
Floors - Brent(3)                    -   $       -        1,095   $  100.00            -   $        -
Basis Swaps
LLS vs. WTI(4)(6)                1,472   $    5.78            -   $       -          183   $     3.00
LLS vs. Brent(5)(6)              1,840   $   (3.72 )      3,650   $   (3.77 )      1,830   $    (1.89 )
Midland vs. Cushing(7)             368   $   (1.20 )          -   $       -            -   $        -
Natural Gas
Fixed Price Swaps                   38   $    4.02           62   $    4.26            7   $     4.20
NGLs
Propane Fixed Price Swaps           15   $    1.14            -   $       -            -   $        -
Propane Collars
Ceilings                             8   $    1.30            -   $       -            -   $        -
Floors                               8   $    1.00            -   $       -            -   $        -



(1) Volumes presented are MBbls for oil, TBtu for natural gas and MMGal for propane. Prices presented are per Bbl of oil, MMBtu of natural gas and Gal for propane.

(2) If market prices settle at or below $75.00 in 2014, we will receive a "locked-in" cash settlement of the market price plus $20.00 per Bbl.

(3) If market prices settle at or below $85.00 in 2015, we will receive a "locked-in" cash settlement of the market price plus $15.00 per Bbl.

(4) EP Energy receives WTI plus basis spread listed and pays LLS.

(5) EP Energy receives Brent less basis spread listed and pays LLS.

(6) We have effective LLS floor prices on future hedged production of $100.57 per Bbl for 2014, $96.24 per Bbl for 2015 and $92.33 per Bbl for 2016. These floors are derived using a combination of fixed price positions and basis positions and do not include any customary refinery or contractual deductions.

(7) EP Energy receives Cushing less basis spread listed and pays Midland.

From July 1, 2014 to August 4, 2014, we added additional LLS fixed price swaps of 0.1 MMBbls on our anticipated 2014 production with an average price of $102.00 per Bbl and LLS hedges of 1.5 MMBbls on our anticipated 2016 production with an average ceiling price of $99.29 per Bbl and an average floor price of $94.00 per Bbl. If market prices settle at or below $80.00 in 2016, we will receive a "locked-in" cash settlement of the market price plus $14.00 per Bbl on the 2016 LLS hedges. Additionally, we entered into offsetting positions on 3 TBtu of natural gas fixed price swaps at an average price of $4.06 per MMBtu related to our anticipated 2014 production in conjunction with the sale of certain natural gas assets. These derivative instruments are not included in the table above.

Summary of Liquidity and Capital Resources. As of June 30, 2014, we had available liquidity, including existing cash, of approximately $2.0 billion. We believe we have sufficient liquidity for 2014 from our cash flows from operations, combined with the availability under our RBL Facility and available cash, to fund our current obligations, projected working capital requirements and capital spending plan. In April 2014, we completed our semi-annual redetermination maintaining the borrowing base of our RBL Facility at $2.5 billion. Additionally, the earliest maturity date of our debt obligations is in 2017. See "Liquidity and Capital Resources" for more information.

Outlook for 2014. For the full year 2014, we expect the following:

Capital expenditures of approximately $2 billion, allocated entirely to our core oil programs: $1 billion for Eagle Ford, $725 million for Wolfcamp, $250 million for Altamont, and additional acquisition capital of approximately $154 million.

Well completions between 255 and 275.

Average daily production volumes for the year of approximately 96 MBoe/d to 100 MBoe/d, including average daily oil production volumes of approximately 54 MBbls/d to 56 MBbls/d.

Per unit adjusted cash operating costs for the year of approximately $12.90 to $13.90 per Boe, and transportation costs of $3.00 to $3.25 per Boe.

Per unit depreciation, depletion and amortization rate for the year of approximately $24.35 to $25.35 per Boe.


Table of Contents

                    Production Volumes and Drilling Summary



Production Volumes. Below is an analysis of our production volumes for the six
months ended June 30:



                           2014   2013

United States (MBoe/d)
Eagle Ford Shale             49     33
Wolfcamp Shale               13      3
Altamont                     15     11
Haynesville Shale            17     32
Other(1)                      -      9
Total (MBoe/d)               94     88

Oil (MBbls/d)(1)             51     33
Natural Gas (MMcf/d)(1)     194    291
NGLs (MBbls/d)(1)            10      7



(1) 2013 includes volumes of Four Star Oil & Gas Company (Four Star), our equity investment sold in September 2013. For the six months ended June 30, 2013, Four Star's production volumes were 1 MBbls/d of oil, 40 MMcf/d of natural gas and 1 MBbls/d of NGLs.

Eagle Ford Shale-Our Eagle Ford Shale equivalent volumes and oil production increased 16 MBoe/d (47%) and 11 MBbls/d (54%), respectively, for the six months ended June 30, 2014 compared to the six months ended June 30, 2013 due to the success of our drilling program in the area. During the six months ended June 30, 2014, we completed 69 additional operated wells in the Eagle Ford, and we had a total of 336 net operated wells as of June 30, 2014. With a majority of our acreage located in the core of the oil window, primarily in LaSalle and Atascosa counties, we continue to grow our oil and NGLs production in the area.

Wolfcamp Shale-Our Wolfcamp Shale equivalent volumes increased 10 MBoe/d (281%) for the six months ended June 30, 2014 compared to the six months ended June 30, 2013 as we continue to progress the development of the program. During the six months ended June 30, 2014, we completed 43 additional operated wells, and as of June 30, 2014 we had a total of 162 net operated wells (which includes wells acquired in April 2014).

Altamont-Our Altamont equivalent volumes increased 3 MBoe/d (30%) for the six months ended June 30, 2014 compared to the six months ended June 30, 2013. Altamont produced an average of 11 MBbls/d of oil during the six months ended June 30, 2014, and we completed 22 additional operated oil wells for a total of 335 net operated wells at June 30, 2014.

Haynesville Shale-Our Haynesville Shale equivalent volumes decreased 14 MMcf/d (45%) for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, due to natural production declines. Our Haynesville drilling program remains suspended based on current natural gas prices. As of June 30, 2014, we had 99 net operated wells in the Haynesville Shale, and our total production for the six months ended June 30, 2014 was approximately 105 MMcf/d.


Table of Contents

                             Results of Operations



The information in the table below provides a summary of our generally accepted
accounting principles (GAAP) financial results.



                                            Quarters ended             Six months ended
                                               June 30,                    June 30,
                                           2014         2013          2014          2013
                                                           (in millions)

Operating revenues
Oil                                     $      461    $     284    $      867    $      541
Natural gas                                     75           91           153           165
NGLs                                            30           15            57            29
Total physical sales                           566          390         1,077           735
Financial derivatives                         (290 )        166          (425 )          35
Total operating revenues                       276          556           652           770

Operating expenses
Natural gas purchases                            5            8             8            10
Transportation costs                            26           22            49            42
Lease operating expense                         50           36            94            71
General and administrative                      42           55           175           113
Depreciation, depletion and
amortization                                   214          137           406           253
Exploration expense                              5           13            13            25
Taxes, other than income taxes                  34           13            67            34
Total operating expenses                       376          284           812           548

Operating (loss) income                       (100 )        272          (160 )         222
Other income                                     -            5             -             7
Loss on extinguishment of debt                   -           (2 )         (17 )          (3 )
Interest expense                               (80 )        (86 )        (159 )        (178 )
(Loss) income from continuing
operations before income taxes                (180 )        189          (336 )          48
Income tax benefit                             (68 )          -          (124 )           -
(Loss) income from continuing
operations                                    (112 )        189          (212 )          48
(Loss) income from discontinued
operations, net of tax                          (6 )         12             4            39
Net (loss) income                       $     (118 )  $     201    $     (208 )  $       87


Table of Contents

Operating Revenues

The table below provides our operating revenues, volumes and prices per unit for the quarter and six months ended June 30, 2014 and 2013. We present (i) average realized prices based on physical sales of oil, natural gas and NGLs as well as
(ii) average realized prices inclusive of the impacts of financial derivative settlements and premiums which reflect cash received or paid during the respective period.

                                             Quarters ended          Six months ended
                                                June 30,                 June 30,
                                            2014         2013        2014         2013
                                                          (in millions)
Operating revenues:
Oil                                       $     461    $    284    $     867    $    541
Natural gas                                      75          91          153         165
NGLs                                             30          15           57          29
Total physical sales                            566         390        1,077         735
Financial derivatives                          (290 )       166         (425 )        35
Total operating revenues                  $     276    $    556    $     652    $    770

Volumes:
Oil (MBbls)(1)                                4,848       3,105        9,221       5,856
Natural gas (MMcf)(1)                        17,429      25,529       35,128      52,779
NGLs (MBbls)(1)                               1,051         716        1,894       1,269
Equivalent volumes (MBoe)(1)                  8,804       8,077       16,970      15,923
Total MBoe/d                                     97          89           94          88

Prices per unit(2):
Oil
Average realized price on physical
sales ($/Bbl)(3)                          $   95.04    $  93.45    $   93.99    $  94.49
Average realized price, including
financial derivatives ($/Bbl)(3)(4)       $   90.76    $  99.71    $   90.97    $ 101.25
Natural gas
Average realized price on physical
sales ($/Mcf)(3)                          $    4.07    $   3.73    $    4.15    $   3.40
Average realized price, including
financial derivatives ($/Mcf)(4)          $    3.38    $   2.68    $    3.32    $   3.07
NGLs
Average realized price on physical
sales ($/Bbl)                             $   27.93    $  25.80    $   29.87    $  28.30
Average realized price, including
financial derivatives ($/Bbl)(4)          $   28.46    $      -    $   29.77    $      -



(1) In September 2013, we sold our equity investment in Four Star. For the quarter and six months ended June 30, 2013, Four Star's production volumes were 68 MBbls and 136 MBbls of oil, 3,638 MMcf and 7,317 MMcf of natural gas, 117 MBbls and 229 MBbls of NGLs and 792 MBoe and 1,585 MBoe of equivalent volumes, respectively.

(2) Prices per unit are based on consolidated volumes and do not include volumes associated with Four Star which was sold in September 2013. Natural gas prices for the quarter and six months ended June 30, 2014 are calculated including a reduction of $5 million and $8 million, respectively, for natural gas purchases associated with managing our physical gas sales. Natural gas prices for the quarter and six months ended June 30, 2013 are calculated including a reduction of $8 million and $10 million, respectively, for natural gas purchases associated with managing our physical gas sales.

(3) Changes in realized oil and natural gas prices reflect the effects of unfavorable unhedged locational or basis differentials and contractual deductions between the commodity price index and the actual price at which we sold our oil and natural gas.

(4) The quarters ended June 30, 2014 and 2013, include approximately $22 million of cash paid and approximately $8 million of cash received, respectively, for the settlement of crude oil derivative contracts and approximately $12 million and $23 million of cash paid, respectively, for the settlement of natural gas financial derivatives. The six months ended June 30, 2014 and 2013, include approximately $29 million of cash paid and approximately $31 million of cash received, respectively, for the settlement of crude oil derivative contracts and approximately $29 million and $16 million of cash paid, respectively, for the settlement of natural gas financial derivatives. For the quarter and six months ended June 30, 2014, we received approximately $1 million and paid less than $1 million for the settlement of NGLs derivative contracts. Cash premiums received for the quarters ended June 30, 2014 and 2013 were approximately $1 million and less than $1 million and for the six months ended June 30, 2014 and 2013 were approximately $1 million and approximately $8 million.


Table of Contents

Physical sales. Physical sales represent accrual-based commodity sales transactions with customers. For the quarter and six months ended June 30, 2014, physical sales increased by $176 million (45%) and $342 million (47%), respectively, compared to the same periods in 2013 largely attributable to period-over-period increases in oil volumes. The table below displays the price and volume variances on our physical sales when comparing the quarters and six months ended June 30, 2014 and 2013.

                                     Quarter ended
                         Oil     Natural gas    NGLs     Total
                                     (in millions)

June 30, 2013 sales     $ 284   $          91   $  15   $   390
Change due to prices        8               3       3        14
Change due to volumes     169             (19 )    12       162
June 30, 2014 sales     $ 461   $          75   $  30   $   566

                                   Six months ended
                         Oil     Natural gas    NGLs     Total
                                     (in millions)

June 30, 2013 sales     $ 541   $         165   $  29   $   735
Change due to prices       (4 )            26       3        25
Change due to volumes     330             (38 )    25       317
June 30, 2014 sales     $ 867   $         153   $  57   $ 1,077

Oil sales for the quarter and six months ended June 30, 2014 compared to the same periods in 2013 increased by $177 million (62%) and $326 million (60%), respectively, due primarily to oil volume growth from our Eagle Ford, Wolfcamp and Altamont drilling programs. For the quarter and six months ended June 30, 2014 compared to the same periods in 2013, Eagle Ford oil production increased by 52% (12 MBbls/d) and 54% (11 MBbls/d), respectively. Wolfcamp oil production increased by 169% (5 MBbls/d) and 239% (5 MBbls/d), respectively, and Altamont oil production volumes increased by 42% (3 MBbls/d) and 33% (3 MBbls/d), respectively.

Natural gas sales decreased for the quarter and six months ended June 30, 2014 compared to the same periods in 2013 primarily due to a decrease in volumes due to natural production declines in the Haynesville Shale partially offset by higher natural gas prices. Our Haynesville drilling program remains suspended based on current natural gas prices.

Our oil and natural gas is typically sold at index prices (NYMEX, LLS, WTI or Henry Hub) or posted prices at various delivery points across our producing basins. Realized prices received (not considering the effects of hedges) are generally less than the stated index price as a result of contractual deducts, differentials from the index to the delivery point and/or discounts for quality or grade. Generally as the index price of our commodities increase, deducts and differentials widen and can further widen for temporary or permanent changes in supply or demand, capacity constraints or the build out of infrastructure in developing areas.

In the Eagle Ford, our oil is sold in a largely LLS-based market. In Wolfcamp, . . .

  Add EPE to Portfolio     Set Alert         Email to a Friend  
Get SEC Filings for Another Symbol: Symbol Lookup
Quotes & Info for EPE - All Recent SEC Filings
Copyright © 2014 Yahoo! Inc. All rights reserved. Privacy Policy - Terms of Service
SEC Filing data and information provided by EDGAR Online, Inc. (1-800-416-6651). All information provided "as is" for informational purposes only, not intended for trading purposes or advice. Neither Yahoo! nor any of independent providers is liable for any informational errors, incompleteness, or delays, or for any actions taken in reliance on information contained herein. By accessing the Yahoo! site, you agree not to redistribute the information found therein.