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EX-12.1 - EXHIBIT 12.1 - EP Energy LLCex121ratioofearningsllc630.htm
EX-32.2 - EXHIBIT 32.2 - EP Energy LLCex32263016llc10q.htm
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EX-31.1 - EXHIBIT 31.1 - EP Energy LLCex31163016llc10q.htm

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 Form 10-Q
 
 
(Mark One)
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2016
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
                     For the transition period from             to             
Commission File Number 333-183815
 
 
 
EP Energy LLC
(Exact Name of Registrant as Specified in Its Charter)
Delaware
45-4871021
(State or Other Jurisdiction of
 Incorporation or Organization)
(I.R.S. Employer
 Identification No.)
 
 
1001 Louisiana Street
Houston, Texas
77002
(Address of Principal Executive Offices)
(Zip Code)
 Telephone Number: (713) 997-1000
 Internet Website: www.epenergy.com
 
 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes o  No x
 Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o
 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.:
Large accelerated filer o
 
Accelerated filer o
 
 
 
Non-accelerated filer x
 
Smaller reporting company o
(Do not check if a smaller reporting company)
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes o  No x
 



EP ENERGY LLC
 
TABLE OF CONTENTS
 
Below is a list of terms that are common to our industry and used throughout this document:
 
/d
 
=
 
per day
Bbl
 
=
 
barrel
Boe
 
=
 
barrel of oil equivalent
Gal
 
=
 
gallons
LLS
 
=
 
light Louisiana sweet crude oil
MBoe
 
=
 
thousand barrels of oil equivalent
MBbls
 
=
 
thousand barrels
Mcf
 
=
 
thousand cubic feet
MMBtu
 
=
 
million British thermal units
MMBbls
 
=
 
million barrels
MMcf
 
=
 
million cubic feet
MMGal
 
=
 
million gallons
NGLs
 
=
 
natural gas liquids
NYMEX
 
=
 
New York Mercantile Exchange
TBtu
 
=
 
trillion British thermal units
WTI
 
=
 
West Texas intermediate
 
When we refer to oil and natural gas in “equivalents”, we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil and/or NGLs is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.
 
When we refer to “us”, “we”, “our”, “ours”, “the Company” or “EP Energy”, we are describing EP Energy LLC and/or our subsidiaries.
 

i


CAUTIONARY STATEMENTS FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
 
We have made statements in this document that constitute forward-looking statements, as that term is defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements include information concerning possible or assumed future results of operations. The words “believe”, “expect”, “estimate”, “anticipate” and similar expressions will generally identify forward-looking statements. These statements may relate to information or assumptions about:
 
capital and other expenditures;
financing plans;
capital structure;
liquidity and cash flow;
pending legal proceedings, claims and governmental proceedings, including environmental matters;
future economic and operating performance;
operating income;
management’s plans; and
goals and objectives for future operations.
Forward-looking statements are subject to risks and uncertainties. While we believe the assumptions or bases underlying the forward-looking statements are reasonable and are made in good faith, we caution that assumed facts or bases almost always vary from actual results, and these differences can be material, depending upon the circumstances. We cannot assure you that the statements of expectation or belief contained in our forward-looking statements will result or be achieved or accomplished. Important factors that could cause actual results to differ materially from estimates or projections contained in our forward-looking statements are described in our 2015 Annual Report on Form 10-K. There have been no material changes to the risk factors described in the Form 10-K.

1


PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

EP ENERGY LLC
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In millions)
(Unaudited) 

 
Quarter ended 
 June 30,
 
Six months ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
Operating revenues
 

 
 

 
 

 
 

Oil
$
165

 
$
307

 
$
294

 
$
536

Natural gas
25

 
46

 
67

 
94

NGLs
15

 
15

 
26

 
28

Financial derivatives
(105
)
 
(179
)
 
(63
)
 
24

Total operating revenues
100

 
189

 
324

 
682

 
 
 
 
 
 
 
 
Operating expenses
 

 
 

 
 

 
 

Oil and natural gas purchases
3

 
8

 
7

 
15

Transportation costs
24

 
25

 
54

 
52

Lease operating expense
38

 
47

 
80

 
94

General and administrative
32

 
35

 
70

 
82

Depreciation, depletion and amortization
97

 
253

 
210

 
477

Gain on sale of assets
(82
)
 

 
(82
)
 

Exploration and other expense
1

 
6

 
2

 
12

Taxes, other than income taxes
14

 
23

 
28

 
45

Total operating expenses
127

 
397

 
369

 
777

 
 
 
 
 
 
 
 
Operating loss
(27
)
 
(208
)
 
(45
)
 
(95
)
Gain (loss) on extinguishment of debt
162

 
(41
)
 
358

 
(41
)
Interest expense
(73
)
 
(81
)
 
(157
)
 
(165
)
Income (loss) before income taxes
62

 
(330
)
 
156

 
(301
)
Income tax benefit

 
(120
)
 

 
(110
)
Net income (loss)
$
62

 
$
(210
)
 
$
156

 
$
(191
)
 
See accompanying notes.


2


EP ENERGY LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(Unaudited)
 
 
June 30, 2016
 
December 31, 2015
ASSETS
 

 
 

Current assets
 

 
 

Cash and cash equivalents
$
36

 
$
24

Accounts receivable
 

 
 

Customer, net of allowance of $1 in 2016 and 2015
121

 
189

Other, net of allowance of $1 in 2016 and 2015
9

 
12

Materials and supplies
22

 
24

Derivative instruments
294

 
694

Assets held for sale

 
344

Prepaid assets
4

 
5

Total current assets
486

 
1,292

Property, plant and equipment, at cost
 

 
 

Oil and natural gas properties
6,934

 
6,721

Other property, plant and equipment
83

 
80

 
7,017

 
6,801

Less accumulated depreciation, depletion and amortization
2,563

 
2,374

Total property, plant and equipment, net
4,454

 
4,427

Other assets
 

 
 

Derivative instruments
44

 
85

Unamortized debt issue costs - revolving credit facility
14

 
23

Other
1

 
1

 
59

 
109

Total assets
$
4,999

 
$
5,828

 
See accompanying notes.

3


EP ENERGY LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(Unaudited)
 
 
June 30, 2016
 
December 31, 2015
LIABILITIES AND EQUITY
 

 
 

Current liabilities
 

 
 

Accounts payable
 

 
 

Trade
$
60

 
$
69

Other
118

 
164

Income tax payable to parent
6

 
6

Derivative instruments
1

 

Accrued interest
37

 
47

Asset retirement obligations
1

 
1

Liabilities related to assets held for sale

 
24

Short-term debt, net of debt issue costs
53

 

Other accrued liabilities
29

 
46

Total current liabilities
305

 
357

 
 
 
 
Long-term debt, net of debt issue costs
3,876

 
4,812

Other long-term liabilities
 

 
 

Derivative instruments

 
8

Asset retirement obligations
39

 
37

Other
8

 
6

Total non-current liabilities
3,923

 
4,863

 
 
 
 
Commitments and contingencies (Note 7)


 


Member’s equity
771

 
608

Total liabilities and equity
$
4,999

 
$
5,828

 
See accompanying notes.


4


EP ENERGY LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)
 
 
Six months ended June 30,
 
2016
 
2015
Cash flows from operating activities
 

 
 

Net income (loss)
$
156

 
$
(191
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
 

 
 

Depreciation, depletion and amortization
210

 
477

Gain on sale of assets
(82
)
 

Deferred income tax benefit

 
(115
)
(Gain) loss on extinguishment of debt
(358
)
 
41

Other
17

 
27

Asset and liability changes
 

 
1

Accounts receivable
86

 
30

Accounts payable
(32
)
 
(87
)
Derivative instruments
434

 
370

Accrued interest
(10
)
 
(4
)
Other asset changes
3

 

Other liability changes
(21
)
 
(6
)
Net cash provided by operating activities
403

 
542

 
 
 
 
Cash flows from investing activities
 

 
 

Cash paid for capital expenditures
(258
)
 
(804
)
Proceeds from the sale of assets
390

 

Other

 
1

Net cash provided by (used in) investing activities
132

 
(803
)
 
 
 
 
Cash flows from financing activities
 

 
 

Proceeds from issuance of long-term debt
575

 
1,465

Repayments and repurchases of long-term debt
(1,097
)
 
(1,199
)
Contribution from parent

 
20

Debt issuance costs
(1
)
 
(19
)
Net cash (used in) provided by financing activities
(523
)
 
267

 
 
 
 
Change in cash and cash equivalents
12

 
6

Cash and cash equivalents
 

 
 
Beginning of period
24

 
21

End of period
$
36

 
$
27

 
See accompanying notes


5


EP ENERGY LLC
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(In millions)
(Unaudited)
 
 
Total Member’s
Equity
Balance at December 31, 2015
$
608

Share-based compensation
9

Distribution to parent
(2
)
Net income
156

Balance at June 30, 2016
$
771

 
See accompanying notes.


6


EP ENERGY LLC
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. Basis of Presentation and Significant Accounting Policies
 
Basis of Presentation
We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission (SEC) and in accordance with United States generally accepted accounting principles (U.S. GAAP) as it applies to interim financial statements. Because this is an interim period report presented using a condensed format, it does not include all of the disclosures required by U.S. GAAP and should be read along with our 2015 Annual Report on Form  10-K. The condensed consolidated financial statements as of June 30, 2016 and 2015 are unaudited. The consolidated balance sheet as of December 31, 2015 has been derived from the audited consolidated balance sheet included in our 2015 Annual Report on Form 10-K.  In our opinion, all adjustments which are of a normal, recurring nature are reflected to fairly present these interim period results. The results for any interim period are not necessarily indicative of the expected results for the entire year. 
Significant Accounting Policies
There were no changes in significant accounting policies as described in the 2015 Annual Report on Form 10-K.
New Accounting Pronouncements Issued But Not Yet Adopted
The following accounting standards have been issued but not yet adopted as of June 30, 2016.
Stock Compensation.  In March 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-09, Improvements to Employee Share-Based Payment Accounting, which updates several aspects of the accounting for and disclosure of share-based payment transactions. Adoption of this standard is required beginning in the first quarter of 2017 and early adoption is allowed. We are evaluating the impact this update will have in our financial statements.

Leases.  In February 2016, the FASB issued ASU No. 2016-02, Leases, which requires lessees to recognize lease assets and lease liabilities on the balance sheet and disclose key information about leasing arrangements.  Adoption of this standard is required beginning in the first quarter of 2019 and early adoption is allowed.  We are evaluating the impact this update will have in our financial statements.

Revenue Recognition.  In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which clarifies the principles for recognizing revenue and develops a common revenue standard for U.S. GAAP and International Financial Reporting Standards. In July 2015, the FASB approved the deferral of the new revenue standard by one year, with the option of early adoption in 2017 or, if not adopted early, beginning in the first quarter of 2018. Retrospective application of this standard is required upon adoption.  We are currently evaluating the impact, if any, that this update will have on our financial statements.


7


2. Divestitures

In May 2016, we completed the sale of our assets located in the Haynesville and Bossier shales for approximately $420 million (net cash proceeds of $390 million after customary adjustments). We recorded a gain on the sale of approximately $83 million, with the buyer also assuming a transportation commitment totaling $106 million. We classified the assets and liabilities associated with the assets sold as held for sale on our consolidated balance sheet as of December 31, 2015.
Summarized operating results and financial position data of our assets held for sale were as follows (in millions):
 
Quarter ended 
 June 30,
 
Six months ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
Operating revenues
$
6

 
$
17

 
$
26

 
$
36

 
 
 
 
 
 
 
 
Operating expenses
 

 
 

 
 
 
 
Transportation costs
2

 
5

 
7

 
11

Lease operating expense

 
1

 
1

 
3

Depreciation, depletion and amortization

 
7

 
16

 
13

Other expense
1

 
4

 
5

 
6

Total operating expenses
3

 
17

 
29

 
33

Gain on sale of assets
83

 

 
83

 

Income before income taxes
$
86

 
$

 
$
80

 
$
3

 
December 31, 2015
Assets
 
Current assets
$
16

Property, plant and equipment, net
328

Total assets held for sale
$
344

 
 
Liabilities
 
Accounts payable
$
17

Other current liabilities
4

Asset retirement obligations
3

Total liabilities related to assets held for sale
$
24



3. Income Taxes
 
General. Our taxable income or loss is included in our parent's (EP Energy Corporation) U.S. federal and certain state returns. EP Energy Corporation pays all consolidated U.S. federal and state income tax directly to the appropriate taxing jurisdictions. We record income taxes on a separate return basis in our financial statements as if we had filed separate income tax returns under our existing structure. In certain states, we also file and pay directly to the state taxing authorities.
Effective Tax Rate. Interim period income taxes are computed by applying an anticipated annual effective tax rate to year-to-date income or loss, except for significant, unusual or infrequently occurring items, which income tax effects are recorded in the period in which they occur. Changes in tax laws or rates are recorded in the period they are enacted.

For the quarter and six months ended June 30, 2016, our effective tax rates were 0%. Our effective tax rates differed from the statutory rate as a result of adjustments to the valuation allowance on our deferred tax assets which offset deferred income tax expense by $24 million and $59 million for the quarter and six months ended June 30, 2016, respectively. We evaluate the realization of our deferred tax assets and record a valuation allowance after considering cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in prior carryback years, tax planning strategies and future taxable income for each of our taxable jurisdictions. Based upon the evaluation of the available evidence, we maintained a valuation allowance against our net deferred tax assets of $380 million as of June 30, 2016.

8


Our effective tax rate for the quarter and six months ended June 30, 2015 was relatively consistent with the statutory tax rate. Our effective tax rates in 2015 were primarily impacted by the effects of state income taxes (net of federal
income tax effects).

Other. The Company's and certain subsidiaries' income tax years remain open and subject to examination by both federal and state tax authorities. Our parent's, EPE Acquisition LLC, 2013 U.S. tax return is under examination by the IRS.


4. Fair Value Measurements
 
We use various methods to determine the fair values of our financial instruments. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value.  As of June 30, 2016 and December 31, 2015, all derivative financial instruments were classified as Level 2. Our assessment of the level of an instrument can change over time based on the maturity or liquidity of the instrument.

The following table presents the carrying amounts and estimated fair values of our financial instruments:
 
 
June 30, 2016
 
December 31, 2015
 
Carrying
 Amount
 
Fair
 Value
 
Carrying
 Amount
 
Fair
 Value
 
(in millions )
Short-term debt
$
54

 
$
34

 
$

 
$

 
 
 
 
 
 
 
 
Long-term debt (see Note 6)
$
3,916

 
$
3,041

 
$
4,869

 
$
3,379

 
 
 
 
 
 
 
 
Derivative instruments
$
337

 
$
337

 
$
771

 
$
771

 
As of June 30, 2016 and December 31, 2015, the carrying amount of cash and cash equivalents, accounts receivable and accounts payable represent fair value because of the short-term nature of these instruments. We hold long-term debt obligations with various terms. We estimated the fair value of debt (representing a Level 2 fair value measurement) primarily based on quoted market prices for the same or similar issuances, including consideration of our credit risk.
Oil, Natural Gas and NGLs Derivative Instruments.  We attempt to mitigate a portion of our commodity price risk and stabilize cash flows associated with forecasted sales of oil, natural gas and NGLs through the use of financial derivatives.  As of June 30, 2016, we had fixed price derivative contracts for 21 MMBbls (8 MMBbls of 2016 fixed price swap positions and 13 MMBbls of 2017 fixed price swap positions) of oil. In addition, as of June 30, 2016 we had derivative contracts that offset positions on 0.4 MMBbls of 2016 oil fixed price swaps. As of December 31, 2015, we had fixed price derivative contracts for 23 MMBbls of oil.  As of June 30, 2016 and December 31, 2015, we also had derivative contracts on 11 TBtu of natural gas and 8 MMGal of propane and 7 TBtu of natural gas and 15 MMGal of propane, respectively. In addition, we have derivative contracts related to locational basis differences and/or timing of physical settlement prices on our oil production. None of our derivative contracts are designated as accounting hedges.
The following table presents the fair value associated with our derivative financial instruments as of June 30, 2016 and December 31, 2015. All of our derivative instruments are subject to master netting arrangements which provide for the unconditional right of offset for all derivative assets and liabilities with a given counterparty in the event of default. We present assets and liabilities related to these instruments in our balance sheets as either current or non-current assets or liabilities based on their anticipated settlement date, net of the impact of master netting agreements.  On derivative contracts recorded as assets in the table below, we are exposed to the risk that our counterparties may not perform.

9


 
Level 2
 
Derivative Assets
 
Derivative Liabilities
 
Gross Fair Value
 
 
 
Balance Sheet Location
 
Gross Fair Value
 
 
 
Balance Sheet Location
 
 
Impact of
Netting
 
Current
 
Non-
current
 
 
Impact of
Netting
 
Current
 
Non-
current
 
 
 
(in millions)
 
 
 
 
 
(in millions)
 
 
June 30, 2016
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Derivative instruments
$
362

 
$
(24
)
 
$
294

 
$
44

 
$
(25
)
 
$
24

 
$
(1
)
 
$

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2015
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Derivative instruments
$
795

 
$
(16
)
 
$
694

 
$
85

 
$
(24
)
 
$
16

 
$

 
$
(8
)
For the quarters ended June 30, 2016 and 2015, we recorded derivative losses of $105 million and $179 million, respectively, on our oil, natural gas and NGLs financial derivative instruments. For the six months ended June 30, 2016 and 2015, we recorded a derivative loss of $63 million and a derivative gain of $24 million, respectively. Derivative gains and losses on our oil, natural gas and NGLs financial derivative instruments are recorded in operating revenues in our consolidated statement of income. In June 2016, we exchanged LLS fixed price swaps on our 2016 oil positions for 7.7 MMBbls of WTI three way collars in 2017. The exchange was non-cash and no gain or loss was recognized on the transaction.
Interest Rate Derivative Instruments.  We have interest rate swaps with a notional amount of $600 million that extend through March 2017 and are intended to reduce variable interest rate risk. As of June 30, 2016, we had a net liability of $1 million and as of December 31, 2015, we had a net asset of $1 million related to interest rate derivative instruments included on our consolidated balance sheets.  For both of the quarters ended June 30, 2016 and 2015, we recorded $1 million of interest expense related to the change in fair market value and cash settlements of our interest rate derivative instruments. For the six months ended June 30, 2016 and 2015, we recorded $3 million and $5 million of interest expense, respectively, related to the change in fair market value and cash settlements of our interest rate derivative instruments.
5.  Property, Plant and Equipment
 
Oil and Natural Gas Properties.  As of June 30, 2016 and December 31, 2015, we had approximately $4.4 billion for both periods of total property, plant, and equipment, net of accumulated depreciation, depletion and amortization on our consolidated balance sheets, substantially all of which relates to proved and unproved oil and natural gas properties.
Our capitalized costs related to proved and unproved oil and natural gas properties by area were as follows:
 
 
June 30, 2016
 
December 31, 2015
 
 
(in millions)
Proved
 
 
 
 
    Eagle Ford
 
$
2,938

 
$
2,833

    Wolfcamp
 
2,255

 
2,174

    Altamont
 
1,591

 
1,553

        Total Proved
 
6,784

 
6,560

Unproved
 
 
 
 
    Wolfcamp
 
95

 
97

    Altamont
 
56

 
64

        Total Unproved
 
151

 
161

Less accumulated depletion
 
2,519

 
2,335

        Net capitalized costs for oil and natural gas properties
 
$
4,416

 
$
4,386

During the six months ended June 30, 2016, we transferred approximately $7 million from unproved properties to proved properties. For the quarters ended June 30, 2016 and 2015, we recorded less than $1 million and $4 million, respectively, of amortization of unproved leasehold costs in exploration expense in our consolidated statement of income. For the six months ended June 30, 2016 and 2015, we recorded less than $1 million and $8 million, respectively, of amortization of unproved leasehold costs. Suspended well costs were not material as of June 30, 2016 or December 31, 2015
We evaluate capitalized costs related to proved properties at least annually or upon a triggering event (such as a significant continued forward commodity price decline) to determine if impairment of such properties has occurred.

10


Capitalized costs associated with unproved properties (e.g. leasehold acquisition costs associated with non-producing areas) are also assessed for impairment based on estimated drilling plans and capital expenditures which may also change relative to forward commodity prices and/or potential lease expirations.
Commodity prices have a significant impact on our impairment assessments. While forward commodity price changes as of June 30, 2016 did not result in any impairment charges of our proved or unproved property costs during the quarter, future commodity price declines may cause changes to our future capital, production rates, levels of proved reserves and development plans, which may result in an impairment of the carrying value of our proved and/or unproved properties in the future.
Leasehold acquisition costs associated with non-producing or unproved areas are assessed for impairment based on our estimated drilling plans and capital expenditures relative to potential lease expirations. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by continuing exploration and development activities.  Our ability to retain our leases and thus recover our non-producing leasehold costs will be dependent upon a number of factors including our levels of drilling activity, which may include drilling the acreage on our own behalf or jointly with partners, or our ability to modify or extend our leases. Should oil prices not justify sufficient capital allocation to the continued development of properties where we have these non-producing leasehold costs, we could incur impairment charges of our unproved property costs. In May 2016, we amended our Wolfcamp development agreement with the University Lands to provide flexibility to extend the time frame to hold our acreage by nearly four years to the end of 2021, with an increase in annual well completion requirements from six wells per year to 34, 55 and 55 wells per year in 2016, 2017 and 2018, respectively. Currently, we have the intent and believe we have the ability to fulfill our annual Wolfcamp drilling commitment and/or develop our unproved areas prior to having to relinquish any associated leases. 
Asset Retirement Obligations.  We have legal asset retirement obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We settle these obligations when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue these obligations when we can estimate the timing and amount of their settlement.
In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including a credit-adjusted risk-free rate between 7-9 percent on a significant portion of our obligations and a projected inflation rate of 2.5 percent.  Changes in estimates represent changes to the expected amount and timing of payments to settle our asset retirement obligations. Typically, these changes result from obtaining new information about the timing of our obligations to plug and abandon oil and natural gas wells and the costs to do so. The net asset retirement liability as of June 30, 2016 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability from January 1 through June 30, 2016 were as follows: 
 
2016
 
(in millions)
Net asset retirement liability at January 1
$
38

Accretion expense
2

Net asset retirement liability at June 30
$
40

Capitalized Interest.  Interest expense is reflected in our financial statements net of capitalized interest.  We capitalize
interest primarily on the costs associated with drilling and completing wells until production begins. The interest rate used is
the weighted average interest rate of our outstanding borrowings. Capitalized interest for the quarter and six months ended June 30, 2016 was less than $1 million and approximately $2 million, respectively. Capitalized interest for the quarter and six months ended June 30, 2015 was approximately $5 million and $9 million, respectively. 

11


6. Long-Term Debt 
Listed below are our debt obligations as of the periods presented:
 
Interest Rate
 
June 30, 2016
 
December 31, 2015
 
 
 
(in millions)
RBL credit facility - due May 24, 2019(1)
Variable
 
$
910

 
$
1,072

Senior secured term loan - due May 24, 2018(2)(4)
Variable
 
467

 
497

Senior secured term loan - due April 30, 2019(3)(4)
Variable
 
142

 
150

Senior unsecured notes - due May 1, 2020
9.375%
 
1,596

 
2,000

Senior unsecured notes - due September 1, 2022
7.75%
 
250

 
350

Senior unsecured notes - due June 15, 2023
6.375%
 
551

 
800

Total long-term debt
 
 
3,916

 
4,869

Less unamortized debt issue costs
 
 
(40
)
 
(57
)
Total long-term debt, net
 
 
3,876

 
4,812

Short-term debt, net of debt issue costs
 
 
53

 

Total debt
 
 
$
3,929

 
$
4,812

 
(1)
The RBL Facility (as defined below) carries interest at a specified margin over LIBOR of 2.50% to 3.50%, based on borrowing utilization.
(2)The term loan was issued at 99% of par and carries interest at a specified margin over the LIBOR of 2.75%, with a minimum LIBOR floor of 0.75%.  As of
June 30, 2016 and December 31, 2015, the effective interest rate of the term loan was 3.50%.
(3)
The term loan carries interest at a specified margin over the LIBOR of 3.50%, with a minimum LIBOR floor of 1.00%.  As of June 30, 2016 and December 31, 2015, the effective interest rate for the term loan was 4.50%.
(4)The term loans are secured by a second priority lien on all of the collateral securing the RBL Facility, and effectively rank junior to any existing
and future first lien secured indebtedness of the Company.
 
During the six months ended June 30, 2016, we paid approximately $360 million in cash to repurchase a total of approximately $737 million in aggregate principal amount of our senior unsecured notes and term loans which resulted in a gain on extinguishment of debt of approximately $170 million and $366 million for the quarter and six months ended June 30, 2016 (including $5 million and $11 million, respectively, of non-cash expense related to eliminating associated unamortized debt issue costs).  For both the quarter and six months ended June 30, 2016, we also recorded a loss on extinguishment of debt of approximately $8 million related to eliminating a portion of the unamortized debt issue costs due to the reduction of our RBL borrowing base in May 2016.

Subsequent to June 30, 2016, we repurchased an additional $54 million of our senior unsecured notes for approximately $34 million in cash. We classified the principal amount of this additional long-term debt repurchased as short-term debt on our consolidated balance sheet as of June 30, 2016.    

During the second quarter of 2015, we issued $800 million of 6.375% senior notes due in June 2023. We used a
substantial portion of the proceeds from the offering to purchase for cash all of our $750 million senior secured notes due in
2019. In conjunction with repurchasing these notes, we recorded a $41 million loss on extinguishment of debt, of which
$12 million was a non-cash expense related to eliminating associated unamortized debt issuance costs.

Unamortized Debt Issue Costs. As of June 30, 2016 and December 31, 2015, we had total unamortized debt issue costs of $55 million and $80 million. Of these amounts, $14 million and $23 million, respectively, are associated with our Reserve-Based Loan facility (RBL Facility) and $41 million ($1 million of which is classified as short-term) and $57 million, respectively, are associated with our senior secured term loans and senior notes. During the quarter and six months ended June 30, 2016, we expensed approximately $13 million and $19 million, respectively, in conjunction with the repurchase of a portion of our senior unsecured notes and term loans and the reduction of our RBL borrowing base. During both of the quarters ended June 30, 2016 and 2015, we amortized $4 million of deferred financing costs into interest expense.  For each of the six months ended June 30, 2016 and 2015, amortization of deferred financing costs was $8 million and $10 million, respectively.

Reserve-based Loan Facility. We have a reserve-based credit facility in place which allows us to borrow funds or issue letters of credit. The RBL Facility is collateralized by certain of our oil and natural gas properties and has a borrowing base subject to semi-annual redetermination.  In May 2016, we completed our semi-annual redetermination, and the borrowing base of our RBL Facility was reduced to $1.65 billion, reflecting significantly lower bank commodity price forecasts, the sale of our Haynesville assets and the roll-off of certain hedge positions. Our next redetermination date is in November 2016. Downward revisions of our oil and natural gas reserves as a result of declines in commodity prices, performance revisions, or sales of

12


assets, or the incurrence of certain types of additional debt, among other items, could cause a further reduction of our borrowing base which could negatively impact our borrowing capacity under the RBL Facility in the future.
The maturity of our RBL Facility is in May 2019, provided that we retire or refinance our 2018 and 2019 secured notes and term loans (collectively, the "second lien debt") at least six months prior to their maturity. In the second quarter of 2015, we repurchased all of our senior secured notes due in 2019. We will be required to retire or refinance remaining amounts outstanding under our (i) $500 million senior secured term loans due 2018 by November 2017 and our (ii) $150 million senior secured term loans due 2019 by November 2018.If we do not retire or refinance these term loans on either of these respective dates, our RBL Facility will mature at that time.
As of June 30, 2016, we had $706 million of available capacity remaining with approximately $34 million of letters of credit issued and approximately $910 million outstanding under the facility. 
Guarantees.  Our obligations under the RBL Facility, term loan, secured and unsecured notes are fully and unconditionally guaranteed, jointly and severally, by the Company’s present and future direct and indirect wholly owned material domestic subsidiaries.  EP Energy LLC has no independent assets or operations. Any subsidiaries of EP Energy LLC, other than the subsidiary guarantors, are minor.  The subsidiary guarantees are subject to certain automatic customary releases, including the sale or disposition of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance or covenant defeasance, or designation of a subsidiary guarantor as unrestricted in accordance with the applicable indenture.  There are no significant restrictions on the ability of the Company or any guarantor to obtain funds from its subsidiaries by dividend or loan.
Restrictive Provisions/Covenants.  The availability of borrowings under our credit agreements and our ability to incur additional indebtedness is subject to various financial and non-financial covenants and restrictions. At June 30, 2016 we were in compliance with all of our debt covenants. In conjunction with our RBL Facility redetermination in May 2016, we amended certain covenants, the most significant of which suspended the requirement that our debt to EBITDAX ratio, as defined in the credit agreement, not exceed 4.5 to 1.0 and replaced it with a requirement that our ratio of first lien debt to EBITDAX not exceed 3.5 to 1.0. The 4.5 to 1.0 debt to EBITDAX requirement will be reinstated beginning in April 2018. As part of the amendment, we also agreed to limit debt repurchases occurring after the redetermination to $350 million subject to certain future adjustments.

7. Commitments and Contingencies
 
Legal Matters
 
We and our subsidiaries and affiliates are parties to various legal actions and claims that arise in the ordinary course of our business. For each matter, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of our current matters cannot be predicted with certainty and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure and adjust our accruals accordingly, and these adjustments could be material. As of June 30, 2016, we had approximately $2 million accrued for all outstanding legal matters.
Indemnifications and Other Matters. We periodically enter into indemnification arrangements as part of the divestitures of assets or businesses.  These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes, environmental and other contingent matters. In addition, under various laws or regulations, we could be subject to the imposition of certain liabilities. For example, the recent decline in commodity prices has created an environment where there is an increased risk that owners and/or operators of assets previously purchased from us may no longer be able to satisfy plugging and abandonment obligations that attach to such assets. In that event, under various laws or regulations, we could be required to assume these plugging or abandonment obligations on assets no longer owned or operated by us. As of June 30, 2016, we had approximately $8 million accrued related to these indemnifications and other matters.
Environmental Matters
We are subject to existing federal, state and local laws and regulations governing environmental quality, pollution control and greenhouse gas (GHG) emissions.  Numerous governmental agencies, such as the Environmental Protection Agency (EPA), issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations

13


of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements.
The environmental laws and regulations to which we are subject also require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of June 30, 2016, we had accrued and had exposure of approximately $1 million for related environmental remediation costs associated with onsite, offsite and groundwater technical studies and for related environmental legal costs. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our environmental remediation projects are in various stages of completion. The liabilities we have recorded reflect our current estimates of amounts that we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.
Climate Change and Other Emissions.  The EPA and several state environmental agencies have adopted regulations to regulate GHG emissions. Although the EPA has adopted a “tailoring” rule to regulate GHG emissions, the U.S. Supreme Court partially invalidated it in an opinion decided June 2014.  The tailoring rule remains applicable for those facilities considered major sources of six other “criteria” pollutants and at this time we do not expect a material impact to our existing operations from the rule. Any regulations regarding GHG emissions would likely increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric-driven compression at facilities to obtain regulatory permits and approvals in a timely manner.
As part of the White House’s Climate Action Plan Strategy to Reduce Methane Emissions, the EPA, the Pipeline and Hazardous Materials Safety Administration (PHMSA) and the Bureau of Land Management (BLM) have recently proposed or finalized new regulations affecting the oil and gas industry. On October 13, 2015, the PHMSA published a proposed rule for oil pipelines, in part requiring inspections in areas affected by natural disasters, expanding use of leak detection systems, and increased use of inline inspection tools. On January 22, 2016, the BLM released a proposed rule for oil and gas facilities on onshore federal and Indian leases to prohibit venting, limit flaring, require leak detection, and allow adjustment of royalty rates for new leases. Although we are examining these proposed regulations, it is uncertain what impact they might have on our operations until they are implemented.
On September 18, 2015, the EPA published several proposed regulations under the Clean Air Act to reduce methane and volatile organic compounds emissions, in part through green completions at oil wells, fugitive emission surveys, limits on pneumatic pumps and controllers, and draft guidelines for controls on equipment in ozone nonattainment areas. These rules were finalized on June 3, 2016 and went into effect August 2, 2016. We are evaluating whether any material capital expenditure will be required for initial and ongoing compliance with these rules.
Air Quality Regulations. The EPA has promulgated various performance and emission standards that mandate air pollutant emission limits and operating requirements for stationary reciprocating internal combustion engines and process equipment.  We do not anticipate material capital expenditures to meet these requirements.
In August 2012, the EPA promulgated additional standards to reduce various air pollutants associated with hydraulic fracturing of natural gas wells and equipment including compressors, storage vessels, and pneumatic valves.  Additional amendments to the new standard were finalized in 2013 and 2014.  We do not anticipate material capital expenditures to meet these requirements. 

14


The EPA has promulgated regulations to require pre-construction permits for minor sources of air emissions in tribal lands.  On September 18, 2015, the EPA proposed a federal implementation plan (FIP), rather than a general permit, to effect these regulations. The FIP was finalized on June 3, 2016, requiring registration of such new and modified minor sources beginning October 3, 2015 and incorporating emission limits and other requirements from six standards under the Clean Air Act for the oil and gas industry. Additionally, the FIP requires an operator to document compliance with the Endangered Species Act and National Historic Preservation Act. This rule could delay pad construction and commencement of drilling if the EPA does not timely provide written confirmation that requisites of the FIP have been met.
Hydraulic Fracturing Regulations. We use hydraulic fracturing extensively in our operations. Various regulations have been adopted and proposed at the federal, state and local levels to regulate hydraulic fracturing operations. These regulations range from banning or substantially limiting hydraulic fracturing operations, requiring disclosure of the hydraulic fracturing fluids and requiring additional permits for the use, recycling and disposal of water used in such operations. In addition, various agencies, including the EPA and Department of Energy are reviewing changes in their regulations to address the environmental impacts of hydraulic fracturing operations. Until such regulations are implemented, it is uncertain what impact they might have on our operations. In March 2015, the BLM published final rules for hydraulic fracturing on federal and certain tribal lands, including use of tanks for recovered water, updated cementing and testing requirements, and disclosure of chemicals used in hydraulic fracturing. Several states and the Ute Indian Tribe filed suit to challenge these rules. On September 30, 2015, a federal court issued a preliminary injunction suspending the rules and, on June 21, 2016, ordered the rules set aside as exceeding the BLM’s authority. The BLM has filed an appeal in the Tenth Circuit Court of Appeals. No material cost is expected for the Company’s 2016 program.
Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Matters. As part of our environmental remediation projects, we are or have received notice that we could be designated as a Potentially Responsible Party (PRP) with respect to one active site under the CERCLA or state equivalents. As of June 30, 2016, we have estimated our share of the remediation costs at this site to be less than $1 million. Because the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and because in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro-rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these matters are included in the reserve for environmental matters discussed above.
Waste Handling. Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements imposed under the Resource Conservation and Recovery Act, as amended, and comparable state laws. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.
It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations, and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.

15


8. Long-Term Incentive Compensation
 
Our long-term incentive (LTI) programs consist of certain equity and liability based compensation awards including restricted stock, stock options and performance units. A summary of the changes in our parent’s non-vested restricted shares for the six months ended June 30, 2016 is presented below:
 
 
Number of Shares
 
Weighted Average
Grant Date Fair Value
per Share
Non-vested at December 31, 2015
 
3,987,654

 
$
10.98

Granted
 
4,619,572

 
$
6.10

Vested
 
(1,177,518
)
 
$
11.78

Forfeited
 
(576,711
)
 
$
9.06

Non-vested at June 30, 2016
 
6,852,997

 
$
7.72


During the first quarter of 2016, our parent granted 83,150 performance units to certain members of EP Energy's management team. Performance units have a target value of $100 per unit; however, the ultimate value of each performance unit will range from zero to $200 depending on the level of total shareholder return (TSR) relative to that of EP Energy’s peer group of companies. The performance units vest in three separate tranches (1 year, 2 year and 3 year calendar periods). For accounting purposes, the performance units are treated as a liability award with the expense recognized on an accelerated basis. The fair value measured at the grant date was approximately $8 million which is subsequently remeasured at the end of each reporting period. As of June 30, 2016, the fair value of these awards (net of forfeitures) was approximately $6 million. The fair value of the performance-based units granted was estimated on the date of grant using a Monte-Carlo simulation for each of three separate performance tranches based on the relative TSR results for each separate tranche period beginning January 1, 2016. The performance units may be settled in either stock or cash at the election of the board of directors of our parent. Assuming such amounts were settled in stock at June 30, 2016, the number of shares that we would issue upon settlement of the 2016 performance unit grants, assuming the awards were vested and relative TSR performance was determined at that date, would be approximately 3.1 million shares.

We record compensation expense on our LTI awards as general and administrative expense over the requisite service period, net of estimates of forfeitures. Pre-tax compensation expense related to all of our parent's LTI awards (both equity and liability based) was approximately $5 million and $10 million for the quarters and six months ended June 30, 2016 and June 30, 2015, respectively. As of June 30, 2016, we had unrecognized compensation expense of $65 million.  We will recognize an additional $13 million related to our outstanding awards during the remainder of 2016, $38 million over the remaining requisite service periods subsequent to 2016 and $14 million upon a specified capital transaction when the right to such amounts becomes non-forfeitable.

9. Related Party Transactions
    
Affiliate Supply Agreement.  For the six months ended June 30, 2016 and 2015, we recorded approximately $5 million and $44 million, respectively, in capital expenditures for amounts expended under supply agreements entered into with an affiliate of Apollo Management, LLC to provide certain fracturing materials to our Eagle Ford drilling operations. This agreement was terminated effective May 2016.
Taxes. We are party to a tax accrual policy with our parent whereby our parent files U.S. and certain state tax returns on our behalf. At both June 30, 2016 and December 31, 2015, we had federal income tax payable due to parent of $6 million.

16


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 2015 Annual Report on Form 10-K. Actual results may differ materially from those contained in any forward-looking statements. 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 LLC 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 three core areas:  the Eagle Ford Shale (South Texas), the Wolfcamp Shale (Permian Basin in West Texas) and the Altamont Field in the Uinta Basin (Northeastern Utah).  In May 2016, we completed the sale of our assets located in the Haynesville and Bossier shales for approximately $420 million (net proceeds of $390 million in cash after customary adjustments) and recorded a gain on the sale of approximately $83 million.
We evaluate growth opportunities for our asset portfolio that are aligned with our core competencies and that are in areas that we believe can provide us a competitive advantage. Strategic acquisitions of leasehold acreage or acquisitions of producing assets can provide opportunities to achieve our long-term goals by leveraging existing expertise in our core 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. We continuously evaluate our asset portfolio and will sell oil and natural gas properties if they no longer meet our long-term goals.
Factors Influencing Our Profitability.  Our profitability is dependent on the prices we receive for our oil and natural gas, the costs to explore, develop, and produce our oil and natural gas, 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. Future commodity price declines may cause changes to our future capital, production rates, levels of proved reserves and development plans, all of which impact performance. Additionally, we may be impacted by weather events, regulatory issues or other third party actions outside of our control.    
We attempt to mitigate certain risks by entering into longer term contractual arrangements to control costs and by entering into derivative contracts to stabilize cash flows and reduce the financial impact of unfavorable movements in both commodity prices and locational price differences. Because we apply mark-to-market accounting on our derivative contracts, 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 contracts or positions or to alter existing contracts or positions are made based on the goals of the overall company.
Derivative Instruments.  Our realized prices from the sale of our oil and natural gas 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 and natural gas, and (ii) other contractual pricing adjustments contained in our underlying sales contracts.  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 downward commodity price movements and locational price differences.


17


During the six months ended June 30, 2016, we (i) settled commodity index hedges on approximately 99% of our oil production, 78% of our total liquids production and 17% of our natural gas production at average floor prices of $80.29 per barrel of oil, $0.55 per gallon of NGLs and $4.20 per MMBtu of natural gas, respectively and (ii) hedged basis risk on approximately 99% of our year-to-date Eagle Ford oil production.  To the extent our oil and natural gas production is unhedged, either from a commodity index or locational price perspective, our financial results will be impacted from period to period.  The following table and discussion that follows reflects the contracted volumes and the prices we will receive under derivative contracts we held as of June 30, 2016.
 
2016
 
2017
 
Volumes(1)
 
Average
Price(1)
 
Volumes(1)
 
Average
Price(1)
Oil
 

 
 

 
 

 
 

Fixed Price Swaps
 

 
 

 
 

 
 

WTI
4,278

 
$
80.03

 
4,015

 
$
66.11

LLS
3,495

 
$
81.38

 

 
$

Three Way Collars
 
 
 
 
 
 
 
Ceiling - WTI

 
$

 
8,833

 
$
70.37

Floors - WTI(2) 

 
$

 
8,833

 
$
60.62

Basis Swaps
 
 
 
 
 
 
 
LLS vs. WTI(3)
1,012

 
$
3.91

 

 
$

LLS vs. Brent(4)

 
$

 
3,650

 
$
(3.14
)
Midland vs. Cushing(5)
368

 
$
(0.83
)
 
1,460

 
$
(0.68
)
WTI - CM vs. TM(6)
3,495

 
$
0.29

 

 
$

NYMEX Roll(7)
3,680

 
$
(0.84
)
 

 
$

Natural Gas
 
 
 
 
 
 
 
Fixed Price Swaps
11

 
$
3.39

 

 
$

Propane
 
 
 
 
 
 
 
Fixed Price Swaps
8

 
$
0.55

 

 
$

 
(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 $46.24 in 2017, we will receive a “locked-in” cash settlement of the market price plus $14.38 per Bbl.
(3)
EP Energy receives WTI plus the basis spread listed and pays LLS.
(4)
EP Energy receives Brent plus the basis spread listed and pays LLS.
(5)
EP Energy receives Cushing plus the basis spread listed and pays Midland.
(6)
EP Energy receives WTI trade month (TM) plus the spread listed and pays WTI calendar month (CM).
(7)
These positions hedge the timing risk associated with our physical sales. We generally sell oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the "trade month roll").
     Included in the table above are 7.7 MMBbls of 2017 WTI three way collars that we exchanged in the second quarter for existing LLS fixed price swaps on our 2016 oil positions. The exchange was non-cash and no gain or loss was recognized on the transaction. In addition to the derivative contracts presented in the table above, during 2016 we have entered into contracts offsetting 368 MBbls of 2016 LLS fixed price swaps, 1,104 MBbls of 2016 LLS vs. Brent basis swaps and 4,785 MBbls of 2016 WTI - CM vs. TM of our remaining derivative contracts. By entering into these offsetting positions, we effectively “locked-in” additional net cash settlements of approximately $6 million which will be received during the remainder of 2016.
For the period from July 1, 2016 through August 3, 2016, we have entered into additional derivative contracts on approximately 3.7 TBtu of 2017 natural gas fixed price swaps with an average price of $3.13 per MMBtu.
Summary of Liquidity and Capital Resources.  As of June 30, 2016, we had available liquidity, including existing cash, of approximately $745 million reflecting a revised RBL borrowing base of $1.65 billion. During 2016, we have taken a number of steps to maintain or improve our liquidity, strengthen our balance sheet and expand our financial flexibility. These steps have included (i) completing the sale of our Haynesville and Bossier Shale assets in May 2016, (ii) repurchasing over $700 million of our unsecured notes and term loans for cash at a discount (iii) amending certain restrictive debt covenants in our RBL Facility through the first quarter of 2018, and (iv) entering into hedge transactions to provide additional 2017 price protection. See additional details of these transactions in “Liquidity and Capital Resources”.

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Production Volumes and Drilling Summary
 
Production Volumes. Below is an analysis of our production volumes for the six months ended June 30:
 
 
2016
 
2015
United States (MBoe/d)
 

 
 

Eagle Ford Shale
47.9

 
57.6

Wolfcamp Shale
18.0

 
18.5

Altamont
15.9

 
17.3

Haynesville Shale
12.4

 
12.2

Other
0.1

 
0.1

Total
94.3

 
105.7

 
 
 
 
Oil (MBbls/d)
47.9

 
61.7

Natural Gas (MMcf/d)
193

 
186

NGLs (MBbls/d)
14.2

 
13.0

 
Eagle Ford Shale—Our Eagle Ford Shale equivalent volumes decreased by 9.7 MBoe/d (approximately 17%) and oil production decreased by 10.0 MBbls/d (25%) for the six months ended June 30, 2016 compared to the same period in 2015.  During the six months ended June 30, 2016, we completed 24 additional operated wells in the Eagle Ford, for a total of 587 net operated wells as of June 30, 2016.
Wolfcamp Shale—Our Wolfcamp Shale equivalent volumes decreased 0.5 MBoe/d (approximately 3%) and oil production decreased by 2.4 MBoe/d (approximately 26%) for the six months ended June 30, 2016 compared to the same period in 2015. During the six months ended June 30, 2016, we completed 10 additional operated wells for a total of 247 net operated wells as of June 30, 2016
Altamont—Our Altamont equivalent volumes decreased 1.4 MBoe/d (approximately 8%) for the six months ended June 30, 2016 compared to the same period in 2015. Altamont produced an average of 11.2 MBbls/d of oil during the six months ended June 30, 2016, and we completed an additional four operated oil wells for a total of 371 net operated wells as of June 30, 2016.
Haynesville Shale—Our Haynesville Shale equivalent volumes increased 0.2 MMcf/d (approximately 2%) for the six months ended June 30, 2016 compared to the same period ended June 30, 2015. In May 2016, we completed the sale of our Haynesville Shale assets.
Our oil production declines in our Eagle Ford, Wolfcamp and Altamont core areas reflect the slowed pace of development in our drilling programs due to reduced capital spending in the latter part of 2015 and the first half of 2016. Future volumes will be impacted by our levels of capital spending and the timing of that spending. In the current commodity price environment, we could see continued low spending levels which may result in lower reported volumes in the future.


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Results of Operations
 
The information in the table below provides a summary of our financial results.
 
 
Quarter ended 
 June 30,
 
Six months ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
 
(in millions)
Operating revenues
 

 
 

 
 

 
 

Oil
$
165

 
$
307

 
$
294

 
$
536

Natural gas
25

 
46

 
67

 
94

NGLs
15

 
15

 
26

 
28

Total physical sales
205

 
368

 
387

 
658

Financial derivatives
(105
)
 
(179
)
 
(63
)
 
24

Total operating revenues
100

 
189

 
324

 
682

 
 
 
 
 
 
 
 
Operating expenses
 

 
 

 
 

 
 

Oil and natural gas purchases
3

 
8

 
7

 
15

Transportation costs
24

 
25

 
54

 
52

Lease operating expense
38

 
47

 
80

 
94

General and administrative
32

 
35

 
70

 
82

Depreciation, depletion and amortization
97

 
253

 
210

 
477

Gain on sale of assets
(82
)
 

 
(82
)
 

Exploration and other expense
1

 
6

 
2

 
12

Taxes, other than income taxes
14

 
23

 
28

 
45

Total operating expenses
127

 
397

 
369

 
777

 
 
 
 
 
 
 
 
Operating loss
(27
)
 
(208
)
 
(45
)
 
(95
)
Gain (loss) on extinguishment of debt
162

 
(41
)
 
358

 
(41
)
Interest expense
(73
)
 
(81
)
 
(157
)
 
(165
)
Income (loss) before income taxes
62

 
(330
)
 
156

 
(301
)
Income tax benefit

 
(120
)
 

 
(110
)
Net income (loss)
$
62

 
$
(210
)
 
$
156

 
$
(191
)

20


Operating Revenues
 
The table below provides our operating revenues, volumes and prices per unit for the quarters and six months ended June 30, 2016 and 2015. 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.
 
Quarter ended 
 June 30,
 
Six months ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
 
(in millions)
Operating revenues:
 

 
 

 
 

 
 

Oil
$
165

 
$
307

 
$
294

 
$
536

Natural gas
25

 
46

 
67

 
94

NGLs
15

 
15

 
26

 
28

Total physical sales
205

 
368

 
387

 
658

Financial derivatives
(105
)
 
(179
)
 
(63
)
 
24

Total operating revenues
$
100

 
$
189

 
$
324

 
$
682

 
 
 
 
 
 
 
 
Volumes:
 

 
 

 
 

 
 

Oil (MBbls)
4,100

 
5,766

 
8,724

 
11,168

Natural gas (MMcf)
13,954

 
17,037

 
35,104

 
33,665

NGLs (MBbls)
1,265

 
1,315

 
2,582

 
2,359

Equivalent volumes (MBoe)
7,691

 
9,920

 
17,157

 
19,138

Total MBoe/d
84.5

 
109.0

 
94.3

 
105.7

 
 
 
 
 
 
 
 
Prices per unit(1):
 

 
 

 
 

 
 

Oil
 

 
 

 
 

 
 

Average realized price on physical sales ($/Bbl)(2) 
$
40.13

 
$
53.17

 
$
33.64

 
$
47.96

Average realized price, including financial derivatives ($/Bbl)(2)(3)
$
77.45

 
$
79.18

 
$
74.95

 
$
78.80

Natural gas
 
 
 
 
 

 
 

Average realized price on physical sales ($/Mcf)(2)
$
1.60

 
$
2.20

 
$
1.73

 
$
2.35

Average realized price, including financial derivatives ($/Mcf)(3)
$
1.90

 
$
3.68

 
$
1.95

 
$
3.69

NGLs
 
 
 
 
 

 
 

Average realized price on physical sales ($/Bbl)
$
11.90

 
$
11.91

 
$
10.03

 
$
11.96

Average realized price, including financial derivatives ($/Bbl)(3) 
$
12.06

 
$
13.08

 
$
10.34

 
$
12.72

 
(1)
Oil prices for the quarter and six months ended June 30, 2016 are calculated including a reduction of less than $1 million and approximately $1 million, respectively, for oil purchases associated with managing our physical sales. Natural gas prices for the quarter and six months ended June 30, 2016 are calculated including a reduction of approximately $3 million and $7 million, respectively, for natural gas purchases associated with managing our physical sales. Natural gas prices for the quarter and six months ended June 30, 2015 are calculated including a reduction of $8 million and $15 million, respectively, for natural gas purchases associated with managing our physical sales.
(2)
Changes in realized oil and natural gas prices reflect the effects of unfavorable unhedged locational or basis differentials, unhedged volumes and contractual deductions between the commodity price index and the actual price at which we sold our oil and natural gas.
(3)
The quarters ended June 30, 2016 and 2015, include approximately $153 million and $150 million of cash received, respectively, for the settlement of crude oil derivative contracts and approximately $4 million and $25 million of cash received, respectively, for the settlement of natural gas financial derivatives.  The six months ended June 30, 2016 and 2015, include approximately $360 million and $344 million of cash received, respectively, for the settlement of crude oil derivative contracts and approximately $8 million and $45 million of cash received, respectively, for the settlement of natural gas financial derivatives. The quarters ended June 30, 2016 and 2015 also include less than $1 million and approximately $2 million of cash received, respectively, for the settlement of NGLs derivative contracts. The six months ended June 30, 2016 and 2015 include approximately $1 million and $2 million of cash received, respectively, for the settlement of NGLs derivative contracts. No cash premiums were received or paid for the quarters or six months ended June 30, 2016 and 2015.




21


Physical sales.  Physical sales represent accrual-based commodity sales transactions with customers. For the quarter and six months ended June 30, 2016, physical sales decreased by $163 million (44%) and $271 million (41%), respectively, compared to the same periods in 2015. Physical sales have decreased due to lower commodity prices across all commodity types and lower oil volumes reflecting the slowed pace of development in our drilling programs due to reduced capital spending in the latter part of 2015 and the first half of 2016. The table below displays the price and volume variances on our physical sales when comparing the quarters and six months ended June 30, 2016 and 2015
 
Quarter ended
 
Oil
 
Natural gas
 
NGLs
 
Total
 
(in millions)
June 30, 2015 sales
$
307

 
$
46

 
$
15

 
$
368

Change due to prices
(53
)
 
(12
)
 

 
(65
)
Change due to volumes
(89
)
 
(9
)
 

 
(98
)
June 30, 2016 sales
$
165

 
$
25

 
$
15

 
$
205

 
Six months ended
 
Oil
 
Natural gas
 
NGLs
 
Total
 
(in millions)
June 30, 2015 sales
$
536

 
$
94

 
$
28

 
$
658

Change due to prices
(125
)
 
(31
)
 
(5
)
 
(161
)
Change due to volumes
(117
)
 
4

 
3

 
(110
)
June 30, 2016 sales
$
294

 
$
67

 
$
26

 
$
387

Oil sales for the quarter and six months ended June 30, 2016 compared to the same periods in 2015 decreased by $142 million (46%) and $242 million (45%), respectively, due primarily to lower oil prices and a decline in oil volumes in all of our oil programs.  For the quarter and six months ended June 30, 2016 compared to the same periods in 2015, Eagle Ford oil production decreased by 34% (14.2 MBbls/d) and 25% (10 MBbls/d), respectively, Wolfcamp oil production decreased by 24% (2.2 MBbls/d) and 26% (2.4 MBbls/d), respectively, and Altamont oil production decreased by 15% (1.9 MBbls/d) and 11% (1.4 MBbls/d), respectively, reflecting the slowed pace of development of our core areas.
Natural gas sales decreased for the quarter and six months ended June 30, 2016 compared to the same periods in 2015 primarily due to lower natural gas prices, offset by natural gas volume growth primarily in Wolfcamp for the six months ended June 30, 2016. In May 2016, we sold our Haynesville Shale assets and as a result expect natural gas volumes to decrease in future periods. For the quarter and six months ended June 30, 2016, our Haynesville Shale produced a total of 38 MMcf/d and 75 MMcf/d, respectively, of natural gas.
Our oil and natural gas is sold at index prices (WTI, LLS and 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 fixed or variable contractual deducts, differentials from the index to the delivery point, adjustments for time, and/or discounts for quality or grade.  Generally as the index price of our commodities decreases, the fixed contractual deducts in our physical sales contracts reduce the realized prices we receive on a percentage of NYMEX basis.
In the Eagle Ford, our oil is sold at prices tied to benchmark LLS crude oil.  In Wolfcamp, physical barrels are generally sold at the WTI Midland Index, which trades at a spread to WTI Cushing.  Pricing for both areas has been influenced by the weakening average price adjustments we receive on physical sales. In Altamont, market pricing of our oil is based upon NYMEX based agreements which reflect transportation and handling costs associated with moving wax crude to end users.  Across all regions, natural gas realized pricing is influenced by factors such as excess royalties paid on flared gas and the percentage of proceeds retained under processing contracts, in addition to the normal seasonal supply and demand influences and those factors discussed above. The table below displays the weighted average differentials and deducts on our oil and natural gas sales on an average NYMEX price. 

22


 
Quarter ended June 30,
 
2016
 
2015
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
Differentials and deducts
$
(5.36
)
 
$
(0.34
)
 
$
(4.87
)
 
$
(0.40
)
NYMEX
$
45.59

 
$
1.95

 
$
57.94

 
$
2.64

Net back realization %
88.2
%
 
82.6
%
 
91.6
%
 
84.8
%

 
Six months ended June 30,
 
2016
 
2015
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
Differentials and deducts
$
(5.82
)
 
$
(0.30
)
 
$
(5.51
)
 
$
(0.45
)
NYMEX
$
39.52

 
$
2.02

 
$
53.29

 
$
2.81

Net back realization %
85.3
%
 
85.1
%
 
89.7
%
 
84.0
%
 
The lower realization percentage in the quarter and six months ended June 30, 2016 relative to the same periods in 2015 was primarily a result of a reduced LLS premium relative to NYMEX in Eagle Ford, partially offset by improved physical sales contract pricing in Altamont and improved Midland-Cushing basis spread in Wolfcamp. The smaller natural gas differentials and deducts in the quarter and six months ended June 30, 2016 were primarily a result of improved locational basis differentials and contract restructuring in the Haynesville area, and lower excess royalties paid on flared gas. In the Eagle Ford area, flared volumes were lower in 2016 compared to the same periods in 2015.
NGLs sales remained flat for the quarter ended June 30, 2016 and decreased for the six months ended June 30, 2016 compared to the same period in 2015. Average realized prices decreased for the six months ended June 30, 2016 compared to the same period in 2015, due to lower pricing on all liquids components. NGLs pricing is largely tied to crude oil prices. NGLs volumes increased for the six months ended June 30, 2016 primarily as a result of lower flaring in our Eagle Ford and Wolfcamp drilling programs.
Future growth in our overall oil sales (including the impact of financial derivatives) will largely be impacted by commodity pricing, our ability to maintain or grow oil volumes, by the location of our production and by the nature of our sales contracts. Based on our hedges in place as of June 30, 2016, we have approximately 8 MMBbls hedged for 2016 at a weighted average price of $80.67 per barrel. We also have contracts that effectively "lock-in" additional cash settlements, on 0.4 MMBbls of 2016 LLS fixed price swaps, 1,104 MBbls of 2016 LLS vs. Brent basis swaps and 4,785 MBbls of 2016 WTI - CM vs. TM, representing approximately $6 million which will be received during the remainder of 2016. See "Our Business" for further information on our derivative instruments.
Gains or losses on financial derivatives.  We record gains or losses due to changes in the fair value of our derivative contracts based on forward commodity prices relative to the prices in the underlying contracts. We realize such gains or losses when we settle the derivative position. During the quarter ended June 30, 2016, we recorded $105 million of derivative losses compared to derivative losses of $179 million during the quarter ended June 30, 2015.  For the six months ended June 30, 2016, we recorded $63 million of derivative losses compared to derivative gains of $24 million during the six months ended June 30, 2015.
Operating Expenses
Oil and natural gas purchases.  We purchase and sell oil and natural gas on a monthly basis to improve the prices we would otherwise receive for our oil and natural gas or to manage firm transportation agreements. Oil and natural gas purchases for the quarter and six months ended June 30, 2016 were $3 million and $7 million, respectively, compared to $8 million and $15 million for the same periods in 2015. For both the quarter and six months ended June 30, 2016, natural gas purchases decreased as a result of the sale of Haynesville, partially offset by an increase in oil purchases.
Lease operating expense.  Lease operating expense for the quarter and six months ended June 30, 2016 were $38 million and $80 million, respectively, compared to $47 million and $94 million for the same periods in 2015. We experienced a decrease in lease operating expense in our three core areas for the quarter and six months ended June 30, 2016. In Wolfcamp the decrease was approximately $4 million and $8 million, respectively, due to lower disposal costs, lower flowback and lower maintenance and repair costs. In Altamont, the decrease for the quarter and six months ended June 30, 2016 was approximately $2 million and $4 million, respectively, primarily due to lower disposal and chemical costs. In Eagle Ford, the decrease was

23


approximately $2 million and $1 million, respectively, due to lower flowback and lower disposal costs. We also experienced a general decrease in costs across all programs due to ongoing contract negotiations.
General and administrative expenses.  General and administrative expenses for the quarter and six months ended June 30, 2016 were $32 million and $70 million, respectively, compared to $35 million and $82 million for the same periods in 2015. Lower costs during the quarter and six months ended June 30, 2016 compared to 2015 reflected lower payroll, benefits and administrative costs of $6 million and $10 million, respectively, resulting primarily from a general and administrative headcount reduction of approximately 17% in response to the lower commodity price environment. The decrease during the quarter and six months ended June 30, 2016 was offset by higher severance charges of $2 million recorded in the second quarter of 2016.
Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense for the quarter and six months ended June 30, 2016 were $97 million and $210 million, respectively, compared to $253 million and $477 million for the same periods in 2015. Our depreciation, depletion and amortization costs decreased in 2016 compared to the same period in 2015 due primarily to the impact of the non-cash impairment charge on our proved properties recorded in the fourth quarter of 2015, the sale of our Haynesville Shale assets in May 2016 and an overall decrease in production volumes. Our average depreciation, depletion and amortization costs per unit for the quarters and six months ended June 30 were:
 
Quarter ended 
 June 30,
 
Six months ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
Depreciation, depletion and amortization ($/Boe)
$
12.67

 
$
25.46

 
$
12.27

 
$
24.90


Our depreciation, depletion and amortization rate in the future will be impacted by the level and timing of capital spending, overall cost savings on capital and the level and type of reserves recorded on completed projects.
Gain on sale of assets. For the quarter and six months ended June 30, 2016, we recorded an $83 million gain related to the sale of our assets in the Haynesville and Bossier shales completed in May 2016.
Exploration and other expense.  For the quarter and six months ended June 30, 2016, we recorded $1 million and $2 million, respectively, of exploration expense compared to $6 million and $12 million for the same periods in 2015.  Included in exploration expense for both the quarter and six months ended June 30, 2016, are less than $1 million of amortization of unproved leasehold costs compared to $4 million and $8 million for the same periods in 2015. In addition, in the six months ended June 30, 2015, we recorded approximately $2 million as other expense in conjunction with the early termination of a contract for drilling rigs during the first quarter of 2015.
Taxes, other than income taxes.  Taxes, other than income taxes, for the quarter and six months ended June 30, 2016 were $14 million and $28 million, respectively, compared to $23 million and $45 million for the same periods in 2015.  Production taxes decreased in 2016 compared to the same period in 2015 due to lower oil volumes and the significant impact on severance taxes of lower commodity prices.
Cash Operating Costs and Adjusted Cash Operating Costs.  We use a non-GAAP measure when describing the costs required to produce our oil and natural gas. These measures are cash operating costs and adjusted cash operating costs. Our cash operating costs measure is a non-GAAP measure calculated on a per Boe basis as total operating expenses less depreciation, depletion and amortization expense, transportation costs, exploration expense, oil and natural gas purchases, gains and losses on sales of assets and other expenses. Adjusted cash operating costs is a non-GAAP measure calculated as cash operating costs less transition, restructuring and other costs that affect comparability, and the non-cash portion of compensation expense (which represents compensation expense under long-term incentive programs adjusted for cash payments made under long-term incentive plans). We believe cash operating costs and adjusted cash operating costs per unit provides management and investors valuable measures of operating performance and efficiency relative to other industry participants and relative to our historical results; however, these measures may not be comparable to similarly titled measures used by other companies and should not be used as a substitute to the comparable GAAP measure of operating expenses. The table below represents a reconciliation of our GAAP operating expenses to non-GAAP cash operating costs and adjusted cash operating costs for the quarters and six months ended June 30:

24


 
Quarter ended 
 June 30,
 
2016
 
2015
 
Total
 
Per Unit(1)
 
Total
 
Per Unit(1)
 
(in millions, except per unit costs)
Total operating expenses
$
127

 
$
16.47

 
$
397

 
$
39.99

 
 
 
 
 
 
 
 
Depreciation, depletion and amortization
(97
)
 
(12.67
)
 
(253
)
 
(25.46
)
Transportation costs
(24
)
 
(3.19
)
 
(25
)
 
(2.56
)
Exploration expense
(1
)
 
(0.12
)
 
(5
)
 
(0.59
)
Oil and natural gas purchases
(3
)
 
(0.38
)
 
(8
)
 
(0.78
)
Gain on sale of assets
82

 
10.77

 

 

Total cash operating costs
84

 
10.88

 
106

 
10.60

Transition/restructuring costs, non-cash portion of compensation expense and other(2) 
(5
)
 
(0.60
)
 
1

 
0.17

Total adjusted cash operating costs and adjusted per-unit cash costs
$
79

 
$
10.28

 
$
107

 
$
10.77

 
 
 
 
 
 
 
 
Total equivalent volumes (MBoe)
7,691

 
 

 
9,920

 
 

 
Six months ended June 30,
 
2016
 
2015
 
Total
 
Per Unit(1)
 
Total
 
Per Unit(1)
 
(in millions, except per unit costs)
Total operating expenses
$
369

 
$
21.52

 
$
777

 
$
40.59

 
 
 
 
 
 
 
 
Depreciation, depletion and amortization
(210
)
 
(12.27
)
 
(477
)
 
(24.90
)
Transportation costs
(54
)
 
(3.15
)
 
(52
)
 
(2.73
)
Exploration expense
(2
)
 
(0.11
)
 
(10
)
 
(0.55
)
Oil and natural gas purchases
(7
)
 
(0.42
)
 
(15
)
 
(0.75
)
Gain on sale of assets
82

 
4.81

 

 

Total cash operating costs
178

 
10.38

 
223

 
11.66

Transition/restructuring costs, non-cash portion of compensation expense and other(2)
(17
)
 
(0.96
)
 
(11
)
 
(0.57
)
Total adjusted cash operating costs and adjusted per-unit cash costs
$
161

 
$
9.42

 
$
212

 
$
11.09

 
 
 
 
 
 
 
 
Total equivalent volumes (MBoe)
17,157

 
 

 
19,138

 
 

 
(1)
Per unit costs are based on actual total amounts rather than the rounded totals presented.
(2)
For the quarter ended June 30, 2016, amount includes approximately $2 million of transition and severance costs related to workforce reductions and $3 million of non-cash compensation expense, adjusted for cash payments made on long-term incentive plans of approximately $3 million. For the six months ended June 30, 2016, amount includes approximately $10 million of transition and severance costs related to workforce reductions and $7 million of non-cash compensation expense, adjusted for cash payments made on long-term incentive plans of approximately $3 million. For the quarter ended June 30, 2015, amount includes approximately $2 million of non-cash compensation expense, adjusted for cash payments made of approximately $7 million. For the six months ended June 30, 2015, amount includes approximately $8 million of transition and severance costs related to workforce reductions and $3 million of non-cash compensation expense, adjusted for cash payments made of approximately $7 million..









25





The table below displays the average cash operating costs and adjusted cash operating costs per equivalent unit:
 
 
Quarter ended 
 June 30,
 
Six months ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
Average cash operating costs ($/Boe)
 

 
 

 
 

 
 

Lease operating expenses
$
4.93

 
$
4.72

 
$
4.63

 
$
4.91

Production taxes(1)
1.54

 
2.05

 
1.39

 
2.09

General and administrative expenses(2)
4.20

 
3.59

 
4.11

 
4.30

Taxes, other than production and income taxes
0.21

 
0.24

 
0.25

 
0.26

Other expenses(3) 

 

 

 
0.10

Total cash operating costs
10.88

 
10.60

 
10.38

 
11.66

Transition/restructuring costs, non-cash portion of compensation expense and other(2)
(0.60
)
 
0.17

 
(0.96
)
 
(0.57
)
Total adjusted cash operating costs
$
10.28

 
$
10.77

 
$
9.42

 
$
11.09

 
(1)
Production taxes include ad valorem and severance taxes.
(2)
For additional detail of adjusted items, which are part of general and administrative expenses, refer to the reconciliation of cash operating costs and adjusted cash operating costs above.
(3)
Includes early rig termination fees of $2 million incurred during the first quarter of 2015.
Other Income Statement Items.
Gain (loss) on extinguishment of debt. During the quarter and six months ended June 30, 2016, we paid approximately $217 million and $360 million, respectively, in cash to repurchase a total of approximately $392 million and $737 million, respectively, in aggregate principal amount of our senior unsecured notes and term loans. We recorded a gain on extinguishment of debt of approximately $170 million in the second quarter and $366 million year to date which included $5 million and $11 million, respectively, of non-cash expense related to eliminating associated unamortized debt issue costs.
In addition, for the quarter and six months ended June 30, 2016, we recorded a loss on extinguishment of debt of approximately $8 million related to eliminating a portion of the unamortized debt issue costs on our RBL Facility due to the reduction of our borrowing base in May 2016.
For the quarter and six months ended June 30, 2015, we recorded $41 million ($12 million of which was non-cash) in losses on extinguishment of debt in conjunction with the early repayment and retirement of our $750 million senior secured notes due 2019.
Interest Expense. Interest expense for the quarter and six months ended June 30, 2016 was $73 million and $157 million, respectively, compared to $81 million and $165 million for the same periods in 2015.  Interest expense decreased in 2016 primarily due to the effects of our 2016 debt repurchases.  The decrease in interest expense was partially offset by higher interest expense related to our RBL Facility. We estimate that out debt repurchases will reduce our annual interest expense by approximately $62 million.
Income Taxes. For the quarter and six months ended June 30, 2016, our effective tax rates were 0%. Our effective tax rate differed from the statutory rate as a result of adjustments to the valuation allowance on our deferred tax assets which offset deferred income tax expense by $24 million and $59 million for the quarter and six months ended June 30, 2016 (See Part I, Item 1, Financial Statements, Note 3). The effective tax rate for the quarter and six months ended June 30, 2015 was relatively consistent with the statutory tax rate. Our effective tax rates in 2015 were primarily impacted by the effects of state income taxes (net of federal income tax effects).
 



26


Supplemental Non-GAAP Measures
 
We use the non-GAAP measures “EBITDAX” and “Adjusted EBITDAX” as supplemental measures. We believe these supplemental measures provide meaningful information to our investors. We define EBITDAX 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 long-term incentive programs adjusted for cash payments made under long-term incentive plans), transition, restructuring and other costs that affect comparability, gains and losses on sales of assets and gains and losses on extinguishment of debt.
We believe that the presentation of EBITDAX and Adjusted EBITDAX 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 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. EBITDAX and Adjusted EBITDAX have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or 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.
Below is a reconciliation of our consolidated net income (loss) to EBITDAX and Adjusted EBITDAX:
 
Quarter ended 
 June 30,
 
Six months ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
 
(in millions)
 
 
 
 
Net income (loss)
$
62

 
$
(210
)
 
$
156

 
$
(191
)
Income tax benefit

 
(120
)
 

 
(110
)
Interest expense, net of capitalized interest
73

 
81

 
157