Attached files

file filename
EX-31.2 - EXHIBIT 31.2 - EP Energy LLCex3120331201710qllc.htm
EX-32.2 - EXHIBIT 32.2 - EP Energy LLCex3220331201710qllc.htm
EX-32.1 - EXHIBIT 32.1 - EP Energy LLCex3210331201710qllc.htm
EX-31.1 - EXHIBIT 31.1 - EP Energy LLCex3110331201710qllc.htm
EX-12.1 - EXHIBIT 12.1 - EP Energy LLCex121ratioofearningsllc033.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 March 31, 2017
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,” “smaller reporting company,” and "emerging growth 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)
 
 
 
 
 
Emerging Growth Company o
 
 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
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
Mt. Belvieu
 
=
 
Mont Belvieu natural gas liquids pricing index
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 its 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 2016 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 March 31,
 
2017
 
2016
Operating revenues
 

 
 

Oil
$
204

 
$
129

Natural gas
30

 
42

NGLs
23

 
11

Financial derivatives
70

 
42

Total operating revenues
327

 
224

 
 
 
 
Operating expenses
 

 
 

Oil and natural gas purchases
1

 
4

Transportation costs
29

 
30

Lease operating expense
40

 
42

General and administrative
20

 
38

Depreciation, depletion and amortization
126

 
113

Exploration and other expense
3

 
1

Taxes, other than income taxes
19

 
14

Total operating expenses
238

 
242

 
 
 
 
Operating income (loss)
89

 
(18
)
(Loss) gain on extinguishment of debt
(53
)
 
196

Interest expense
(83
)
 
(84
)
(Loss) income before income taxes
(47
)
 
94

Income tax expense

 

Net (loss) income
$
(47
)
 
$
94

 
See accompanying notes.


2


EP ENERGY LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(Unaudited)
 
 
March 31, 2017
 
December 31, 2016
ASSETS
 

 
 

Current assets
 

 
 

Cash and cash equivalents
$
35

 
$
16

Accounts receivable
 

 
 

Customer, net of allowance of less than $1 in 2017 and 2016
137

 
133

Other, net of allowance of $1 in 2017 and 2016
21

 
16

Materials and supplies
15

 
16

Derivative instruments
88

 
58

Prepaid assets
5

 
5

Total current assets
301

 
244

Property, plant and equipment, at cost
 

 
 

Oil and natural gas properties
7,344

 
7,194

Other property, plant and equipment
85

 
85

 
7,429

 
7,279

Less accumulated depreciation, depletion and amortization
2,901

 
2,781

Total property, plant and equipment, net
4,528

 
4,498

Other assets
 

 
 

Derivative instruments
12

 
4

Unamortized debt issue costs - revolving credit facility
9

 
10

Other
1

 
1

 
22

 
15

Total assets
$
4,851

 
$
4,757

 
See accompanying notes.

3


EP ENERGY LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(Unaudited)
 
 
March 31, 2017
 
December 31, 2016
LIABILITIES AND EQUITY
 

 
 

Current liabilities
 

 
 

Accounts payable
 

 
 

Trade
$
68

 
$
63

Other
141

 
113

Derivative instruments

 
4

Accrued interest
91

 
43

Other accrued liabilities
86

 
98

Total current liabilities
386

 
321

 
 
 
 
Long-term debt, net of debt issue costs
3,864

 
3,789

Other long-term liabilities
 

 
 

Derivative instruments

 
1

Asset retirement obligations
41

 
40

Other
4

 
4

Total non-current liabilities
3,909

 
3,834

 
 
 
 
Commitments and contingencies (Note 7)


 


Member’s equity
556

 
602

Total liabilities and equity
$
4,851

 
$
4,757

 
See accompanying notes.


4


EP ENERGY LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)
 
 
Three months ended March 31,
 
2017
 
2016
Cash flows from operating activities
 

 
 

Net (loss) income
$
(47
)
 
$
94

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

 
 
Depreciation, depletion and amortization
126

 
113

Loss (gain) on extinguishment of debt
53

 
(196
)
Other non-cash income items
5

 
9

Asset and liability changes
 

 
1

Accounts receivable
(12
)
 
89

Accounts payable
2

 
(32
)
Derivative instruments
(43
)
 
171

Accrued interest
48

 
43

Other asset changes
1

 
(1
)
Other liability changes
(19
)
 
9

Net cash provided by operating activities
114

 
299

 
 
 
 
Cash flows from investing activities
 

 
 

Cash paid for capital expenditures
(119
)
 
(179
)
Net cash used in investing activities
(119
)
 
(179
)
 
 
 
 
Cash flows from financing activities
 

 
 

Proceeds from issuance of long-term debt
1,125

 
325

Repayments and repurchases of long-term debt
(1,086
)
 
(380
)
Contributions from parent
4

 

Debt issue costs
(19
)
 

Net cash provided by (used in) financing activities
24

 
(55
)
 
 
 
 
Change in cash and cash equivalents
19

 
65

Cash and cash equivalents
 

 
 
Beginning of period
16

 
24

End of period
$
35

 
$
89

 
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, 2016
$
602

Share-based compensation
(3
)
Cash contributions from parent
4

Net loss
(47
)
Balance at March 31, 2017
$
556

 
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 2016 Annual Report on Form  10-K. The condensed consolidated financial statements as of March 31, 2017 and 2016 are unaudited. The consolidated balance sheet as of December 31, 2016 has been derived from the audited consolidated balance sheet included in our 2016 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 2016 Annual Report on Form 10-K other than in Accounting for Long-Term Incentive Compensation. In the first quarter of 2017, we adopted Accounting Standards Update (ASU) No. 2016-09, Improvements to Employee Share-Based Payment Accounting which simplifies several aspects of the accounting for share-based payment awards to employees including accounting for income taxes, forfeitures, statutory tax withholding requirements and classification in the statement of cash flows. As permitted under ASU 2016-09, we have elected to account for forfeitures in compensation cost when they occur. Upon adoption of the ASU, there was no impact to total member's equity.
New Accounting Pronouncements Issued But Not Yet Adopted
The following accounting standards have been issued but not yet adopted as of March 31, 2017.
Statement of Cash Flows. In August 2016, the Financial Accounting Standards Board (FASB) issued ASU No. 2016-15, Statement of Cash Flows- Classification of Certain Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows - Restricted Cash, which requires restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning of period and end of period total amounts shown on the statement of cash flows.  Retrospective application of these standards is required for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, and early adoption is allowed. We do not anticipate that the adoption of this standard will have a material impact on our consolidated statement of cash flows.

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 continue to evaluate our contracts and other agreements to assess the impact this update will have on 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. Adoption of this standard is required beginning in the first quarter of 2018, with
the option of early adoption in 2017. Modified or full retrospective application of this standard is required upon adoption. Based upon our preliminary contract evaluations, we do not anticipate our adoption of this standard in 2018, utilizing the modified retrospective approach, will have a material impact on our financial statements. We continue to evaluate disclosure requirements and assess any potential changes to our accounting policies, business processes and/or controls as a result of the provisions of this standard. 





7


2. Divestitures

In March 2016, we entered into an agreement to sell our assets located in the Haynesville and Bossier shales. 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 $388 million after customary adjustments) with the buyer also assuming a transportation commitment totaling $106 million.

Summarized operating results of our assets sold were as follows (in millions):
 
Quarter ended 
 March 31,
 
2016
Operating revenues
$
20

 
 
Operating expenses
 

Transportation costs
5

Lease operating expense
1

Depreciation, depletion and amortization
16

Other expense
4

Total operating expenses
26

Loss before income taxes
$
(6
)


3. Income Taxes
 
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.
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 both of the quarters ended March 31, 2017 and 2016, our effective tax rates were approximately 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 benefit by $15 million for the quarter ended March 31, 2017 and deferred income tax expense by $35 million for the quarter ended March 31, 2016. 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 $457 million as of March 31, 2017.

The Company's and certain subsidiaries' income tax years (2013-2016) remain open and subject to examination by both federal and state tax authorities. One 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 March 31, 2017 and December 31, 2016, all of our 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.

8



The following table presents the carrying amounts and estimated fair values of our financial instruments:
 
 
March 31, 2017
 
December 31, 2016
 
Carrying
 Amount
 
Fair
 Value
 
Carrying
 Amount
 
Fair
 Value
 
(in millions )
Long-term debt (see Note 6)
$
3,921

 
$
3,613

 
$
3,856

 
$
3,637

 
 
 
 
 
 
 
 
Derivative instruments
$
100

 
$
100

 
$
57

 
$
57

 
As of March 31, 2017 and December 31, 2016, 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, considering 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 March 31, 2017, we had derivative contracts in the form of fixed price swaps and three-way collars on 13 MMBbls of oil (10 MMBbls in 2017 and 3 MMBbls in 2018). In addition to our oil derivatives, we had derivative contracts in the form of fixed price swaps and options on 44 TBtu of natural gas (26 TBtu in 2017 and 18 TBtu in 2018) and 136 MMGal of ethane and propane fixed price swaps (75 MMGal in 2017 and 61 MMGal in 2018). As of December 31, 2016, we had fixed price derivative contracts for 16 MMBbls of oil, 36 TBtu on natural gas and 108 MMGal on ethane. In addition to the contracts above, we have derivative contracts related to locational basis differences 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 March 31, 2017 and December 31, 2016. 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 consolidated 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.
 
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)
 
 
March 31, 2017
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Derivative instruments
$
111

 
$
(11
)
 
$
88

 
$
12

 
$
(11
)
 
$
11

 
$

 
$

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2016
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Derivative instruments
$
79

 
$
(17
)
 
$
58

 
$
4

 
$
(22
)
 
$
17

 
$
(4
)
 
$
(1
)
For the quarters ended March 31, 2017 and 2016, we recorded derivative gains of $70 million and $42 million, respectively. Derivative gains and losses on our oil, natural gas and NGLs financial derivative instruments are recorded in operating revenues in our consolidated income statements.
Interest Rate Derivative Instruments.  On March 31, 2017, our interest rate swaps with a notional amount of $600 million ended. As of December 31, 2016, we had a net asset of less than $1 million related to interest rate derivative instruments included on our consolidated balance sheet.  For the quarters ended March 31, 2017 and 2016, we recorded less than $1 million of interest income and $2 million of interest expense related to the change in fair market value and cash settlements on our interest rate derivative instruments.

9


5.  Property, Plant and Equipment
 
Oil and Natural Gas Properties.  As of both March 31, 2017 and December 31, 2016, we had approximately $4.5 billion 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:
 
 
March 31, 2017
 
December 31, 2016
 
 
(in millions)
Proved
 
 
 
 
    Eagle Ford
 
$
3,089

 
$
3,001

    Wolfcamp
 
2,490

 
2,415

    Altamont
 
1,643

 
1,624

        Total Proved
 
7,222

 
7,040

Unproved
 
 
 
 
    Wolfcamp
 
62

 
94

    Altamont
 
60

 
60

        Total Unproved
 
122

 
154

Less accumulated depletion
 
2,848

 
2,731

        Net capitalized costs for oil and natural gas properties
 
$
4,496

 
$
4,463

During the quarter ended March 31, 2017, we transferred approximately $32 million from unproved properties to proved properties. For the quarters ended March 31, 2017 and 2016, we recorded approximately $1 million and less than $1 million, respectively, of amortization of unproved leasehold costs in exploration expense in our consolidated income statements. Suspended well costs were not material as of March 31, 2017 or December 31, 2016
We evaluate capitalized costs related to proved properties upon a triggering event (such as a significant decline in forward commodity prices) to determine if an impairment of such properties has occurred. Capitalized costs associated with unproved properties (e.g. leasehold acquisition costs associated with non-producing areas) are also assessed upon a triggering event for impairment based on estimated drilling plans and capital expenditures which may also change based on forward commodity price changes and/or potential lease expirations. Commodity price declines may cause changes to our capital spending levels, 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.
Generally, economic recovery of unproved reserves in non-producing or unproved 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 is 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 commodity prices not justify sufficient capital allocation to the continued development of properties where we have non-producing leasehold costs, we could incur impairment charges of our unproved property costs.
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 and 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 primarily 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, or reassessing our assumptions in light of changing market conditions. The net asset retirement liability as of March 31, 2017 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability from January 1 through March 31, 2017 were as follows: 

10


 
2017
 
(in millions)
Net asset retirement liability at January 1
$
41

Accretion expense
1

Net asset retirement liability at March 31
$
42

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 quarters ended March 31, 2017 and 2016 was approximately $1 million and $2 million, respectively. 

6. Long-Term Debt 
Listed below are our debt obligations as of the periods presented:
 
Interest Rate
 
March 31, 2017
 
December 31, 2016
 
 
 
(in millions)
RBL credit facility - due May 24, 2019(1)
Variable
 
$
265

 
$
370

Senior secured term loans:
 
 
 
 
 
Due May 24, 2018(2)(4)
Variable
 
21

 
21

Due April 30, 2019(3)(4)
Variable
 
8

 
8

Due June 30, 2021(5)
Variable
 

 
580

Senior secured notes:
 
 
 
 
 
Due November 29, 2024
8.00%
 
500

 
500

Due February 15, 2025
8.00%
 
1,000

 

Senior unsecured notes:
 
 
 
 
 
Due May 1, 2020
9.375%
 
1,326

 
1,576

Due September 1, 2022
7.75%
 
250

 
250

Due June 15, 2023
6.375%
 
551

 
551

Total long-term debt
 
 
3,921

 
3,856

Less unamortized debt issue costs
 
 
(57
)
 
(67
)
Total long-term debt, net
 
 
$
3,864

 
$
3,789

 
(1)
Carries interest at a specified margin over LIBOR of 2.50% to 3.50%, based on borrowing utilization.
(2)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 March 31, 2017 and
December 31, 2016, the effective interest rate of the term loan was 3.80% and 3.50%, respectively.
(3)
Carries interest at a specified margin over the LIBOR of 3.50%, with a minimum LIBOR floor of 1.00%.  As of March 31, 2017 and December 31, 2016, the effective interest rate for the term loan was 4.55% and 4.50%, respectively.
(4)
Secured by a second priority lien on all of the collateral securing the RBL Facility, and effectively rank junior to any existing and future priority lien secured indebtedness of the Company.
(5)
As of December 31, 2016, the effective interest rate for the term loan was 9.75%.

     During the first quarter of 2017, we issued $1 billion of 8.00% senior secured notes which mature in 2025 and used the proceeds (less fees and expenses) to (i) repay in full our $580 million senior secured term loans due 2021, (ii) repurchase $250 million of our 9.375% senior notes due 2020 in the open market and (iii) repay $111 million of the amounts outstanding under our Reserve-Based Loan facility (RBL Facility). As a result of the issuance, our RBL borrowing base was also reduced to $1.44 billion. In conjunction with these transactions, we recorded a loss on extinguishment of debt of approximately $53 million (including $30 million in non-cash expense related to eliminating associated unamortized debt issue costs and debt discounts).

During the first quarter of 2016, we paid approximately $143 million in cash to repurchase a total of approximately $345 million in aggregate principal amount of our senior unsecured notes. We recorded a gain on extinguishment of debt of approximately $196 million (including $6 million of non-cash expense related to eliminating associated unamortized debt issue costs).
    
Unamortized Debt Issue Costs. As of March 31, 2017 and December 31, 2016, we had total unamortized debt issue costs of $66 million and $77 million. Of these amounts, $9 million and $10 million, respectively, are associated with our RBL Facility and $57 million and $67 million, respectively, are associated with our senior secured term loans and senior notes.

11


During the first quarter of 2017, we (i) recorded an additional $19 million in conjunction with the issuance of our $1 billion of 8.00% senior secured notes and (ii) expensed approximately $28 million in conjunction with the repurchase of a portion of our senior secured term loans and senior unsecured notes and the reduction of our RBL borrowing base. During both of the quarters ended March 31, 2017 and 2016, we amortized $4 million of deferred financing costs into interest expense. 

Reserve-based Loan Facility. We have a $1.44 billion credit facility in place which allows us to borrow funds or issue letters of credit. The facility matures in May 2019. As of March 31, 2017, we had $1,153 million of available capacity remaining with approximately $19 million of letters of credit issued and approximately $265 million outstanding under the facility. 
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 April 2017, we completed the semi-annual redetermination and reaffirmed the borrowing base at $1.44 billion. Our next redetermination date is in October 2017.  Downward revisions of our oil and natural gas reserves due to declines in commodity prices, performance revisions, sales of 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.
Guarantees.  Our obligations under the RBL Facility, term loans, 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, the most restrictive of which is a requirement that our first lien debt to EBITDAX, as defined in the credit agreement, not exceed 3.5 to1.0. As of March 31, 2017, we were in compliance with our debt covenants, and our ratio of first lien debt to EBITDAX was 0.28x. In April 2017, in conjunction with the redetermination, our first lien debt to EBITDAX covenant was extended through March 31, 2019. In addition, the first lien debt to EBITDAX ratio covenant was reduced to 3.0 to 1.0, and the company paid an amendment fee of approximately $1 million. In April 2019, our financial covenant will revert to a requirement that our total debt to EBITDAX ratio not exceed 4.5 to 1.0.

Under our RBL Facility, we are also limited in non-RBL Facility debt repurchases to $350 million, subject to certain adjustments. The $350 million limit has increased as a result of recent divestitures and financing transactions and will continue to be subject to future adjustments. Certain other covenants and restrictions, among other things, also limit our ability to incur or guarantee additional indebtedness; make any restricted payments or pay any dividends on equity interests or redeem, repurchase or retire parent entities’ equity interests or subordinated indebtedness; sell assets; make investments; create certain liens; prepay debt obligations; engage in transactions with affiliates; and enter into certain hedge agreements.

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 March 31, 2017, we had approximately $3 million accrued for all outstanding legal matters.
Indemnifications and Other Matters. We periodically enter into indemnification arrangements as part of the divestiture 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 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

12


plugging and abandonment obligations that attach to such assets. In that event, under various laws or regulations, we could be required to assume all, or a portion of the plugging or abandonment obligations on assets we no longer own or operate. As of March 31, 2017, we had approximately $8 million accrued related to these indemnifications and other matters.
Non-Income Tax Matters. We are under a number of examinations by taxing authorities related to non-income tax
matters.     As of March 31, 2017, we had approximately $47 million accrued (included in other accrued liabilities in our consolidated balance sheet) in connection with ongoing examinations related to certain prior period non-income tax 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. 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. For additional details on certain environmental matters, including matters related to climate change, air quality and other emissions, hydraulic fracturing regulations and waste handling, refer to the Risk Factors section of our 2016 Annual Report on Form 10-K.
While our reserves for environmental matters are currently not material, there are still uncertainties related to the ultimate costs we may incur in the future in order to comply with 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. Based upon our evaluation and experience to date, however, we believe our accruals for these matters are adequate. It is possible that new information or future developments could result in substantial additional costs and liabilities which could require us to reassess our potential exposure related to these matters and to adjust our accruals accordingly, and these adjustments could be material.

8. Long-Term Incentive Compensation
 
Restricted Stock. Our parent's long-term incentive (LTI) programs consist of restricted stock, stock option and performance unit awards. A summary of the changes in our parent’s non-vested restricted shares for the quarter ended March 31, 2017 is presented below:
 
 
Number of Shares
 
Weighted Average
Grant Date Fair Value
per Share
Non-vested at December 31, 2016
 
6,326,788

 
$
7.69

Granted
 
4,953,434

 
$
4.28

Vested
 
(1,823,054
)
 
$
7.26

Forfeited
 
(490,478
)
 
$
7.91

Non-vested at March 31, 2017
 
8,966,690

 
$
5.88


Performance Unit Awards. A summary of the changes in our parent's performance unit awards for the quarter ended March 31, 2017 is presented below:
 
Number of Awards
 
 Weighted Average
Fair Value
Non-vested at December 31, 2016
78,900

 
$
97.77

Granted(1)
40,470

 
$
36.57

Vested
(22,302
)
 
$
159.92

Forfeited
(12,000
)
 
$
159.92

Non-vested at March 31, 2017
85,068

 
$
66.49

 
(1)
Grant date fair value at March 16, 2017 is based on: (i) an expected term of 3 years, (ii) expected volatility of 96.71%, which is based upon the historical stock price volatility and (iii) a risk-free interest rate of 1.57%, based upon the yield on U.S. Treasury STRIPS over the expected term as of the grant date.


13


Our performance unit awards are treated as liability awards for accounting purposes with the expense recognized on an accelerated basis and fair value remeasured at each reporting period. During the first quarter ended March 31, 2017, we paid approximately $4 million in connection with awards that vested and had accrued approximately $1 million related to unvested outstanding performance unit awards. Performance unit awards may be settled in either stock or cash at the election of the board of directors of our parent. Had all outstanding performance unit awards at March 31, 2017 vested and been settled in stock, 0.8 million shares would have been issued. Refer to our 2016 Annual Report on Form 10-K for further description regarding the terms and details of these awards.

We record compensation expense on all of our LTI awards as general and administrative expense over the requisite service period. Pre-tax compensation expense related to all of our parent's LTI awards (both equity and liability based), net of the impact of forfeitures, was approximately $(1) million and $5 million for the quarters ended March 31, 2017 and 2016, respectively. Compensation expense for the quarter ended March 31, 2017 reflects approximately $7 million of forfeitures. As of March 31, 2017, we had unrecognized compensation expense of $63 million.  We will recognize an additional $18 million related to our outstanding awards during the remainder of 2017, $33 million over the remaining requisite service periods subsequent to 2017 and $12 million should a specified capital transaction occur and the right to such amounts become non-forfeitable.


9. Related Party Transactions
    
Joint Venture. In January 2017, we entered into a drilling joint venture with Wolfcamp Drillco Operating L.P. (the
Investor), which is managed and controlled by an affiliate of Apollo Global Management LLC, to fund future oil and natural gas development in our Wolfcamp program. The Investor is anticipated to fund an estimated $450 million over the entire program (150 wells in two separate 75 well tranches), or approximately 60 percent of the estimated drilling, completion and equipping costs of the wells in exchange for a 50 percent working interest in the joint venture wells.  Once the Investor achieves a 12 percent internal rate of return on its invested capital in each tranche, its working interest reverts to 15 percent.  We are the operator of the joint venture assets and the transaction increases our well-level returns on the jointly developed wells. The first wells under the joint venture began producing in January 2017, and for the quarter ended March 31, 2017, we recovered approximately $57 million related to the capital costs of the joint venture wells from the Investor.

Affiliate Supply Agreement.  For the quarters ended March 31, 2017 and 2016, we recorded less than $1 million and approximately $4 million in capital expenditures for amounts expended under supply agreements entered into with an affiliate of Apollo Global Management, LLC to provide certain materials used in our Eagle Ford drilling operations.

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 March 31, 2017 and December 31, 2016, we had federal income tax payable due to parent of $1 million.
 

14


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 2016 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 development and acquisition of unconventional onshore oil and natural gas properties in the United States. We operate through a diverse base of producing assets and are focused on creating shareholder value through the development of our drilling inventory located in three core areas:  the Wolfcamp Shale (Permian Basin in West Texas), the Eagle Ford Shale (South Texas), and the Altamont Field in the Uinta Basin (Northeastern Utah). 
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 also sell oil and natural gas properties if they no longer meet our long-term goals.
In January 2017, we entered into a drilling joint venture to accelerate and fund future oil and natural gas development
in our Wolfcamp program. Under the joint venture, our partner is participating in the development of up to 150 wells in two
separate 75 well tranches primarily in Reagan and Crockett counties. Our joint venture investor will fund approximately $450
million over the entire program, or approximately 60 percent of the drilling, completion and equipping costs in exchange for a
50 percent working interest in the joint venture wells. Once the investor achieves a 12 percent internal rate of return on its
invested capital in each tranche, its working interest reverts to 15 percent. We are the operator of the joint venture assets and the transaction increases our well-level returns on the jointly developed wells. The first wells under the joint venture began production in January 2017.
    
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 operating 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.    
Forward commodity prices play a significant role in determining the recoverability of proved or unproved property
costs on our balance sheet. Future price declines, along with changes to our future capital, production rates, levels of proved
reserves and development plans, may result in an impairment of the carrying value of our proved and/or unproved properties in
the future, and such charges could be significant.

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,

15


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, natural gas and NGLs are affected by (i) commodity price movements, including locational or basis price differences that exist between the commodity index price (e.g., WTI) and the actual price at which we sell the commodity, 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 unfavorable movements in locational prices.
During the quarter ended March 31, 2017, we (i) settled commodity index hedges on approximately 75% of our oil production, 59% of our total liquids production and on 51% of our natural gas production at average floor prices of $61.66 per barrel of oil, $0.67 per gallon of NGLs and $3.25 per MMBtu of natural gas, respectively.  To the extent our oil and natural gas production is unhedged, either from a commodity index or locational price perspective, our operating revenues 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 March 31, 2017.
 
2017
 
2018
 
Volumes(1)
 
Average
Price(1)
 
Volumes(1)
 
Average
Price(1)
Oil
 

 
 

 
 

 
 

Fixed Price Swaps
 

 
 

 
 

 
 

WTI
3,025

 
$
63.94

 

 
$

Three Way Collars
 
 
 
 
 
 
 
Ceiling - WTI
6,655

 
$
70.37

 
3,285

 
$
65.00

Floors - WTI(2)(3)
6,655

 
$
60.62

 
3,285

 
$
60.00

Basis Swaps
 
 
 
 
 
 
 
LLS vs. Brent(4)
2,750

 
$
(3.14
)
 

 
$

Midland vs. Cushing(5)
1,100

 
$
(0.68
)
 

 
$

Natural Gas
 
 
 
 
 
 
 
Fixed Price Swaps
18

 
$
3.25

 
18

 
$
3.07

Ceiling
8

 
$
3.67

 

 
$

Floors
8

 
$
3.35

 

 
$

NGLs
 
 
 
 
 
 
 
Fixed Price Swaps - Ethane
46

 
$
0.27

 
61

 
$
0.30

Fixed Price Swaps - Propane
29

 
$
0.67

 

 
$

 
(1)
Volumes presented are MBbls for oil, TBtu for natural gas and MMGal for NGLs. Prices presented are per Bbl of oil, MMBtu of natural gas and Gal for NGLs.
(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)
If market prices settle at or below $50.00 in 2018, we will receive a “locked-in” cash settlement of the market price plus $10.00 per Bbl.
(4)
EP Energy receives Brent plus the basis spread listed and pays LLS. These positions listed do not include Brent vs. LLS basis swaps which offset our 2.75 MBbls LLS vs. Brent with an average of $(0.46) per barrel of oil.
(5)
EP Energy receives Cushing plus the basis spread listed and pays Midland.

     For the period from April 1, 2017 through May 2, 2017, we entered into a non-cash derivative exchange on 2.0 MMBbls of 2017 WTI fixed price swaps for 5.6 MMBbls of 2018 three way collars. Additionally we entered into derivative contracts on 4.9 TBtu and 14.6 TBtu of 2017 and 2018 Waha natural gas basis swaps.
Summary of Liquidity and Capital Resources.  As of March 31, 2017, we had available liquidity of approximately $1,188 million, reflecting $1,153 million of available liquidity on our $1.44 billion RBL Facility borrowing base and $35 million of available cash. In 2017, we continued to take steps to improve our liquidity, strengthen our balance sheet and expand our financial flexibility by issuing $1 billion of 8.00% senior secured notes which mature in 2025 and using the net proceeds to (i) repay in full our $580 million senior secured term loans due 2021, (ii) repurchase $250 million of our 9.375% senior notes due 2020 in the open market, and (iii) repay $111 million of the amounts outstanding under our RBL Facility. In April 2017, we also reaffirmed the borrowing base of our RBL Facility at $1.44 billion and amended our credit agreement, extending the first lien debt to EBITDAX covenant through March 31, 2019, and reducing it such that the ratio of first lien debt to EBITDAX may not exceed 3.0 to 1.0. For a further discussion of our liquidity and capital resources, including factors that could impact our liquidity, see Liquidity and Capital Resources.

16


Production Volumes and Drilling Summary
 
Production Volumes. Below is an analysis of our production volumes for the quarters ended March 31:
 
 
2017
 
2016
United States (MBoe/d)
 

 
 

Wolfcamp Shale
27.5

 
18.3

Eagle Ford Shale
37.7

 
50.8

Altamont
17.3

 
16.2

Other(1)

 
18.7

Total
82.5

 
104.0

 
 
 
 
Oil (MBbls/d)
46.9

 
50.8

Natural Gas (MMcf/d)(1)
127

 
232

NGLs (MBbls/d)
14.4

 
14.5

 
 
(1)
Primarily consists of Haynesville Shale which was sold in May 2016. For the quarter ended March 31, 2016, natural gas volumes included 111 MMcf/d from the Haynesville Shale.

Wolfcamp Shale—Our Wolfcamp Shale equivalent volumes increased 9.2 MBoe/d (approximately 50%) and oil production increased by 4.1 MBoe/d (approximately 59%) for the quarter ended March 31, 2017 compared to the same period in 2016. During the quarter ended March 31, 2017, we completed 11 additional operated wells, for a total of 286 net operated wells as of March 31, 2017
Eagle Ford Shale—Our Eagle Ford Shale equivalent volumes decreased by 13.1 MBoe/d (approximately 26%) and oil production decreased by 8.5 MBbls/d (approximately 26%) for the quarter ended March 31, 2017 compared to the same period in 2016.  During the quarter ended March 31, 2017, we completed 30 additional operated wells in the Eagle Ford, for a total of 628 net operated wells as of March 31, 2017.
Altamont—Our Altamont equivalent volumes increased 1.1 MBoe/d (approximately 7%) and oil production increased by 0.5 MBbls/d (approximately 4%) for the quarter ended March 31, 2017 compared to the same period in 2016. During the quarter ended March 31, 2017, we completed three additional operated oil wells, for a total of 376 net operated wells as of March 31, 2017.
Our production declines in our Eagle Ford area reflect natural declines and the slowed pace of development in our drilling program due to reduced capital spending in 2016, while increases in Wolfcamp reflect incremental capital allocated to this program in 2016. Future volumes across all our assets will be impacted by the level of natural declines, and the level and timing of capital spending in each respective asset. In the current commodity price environment, we may continue to have low spending levels which may result in lower produced volumes in the future.


17


Results of Operations
 
The information in the table below provides a summary of our financial results.
 
 
Quarter ended 
 March 31,
 
2017
 
2016
 
(in millions)
Operating revenues
 

 
 

Oil
$
204

 
$
129

Natural gas
30

 
42

NGLs
23

 
11

Total physical sales
257

 
182

Financial derivatives
70

 
42

Total operating revenues
327

 
224

 
 
 
 
Operating expenses
 

 
 

Oil and natural gas purchases
1

 
4

Transportation costs
29

 
30

Lease operating expense
40

 
42

General and administrative
20

 
38

Depreciation, depletion and amortization
126

 
113

Exploration and other expense
3

 
1

Taxes, other than income taxes
19

 
14

Total operating expenses
238

 
242

 
 
 
 
Operating income (loss)
89

 
(18
)
(Loss) gain on extinguishment of debt
(53
)
 
196

Interest expense
(83
)
 
(84
)
(Loss) income before income taxes
(47
)
 
94

Income tax expense

 

Net (loss) income
$
(47
)
 
$
94


18


Operating Revenues
 
The table below provides our operating revenues, volumes and prices per unit for the quarters ended March 31, 2017 and 2016. 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 
 March 31,
 
2017
 
2016
 
(in millions)
Operating revenues:
 

 
 

Oil
$
204

 
$
129

Natural gas
30

 
42

NGLs
23

 
11

Total physical sales
257

 
182

Financial derivatives
70

 
42

Total operating revenues
$
327

 
$
224

 
 
 
 
Volumes:
 

 
 

Oil (MBbls)
4,219

 
4,624

Natural gas (MMcf)(1)
11,465

 
21,150

NGLs (MBbls)
1,296

 
1,317

Equivalent volumes (MBoe)(1)
7,426

 
9,466

Total MBoe/d(1)
82.5

 
104.0

 
 
 
 
Prices per unit(2):
 

 
 

Oil
 

 
 

Average realized price on physical sales ($/Bbl)(3) 
$
48.43

 
$
27.89

Average realized price, including financial derivatives ($/Bbl)(3)(4)
$
54.90

 
$
72.73

Natural gas
 
 
 
Average realized price on physical sales ($/Mcf)(3)
$
2.49

 
$
1.81

Average realized price, including financial derivatives ($/Mcf)(3)(4)
$
2.46

 
$
1.99

NGLs
 
 
 
Average realized price on physical sales ($/Bbl)
$
17.63

 
$
8.24

Average realized price, including financial derivatives ($/Bbl)(4) 
$
17.76

 
$
8.69

 

(1)
For the quarter ended March 31, 2016, Haynesville Shale production volumes were 10,130 MMcf of natural gas and 1,688 MBoe (18.6 MBoe/d) of equivalent volumes.
(2)
Natural gas prices for the quarters ended March 31, 2017 and 2016 reflect operating revenues for natural gas reduced by approximately $1 million and $4 million, respectively, for natural gas purchases associated with managing our physical sales. Oil prices for the quarter ended March 31, 2016 reflect operating revenues for oil reduced by less than $1 million for oil purchases associated with managing our physical sales.
(3)
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.
(4)
The quarters ended March 31, 2017 and 2016, include approximately $27 million and $207 million, respectively, of cash received for the settlement of crude oil derivative contracts and less than $1 million of cash paid and approximately $4 million of cash received, respectively, for the settlement of natural gas financial derivatives.  The quarters ended March 31, 2017 and 2016 also include less than $1 million and approximately $1 million of cash received, respectively, for the settlement of NGLs derivative contracts. 







19


Physical sales.  Physical sales represent accrual-based commodity sales transactions with customers. For the quarter ended March 31, 2017, physical sales increased by $75 million (41%) compared to the same period in 2016. Physical sales have increased primarily due to higher prices across all commodity types, partially offset by lower oil and natural gas volumes reflecting the continued slower pace of development in our drilling programs due to reduced capital spending in 2016 and the first quarter of 2017 and from the impact of the sale of our Haynesville Shale assets in May 2016. The table below displays the price and volume variances on our physical sales when comparing the quarters ended March 31, 2017 and 2016
 
Oil
 
Natural gas
 
NGLs
 
Total
 
(in millions)
March 31, 2016 sales
$
129

 
$
42

 
$
11

 
$
182

Change due to prices
86

 
6

 
12

 
104

Change due to volumes
(11
)
 
(18
)
 

 
(29
)
March 31, 2017 sales
$
204

 
$
30

 
$
23

 
$
257

Oil sales for the quarter ended March 31, 2017 compared to the same period in 2016 increased by $75 million (58%), due primarily to higher oil prices.  Partially offsetting this increase was a decrease in oil volumes in Eagle Ford reflecting the slowed pace of development of that program in 2016. For the quarter ended March 31, 2017 compared to the same period in 2016, Eagle Ford oil production decreased by 26% (8.5 MBbls/d).
Natural gas sales decreased for the quarter ended March 31, 2017 compared to the same period in 2016 primarily due to lower volumes from the sale of our Haynesville Shale assets in May 2016. The Haynesville Shale produced a total of 111 MMcf/d for the quarter ended March 31, 2016. Partially offsetting this decrease were higher natural gas prices and natural gas volume growth primarily in Wolfcamp during the quarter ended March 31, 2017.
Our oil, natural gas and NGLs are sold at index prices (WTI, LLS, Henry Hub and Mt. Belvieu) or refiners' 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 deductions, differentials from the index to the delivery point, adjustments for time, and/or discounts for quality or grade. 
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.  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. 
 
Quarter ended March 31,
 
2017
 
2016
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
Differentials and deducts
$
(3.81
)
 
$
(0.81
)
 
$
(5.52
)
 
$
(0.29
)
NYMEX
$
51.91

 
$
3.32

 
$
33.45

 
$
2.09

Net back realization %
92.7
%
 
75.6
%
 
83.5
%
 
86.1
%

The higher oil realization percentage in the quarter ended March 31, 2017 was primarily a result of improved physical sales contracts in all programs, and the impact of higher WTI prices. The lower natural gas realization percentage in the quarter ended March 31, 2017 was primarily a result of the impact of the sale of our Haynesville assets and its associated lower basis differentials. Also impacting the lower realization percentage in 2017 was the impact on basis differentials in Wolfcamp due to constrained natural gas takeaway capacity in the basin.
NGLs sales increased by $12 million for the quarter ended March 31, 2017 compared with the same period in 2016. Average realized prices for the quarter ended March 31, 2017 were higher compared to the same period in 2016, due to higher pricing on all liquids components. NGLs pricing is largely tied to crude oil prices. NGLs volumes remained relatively flat for the quarter ended March 31, 2017 compared to the same period in 2016.
Future growth in our overall oil and natural gas sales (including the impact of financial derivatives) will largely be impacted by commodity pricing, our level of hedging, our ability to maintain or grow oil volumes and by the location of our

20


production and the nature of our sales contracts. See "Our Business" and "Liquidity and Capital Resources" 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 March 31, 2017, we recorded $70 million of derivative gains compared to derivative gains of $42 million during the quarter ended March 31, 2016
Operating Expenses
The table below provides our operating expenses, volumes and operating expenses per unit for each of the periods presented:
 
Quarter ended 
 March 31,
 
2017
 
2016
 
Total
 
Per Unit(1)
 
Total
 
Per Unit(1)
 
(in millions, except per unit costs)
Operating expenses
 
 
 
 
 
 
 
Oil and natural gas purchases
$
1

 
$
0.15

 
$
4

 
$
0.46

Transportation costs
29

 
3.84

 
30

 
3.11

Lease operating expense
40

 
5.37

 
42

 
4.38

General and administrative(2)
20

 
2.66

 
38

 
4.04

Depreciation, depletion and amortization
126

 
16.99

 
113

 
11.94

Exploration and other expense
3

 
0.39

 
1

 
0.13

Taxes, other than income taxes
19

 
2.61

 
14

 
1.55

Total operating expenses
$
238

 
$
32.01

 
$
242

 
$
25.61

 
 
 
 

 
 
 
 

Total equivalent volumes (MBoe)
7,426

 
 
 
9,466

 
 
 
(1)
Per unit costs are based on actual amounts rather than the rounded totals presented.
(2)
For the quarter ended March 31, 2017, amount includes approximately $(4) million or $(0.53) per Boe of non-cash compensation expense (cash payments exceeded recognized compensation expense). For the quarter ended March 31, 2016, amount includes approximately $8 million or $0.83 per Boe of transition and severance costs related to workforce reductions and $4 million or $0.43 per Boe of non-cash compensation expense.

Oil and natural gas purchases.  From time to time, we purchase and sell oil and natural gas 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 ended March 31, 2017 decreased by $3 million compared to the same period in 2016 primarily due to the sale of our Haynesville assets in May 2016.
Lease operating expense.  Lease operating expense for the quarter ended March 31, 2017 decreased by $2 million compared to the same period in 2016 including a decrease of $4 million in Eagle Ford due to lower disposal and chemical costs and a decrease of $1 million due to the sale of Haynesville in May 2016. These decreases were offset by an increase of $3 million due to higher maintenance and repair costs in our Wolfcamp, Eagle Ford and Altamont areas. On a per equivalent unit basis, lease operating expense increased 23% from $4.38 per Boe in the first quarter of 2016 to $5.37 per Boe in the first quarter of 2017 due to lower production volumes in 2017.
General and administrative expenses.  General and administrative expenses for the quarter ended March 31, 2017 decreased by $18 million compared to the same period in 2016. Lower costs during the quarter ended March 31, 2017 compared to the same period in 2016 included lower payroll, benefits and administrative costs of $12 million and lower severance expense of $8 million. The lower payroll, benefits and administrative costs resulted from lower headcount in the quarter ended March 31, 2017 when compared to March 31, 2016.
Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense for the quarter ended March 31, 2017 increased compared to the same period in 2016 due primarily to a reduction in reserves in Eagle Ford and higher Wolfcamp and Altamont volumes during the quarter ended March 31, 2017 compared to 2016. Our Wolfcamp and Altamont areas have a higher depreciation, depletion and amortization cost per unit than Eagle Ford as a result of a non-cash

21


impairment charge recorded in 2015 on our proved properties in Eagle Ford. Our average depreciation, depletion and amortization costs per unit for the quarters ended March 31 were:
 
Quarter ended 
 March 31,
 
2017
 
2016
Depreciation, depletion and amortization ($/Boe)
$
16.99

 
$
11.94


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. For the full year 2017, we currently anticipate our depreciation, depletion and amortization costs per unit to be between $16.00 and $17.00 per Boe.
Taxes, other than income taxes.  Taxes, other than income taxes, for the quarter ended March 31, 2017 increased by $5 million from the same period in 2016 due to an increase of severance taxes as a result of higher commodity prices.
Other Income Statement Items.
(Loss) gain on extinguishment of debt. During the first quarter of 2017, we issued $1 billion of 8.00% senior secured notes and used the proceeds (less fees and expenses) to (i) repay in full our $580 million senior secured term loans due 2021, (ii) repurchase $250 million of our 9.375% senior notes due 2020 in the open market and (iii) repay $111 million of the amounts outstanding under our Reserve-Based Loan facility (RBL Facility). In conjunction with these transactions, we recorded a loss on extinguishment of debt of approximately $53 million (including $30 million in non-cash expense related to eliminating associated unamortized debt issuance costs and debt discounts).
During the first quarter of 2016, we paid approximately $143 million in cash to repurchase a total of approximately $345 million in aggregate principal amount of our senior unsecured notes. We recorded a gain on extinguishment of debt of approximately $196 million (including $6 million of non-cash expense related to eliminating associated unamortized debt issue costs).

Income Taxes. For both of the quarters ended March 31, 2017 and 2016, our effective tax rates were approximately 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 benefit by $15 million for the quarter ended March 31, 2017 and deferred income tax expense by $35 million for the quarter ended March 31, 2016.
 



22


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 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 these plans), transition, restructuring and other costs that affect comparability 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 (loss) income to EBITDAX and Adjusted EBITDAX:
 
Quarter ended 
 March 31,
 
2017
 
2016
 
(in millions)
Net (loss) income
$
(47
)
 
$
94

Interest expense, net of capitalized interest
83

 
84

Depreciation, depletion and amortization
126

 
113

Exploration expense
3

 
1

EBITDAX
165

 
292

Mark-to-market on financial derivatives(1)
(70
)
 
(42
)
Cash settlements and cash premiums on financial derivatives(2)
28

 
212

Non-cash portion of compensation expense(3)
(4
)
 
4

Transition, restructuring and other costs(4)

 
8

Loss (gain) on extinguishment of debt
53

 
(196
)
Adjusted EBITDAX
$
172

 
$
278

 
(1)
Represents the income statement impact of financial derivatives.
(2)
Represents actual cash settlements related to financial derivatives. No cash premiums were received or paid for the quarters ended March 31, 2017 and 2016.
(3)
For the quarters ended March 31, 2017 and 2016, the non-cash portion of compensation expense (net of forfeitures) includes cash payments of approximately $4 million and less than $1 million, respectively.
(4)
Reflects transition and severance costs related to workforce reductions.


23


Commitments and Contingencies
 
For a further discussion of our commitments and contingencies, see Part I, Item 1, Financial Statements, Note 7.
Liquidity and Capital Resources
Our primary sources of liquidity are cash generated by our operations and borrowings under our RBL Facility. Our primary uses of cash are capital expenditures, debt service, including interest, and working capital requirements. Our available liquidity was approximately $1,188 million as of March 31, 2017.
In 2017, we continued to take steps to improve our liquidity, strengthen our balance sheet and expand our financial flexibility by issuing $1 billion of 8.00% senior secured notes which mature in 2025 and using the net proceeds to (i) repay in full our $580 million senior secured term loans due 2021, (ii) repurchase $250 million of our 9.375% senior notes due 2020 in the open market, and (iii) repay $111 million of the amounts outstanding under our RBL Facility.
Our RBL Facility has a borrowing base subject to semi-annual redetermination. In February 2017, as a result of the issuance of our $1 billion senior secured notes due 2025, our RBL borrowing base was reduced to $1.44 billion. In April 2017, we completed the semi-annual redetermination and reaffirmed the borrowing base at $1.44 billion. Downward revisions of our oil and natural gas reserves volume and value due to declines in commodity prices, the impact of lower estimated capital spending in response to lower prices, performance revisions, or sales of assets, or the incurrence of certain types of additional debt, among other items, could cause a reduction of our borrowing base in the future, and these reductions could be significant.

In April 2017, in conjunction with the redetermination, our first lien debt to EBITDAX covenant was extended through March 31, 2019. In addition, the first lien debt to EBITDAX ratio covenant was reduced to 3.0 to 1.0, and the company paid an amendment fee of approximately $1 million. As of March 31, 2017 our ratio of first lien debt to EBITDAX was 0.28x. In April 2019, this financial covenant will revert to a requirement that our total debt to EBITDAX ratio not exceed 4.5 to 1.0, and in May 2019 our RBL Facility will mature. Under our RBL Facility, we are also limited in non-RBL Facility debt repurchases to $350 million, subject to certain adjustments. The $350 million limit has increased as a result of recent divestitures and financing transactions and will continue to be subject to future adjustments.
    
For 2017 and 2018, we have derivative contracts on 9.7 MMBbls and 3.3 MMBbls of our anticipated oil production
at a weighted average price of $61.66 and $60.00 per barrel of oil and 26 TBtu and 18 TBtu of our anticipated natural gas
production at a weighted average price of $3.28 and $3.07 per MMBtu, respectively. As of March 31, 2017 based on the mid-point of our forecasted 2017 guidance, our oil and natural gas derivative contracts provide price protection on approximately 75% and 76%, respectively, of our anticipated 2017 oil and natural gas production. In April 2017, we entered into a non-cash derivative exchange on 2.0 MMBbls of 2017 WTI fixed price swaps for 5.6 MMBbls of 2018 three way collars and additional derivative contracts. As a result of this derivative exchange and other transactions through May 2, 2017, we have price protection on approximately 63% and 76%, respectively, on our anticipated 2017 oil and natural gas production, and approximately 52% and 44% on our 2018 oil and natural gas production, respectively, all based on the mid-point of our forecasted 2017 guidance. See "Our Business" for further information on our derivative instruments.

For 2017, we expect to spend approximately $630 million to $730 million in capital in our programs. Based upon our
current price and cost assumptions, including the impact of our hedges, we believe that our current capital program will exceed
our estimated operating cash flows. In the first quarter of 2017, our cash flows from operations were approximately in line with cash paid for capital expenditures. We believe the borrowing capacity under our RBL Facility together with expected cash flows from our operations will be sufficient to fund our capital program and meet current obligations and projected working capital requirements through the next twelve months.

Our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the RBL Facility, (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all, or (iii) obtain additional capital if required on acceptable terms or at all to fund our capital programs or any potential future acquisitions, joint ventures or other similar transactions, will depend on prevailing economic conditions many of which are beyond our control. The ongoing volatility in the energy industry and in commodity prices will likely continue to impact our outlook. Our plans are intended to address the impacts of the current volatility in commodity prices while (i) maintaining sufficient liquidity to fund capital in our drilling programs, (ii) meeting our debt maturities, and (iii) managing and working to strengthen our balance sheet. We will continue to be opportunistic and aggressive in managing our cost structure and in turn, our liquidity to meet our capital and operating needs. Accordingly, we will continue to pursue cost saving measures where possible to reduce our capital, operating, and general and administrative costs, which may include renegotiating contracts with contractors, suppliers and service

24


providers, deferring and eliminating various discretionary costs, and/or reducing the number of staff and contractors, if necessary.
To the extent commodity prices remain low or decline further, or we experience disruptions in the financial markets impacting our longer-term access to them or that affect our cost of capital, our ability to fund future growth projects may be further impacted. We continually monitor the capital markets and our capital structure and make changes from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity and/or achieving cost efficiency. For example, we could (i) elect to continue to repurchase additional amounts of our outstanding debt in the future for cash through open market repurchases or privately negotiated transactions with certain of our debtholders subject to the limitations in our RBL Facility or (ii) issue additional secured debt as permitted under our debt agreements, although there is no assurance we would do so. It is also possible that additional adjustments to our plan and outlook may occur based on market conditions and the needs of the Company at that time, which could include selling assets, liquidating all or a portion of our hedge portfolio, seeking additional partners to develop our assets, and/or further reducing our planned capital spending program.
Capital Expenditures.  Our capital expenditures and average drilling rigs by area for the quarter ended March 31, 2017 were:
 
Capital
Expenditures(1)
(in millions)
 
Average Drilling
 Rigs
Eagle Ford Shale
$
92

 
1.0

Wolfcamp Shale
40

 
2.0

Altamont
20

 
1.3

Total
$
152

 
4.3

 
(1) Represents accrual-based capital expenditures.

Debt. As of March 31, 2017, our total debt was approximately $3.9 billion, comprised of $29 million in senior secured term loans with maturity dates in 2018 and 2019, $265 million outstanding under the RBL Facility which matures in 2019, $2.1 billion in senior unsecured notes due in 2020, 2022 and 2023, and $1.5 billion in senior secured notes due in 2024 and 2025. For additional details on our long-term debt, including maturities, borrowing capacity and restrictive covenants under our debt agreements, see above and Part I, Item 1, Financial Statements, Note 6.
    
    

25


Overview of Cash Flow Activities.  Our cash flows from operations are summarized as follows (in millions):
 
Three months ended March 31,
 
2017
 
2016
Cash Inflows
 

 
 

Operating activities
 

 
 

Net (loss) income
$
(47
)
 
$
94

Loss (gain) on extinguishment of debt
53

 
(196
)
Other income adjustments
131

 
122

Changes in assets and liabilities
(23
)
 
279

Total cash flow from operations
$
114

 
$
299

 
 
 
 
Financing activities
 
 
 
Proceeds from issuance of long-term debt
$
1,125

 
$
325

Contributions from parent
4

 

 Cash inflows from financing activities
$
1,129

 
$
325

 
 
 
 
Total cash inflows
$
1,243

 
$
624

 
 
 
 
Cash Outflows
 

 
 

Investing activities
 
 
 

Capital expenditures
$
119

 
$
179

 
 
 
 
Financing activities
 

 
 

Repayments and repurchases of long-term debt
$
1,086

 
$
380

Debt issuance costs
19

 

 
$
1,105

 
$
380

 
 
 
 
Total cash outflows
$
1,224

 
$
559

 
 
 
 
Net change in cash and cash equivalents
$
19

 
$
65


26


Contractual Obligations

We are party to various contractual obligations. Some of these obligations are reflected in our financial statements,
such as liabilities from financing obligations and commodity-based derivative contracts, while other obligations, such as operating leases and capital commitments, are not reflected on our consolidated balance sheet. The following table and discussion summarizes our contractual cash obligations as of March 31, 2017, for each of the periods presented:
 
2017
 
2018- 2019
 
2020 - 2021
 
Thereafter
 
Total
 
 
 
 
 
(in millions)
 
 
 
 
Financing obligations:
 

 
 

 
 

 
 

 
 

Principal
$

 
$
294

 
$
1,326

 
$
2,301

 
$
3,921

Interest
235

 
617

 
390

 
431

 
1,673

Operating leases
6

 
10

 
10

 
22

 
48

Other contractual commitments and purchase obligations:
 
 
 
 
 
 
 
 
 
Volume and transportation commitments
49

 
126

 
109

 
47

 
331

Other obligations
31

 
1

 

 

 
32

Total contractual obligations
$
321

 
$
1,048

 
$
1,835

 
$
2,801

 
$
6,005


Financing Obligations (Principal and Interest). Debt obligations included in the table above represent
stated maturities. Interest payments are shown through the stated maturity date of the related debt based on (i) the contractual
interest rate for fixed rate debt and (ii) current market interest rates and the contractual credit spread for variable rate debt. See Note 6 for more information on the maturities of our long-term debt.

Operating Leases. Amounts include leases related to our office space and various equipment.

Other Contractual Commitments and Purchase Obligations. Other contractual commitments and purchase obligations
are legally enforceable agreements to purchase goods or services that have fixed or minimum quantities and fixed or minimum
variable price provisions. Amounts in the schedule above approximate the timing of the underlying obligations. Included are the following:

Volume and Transportation Commitments. Included in these amounts are commitments for demand charges for firm access to natural gas transportation, volume deficiency contracts and firm oil capacity contracts.

Other Obligations. Included in these amounts are commitments for drilling, completion and seismic
activities for our operations and various other maintenance, engineering, procurement and construction
contracts. Our future commitments under these contracts may change reflecting changes in commodity prices
and any related effect on the supply and demand for these services. We have excluded asset retirement
obligations and reserves for litigation and environmental remediation, as these liabilities are not contractually
fixed as to timing and amount.


27


Item 3. Qualitative and Quantitative Disclosures About Market Risk
 
This information updates, and should be read in conjunction with the information disclosed in our 2016 Annual Report on Form 10-K, in addition to the information presented in Items 1 and 2 of Part I of this Quarterly Report on Form 10-Q.  There have been no material changes in our quantitative and qualitative disclosures about market risks from those reported in our 2016 Annual Report on Form 10-K, except as presented below:
Commodity Price Risk
The table below presents the change in fair value of our commodity-based derivatives due to hypothetical changes in oil and natural gas prices, discount rates and credit rates at March 31, 2017:
 
 
 
Oil, Natural Gas and NGLs Derivatives
 
 
 
10 Percent Increase
 
10 Percent Decrease
 
Fair Value
 
Fair Value
 
Change
 
Fair Value
 
Change
 
 
 
 
 
(in millions)
 
 
 
 
Price impact(1)
$
100

 
$
34

 
$
(66
)
 
$
161

 
$
61

 
 
 
Oil, Natural Gas and NGLs Derivatives
 
 
 
1 Percent Increase
 
1 Percent Decrease
 
Fair Value
 
Fair Value
 
Change
 
Fair
Value
 
Change
 
 
 
 
 
(in millions)
 
 
 
 
Discount rate(2)
$
100

 
$
99

 
$
(1
)
 
$
100

 
$

Credit rate(3)
$
100

 
$
99

 
$
(1
)
 
$
100

 
$

 
(1)
Presents the hypothetical sensitivity of our commodity-based derivatives to changes in fair values arising from changes in oil, natural gas and NGLs prices.
(2)
Presents the hypothetical sensitivity of our commodity-based derivatives to changes in the discount rates we used to determine the fair value of our derivatives.
(3)
Presents the hypothetical sensitivity of our commodity-based derivatives to changes in credit risk of our counterparties.
Item 4. Controls and Procedures
 
Evaluation of Disclosure Controls and Procedures
As of March 31, 2017, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act), is accurate, complete and timely. Our management, including our CEO and our CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our CEO and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of March 31, 2017.
Changes in Internal Control over Financial Reporting
     There were no changes in EP Energy LLC’s internal control over financial reporting during the first three months of 2017 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

28


PART II — OTHER INFORMATION
Item 1. Legal Proceedings
See Part I, Item 1, Financial Statements, Note 7.
Item 1A. Risk Factors
There have been no material changes to the risk factors previously disclosed in the 2016 Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 
None.
Item 3. Defaults Upon Senior Securities 
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
None.
Item 6. Exhibits
 
The Exhibit Index is incorporated herein by reference.
The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and:
should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;
may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and
were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

29


SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. 
 
EP ENERGY LLC
 
 
 
 
Date: May 4, 2017
/s/ Kyle A. McCuen
 
Kyle A. McCuen
 
Vice President, Interim Chief Financial Officer and Treasurer
 
(Principal Financial Officer)
 
 
Date: May 4, 2017
/s/ Francis C. Olmsted III
 
Francis C. Olmsted III
 
Vice President and Chief Accounting Officer
 
(Principal Accounting Officer)

30


EP ENERGY LLC
EXHIBIT INDEX
 
Each exhibit identified below is filed as part of this Report. Exhibits filed with this Report are designated by “*”.  All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
Exhibit
Number
 
Description
 
 
 
#2.1
 
Participation and Development Agreement, dated as of January 24, 2017, by and among EP Energy E&P Company, L.P. and Wolfcamp DrillCo Operating L.P. (Exhibit 2.5 to EP Energy Corporation’s Annual Report on Form 10-K filed with the SEC on March 3, 2017).
 
 
 
2.2
 
Letter Agreement, dated as of January 24, 2017, by and among EP Energy E&P Company, L.P. and Wolfcamp DrillCo Operating L.P. (Exhibit 2.6 to EP Energy Corporation’s Annual Report on Form 10-K filed with the SEC on March 3, 2017).
 
 
 
10.1
 
Consent and Acknowledgement, dated as of February 6, 2017, by Wilmington Trust, National Association, as new Term Facility Agent and Applicable Second Lien Agent, and acknowledged by JPMorgan Chase Bank, N.A., as Applicable First Lien Agent, Citibank, N.A., as prior Term Facility Agent and prior Applicable Second Lien Agent, Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent, and EP Energy LLC, with respect to the Priority Lien Intercreditor Agreement, dated as of August 24, 2016 and supplemented on November 29, 2016 (Exhibit 10.1 to EP Energy Corporation’s Report on Form 8-K, filed with the SEC on February 7, 2017).
 
 
 
10.2
 
Consent and Acknowledgement, dated as of February 6, 2017, by Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent, and acknowledged by JPMorgan Chase Bank, N.A., as Applicable First Lien Agent, Wilmington Savings Fund Society, FSB (as successor to Citibank, N.A.), as Applicable Second Lien Agent, Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent, and EP Energy LLC, with respect to the Amended and Restated Senior Lien Intercreditor Agreement, dated as of August 24, 2016 and supplemented on November 29, 2016 (Exhibit 10.2 to EP Energy Corporation’s Report on Form 8-K, filed with the SEC on February 7, 2017).
 
 
 
10.3
 
Collateral Agreement, dated as of February 6, 2017, by and among EP Energy LLC, the Subsidiaries of EP Energy LLC party thereto and Wilmington Trust, National Association, as collateral agent (Exhibit 10.3 to EP Energy Corporation’s Report on Form 8-K, filed with the SEC on February 7, 2017).
 
 
 
10.4
 
Pledge Agreement, dated as of February 6, 2017, by and among EP Energy LLC, the Subsidiaries of EP Energy LLC party thereto and Wilmington Trust, National Association, as collateral agent (Exhibit 10.4 to EP Energy Corporation’s Report on Form 8-K, filed with the SEC on February 7, 2017).
 
 
 
*12.1
 
Ratio of Earnings to Fixed Charges.
 
 
 
*31.1
 
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
*31.2
 
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
*32.1
 
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
*32.2
 
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
*101.INS
 
XBRL Instance Document.
 
 
 
*101.SCH
 
XBRL Schema Document.
 
 
 
*101.CAL
 
XBRL Calculation Linkbase Document.
 
 
 
*101.DEF
 
XBRL Definition Linkbase Document.
 
 
 
*101.LAB
 
XBRL Labels Linkbase Document.
 
 
 
*101.PRE
 
XBRL Presentation Linkbase Document.
#
Certain exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A list of these exhibits and schedules is included after the table of contents in the Participation and Development Agreement. The Company agrees to furnish a supplemental copy of any such omitted exhibit or schedule to the SEC upon request.