10-Q 1 epenergyllcq22018-10q.htm 10-Q Document

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 Form 10-Q
 
 
(Mark One)
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2018
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 (§232.405 of this chapter) 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, smaller reporting company, or an emerging growth 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”, “plan”, “intend”, “could”, “should”, “project” 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 2017 Annual Report on Form 10-K. There have been no material changes to the risk factors described in the Form 10-K.

1


PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

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

 
Quarter ended 
 June 30,
 
Six months ended 
 June 30,
 
2018
 
2017
 
2018
 
2017
Operating revenues
 

 
 

 
 

 
 

Oil
$
281

 
$
202

 
$
533

 
$
406

Natural gas
18

 
27

 
40

 
57

NGLs
30

 
22

 
56

 
45

Financial derivatives
(64
)
 
45

 
(78
)
 
115

Total operating revenues
265

 
296

 
551

 
623

 
 
 
 
 
 
 
 
Operating expenses
 

 
 

 
 

 
 

Oil and natural gas purchases

 
1

 

 
2

Transportation costs
26

 
28

 
51

 
57

Lease operating expense
38

 
39

 
77

 
79

General and administrative
28

 
26

 
47

 
46

Depreciation, depletion and amortization
129

 
124

 
249

 
250

Impairment charges

 
1

 

 
1

Exploration and other expense

 
1

 
1

 
4

Taxes, other than income taxes
21

 
15

 
41

 
34

Total operating expenses
242

 
235

 
466

 
473

 
 
 
 
 
 
 
 
Operating income
23

 
61

 
85

 
150

Gain (loss) on extinguishment/modification of debt
7

 
13

 
48

 
(40
)
Interest expense
(88
)
 
(82
)
 
(173
)
 
(165
)
Loss before income taxes
(58
)
 
(8
)
 
(40
)
 
(55
)
Income tax expense

 

 

 

Net loss
$
(58
)
 
$
(8
)
 
$
(40
)
 
$
(55
)
 
See accompanying notes.


2


EP ENERGY LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(Unaudited)
 
 
June 30, 2018
 
December 31, 2017
ASSETS
 

 
 

Current assets
 

 
 

Cash and cash equivalents
$
98

 
$
27

Restricted cash
1

 
18

Accounts receivable
 

 
 

Customer, net of allowance of less than $1 in 2018 and 2017
171

 
158

Other, net of allowance of $1 in 2018 and 2017
27

 
13

Materials and supplies
17

 
16

Derivative instruments
6

 
18

Assets held for sale

 
172

Prepaid assets
4

 
35

Total current assets
324

 
457

Property, plant and equipment, at cost
 

 
 

Oil and natural gas properties
8,191

 
7,532

Other property, plant and equipment
65

 
69

 
8,256

 
7,601

Less accumulated depreciation, depletion and amortization
3,424

 
3,179

Total property, plant and equipment, net
4,832

 
4,422

Other assets
 

 
 

Derivative instruments
3

 
4

Unamortized debt issue costs - revolving credit facility
9

 
6

Other
1

 
2

 
13

 
12

Total assets
$
5,169

 
$
4,891

 
See accompanying notes.

3


EP ENERGY LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(Unaudited)
 
 
June 30, 2018
 
December 31, 2017
LIABILITIES AND EQUITY
 

 
 

Current liabilities
 

 
 

Accounts payable
 

 
 

Trade
$
103

 
$
88

Other
160

 
158

Derivative instruments
52

 
17

Accrued interest
69

 
62

Liabilities related to assets held for sale

 
2

Short-term debt, net of debt issue costs
8

 
21

Other accrued liabilities
87

 
100

Total current liabilities
479

 
448

 
 
 
 
Long-term debt, net of debt issue costs
4,291

 
4,022

Other long-term liabilities
 

 
 

Derivative instruments
9

 

Asset retirement obligations
35

 
33

Other
5

 
5

Total non-current liabilities
4,340

 
4,060

 
 
 
 
Commitments and contingencies (Note 7)


 


Member’s equity
350

 
383

Total liabilities and equity
$
5,169

 
$
4,891

 
See accompanying notes.


4


EP ENERGY LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)
 
 
Six months ended 
 June 30,
 
2018
 
2017
Cash flows from operating activities
 

 
 

Net loss
$
(40
)
 
$
(55
)
Adjustments to reconcile net loss to net cash provided by operating activities
 

 
 
Depreciation, depletion and amortization
249

 
250

Impairment charges

 
1

(Gain) loss on extinguishment/modification of debt
(48
)
 
40

Other non-cash income items
13

 
14

Asset and liability changes
 

 
1

Accounts receivable
(28
)
 
(20
)
Accounts payable
(8
)
 
(7
)
Derivative instruments
57

 
(57
)
Accrued interest
7

 
22

Other asset changes
6

 
2

Other liability changes
4

 
(12
)
Net cash provided by operating activities
212

 
178

 
 
 
 
Cash flows from investing activities
 

 
 

Cash paid for capital expenditures
(384
)
 
(266
)
Proceeds from the sale of assets
169

 

Cash paid for acquisitions
(239
)
 

Net cash used in investing activities
(454
)
 
(266
)
 
 
 
 
Cash flows from financing activities
 

 
 

Proceeds from issuance of long-term debt
1,665

 
1,385

Repayments and repurchases of long-term debt
(1,291
)
 
(1,253
)
Fees/costs on debt exchange
(62
)
 

Contributions from parent
4

 
4

Debt issue costs
(20
)
 
(20
)
Net cash provided by financing activities
296

 
116

 
 
 
 
Change in cash, cash equivalents and restricted cash
54

 
28

 
 

 
 
Cash, cash equivalents and restricted cash - beginning of period
45

 
16

Cash, cash equivalents and restricted cash - end of period
$
99

 
$
44

 
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, 2017
$
383

Share-based compensation
3

Cash contributions from parent
4

Net loss
(40
)
Balance at June 30, 2018
$
350

 
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 2017 Annual Report on Form  10-K. The condensed consolidated financial statements as of June 30, 2018 and 2017 are unaudited. The consolidated balance sheet as of December 31, 2017 has been derived from the audited consolidated balance sheet included in our 2017 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
In the first quarter of 2018, we adopted Accounting Standards Update (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. As permitted under ASU No. 2014-09, we elected to utilize the modified retrospective approach, which did not have a material impact on our financial statements. There were no other changes in significant accounting policies as described in the 2017 Annual Report on Form 10-K
New Accounting Pronouncements Issued But Not Yet Adopted
The following accounting standards have been issued but not yet adopted as of June 30, 2018.
Leases.  In February 2016, the Financial Accounting Standards Board (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.

2. Acquisitions and Divestitures

Acquisitions. In the first quarter of 2018, we completed the acquisition of producing properties and undeveloped acreage in Eagle Ford for approximately $246 million, after customary adjustments. Our balance sheet reflects the cost of the assets acquired as proved properties. Of the total purchase price, we paid $221 million upon closing during the first quarter of 2018 and $25 million to the buyer as a deposit in December 2017. Subsequent to June 30, 2018, we completed an acquisition of additional working interests in certain producing properties in Eagle Ford for approximately $31 million, subject to customary post-closing adjustments.

Divestitures. In the first quarter of 2018, we completed the sale of certain assets in the Altamont area for approximately $177 million, after customary adjustments. Of the total sales price, we received a deposit of $18 million (reflected in restricted cash in the balance sheet) in December 2017 and additional cash proceeds of $159 million upon closing. We treated this sale as a normal retirement reflecting the difference between net cash proceeds and the underlying net book value of the assets sold in accumulated depreciation rather than recording a gain on sale of assets. As of December 31, 2017, we classified the assets and liabilities associated with the assets to be sold as held for sale in our consolidated balance sheet.

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.

7


Effective Tax Rate. Interim period income taxes are computed by applying an anticipated annual effective tax rate to year-to-date income or loss, except for significant, unusual or infrequently occurring items, which income tax effects are recorded in the period in which they occur. Changes in tax laws or rates are recorded in the period they are enacted.

For the quarters and six months ended June 30, 2018 and 2017, our effective tax rates were 0%. Our effective tax rates in 2018 and 2017 differed from the statutory rates of 21% and 35%, respectively, primarily as a result of our recognition of a full valuation allowance on our net deferred tax assets. For the quarters ended June 30, 2018 and 2017, we recorded adjustments to the valuation allowance on our net deferred tax assets which offset deferred income tax benefit of $13 million and $2 million, respectively, and offset deferred income tax benefit of $8 million and $17 million for the six months ended June 30, 2018 and 2017, respectively.

Other. During 2017, we recorded a provisional effect of the Tax Cuts and Jobs Act (the Act). While there was no overall impact on our financial statements from the Act, we are still analyzing certain aspects of the Act with available guidance and have no adjustments to the recorded provisional amounts.

We evaluate the realization of our deferred tax assets and record any associated 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 $326 million as of June 30, 2018.

The Company’s and certain subsidiaries’ income tax years after 2013 remain open and subject to examination by both federal and state tax authorities, and in the second quarter of 2018 we were notified of an IRS examination of our parent’s 2016 U.S. tax return.

4. Fair Value Measurements
 
We use various methods to determine the fair values of our financial instruments. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value.  As of June 30, 2018 and December 31, 2017, 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.

The following table presents the carrying amounts and estimated fair values of our financial instruments:
 
 
June 30, 2018
 
December 31, 2017
 
Carrying
 Amount
 
Fair
 Value
 
Carrying
 Amount
 
Fair
 Value
 
(in millions)
Short-term debt
$
8

 
$
8

 
$
21

 
$
19

 
 
 
 
 
 
 
 
Long-term debt (see Note 6)
$
4,395

 
$
3,816

 
$
4,072

 
$
3,248

 
 
 
 
 
 
 
 
Derivative instruments
$
(52
)
 
$
(52
)
 
$
5

 
$
5

 
As of June 30, 2018 and December 31, 2017, 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 June 30, 2018, we had derivative contracts in the form of fixed price swaps, collars and three-way collars on 16 MMBbls of oil (8 MMBbls in 2018 and 8 MMBbls in 2019). In addition to our oil derivatives, we had derivative contracts in the form of fixed price swaps on 20 TBtu of natural gas (13 TBtu in 2018 and 7 TBtu in 2019) and 46 MMGal of ethane and propane fixed price swaps in 2018. As of December 31, 2017, we had derivative contracts for 14 MMBbls of oil, 33 TBtu of natural gas and 92

8


MMGal of ethane and propane. In addition to the contracts above, we have derivative contracts related to locational basis differences on our oil and natural gas production. None of our derivative contracts are designated as accounting hedges.
The following table presents the fair value associated with our derivative financial instruments as of June 30, 2018 and December 31, 2017. 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)
 
 
June 30, 2018
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Derivative instruments
$
37

 
$
(28
)
 
$
6

 
$
3

 
$
(89
)
 
$
28

 
$
(52
)
 
$
(9
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2017
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Derivative instruments
$
33

 
$
(11
)
 
$
18

 
$
4

 
$
(28
)
 
$
11

 
$
(17
)
 
$

For the quarters ended June 30, 2018 and 2017, we recorded a derivative loss of $64 million and a derivative gain of $45 million, respectively. For the six months ended June 30, 2018 and 2017, we recorded a derivative loss of $78 million and a derivative gain of $115 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.
5.  Property, Plant and Equipment
 
Oil and Natural Gas Properties.  As of June 30, 2018 and December 31, 2017, we had approximately $4.8 billion and $4.4 billion, respectively, of total property, plant, and equipment, net of accumulated depreciation, depletion and amortization on our consolidated balance sheets, substantially all of which relates to proved and unproved oil and natural gas properties.
Our capitalized costs related to proved and unproved oil and natural gas properties by area were as follows:
 
 
June 30, 2018
 
December 31, 2017
 
 
(in millions)
Proved
 
 
 
 
    Eagle Ford
 
$
3,734

 
$
3,219

    Permian
 
2,799

 
2,705

    Altamont
 
1,599

 
1,542

        Total Proved
 
8,132

 
7,466

Unproved
 
 
 
 
    Permian
 
59

 
66

Less accumulated depletion
 
(3,384
)
 
(3,137
)
        Net capitalized costs for oil and natural gas properties
 
$
4,807

 
$
4,395

For the quarter ended June 30, 2018, we did not record any amortization of unproved leasehold costs in exploration expense in our consolidated income statement. For the quarter ended June 30, 2017, we recorded approximately $1 million of amortization of unproved leasehold costs in exploration expense in our consolidated income statement. For the six months ended June 30, 2018 and 2017, we recorded less than $1 million and approximately $2 million, respectively, of amortization of unproved leasehold costs. Suspended well costs were not material as of June 30, 2018 or December 31, 2017
We evaluate capitalized costs related to proved properties upon a triggering event (such as a significant continued 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 relative to forward commodity prices and/or potential lease expirations. Commodity price declines may cause changes to our

9


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 percent and 9 percent on a significant portion of our obligations and a projected inflation rate of 2.5 percent. Changes in estimates in the table below 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 June 30, 2018 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability from January 1 through June 30, 2018 were as follows: 
 
2018
 
(in millions)
Net asset retirement liability at January 1
$
35

Accretion expense
1

Changes in estimate
1

Net asset retirement liability at June 30
$
37

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 using a weighted average interest rate on our outstanding borrowings. Capitalized interest for the quarter and six months ended June 30, 2018 was approximately $2 million and $3 million, respectively. Capitalized interest for the quarter and six months ended June 30, 2017 was approximately $1 million and $2 million, respectively.


10


6. Long-Term Debt 
Listed below are our debt obligations as of the periods presented:
 
Interest Rate
 
June 30, 2018
 
December 31, 2017
 
 
 
(in millions)
RBL credit facility - due November 23, 2021(1)
Variable
 
$

 
$
595

Senior secured term loans:
 
 
 
 
 
Due May 24, 2018(2)(3)
Variable
 

 
21

Due April 30, 2019(4)
Variable
 
8

 
8

Senior secured notes:
 
 
 
 
 
Due May 1, 2024
9.375%
 
1,092

 

Due November 29, 2024
8.00%
 
500

 
500

Due February 15, 2025
8.00%
 
1,000

 
1,000

Due May 15, 2026
7.75%
 
1,000

 

Senior unsecured notes:
 
 
 
 
 
Due May 1, 2020
9.375%
 
246

 
1,200

Due September 1, 2022
7.75%
 
195

 
250

Due June 15, 2023
6.375%
 
362

 
519

Total debt
 
 
4,403

 
4,093

     Less short-term debt, net of debt issue costs of less than $1 million
 
 
(8
)
 
(21
)
Total long-term debt
 
 
4,395

 
4,072

Less debt discount and non-current portion of unamortized debt issue costs
 
 
(104
)
 
(50
)
Total long-term debt, net
 
 
$
4,291

 
$
4,022

 
(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 LIBOR of 2.75%, with a minimum LIBOR floor of 0.75%. As of December 31, 2017, the effective
interest rate of the term loan was 4.23%,.
(3)
In April 2018, we retired the term loan in full.
(4)
Carries interest at a specified margin over the LIBOR of 3.50%, with a minimum LIBOR floor of 1.00%.  As of June 30, 2018 and December 31, 2017, the effective interest rate for the term loan was 5.81% and 4.98%, respectively.

     In April 2018, we paid approximately $10 million in cash to repurchase a total of approximately $19 million in aggregate principal amount of our senior unsecured notes due 2022 and 2023. In connection with these repurchases, we recorded a gain on extinguishment of debt of approximately $9 million (including less than $1 million of non-cash expense related to eliminating associated unamortized debt issue costs).

In addition, in May 2018, we issued $1 billion of 7.75% senior secured notes which mature in 2026 and used the proceeds (less fees and expenses) to repay $907 million of the amounts outstanding at that time under our Reserve-Based Loan Facility (RBL Facility). In conjunction with issuing the notes, we also reduced the amount of RBL Facility commitments to $629 million, which resulted in recording a loss of $2 million reflecting the elimination of associated unamortized debt-issue costs.

During the first quarter of 2018, we completed an exchange of $954 million, $54 million and $139 million of the outstanding amount of our senior unsecured notes maturing in May 2020, September 2022 and June 2023, respectively, for new 9.375% senior secured notes maturing in 2024 with an aggregate principal amount of approximately $1,092 million. The exchange transaction was accounted for as a modification of debt for our senior unsecured notes maturing in May 2020 and an extinguishment of debt for our senior unsecured notes maturing in September 2022 and June 2023. In conjunction with the exchange, we incurred approximately $62 million in related fees, of which we (i) recorded $48 million as debt discount primarily reflecting amounts paid to our 2020 noteholders associated with the exchange of our 2020 notes, (ii) capitalized $2 million as debt issuance costs, and (iii) recorded $12 million in loss on modification of debt. In addition, we recorded a gain on extinguishment of debt in the amount of $53 million primarily associated with retiring a portion of our 2022 and 2023 notes at less than face value, net of the write-off of $2 million in previously unamortized debt issue costs.

During the six months ended June 30, 2017, we paid approximately $42 million in cash to repurchase a total of approximately $56 million in 2020 notes which resulted in a gain on extinguishment of debt of approximately $13 million

11


(including $1 million of non-cash expense related to eliminating associated unamortized debt issue costs). In addition, we issued $1 billion of 8.00% senior secured notes maturing in 2025 using the proceeds to repay certain senior secured term loans and notes and repay a portion of the amounts outstanding under our 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 issue costs and debt discounts).

Unamortized Debt Issue Costs and Debt Discounts. As of June 30, 2018, we had total debt discount of $46 million associated with our senior secured notes maturing in 2024 and as of December 31, 2017, we had less than $1 million. As of June 30, 2018 and December 31, 2017, we had total unamortized debt issue costs of $67 million and $56 million, respectively. Of these amounts, $9 million and $6 million, respectively, are associated with our RBL Facility and $58 million and $50 million, respectively, are associated with our senior secured term loans and senior notes. Debt discounts and unamortized debt issue costs associated with our senior secured term loans and senior notes are reflected net of the face value of debt on our consolidated balance sheet.

Reserve-based Loan Facility. We have an RBL Facility which allows us to borrow funds or issue letters of credit (LCs) up to $629 million. The RBL Facility matures in November 2021. As of June 30, 2018, we had $610 million of capacity remaining with approximately $19 million of LCs issued and no amounts outstanding under the RBL 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 January 2018, as a result of our debt exchange, our borrowing base was reduced from $1.4 billion to $1.36 billion.  Subsequently in May 2018, we amended our RBL credit agreement, which extended the RBL Facility maturity date to November 23, 2021, reaffirmed the borrowing base at $1.36 billion and reduced the amount of total available commitments to $629 million. The next scheduled redetermination of the borrowing base will be in October 2018. 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.
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 RBL Facility and our ability to incur additional indebtedness is subject to various financial and non-financial covenants and restrictions. As part of our RBL Facility amendment in May 2018, we (i) extended our first lien debt to EBITDAX financial covenant and reduced the ratio to 2.25 to 1.00 and (ii) included a financial covenant for a current ratio (as defined in the RBL credit agreement) to be not less than 1.00 to 1.00. As of June 30, 2018, we were in compliance with our debt covenants.

Under our various debt agreements, we are limited in our ability to repurchase certain tranches of non-RBL Facility debt. Certain other covenants and restrictions, among other things, also limit or place certain conditions on our ability to incur or guarantee additional indebtedness, make restricted payments, pay dividends on equity interests, redeem, repurchase or retire our parent entities’ equity interests or subordinated indebtedness, sell assets, make investments, create certain liens, prepay debt obligations, engage in certain transactions with affiliates, and enter into certain hedging 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

12


developments could require us to reassess our potential exposure and adjust our accruals accordingly, and these adjustments could be material. As of June 30, 2018, we had approximately $8 million accrued for all outstanding legal matters.
FairfieldNodal v. EP Energy E&P Company, L.P. On March 3, 2014, Fairfield filed suit against one of our subsidiaries in the 157th District Court of Harris County, Texas, claiming we were contractually obligated to pay a transfer fee of approximately $21 million for seismic licensing, triggered by a change in control with the Sponsors’ (affiliates of Apollo Global Management LLC, Riverstone Holdings LLC, Access Industries and Korea National Oil Corporation, collectively, the Sponsors) acquisition of our predecessor entity in 2012. Prior to the change in control, we had unilaterally terminated the seismic licensing agreements, and we returned the applicable seismic data. Fairfield also claimed EP Energy did not properly maintain the confidentiality of the seismic data and interpretations made from it. In April 2015, the district court granted summary judgment to EP Energy, and Fairfield then appealed. On July 6, 2017, an intermediate court of appeals in Texas reversed the judgment related to the transfer fee and denied rehearing on October 5, 2017. We filed a petition for review in the Texas Supreme Court in December 2017. At this time, we are unable to estimate the amount or range of possible loss, if any, on this matter.
Weyerhaeuser Company v. Pardee Minerals LLC, et al. On July 5, 2017, Weyerhaeuser filed suit against one of our subsidiaries, among other defendants, in the United States District Court for the Western District of Louisiana.  Weyerhaeuser seeks to recoup the value of production (approximately $19 million) plus judicial interest (approximately $11 million at this time) from certain wells drilled by EP Energy between 2002 and 2013 on leases Weyerhaeuser claims were invalid.  Weyerhaeuser alleges that lessees prior to EP Energy had not drilled wells in good faith to perpetuate the associated mineral servitude (rights conveyed to produce minerals), rendering EP Energy’s subsequent lease invalid. A trial date has been set for May 13, 2019. At this time, we are unable to estimate the amount or range of possible loss, if any, on this matter.
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 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 June 30, 2018, we had approximately $4 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 June 30, 2018, we had approximately $43 million accrued (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 2017 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.

13


8. Long-Term Incentive Compensation

Our parent’s long-term incentive (LTI) programs consist of restricted stock, stock options and performance shares/units awards. Refer to our 2017 Annual Report on Form 10-K for further description regarding the terms and details of these awards.
 
Restricted Stock. A summary of the changes in our parent’s non-vested restricted shares for the six months ended June 30, 2018 is presented below:
 
 
Number of Shares
 
Weighted Average
Grant Date Fair Value
per Share
Non-vested at December 31, 2017
 
5,283,986

 
$
4.93

Granted
 
6,905,525

 
$
1.94

Vested
 
(1,881,894
)
 
$
5.66

Forfeited
 
(1,125,898
)
 
$
4.62

Non-vested at June 30, 2018
 
9,181,719

 
$
2.57


Performance Share Units. In May 2018, we granted 599,040 PSUs to certain EP Energy employees. The grant date fair value of the 2018 awards was approximately $4 million as determined by a Monte Carlo simulation, utilizing an expected volatility of approximately 90% and a risk free rate of approximately 3%. As of June 30, 2018, we had a total of 1,508,640 PSUs outstanding. PSUs will be earned based upon the achievement of specified stock price goals over a four-year performance period and will vest over a weighted average period of five years. Our PSUs are treated as an equity award with the expense recognized on an accelerated basis over the life of the award.
Performance Unit Awards. Our performance unit awards are based upon achievement of a level of total shareholder return and may be settled in either stock or cash at the election of the Board of Directors of our parent. These awards are treated as a liability award for accounting purposes with the expense recognized on an accelerated basis over the life of the award and fair value remeasured at each reporting period. During the six months ended June 30, 2018, we made no payments in connection with awards that vested and had less than $1 million accrued related to unvested outstanding performance unit awards.
We record compensation expense on all of our parent’s 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 $3 million and $6 million for the quarters ended June 30, 2018 and 2017, respectively, and $4 million and $5 million for the six months ended June 30, 2018 and 2017, respectively. Included in pre-tax compensation expense for the six months ended June 30, 2017 was approximately $7 million of forfeitures recorded during the quarter ended March 31, 2017. As of June 30, 2018, we had unrecognized compensation expense of $34 million.  We will recognize an additional $9 million related to our outstanding awards during the remainder of 2018, $23 million over the remaining requisite service periods subsequent to 2018 and $2 million should a specified capital transaction occur and the right to such amounts become non-forfeitable.

9. Related Party Transactions
    
Joint Venture. In 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 the Permian basin. Subsequently, Access Industries acquired an indirect minority ownership interest in the Investor and therefore is also indirectly responsible for funding a portion of the Investor’s capital commitment. The Investor agreed to fund 60 percent of the estimated drilling, completion and equipping costs in the joint venture wells, divided into two approximately $225 million investment tranches, in exchange for a 50 percent working interest. 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 have substantially completed the planned activity in the first tranche. In April 2018, we amended the drilling joint venture to direct the second tranche investment to the Eagle Ford. The first wells in the second tranche are expected to begin producing in the third quarter of 2018. We are the operator of the joint venture assets.

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. As December 31, 2017, we had no state income tax payable due to our parent.
 

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 2017 Annual Report on Form 10-K. Actual results may differ materially from those contained in any forward-looking statements. Unless otherwise indicated or the context otherwise requires, references in this MD&A section to “we”, “our”, “us” and “the Company” refer to EP Energy LLC and each of its consolidated subsidiaries.
Our Business
 
Overview.  We are an independent exploration and production company engaged in the acquisition and development of unconventional onshore oil and natural gas properties in the United States. We operate through a diverse base of producing assets and are focused on providing returns to our shareholders through the development of our drilling inventory located in three areas:  the Eagle Ford Shale in South Texas, the Permian basin in West Texas, and the Altamont Field in the Uinta basin in Northeastern Utah. 
Our strategy is to invest in opportunities that provide the highest return across our asset base, continually seek out operating and capital efficiencies, effectively manage costs, and identify accretive acquisition opportunities and divestitures, all with the objective of enhancing our portfolio, growing asset value, improving cash flow, increasing financial flexibility and providing an attractive return to our parent’s shareholders. We evaluate opportunities in our portfolio that are aligned with this strategy and our core competencies and that offer a competitive advantage. In addition to opportunities in our current portfolio, strategic acquisitions of leasehold acreage or acquisitions of producing assets allow us to leverage existing expertise in our areas, balance our exposure to regions, basins and commodities, help us to achieve or enhance risk-adjusted returns competitive with those available in our existing programs and increase our reserves. We also continuously evaluate our asset portfolio and will sell oil and natural gas properties if they no longer meet our long-term objectives.
During the first half of 2018, we completed the acquisition of producing properties and undeveloped acreage in Eagle Ford, primarily in La Salle County, for approximately $246 million, after customary closing adjustments. The acquisition represents a 26 percent expansion of our Eagle Ford acreage position at December 31, 2017 or approximately 24,500 net acres. We also completed the sale of certain assets in the Altamont area for approximately $177 million, after customary closing adjustments. The divestiture represents approximately 13 percent of our Altamont acreage position at December 31, 2017, or approximately 23,330 net acres. Subsequent to June 30, 2018, we completed an acquisition of additional working interests in certain producing properties in Eagle Ford for approximately $31 million, subject to customary post-closing adjustments.
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 changes may affect our future capital spending levels, production rates and/or related operating revenues (net of any associated royalties), 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. While prices have generally improved over the past two years, future price declines, along with changes to our future capital spending levels, 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.

15



Derivative Instruments.  Our realized prices from the sale of our oil, natural gas and NGLs are affected by (i) commodity price movements, including locational or basis price differences that exist between the commodity index price (e.g., WTI) and the actual price at which we sell our commodities 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. Adjustments to our strategy and the decision to enter into new contracts or positions to alter existing contracts or positions are made based on the goals of the overall company. Because we apply mark-to-market accounting on our derivative contracts, our reported results of operations and financial position can be impacted significantly by commodity price movements from period to period.
During the six months ended June 30, 2018, we settled commodity index hedges on approximately 88% of our oil production, 77% of our total liquids production and 56% of our natural gas production at average floor prices of $58.48 per barrel of oil, $0.45 per gallon of NGLs and $3.04 per MMBtu of natural gas, respectively.  To the extent our oil, natural gas and NGLs 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 reflects the contracted volumes and the prices we will receive under derivative contracts we held as of June 30, 2018.
 
2018
 
2019
 
Volumes(1)
 
Average
Price(1)
 
Volumes(1)
 
Average
Price(1)
Oil
 

 
 

 
 

 
 

Fixed Price Swaps
 

 
 

 
 

 
 

WTI
2,576

 
$
56.49

 
730

 
$
55.88

Collars
 
 
 
 
 
 
 
Ceiling - WTI
552

 
$
64.98

 
1,275

 
$
65.80

        Floors - WTI
552

 
$
55.00

 
1,275

 
$
55.00

Three Way Collars
 
 
 
 
 
 
 
Ceiling - WTI
4,466

 
$
68.15

 
6,205

 
$
67.77

Floors - WTI
4,466

 
$
60.00

 
6,205

 
$
58.24

Sub-Floor - WTI
4,466

 
$
50.00

 
6,205

 
$
45.00

Basis Swaps
 
 
 
 
 
 
 
LLS vs. WTI(2)
2,576

 
$
2.84

 

 
$

Midland vs. Cushing(3)
1,902

 
$
(1.02
)
 

 
$

NYMEX Roll(4)
1,840

 
$
0.09

 

 
$

Natural Gas
 
 
 
 
 
 
 
Fixed Price Swaps
13

 
$
3.04

 
7

 
$
2.97

Basis Swaps
 
 
 
 
 
 
 
WAHA vs. Henry Hub(5)
7

 
$
(0.46
)
 
7

 
$
(0.39
)
NGLs
 
 
 
 
 
 
 
Fixed Price Swaps - Ethane
31

 
$
0.30

 

 
$

Fixed Price Swaps - Propane
15

 
$
0.75

 

 
$

 
(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)
EP Energy receives WTI plus the basis spread listed and pays LLS.
(3)
EP Energy receives Cushing plus the basis spread listed and pays Midland. These positions do not include 306 MBbls of oil at an average price of $1.06 per barrel of oil, which offset our 2.2 MBbls Midland vs. Cushing basis swaps positions.
(4)
These positions hedge the timing risk associated with our physical sales. We generally sell oil for the delivery month at a sales price based on the average NYMEX WTI
price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month
during the period when the delivery month is prompt (the “trade month roll”).
(5)
EP Energy receives Henry Hub plus the basis spread listed and pays WAHA.

    




16



For the period from July 1, 2018 through August 8, 2018, we entered into additional derivative contracts on 0.4 MMBbls of 2019 WTI oil three-way collars with a ceiling price of $70.85, a floor of $60.00 and sub-floor of $45.00 and 1.1 MMBbls of 2019 Midland vs. Cushing oil basis swaps with an average price of $(6.47) per barrel of oil.

For our three-way collar contracts in the tables above, the sub-floor prices represent the price below which we receive WTI plus a weighted average spread of $10.00 in 2018 and $13.24 in 2019 on the indicated volumes. If WTI is above our sub-floor prices, we receive the noted floor price until WTI exceeds that floor price. Above the floor price, we receive WTI until prices exceed the noted ceiling price in our three-way collars, at which time we receive the fixed ceiling price. As of June 30, 2018, the average forward price of oil was $70.66 per barrel of oil for the remainder of 2018 and $65.36 per barrel of oil for 2019.
     Summary of Liquidity and Capital Resources.  As of June 30, 2018, we had available liquidity of approximately $708 million, reflecting $610 million of available liquidity on our Reserve-Based Loan facility (RBL Facility) borrowing base and $98 million of available cash. Our RBL Facility is our primary source of liquidity beyond our operating cash flow and matures in November of 2021. In the first half of 2018, we took a number of steps to improve our liquidity, expand our financial flexibility and manage our leverage by (i) exchanging approximately $1,147 million of the outstanding amounts of our senior unsecured notes maturing in 2020, 2022 and 2023 for new 9.375% senior secured notes maturing in 2024, (ii) issuing $1 billion of 7.75% senior secured notes, which mature in 2026 and using the net proceeds to repay in full the outstanding amounts at that time under our RBL Facility and (iii) extending the maturity of our RBL Facility from May 2019 to November 2021.
During the first half of 2018, we also (i) completed our largest acquisition to date in the Eagle Ford for approximately $246 million, after customary adjustments, and at the same time (ii) completed the sale of certain assets in Altamont for approximately $177 million after customary adjustments. Subsequent to June 30, 2018, we completed an acquisition of additional working interests in certain producing properties in Eagle Ford for approximately $31 million, subject to customary post-closing adjustments. For a further discussion of our liquidity and capital resources, including factors that could impact our liquidity, see Liquidity and Capital Resources.

17


Production Volumes and Drilling Summary
 
Production Volumes. Below is an analysis of our production volumes for the six months ended June 30:
 
 
2018
 
2017
Equivalent Volumes (MBoe/d)
 

 
 

Eagle Ford Shale
37.6

 
39.6

Permian
26.7

 
26.4

Altamont
17.0

 
17.7

Total
81.3

 
83.7

 
 
 
 
Oil (MBbls/d)
46.3

 
48.0

Natural Gas (MMcf/d)
125

 
126

NGLs (MBbls/d)
14.2

 
14.8

    
Eagle Ford Shale—Our Eagle Ford Shale equivalent volumes decreased 2.0 MBoe/d (approximately 5%) and oil production decreased by 0.3 MBbls/d (approximately 1%) for the six months ended June 30, 2018 compared to the same period in 2017. During the six months ended June 30, 2018, we frac’d (wells fracture stimulated) 41 gross wells, of which 35 wells were completed for a total of 763 net operated wells.
Permian—Our Permian basin equivalent volumes increased 0.3 MBoe/d (approximately 1%) and oil production decreased by 0.8 MBbls/d (approximately 8%) for the six months ended June 30, 2018 compared to the same period in 2017. During the six months ended June 30, 2018, we frac’d 21 gross wells, all of which were completed for a total of 349 net operated wells.
Altamont—Our Altamont equivalent volumes decreased 0.7 MBoe/d (approximately 4%) and oil production decreased by 0.6 MBbls/d (approximately 5%) for the six months ended June 30, 2018 compared to the same period in 2017. During the six months ended June 30, 2018, we frac’d 16 gross wells, all of which were completed for a total of 336 net operated wells. We also recompleted 52 gross wells during 2018.
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 area.

18


Results of Operations
 
The information in the table below provides a summary of our financial results.
 
 
Quarter ended 
 June 30,
 
Six months ended 
 June 30,
 
2018
 
2017
 
2018
 
2017
 
(in millions)
Operating revenues
 

 
 

 
 

 
 

Oil
$
281

 
$
202

 
$
533

 
$
406

Natural gas
18

 
27

 
40

 
57

NGLs
30

 
22

 
56

 
45

Total physical sales
329

 
251

 
629

 
508

Financial derivatives
(64
)
 
45

 
(78
)
 
115

Total operating revenues
265

 
296

 
551

 
623

 
 
 
 
 
 
 
 
Operating expenses
 

 
 

 
 

 
 

Oil and natural gas purchases

 
1

 

 
2

Transportation costs
26

 
28

 
51

 
57

Lease operating expense
38

 
39

 
77

 
79

General and administrative
28

 
26

 
47

 
46

Depreciation, depletion and amortization
129

 
124

 
249

 
250

Impairment charges

 
1

 

 
1

Exploration and other expense

 
1

 
1

 
4

Taxes, other than income taxes
21

 
15

 
41

 
34

Total operating expenses
242

 
235

 
466

 
473

 
 
 
 
 
 
 
 
Operating income
23

 
61

 
85

 
150

Gain (loss) on extinguishment/modification of debt
7

 
13

 
48

 
(40
)
Interest expense
(88
)
 
(82
)
 
(173
)
 
(165
)
Loss before income taxes
(58
)
 
(8
)
 
(40
)
 
(55
)
Income tax expense

 

 

 

Net loss
$
(58
)
 
$
(8
)
 
$
(40
)
 
$
(55
)

19


Operating Revenues
 
The table below provides our operating revenues, volumes and prices per unit for the quarters and six months ended June 30, 2018 and 2017. We present (i) average realized prices based on physical sales of oil, natural gas and NGLs as well as (ii) average realized prices inclusive of the impacts of financial derivative settlements and premiums which reflect cash received or paid during the respective period.
 
Quarter ended 
 June 30,
 
Six months ended 
 June 30,
 
2018
 
2017
 
2018
 
2017
 
(in millions)
Operating revenues:
 

 
 

 
 

 
 

Oil
$
281

 
$
202

 
$
533

 
$
406

Natural gas
18

 
27

 
40

 
57

NGLs
30

 
22

 
56

 
45

Total physical sales
329

 
251

 
629

 
508

Financial derivatives
(64
)
 
45

 
(78
)
 
115

Total operating revenues
$
265

 
$
296

 
$
551

 
$
623

 
 
 
 
 
 
 
 
Volumes:
 

 
 

 
 

 
 

Oil (MBbls)
4,299

 
4,452

 
8,386

 
8,671

Natural gas (MMcf)
11,274

 
11,353

 
22,609

 
22,818

NGLs (MBbls)
1,334

 
1,386

 
2,566

 
2,682

Equivalent volumes (MBoe)
7,512

 
7,730

 
14,720

 
15,156

Total MBoe/d
82.5

 
84.9

 
81.3

 
83.7

 
 
 
 
 
 
 
 
Prices per unit(1):
 

 
 

 
 

 
 

Oil
 

 
 

 
 

 
 

Average realized price on physical sales ($/Bbl)(2) 
$
65.53

 
$
45.27

 
$
63.60

 
$
46.81

Average realized price, including financial derivatives ($/Bbl)(2)(3)
$
62.30

 
$
51.83

 
$
60.62

 
$
53.33

Natural gas
 
 
 
 
 

 
 
Average realized price on physical sales ($/Mcf)(2)
$
1.58

 
$
2.40

 
$
1.76

 
$
2.45

Average realized price, including financial derivatives ($/Mcf)(2)(3)
$
1.96

 
$
2.49

 
$
2.00

 
$
2.48

NGLs
 
 
 
 
 

 
 
Average realized price on physical sales ($/Bbl)
$
22.65

 
$
16.00

 
$
21.82

 
$
16.79

Average realized price, including financial derivatives ($/Bbl)(3) 
$
22.07

 
$
16.56

 
$
21.51

 
$
17.14

 
(1)
For both of the quarters and six months ended June 30, 2018 and 2017, there were no oil purchases associated with managing our physical oil sales. Natural gas prices for both of the quarter and six months ended June 30, 2018 reflect operating revenues for natural gas reduced by less than $1 million for natural gas purchases associated with managing our physical sales. Natural gas prices for the quarter and six months ended June 30, 2017 reflect operating revenues for natural gas reduced by approximately $1 million and $2 million, respectively, for natural gas purchases associated with managing our physical sales.
(2)
Changes in realized oil and natural gas prices reflect the effects of unhedged locational or basis differentials, unhedged volumes and contractual deductions between the commodity price index and the actual price at which we sold our oil and natural gas.
(3)
The quarters ended June 30, 2018 and 2017, include cash paid of approximately $14 million and cash received of approximately $30 million, respectively, for the settlement of crude oil derivative contracts and approximately $4 million and $1 million of cash received, respectively, for the settlement of natural gas financial derivatives. The six months ended June 30, 2018 and 2017, include cash paid of approximately $25 million and cash received of approximately $57 million, respectively, for the settlement of crude oil derivative contracts and approximately $5 million and $1 million of cash received, respectively, for the settlement of natural gas financial derivatives. The quarters ended June 30, 2018 and 2017 also include cash paid of approximately $1 million and cash received of less than $1 million, respectively, for the settlement of NGLs derivative contracts. The six months ended June 30, 2018 and 2017, include cash paid of approximately $1 million and cash received of approximately $1 million, respectively, for the settlement of NGLs derivative contracts.








20


Physical sales.  Physical sales represent accrual-based commodity sales transactions with customers. For the quarter and six months ended June 30, 2018, physical sales increased by $78 million (31%) and $121 million (24%), respectively, compared to the same periods in 2017. The table below displays the price and volume variances on our physical sales when comparing the quarter and six months ended June 30, 2018 and 2017
 
Quarter ended
 
Oil
 
Natural gas
 
NGLs
 
Total
 
(in millions)
June 30, 2017 sales
$
202

 
$
27

 
$
22

 
$
251

Change due to prices
86

 
(9
)
 
9

 
86

Change due to volumes
(7
)
 

 
(1
)
 
(8
)
June 30, 2018 sales
$
281

 
$
18

 
$
30

 
$
329

 
Six months ended
 
Oil
 
Natural gas
 
NGLs
 
Total
 
(in millions)
June 30, 2017 sales
$
406

 
$
57

 
$
45

 
$
508

Change due to prices
140

 
(17
)
 
13

 
136

Change due to volumes
(13
)
 

 
(2
)
 
(15
)
June 30, 2018 sales
$
533

 
$
40

 
$
56

 
$
629

Oil sales for the quarter and six months ended June 30, 2018, compared to the same periods in 2017, increased by $79 million (39%) and $127 million (31%), respectively, due primarily to higher oil prices in all areas, partially offset by slightly lower oil production overall.
Natural gas sales decreased by $9 million (33%) and $17 million (30%) for the quarter and six months ended June 30, 2018, respectively, compared to the same periods in 2017 primarily due to lower natural gas prices.
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 largely sold at prices tied to benchmark LLS crude oil, with the addition of Brent-based pricing in June 2018.  In the Permian, 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 a locational difference at the wellhead.  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 June 30,
 
2018
 
2017
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
Differentials and deducts
$
(2.27
)
 
$
(1.10
)
 
$
(3.16
)
 
$
(0.79
)
NYMEX
$
67.88

 
$
2.80

 
$
48.29

 
$
3.19

Net back realization %
96.7
%
 
60.7
%
 
93.5
%
 
75.2
%


21


 
Six months ended June 30,
 
2018
 
2017
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
Differentials and deducts
$
(1.67
)
 
$
(1.07
)
 
$
(3.52
)
 
$
(0.80
)
NYMEX
$
65.37

 
$
2.90

 
$
50.10

 
$
3.25

Net back realization %
97.4
%
 
63.1
%
 
93.0
%
 
75.4
%

The higher oil realization percentage in the quarter and six months ended June 30, 2018 was primarily a result of the improvement of both physical sales contracts in Eagle Ford and NYMEX pricing, which increased our realized prices that are based on a fixed percentage of NYMEX. The lower natural gas realization percentage in the quarter and six months ended June 30, 2018 was primarily a result of presenting certain transportation costs as a deduction from natural gas sales in conjunction with adopting Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers in the first quarter of 2018.
NGLs sales increased by $8 million (36%) and $11 million (24%) for the quarter and six months ended June 30, 2018, respectively, compared with the same periods in 2017. Average realized prices for the quarter and six months ended June 30, 2018 were higher compared to the same periods in 2017, due to higher pricing on all liquids components. NGLs pricing is largely tied to crude oil prices.
Future growth in our overall oil, natural gas and NGLs sales (including the impact of financial derivatives) will largely be impacted by commodity prices, our level of hedging, our ability to maintain or grow oil volumes and by the location of our 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 June 30, 2018, we recorded $64 million of derivative losses compared to a derivative gain of $45 million during the quarter ended June 30, 2017. For the six months ended June 30, 2018, we recorded $78 million of derivative losses compared to a derivative gain of $115 million during the six months ended June 30, 2017.
Operating Expenses
The table below provides our operating expenses, volumes and operating expenses per unit for each of the periods presented:
 
Quarter ended June 30,
 
2018
 
2017
 
Total
 
Per Unit(1)
 
Total
 
Per Unit(1)
 
(in millions, except per unit costs)
Operating expenses
 
 
 
 
 
 
 
Oil and natural gas purchases
$

 
$

 
$
1

 
$
0.09

Transportation costs
26

 
3.49

 
28

 
3.66

Lease operating expense
38

 
4.95

 
39

 
5.07

General and administrative(2)
28

 
3.74

 
26

 
3.43

Depreciation, depletion and amortization
129

 
17.20

 
124

 
15.99

Impairment charges

 

 
1

 
0.05

Exploration and other expense

 

 
1

 
0.20

Taxes, other than income taxes
21

 
2.82

 
15

 
1.97

Total operating expenses
$
242

 
$
32.20

 
$
235

 
$
30.46

 
 
 
 

 
 
 
 

Total equivalent volumes (MBoe)
7,512

 
 
 
7,730

 
 


22


 
Six months ended June 30,
 
2018
 
2017
 
Total
 
Per Unit(1)
 
Total
 
Per Unit(1)
 
(in millions, except per unit costs)
Operating expenses
 
 
 
 
 
 
 
Oil and natural gas purchases
$

 
$

 
$
2

 
$
0.12

Transportation costs
51

 
3.46

 
57

 
3.75

Lease operating expense
77

 
5.21

 
79

 
5.21

General and administrative(2)
47

 
3.17

 
46

 
3.05

Depreciation, depletion and amortization
249

 
16.95

 
250

 
16.48

Impairment charges

 

 
1

 
0.04

Exploration and other expense
1

 
0.09

 
4

 
0.29

Taxes, other than income taxes
41

 
2.78

 
34

 
2.28

Total operating expenses
$
466

 
$
31.66

 
$
473

 
$
31.22

 
 
 
 
 
 
 
 
Total equivalent volumes (MBoe)
14,720

 
 
 
15,156

 
 

 
(1)
Per unit costs are based on actual amounts rather than the rounded totals presented.
(2)
For the quarter and six months ended June 30, 2018, amount includes approximately $2 million or $0.38 per Boe and $4 million or $0.30 per Boe, respectively, of non-cash compensation expense. The quarter and six months ended June 30, 2018 also include approximately $6 million or $0.77 per Boe and $6 million or $0.40 per Boe, respectively, of transition and severance costs related to workforce reductions. For the quarter and six months ended June 30, 2017, amount includes approximately $6 million or $0.80 per Boe and $2 million or $0.14 per Boe, respectively, of non-cash compensation expense.

Transportation costs.  Transportation costs for the quarter and six months ended June 30, 2018 decreased by $2 million and $6 million, respectively, compared to the same periods in 2017 as a result of presenting certain transportation costs as a deduction from natural gas sales in conjunction with adopting ASU No. 2014-09, Revenue from Contracts with Customers in the first quarter of 2018.
Lease operating expense.  Lease operating expense decreased by $1 million and $2 million for the quarter and six months ended June 30, 2018, respectively, compared to the same periods in 2017. The decrease for the quarter ended June 30, 2018 compared to 2017 is due to lower maintenance and repair costs in all areas, partially offset by higher compression, disposal and chemical costs in the Permian and Eagle Ford. The decrease for the six months ended June 30, 2018 compared to the same period in 2017 is due to lower maintenance and repair costs in Altamont and Eagle Ford, partially offset by higher compression and disposal costs in Eagle Ford and higher chemical and disposal costs in the Permian.
General and administrative expenses.  General and administrative expenses for the quarter and six months ended June 30, 2018 increased by $2 million and $1 million, respectively, compared to the same periods in 2017. Higher costs during the quarter and six months ended June 30, 2018 compared to the same periods in 2017 were primarily due to higher severance expense of $6 million in both periods in 2018, partially offset by lower payroll costs as a result of a reduction in headcount in 2018 when compared to the same periods in 2017.
Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense increased for the quarter ended June 30, 2018 and decreased for the six months ended June 30, 2018 due to increased capital spending and slightly lower production volumes when compared to the same periods in 2017. Our depreciation, depletion and amortization rate in the future will be impacted by the level, the location, and timing of capital spending, the overall cost of capital and the level and type of reserves recorded on completed projects. Our average depreciation, depletion and amortization costs per unit for the quarter and six months ended June 30 were:
 
Quarter ended 
 June 30,
 
Six months ended 
 June 30,
 
2018
 
2017
 
2018
 
2017
Depreciation, depletion and amortization ($/Boe)
$
17.20

 
$
15.99

 
$
16.95

 
$
16.48

Taxes, other than income taxes. Taxes, other than income taxes for the quarter and six months ended June 30, 2018 increased by $6 million and $7 million, respectively, compared to the same periods in 2017 primarily due to an increase in severance taxes as a result of higher commodity prices.

23



Other Income Statement Items.
Gain (loss) on extinguishment/modification of debt. During the quarter ended June 30, 2018, we recorded a gain on extinguishment of debt of approximately $9 million as a result of our repurchase of approximately $19 million in aggregate principal amount of our senior unsecured notes. In addition, we recorded a loss of $2 million reflecting eliminating associated unamortized debt-issue costs as a result of amending our RBL credit agreement. During the six months ended June 30, 2018, we also completed an exchange of $1,147 million in amounts outstanding under certain senior unsecured notes for approximately $1,092 in new senior secured notes. In conjunction with the exchange, we recorded a net gain on the extinguishment of debt of approximately $41 million ($2 million of which was non-cash) as further discussed in Part I, Item 1, Financial Statements, Note 7.

For the quarter and six months ended June 30, 2017, we paid approximately $42 million in cash to repurchase approximately $56 million in aggregate principal amount of our senior unsecured notes due 2020. We recorded a gain on extinguishment of debt of approximately $13 million (including $1 million in non-cash expense related to eliminating associated unamortized debt issue costs). In addition, during the six months ended June 30, 2017, we retired our senior secured term loans due 2021 and a portion of our 9.375% senior notes due 2020, recording 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).
    
Interest expense. Interest expense for the quarter and six months ended June 30, 2018 increased by $6 million and $8 million, respectively, compared to the same periods in 2017 due primarily to higher average borrowings under our RBL Facility in 2018.

Income taxes. For the quarters and six months ended June 30, 2018 and 2017, our effective tax rates were 0%. Our effective tax rates in 2018 and 2017 differed from the statutory rates of 21% and 35%, respectively, as a result of our recognition of a full valuation allowance on our net deferred tax assets. For the quarters ended June 30, 2018 and 2017, we recorded adjustments to the valuation allowance on our net deferred tax assets, which offset deferred income tax benefit of $13 million and $2 million, respectively, and offset deferred income tax benefit of $8 million and $17 million for the six months ended June 30, 2018 and 2017, respectively.



24


Supplemental Non-GAAP Measures
 
We use the non-GAAP measures “EBITDAX” and “Adjusted EBITDAX” as supplemental measures. We believe these supplemental measures provide meaningful information to our investors. We define EBITDAX as net income (loss) plus interest and debt expense, income taxes, depreciation, depletion and amortization and exploration expense. Adjusted EBITDAX is defined as EBITDAX, adjusted as applicable in the relevant period for the net change in the fair value of derivatives (mark-to-market effects of financial derivatives, net of cash settlements and cash premiums related to these derivatives), the non-cash portion of compensation expense (which represents non-cash compensation expense under long-term incentive programs adjusted for cash payments made under these plans), transition, severance and other costs that affect comparability, gains and losses on extinguishment/modification of debt and impairment charges.
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 
 June 30,
 
Six months ended 
 June 30,
 
2018
 
2017
 
2018
 
2017
 
(in millions)
Net loss
$
(58
)
 
$
(8
)
 
$
(40
)
 
$
(55
)
Income tax expense

 

 

 

Interest expense, net of capitalized interest
88

 
82

 
173

 
165

Depreciation, depletion and amortization
129

 
124

 
249

 
250

Exploration expense
1

 
1

 
2

 
4

EBITDAX
160

 
199

 
384

 
364

Mark-to-market on financial derivatives(1)
64

 
(45
)
 
78

 
(115
)
Cash settlements and cash premiums on financial derivatives(2)
(10
)
 
31

 
(20
)
 
59

Non-cash portion of compensation expense(3)
2

 
6

 
4

 
2

Transition, severance and other costs(4)
6

 

 
6

 

(Gain) loss on extinguishment/modification of debt
(7
)
 
(13
)
 
(48
)
 
40

Impairment charges

 
1

 

 
1

Adjusted EBITDAX
$
215

 
$
179

 
$
404

 
$
351

 
(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 and six months ended June 30, 2018 and 2017.
(3)
There were no cash payments for the quarters ended June 30, 2018 and 2017 and none for the six months ended June 30, 2018. For the six months ended June 30, 2017, cash payments were approximately $4 million.
(4)
Reflects transition and severance costs related to workforce reductions.





25


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 $708 million as of June 30, 2018.
From a liquidity standpoint, our near-term strategic goal is to work towards cash flow neutrality by focusing on operating and capital efficiency, reducing cash costs and identifying accretive acquisition opportunities and divestitures while maintaining financial flexibility and managing our leverage. Our longer-term goal is to improve our cash flow to enhance our portfolio, grow our asset value and generate positive total returns for our shareholders. In 2018, we continued to take steps to improve our liquidity, expand our financial flexibility, and manage our leverage. These actions included (i) exchanging $954 million, $54 million and $139 million of the outstanding amount of our senior unsecured notes maturing in May 2020, September 2022 and June 2023, respectively, for new 9.375% senior secured notes maturing in 2024 with an aggregate principal amount of approximately $1,092 million, (ii) issuing $1 billion of 7.75% senior secured notes, which mature in 2026 and using the net proceeds to repay in full the outstanding amounts at that time under our RBL Facility and (iii) extending the maturity of our RBL Facility from May 2019 to November 2021.

Availability of borrowings under our RBL Facility is an important source of liquidity for us. In May 2018, we amended our RBL credit agreement which extended our RBL Facility maturity date to November 23, 2021, reaffirmed the borrowing base at $1.36 billion and reduced the amount of total available commitments to $629 million. The next scheduled redetermination of the borrowing base will be in October 2018. 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, 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. Conversely, future acquisitions, reserve additions and higher commodity prices may have the effect of increasing our borrowing base.

As part of amending our RBL credit agreement in May 2018, we (i) extended our first lien debt to EBITDAX financial covenant and reduced the ratio to 2.25 to 1.00 and (ii) included a financial covenant for a current ratio (as defined in the RBL credit agreement) to be not less than 1.00 to 1.00. Under our various debt agreements, we are also limited in our ability to repurchase certain tranches of non-RBL Facility debt. As of June 30, 2018, we were in compliance with our debt covenants.

During the first half of 2018, we entered into transactions to enhance capital efficiency and pursue acquisitions while doing so in a cash or leverage enhancing manner, including (i) the completion of our largest acquisition to date for approximately $246 million, after customary adjustments, in the Eagle Ford while at the same time (ii) completing the sale of certain assets in Altamont for approximately $177 million after customary closing adjustments. Subsequent to June 30, 2018, we completed an acquisition of additional working interests in certain producing properties in Eagle Ford for approximately $31 million, subject to customary post-closing adjustments.

To protect our cash flows and preserve our liquidity, we enter into derivative contracts on a substantial portion of our anticipated future production volumes. As of June 30, 2018, we have derivative contracts (swaps, collars and three-way collars) on 8 MMBbls and 8 MMBbls of our anticipated oil production at a weighted average price of $58.45 and $57.52 per barrel of oil for 2018 and 2019, respectively. Approximately 80% of these crude oil contracts will also allow for upside participation (to a weighted average price of approximately $63.96 per barrel for 2018 and $66.41 for 2019). Additionally, our 2018 and 2019 three-way collar contracts contain certain sub-floor prices (weighted average prices of $50 and $45 per barrel) that limit the amount of our derivative settlements under these three-way contracts should prices drop below the sub-floor prices. For 2018 and 2019, we also have derivative swap contracts on 13 TBtu and 7 TBtu of our anticipated natural gas production at a weighted average price of $3.04 and $2.97 per MMBtu, respectively. As of June 30, 2018 based on the mid-point of our forecasted 2018 guidance, our oil and natural gas derivative contracts provide price protection on approximately 90% and 56%, respectively, of our anticipated 2018 oil and natural gas production. Refer to Our Business for more detailed information on our derivative instruments.

For 2018, we expect to spend approximately $630 million to $670 million in capital (not including acquisition capital) in our programs. Based upon our current price and cost assumptions and our hedge program, we believe that our current capital program will exceed our estimated operating cash flows after interest payments. We believe the borrowing capacity under our RBL Facility together with expected cash flows from our operations, including cash flows generated by our recent Eagle Ford

26


acquisition, 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 providers, deferring and eliminating various discretionary costs, and/or reducing the number of staff and contractors, if necessary.
Should commodity prices decline significantly from current levels, 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 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 debt agreements 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 six months ended June 30, 2018 were:
 
Capital
Expenditures(1)
(in millions)
 
Average Drilling
 Rigs
Eagle Ford Shale
$
257

 
3.0

Permian
91

 
0.6

Altamont
63

 
2.0

Total
$
411

 
5.6

Acquisition capital(2)
$
264

 
 
Total Capital Expenditures
$
675

 
 
 
(1)
Represents accrual-based capital expenditures.
(2)
Includes a deposit made in December 2017.

Debt. As of June 30, 2018, our total debt was approximately $4.4 billion, comprised of $8 million in senior secured term loans maturing in 2019, $803 million in senior unsecured notes due in 2020, 2022 and 2023, and $3.6 billion in senior secured notes due in 2024, 2025 and 2026. 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.    

27


Overview of Cash Flow Activities.  Our cash flows are summarized as follows (in millions):
 
Six months ended 
 June 30,
 
2018
 
2017
Cash Inflows
 

 
 

Operating activities
 

 
 

Net loss
$
(40
)
 
$
(55
)
(Gain) loss on extinguishment/modification of debt
(48
)
 
40

Other income adjustments
262

 
264

Changes in assets and liabilities
38

 
(72
)
Total cash flow from operations
212

 
178

 
 
 
 
 
 

 
 

Investing activities
 

 
 

Proceeds from the sale of assets
169

 

 Cash inflows from investing activities
169

 

 
 
 
 
Financing activities
 
 
 
Proceeds from issuance of long-term debt
1,665

 
1,385

Contributions from parent
4

 
4

 Cash inflows from financing activities
1,669

 
1,389

 
 
 
 
Total cash inflows
$
2,050

 
$
1,567

 
 
 
 
Cash Outflows
 

 
 

Investing activities
 
 
 

Capital expenditures
$
384

 
$
266

Cash paid for acquisitions
239

 

Cash outflows from investing activities
623

 
266

 
 
 
 
Financing activities
 

 
 

Repayments and repurchases of long-term debt
1,291

 
1,253

Fees/costs on debt exchange
62

 

Debt issue costs
20

 
20

Cash outflows from financing activities
1,373

 
1,273

 
 
 
 
Total cash outflows
$
1,996

 
$
1,539

 
 
 
 
Net change in cash, cash equivalents and restricted cash
$
54

 
$
28


28


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 June 30, 2018, for each of the periods presented: