Company Quick10K Filing
Quick10K
EP Energy
10-Q 2019-06-30 Quarter: 2019-06-30
10-Q 2019-06-30 Quarter: 2019-06-30
10-Q 2019-03-31 Quarter: 2019-03-31
10-Q 2019-03-31 Quarter: 2019-03-31
10-K 2018-12-31 Annual: 2018-12-31
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2019-10-03 Bankruptcy, Off-BS Arrangement, Regulation FD, Exhibits
8-K 2019-09-18 Enter Agreement
8-K 2019-09-14 Enter Agreement, Exhibits
8-K 2019-09-03 Regulation FD
8-K 2019-08-15 Regulation FD
8-K 2019-08-09 Earnings, Exhibits
8-K 2019-05-29 Officers
8-K 2019-05-23 Regulation FD, Exhibits
8-K 2019-05-08 Earnings, Exhibits
8-K 2019-04-29 Officers
8-K 2019-03-25 Officers
8-K 2019-03-14 Earnings, Regulation FD, Exhibits
8-K 2019-02-28 Officers
8-K 2019-01-03 Regulation FD, Exhibits
8-K 2018-12-05 Officers
8-K 2018-11-07 Earnings, Exhibits
8-K 2018-09-04 Regulation FD, Exhibits
8-K 2018-08-10 Regulation FD, Exhibits
8-K 2018-08-09 Earnings, Exhibits
8-K 2018-05-23 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-05-18 Regulation FD, Exhibits
8-K 2018-05-17 Regulation FD, Exhibits
8-K 2018-05-09 Regulation FD, Exhibits
8-K 2018-05-08 Earnings, Exhibits
8-K 2018-04-27 Enter Agreement, Exhibits
8-K 2018-02-28 Earnings, Regulation FD, Exhibits
8-K 2018-01-26 Officers
8-K 2018-01-23 Regulation FD, Exhibits
8-K 2018-01-22 Earnings, Regulation FD, Exhibits
8-K 2018-01-03 Enter Agreement, Off-BS Arrangement, Exhibits
FANG Diamondback Energy 15,397
CHK Chesapeake Energy 2,516
GPRK Geopark 1,021
LPI Laredo Petroleum 587
CRC California Resources 499
ISRL Isramco 327
DWSN Dawson Geophysical 47
CEI Camber Energy 3
PTR PetroChina 0
SSL Sasol 0
EPE 2019-06-30
Part I - Financial Information
Item 1. Financial Statements
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Qualitative and Quantitative Disclosures About Market Risk
Item 4. Controls and Procedures
Part II - Other Information
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 3. Defaults Upon Senior Securities
Item 4. Mine Safety Disclosures
Item 5. Other Information
Item 6. Exhibits
EX-31.1 exhibit311q22019epellc.htm
EX-31.2 exhibit312q22019epellc.htm
EX-32.1 exhibit321q22019epellc.htm
EX-32.2 exhibit322q22019epellc.htm

EP Energy Earnings 2019-06-30

EPE 10Q Quarterly Report

Balance SheetIncome StatementCash Flow

10-Q 1 epenergyllcq22019-10q.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, 2019
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 every Interactive Data File required to be submitted 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 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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” a “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 x
 
 
 
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
Securities registered pursuant to Section 12(b) of the Act: None
 



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
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
 
This report contains forward-looking statements that involve risks and uncertainties, many of which are beyond our control. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from the actual results and such variances can be material. Where we express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur. The words “believe”, “expect”, “estimate”, “anticipate”, "plan", “intend”, "could" and “should” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements are expressly qualified by these and the other cautionary statements in this Quarterly Report on Form 10-Q, including those set forth in Item 1A, "Risk Factors". Important factors that could cause our actual results to differ materially from the expectations reflected in our forward-looking statements include, among others:
the volatility of and potential for sustained low oil, natural gas, and NGLs prices;

the supply and demand for oil, natural gas and NGLs;

changes in commodity prices and basis differentials for oil and natural gas;

our ability to meet production volume targets;

the uncertainty of estimating proved reserves and unproved resources;

our ability to develop proved undeveloped reserves;

the future level of operating and capital costs;

the availability and cost of financing to fund future exploration and production operations;

the success of drilling programs with regard to proved undeveloped reserves and unproved resources;

our ability to comply with the covenants in various financing documents, including making principal and
interest payments or to obtain any necessary consents, waivers or forbearances thereunder;

our ability to generate sufficient cash flow to meet our debt obligations and commitments;

the possibility that we may not be able to continue as a going concern if we are not successful in obtaining
the necessary additional liquidity, refinancing any of our indebtedness on commercially reasonable terms or at all, executing on our strategic alternatives and/or if there is not a sustained, significant increase in commodity prices;

our limited ability to borrow under existing debt agreements to fund our operations;

our ability to obtain necessary governmental approvals for proposed exploration and production projects and
to successfully construct and operate such projects;

actions by credit rating agencies, including potential downgrades;

credit and performance risks of our lenders, trading counterparties, customers, vendors, suppliers and third
party operators;

general economic and weather conditions in geographic regions or markets we serve, or where operations are
located, including the risk of a global recession and negative impact on demand for oil and/or natural gas;

the uncertainties associated with governmental regulation, including any potential changes in federal and
state tax laws and regulations;

competition; and


1


the other factors described under Item 1A, “Risk Factors,” of our 2018 Annual Report on Form 10-K, the
additional factors described under Item 1A, “Risk Factors”, of this Quarterly Report on Form 10-Q, and any updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by these forward-looking statements may not occur, and, if any of such events do occur, we may not have anticipated the timing of their occurrence or the extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of these forward-looking statements. These forward-looking statements speak only as of the date made, and we undertake no obligation, other than as required by applicable law, to update or revise any forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.


2


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,
 
2019
 
2018
 
2019
 
2018
Operating revenues
 

 
 

 
 

 
 

Oil
$
204

 
$
281

 
$
397

 
$
533

Natural gas
8

 
18

 
26

 
40

NGLs
15

 
30

 
33

 
56

Financial derivatives
29

 
(64
)
 
(66
)
 
(78
)
Total operating revenues
256

 
265

 
390

 
551

 
 
 
 
 
 
 
 
Operating expenses
 

 
 

 
 

 
 

Transportation costs
23

 
26

 
48

 
51

Lease operating expense
30

 
38

 
67

 
77

General and administrative
43

 
28

 
64

 
47

Depreciation, depletion and amortization
94

 
129

 
188

 
249

Exploration and other expense
1

 

 
2

 
1

Taxes, other than income taxes
20

 
21

 
31

 
41

Total operating expenses
211

 
242

 
400

 
466

 
 
 
 
 
 
 
 
Operating income (loss)
45

 
23

 
(10
)
 
85

Gain on extinguishment/modification of debt

 
7

 
10

 
48

Interest expense
(95
)
 
(88
)
 
(190
)
 
(173
)
Loss before income taxes
(50
)
 
(58
)
 
(190
)
 
(40
)
Income tax expense

 

 

 

Net loss
$
(50
)
 
$
(58
)
 
$
(190
)
 
$
(40
)
 
See accompanying notes.


3


EP ENERGY LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(Unaudited)
 
 
June 30, 2019
 
December 31, 2018
ASSETS
 

 
 

Current assets
 

 
 

Cash and cash equivalents
$
52

 
$
27

Accounts receivable
 

 
 

Customer, net of allowance of less than $1 in 2019 and 2018
115

 
164

Other, net of allowance of $1 in 2019 and 2018
11

 
66

Materials and supplies
28

 
22

Derivative instruments
24

 
101

Other
31

 
5

Total current assets
261

 
385

Property, plant and equipment, at cost
 

 
 

Oil and natural gas properties
7,625

 
7,344

Other property, plant and equipment
76

 
81

 
7,701

 
7,425

Less accumulated depreciation, depletion and amortization
3,813

 
3,651

Total property, plant and equipment, net
3,888

 
3,774

Other assets
 

 
 

Derivative instruments
10

 
13

Unamortized debt issue costs - revolving credit facility
6

 
8

Operating lease assets and other
25

 
1

 
41

 
22

Total assets
$
4,190

 
$
4,181

 
See accompanying notes.

4


EP ENERGY LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(Unaudited)
 
 
June 30, 2019
 
December 31, 2018
LIABILITIES AND EQUITY
 

 
 

Current liabilities
 

 
 

Current maturities of long-term debt, net of debt issue costs
$
182

 
$
58

 Owner and royalties payable
75

 
144

 Accounts payable and accrued expenses
154

 
105

Accrued interest
69

 
70

 Accrued legal and other reserves
44

 
47

Other accrued liabilities
21

 
16

Total current liabilities
545

 
440

 
 
 
 
Long-term debt, net of debt issue costs
4,365

 
4,285

Other long-term liabilities
 

 
 

Asset retirement obligations
41

 
39

      Lease obligations and other
24

 
16

Total non-current liabilities
4,430

 
4,340

 
 
 
 
Commitments and contingencies (Note 6)


 


Member’s equity
(785
)
 
(599
)
Total liabilities and equity
$
4,190

 
$
4,181

 
See accompanying notes.


5


EP ENERGY LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)
 
 
Six months ended
June 30,
 
2019
 
2018
Cash flows from operating activities
 

 
 

Net loss
$
(190
)
 
$
(40
)
Adjustments to reconcile net loss to net cash provided by operating activities
 

 
 
Depreciation, depletion and amortization
188

 
249

Gain on extinguishment/modification of debt
(10
)
 
(48
)
Other non-cash income items
14

 
13

Asset and liability changes
 

 
1

Accounts receivable
103

 
(28
)
      Owner and royalties payable
(68
)
 
5

      Accounts payable and accrued expenses
12

 
(22
)
Derivative instruments
80

 
57

Accrued interest
(1
)
 
7

Other asset changes
(32
)
 
6

Other liability changes
(12
)
 
13

Net cash provided by operating activities
84

 
212

 
 
 
 
Cash flows from investing activities
 

 
 

Cash paid for capital expenditures
(249
)
 
(384
)
Proceeds from the sale of assets

 
169

Cash paid for acquisitions
(15
)
 
(239
)
Net cash used in investing activities
(264
)
 
(454
)
 
 
 
 
Cash flows from financing activities
 

 
 

Proceeds from issuance of long-term debt
615

 
1,665

Repayments and repurchases of long-term debt
(408
)
 
(1,291
)
Fees/costs on debt exchange

 
(62
)
Contributions from parent

 
4

Debt issue costs

 
(20
)
Other
(2
)
 

Net cash provided by financing activities
205

 
296

 
 
 
 
Change in cash, cash equivalents and restricted cash
25

 
54

 
 

 
 
Cash, cash equivalents and restricted cash - beginning of period
27

 
45

Cash, cash equivalents and restricted cash - end of period
$
52

 
$
99

 
See accompanying notes.


6


EP ENERGY LLC
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(In millions)
(Unaudited)
 
 
Total Member’s
Equity
Balance at December 31, 2017
$
383

Cash contributions from parent
4

Net income
18

Balance at March 31, 2018
$
405

Share-based compensation
3

Net loss
(58
)
Balance at June 30, 2018
$
350

Share-based compensation
2

Cash contributions from parent
9

Net loss
(44
)
Balance at September 30, 2018
$
317

Cash contributions from parent
(4
)
Share-based compensation
7

Net loss
(919
)
Balance at December 31 2018
$
(599
)
Share-based compensation
3

Net loss
(140
)
Balance at March 31, 2019
$
(736
)
Share-based compensation
1

Net loss
(50
)
Balance at June 30, 2019
$
(785
)
 
See accompanying notes.


7


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 2018 Annual Report on Form  10-K. The condensed consolidated financial statements as of June 30, 2019 and 2018 are unaudited. The consolidated balance sheet as of December 31, 2018 has been derived from the audited consolidated balance sheet included in our 2018 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. Our financial statements for prior periods include reclassifications that were made to conform to the current year presentation, none of which impacted our reported net income, stockholder’s equity or cash flows from operating activities. The results for any interim period are not necessarily indicative of the expected results for the entire year. 
Liquidity and Ability to Continue as a Going Concern

The accompanying interim consolidated financial statements have been prepared assuming the Company will continue as a going concern. The interim consolidated financial statements do not include any adjustments that might result from the outcome of a going concern uncertainty.

As previously disclosed, in May 2020, $182 million of our senior unsecured notes will mature. Based on our forecasted EBITDAX and cash on hand, we anticipate that we will not have sufficient liquidity to repay these notes, meet our working capital needs and/or fund our planned capital expenditures as of one year from the filing date of these financial statements without obtaining additional liquidity through other sources. On August 1, 2019, we borrowed $268 million under our Reserve-Based Loan Facility (RBL Facility). Following this drawdown, we have no borrowing capacity remaining under the RBL Facility.

In addition, in the next six months, we have the following near-term interest payments due on our indebtedness: (i) an approximately $40 million interest payment due under the indenture governing our 8.000% 1.5 Lien Notes due 2025 (the “2025 1.5 Lien Notes”) on August 15, 2019; (ii) an approximately $7 million interest payment due under the indenture governing our 7.750% Senior Unsecured Notes due 2022 on September 1, 2019; (iii) an approximately $9 million interest payment due under the indenture governing our 9.375% Senior Unsecured Notes due 2020 on November 1, 2019; (iv) an approximately $51 million interest payment under the indenture governing our 9.375% 1.5 Lien Notes due 2024 on November 1, 2019; (v) an approximately $39 million interest payment due under the indenture governing our 7.750% 1.125 Lien Notes due 2026 on November 15, 2019; (vi) an approximately $20 million interest payment due under the indenture governing our 8.000% 1.25 Lien Notes due 2024 on December 2, 2019; and (vii) an approximately $10 million interest payment due under the indenture governing our 6.375% Senior Unsecured Notes due 2023 on December 15, 2019. While no decision has been made at this time, we may determine not to pay the interest due on our 2025 1.5 Lien Notes on the August 15, 2019 interest payment due date, and we may decide to utilize the 30-day grace period under the indenture governing the 2025 1.5 Lien Notes, or may not make this interest payment or future interest payments at all. Any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis, including with respect to the 2025 1.5 Lien Notes, would likely result in a default under that indebtedness and likely cause cross-defaults and/or cross-acceleration under our other indebtedness, which in the event of available capacity, could limit our ability to borrow under the RBL Facility.

As a result of these issues, there is substantial doubt about the Company’s ability to continue as a going concern. In order to address these issues, our Board of Directors (the “Board”) has appointed a special committee (the “Special Committee”) of the Board consisting of independent members of the Board who are not affiliated with our Sponsors (affiliates of Apollo Global Management LLC, Riverstone Holdings LLC, Access Industries and Korea National Oil Corporation, collectively, the “Sponsors”), and we have engaged financial and legal advisors to consider a number of potential actions we may take in order to address our liquidity and balance sheet issues. We are evaluating certain strategic alternatives including financings, refinancings, amendments, waivers, forbearances, asset sales, debt issuances, exchanges and purchases, out-of-court or in-court restructurings (pursuant to which we may seek relief under the United States Bankruptcy Code, Title 11 (the “Bankruptcy Code”)) and/or similar transactions involving the Company, none of which have been implemented at this time. The Special Committee is authorized to, among other things, consider, evaluate and approve such strategic alternatives.

8


However, there is no assurance that our actions will be successful in alleviating these concerns. Should we not be able to execute on one of or a combination of these strategic alternatives, we would be unable to continue as a going concern. In addition, in the absence of any suitable relief through the actions mentioned above, should we be required to include a going concern qualification in our year-end audit report and audited financial statements for 2019, the disclosure would be considered a default under the RBL Facility, and potentially an event of default if not waived within 30 days after receiving notice of the default from the administrative agent under the RBL Facility. An event of default under the RBL Facility could trigger cross-defaults and/or cross acceleration under our other debt agreements, including our senior secured and unsecured notes, which could also result in the acceleration of those obligations by the lenders thereunder.
Furthermore, failure to comply with not only the covenants associated with the indebtedness noted above, but also those under each of our debt agreements would likely result in a default under the indebtedness and likely cause cross-defaults and/or cross-acceleration under our other indebtedness. Any cross-defaults and cross-accelerations of our indebtedness could have a material adverse effect on our business, financial condition, liquidity and results of operations and could require that we take other actions to protect our business, including seeking forbearance agreements from our lenders and investors and/or filing for protection under the Bankruptcy Code.
Significant Accounting Policies
In the first quarter of 2019, we adopted Accounting Standards Update (ASU) No. 2016-02, Leases, which requires lessees to recognize lease assets and liabilities on the balance sheet and disclose key information about leasing arrangements. We adopted this standard on a modified retrospective basis, allowing us to account for leases entered into before adoption under prior ASC 840 guidance. The adoption did not have a material impact on our consolidated financial statements, nor did the adoption result in a cumulative-effect adjustment to retained earnings. In addition, we made certain permitted elections upon adoption, the most significant of which were (i) exempting short-term leases (i.e., leases with an initial term of less than 12 months) from balance sheet recognition, (ii) maintaining existing accounting treatment for existing or expired land easements not previously accounted for as leases under prior guidance and (iii) accounting for lease and non-lease components in a contract as a single lease component when not readily determinable. For a further discussion on leases, see Note 6.

2. 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.
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 both the quarters and six months ended June 30, 2019 and 2018, our effective tax rates were 0%. Our effective tax rates in 2019 and 2018 differed from the statutory rate of 21% primarily as a result of our recognition of a full valuation allowance on our net deferred tax assets. In addition, we recorded adjustments to the valuation allowance on our net deferred tax assets, which offset deferred income tax benefits by $9 million and $13 million, for the quarters ended June 30, 2019 and 2018, respectively, and by $39 million and $8 million for the six months ended June 30, 2019 and 2018, respectively.

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 $575 million as of June 30, 2019.

The Company's and certain subsidiaries' income tax years after 2014 remain open and subject to examination by both federal and state tax authorities, and in 2018 we were notified of an IRS examination of our parent's 2016 U.S. tax return.

    

9


3. 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, 2019 and December 31, 2018, 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, 2019
 
December 31, 2018
 
Carrying
 Amount
 
Fair
 Value
 
Carrying
 Amount
 
Fair
 Value
 
(in millions)
Current maturities of long-term debt
$
182

 
$
7

 
$
58

 
$
44

 
 
 
 
 
 
 
 
Long-term debt (see Note 6)
$
4,453

 
$
2,051

 
$
4,380

 
$
2,532

 
 
 
 
 
 
 
 
Derivative instruments
$
34

 
$
34

 
$
114

 
$
114

 
As of June 30, 2019 and December 31, 2018, the carrying amount of cash and cash equivalents, accounts receivable, owner and royalties payable, 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, 2019, we had derivative contracts in the form of collars and three-way collars on 19 MMBbls of oil (7 MMBbls in 2019 and 12 MMBbls in 2020). In addition to our oil derivatives, we had derivative contracts in the form of fixed price swaps and collars on 13 TBtu of natural gas in 2019. As of December 31, 2018, we had derivative contracts for 16 MMBbls of oil and 26 TBtu of natural gas. 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, 2019 and December 31, 2018. 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, 2019
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Derivative instruments
$
38

 
$
(4
)
 
$
24

 
$
10

 
$
(4
)
 
$
4

 
$

 
$

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2018
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Derivative instruments
$
116

 
$
(2
)
 
$
101

 
$
13

 
$
(2
)
 
$
2

 
$

 
$

For the quarters ended June 30, 2019 and 2018, we recorded derivative gains and losses of $29 million and $64 million, respectively. For the six months ended June 30, 2019 and 2018, we recorded derivative losses of $66 million and $78 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.

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4.  Property, Plant and Equipment
 
Oil and Natural Gas Properties.  As of June 30, 2019 and December 31, 2018, we had approximately $3.9 billion and $3.8 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 oil and natural gas properties.
Our capitalized costs related to proved oil and natural gas properties by area were as follows:
 
 
June 30, 2019
 
December 31, 2018
 
 
(in millions)
Proved
 
 
 
 
    Eagle Ford
 
$
4,132

 
$
3,898

    Permian
 
1,789

 
1,787

Northeastern Utah
 
1,704

 
1,659

        Total Proved
 
7,625

 
7,344

Less accumulated depletion
 
(3,772
)
 
(3,607
)
        Net capitalized costs for oil and natural gas properties
 
$
3,853

 
$
3,737

Suspended well costs were not material as of June 30, 2019 or December 31, 2018
We evaluate capitalized costs related to proved properties upon a triggering event (e.g., a significant continued decline in forward commodity prices) to determine if an impairment of such properties has occurred. 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 properties in the future.

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.
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 June 30, 2019 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, 2019 were as follows: 
 
2019
 
(in millions)
Net asset retirement liability at January 1
$
42

Accretion expense
2

Net asset retirement liability at June 30
$
44

Capitalized Interest.  Interest expense is reflected in our consolidated 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 both the quarters and six months ended June 30, 2019 and 2018 were approximately $2 million and $3 million, respectively.


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5. Long-Term Debt 
Listed below are our debt obligations as of the periods presented:
 
Interest Rate
 
June 30, 2019
 
December 31, 2018
 
 
 
(in millions)
RBL credit facility - due November 23, 2021(1)
Variable
 
$
355

 
$
100

Senior secured term loans:
 
 
 
 
 
2.0 Lien due April 30, 2019(2)
Variable
 

 
8

Senior secured notes:
 
 
 
 
 
1.5 Lien due May 1, 2024
9.375%
 
1,092

 
1,092

1.25 Lien due November 29, 2024
8.000%
 
500

 
500

1.5 Lien due February 15, 2025
8.000%
 
1,000

 
1,000

1.125 Lien due May 15, 2026
7.750%
 
1,000

 
1,000

Senior unsecured notes:
 
 
 
 
 
Due May 1, 2020
9.375%
 
182

 
232

Due September 1, 2022
7.75%
 
182

 
182

Due June 15, 2023
6.375%
 
324

 
324

Total debt
 
 
4,635

 
4,438

     Current maturities of long-term debt, net of debt issue costs of less than $1 million
 
 
(182
)
 
(58
)
Total long-term debt
 
 
4,453

 
4,380

Less debt discount and non-current portion of unamortized debt issue costs(3)
 
 
(88
)
 
(95
)
Total long-term debt, net
 
 
$
4,365

 
$
4,285

 
(1)
Carries interest at a specified margin over LIBOR of 2.50% to 3.50%, based on borrowing utilization.
(2)
Carries interest at a specified margin over the LIBOR of 3.50%, with a minimum LIBOR floor of 1.00%.  As of April 30, 2019 and December 31, 2018, the effective interest rates for the term loan were 6.08% and 6.21%. In April 2019, we retired the note in full.
(3)
Includes debt discount of $39 million and $42 million as of June 30, 2019 and December 31, 2018, respectively, associated with our 1.5 Lien Notes maturing in 2024 and unamortized debt issue costs of $49 million and $53 million as of June 30, 2019 and December 31, 2018, respectively.

     
Gain on extinguishment/modification of debt. During 2018, we completed an exchange of approximately $1.1 billion of certain senior unsecured notes for new 1.5 Lien Notes maturing in 2024. The exchange transaction was accounted for as a modification of debt and an extinguishment of debt depending on the senior unsecured notes exchanged. In conjunction with the exchange, we recorded a $12 million loss on debt considered modified for accounting purposes and a net gain of $53 million on debt considered extinguished for accounting purposes.
Additionally, in 2019 and 2018, we also recorded gains and losses on extinguishment/modification of debt primarily related to repurchased debt as follows:
 
 
Quarter ended June 30,
 
Six months ended June 30,
 
 
2019
 
2018
 
2019
 
2018
 
 
(in millions)
Debt repurchased- face value(1)
 

 
19

 
50

 
19

Cash paid
 

 
10

 
40

 
10

Gain on extinguishment of debt
 

 
9

 
10

 
9

Other losses on extinguishment of debt(2)
 

 
(2
)
 

 
(2
)
 
(1)    In 2019 and 2018, repurchases were associated with our 2020 senior unsecured notes and 2022 and 2023 senior unsecured notes, respectively.
(2)    Reflects the elimination of associated unamortized debt issue costs related to the reduction of our RBL Facility commitments in 2018.

Reserve-based Loan Facility. We have a 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, 2019, we had $247 million of capacity remaining with approximately $27 million of LCs issued and $355 million outstanding under the RBL Facility.  On August 1,

12


2019, we borrowed $268 million under our RBL Facility. Following this drawdown, we have no borrowing capacity remaining 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 April 2019, our RBL borrowing base was reaffirmed at $1.36 billion and total commitments remained at $629 million. Our next redetermination date is in November 2019. 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, including first lien debt to EBITDAX and current ratio financial covenants. First lien debt for purposes of the covenant only includes amounts borrowed under our RBL Facility. Our current financial covenants require us to maintain a ratio of first lien debt to EBITDAX not exceeding 2.25 to 1.00 and a current ratio (as defined in the RBL Facility) of not less than 1.00 to 1.00. As of June 30, 2019, 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. We are also subject to cross-defaults and/or cross-acceleration under our debt agreements which are further described in Note 1.


6. Commitments and Contingencies
 
Legal Matters
 
We and our subsidiaries and affiliates are parties to various legal actions and claims that arise in the ordinary course of our business. For each matter, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of our current matters cannot be predicted with certainty and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure and adjust our accruals accordingly, and these adjustments could be material. As of June 30, 2019, we had approximately $29 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, which denied review in June 2019. We filed a motion for rehearing in the Texas Supreme Court on July 31, 2019. If denied, the case will be remanded to the trial court for further proceedings. As of June 30, 2019, we had accrued $21 million related to this matter.

13


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 after November 2006 (approximately $15.6 million) plus judicial interest (approximately $7.8 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. As of June 30, 2019, we had accrued $3 million related to this matter, which was subsequently settled in July 2019.
Storey Minerals, Ltd., et al. v. EP Energy E&P Company, L.P. On May 29, 2018, Storey Minerals, Ltd., Maltsberger/Storey Ranch, LLC, and Rene R. Barrientos, Ltd. (collectively, “MSB”) filed suit against EP Energy in the 81st Judicial District Court of La Salle County, Texas. MSB alleged that by acquiring certain oil and gas leases within the perimeter of the Storey Altito Ranch, EP Energy triggered the most favored nation clause (“MFN clause”) in the leases. After investigation, EP Energy agreed that the MFN clause had been triggered and tendered a lease amendment with a check for $4 million for increased lease bonus. EP Energy's calculation confirmed that no delay rentals were due. MSB, however, did not accept the tender and asserts that the MFN clause operates retroactively to the date of the lease and applies to all of the acreage leased at that time. EP Energy maintains that the unambiguous language in the MFN clause operates prospectively and supports its tendered amendment and calculation. The parties filed cross-motions for summary judgment. In June 2019, the court entered an order agreeing with EP Energy on delay rentals, but with MSB on lease bonus. The court entered a final judgment in July 2019 ordering EP Energy to pay MSB $43.8 million in increased lease bonus, attorney’s fees, expenses and interest to date. EP Energy filed an appeal to the Fourth Circuit Court of Appeals in San Antonio on July 17, 2019 and intends to pursue fully its appeal. As of June 30, 2019, EP Energy's accrual of $4 million related to this matter reflects the amount tendered to MSB with the lease amendment noted above, which EP Energy believes is the appropriate amount of increased bonus due to MSB.
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 2018 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.
Other Matters
As of June 30, 2019, we had approximately $15 million accrued (in other accrued liabilities in our consolidated balance sheet) related to other contingent matters including, but not limited to, a number of examinations by taxing authorities on non-income matters and indemnifications that we periodically enter into 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 and other contingent matters. In addition, 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.
Lease Obligations

Our noncancellable leases classified as finance leases for accounting purposes include certain compressors under long-term arrangements which were capitalized upon commencement of the lease term at the fair value of the leased asset , which was lower than the present value of the minimum lease payments. The discount rate used for our finance leases was the incremental borrowing rate adjusted so that the present value of the corresponding lease payments did not exceed the fair value of the leased asset. For the quarter ended June 30, 2019, both interest and depreciation expense associated with our finance

14


leases was approximately $1 million and related cash payments were approximately $2 million. For the six months ended June 30, 2019, both interest and depreciation expense associated with our finance leases were approximately $2 million and related cash payments were approximately $4 million.
    
Our noncancellable leases classified as operating leases and capitalized upon commencement of the lease term for accounting purposes include those for office space, drilling rigs and field equipment. The discount rate used for our operating leases is either the discount rate implicit in the contract, or the applicable interest rate on a collateralized basis if not determinable. Operating lease costs for minimum lease payments are recognized as capital or expense on a straight-line basis over the lease term depending on the nature of the payment. For the quarter ended June 30, 2019, operating lease costs and related cash payments were approximately $3 million and $2 million, respectively, and $5 million and $3 million, respectively, for the six months ended June 30, 2019. These were primarily capitalized as part of our oil and natural gas properties. Variable lease costs (amounts incurred beyond minimum lease payments such as utilities, usage, maintenance, mobilization fees, etc.) are recognized in the period incurred. For both the quarter and six months ended June 30, 2019, variable lease costs were approximately $1 million

Short-term lease costs for the quarter and six months ended June 30, 2019 were approximately $7 million and $16 million, respectively, and were primarily capitalized as part of our oil and natural gas properties.
    
Supplemental balance sheet information related to leases was as follows:
 
 
June 30, 2019
 
 
(in millions)
Operating lease assets(1)(4)
 
$
23

Finance lease assets(2)
 
11

        Total lease assets
 
$
34

 
 
 
Operating leases(3)(4)
 
 
   Current liability
 
$
10

   Noncurrent liability
 
13

        Total operating lease liability
 
$
23

Finance leases(3)
 
 
   Current liability
 
$
2

   Noncurrent liability
 
9

        Total finance lease liability
 
$
11

 
 
 
Weighted average remaining lease term
 
 
   Operating leases
 
4 years

   Finance leases
 
4 years

Weighted average discount rate
 
 
   Operating leases
 
9.37
%
   Finance leases
 
26.52
%
 
(1)
Operating lease assets are reflected in Operating lease assets and other in our consolidated balance sheet as of June 30, 2019.
(2)
Finance lease assets are reflected in Other property, plant and equipment in our consolidated balance sheet as of June 30, 2019.
(3)    Current and noncurrent operating and finance lease liabilities are reflected in Other accrued liabilities and Lease obligations and other, respectively, in our consolidated
balance sheet as of June 30, 2019.
(4)
Upon adoption of ASU 2016-02 effective January 1, 2019, we recognized operating leases of approximately $10 million. For the six months ended June 30, 2019, we also recorded an additional $16 million of operating leases.

Future minimum annual rental commitments under non-cancelable future operating and finance lease commitments at June 30, 2019, were as follows:


15


 
 
Operating Leases
 
Finance Leases
 
 
(in millions)
2019
 
$
6

 
$
2

2020
 
10

 
5

2021
 
3

 
5

2022
 
2

 
5

Thereafter
 
6

 
2

Total
 
$
27

 
$
19

Less: imputed interest
 
(4
)
 
(8
)
   Present value of operating and finance lease obligations
 
$
23

 
$
11


7. Incentive Compensation

Long-term Incentive Compensation
Our parent’s long-term incentive (LTI) programs consist of restricted stock, stock options, cash-based incentives and performance share units awards. Refer to our 2018 Annual Report on Form 10-K and on Form 10-K/A for further information regarding the terms and details of these 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 for both of the quarters ended June 30, 2019 and 2018, and $7 million and $4 million for the six months ended June 30, 2019 and 2018, respectively. As of June 30, 2019, we had unrecognized compensation expense of $18 million of which we will recognize $7 million during the remainder of 2019 and $11 million thereafter.
 
Restricted Stock. A summary of the changes in our parent’s non-vested restricted shares for the six months ended June 30, 2019 is presented below:
 
 
Number of Shares
 
Weighted Average
Grant Date Fair Value
per Share
Non-vested at December 31, 2018
 
7,060,334

 
$
2.69

Granted
 
103,000

 
$
0.70

Vested
 
(1,112,910
)
 
$
4.93

Forfeited
 
(754,623
)
 
$
2.60

Non-vested at June 30, 2019
 
5,295,801

 
$
2.24


Performance Share Units. In 2018, we granted 618,720 performance share units (PSUs) to certain EP Energy employees. The grant date fair value of the 2018 awards was approximately $5 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, 2019, we had a total of 1,487,280 PSUs outstanding. PSUs will vest over a weighted average period of three years and earned only upon the achievement of specified stock price goals. Our PSUs are treated as an equity award with the expense recognized on an accelerated basis over the life of the award.
Key Employee Retention Program
On May 29, 2019, the Compensation Committee of the Board of Directors of the Company approved the implementation of a Key Employee Retention Program (a “KERP”) for all employees of the Company. KERP payments totaling approximately $21 million were made in July 2019 and were comprised of approximately $10 million in lieu of target bonus amounts for 2019 performance, which were already being accrued during the year, plus an incremental amount of approximately $11 million in lieu of long-term incentive compensation for 2019. KERP payments are subject to certain termination provisions through June 30, 2020 which would result in the repayment of the award in full.

As of June 30, 2019, our consolidated balance sheet reflects a liability and deferred charge in the amount of approximately $21 million and $20 million, respectively, related to the KERP. For accounting purposes, deferred expense is

16


being amortized over the 13 month term of the KERP agreement. During both the quarter and six months ended June 30, 2019, we recorded less than $1 million in expense related to the KERP.


8. Related Party Transactions
    
Joint Venture. We are party to a drilling joint venture to fund future oil and natural gas development with Wolfcamp Drillco Operating L.P. (the Investor, which is managed and controlled by an affiliate of Apollo Global Management LLC) and indirectly through Access Industries (through an indirect minority ownership interest in the Investor).  At June 30, 2019 and December 31, 2018, we had accounts receivable of $3 million and $47 million, respectively, and payables to our owner of $9 million and $20 million, respectively, associated with our Investor reflected in our consolidated balance sheets. Refer to our 2018 Annual Report on Form 10-K and on Form 10-K/A for further information on the joint venture agreement.

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 of December 31, 2018, we had no state income tax payable due to our parent.

17


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 this Quarterly Report on Form 10-Q and our 2018 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, Northeastern Utah (NEU) in the Uinta basin, and the Permian basin in West Texas. 
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 and increasing financial flexibility. 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.
We are party to a drilling joint venture agreement in the Eagle Ford with a total anticipated joint venture investment of $225 million. As of June 30, 2019, we have drilled and completed all wells under the amended agreement. Additionally, subject to certain time limits, we will provide our joint venture partner the option to participate in additional wells in the development areas. For a further discussion on this joint venture, see Part I, Item 1, "Financial Information", Note 8. In NEU, we are also party to a drilling joint venture agreement under which our joint venture partner is participating in the development of 53 wells. As of June 30, 2019, we have drilled and completed 47 wells under the NEU joint venture agreement.

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 and capital costs;
managing commodity price risks on our oil and natural gas production; and
managing debt levels and related interest costs.
In addition to these factors, our future profitability and performance is affected by volatility in the financial and commodity markets. 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 and profitability.     
Forward commodity prices play a significant role in determining the recoverability of proved property costs on our balance sheet. While prices have generally stabilized over recent 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 properties in the future, and such charges could be significant.


18


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 or 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.
The following table and discussion reflects the contracted volumes and the prices we will receive under derivative contracts we held as of June 30, 2019.
 
2019
 
2020
 
Volumes(1)
 
Average
Price(1)
 
Volumes(1)
 
Average
Price(1)
Oil
 

 
 

 
 

 
 

Collars
 
 
 
 
 
 
 
Ceiling - WTI
736

 
$
69.78

 

 
$

        Floors - WTI
736

 
$
57.50

 

 
$

Three Way Collars
 
 
 
 
 
 
 
Ceiling - WTI
6,072

 
$
66.01

 
11,712

 
$
65.11

Floors - WTI
6,072

 
$
55.76

 
11,712

 
$
55.90

Sub-Floor - WTI
6,072

 
$
45.00

 
11,712

 
$
45.00

Basis Swaps
 
 
 
 
 
 
 
Midland vs. Cushing(2)
736

 
$
(5.23
)
 
1,464

 
$
0.46

NYMEX Roll(3)
244

 
$
0.25

 

 
$

Natural Gas
 
 
 
 
 
 
 
Fixed Price Swaps
6

 
$
3.01

 

 
$

Collars
 
 
 
 
 
 
 
Ceiling
7

 
$
4.26

 

 
$

Floors
7

 
$
2.75

 

 
$

Basis Swaps
 
 
 
 
 
 
 
WAHA vs. Henry Hub(4)
4

 
$
(0.39
)
 

 
$

 

(1)
Volumes presented are MBbls for oil and TBtu for natural gas. Prices presented are per Bbl of oil and MMBtu of natural gas.
(2)
EP Energy receives Cushing plus the basis spread listed and pays Midland.
(3)
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”).
(4)
EP Energy receives Henry Hub plus the basis spread listed and pays WAHA.


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 $10.76 in 2019 and $10.90 in 2020 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, 2019, the average forward price of oil was $58.16 per barrel of oil for the remainder of 2019 and $55.91 per barrel of oil for 2020.
During the six months ended June 30, 2019, we settled commodity index hedges on approximately 99% of our oil production, 73% of our total NGLs production and 60% of our natural gas production at average floor prices of $55.92 per barrel of oil and $2.86 per MMBtu of natural gas, respectively. As of June 30, 2019, approximately 100% of our future crude oil contracts allow for upside participation (to a weighted average price of approximately $66.41 per barrel for 2019 and $65.11 per barrel for 2020) while containing certain sub-floor prices (weighted average prices of $45.00 per barrel) that limit the amount of our derivative settlements under these three-way contracts should prices drop below the sub-floor prices. 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.

19


 
Liquidity and Capital Resources
Our primary sources of liquidity are cash generated by our operations and borrowings under our Reserve-Based Loan Facility (RBL Facility) which matures in 2021 and our primary uses of cash are capital expenditures, debt service, including interest, and working capital requirements. Our available liquidity was $299 million as of June 30, 2019.
In April 2019, our RBL borrowing base was reaffirmed at $1.36 billion and total commitments remained at $629 million. However, 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 prices may have the effect of increasing our borrowing base.

Debt Maturities and Covenants.. As of June 30, 2019, our total debt was approximately $4.6 billion, comprised of $182 million in senior unsecured notes due in 2020, $355 million outstanding under the RBL Facility which matures in 2021, $506 million in senior unsecured notes due in 2022 and 2023, and $3.6 billion in 1.5 Lien Notes due in 2024 and 2025, 1.25 Lien Notes due in 2024 and 1.125 Lien Notes due in 2026. Our most restrictive financial debt covenants (which were modified and/or extended in 2018) include a requirement to maintain a first lien debt to EBITDAX ratio of 2.25 to 1.00 and a current ratio (as defined in the RBL Facility) of not less than 1.00 to 1.00. As of June 30, 2019, we were in compliance with our debt covenants. For additional details on our long-term debt, see Part I, Item 1, Financial Statements, Note 5.    

As previously disclosed, in May 2020, $182 million of our senior unsecured notes will mature. Based on our forecasted EBITDAX and cash on hand, we anticipate that we will not have sufficient liquidity to repay these notes, meet our working capital needs and/or fund our planned capital expenditures as of May 2020 when these notes are due. On August 1, 2019, we borrowed $268 million under our RBL Facility. Following this drawdown, we have no borrowing capacity remaining under the RBL Facility.

In addition, in the next six months we have the following near-term interest payments due on our indebtedness: (i) an approximately $40 million interest payment due under the indenture governing our 8.000% 1.5 Lien Notes due 2025 (the “2025 1.5 Lien Notes”) on August 15, 2019; (ii) an approximately $7 million interest payment due under the indenture governing our 7.750% Senior Unsecured Notes due 2022 on September 1, 2019; (iii) an approximately $9 million interest payment due under the indenture governing our 9.375% Senior Unsecured Notes due 2020 on November 1, 2019; (iv) an approximately $51 million interest payment under the indenture governing our 9.375% 1.5 Lien Notes due 2024 on November 1, 2019; (v) an approximately $39 million interest payment due under the indenture governing our 7.750% 1.125 Lien Notes due 2026 on November 15, 2019; (vi) an approximately $20 million interest payment due under the indenture governing our 8.000% 1.25 Lien Notes due 2024 on December 2, 2019; and (vii) an approximately $10 million interest payment due under the indenture governing our 6.375% Senior Unsecured Notes due 2023 on December 15, 2019. While no decision has been made at this time, we may determine not to pay the interest due on our 2025 1.5 Lien Notes on the August 15, 2019 interest payment due date, and we may decide to utilize the 30-day grace period under the indenture governing the 2025 1.5 Lien Notes, or may not make this payment or future interest payments at all. Any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis, including with respect to the 2025 1.5 Lien Notes, would likely result in a default under that indebtedness and likely cause cross-defaults and/or cross-acceleration under our other indebtedness, which in the event of available capacity, could limit our ability to borrow under the RBL Facility.

As a result of these issues, there is substantial doubt about the Company’s ability to continue as a going concern. In order to address these issues, our Board of Directors (the “Board”) has appointed a special committee (the “Special Committee”) of the Board consisting of independent members of the Board who are not affiliated with our Sponsors (affiliates of Apollo Global Management LLC, Riverstone Holdings LLC, Access Industries and Korea National Oil Corporation, collectively, the “Sponsors”), and we have engaged financial and legal advisors to consider a number of potential actions we may take in order to address our liquidity and balance sheet issues. We are evaluating certain strategic alternatives including financings, refinancings, amendments, waivers, forbearances, asset sales, debt issuances, exchanges and purchases, out-of-court or in-court restructurings (pursuant to which we may seek relief under the Bankruptcy Code and/or similar transactions involving the Company), none of which have been implemented at this time. The Special Committee is authorized to, among other things, consider, evaluate and approve such strategic alternatives.
However, there can be no assurance that this review will be successful, and an in-court restructuring pursuant to which we may seek relief under the Bankruptcy Code may be unavoidable. Any transaction or action we determine to pursue, including seeking in-court protection under the Bankruptcy Code, could require our senior management to spend a significant

20


amount of time and effort dealing with such transaction or action instead of focusing exclusively on our business operations and make it more difficult to attract, retain or replace management and other key personnel necessary to the success and growth of our business; cause the loss of confidence in us by our customers; and have a material adverse effect on our business, financial condition, liquidity and results of operations.
Even if we are able to implement such strategic alternatives, they may be insufficient to meet our debt and other obligations over the longer term. Furthermore, such strategic alternatives may not yield additional value for stockholders, and may adversely affect our creditors or our existing stockholders, potentially resulting in a reduction in the value of their investment or the loss of all or substantially all of their investment in us. In addition, we may incur substantial expenses associated with identifying and evaluating potential strategic alternatives, and the process of exploring strategic alternatives may be time consuming and disruptive to our business operations.
Should we not be able to execute on one of or a combination of these strategic alternatives, we would be unable to continue as a going concern.In addition, in the absence of any suitable relief through the actions mentioned above, should we be required to include a going concern qualification in our year-end audit report and audited financial statements for 2019, the disclosure would also be considered a default under the Company's RBL Facility, and potentially an event of default if not waived within 30 days after receiving notice of the default from the administrative agent under the RBL Facility. An event of default under the RBL Facility could trigger cross-defaults and/or cross acceleration under our other debt agreements, including our senior secured term loan and our senior secured and unsecured notes, which could also result in the acceleration of those obligations by the lenders thereunder.
Furthermore, failure to comply with not only the covenants associated with the indebtedness noted above, but also those under each of our debt agreements would likely result in a default under the indebtedness and likely cause cross-defaults and/or cross-acceleration under our other indebtedness. Any cross-defaults and cross-accelerations of our indebtedness could have a material adverse effect on our business, financial condition, liquidity and results of operations and could require that we take other actions to protect our business, including seeking forbearance agreements from our lenders and investors and/or filing for protection under the Bankruptcy Code.
    
Capital Expenditures.  Our capital expenditures and average drilling rigs by area for the six months ended June 30, 2019 were:
 
Capital
Expenditures(1)
(in millions)
 
Average Drilling
 Rigs
Eagle Ford Shale
$
226

 
2.8

Northeastern Utah
60

 
1.3

Permian
2

 

Total
$
288

 
4.1

   Acquisition capital
$
15

 
 
Total Capital Expenditures
$
303

 
 
 
(1)
Represents accrual-based capital expenditures.

    


21


Overview of Cash Flow Activities.  Our cash flows are summarized as follows (in millions):
 
Six months ended
June 30,
 
2019
 
2018
Cash Inflows
 

 
 

Operating activities
 

 
 

Net loss
$
(190
)
 
$
(40
)
Gain on extinguishment/modification of debt
(10
)
 
(48
)
Other income adjustments
202

 
262

Changes in assets and liabilities
82

 
38

Total cash flow from operations
84

 
212

 
 
 
 
 
 

 
 

Investing activities
 

 
 

Proceeds from the sale of assets

 
169

 Cash inflows from investing activities

 
169

 
 
 
 
Financing activities
 
 
 
Proceeds from issuance of long-term debt
615

 
1,665

Contributions from parent

 
4

 Cash inflows from financing activities
615

 
1,669

 
 
 
 
Total cash inflows
$
699

 
$
2,050

 
 
 
 
Cash Outflows
 

 
 

Investing activities
 
 
 

Capital expenditures
$
249

 
$
384

Cash paid for acquisitions
15

 
239

Cash outflows from investing activities
264

 
623

 
 
 
 
Financing activities
 

 
 

Repayments and repurchases of long-term debt
408

 
1,291

Fees/costs on debt exchange

 
62

Debt issue costs

 
20

Other
2

 

Cash outflows from financing activities
410

 
1,373

 
 
 
 
Total cash outflows
$
674

 
$
1,996

 
 
 
 
Net change in cash, cash equivalents and restricted cash
$
25

 
$
54



22


Production Volumes and Drilling Summary
 
Production Volumes. Below is an analysis of our production volumes for the six months ended June 30:
 
 
2019
 
2018
Equivalent Volumes (MBoe/d)
 

 
 

Eagle Ford
32.8

 
37.6

Northeastern Utah
15.6

 
17.0

Permian
23.2

 
26.7

Total
71.6

 
81.3

 
 
 
 
Oil (MBbls/d)
 
 
 
Eagle Ford
21.6

 
24.9

Northeastern Utah
10.1

 
11.7

Permian
6.8

 
9.7

Total
38.5

 
46.3

 
 
 
 
Natural Gas (MMcf/d)
 
 
 
Eagle Ford(1)
33

 
38

Northeastern Utah
33

 
32

Permian
52

 
55

Total
118

 
125

 
 
 
 
NGLs (MBbls/d)
 
 
 
Eagle Ford
5.7

 
6.4

Northeastern Utah

 

Permian
7.7

 
7.8

Total
13.4

 
14.2

 
(1)
Production volume excludes 7 MMcf/d of reinjected gas volumes used in operations during the six months ended June 30, 2019.
 
Production Summary. For the six months ended June 30, 2019 compared to the same period in 2018, (i) Eagle Ford equivalent volumes decreased 4.8 MBoe/d or (approximately 13%) due to fewer wells placed on production in the second half of 2018 and first half of 2019, (ii) NEU equivalent volumes decreased 1.4 MBoe/d or (approximately 8%) due to reduced drilling activity in 2019, and (iii) Permian equivalent volumes decreased 3.5 MBoe/d or (approximately 13%) reflecting the slower pace of development due to a significant reduction in capital allocated to the Permian. In Eagle Ford and Permian, our 2019 production volumes were also negatively impacted by downstream third-party operational issues and constraints.
    
Drilling Summary. During the six months ended June 30, 2019, we (i) frac’d (wells fracture stimulated) 26 gross wells in the Eagle Ford, 24 of which came online for a total of 811 net operated wells, and (ii) frac’d 7 gross wells in NEU, all of which came online for a total of 292 net operated wells. We did not frac any wells in the Permian during the six months ended June 30, 2019, and currently operate 350 net wells in the area. As of June 30, 2019, we also had a total of 62 gross wells in progress, of which all were drilled, but not completed across our programs.
    
    


23


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,
 
2019
 
2018
 
2019
 
2018
 
(in millions)
Operating revenues
 

 
 

 
 

 
 

Oil
$
204

 
$
281

 
$
397

 
$
533

Natural gas
8

 
18

 
26

 
40

NGLs
15

 
30

 
33

 
56

Total physical sales
227

 
329

 
456

 
629

Financial derivatives
29

 
(64
)
 
(66
)
 
(78
)
Total operating revenues
256

 
265

 
390

 
551

 
 
 
 
 
 
 
 
Operating expenses
 

 
 

 
 

 
 

Transportation costs
23

 
26

 
48

 
51

Lease operating expense
30

 
38

 
67

 
77

General and administrative
43

 
28

 
64

 
47

Depreciation, depletion and amortization
94

 
129

 
188

 
249

Exploration and other expense
1

 

 
2

 
1

Taxes, other than income taxes
20

 
21

 
31

 
41

Total operating expenses
211

 
242

 
400

 
466

 
 
 
 
 
 
 
 
Operating income (loss)
45

 
23

 
(10
)
 
85

Gain on extinguishment/modification of debt

 
7

 
10

 
48

Interest expense
(95
)
 
(88
)
 
(190
)
 
(173
)
Loss before income taxes
(50
)
 
(58
)
 
(190
)
 
(40
)
Income tax expense

 

 

 

Net loss
$
(50
)
 
$
(58
)
 
$
(190
)
 
$
(40
)

24


Operating Revenues
 
The table below provides our operating revenues, volumes and prices per unit for the quarters and six months ended June 30, 2019 and 2018. 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,
 
2019
 
2018
 
2019
 
2018
 
(in millions)
Operating revenues:
 

 
 

 
 

 
 

Oil
$
204

 
$
281

 
$
397

 
$
533

Natural gas
8

 
18

 
26

 
40

NGLs
15

 
30

 
33

 
56

Total physical sales
227

 
329

 
456

 
629

Financial derivatives
29

 
(64
)
 
(66
)
 
(78
)
Total operating revenues
$
256

 
$
265

 
$
390

 
$
551

 
 
 
 
 
 
 
 
Volumes:
 

 
 

 
 

 
 

Oil (MBbls)
3,424

 
4,299

 
6,970

 
8,386

Natural gas (MMcf)
10,121

 
11,274

 
21,277

 
22,609

NGLs (MBbls)
1,245

 
1,334

 
2,428

 
2,566

Equivalent volumes (MBoe)
6,356

 
7,512

 
12,944

 
14,720

Total MBoe/d
69.8

 
82.5

 
71.6

 
81.3

 
 
 
 
 
 
 
 
Prices per unit(1):
 

 
 

 
 

 
 

Oil
 

 
 

 
 

 
 

Average realized price on physical sales ($/Bbl)(2) 
$
59.72

 
$
65.53

 
$
56.97

 
$
63.60

Average realized price, including financial derivatives ($/Bbl)(2)(3)
$
59.84

 
$
62.30

 
$
57.89

 
$
60.62

Natural gas
 
 
 
 
 

 
 
Average realized price on physical sales ($/Mcf)(2)
$
0.80

 
$
1.58

 
$
1.21

 
$
1.76

Average realized price, including financial derivatives ($/Mcf)(2)(3)
$
1.36

 
$
1.96

 
$
1.57

 
$
2.00

NGLs
 
 
 
 
 

 
 
Average realized price on physical sales ($/Bbl)
$
12.06

 
$
22.65

 
$
13.81

 
$
21.82

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

 
$
22.07

 
$
13.81

 
$
21.51

 
(1)
For both of the quarters and six months ended June 30, 2019 and 2018, there were no oil purchases associated with managing our physical oil sales. Natural gas prices for both of the quarters and six months ended June 30, 2019 and 2018 reflect operating revenues for natural gas reduced by less than $1 million 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, 2019 and 2018, include cash received of less than $1 million and cash paid of approximately $14 million, respectively, for the settlement of crude oil derivative contracts and approximately $6 million and $4 million of cash received, respectively, for the settlement of natural gas financial derivatives. The six months ended June 30, 2019 and 2018, include cash received of approximately $6 million and cash paid of approximately $25 million, respectively, for the settlement of crude oil derivative contracts and approximately $8 million and $5 million of cash received, respectively, for the settlement of natural gas financial derivatives. Both the quarter and six months ended June 30, 2018 also include $1 million of cash paid for the settlement of NGLs derivative contracts.









25


Physical sales.  Physical sales represent accrual-based commodity sales transactions with customers. The table below displays the price and volume variances on our physical sales when comparing the quarter and six months ended June 30, 2019 and 2018
 
Quarter ended
 
Oil
 
Natural gas
 
NGLs
 
Total
 
(in millions)
June 30, 2018 sales
$
281

 
$
18

 
$
30

 
$
329

Change due to prices
(20
)
 
(8
)
 
(13
)
 
(41
)
Change due to volumes
(57
)
 
(2
)
 
(2
)
 
(61
)
June 30, 2019 sales
$
204

 
$
8

 
$
15

 
$
227

 
Six months ended
 
Oil
 
Natural gas
 
NGLs
 
Total
 
(in millions)
June 30, 2018 sales
$
533

 
$
40

 
$
56

 
$
629

Change due to prices
(46
)
 
(12
)
 
(20
)
 
(78
)
Change due to volumes
(90
)
 
(2
)
 
(3
)
 
(95
)
June 30, 2019 sales
$
397

 
$
26

 
$
33

 
$
456

Oil sales for the quarter and six months ended June 30, 2019, compared to the same periods in 2018, decreased by $77 million (27%) and $136 million (26)%, respectively, due primarily to lower oil prices and production in all areas reflecting lower capital spending from the first half of 2018 through the first half of 2019.
Natural gas sales decreased by $10 million (56%) and $14 million (35)%, respectively, for the quarter and six months ended June 30, 2019 compared to the same periods in 2018 primarily due to lower natural gas prices and production in the Eagle Ford and Permian.
Our oil, natural gas and NGLs are sold at index prices (WTI, Brent, 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 primarily to benchmark Magellan East Houston crude oil. In NEU, market pricing of our oil is based upon NYMEX-based agreements, which reflect a locational difference at the wellhead. In the Permian, physical barrels are generally sold at the WTI Midland Index, which trades at a spread to WTI Cushing. Across all regions, natural gas realized pricing is influenced by factors such as regional basis differentials, 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,
 
2019
 
2018
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
Differentials and deducts
$
(0.15
)
 
$
(1.77
)
 
$
(2.27
)
 
$
(1.10
)
NYMEX
$
59.82

 
$
2.64

 
$
67.88

 
$
2.80

Net back realization %
99.7
%
 
33.0
%
 
96.7
%
 
60.7
%


26


 
Six months ended June 30,
 
2019
 
2018
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
Differentials and deducts
$
(0.67
)
 
$
(1.63
)
 
$
(1.67
)
 
$
(1.07
)
NYMEX
$
57.36

 
$
2.89

 
$
65.37

 
$
2.90

Net back realization %
98.8
%
 
43.6
%
 
97.4
%
 
63.1
%

The oil realization percentages for the quarter and six months ended June 30, 2019 were higher as compared to the same periods in 2018 primarily as a result of the improvement of Magellan East Houston and Midland basis pricing and physical sales contracts relative to lower NYMEX WTI pricing. The lower natural gas realization percentage for the quarter and six months ended June 30, 2019 were primarily a result of weaker Permian basin natural gas pricing.
NGLs sales decreased by $15 million (50%) and $23 million (41)%, respectively, for the quarter and six months ended June 30, 2019 compared with the same periods in 2018 as a result of lower average realized prices due to lower pricing on all liquid components.
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 capital expenditures, 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 quarters ended June 30, 2019 and 2018, we recorded $29 million and $64 million of derivative gains and losses, respectively. For the six months ended June 30, 2019 and 2018, we recorded $66 million and $78 million of derivative losses, respectively.
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,
 
2019
 
2018
 
Total
 
Per Unit(1)
 
Total
 
Per Unit(1)
 
(in millions, except per unit costs)
Operating expenses
 
 
 
 
 
 
 
Transportation costs
$
23

 
$
3.67

 
$
26

 
$
3.49

Lease operating expense
30

 
4.84

 
38

 
4.95

General and administrative(2)
43

 
6.77

 
28

 
3.74

Depreciation, depletion and amortization
94

 
14.83

 
129

 
17.20

Exploration and other expense
1

 
0.10

 

 

Taxes, other than income taxes
20

 
3.04

 
21

 
2.82

Total operating expenses
$
211