Company Quick10K Filing
EP Energy
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$0.00 250 $68
10-Q 2019-11-12 Quarter: 2019-09-30
10-Q 2019-11-12 Quarter: 2019-09-30
10-Q 2019-08-09 Quarter: 2019-06-30
10-Q 2019-08-09 Quarter: 2019-06-30
10-Q 2019-05-09 Quarter: 2019-03-31
10-Q 2019-05-09 Quarter: 2019-03-31
10-K 2019-03-18 Annual: 2018-12-31
10-K 2019-03-18 Annual: 2018-12-31
10-Q 2018-11-08 Quarter: 2018-09-30
10-Q 2018-08-10 Quarter: 2018-06-30
10-Q 2018-05-09 Quarter: 2018-03-31
10-K 2018-03-02 Annual: 2017-12-31
10-Q 2017-11-03 Quarter: 2017-09-30
10-Q 2017-08-03 Quarter: 2017-06-30
10-Q 2017-05-04 Quarter: 2017-03-31
10-K 2017-03-03 Annual: 2016-12-31
10-Q 2016-10-27 Quarter: 2016-09-30
10-Q 2016-08-04 Quarter: 2016-06-30
10-Q 2016-05-05 Quarter: 2016-03-31
10-K 2016-02-22 Annual: 2015-12-31
10-Q 2015-10-30 Quarter: 2015-09-30
10-Q 2015-07-30 Quarter: 2015-06-30
10-Q 2015-04-30 Quarter: 2015-03-31
10-K 2015-02-23 Annual: 2014-12-31
10-Q 2014-11-05 Quarter: 2014-09-30
10-Q 2014-08-07 Quarter: 2014-06-30
10-Q 2014-05-09 Quarter: 2014-03-31
10-K 2014-02-28 Annual: 2013-12-31
10-Q 2013-11-07 Quarter: 2013-09-30
10-Q 2013-08-14 Quarter: 2013-06-30
10-Q 2013-05-09 Quarter: 2013-03-31
10-K 2013-03-01 Annual: 2012-12-31
10-Q 2012-11-30 Quarter: 2012-09-30
8-K 2020-01-14 Regulation FD, Exhibits
8-K 2020-01-09 Regulation FD, Exhibits
8-K 2019-12-31 Regulation FD, Exhibits
8-K 2019-12-16 Regulation FD, Exhibits
8-K 2019-12-03 Regulation FD, Exhibits
8-K 2019-11-25 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2019-11-19 Regulation FD, Exhibits
8-K 2019-11-12 Earnings, Exhibits
8-K 2019-10-18
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 2018-05-17 Regulation FD
8-K 2018-05-14 Officers, Shareholder Vote
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
EPE 2019-09-30
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, Quantitative and 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 ex3110930201910q.htm
EX-31.2 ex3120930201910q.htm
EX-32.1 ex3210930201910q.htm
EX-32.2 ex3220930201910q.htm

EP Energy Earnings 2019-09-30

EPE 10Q Quarterly Report

Balance SheetIncome StatementCash Flow

Comparables ($MM TTM)
Ticker M Cap Assets Liab Rev G Profit Net Inc EBITDA EV G Margin EV/EBITDA ROA
EGY 99 202 86 98 0 94 113 37 0% 0.3 47%
ROSE 86 806 451 307 300 24 240 422 98% 1.8 3%
LONE 72 752 573 210 0 12 143 532 0% 3.7 2%
EPE 68 4,190 4,975 1,163 770 -1,153 -325 4,380 66% -13.5 -28%
MCF 59 253 124 65 0 24 67 59 0% 0.9 10%
LLEX 55 485 231 78 0 -10 22 171 0% 7.7 -2%
AMR 50 1,383 1,182 463 331 -1,520 -1,467 974 71% -0.7 -110%
DWSN 47 142 36 143 0 -28 -3 17 0% -5.0 -20%
TAT 46 144 94 72 0 -6 31 43 0% 1.4 -4%
UPL 40 1,873 2,729 904 0 156 156 2,191 0% 14.1 8%

10-Q 1 epenergycorp0930201910q.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 September 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 001-36253
 
 EP Energy Corporation
(Exact Name of Registrant as Specified in Its Charter)
Delaware
 
46-3472728
(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
 
Securities registered pursuant to Section 12(b) of the Act*:
Title of each class
 
Trading Symbol(s)
 
Name of each exchange on which registered
Class A Common Stock,
par value $0.01 per share
 
EPEGQ
 
N/A
*On June 7, 2019, a Form 25 relating to the delisting and deregistration under Section 12(b) of the Act of the registrant's Class A common stock was filed by the New York Stock Exchange LLC. The registrant's Class A common stock trades on the OTC Pink Sheets Market.
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 x  No o
 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
 
Non-accelerated filer o
 
Emerging Growth Company o
Accelerated filer x
 
Smaller reporting company x
 
 
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
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
 Class A Common Stock, par value $0.01 per share. Shares outstanding as of October 31, 2019: 255,030,035
Class B Common Stock, par value $0.01 per share. Shares outstanding as of October 31, 2019: 237,256
 



EP ENERGY CORPORATION

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 Corporation and/or its subsidiaries.
 All references to “common stock” herein refer to Class A common stock.

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:
risks and uncertainties relating to the voluntary petitions (the “Chapter 11 Cases”) filed in the United States Bankruptcy Court, including: our ability to obtain Bankruptcy Court approval with respect to our motions, risks associated with third-party motions, Bankruptcy Court rulings and the outcome of the Chapter 11 Cases in general, the length of time we will operate under the Chapter 11 Cases;

the potential adverse effects of disruption from the Chapter 11 Cases on us, our liquidity and/or results of operations, and on the interests of our various constituents making it more difficult to maintain business and operational relationships, retain key executives and maintain various licenses and approvals necessary for us to conduct our business;

risk and uncertainties relating to: our ability to complete definitive documentation in connection with any
financing and the amount, terms and conditions of any such financing; and our ability to obtain requisite support for our Ch. 11 Plan from various stakeholders and confirm and consummate that plan in accordance with the terms of the plan support agreement and/or the backstop commitment agreement as described in Part I, Item 1, Financial Statements, Note 1A;

risks associated with our ability to continue as a going concern;

risks related to the trading of our securities on the OTC Pink Market;

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 or to obtain any necessary consents,
waivers or forbearances thereunder;

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

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

1


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

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 CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per common share amounts)
(Unaudited)
 
 
Quarter ended
September 30,
 
Nine months ended
September 30,
 
2019
 
2018
 
2019
 
2018
Operating revenues
 

 
 

 
 

 
 

Oil
$
193

 
$
287

 
$
590

 
$
820

Natural gas
10

 
15

 
36

 
55

NGLs
12

 
36

 
45

 
92

Financial derivatives
32

 
(44
)
 
(34
)
 
(122
)
Total operating revenues
247

 
294

 
637

 
845

 
 
 
 
 
 
 
 
Operating expenses
 

 
 

 
 

 
 

Oil and natural gas purchases

 
3

 

 
3

Transportation costs
23

 
25

 
71

 
76

Lease operating expense
34

 
46

 
101

 
123

General and administrative
38

 
21

 
102

 
68

Depreciation, depletion and amortization
116

 
127

 
304

 
376

Gain on sale of assets

 
(1
)
 

 
(1
)
Impairment charges
458

 

 
458

 

Exploration and other expense
1

 
2

 
3

 
3

Taxes, other than income taxes
12

 
22

 
43

 
63

Total operating expenses
682

 
245

 
1,082

 
711

 
 
 
 
 
 
 
 
Operating (loss) income
(435
)
 
49

 
(445
)
 
134

Other income
4

 
2

 
4

 
2

Gain on extinguishment/modification of debt

 

 
10

 
48

Interest expense
(189
)
 
(95
)
 
(379
)
 
(268
)
Loss before income taxes
(620
)
 
(44
)
 
(810
)
 
(84
)
Income tax expense

 

 

 

Net loss
$
(620
)
 
$
(44
)
 
$
(810
)
 
$
(84
)
 
 
 
 
 
 
 
 
Basic and diluted net income (loss) per common share
 

 
 

 
 

 
 

Net loss
$
(2.48
)
 
$
(0.18
)
 
$
(3.25
)
 
$
(0.34
)
Basic and diluted weighted average common shares outstanding
250

 
248

 
250

 
247


See accompanying notes.


3


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

 
 

Current assets
 

 
 

Cash and cash equivalents
$
188

 
$
27

Restricted cash
1

 

Accounts receivable
 

 
 

Customer, net of allowance of less than $1 in 2019 and 2018
118

 
164

Other, net of allowance of $1 in 2019 and 2018
15

 
66

Materials and supplies
46

 
22

Derivative instruments
46

 
101

Other
38

 
5

Total current assets
452

 
385

Property, plant and equipment, at cost
 

 
 

Oil and natural gas properties
7,320

 
7,344

Other property, plant and equipment
71

 
81

 
7,391

 
7,425

Less accumulated depreciation, depletion and amortization
3,915

 
3,651

Total property, plant and equipment, net
3,476

 
3,774

Other assets
 

 
 

Derivative instruments
12

 
13

Unamortized debt issue costs - revolving credit facility

 
8

Operating lease assets and other
22

 
1

 
34

 
22

Total assets
$
3,962

 
$
4,181

 
See accompanying notes.

4


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

 
 

Current liabilities
 

 
 

Current portion of long-term debt
$
4,882

 
$
58

Owner and royalties payable
76

 
144

Accounts payable and accrued expenses
122

 
105

Accrued interest
161

 
70

Accrued legal and other reserves
37

 
47

Other current liabilities
23

 
16

Total current liabilities
5,301

 
440

 
 
 
 
Long-term debt, net of debt issue costs

 
4,285

Other long-term liabilities
 

 
 

Asset retirement obligations
41

 
39

Lease obligations and other
22

 
16

Total non-current liabilities
63

 
4,340

 
 
 
 
Commitments and contingencies (Note 8)


 


 
 
 
 
Stockholders’ equity
 

 
 

Class A shares, $0.01 par value; 550 million shares authorized; 256 million shares issued and 255 million outstanding at September 30, 2019; 256 million shares issued and outstanding at December 31, 2018
3

 
3

Class B shares, $0.01 par value; less than one million shares authorized, issued and outstanding at September 30, 2019 and December 31, 2018

 

Preferred stock, $0.01 par value; 50 million shares authorized; no shares issued or outstanding

 

Treasury stock (at cost), one million and less than one million shares at September 30, 2019 and December 31, 2018, respectively
(1
)
 
(1
)
Additional paid-in capital
3,543

 
3,536

Accumulated deficit
(4,947
)
 
(4,137
)
Total stockholders’ equity
(1,402
)
 
(599
)
Total liabilities and equity
$
3,962

 
$
4,181

 
See accompanying notes.


5


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

 
 

Net loss
$
(810
)
 
$
(84
)
Adjustments to reconcile net loss to net cash provided by operating activities
 

 
 

Depreciation, depletion and amortization
304

 
376

Gain on sale of assets

 
(1
)
Impairment charges
458

 

Gain on extinguishment/modification of debt
(10
)
 
(48
)
Write-off of debt discount and deferred issue costs
90

 

Other non-cash income items
20

 
22

Asset and liability changes
 

 
 

Accounts receivable
96

 
(68
)
Owner and royalties payable
(68
)
 
35

Accounts payable and accrued expenses
(3
)
 
(18
)
Derivative instruments
56

 
87

Accrued interest
91

 
50

Other asset changes
(55
)
 
15

Other liability changes
(20
)
 
14

Net cash provided by operating activities
149

 
380

 
 
 
 
Cash flows from investing activities
 

 
 

Cash paid for capital expenditures
(422
)
 
(559
)
Proceeds from the sale of assets

 
175

Cash paid for acquisitions
(18
)
 
(275
)
Net cash used in investing activities
(440
)
 
(659
)
 
 
 
 
Cash flows from financing activities
 

 
 

Proceeds from issuance of long-term debt
923

 
1,805

Repayments and repurchases of long-term debt
(468
)
 
(1,431
)
Fees/costs on debt exchange

 
(62
)
Debt issue costs

 
(21
)
Other
(2
)
 
(1
)
Net cash provided by financing activities
453

 
290

 
 
 
 
Change in cash, cash equivalents and restricted cash
162

 
11

 
 

 
 

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

 
45

Cash, cash equivalents and restricted cash - end of period
$
189

 
$
56

 
See accompanying notes.


6


EP ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(In millions)
(Unaudited)
 
 
Class A Stock
 
Class B Stock
 
Treasury Stock
 
Additional
Paid-in Capital
 
Retained Earnings (Accumulated Deficit)
 
 
 
Shares
 
Amount
 
Shares
 
Amount
 
 
 
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2017
252

 
$
3

 
0.3

 
$

 
$
(3
)
 
$
3,526

 
$
(3,134
)
 
$
392

Share-based compensation
(1
)
 

 

 

 
(1
)
 
1

 

 

Net income

 

 

 

 

 

 
18

 
18

Balance at March 31, 2018
251

 
$
3

 
0.3

 
$

 
$
(4
)
 
$
3,527

 
$
(3,116
)
 
$
410

Share-based compensation
6

 

 

 

 
4

 
(1
)
 

 
3

Net loss

 

 

 

 

 

 
(58
)
 
(58
)
Balance at June 30, 2018
257

 
$
3

 
0.3

 
$

 
$

 
$
3,526

 
$
(3,174
)
 
$
355

Share-based compensation

 

 

 

 

 
6

 

 
6

Net loss

 

 

 

 

 

 
(44
)
 
(44
)
Balance at September 30, 2018
257

 
$
3

 
0.3

 
$

 
$

 
$
3,532

 
$
(3,218
)
 
$
317

Share-based compensation
(1
)
 

 

 

 
(1
)
 
4

 

 
3

Net loss

 

 

 

 
 
 

 
(919
)
 
(919
)
Balance at December 31, 2018
256

 
$
3

 
0.3

 
$

 
$
(1
)
 
$
3,536

 
$
(4,137
)
 
$
(599
)
Share-based compensation

 

 

 

 

 
3

 

 
3

Net loss

 

 

 

 

 

 
(140
)
 
(140
)
Balance at March 31, 2019
256

 
$
3

 
0.3

 
$

 
$
(1
)
 
$
3,539

 
$
(4,277
)
 
$
(736
)
Share-based compensation
(1
)
 

 

 

 

 
1

 

 
1

Net loss

 

 

 

 

 

 
(50
)
 
(50
)
Balance at June 30, 2019
255

 
$
3

 
0.3

 
$

 
$
(1
)
 
$
3,540

 
$
(4,327
)
 
$
(785
)
Share-based compensation

 

 

 

 

 
3

 

 
3

Net loss

 

 

 

 

 

 
(620
)
 
(620
)
Balance at September 30, 2019
255

 
$
3

 
0.3

 
$

 
$
(1
)
 
$
3,543

 
$
(4,947
)
 
$
(1,402
)
 
See accompanying notes.


7


EP ENERGY CORPORATION
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 September 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.

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 8.


1A. Voluntary Reorganization under Chapter 11 Proceedings

Formation of Special Committee. In the second quarter 2019, our Board of Directors (the “Board”) appointed a special committee (the “Special Committee”) of three independent directors that are not affiliated with the Sponsors (affiliates of Apollo Global Management, Inc. (“Apollo”), Riverstone Holdings LLC, Access Industries, Inc. (“Access”) and Korea National Oil Corporation, collectively, the “Sponsors”), and we engaged financial and legal advisors to consider a number of potential actions and evaluate certain strategic alternatives to address our liquidity and balance sheet issues.
Covenant Violations, Forbearance, and Chapter 11 Proceedings. On August 15, 2019, we did not make the approximately $40 million cash interest payment due and payable with respect to the 8.000% Senior Secured Notes due 2025 (the “2025 1.5 Lien Notes”). On September 3, 2019, we did not make the approximately $7 million cash interest payment due and payable with respect to the 7.750% Senior Notes due 2022 (the “2022 Unsecured Notes”). Our failure to make these interest payments within thirty days after they were due and payable resulted in an event of default under the respective indentures governing the 2025 1.5 Lien Notes and 2022 Unsecured Notes. Each event of default under the indentures noted above also resulted in a cross-default under the Reserve-Based Facility (RBL Facility).

On September 14, 2019, we entered into forbearance agreements, extending through October 3, 2019, with (i) certain beneficial owners and/or investment advisors or managers of discretionary accounts for the beneficial owners of greater than 70% of the aggregate principal amount of the outstanding 2025 1.5 Lien Notes (collectively, the “Noteholders”) and (ii) certain lenders holding greater than a majority of the revolving commitments under our RBL Facility and the administrative agent and collateral agent under the RBL Facility (collectively, the “RBL Forbearing Parties”) pursuant to which each Noteholder and RBL Forbearing Party temporarily agreed to forbear from exercising any rights or remedies they may have occurred in respect of the failure to make the $40 million cash interest payment.
On October 3, 2019, we and certain of our direct and indirect subsidiaries (collectively with the Company, the “Debtors”) filed voluntary petitions (the “Chapter 11 Cases”) in the United States Bankruptcy Court for the Southern District of

8


Texas (the “Bankruptcy Court”) seeking relief under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”). To ensure ordinary course operations, the Debtors have obtained approval from the Bankruptcy Court for a variety of “first day” motions, including motions to obtain customary relief intended to assure our ability to continue our ordinary course operations after the filing date. In addition, the Debtors have received authority to use cash collateral of the lenders under the RBL Facility.
The commencement of the Chapter 11 Cases constituted an immediate event of default, and caused the automatic and immediate acceleration of all debt outstanding under or in respect of a number of our instruments and agreements relating to our direct financial obligations, including our RBL Facility and indentures governing the 2025 1.5 Lien Notes, 7.750% Senior Secured Notes due 2026, 2024 1.5 Lien Notes, 9.375% Senior Secured Notes due 2024, 9.375% Senior Notes due 2020, 7.750% Senior Unsecured Notes due 2022 and 6.375% Senior Notes due 2023 (collectively, the “Senior Notes”). Any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Chapter 11 Cases and the creditors’ rights of enforcement in respect of the Senior Notes and the RBL Facility are subject to the applicable provisions of the Bankruptcy Code.

Plan Support Agreement. On October 18, 2019, the Debtors entered into a plan support agreement (the “PSA”) to support a restructuring on the terms of a chapter 11 plan (the “Plan”) with holders of approximately 52.0% of the 8.000% Senior Secured Notes due 2024 (the “2024 1.5 Lien Notes”) and approximately 79.3% of the 9.375% Senior Secured Notes due 2024 and the 2025 1.5 Lien Notes issued, in each case, by EP Energy LLC and Everest Acquisition Finance Inc. The holders of these notes included affiliates of, or funds managed by, Elliott Management Corporation, Apollo (together with Elliott, the “Initial Supporting Noteholders”), Access, and Avenue Capital Group (collectively, with the Initial Supporting Noteholders and Access, the “Supporting Noteholders”). Pursuant to the PSA, the Plan will be implemented in accordance with the plan term sheet annexed to the PSA, which is premised on (i) an equity rights offering (the “Rights Offering”), $463 million of which is backstopped by the Supporting Noteholders under a backstop commitment agreement (the “BCA”), and (ii) an approximately $629 million exit facility for which, as of October 18, 2019, over 90% of the lenders under the RBL Facility have committed to provide support, and which the RBL Facility and proposed DIP Facility discussed below will convert into on the effective date of the Plan. Capitalized terms used in this section but not otherwise defined shall have the meanings ascribed to such terms in the PSA (noted as an exhibit to this filing) or as noted below in the Backstop Commitment Agreement or Debtor-in-Possession Agreement discussions.     
The PSA contemplates a Plan which would provide for the following treatment:
a)
Holders of RBL Claims will receive their Pro Rata share of the Exit Facility as a first lien, second-out term loan; provided that each holder of an Allowed RBL Claim that elects to participate in the Exit Facility by the Voting Deadline will receive its Pro Rata share (with the holders of Allowed DIP Claims) of first lien, first-out revolving loans and letter of credit participations under the Exit Credit Agreement.

b)
Holders of 1.125L Notes Claims will be reinstated in the principal amount of $1 billion and Holders of 1.25L Notes Claims will be reinstated in the principal amount of $500 million, provided that the Debtors may, with the consent of the Initial Supporting Noteholders, deliver a notice of redemption with respect to, or otherwise voluntarily prepay (including by way of tender offer), a portion of these notes, or (ii) receive new notes on terms acceptable to the Initial Supporting Noteholders and the Company.

c)
Holders of 1.5L Notes Claims will receive, on account of the secured portion of such 1.5L Notes Claims, their pro rata share of (i) 99.0% of the New Common Shares, subject to dilution by the Rights Offering Shares, the Private Placement, the Commitment Premium, the Jeter and EIP Shares, and (ii) the right to participate in the Rights Offering.

d)
Holders of Unsecured Claims will receive their pro rata share of 1.0% of the New Common Shares, subject to dilution by the Rights Offering Shares, the Commitment Premium, the Private Placement, the Jeter and EIP Shares (as defined below); provided, that a convenience class may be established under the Plan (with such Plan provisions being acceptable to the Initial Supporting Noteholders) to provide distributions up to an aggregate amount in Cash to be specified under the Plan.

e)
Holders of existing Class A common stock and restricted stock prior to reorganization will receive, on account of available assets of the Company, their pro rata share of $500,000 in cash.

The Plan will also provide for the following additional terms:

9


a)
Apollo and Access may contribute their equity interests in Wolfcamp Drillco Operating L.P. to the reorganized debtors in exchange for New Common Shares (the “Jeter Shares”), subject to the agreement of the Company, Access, and the Initial Supporting Noteholders.

b)
The Company may consummate a private placement of New Common Shares, subject to dilution by the Jeter and EIP Shares, for an aggregate purchase price of up to $75 million, in cash.

c)
Establishment of a post-emergence employee incentive plan (the “EIP”) on the effective date of the Plan. All awards issued under the EIP, including restricted stock units, options, New Common Shares, or other rights exercisable, exchangeable, or convertible into New Common Shares (“EIP shares”) will be dilutive of all other equity interests in the reorganized debtors in accordance with the Plan. Ten percent of the New Common Shares, on a fully diluted basis, shall be reserved for issuance in connection with the EIP.

The PSA contains certain covenants on the part of the Company and the Supporting Noteholders, including that the Supporting Noteholders vote in favor of the Plan and otherwise facilitate the restructuring transactions, subject to the terms of the PSA. The PSA also provides for termination by each party upon the occurrence of certain events, including without limitation the failure of the Company to achieve certain milestones and the termination of the BCA (discussed further below).
Backstop Commitment Agreement. On October 18, 2019 the Debtors entered into the BCA with the Commitment Parties pursuant to which they agreed to backstop $463 million of the Rights Offering. The BCA is subject to Bankruptcy Court approval. Capitalized terms used in this section but not otherwise defined herein shall have the meanings ascribed to such terms in the BCA noted as an exhibit to this filing.
The Commitment Parties have committed, in connection with the Rights Offering, to (i) exchange $138 million in principal amount of 2025 1.25 Lien Notes for New Common Shares at the Exchange Purchase Price (the "Exchange Transaction") and (ii) purchase additional New Common Shares at the Cash Purchase Price for cash consideration of up to $325 million (reduced dollar for dollar for cash proceeds received in the Rights Offering) (the "Cash Purchase Obligation"). The Special Committee approved entry into the PSA and BCA.
As consideration for their backstop commitment, the Commitment Parties shall be entitled to receive $26 million in the form of New Common Shares issued at the Cash Purchase Price (the “Commitment Premium”). Alternatively, if the BCA is terminated due to certain events specified therein, the Commitment Parties shall be entitled to receive a $26 million cash termination fee (the “Termination Fee”). The Commitment Premium and Termination Fee will be allocated among the Commitment Parties as provided in the BCA.
The Commitment Parties’ obligation to backstop the Rights Offering, and the other transactions contemplated by the BCA, are conditioned upon the satisfaction (or waiver) of all conditions to the effectiveness of the Plan, and other conditions precedent set forth in the BCA, including Bankruptcy Court approval of the BCA. The BCA may be terminated upon the occurrence of certain events, including termination of the PSA and material, uncured breaches by the parties under the BCA.
Debtor-in-Possession Agreement. In connection with the PSA and the Chapter 11 Cases, on October 18, 2019, the Debtors also received an underwritten commitment from certain of the lenders under the RBL Facility to provide (i) for an approximately $315 million Senior Secured Superpriority Debtor-in-Possession Facility (the “DIP Facility”), and (ii) support for an approximately $629 million Senior Secured Revolving Exit Facility (the “Exit Facility”), which will consist of a first-out revolving tranche provided by the lenders under the DIP Facility (whose remaining claims under the RBL Facility will automatically convert into such first-out revolving tranche upon effectiveness of the Exit Facility) and a second-out term loan tranche provided by the lenders under the RBL Facility which are not also lenders under the DIP Facility (whose claims under the RBL Facility will automatically convert into such second-out term loan tranche upon effectiveness of the Exit Facility) (if any). The Exit Facility is anticipated to be effective upon the Debtors’ emergence from the Chapter 11 Cases. The proceeds of the Exit Facility may be used to fund distributions under the Plan, for working capital and for other general corporate purposes, to issue letters of credit, for transaction fees and expenses and for fees related to the Debtors’ emergence from the Chapter 11 Cases. The DIP Facility and the Exit Facility are each subject to customary closing conditions and Bankruptcy Court approval.

Ability to Continue as a Going Concern. The significant risks and uncertainties related to the Company’s liquidity and Chapter 11 proceedings described above raise substantial doubt about the Company’s ability to continue as a going concern. For the duration of the Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to a high degree of risks and uncertainty associated with the Chapter 11 proceedings. The outcome of the Chapter 11 process is subject to a high degree of uncertainty and is dependent upon factors that are outside of the Company’s control, including actions of the Bankruptcy Court and the Company’s creditors. There can be no assurance that we will confirm and consummate the Plan under the PSA or complete another plan of reorganization with respect to the Chapter 11 proceedings.

10


Further, the Plan under the PSA, or completion of another plan of reorganization, could materially change the amounts and classifications of assets and liabilities reported in the consolidated financial statements. The accompanying consolidated financial statements have (i) been prepared on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities and other commitments in the normal course of business and (ii) do not include any adjustments to reflect the possible future effects of this uncertainty on the recoverability or classification of recorded asset amounts or the amounts or classifications of liabilities.


2. Impairment Charges

We evaluate capitalized costs related to proved properties upon a triggering event (e.g., a significant continued decline in forward commodity prices or significant reduction to development capital) 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 and/or unproved properties in the future.
As a result of the filing of our Chapter 11 Cases (see Note 1A) and the uncertainties surrounding the availability of financing that would be available to develop our proved undeveloped reserves, we performed an impairment assessment of our asset groups under ASC 360. As a result, the undiscounted future cash flows related to our Northeastern Utah (NEU) proved properties were not in excess of the related carrying value of the asset. Accordingly, we have recorded a non-cash impairment charge for both the quarter and nine months ended September 30, 2019 of approximately $458 million related to this asset group, reflecting a reduction in the net book value of the proved property in this area to its estimated fair value.

3. Income Taxes
 
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 nine months ended September 30, 2019 and 2018, our effective tax rates were approximately 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 $135 million and $10 million, for the quarters ended September 30, 2019 and 2018, respectively, and by $174 million and $18 million for the nine months ended September 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 $1,031 million as of September 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 2016 U.S. tax return.



11


4. Earnings Per Share
 
We exclude potentially dilutive securities from the determination of diluted earnings per share (as well as their related income statement impacts) when their impact on net income per common share is antidilutive. Potentially dilutive securities consist of our stock options, restricted stock and performance share unit awards. For both the quarters and nine months ended September 30, 2019 and 2018, we incurred net losses and accordingly excluded all potentially dilutive securities from the determination of diluted earnings per share as their impact on loss per common share was antidilutive.

5. 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 September 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:
 
September 30, 2019
 
December 31, 2018
 
Carrying
 Amount
 
Fair
 Value
 
Carrying
 Amount
 
Fair
 Value
 
(in millions)
Current portion of long-term debt
$
4,882

 
$
1,684

 
$
58

 
$
44

 
 
 
 
 
 
 
 
Long-term debt (see Note 7)
$

 
$

 
$
4,380

 
$
2,532

 
 
 
 
 
 
 
 
Derivative instruments
$
58

 
$
58

 
$
114

 
$
114

 
As of September 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 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 September 30, 2019, we had derivative contracts in the form of collars and three-way collars on 15 MMBbls of oil (3 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 6 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 September 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.

12


 
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)
September 30, 2019
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Derivative instruments
$
60

 
$
(2
)
 
$
46

 
$
12

 
$
(2
)
 
$
2

 
$

 
$

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2018
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Derivative instruments
$
116

 
$
(2
)
 
$
101

 
$
13

 
$
(2
)
 
$
2

 
$

 
$


 For the quarters ended September 30, 2019 and 2018, we recorded derivative gains and losses of $32 million and $44 million, respectively. For the nine months ended September 30, 2019 and 2018, we recorded derivative losses of $34 million and $122 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. 

Other Fair Value Considerations. During the quarter and nine months ended September 30, 2019, we recorded a non-cash impairment charge on our proved properties in NEU. The estimate of fair value of our proved oil and natural gas properties used to determine the impairment was estimated using a discounted cash flow model. These estimates represented a Level 3 fair value measurement. Significant Level 3 inputs associated with the calculation of discounted cash flows used in the impairment analysis include management’s estimate of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. See Note 2 for a further discussion of our impairment charge.


6.  Property, Plant and Equipment 
Oil and Natural Gas Properties.  As of September 30, 2019 and December 31, 2018, we had approximately $3.5 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:
 
September 30, 2019
 
December 31, 2018
 
(in millions)
Proved
 
 
 
Eagle Ford
$
4,250

 
$
3,898

Permian
1,791

 
1,787

Northeastern Utah
1,279

 
1,659

Total Proved
7,320

 
7,344

Less accumulated depletion
(3,880
)
 
(3,607
)
Net capitalized costs for oil and natural gas properties
$
3,440

 
$
3,737

Suspended well costs were not material as of September 30, 2019 or December 31, 2018
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 September 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 September 30, 2019 were as follows:

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2019
 
(in millions)
Net asset retirement liability at January 1
$
42

Liabilities settled
(1
)
Accretion expense
3

Net asset retirement liability at September 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 ended September 30, 2019 and 2018 was approximately $2 million, and for the nine months ended September 30, 2019 and 2018 were approximately $5 million and $4 million, respectively.


7. Long-Term Debt
Listed below are our debt obligations as of the periods presented:
 
Interest Rate
 
September 30, 2019
 
December 31, 2018
 
 
 
(in millions)
RBL credit facility - due November 23, 2021(1)
Variable
 
$
602

 
$
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

Unamortized discount and debt issue costs(3)
 
 

 
(95
)
Total debt
 
 
4,882

 
4,343

Current portion of long-term debt(3)
 
 
(4,882
)
 
(58
)
Total long-term debt
 
 
$

 
$
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 December 31, 2018, the effective interest rate for the term loan was 6.21%. In April 2019, we retired the note in full.
(3)
Due to uncertainties at September 30, 2019 regarding default, event of default and cross-default provisions under our indentures and RBL Facility (including those discussed in Note 1A), we reclassified our debt as current and wrote off approximately $90 million in unamortized debt discount and debt issue costs.

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, during the nine months ended September 30, 2019 and 2018, we recorded a net gain on extinguishment/modification of debt of $10 million and $7 million, respectively, primarily related to repurchased debt. In the first quarter of 2019, we paid approximately $40 million in cash to repurchase a total of $50 million in aggregate principal amount of our senior unsecured notes due 2020. In the second quarter of 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.


14


Reserve-based Loan Facility. As of September 30, 2019, we had borrowed the remaining $268 million under our RBL Facility and had no capacity remaining with approximately $27 million of LCs issued and $602 million outstanding under the RBL Facility.

Covenant Violations, Forbearance, and Chapter 11 Proceedings. On August 15, 2019, we did not make the approximately $40 million cash interest payment due with respect to the 2025 1.5 Lien Senior Secured Notes. On September 3, 2019, we did not make the approximately $7 million cash interest payment due with respect to the 2022 Unsecured Notes. Our failure to make these interest payments within thirty days after they were due and payable resulted in an event of default under the respective indentures governing the 2025 1.5 Lien Notes and 2022 Unsecured Notes. Each event of default under the indentures noted above also resulted in a cross-default under the RBL Facility.
On September 14, 2019, we entered into forbearance agreements, extending through October 3, 2019, with the Noteholders and the RBL Forbearing Parties, pursuant to which each Noteholder and RBL Forbearing Party temporarily agreed, subject to certain terms and conditions, to forbear from exercising any rights or remedies they may have in respect of the failure to make the approximately $40 million cash interest payment.

On October 3, 2019, the Debtors filed the Chapter 11 Cases in the Bankruptcy Court seeking relief under the Bankruptcy Code. The commencement of the Chapter 11 Cases constituted an immediate event of default, and caused the automatic and immediate acceleration of all debt outstanding under or in respect of a number of our instruments and agreements relating to our direct financial obligations, including the RBL Facility and indentures governing the Senior Notes. Any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Chapter 11 Cases and the creditors’ rights of enforcement in respect of the Senior Notes and the RBL Facility are subject to the applicable provisions of the Bankruptcy Code. For a further discussion of the Chapter 11 Cases, see Note 1A.


8. Commitments and Contingencies
 
Chapter 11 Proceedings
On October 3, 2019, the Debtors filed the Chapter 11 Cases in the Bankruptcy Code seeking relief under the Bankruptcy Code. We expect to continue operations in the normal course during the pendency of the Chapter 11 Cases. In addition, commencement of the Chapter 11 Cases automatically stayed all of the proceedings and actions against the Company, including those noted below. For a further discussion of the Chapter 11 Cases, see Note 1A.
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 September 30, 2019, we had approximately $26 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, Riverstone Holdings LLC, Access 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 September 30, 2019, we had accrued $21 million related to 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

15


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. We settled this matter in July 2019 for $3 million.
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 September 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 September 30, 2019, we had approximately $12 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 September 30, 2019, interest and depreciation expense associated with our finance leases was approximately $1 million and less than $1 million, respectively, and related cash payments were approximately $1

16


million. For the nine months ended September 30, 2019, interest and depreciation expense associated with our finance leases were approximately $3 million and $2 million , respectively, 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 September 30, 2019, operating lease costs and related cash payments were approximately $3 million and $4 million, respectively, and $8 million and $7 million, respectively, for the nine months ended September 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 the quarter and nine months ended September 30, 2019, variable lease costs were approximately $1 million and $2 million, respectively. 

Short-term lease costs for the quarter and nine months ended September 30, 2019 were approximately $3 million and $18 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:
 
 
September 30, 2019
 
 
(in millions)
Operating lease assets(1)(4)
 
$
21

Finance lease assets(2)
 
10

        Total lease assets
 
$
31

 
 
 
Operating leases(3)(4)
 
 
   Current liability
 
$
11

   Noncurrent liability
 
10

        Total operating lease liability
 
$
21

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
 
9.24
%
   Finance leases
 
26.52
%
 
(1)
Operating lease assets are reflected in Operating lease assets and other in our consolidated balance sheet as of September 30, 2019.
(2)
Finance lease assets are reflected in Other property, plant and equipment in our consolidated balance sheet as of September 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 September 30, 2019.
(4)
Upon adoption of ASU 2016-02 effective January 1, 2019, we recognized operating leases of approximately $10 million. For the nine months ended September 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 September 30, 2019, were as follows:


17


 
 
Operating Leases
 
Finance Leases
 
 
(in millions)
2019
 
$
3

 
$
1

2020
 
10

 
5

2021
 
3

 
5

2022
 
2

 
5

Thereafter
 
6

 
2

Total
 
$
24

 
$
18

Less: imputed interest
 
(3
)
 
(7
)
   Present value of operating and finance lease obligations
 
$
21

 
$
11


9. Incentive Compensation
Long-term Incentive Compensation
Our 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 LTI awards as general and administrative expense over the requisite service period. Pre-tax compensation expense related to all of our LTI awards (both equity and liability based), net of the impact of forfeitures, was approximately $2 million and $5 million for the quarters ended September 30, 2019 and 2018, respectively, and $7 million and $10 million for the nine months ended September 30, 2019 and 2018, respectively. As of September 30, 2019, we had unrecognized compensation expense of $13 million of which we will recognize $2 million during the remainder of 2019 and $11 million thereafter.

Restricted Stock. A summary of the changes in our non-vested restricted shares for the nine months ended September 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
 
(1,114,001
)
 
$
4.95

Forfeited
 
(905,338
)
 
$
2.46

Non-vested at September 30, 2019
 
5,143,995

 
$
2.20


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 September 30, 2019, we had a total of 1,480,260 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 September 30, 2019, our consolidated balance sheet reflects a deferred charge in the amount of approximately $15 million related to the KERP. For accounting purposes, deferred expense is being amortized over the 13 month term of the KERP agreement. During the quarter and nine months ended September 30, 2019, we recorded $5 million and $6 million, respectively, in expense related to the KERP.

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10. Related Party Transactions
 
Chapter 11 Proceedings. As of September 30, 2019, affiliates of Apollo held approximately $675 million of the aggregate outstanding principal amount of approximately $2,092 million of our 9.375% 1.5 Lien Notes due 2024 and 2025 1.5 Lien Notes, and approximately $21 million of the outstanding principal amount of $500 million of our 2024 1.25 Lien Notes. As of September 30, 2019, affiliates of Access held approximately $48 million of our 1.5 Lien Notes. In connection with the Chapter 11 Cases, on October 18, 2019, we entered into the (i) PSA, to support a restructuring on the terms of the Plan described therein, and (ii) BCA, pursuant to which the Commitment Parties agreed to backstop the Rights Offering, in each case, with holders of certain of our debt, including affiliates of, or funds managed by, Apollo and Access. For a discussion of the Chapter 11 Cases as well as the PSA, BCA and other agreements, refer to Note 1A.

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) and indirectly through Access (through an indirect minority ownership interest in the Investor). At September 30, 2019 and December 31, 2018, we had accounts receivable of $1 million and $47 million, respectively, and payables to our owner of $6 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.

19



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 Corporation and each of its consolidated subsidiaries.
 
Our Business
Overview.  We are an independent exploration and production company engaged in the acquisition and development of unconventional onshore oil and natural gas properties in the United States.  We operate through a diverse base of producing assets 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. 
Recent Developments - Chapter 11 Proceedings. On October 3, 2019, the Debtors filed the Chapter 11 Cases in the Bankruptcy Court seeking relief under the Bankruptcy Code. We expect to continue operations in the normal course during the pendency of the Chapter 11 Cases. To ensure ordinary course operations, the Debtors have obtained approval from the Bankruptcy Court for a variety of “first day” motions, including motions to obtain customary relief intended to assure our ability to continue our ordinary course operations after the filing date. In addition, the Debtors have received authority to use cash collateral of the lenders under the Reserve-Based Loan Facility (RBL Facility). For a further discussion of the Chapter 11 Cases and related matters, see Liquidity and Capital Resources and Part I, Item 1, Financial Statements, Notes 1A, 7 and 8.
Strategy. 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 the second quarter 2019, we had 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 Statements, Note 10. 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 September 30, 2019, we have drilled and completed 51 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

20


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.

 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 September 30, 2019.
 
 
2019
 
2020
 
 
Volumes(1)
 
Average
Price(1)
 
Volumes(1)
 
Average
Price(1)
Oil
 
 

 
 

 
 
 
 
Collars
 
 
 
 
 
 
 
 
Ceiling - WTI
 
368

 
$
69.78

 

 
$

Floors - WTI
 
368

 
$
57.50

 

 
$

Three Way Collars
 
 
 
 
 
 
 
 
Ceiling - WTI
 
3,036

 
$
66.01

 
11,712

 
$
65.11

Floors - WTI
 
3,036

 
$
55.76

 
11,712

 
$
55.90

 Sub-Floor - WTI
 
3,036

 
$
45.00

 
11,712

 
$
45.00

Basis Swaps
 
 
 
 
 
 
 
 
Midland vs. Cushing(2) 
 
368

 
$
(5.23
)
 
1,464

 
$
0.46

NYMEX Roll(3) 
 
184

 
$
0.25

 

 
$

Natural Gas
 
 
 
 
 
 
 
 
Fixed Price Swaps
 
3

 
$
3.01

 

 
$

Collars
 
 
 
 
 
 
 
 
Ceiling
 
3

 
$
4.26

 

 
$

       Floors
 
3

 
$
2.75

 

 
$

 
(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 September 30, 2019, the average forward price of oil was $53.84 per barrel of oil for the remainder of 2019 and $51.46 per barrel of oil for 2020.

During the nine months ended September 30, 2019, we settled commodity index hedges on approximately 98% of our oil production, 74% of our total liquids production and 62% of our natural gas production at average floor prices of $55.93 per barrel of oil and $2.86 per MMBtu of natural gas, respectively. As of September 30, 2019, approximately 100% of our future

21


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.


22


Liquidity and Capital Resources

Overview. As of September 30, 2019, our primary sources of liquidity are cash generated by our operations and borrowings under our RBL Facility which matures in 2021. Our primary uses of cash are capital expenditures, debt service, including interest, and working capital requirements. As of September 30, 2019, our available liquidity was $188 million.

Chapter 11 Proceedings. In the second quarter 2019, our Board of Directors (the “Board”) appointed a special committee (the “Special Committee”) of three independent directors that are not affiliated with the Sponsors (affiliates of Apollo Global Management, Inc. (“Apollo”), Riverstone Holdings LLC, Access Industries, Inc. (“Access”) and Korea National Oil Corporation, collectively, the “Sponsors”), and we engaged financial and legal advisors to consider a number of potential actions and evaluate certain strategic alternatives to address our liquidity and balance sheet issues.

On August 15, 2019, we did not make the approximately $40 million cash interest payment due and payable with respect to the 8.000% Senior Secured Notes due 2025 (the “2025 1.5 Lien Notes”). On September 3, 2019, we did not make the approximately $7 million cash interest payment due and payable with respect to the 7.750 Senior Notes due 2022 (the “2022 Unsecured Notes”). Our failure to make these interest payments within thirty days after it they were due and payable resulted in an event of default under the respective indentures governing the 2025 1.5 Lien Notes and 2022 Unsecured Notes. Each event of default under the indentures noted above also resulted in a cross-default under the RBL Facility. On September 14, 2019, we entered into forbearance agreements with the Noteholders and the RBL Forbearing Parties pursuant to which each Noteholder and RBL Forbearing Party temporarily agreed to forbear from exercising any rights or remedies they may have in respect of the failure to make the $40 million cash interest payment. The forbearance period was subsequently extended until October 3, 2019, at which time the Debtors filed the Chapter 11 Cases in the Bankruptcy Court seeking relief under the Bankruptcy Code.

The commencement of the Chapter 11 Cases constituted an immediate event of default, and caused the automatic and immediate acceleration of all debt outstanding under or in respect of a number of our instruments and agreements relating to our direct financial obligations, including our RBL Facility and indentures governing the 2025 1.5 Lien Notes, 7.750% Senior Secured Notes due 2026, 2024 1.5 Lien Notes, 9.375% Senior Secured Notes due 2024, 9.375% Senior Notes due 2020, 7.750% Senior Unsecured Notes due 2022 and 6.375% Senior Notes due 2023 (collectively, the “Senior Notes”). Any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Chapter 11 Cases and the creditors’ rights of enforcement in respect of the Senior Notes and the RBL Facility are subject to the applicable provisions of the Bankruptcy Code.

On October 18, 2019, the Debtors entered into the PSA with the Supporting Noteholders, to support a restructuring on the terms of the Plan premised on (i) the equity rights offering of up to $475 million (the “Rights Offering”), $463 million of which is backstopped by the Commitment Parties, and (ii) an approximately $629 million exit facility for which, as of October 18, 2019, over 90% of the lenders under the RBL Facility have committed to provide support, and which the RBL Facility and proposed DIP Facility (as defined below) will convert into on the effective date of the Plan.

As part of the restructuring, the Company may also consummate a private placement of New Common Shares, subject to dilution by the Jeter Shares and EIP Shares, for an aggregate purchase price of up to $75 million, in cash, on terms acceptable to the Company and Initial Supporting Noteholders. In addition, Apollo and Access may contribute their equity interests in Wolfcamp Drillco Operating L.P. to the Reorganized Debtors in exchange for the Jeter Shares, subject to the agreement of the Company, Access, and the Initial Supporting Noteholders.

As more fully disclosed in Part I, Item 1, Financial Statements, Note 1A, the PSA contemplates a Plan which would provide for the treatment of holders of certain claims and existing equity interests. The Plan will also provide for the establishment of a post-emergence employee incentive plan on the effective date of the Plan.

In connection with the PSA and the Chapter 11 Cases, the Debtors have received an underwritten commitment from certain of the lenders under the RBL Facility to provide (i) for the for an approximately $315 million Senior Secured Superpriority Debtor-in-Possession Facility, and (ii) support for the $629 million Senior Secured Revolving Exit Facility, arranged by J.P. Morgan Chase Bank, N.A. The DIP Facility is intended to be utilized prior to the Debtors’ emergence from the Chapter 11 Cases. The Exit Facility is anticipated to be effective upon the Debtors’ emergence from the Chapter 11 Cases. The proceeds of the Exit Facility may be used to fund distributions under the Plan, for working capital and for other general corporate purposes, to issue letters of credit, for transaction fees and expenses and for fees related to the Debtors’ emergence from the Chapter 11 Cases. The DIP Facility and the Exit Facility are each subject to customary closing conditions, and Bankruptcy Court approval.


23


We expect to continue operations in the normal course during the pendency of the Chapter 11 Cases. To ensure ordinary course operations, the Debtors have obtained approval from the Bankruptcy Court for a variety of “first day” motions, including motions to obtain customary relief intended to assure our ability to continue our ordinary course operations after the filing date. In addition, the Debtors have received authority to use cash collateral of the lenders under the RBL Facility.
    
However, for the duration of the Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to a high degree of risk and uncertainty associated with the Chapter 11 proceedings. The outcome of the Chapter 11 is dependent upon factors that are outside of the Company’s control, including actions of the Bankruptcy Court and the Company’s creditors. The significant risks and uncertainties related to the Company’s liquidity and Chapter 11 proceedings described above raise substantial doubt about the Company’s ability to continue as a going concern. There can be no assurance that we will confirm and consummate the Plan under the PSA or complete another plan of reorganization with
respect to the Chapter 11 proceedings.

For a further discussion of all Chapter 11 related matters, including, but not limited to the PSA, BCA, DIP Facility, and Exit Facility, see Part I, Item 1, Financial Statements, Note 1A.

Capital Expenditures.  Our capital expenditures and average drilling rigs by area for the nine months ended September 30, 2019 were:
 
Capital
Expenditures(1)
(in millions)
 
Average Drilling
Rigs
Eagle Ford Shale
$
348


2.3

Northeastern Utah
92


1.6

Permian
4



Total
$
444


3.9

   Acquisition capital
$
18

 
 
Total Capital Expenditures
$
462

 
 
 
(1)
Represents accrual-based capital expenditures.

    
    

24


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

 
 

Operating activities
 

 
 

Net loss
$
(810
)
 
$
(84
)
Gain on sale of assets

 
(1
)
Gain on extinguishment/modification of debt
(10
)
 
(48
)
Write-off of debt discount and deferred issue costs
90

 

Other income adjustments
782

 
398

Changes in assets and liabilities
97

 
115

Total cash flow from operations
149

 
380

 
 
 
 
Investing activities
 

 
 

Proceeds from the sale of assets

 
175

Cash inflows from investing activities

 
175

 


 


Financing activities
 

 
 

Proceeds from issuance of long-term debt
923

 
1,805

Cash inflows from financing activities
923

 
1,805

 
 
 
 
Total cash inflows
$
1,072

 
$
2,360

 
 
 
 
Cash Outflows
 

 
 

Investing activities
 

 
 

Capital expenditures
$
422

 
$
559

Cash paid for acquisitions
18

 
275

Cash outflows from investing activities
440

 
834

 


 


Financing activities
 

 
 

Repayments and repurchases of long-term debt
468

 
1,431

Fees/costs on debt exchange

 
62

Debt issue costs

 
21

Other
2

 
1

Cash outflows from financing activities
470

 
1,515

 
 
 
 
Total cash outflows
$
910

 
$
2,349

 
 
 
 
Net change in cash, cash equivalents and restricted cash
$
162

 
$
11



25


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

 
 

Eagle Ford
32.9

 
37.0

Northeastern Utah
15.5

 
17.2

Permian
21.6

 
26.8

Total
70.0

 
81.0

 
 
 
 
Oil (MBbls/d)
 
 
 
Eagle Ford
21.8

 
25.2

Northeastern Utah
10.1

 
11.8

Permian
6.4

 
9.4

Total
38.3

 
46.4

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

 
35

Northeastern Utah
32

 
32

Permian
48

 
56

Total
113

 
123

 
 
 
 
NGLs (MBbls/d)
 
 
 
Eagle Ford
5.6

 
6.0

Northeastern Utah

 

Permian
7.2

 
8.1

Total
12.8

 
14.1

 
(1)
Production volume excludes 22 MMcf/d of reinjected gas volumes used in operations during the nine months ended September 30, 2019.

Production Summary. For the nine months ended September 30, 2019 compared to the same period in 2018, (i) Eagle Ford equivalent volumes decreased 4.1 MBoe/d or (approximately 11%) due to fewer wells placed on production in the second half of 2018 through 2019, (ii) NEU equivalent volumes decreased 1.7 MBoe/d or (approximately 10%) due to reduced drilling activity in 2019, and (iii) Permian equivalent volumes decreased 5.2 MBoe/d or (approximately 19%) 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 and more reinjected gas as compared to the same period in 2018.

Drilling Summary. During the nine months ended September 30, 2019, we (i) frac’d (wells fracture stimulated) 54 gross wells in the Eagle Ford, all of which came online for a total of 847 net operated wells, and (ii) frac’d 11 gross wells in NEU, 10 of which came online for a total of 345 net operated wells. We did not frac any wells in the Permian during the nine months ended September 30, 2019, and currently operate 353 net wells in the area. As of September 30, 2019, we also had a total of 39 gross wells in progress, of which 37 were drilled, but not completed across our programs.

    

26


Results of Operations
 
The information in the table below provides a summary of our financial results.
 
Quarter ended
September 30,
 
Nine months ended
September 30,
 
2019
 
2018
 
2019
 
2018
 
(in millions)
Operating revenues
 

 
 

 
 

 
 

Oil
$
193

 
$
287

 
$
590

 
$
820

Natural gas
10

 
15

 
36

 
55

NGLs
12

 
36

 
45

 
92

Total physical sales
215

 
338

 
671

 
967

Financial derivatives
32

 
(44
)
 
(34
)
 
(122
)
Total operating revenues
247

 
294

 
637

 
845

 
 
 
 
 
 
 
 
Operating expenses
 

 
 

 
 

 
 

Oil and natural gas purchases

 
3

 

 
3

Transportation costs
23

 
25

 
71

 
76

Lease operating expense
34

 
46

 
101

 
123

General and administrative
38

 
21

 
102

 
68

Depreciation, depletion and amortization
116

 
127

 
304

 
376

Gain on sale of assets

 
(1
)
 

 
(1
)
Impairment charges
458

 

 
458

 

Exploration and other expense
1

 
2

 
3

 
3

Taxes, other than income taxes
12

 
22

 
43

 
63

Total operating expenses
682

 
245

 
1,082

 
711

 
 
 
 
 
 
 
 
Operating (loss) income
(435
)
 
49

 
(445
)
 
134

Other income
4

 
2

 
4

 
2

Gain on extinguishment/modification of debt

 

 
10

 
48

Interest expense
(189
)
 
(95
)
 
(379
)
 
(268
)
Loss before income taxes
(620
)
 
(44
)
 
(810
)
 
(84
)
Income tax expense

 

 

 

Net loss
$
(620
)
 
$
(44
)
 
$