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Form 10-Q EP Energy Corp For: Mar 31

May 9, 2019 2:54 PM EDT

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
 
 Form 10-Q
 
 
(Mark One)
 x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 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
 
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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, a “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer o
 
Accelerated filer x
Non-accelerated filer o
 
Smaller reporting company x
Emerging Growth Company o
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Trading Symbol(s)
 
Name of each exchange on which registered
Class A Common Stock,
par value $0.01 per share
 
EPE
 
New York Stock Exchange
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 April 30, 2019: 255,620,292
Class B Common Stock, par value $0.01 per share. Shares outstanding as of April 30, 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
 
We have made statements in this document that constitute forward-looking statements, as that term is defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements include information concerning possible or assumed future results of operations. The words “believe”, “expect”, “estimate”, “anticipate”, “plan”, “intend”, “could”, “should”, “project” and similar expressions will generally identify forward-looking statements. These statements may relate to information or assumptions about:
 
                 capital and other expenditures;
 
                 financing plans;
 
                 capital structure;
 
                 liquidity and cash flow, including the possibility that we may not be able to continue as a going concern beginning
in May 2020 if we are not successful in obtaining the additional necessary liquidity and/or if commodity prices do not appreciably increase;
 
                 pending legal proceedings, claims and governmental proceedings, including environmental matters;
 
                 future economic and operating performance;
 
                 operating income;
 
                 management’s plans; and

                 goals and objectives for future operations.
 
Forward-looking statements are subject to risks and uncertainties. While we believe the assumptions or bases underlying the forward-looking statements are reasonable and are made in good faith, we caution that assumed facts or bases almost always vary from actual results, and these differences can be material, depending upon the circumstances. We cannot assure you that the statements of expectation or belief contained in our forward-looking statements will result or be achieved or accomplished. Important factors that could cause actual results to differ materially from estimates or projections contained in our forward-looking statements are described in our 2018 Annual Report on Form 10-K. There have been no material changes to the risk factors described in the Form 10-K.


1


PART I — FINANCIAL INFORMATION
 
Item 1. Financial Statements


EP ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per common share amounts)
(Unaudited)
 
 
Quarter ended 
 March 31,
 
2019
 
2018
Operating revenues
 

 
 

Oil
$
193

 
$
252

Natural gas
18

 
22

NGLs
18

 
26

Financial derivatives
(95
)
 
(14
)
Total operating revenues
134

 
286

 
 
 
 
Operating expenses
 

 
 

Transportation costs
25

 
25

Lease operating expense
37

 
39

General and administrative
21

 
19

Depreciation, depletion and amortization
94

 
120

Exploration and other expense
1

 
1

Taxes, other than income taxes
11

 
20

Total operating expenses
189

 
224

 
 
 
 
Operating (loss) income
(55
)
 
62

Gain on extinguishment/modification of debt
10

 
41

Interest expense
(95
)
 
(85
)
(Loss) income before income taxes
(140
)
 
18

Income tax expense

 

Net (loss) income
$
(140
)
 
$
18

 
 
 
 
Basic and diluted net income (loss) per common share
 

 
 

Net (loss) income
$
(0.56
)
 
$
0.07

Basic and diluted weighted average common shares outstanding
249

 
247


See accompanying notes.


2


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

 
 

Current assets
 

 
 

Cash and cash equivalents
$
10

 
$
27

Accounts receivable
 

 
 

Customer, net of allowance of less than $1 in 2019 and 2018
145

 
164

Other, net of allowance of $1 in 2019 and 2018
32

 
66

Materials and supplies
26

 
22

Derivative instruments
12

 
101

Prepaid assets
9

 
5

Total current assets
234

 
385

Property, plant and equipment, at cost
 

 
 

Oil and natural gas properties
7,480

 
7,344

Other property, plant and equipment
76

 
81

 
7,556

 
7,425

Less accumulated depreciation, depletion and amortization
3,722

 
3,651

Total property, plant and equipment, net
3,834

 
3,774

Other assets
 

 
 

Derivative instruments
2

 
13

Unamortized debt issue costs - revolving credit facility
7

 
8

Operating lease assets and other
24

 
1

 
33

 
22

Total assets
$
4,101

 
$
4,181

 
See accompanying notes.

3


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

 
 

Current liabilities
 

 
 

Accounts payable
 

 
 

Trade
$
88

 
$
115

Other
140

 
111

Derivative instruments
3

 

Accrued interest
110

 
70

Short-term debt, net of debt issue costs
8

 
58

Other accrued liabilities
54

 
86

Total current liabilities
403

 
440

 
 
 
 
Long-term debt, net of debt issue costs
4,368

 
4,285

Other long-term liabilities
 

 
 

Asset retirement obligations
40

 
39

Lease obligations and other
26

 
16

Total non-current liabilities
4,434

 
4,340

 
 
 
 
Commitments and contingencies (Note 8)


 


 
 
 
 
Stockholders’ equity
 

 
 

Class A shares, $0.01 par value; 550 million shares authorized; 257 million shares issued and 256 million outstanding at March 31, 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 March 31, 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 March 31, 2019 and December 31, 2018, respectively
(1
)
 
(1
)
Additional paid-in capital
3,539

 
3,536

Accumulated deficit
(4,277
)
 
(4,137
)
Total stockholders’ equity
(736
)
 
(599
)
Total liabilities and equity
$
4,101

 
$
4,181

 
See accompanying notes.


4


EP ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)
 
 
Three months ended 
 March 31,
 
2019
 
2018
Cash flows from operating activities
 

 
 

Net (loss) income
$
(140
)
 
$
18

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

 
 

Depreciation, depletion and amortization
94

 
120

Gain on extinguishment/modification of debt
(10
)
 
(41
)
Other non-cash income items
8

 
5

Asset and liability changes
 

 
 

Accounts receivable
52

 
(6
)
Accounts payable
(23
)
 
(15
)
Derivative instruments
103

 
4

Accrued interest
40

 
6

Other asset changes
(7
)
 
7

Other liability changes
(45
)
 
(11
)
Net cash provided by operating activities
72

 
87

 
 
 
 
Cash flows from investing activities
 

 
 

Cash paid for capital expenditures
(125
)
 
(173
)
Proceeds from the sale of assets

 
167

Cash paid for acquisitions
(3
)
 
(223
)
Net cash used in investing activities
(128
)
 
(229
)
 
 
 
 
Cash flows from financing activities
 

 
 

Proceeds from issuance of long-term debt
270

 
460

Repayments and repurchases of long-term debt
(230
)
 
(280
)
Fees/costs on debt exchange

 
(62
)
Other
(1
)
 
(1
)
Net cash provided by financing activities
39

 
117

 
 
 
 
Change in cash, cash equivalents and restricted cash
(17
)
 
(25
)
 
 

 
 

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

 
45

Cash, cash equivalents and restricted cash - end of period
$
10

 
$
20

 
See accompanying notes.


5


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
)
 
See accompanying notes.


6


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 March 31, 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. The results for any interim period are not necessarily indicative of the expected results for the entire year.

Liquidity and Ability to Continue as a Going Concern

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

As previously disclosed, in May 2020, $182 million of our senior unsecured notes will mature. Based on our forecasted EBITDAX, cash on hand, and remaining capacity under our Reserve-Based Loan Facility (RBL Facility), we anticipate that we will not have sufficient liquidity to repay these notes, meet our working capital needs and/or fund our planned capital expenditures as of one year from the filing date of these financial statements without generating additional liquidity through other sources. These factors raise substantial doubt about the Company’s ability to continue as a going concern.

In order to address the potential future liquidity shortfall, we are evaluating certain other sources of incremental liquidity, including additional debt issuances or refinancings and/or asset sales, none of which have been implemented at this time. While the Company believes in the viability of its strategy to generate additional liquidity through one of or a combination of these sources, there is no assurance that our actions will be successful in alleviating the liquidity concerns. Should we not be able to execute on one of or a combination of these liquidity-enhancing actions, we would be unable to continue as a going concern beginning in the second quarter of 2020.

In addition, in the absence of any suitable relief through the actions mentioned above, should we be required to include a going concern qualification in our year-end audit report and audited financial statements for 2019, the disclosure would be considered a default under the RBL Facility, and potentially an event of default if not waived within 30 days after receiving notice of the default from the administrative agent under the RBL Facility. An event of default under the RBL Facility could trigger cross-defaults under our other debt agreements, including our senior secured term loan and our senior secured and unsecured notes, which could also result in the acceleration of those obligations by the lenders thereunder.     

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.


7


2. Acquisitions and Divestitures
 
Acquisitions. In the first quarter of 2018, we completed the acquisition of producing properties and proved undeveloped acreage in the Eagle Ford for approximately $246 million, after customary adjustments. Of the total purchase price, we paid $221 million upon closing during the first quarter of 2018. Our balance sheet reflects the cost of these assets acquired during the year as proved properties.

Divestitures. In the first quarter of 2018, we completed the sale of certain assets in Northeastern Utah (NEU) for approximately $177 million, after customary adjustments. We received cash proceeds of $159 million upon closing. We treated this sale as a normal retirement reflecting the difference between net cash proceeds and the underlying net book value of the assets sold in accumulated depreciation rather than recording a gain on sale of assets.
    
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 of the quarters ended March 31, 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. For the quarters ended March 31, 2019 and 2018, we recorded adjustments to the valuation allowance on our net deferred tax assets, which offset deferred income tax benefit of $30 million and deferred income tax expense of $5 million, 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 $887 million as of March 31, 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.


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 the quarter ended March 31, 2019, 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. For the quarter ended March 31, 2018, less than one million shares are included as dilutive securities in our calculation of diluted earnings per share.
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 March 31, 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:

8


 
March 31, 2019
 
December 31, 2018
 
Carrying
 Amount
 
Fair
 Value
 
Carrying
 Amount
 
Fair
 Value
 
(in millions)
Short-term debt
$
8

 
$
8

 
$
58

 
$
44

 
 
 
 
 
 
 
 
Long-term debt (see Note 7)
$
4,460

 
$
2,166

 
$
4,380

 
$
2,532

 
 
 
 
 
 
 
 
Derivative instruments
$
11

 
$
11

 
$
114

 
$
114

 
As of March 31, 2019 and December 31, 2018, the carrying amount of cash and cash equivalents, accounts receivable and accounts payable represent fair value because of the short-term nature of these instruments. We hold long-term debt obligations with various terms. We estimated the fair value of debt (representing a Level 2 fair value measurement) primarily based on quoted market prices for the same or similar issuances, considering our credit risk.
 
Oil, Natural Gas and NGLs Derivative Instruments.  We attempt to mitigate a portion of our commodity price risk and stabilize cash flows associated with forecasted sales of oil, natural gas and NGLs through the use of financial derivatives.  As of March 31, 2019, we had derivative contracts in the form of collars and three-way collars on 22 MMBbls of oil (10 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 19 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 March 31, 2019 and December 31, 2018. All of our derivative instruments are subject to master netting arrangements, which provide for the unconditional right of offset for all derivative assets and liabilities with a given counterparty in the event of default. We present assets and liabilities related to these instruments in our consolidated balance sheets as either current or non-current assets or liabilities based on their anticipated settlement date, net of the impact of master netting agreements.  On derivative contracts recorded as assets in the table below, we are exposed to the risk that our counterparties may not perform.
 
Level 2
 
Derivative Assets
 
Derivative Liabilities
 
Gross
Fair Value
 
 
 
Balance Sheet Location
 
Gross 
Fair Value
 
 
 
Balance Sheet Location
 
 
Impact of
Netting
 
Current
 
Non-
current
 
 
Impact of
Netting
 
Current
 
Non-
current
 
(in millions)
 
(in millions)
March 31, 2019
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Derivative instruments
$
18

 
$
(4
)
 
$
12

 
$
2

 
$
(7
)
 
$
4

 
$
(3
)
 
$

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2018
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Derivative instruments
$
116

 
$
(2
)
 
$
101

 
$
13

 
$
(2
)
 
$
2

 
$

 
$


     For the quarters ended March 31, 2019 and 2018, we recorded derivative losses of $95 million and $14 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. 

6.  Property, Plant and Equipment 
Oil and Natural Gas Properties.  As of March 31, 2019 and December 31, 2018, we had approximately $3.8 billion of total property, plant, and equipment, net of accumulated depreciation, depletion and amortization on our consolidated balance sheets, substantially all of which relates to proved oil and natural gas properties.

9


Our capitalized costs related to proved oil and natural gas properties by area were as follows:
 
March 31, 2019
 
December 31, 2018
 
(in millions)
Proved
 
 
 
Eagle Ford
$
4,024

 
$
3,898

Permian
1,788

 
1,787

Northeastern Utah
1,668

 
1,659

Total Proved
7,480

 
7,344

Less accumulated depletion
(3,682
)
 
(3,607
)
Net capitalized costs for oil and natural gas properties
$
3,798

 
$
3,737

Suspended well costs were not material as of March 31, 2019 or December 31, 2018
We evaluate capitalized costs related to proved properties upon a triggering event (e.g., a significant continued decline in forward commodity prices) to determine if an impairment of such properties has occurred. Commodity price declines may cause changes to our capital spending levels, production rates, levels of proved reserves and development plans, which may result in an impairment of the carrying value of our proved properties in the future.

Asset Retirement Obligations. We have legal asset retirement obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We settle these obligations when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue these obligations when we can estimate the timing and amount of their settlement.

In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including a credit-adjusted risk-free rate between 7 percent and 9 percent on a significant portion of our obligations and a projected inflation rate of 2.5 percent. Changes in estimates in the table below represent changes to the expected amount and timing of payments to settle our asset retirement obligations. Typically, these changes primarily result from obtaining new information about the timing of our obligations to plug and abandon oil and natural gas wells and the costs to do so, or reassessing our assumptions in light of changing market conditions. The net asset retirement liability as of March 31, 2019 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability from January 1 through March 31, 2019 were as follows:
 
2019
 
(in millions)
Net asset retirement liability at January 1
$
42

Accretion expense
1

Net asset retirement liability at March 31
$
43

 
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 of the quarters ended March 31, 2019 and 2018 was approximately $1 million.



10


7. Long-Term Debt
Listed below are our debt obligations as of the periods presented:
 
Interest Rate
 
March 31, 2019
 
December 31, 2018
 
 
 
(in millions)
RBL credit facility - due November 23, 2021(1)
Variable
 
$
180

 
$
100

Senior secured term loans:
 
 
 
 
 
Due April 30, 2019(2)
Variable
 
8

 
8

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

 
1,092

Due November 29, 2024
8.00%
 
500

 
500

Due February 15, 2025
8.00%
 
1,000

 
1,000

Due May 15, 2026
7.75%
 
1,000

 
1,000

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

 
232

Due September 1, 2022
7.75%
 
182

 
182

Due June 15, 2023
6.375%
 
324

 
324

Total debt
 
 
4,468

 
4,438

Less short-term debt, net of debt issue costs of less than $1 million
 
 
(8
)
 
(58
)
Total long-term debt
 
 
4,460

 
4,380

Less debt discount and non-current portion of unamortized debt issue costs(3)
 
 
(92
)
 
(95
)
Total long-term debt, net
 
 
$
4,368

 
$
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 March 31, 2019 and December 31, 2018, the effective interest rate for the term loan was 6.08% and 6.21%, respectively. In April 2019, we retired the note in full.
(3)
Includes debt discount of $41 million and $42 million as of March 31, 2019 and December 31, 2018, respectively, associated with our senior secured notes maturing in 2024 and unamortized debt issue costs of $51 million and $53 million as of March 31, 2019 and December 31, 2018, respectively.

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 connection with these repurchases, we recorded a gain on extinguishment of debt of approximately $10 million (including less than $1 million of non-cash expense related to eliminating associated unamortized debt issue costs).

During the first quarter of 2018, we completed an exchange of approximately $1,147 million of our senior unsecured notes maturing in May 2020, September 2022 and June 2023 for new 9.375% senior secured notes maturing in 2024 with an aggregate principal amount of approximately $1,092 million. The exchange transaction was accounted for as a modification of debt for our senior unsecured notes maturing in May 2020 and an extinguishment of debt for our senior unsecured notes maturing in September 2022 and June 2023. In conjunction with the exchange, we incurred approximately $62 million in related fees, recording $48 million as debt discount associated with exchanging our 2020 notes and $12 million in loss on modification of debt. In addition, we recorded a net gain on extinguishment of debt in the amount of $53 million primarily associated with retiring a portion of our 2022 and 2023 notes at less than face value.

Reserve-based Loan Facility. We have a RBL Facility which allows us to borrow funds or issue letters of credit (LCs) up to $629 million. The RBL Facility matures in November 2021. As of March 31, 2019, we had $430 million of capacity remaining with approximately $19 million of LCs issued and $180 million outstanding under the RBL Facility.

The RBL Facility is collateralized by certain of our oil and natural gas properties and has a borrowing base subject to semi-annual redetermination. In April 2019, our RBL borrowing base was reaffirmed at $1.36 billion and total commitments remained at $629 million. Downward revisions of our oil and natural gas reserves volume and value due to declines in commodity prices, the impact of lower estimated capital spending in response to lower prices, performance revisions, or sales of assets or the incurrence of certain types of additional debt, among other items, could cause a reduction of our borrowing base in the future, and these reductions could be significant.


11


Restrictive Provisions/Covenants.  The availability of borrowings under our RBL Facility and our ability to incur additional indebtedness is subject to various financial and non-financial covenants and restrictions, including first lien debt to EBITDAX and current ratio financial covenants. First lien debt for purposes of the covenant only includes amounts borrowed under our RBL Facility. Our current financial covenants require us to maintain a ratio of first lien debt to EBITDAX not exceeding 2.25 to 1.00 and a current ratio (as defined in the RBL Facility) of not less than 1.00 to 1.00. As of March 31, 2019, we were in compliance with our debt covenants.
Under our various debt agreements, we are limited in our ability to repurchase certain tranches of non-RBL Facility debt. Certain other covenants and restrictions, among other things, also limit or place certain conditions on our ability to incur or guarantee additional indebtedness, make restricted payments, pay dividends on equity interests, redeem, repurchase or retire equity interests or subordinated indebtedness, sell assets, make investments, create certain liens, prepay debt obligations, engage in certain transactions with affiliates, and enter into certain hedging agreements.

8. Commitments and Contingencies
 
Legal Matters
 
We and our subsidiaries and affiliates are parties to various legal actions and claims that arise in the ordinary course of our business. For each matter, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of our current matters cannot be predicted with certainty and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure and adjust our accruals accordingly, and these adjustments could be material. As of March 31, 2019, we had approximately $5 million accrued for all outstanding legal matters. 
FairfieldNodal v. EP Energy E&P Company, L.P. On March 3, 2014, Fairfield filed suit against one of our subsidiaries in the 157th District Court of Harris County, Texas, claiming we were contractually obligated to pay a transfer fee of approximately $21 million for seismic licensing, triggered by a change in control with the Sponsors’ (affiliates of Apollo Global Management LLC, Riverstone Holdings LLC, Access Industries and Korea National Oil Corporation, collectively, the Sponsors) acquisition of our predecessor entity in 2012. Prior to the change in control, we had unilaterally terminated the seismic licensing agreements, and we returned the applicable seismic data. Fairfield also claimed EP Energy did not properly maintain the confidentiality of the seismic data and interpretations made from it. In April 2015, the district court granted summary judgment to EP Energy, and Fairfield then appealed. On July 6, 2017, an intermediate court of appeals in Texas reversed the judgment related to the transfer fee and denied rehearing on October 5, 2017. We filed a petition for review in the Texas Supreme Court in December 2017 and filed briefing on the merits in December 2018. At this time, we are unable to estimate the amount or range of possible loss, if any, on this matter.
Weyerhaeuser Company v. Pardee Minerals LLC, et al. On July 5, 2017, Weyerhaeuser filed suit against one of our subsidiaries, among other defendants, in the United States District Court for the Western District of Louisiana.  Weyerhaeuser seeks to recoup the value of production 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. A trial date has been set for December 9, 2019. At this time, we are unable to estimate the amount or range of possible loss, if any, on this matter.
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 $3.8 million for increased lease bonus. The Company'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. On April 5, 2019, the Court circulated a letter agreeing with EP Energy on delay rentals but with MSB on lease bonus. Based on the court’s letter and MSB’s calculation of its net mineral acreage, MSB would be due an additional bonus payment of approximately $41 million. No final

12


order on summary judgment has been signed.  However, both parties intend to appeal to the Fourth Circuit Court of Appeals in San Antonio when a final order has been signed. As of March 31, 2019, we have accrued $3.8 million related to this matter.
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 March 31, 2019, we had approximately $15 million accrued (in other accrued liabilities in our consolidated balance sheet) related to other contingent matters including, but not limited to, a number of examinations by taxing authorities on non-income matters and indemnifications that we periodically enter into as part of the divestiture of assets or businesses. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes, environmental 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 March 31, 2019, both interest and depreciation expense associated with our finance leases was approximately $1 million and related cash payments were approximately $2 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 March 31, 2019, both operating lease costs and related cash payments were approximately $2 million and 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 ended March 31, 2019, variable lease costs were less than $1 million

Short-term lease costs for the quarter ended March 31, 2019 were approximately $9 million and were primarily capitalized as part of our oil and natural gas properties.

Supplemental balance sheet information related to leases was as follows:

13


 
 
March 31, 2019
 
 
(in millions)
Operating lease assets(1)
 
$
23

Finance lease assets(2)
 
12

        Total lease assets
 
$
35

 
 
 
Operating leases(3)
 
 
   Current liability
 
$
9

   Noncurrent liability
 
14

        Total operating lease liability
 
$
23

Finance leases(3)
 
 
   Current liability
 
$
2

   Noncurrent liability
 
10

        Total finance lease liability
 
$
12

 
 
 
Weighted average remaining lease term
 
 
   Operating leases
 
4 years

   Finance leases
 
4 years

Weighted average discount rate
 
 
   Operating leases
 
9.25
%
   Finance leases
 
23.99
%
 
(1)
Operating lease assets are reflected in Operating lease assets and other in our consolidated balance sheet as of March 31, 2019.
(2)
Finance lease assets are reflected in Other property, plant and equipment in our consolidated balance sheet as of March 31, 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 March 31, 2019.

Future minimum annual rental commitments under non-cancelable future operating and finance lease commitments at March 31, 2019, were as follows:

 
 
Operating Leases
 
Finance Leases
 
 
(in millions)
2019
 
$
8

 
$
4

2020
 
9

 
5

2021
 
2

 
4

2022
 
2

 
4

Thereafter
 
6

 
2

Total
 
$
27

 
$
19

Less: imputed interest
 
(4
)
 
(7
)
   Present value of operating and finance lease obligations
 
$
23

 
$
12


9. 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 $4 million and $2 million for the quarters ended March 31, 2019 and 2018, respectively. As of March 31, 2019, we had unrecognized compensation expense of $23 million of which we will recognize an additional $11 million during the remainder of 2019 and $12 million thereafter.

14


Restricted Stock. A summary of the changes in our non-vested restricted shares for the quarter ended March 31, 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
 
(1,099,892
)
 
$
4.93

Forfeited
 
(249,058
)
 
$
2.60

Non-vested at March 31, 2019
 
5,814,384

 
$
2.23

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 March 31, 2019, we had a total of 1,504,560 PSUs outstanding. PSUs will be earned based upon the achievement of specified stock price goals and will vest over a weighted average period of three years. Our PSUs are treated as an equity award with the expense recognized on an accelerated basis over the life of the award.
10. Related Party Transactions
 
Joint Venture. We are party to a drilling joint venture to fund future oil and natural gas development with Wolfcamp Drillco Operating L.P. (the Investor, which is managed and controlled by an affiliate of Apollo Global Management LLC) and indirectly through Access Industries (through an indirect minority ownership interest in the Investor). At March 31, 2019 and December 31, 2018, we had accounts receivable of $24 million and $47 million, respectively, from our Investor and accounts payable of $15 million and $20 million, respectively, to 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.

15


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Our Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the financial statements and the accompanying notes presented in Item 1 of Part I of this Quarterly Report on Form 10-Q. This discussion contains forward-looking statements and involves numerous risks and uncertainties, including, but not limited to, those described in the “Risk Factors” section of our 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 and are focused on providing returns to our shareholders through the development of our drilling inventory located in three areas: the Eagle Ford Shale in South Texas, Northeastern Utah (NEU) in the Uinta basin, and the Permian basin in West Texas. 

Our strategy is to invest in opportunities that provide the highest return across our asset base, continually seek out operating and capital efficiencies, effectively manage costs, and identify accretive acquisition opportunities and divestitures, all with the objective of enhancing our portfolio, growing asset value, improving cash flow and increasing financial flexibility. We evaluate opportunities in our portfolio that are aligned with this strategy and our core competencies and that offer a competitive advantage. In addition to opportunities in our current portfolio, strategic acquisitions of leasehold acreage or acquisitions of producing assets allow us to leverage existing expertise in our areas, balance our exposure to regions, basins and commodities, help us to achieve or enhance risk-adjusted returns competitive with those available in our existing programs and increase our reserves. We also continuously evaluate our asset portfolio and will sell oil and natural gas properties if they no longer meet our long-term objectives.

We are party to a drilling joint venture agreement in the Eagle Ford with a total anticipated joint venture investment of $225 million. As of March 31, 2019, we have drilled and completed 53 wells in the Eagle Ford under the amended agreement and expect to drill and complete the remaining wells in the second quarter of 2019. Additionally, subject to certain time limits, we will provide our joint venture partner the option to participate in additional wells in the development areas. For a further discussion on this joint venture, see Part I, Item 1, "Financial Information", Note 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 March 31, 2019, we have drilled and completed 44 wells under the NEU joint venture agreement.

Factors Influencing Our Profitability.  Our profitability is dependent on the prices we receive for our oil and natural gas, the costs to explore, develop, and produce our oil and natural gas, and the volumes we are able to produce, among other factors. Our long-term profitability will be influenced primarily by: 

growing our proved reserve base and production volumes through the successful execution of our drilling
programs or through acquisitions; 
finding and producing oil and natural gas at reasonable costs; 
managing operating and capital costs;
managing commodity price risks on our oil and natural gas production; and
managing debt levels and related interest costs.
In addition to these factors, our future profitability and performance is affected by volatility in the financial and commodity markets. Commodity price changes may affect our future capital spending levels, production rates and/or related operating revenues (net of any associated royalties), levels of proved reserves and development plans, all of which impact performance and profitability.
 
Forward commodity prices play a significant role in determining the recoverability of proved property costs on our balance sheet. While prices have generally stabilized over recent years, future price declines, along with changes to our future capital spending levels, production rates, levels of proved reserves and development plans may result in an impairment of the carrying value of our proved properties in the future, and such charges could be significant.

16



 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 March 31, 2019.
 
 
2019
 
2020
 
 
Volumes(1)
 
Average
Price(1)
 
Volumes(1)
 
Average
Price(1)
Oil
 
 

 
 

 
 
 
 
Collars
 
 
 
 
 
 
 
 
Ceiling - WTI
 
1,100

 
$
69.78

 

 
$

Floors - WTI
 
1,100

 
$
57.50

 

 
$

Three Way Collars
 
 
 
 
 
 
 
 
Ceiling - WTI
 
9,075

 
$
66.01

 
11,712

 
$
65.11

Floors - WTI
 
9,075

 
$
55.76

 
11,712

 
$
55.90

 Sub-Floor - WTI
 
9,075

 
$
45.00

 
11,712

 
$
45.00

Basis Swaps
 
 
 
 
 
 
 
 
Midland vs. Cushing(2) 
 
1,100

 
$
(5.23
)
 

 
$

Natural Gas
 
 
 
 
 
 
 
 
Fixed Price Swaps
 
8

 
$
3.01

 

 
$

Collars
 
 
 
 
 
 
 
 
Ceiling
 
11

 
$
4.26

 

 
$

       Floors
 
11

 
$
2.75

 

 
$

Basis Swaps
 
 
 
 
 
 
 
 
WAHA vs. Henry Hub(3)
 
6

 
$
(0.39
)
 

 
$

 
(1)
Volumes presented are MBbls for oil and TBtu for natural gas. Prices presented are per Bbl of oil and MMBtu of natural gas.
(2)
EP Energy receives Cushing plus the basis spread listed and pays Midland.
(3)
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 March 31, 2019, the average forward price of oil was $60.31 per barrel of oil for the remainder of 2019 and $58.46 per barrel of oil for 2020.

During the quarter ended March 31, 2019, we settled commodity index hedges on approximately 99% of our oil production, 74% of our total NGLs production and 56% of our natural gas production at average floor prices of $55.90 per barrel of oil and $2.86 per MMBtu of natural gas, respectively. As of March 31, 2019, approximately 100% of our future crude oil contracts allow for upside participation (to a weighted average price of approximately $66.41 per barrel for 2019 and $65.11 per barrel for 2020) while containing certain sub-floor prices (weighted average prices of $45.00 per barrel) that limit the amount of our derivative settlements under these three-way contracts should prices drop below the sub-floor prices. To the extent our oil, natural gas and NGLs production is unhedged, either from a commodity index or locational price perspective, our operating revenues will be impacted from period to period.




17


Summary of Liquidity and Capital Resources.  Our profitability and performance may also be affected by our significant debt and debt service obligations which impact our available liquidity. As of March 31, 2019, we had available liquidity of $440 million, reflecting $430 million of available capacity under our Reserve-Based Loan Facility (RBL Facility), which matures in November 2021, and $10 million of available cash.

As of March 31, 2019, our total debt was approximately $4.5 billion, comprised of $8 million in senior secured term loans maturing in 2019, $182 million in senior unsecured notes due in 2020, $506 million in senior unsecured notes due in 2022 and 2023, and $3.6 billion in senior secured notes due in 2024, 2025 and 2026. For the quarter ended March 31, 2019, we incurred $95 million in interest expense. Based on our forecasted EBITDAX, cash on hand, and remaining capacity under our RBL Facility, we currently project that we will not have sufficient liquidity available to repay the notes due in May 2020 and meet our working capital needs and/or fund our planned capital expenditures. In order to address this projected shortfall in liquidity, we are evaluating other sources of incremental liquidity, including issuing additional debt, refinancing our debt and/or selling assets, none of which have been implemented at this time.

For a further discussion of our liquidity and capital resources, including factors that could impact our liquidity, see Liquidity and Capital Resources.












18


Production Volumes and Drilling Summary
 
Production Volumes. Below is an analysis of our production volumes for the quarters ended March 31:
 
 
 
2019
 
2018
Equivalent Volumes (MBoe/d)
 
 

 
 

Eagle Ford
 
33.0

 
35.9

Northeastern Utah
 
15.5

 
17.2

Permian
 
24.7

 
27.0

Total
 
73.2

 
80.1

 
 
 
 
 
Oil (MBbls/d)
 
 
 
 
Eagle Ford
 
22.2

 
24.0

Northeastern Utah
 
10.0

 
11.6

Permian
 
7.2

 
9.8

Total
 
39.4

 
45.4

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

 
36

Northeastern Utah
 
33

 
34

Permian
 
58

 
56

Total
 
124

 
126

 
 
 
 
 
NGLs (MBbls/d)
 
 
 
 
Eagle Ford
 
5.3

 
5.9

Northeastern Utah
 

 

Permian
 
7.8

 
7.8

Total
 
13.1

 
13.7

 
(1)     Production volume excludes 5 MMcf/d of reinjected gas volumes used in operations during the quarter ended March 31, 2019.

Production Summary. For the quarter ended March 31, 2019 compared to the same period in 2018, (i) Eagle Ford equivalent volumes decreased 2.9 MBoe/d or (approximately 8%) due to fewer wells placed on production in the second half of 2018 and 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 2.3 MBoe/d or (approximately 9%) reflecting the slower pace of development due to, among other factors, significant reduction in capital allocated to the Permian.

Production Outlook. For the second quarter of 2019, we anticipate our average daily production volumes to be approximately 70 MBoe/d to 73 MBoe/d, including average daily oil production volumes of approximately 37 MBbls/d to 39 MBbls/d. Future volumes across all our assets will be impacted by the level of natural declines, our drilling plans, and the level and timing of capital spending in each respective area.

Drilling Summary. During the quarter ended March 31, 2019, we (i) frac’d (wells fracture stimulated) 13 gross wells in the Eagle Ford, all of which were completed for a total of 803 net operated wells, and (ii) frac’d 4 gross wells in NEU, 3 of which were completed for a total of 342 net operated wells. We did not frac any wells in the Permian during the quarter ended March 31, 2019, and currently operate 350 net wells in the area. As of March 31, 2019, we also had a total of 54 gross wells in progress, of which 46 gross wells were drilled, but not completed across our programs.

    

19


Results of Operations
 
The information in the table below provides a summary of our financial results.
 
Quarter ended 
 March 31,
 
2019
 
2018
 
(in millions)
Operating revenues
 

 
 

Oil
$
193

 
$
252

Natural gas
18

 
22

NGLs
18

 
26

Total physical sales
229

 
300

Financial derivatives
(95
)
 
(14
)
Total operating revenues
134

 
286

 
 
 
 
Operating expenses
 

 
 

Transportation costs
25

 
25

Lease operating expense
37

 
39

General and administrative
21

 
19

Depreciation, depletion and amortization
94

 
120

Exploration and other expense
1

 
1

Taxes, other than income taxes
11

 
20

Total operating expenses
189

 
224

 
 
 
 
Operating (loss) income
(55
)
 
62

Gain on extinguishment/modification of debt
10

 
41

Interest expense
(95
)
 
(85
)
(Loss) income before income taxes
(140
)
 
18

Income tax expense

 

Net (loss) income
$
(140
)
 
$
18



20


Operating Revenues
 
The table below provides our operating revenues, volumes and prices per unit for the quarters ended March 31, 2019 and 2018. We present (i) average realized prices based on physical sales of oil, natural gas and NGLs as well as (ii) average realized prices inclusive of the impacts of financial derivative settlements and premiums which reflect cash received or paid during the respective period.
 
 
Quarter ended 
 March 31,
 
2019
 
2018
 
(in millions)
Operating revenues:
 

 
 

Oil
$
193

 
$
252

Natural gas
18

 
22

NGLs
18

 
26

Total physical sales
229

 
300

Financial derivatives
(95
)
 
(14
)
Total operating revenues
$
134

 
$
286

 
 
 
 
Volumes:
 

 
 

Oil (MBbls)
3,546


4,087

Natural gas (MMcf)
11,156


11,335

NGLs (MBbls)
1,183


1,232

Equivalent volumes (MBoe)
6,588


7,208

Total MBoe/d
73.2


80.1

 
 
 
 
Prices per unit(1):
 

 
 

Oil
 

 
 

Average realized price on physical sales ($/Bbl)(2) 
$
54.32


$
61.56

Average realized price, including financial derivatives ($/Bbl)(2)(3) 
$
56.01


$
58.86

Natural gas
 

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


$
1.94

Average realized price, including financial derivatives ($/Mcf)(2)(3)
$
1.76


$
2.03

NGLs
 

 
Average realized price on physical sales ($/Bbl)
$
15.64


$
20.93

Average realized price, including financial derivatives ($/Bbl)(3)
$
15.64


$
20.91

 
(1)
For the quarters ended March 31, 2019 and 2018, there were no oil purchases associated with managing our physical oil sales. For the quarter ended March 31, 2019, there were no natural gas purchases associated with managing our physical natural gas sales. Natural gas prices for the quarter ended March 31, 2018 reflects operating revenues for natural gas reduced by less than $1 million for natural gas purchases associated with managing our physical sales.
(2)
Changes in realized oil and natural gas prices reflect the effects of unhedged locational or basis differentials, unhedged volumes and contractual deductions between the commodity price index and the actual price at which we sold our oil and natural gas.
(3)
The quarters ended March 31, 2019 and 2018, include cash received of approximately $6 million and cash paid of approximately $11 million, respectively, for the settlement of crude oil derivative contracts and approximately $2 million and $1 million of cash received, respectively, for the settlement of natural gas financial derivatives. The quarter ended March 31, 2018 includes less than $1 million of cash paid for the settlement of NGLs derivative contracts.














21


Physical sales.  Physical sales represent accrual-based commodity sales transactions with customers. The table below displays the price and volume variances on our physical sales when comparing the quarters ended March 31, 2019 and 2018.
 
Oil
 
Natural gas
 
NGLs
 
Total
 
(in millions)
March 31, 2018 sales
$
252

 
$
22

 
$
26

 
$
300

Change due to prices
(26
)
 
(4
)
 
(6
)
 
(36
)
Change due to volumes
(33
)
 

 
(2
)
 
(35
)
March 31, 2019 sales
$
193

 
$
18

 
$
18

 
$
229


Oil sales for the quarter ended March 31, 2019, compared to the same period in 2018, decreased by $59 million (23%) due primarily to lower oil prices and production in all areas reflecting lower capital spending from the first half of 2018 through the first quarter of 2019.
 
Natural gas sales decreased by $4 million (18%) for the quarter ended March 31, 2019 compared to the same period in 2018 primarily due to lower natural gas prices in the Eagle Ford and Permian.

Our oil, natural gas and NGLs are sold at index prices (WTI, Brent, LLS, Henry Hub and Mt. Belvieu) or refiners’ posted prices at various delivery points across our producing basins.  Realized prices received (not considering the effects of hedges) are generally less than the stated index price as a result of fixed or variable contractual deductions, differentials from the index to the delivery point, adjustments for time, and/or discounts for quality or grade. 
 
In the Eagle Ford, our oil is sold at prices tied primarily to benchmark Magellan East Houston crude oil. In NEU, market pricing of our oil is based upon NYMEX-based agreements, which reflect a locational difference at the wellhead. In the Permian, physical barrels are generally sold at the WTI Midland Index, which trades at a spread to WTI Cushing. Across all regions, natural gas realized pricing is influenced by factors such as regional basis differentials, excess royalties paid on flared gas and the percentage of proceeds retained under processing contracts, in addition to the normal seasonal supply and demand influences and those factors discussed above. The table below displays the weighted average differentials and deducts on our oil and natural gas sales on an average NYMEX price.
 
Quarter ended March 31,
 
2019
 
2018
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
Differentials and deducts
$
(1.11
)

$
(1.52
)

$
(1.18
)

$
(1.03
)
NYMEX
$
54.90


$
3.15


$
62.87


$
3.00

Net back realization %
98.0
%
 
51.7
%
 
98.1
%
 
65.7
%

The oil realization percentage for the quarter ended March 31, 2019 was relatively flat as compared to the same period in 2018 primarily as a result of the improvement of Magellan East Houston and Midland basis pricing and physical sales contracts relative to lower NYMEX WTI pricing. The lower natural gas realization percentage for the quarter ended March 31, 2019 was primarily a result of weaker Permian basin natural gas pricing.
 
NGLs sales decreased by $8 million (31%) for the quarter ended March 31, 2019 compared with the same period in 2018. Average realized prices for the quarter ended March 31, 2019 were lower compared to the same period in 2018 due to lower pricing on all liquids components.
Future growth in our overall oil, natural gas and NGLs sales (including the impact of financial derivatives) will largely be impacted by commodity prices, our level of hedging, our capital expenditures, our ability to maintain or grow oil volumes and by the location of our production and the nature of our sales contracts. See Our Business and Liquidity and Capital Resources for further information on our derivative instruments.
Gains or losses on financial derivatives.  We record gains or losses due to changes in the fair value of our derivative contracts based on forward commodity prices relative to the prices in the underlying contracts. We realize such gains or losses when we settle the derivative position. During the quarters ended March 31, 2019 and 2018, we recorded $95 million and $14 million of derivative losses, respectively.


22



Operating Expenses
The table below provides our operating expenses, volumes and operating expenses per unit for each of the periods presented:
 
Quarter ended March 31,
 
2019
 
2018
 
Total
 
Per Unit(1)
 
Total
 
Per Unit(1)
 
(in millions, except per unit costs)
Operating expenses
 
 
 
 
 
 
 
Transportation costs
25

 
3.74

 
25

 
3.43

Lease operating expense
37

 
5.55

 
39

 
5.48

General and administrative(2)
21

 
3.16

 
19

 
2.58

Depreciation, depletion and amortization
94

 
14.34

 
120

 
16.69

Exploration and other expense
1

 
0.08

 
1

 
0.18

Taxes, other than income taxes
11

 
1.73

 
20

 
2.75

Total operating expenses
$
189

 
$
28.60

 
$
224

 
$
31.11

 
 
 
 
 
 
 
 
Total equivalent volumes (MBoe)
6,588

 
 

 
7,208

 
 

 
(1)
Per unit costs are based on actual amounts rather than the rounded totals presented.
(2)
For the quarter ended March 31, 2019, amount includes approximately $4 million or $0.57 per Boe of non-cash compensation expense. The quarter ended March 31, 2019 also includes approximately $1 million or $0.09 per Boe of transition and severance costs related to workforce reductions. For the quarter ended March 31, 2018, amount includes approximately $2 million or $0.27 per Boe of non-cash compensation expense.
Lease operating expense.  Lease operating expense decreased by $2 million for the quarter ended March 31, 2019 compared to the same period in 2018. The decrease for the quarter ended March 31, 2019 compared to 2018 is due primarily to lower maintenance costs in the Eagle Ford and Permian.

 General and administrative expenses.  General and administrative expenses for the quarter ended March 31, 2019 increased by $2 million compared to the same period in 2018. Higher costs during the quarter ended March 31, 2019 compared to the same period in 2018 were primarily due to higher long-term incentive and benefits costs as well as higher professional and legal fees.

Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense decreased for the quarter ended March 31, 2019 primarily due to a non-cash impairment charge recorded in the fourth quarter of 2018 on our proved properties in the Permian, decreased capital spending and slightly lower production volumes when compared to the same period in 2018. Our depreciation, depletion and amortization rate in the future will be impacted by the level, the location, and timing of capital spending, the overall cost of capital and the level and type of reserves recorded on completed projects. Our average depreciation, depletion and amortization costs per unit for the quarters ended March 31 were:
 
Quarter ended 
 March 31,
 
2019
 
2018
Depreciation, depletion and amortization ($/Boe)
$
14.34


$
16.69

 
Taxes, other than income taxes. Taxes, other than income taxes, for the quarter ended March 31, 2019, decreased by $9 million compared to the same period in 2018, primarily due to a decrease in severance taxes as a result of lower commodity prices and the realization of severance tax credits.

Other Income Statement Items.

Gain on extinguishment/modification of debt. During the quarter ended March 31, 2019, we recorded a total gain on extinguishment of debt of $10 million as a result of our repurchase of approximately $50 million in aggregate principal amount of our senior unsecured notes due 2020.


23


For the quarter ended March 31, 2018, we recorded a total gain on extinguishment of $41 million as a result of exchanging certain senior unsecured notes for $1,092 million in new senior secured notes. See Part 1, Item 1, Financial Statements, Note 7 for more information on our long-term debt.

Interest expense. Interest expense for the quarter ended March 31, 2019 increased by $10 million compared to the same period in 2018 due primarily to the issuance of senior secured notes due 2026 in May 2018, partially offset by lower average borrowings under our RBL Facility during the quarter ended March 31, 2019.

Income taxes. For both of the quarters ended March 31, 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. For the quarters ended March 31, 2019 and 2018, we recorded adjustments to the valuation allowance on our net deferred tax assets, which offset deferred income tax benefit of $30 million and deferred income tax expense of $5 million, respectively.


24


Supplemental Non-GAAP Measures
 
We use the non-GAAP measures “EBITDAX” and “Adjusted EBITDAX” as supplemental measures. We believe these supplemental measures provide meaningful information to our investors. We define EBITDAX as net income (loss) plus interest and debt expense, income taxes, depreciation, depletion and amortization and exploration expense. Adjusted EBITDAX is defined as EBITDAX, adjusted as applicable in the relevant period for the net change in the fair value of derivatives (mark-to-market effects of financial derivatives, net of cash settlements and cash premiums related to these derivatives), the non-cash portion of compensation expense (which represents non-cash compensation expense under our long-term incentive programs adjusted for cash payments made under these plans), transition, severance and other costs that affect comparability, and gains and losses on extinguishment/modification of debt.
 
We believe that the presentation of EBITDAX and Adjusted EBITDAX is important to provide management and investors with additional information (i) to evaluate our ability to service debt adjusting for items required or permitted in calculating covenant compliance under our debt agreements, (ii) to provide an important supplemental indicator of the operational performance of our business without regard to financing methods and capital structure, (iii) for evaluating our performance relative to our peers, (iv) to measure our liquidity (before cash capital requirements and working capital needs) and (v) to provide supplemental information about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDAX and Adjusted EBITDAX have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or as an alternative to net income (loss), operating income (loss), operating cash flows or other measures of financial performance or liquidity presented in accordance with GAAP.
 
Below is a reconciliation of our consolidated net (loss) income to EBITDAX and Adjusted EBITDAX:
 
 
Quarter ended 
 March 31,
 
2019
 
2018
 
(in millions)
Net (loss) income
$
(140
)
 
$
18

Income tax expense

 

Interest expense, net of capitalized interest
95

 
85

Depreciation, depletion and amortization
94

 
120

Exploration expense
1

 
1

EBITDAX
50

 
224

Mark-to-market on financial derivatives(1)
95

 
14

Cash settlements and cash premiums on financial derivatives(2) 
8

 
(10
)
Non-cash portion of compensation expense(3) 
4

 
2

Transition, severance and other costs(4)
1

 

Gain on extinguishment/modification of debt
(10
)
 
(41
)
Adjusted EBITDAX
$
148

 
$
189

 
 
(1)
Represents the income statement impact of financial derivatives.
(2)
Represents actual cash settlements related to financial derivatives.  No cash premiums were received or paid for the quarters ended March 31, 2019 and 2018.  
(3)
For the quarter ended March 31, 2019, cash payments were less than $1 million. There were no cash payments for the quarter ended March 31, 2018.
(4)
Reflects transition and severance costs related to workforce reductions.






25


Commitments and Contingencies
 
For a further discussion of our commitments and contingencies, see Part I, Item 1, Financial Statements, Note 8.
 
Liquidity and Capital Resources
 
Our primary sources of liquidity are cash generated by our operations and borrowings under our RBL Facility which matures in 2021 and our primary uses of cash are capital expenditures, debt service, including interest, and working capital requirements. Our available liquidity was $440 million as of March 31, 2019.

In April 2019, our RBL borrowing base was reaffirmed at $1.36 billion and total commitments remained at $629 million. However, downward revisions of our oil and natural gas reserves volume and value due to declines in commodity prices, the impact of lower estimated capital spending in response to lower prices, performance revisions, sales of assets, or the incurrence of certain types of additional debt, among other items, could cause a reduction of our borrowing base in the future, and these reductions could be significant. Conversely, future acquisitions, reserve additions and higher prices may have the effect of increasing our borrowing base.
    
Debt Maturities and Covenants. As of March 31, 2019, our total debt was approximately $4.5 billion, comprised of $8 million in senior secured term loans maturing in 2019, $182 million in senior unsecured notes due in 2020, $506 million in senior unsecured notes due in 2022 and 2023, and $3.6 billion in senior secured notes due in 2024, 2025 and 2026. Our most restrictive financial debt covenants (which were modified and/or extended in 2018) include a requirement to maintain a first lien debt to EBITDAX ratio of 2.25 to 1.00 and a current ratio (as defined in the RBL Facility) of not less than 1.00 to 1.00. As of March 31, 2019, we were in compliance with our debt covenants. For additional details on our long-term debt, see Part I, Item 1, Financial Statements, Note 7.

Capital Expenditures.  Our capital expenditures and average drilling rigs by area for the quarter ended March 31, 2019 were:
 
Capital
Expenditures(1)
(in millions)
 
Average Drilling
Rigs
Eagle Ford Shale
$
125


3.3

Northeastern Utah
25


1.3

Total
$
150


4.6

   Acquisition capital
$
4

 
 
Total Capital Expenditures
$
154

 
 
 
(1)
Represents accrual-based capital expenditures.

Outlook. In the second quarter of 2019, we expect to spend approximately $140 million to $150 million in capital (excluding acquisition capital) in our programs, with approximately 70% allocated to the Eagle Ford Shale and approximately 30% allocated to NEU. Based upon our current price and cost assumptions and our hedge program, we believe that our current capital program will exceed our estimated operating cash flows after interest payments. However, we believe the borrowing capacity under our RBL Facility and expected cash flows from our operations will be sufficient to fund our capital program and meet current obligations and projected working capital requirements through March 31, 2020.

However, as previously disclosed, in May 2020, $182 million of our senior unsecured notes will mature. Based on our forecasted EBITDAX, cash on hand, and remaining capacity under our RBL Facility, we anticipate that we will not have sufficient liquidity to repay these notes, meet our working capital needs and/or fund our planned capital expenditures as of May 2020 when these notes are due. These factors raise substantial doubt about the Company’s ability to continue as a going concern.

In order to address the potential future liquidity shortfall, we are evaluating certain other sources of incremental liquidity, including additional debt issuances or refinancings and/or asset sales, none of which have been implemented at this time. While the Company believes in the viability of its strategy to generate additional liquidity through one of or a combination of these sources, there is no assurance that our actions will be successful in alleviating the liquidity concerns. Should we not be able to execute on one of or a combination of these liquidity-enhancing actions, we would be unable to continue as a going concern beginning in the second quarter of 2020. Even if we are able to implement such strategic alternatives, they may be insufficient to meet our debt and other obligations over the longer term. Furthermore, such strategic

26


alternatives may adversely affect our creditors or our existing stockholders, potentially resulting in a reduction in the value of their investment or the loss of all or substantially all of their investment in us.

In addition, in the absence of any suitable relief through the actions mentioned above, should we be required to include a going concern qualification in our year-end audit report and audited financial statements for 2019, the disclosure would be considered a default under the Company's RBL Facility, and potentially an event of default if not waived within 30 days after receiving notice of the default from the administrative agent under the RBL Facility. An event of default under the RBL Facility could trigger cross-defaults under our other debt agreements, including our senior secured term loan and our senior secured and unsecured notes, which could also result in the acceleration of those obligations by the lenders thereunder.

We will continue to be aggressive in managing our cost structure and in turn, our liquidity, to meet our capital and operating needs. Additionally, we continually monitor the capital markets and will be opportunistic in taking certain future actions to manage our capital structure including, where possible and allowed under our debt agreements (i) acquiring additional amounts of our outstanding debt in the future for cash through open market repurchases or privately negotiated transactions with certain of our debtholders and/or (ii) issuing additional secured debt as permitted under our debt agreements, although there is no assurance we would do so.

Our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the RBL Facility, (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all, or (iii) obtain additional capital on acceptable terms or at all to fund our capital programs or any potential future acquisitions, joint ventures or other similar transactions, will depend on prevailing economic and industry conditions, many of which are volatile and beyond our control. Should commodity prices decline from current levels, or we experience disruptions in the financial markets impacting our cost of capital, it is possible that additional adjustments to our plan and outlook may occur based on market conditions and the needs of the Company at that time, which could include selling assets, seeking additional partners to develop our assets, issuing equity, and/or further reducing our planned capital spending program.

    

27


Overview of Cash Flow Activities.  Our cash flows are summarized as follows (in millions):
 
 
Three months ended 
 March 31,
 
2019
 
2018
Cash Inflows
 

 
 

Operating activities
 

 
 

Net (loss) income
$
(140
)
 
$
18

Gain on extinguishment/modification of debt
(10
)
 
(41
)
Other income adjustments
102

 
125

Changes in assets and liabilities
120

 
(15
)
Total cash flow from operations
72

 
87

 
 
 
 
Investing activities
 

 
 

Proceeds from the sale of assets

 
167

Cash inflows from investing activities

 
167

 


 


Financing activities
 

 
 

Proceeds from issuance of long-term debt
270

 
460

Cash inflows from financing activities
270

 
460

 
 
 
 
Total cash inflows
$
342

 
$
714

 
 
 
 
Cash Outflows
 

 
 

Investing activities
 

 
 

Capital expenditures
$
125

 
$
173

Cash paid for acquisitions
3

 
223

Cash outflows from investing activities
128

 
396

 


 


Financing activities
 

 
 

Repayments and repurchases of long-term debt
230

 
280

Fees/costs on debt exchange

 
62

Other
1

 
1

Cash outflows from financing activities
231

 
343

 
 
 
 
Total cash outflows
$
359

 
$
739

 
 
 
 
Net change in cash, cash equivalents and restricted cash
$
(17
)
 
$
(25
)


28


Item 3. Qualitative and Quantitative Disclosures About Market Risk
 
This information updates, and should be read in conjunction with the information disclosed in our 2018 Annual Report on Form 10-K, in addition to the information presented in Items 1 and 2 of Part I of this Quarterly Report on Form 10-Q.  There have been no material changes in our quantitative and qualitative disclosures about market risks from those reported in our 2018 Annual Report on Form 10-K, except as presented below:
 
Commodity Price Risk
 
The table below presents the change in fair value of our commodity-based derivatives due to hypothetical changes in oil and natural gas prices, discount rates and credit rates at March 31, 2019:
 
 
 
 
Oil, Natural Gas and NGLs Derivatives
 
 
 
10 Percent Increase
 
10 Percent Decrease
 
Fair Value
 
Fair Value
 
Change
 
Fair Value
 
Change
 
(in millions)
Price impact(1) 
$
11


$
(67
)

$
(78
)

$
80


$
69

 
 
 
 
Oil, Natural Gas and NGLs Derivatives
 
 
 
1 Percent Increase
 
1 Percent Decrease
 
Fair Value
 
Fair Value
 
Change
 
Fair
Value
 
Change
 
(in millions)
Discount rate(2) 
$
11


$
11


$


$
11


$

Credit rate(3) 
$
11


$
11


$


$
11


$

 
(1)
Presents the hypothetical sensitivity of our commodity-based derivatives to changes in fair values arising from changes in oil, natural gas and NGLs prices.
(2)
Presents the hypothetical sensitivity of our commodity-based derivatives to changes in the discount rates we used to determine the fair value of our derivatives.
(3)
Presents the hypothetical sensitivity of our commodity-based derivatives to changes in credit risk of our counterparties.
 
Item 4. Controls and Procedures
 
Evaluation of Disclosure Controls and Procedures
 
As of March 31, 2019, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act), is accurate, complete and timely. Our management, including our CEO and our CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our CEO and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of March 31, 2019.
 
Changes in Internal Control over Financial Reporting
 
There were no changes in EP Energy Corporation’s internal control over financial reporting during the first three months of 2019 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.


29


PART II — OTHER INFORMATION
 
Item 1. Legal Proceedings
 
See Part I, Item 1, Financial Statements, Note 8.
 
Item 1A. Risk Factors
 
There have been no material changes to the risk factors previously disclosed in the 2018 Annual Report on Form 10-K.
 
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
 
None.
 
Item 3. Defaults Upon Senior Securities
 
None.
 
Item 4. Mine Safety Disclosures
 
Not applicable.
 
Item 5. Other Information
 
None.
Item 6. Exhibits
 
The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and:
 
         should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

         may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
 
           may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and

            were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.
 
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

Each exhibit identified below is filed as part of this Report. Exhibits filed with this Report are designated by “*”.  All exhibits not so designated are incorporated herein by reference to a prior filing as indicated. 


30


Exhibit
 Number
 
Description
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
*101.INS
 
XBRL Instance Document.
 
 
 
*101.SCH
 
XBRL Schema Document.
 
 
 
*101.CAL
 
XBRL Calculation Linkbase Document.
 
 
 
*101.DEF
 
XBRL Definition Linkbase Document.
 
 
 
*101.LAB
 
XBRL Labels Linkbase Document.
 
 
 
*101.PRE
 
XBRL Presentation Linkbase Document.



31


SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
EP ENERGY CORPORATION
 
 
 
 
Date: May 9, 2019
/s/ Kyle A. McCuen
 
Kyle A. McCuen
 
Senior Vice President, Chief Financial Officer and Treasurer
 
(Principal Financial and Accounting Officer)

32
Exhibit 31.1


CERTIFICATION
 
I, Russell E. Parker, certify that:
 
1.                                      I have reviewed this Quarterly Report on Form 10-Q of EP Energy Corporation;
 
2.                                      Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.                                      Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.                                      The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a 15(f) and 15d 15(f)) for the registrant and have:
 
(a)         Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and
 
(b)         Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and
 
(c)          Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
(d)         Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
 
5.                                      The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
 
(a)         All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
(b)         Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
 
 
Date: May 9, 2019
 
 
/s/ Russell E. Parker
 
Russell E. Parker
 
President and Chief Executive Officer
 
EP Energy Corporation



Exhibit 31.2


CERTIFICATION
 
I, Kyle A. McCuen, certify that:
 
1.                                      I have reviewed this Quarterly Report on Form 10-Q of EP Energy Corporation;
 
2.                                      Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.                                      Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.                                      The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a 15(f) and 15d 15(f)) for the registrant and have:
 
(a)         Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and
 
(b)         Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and
 
(c)          Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
(d)         Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
 
5.                                      The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
 
(a)         All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
(b)         Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
 
 
Date: May 9, 2019
 
 
/s/ Kyle A. McCuen
 
Kyle A. McCuen
 
Senior Vice President, Chief Financial Officer and Treasurer
 
EP Energy Corporation



Exhibit 32.1


CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002
 
In connection with the Quarterly Report on Form 10-Q for the period ending March 31, 2019, of EP Energy Corporation (the “Company”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Russell E. Parker, President and Chief Executive Officer, certify (i) that the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
 
 
/s/ Russell E. Parker
 
Russell E. Parker
 
President and Chief Executive Officer
 
EP Energy Corporation
 
 
 
Date: May 9, 2019
 
A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 32.2


CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002
 
In connection with the Quarterly Report on Form 10-Q for the period ending March 31, 2019, of EP Energy Corporation (the “Company”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kyle A. McCuen, Senior Vice President, Chief Financial Officer and Treasurer, certify (i) that the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
 
 
/s/ Kyle A. McCuen
 
Kyle A. McCuen
 
Senior Vice President, Chief Financial
 
Officer and Treasurer
 
EP Energy Corporation
 
 
 
Date: May 9, 2019
 
A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.





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