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EX-32.2 - EXHIBIT 32.2 - EP Energy Corpex3220930201810q1.htm
EX-32.1 - EXHIBIT 32.1 - EP Energy Corpex3210930201810q1.htm
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EX-31.1 - EXHIBIT 31.1 - EP Energy Corpex3110930201810q1.htm
EX-2.1 - EXHIBIT 2.1 - EP Energy Corpex21firstamendmenttoarpda.htm

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
 
 Form 10-Q
 
 
(Mark One)
 x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2018
OR
o  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
                     For the transition period from             to            
Commission File Number 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
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
 Class A Common Stock, par value $0.01 per share. Shares outstanding as of October 31, 2018: 256,672,389
Class B Common Stock, par value $0.01 per share. Shares outstanding as of October 31, 2018: 240,122
 



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
Gal
=
gallons
LLS
=
light Louisiana sweet crude oil
MBoe
=
thousand barrels of oil equivalent
MBbls
=
thousand barrels
Mcf
=
thousand cubic feet
MMBtu
=
million British thermal units
MMBbls
=
million barrels
MMcf
=
million cubic feet
MMGal
=
million gallons
Mt. Belvieu
=
Mont Belvieu natural gas liquids pricing index
NGLs
=
natural gas liquids
NYMEX
=
New York Mercantile Exchange
TBtu
=
trillion British thermal units
WTI
=
West Texas intermediate
 
When we refer to oil and natural gas in “equivalents”, we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil and/or NGLs is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch. 
When we refer to “us”, “we”, “our”, “ours”, “the Company” or “EP Energy”, we are describing EP Energy 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;
 
                  pending legal proceedings, claims and governmental proceedings, including environmental matters;
 
                  future economic and operating performance;
 
                  operating income;
 
                  management’s plans; and

                  goals and objectives for future operations.
 
Forward-looking statements are subject to risks and uncertainties. While we believe the assumptions or bases underlying the forward-looking statements are reasonable and are made in good faith, we caution that assumed facts or bases almost always vary from actual results, and these differences can be material, depending upon the circumstances. We cannot assure you that the statements of expectation or belief contained in our forward-looking statements will result or be achieved or accomplished. Important factors that could cause actual results to differ materially from estimates or projections contained in our forward-looking statements are described in our 2017 Annual Report on Form 10-K. There have been no material changes to the risk factors described in the Form 10-K.


1


PART I — FINANCIAL INFORMATION
 
Item 1. Financial Statements


EP ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per common share amounts)
(Unaudited)
 
 
Quarter ended 
 September 30,
 
Nine months ended  
 September 30,
 
2018
 
2017
 
2018
 
2017
Operating revenues
 

 
 

 
 

 
 

Oil
$
287

 
$
189

 
$
820

 
$
595

Natural gas
15

 
27

 
55

 
84

NGLs
36

 
26

 
92

 
71

Financial derivatives
(44
)
 
(23
)
 
(122
)
 
92

Total operating revenues
294

 
219

 
845

 
842

 
 
 
 
 
 
 
 
Operating expenses
 

 
 

 
 

 
 

Oil and natural gas purchases
3

 

 
3

 
2

Transportation costs
25

 
29

 
76

 
86

Lease operating expense
46

 
42

 
123

 
121

General and administrative
21

 
25

 
68

 
71

Depreciation, depletion and amortization
127

 
118

 
376

 
368

Gain on sale of assets
(1
)
 

 
(1
)
 

Impairment charges

 
1

 

 
2

Exploration and other expense
2

 
6

 
3

 
10

Taxes, other than income taxes
22

 
16

 
63

 
50

Total operating expenses
245

 
237

 
711

 
710

 
 
 
 
 
 
 
 
Operating income (loss)
49

 
(18
)
 
134

 
132

Other income
2

 

 
2

 

Gain (loss) on extinguishment/modification of debt

 
24

 
48

 
(16
)
Interest expense
(95
)
 
(80
)
 
(268
)
 
(245
)
Loss before income taxes
(44
)
 
(74
)
 
(84
)
 
(129
)
Income tax benefit

 
2

 

 
7

Net loss
$
(44
)
 
$
(72
)
 
$
(84
)
 
$
(122
)
 
 
 
 
 
 
 
 
Basic and diluted net income (loss) per common share
 

 
 

 
 

 
 

Net loss
$
(0.18
)
 
$
(0.29
)
 
$
(0.34
)
 
$
(0.50
)
Basic and diluted weighted average common shares outstanding
248

 
246

 
247

 
246


See accompanying notes.


2


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

 
 

Current assets
 

 
 

Cash and cash equivalents
$
56

 
$
27

Restricted cash

 
18

Accounts receivable
 

 
 

Customer, net of allowance of less than $1 in 2018 and 2017
182

 
158

Other, net of allowance of $1 in 2018 and 2017
56

 
13

Income tax receivable

 
9

Materials and supplies
15

 
16

Derivative instruments

 
18

Assets held for sale

 
172

Prepaid assets
6

 
35

Total current assets
315

 
466

Property, plant and equipment, at cost
 

 
 

Oil and natural gas properties
8,392

 
7,532

Other property, plant and equipment
75

 
69

 
8,467

 
7,601

Less accumulated depreciation, depletion and amortization
3,554

 
3,179

Total property, plant and equipment, net
4,913

 
4,422

Other assets
 

 
 

Derivative instruments
1

 
4

Unamortized debt issue costs - revolving credit facility
8

 
6

Other
2

 
2

 
11

 
12

Total assets
$
5,239

 
$
4,900

 
See accompanying notes.

3


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

 
 

Current liabilities
 

 
 

Accounts payable
 

 
 

Trade
$
119

 
$
88

Other
158

 
158

Derivative instruments
71

 
17

Accrued interest
112

 
62

Liabilities related to assets held for sale

 
2

Short-term debt, net of debt issue costs
8

 
21

Other accrued liabilities
95

 
100

Total current liabilities
563

 
448

 
 
 
 
Long-term debt, net of debt issue costs
4,295

 
4,022

Other long-term liabilities
 

 
 

Derivative instruments
12

 

Asset retirement obligations
39

 
33

Other
13

 
5

Total non-current liabilities
4,359

 
4,060

 
 
 
 
Commitments and contingencies (Note 8)


 


 
 
 
 
Stockholders’ equity
 

 
 

Class A shares, $0.01 par value; 550 million shares authorized; 257 million shares issued and outstanding at September 30, 2018; 252 million shares issued and outstanding at December 31, 2017
3

 
3

Class B shares, $0.01 par value; less than one million shares authorized, issued and outstanding at September 30, 2018 and December 31, 2017

 

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

 

Treasury stock (at cost), less than one million shares at September 30, 2018 and December 31, 2017

 
(3
)
Additional paid-in capital
3,532

 
3,526

Accumulated deficit
(3,218
)
 
(3,134
)
Total stockholders’ equity
317

 
392

Total liabilities and equity
$
5,239

 
$
4,900

 
See accompanying notes.


4


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

 
 

Net loss
$
(84
)
 
$
(122
)
Adjustments to reconcile net loss to net cash provided by operating activities
 

 
 

Depreciation, depletion and amortization
376

 
368

Gain on sale of assets
(1
)
 

Impairment charges

 
2

(Gain) loss on extinguishment/modification of debt
(48
)
 
16

Other non-cash income items
22

 
24

Asset and liability changes
 

 
 

Accounts receivable
(68
)
 
(25
)
Accounts payable
18

 
26

Derivative instruments
87

 
(7
)
Accrued interest
50

 
40

Other asset changes
15

 
(12
)
Other liability changes
13

 
(12
)
Net cash provided by operating activities
380

 
298

 
 
 
 
Cash flows from investing activities
 

 
 

Cash paid for capital expenditures
(559
)
 
(405
)
Proceeds from the sale of assets
175

 

Cash paid for acquisitions
(275
)
 
(29
)
Net cash used in investing activities
(659
)
 
(434
)
 
 
 
 
Cash flows from financing activities
 

 
 

Proceeds from issuance of long-term debt
1,805

 
1,645

Repayments and repurchases of long-term debt
(1,431
)
 
(1,484
)
Fees/costs on debt exchange
(62
)
 

Debt issue costs
(21
)
 
(21
)
Other
(1
)
 
(3
)
Net cash provided by financing activities
290

 
137

 
 
 
 
Change in cash, cash equivalents and restricted cash
11

 
1

 
 

 
 

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

 
20

Cash, cash equivalents and restricted cash - end of period
$
56

 
$
21

 
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, 2016
251

 
$
2

 
0.8

 
$

 
$
(3
)
 
$
3,546

 
$
(2,939
)
 
$
606

Cumulative effect of accounting change

 
$

 

 
$

 
$

 
$
1

 
$
(1
)
 
$

Balance at January 1, 2017
251

 
$
2

 
0.8


$

 
$
(3
)
 
$
3,547

 
$
(2,940
)
 
$
606

Share-based compensation
4

 
1

 
(0.1
)
 

 

 
(4
)
 

 
(3
)
Net loss

 

 

 

 

 

 
(47
)
 
(47
)
Balance at March 31, 2017
255

 
$
3

 
0.7

 
$

 
$
(3
)
 
$
3,543

 
$
(2,987
)
 
$
556

Share-based compensation

 

 

 

 

 
6

 

 
6

Net loss

 

 

 

 

 

 
(3
)
 
(3
)
Balance at June 30, 2017
255

 
$
3

 
0.7


$

 
$
(3
)
 
$
3,549

 
$
(2,990
)
 
$
559

Share-based compensation

 

 

 

 

 
4

 

 
4

Net loss

 

 

 

 

 

 
(72
)
 
(72
)
Balance at September 30, 2017
255

 
$
3

 
0.7

 
$

 
$
(3
)
 
$
3,553

 
$
(3,062
)
 
$
491

Share-based compensation
(3
)
 

 
(0.4
)
 

 

 
(27
)
 

 
(27
)
Net loss

 

 

 

 

 

 
(72
)
 
(72
)
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

 
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 2017 Annual Report on
Form 10-K. The condensed consolidated financial statements as of September 30, 2018 and 2017 are unaudited. The consolidated balance sheet as of December 31, 2017 has been derived from the audited consolidated balance sheet included in our 2017 Annual Report on Form 10-K.  In our opinion, all adjustments which are of a normal, recurring nature are reflected to fairly present these interim period results. The results for any interim period are not necessarily indicative of the expected results for the entire year.

Significant Accounting Policies
 
In the first quarter of 2018, we adopted Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers, which clarifies the principles for recognizing revenue and develops a common revenue standard for U.S. GAAP and International Financial Reporting Standards. As permitted under ASU No. 2014-09, we elected to utilize the modified retrospective approach, which did not have a material impact on our financial statements. There were no other changes in significant accounting policies as described in the 2017 Annual Report on Form 10-K
 
New Accounting Pronouncements Issued But Not Yet Adopted
 
The following accounting standards have been issued but not yet adopted as of September 30, 2018.

Leases.  In February 2016, the Financial Accounting Standards Board (FASB) issued ASU No. 2016-02, Leases, which requires lessees to recognize right-of-use assets and liabilities on the balance sheet and disclose key information about leasing arrangements.  Adoption of this standard is required beginning in the first quarter of 2019 and we anticipate adopting this standard on a modified retrospective basis, recognizing a cumulative-effect adjustment to the opening balance of retained earnings, if any, upon adoption. In addition, we plan to make certain permitted elections upon adoption around lease classification of contracts and land easements existing prior to the adoption date and not recognizing short-term leases on our balance sheet. We continue to evaluate our contracts and other agreements to assess the impact this update will have on our financial statements, processes, policies and internal controls.

2. Acquisitions and Divestitures
 
Acquisitions. In the first quarter of 2018, we completed the acquisition of producing properties and proved undeveloped acreage in 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 and $25 million to the buyer as a deposit in December 2017. In July 2018, we completed an acquisition of additional working interests in certain producing properties in Eagle Ford for approximately $31 million, subject to customary post-closing adjustments. Our balance sheet reflects the cost of each 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), formerly Altamont, for approximately $177 million, after customary adjustments. Of the total sales price, we received a deposit of $18 million (reflected in restricted cash in the balance sheet) in December 2017 and additional cash proceeds of $159 million upon closing. We treated this sale as a normal retirement reflecting the difference between net cash proceeds and the underlying net book value of the assets sold in accumulated depreciation rather than recording a gain on sale of assets. As of December 31, 2017, we classified the assets and liabilities associated with the assets to be sold as held for sale in our consolidated balance sheet.
    

7


3. Income Taxes
 
Effective Tax Rate. Interim period income taxes are computed by applying an anticipated annual effective tax rate to year-to-date income or loss, except for significant, unusual or infrequently occurring items, which income tax effects are recorded in the period in which they occur. Changes in tax laws or rates are recorded in the period they are enacted.
For both the quarter and nine months ended September 30, 2018, our effective tax rates were approximately 0%. For the quarter and nine months ended September 30, 2017, our effective tax rates were approximately 4% and 6%, respectively. Our effective tax rates in 2018 and 2017 differed from the statutory rates of 21% and 35%, respectively, primarily as a result of our recognition of a full valuation allowance on our net deferred tax assets. For the quarters ended September 30, 2018 and 2017, we recorded adjustments to the valuation allowance on our net deferred tax assets, which offset deferred income tax benefit of $10 million and $24 million, respectively, and offset deferred income tax benefit of $18 million and $36 million for the nine months ended September 30, 2018 and 2017, respectively.

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

We evaluate the realization of our deferred tax assets and record any associated valuation allowance after considering cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in prior carryback years, tax planning strategies and future taxable income for each of our taxable jurisdictions. Based upon the evaluation of the available evidence, we maintained a valuation allowance against our net deferred tax assets of $662 million as of September 30, 2018.

The Company’s and certain subsidiaries’ income tax years after 2013 remain open and subject to examination by both federal and state tax authorities, and in the second quarter of 2018 we were notified of an IRS examination of our 2016 U.S. tax return. During the nine months ended September 30, 2018, we also received federal and state refunds of $9 million.

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, performance share unit awards and performance unit awards. For the quarters and nine months ended September 30, 2018 and 2017, we incurred net losses and accordingly excluded all potentially dilutive securities from the determination of diluted earnings per share as their impact on loss per common share was antidilutive.
5. Fair Value Measurements 
We use various methods to determine the fair values of our financial instruments. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value.  As of September 30, 2018 and December 31, 2017, all of our derivative financial instruments were classified as Level 2. Our assessment of the level of an instrument can change over time based on the maturity or liquidity of the instrument.

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

 
$
8

 
$
21

 
$
19

 
 
 
 
 
 
 
 
Long-term debt (see Note 7)
$
4,395

 
$
3,808

 
$
4,072

 
$
3,248

 
 
 
 
 
 
 
 
Derivative instruments
$
(82
)
 
$
(82
)
 
$
5

 
$
5

 
As of September 30, 2018 and December 31, 2017, the carrying amount of cash and cash equivalents, accounts receivable and accounts payable represent fair value because of the short-term nature of these instruments. We hold long-term

8


debt obligations with various terms. We estimated the fair value of debt (representing a Level 2 fair value measurement) primarily based on quoted market prices for the same or similar issuances, considering our credit risk.
 
Oil, Natural Gas and NGLs Derivative Instruments.  We attempt to mitigate a portion of our commodity price risk and stabilize cash flows associated with forecasted sales of oil, natural gas and NGLs through the use of financial derivatives.  As of September 30, 2018, we had derivative contracts in the form of fixed price swaps, collars and three-way collars on 13 MMBbls of oil (4 MMBbls in 2018 and 9 MMBbls in 2019). In addition to our oil derivatives, we had derivative contracts in the form of fixed price swaps on 14 TBtu of natural gas (7 TBtu in 2018 and 7 TBtu in 2019) and 23 MMGal of ethane and propane fixed price swaps in 2018. As of December 31, 2017, we had derivative contracts for 14 MMBbls of oil, 33 TBtu of natural gas and 92 MMGal of ethane and propane. In addition to the contracts above, we have derivative contracts related to locational basis differences on our oil and natural gas production. None of our derivative contracts are designated as accounting hedges.

The following table presents the fair value associated with our derivative financial instruments as of September 30, 2018 and December 31, 2017. All of our derivative instruments are subject to master netting arrangements, which provide for the unconditional right of offset for all derivative assets and liabilities with a given counterparty in the event of default. We present assets and liabilities related to these instruments in our consolidated balance sheets as either current or non-current assets or liabilities based on their anticipated settlement date, net of the impact of master netting agreements.  On derivative contracts recorded as assets in the table below, we are exposed to the risk that our counterparties may not perform.
 
Level 2
 
Derivative Assets
 
Derivative Liabilities
 
Gross
Fair Value
 
 
 
Balance Sheet Location
 
Gross 
Fair Value
 
 
 
Balance Sheet Location
 
 
Impact of
Netting
 
Current
 
Non-
current
 
 
Impact of
Netting
 
Current
 
Non-
current
 
(in millions)
 
(in millions)
September 30, 2018
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Derivative instruments
$
21

 
$
(20
)
 
$

 
$
1

 
$
(103
)
 
$
20

 
$
(71
)
 
$
(12
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2017
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Derivative instruments
$
33

 
$
(11
)
 
$
18

 
$
4

 
$
(28
)
 
$
11

 
$
(17
)
 
$


     For the quarters ended September 30, 2018 and 2017, we recorded derivative losses of $44 million and $23 million, respectively. For the nine months ended September 30, 2018 and 2017, we recorded a derivative loss of $122 million and a derivative gain of $92 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 September 30, 2018 and December 31, 2017, we had approximately $4.9 billion and $4.4 billion, respectively, of total property, plant, and equipment, net of accumulated depreciation, depletion and amortization on our consolidated balance sheets, substantially all of which relates to proved and unproved oil and natural gas properties.
Our capitalized costs related to proved and unproved oil and natural gas properties by area were as follows:
 
September 30, 2018
 
December 31, 2017
 
(in millions)
Proved
 
 
 
Eagle Ford
$
3,865

 
$
3,219

Permian
2,831

 
2,705

Northeastern Utah (formerly Altamont)
1,637

 
1,542

Total Proved
8,333

 
7,466

Unproved
 
 
 
Permian
59

 
66

Less accumulated depletion
(3,512
)
 
(3,137
)
Net capitalized costs for oil and natural gas properties
$
4,880

 
$
4,395


9


For both of the quarter and nine months ended September 30, 2018, we recorded less than $1 million of amortization of unproved leasehold costs in exploration expense in our consolidated income statement. For the quarter and nine months ended September 30, 2017, we recorded approximately $2 million and $4 million, respectively, of amortization of unproved leasehold costs in exploration expense in our consolidated income statement. Suspended well costs were not material as of September 30, 2018 or December 31, 2017
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. Capitalized costs associated with unproved properties (e.g., leasehold acquisition costs associated with non-producing areas) are also assessed upon a triggering event for impairment based on estimated drilling plans and capital expenditures, which may also change relative to forward commodity prices and/or potential lease expirations. Commodity price declines may cause changes to our capital spending levels, production rates, levels of proved reserves and development plans, which may result in an impairment of the carrying value of our proved and/or unproved properties in the future.

Generally, economic recovery of unproved reserves in non-producing or unproved areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by continuing exploration and development activities.  Our ability to retain our leases and thus, recover our non-producing leasehold costs is dependent upon a number of factors including our levels of drilling activity, which may include drilling the acreage on our own behalf or jointly with partners, or our ability to modify or extend our leases. Should commodity prices not justify sufficient capital allocation to the continued development of properties where we have non-producing leasehold costs, we could incur impairment charges of our unproved property costs.

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

In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including a credit-adjusted risk-free rate between 7 percent and 9 percent on a significant portion of our obligations and a projected inflation rate of 2.5 percent. Changes in estimates in the table below represent changes to the expected amount and timing of payments to settle our asset retirement obligations. Typically, these changes primarily result from obtaining new information about the timing of our obligations to plug and abandon oil and natural gas wells and the costs to do so, or reassessing our assumptions in light of changing market conditions. The net asset retirement liability as of September 30, 2018 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability from January 1 through September 30, 2018 were as follows:
 
2018
 
(in millions)
Net asset retirement liability at January 1
$
35

Liabilities incurred
1

Accretion expense
2

Changes in estimate
3

Net asset retirement liability at September 30
$
41

 
Capitalized Interest.  Interest expense is reflected in our financial statements net of capitalized interest. We capitalize
interest primarily on the costs associated with drilling and completing wells until production begins using a weighted average interest rate on our outstanding borrowings. Capitalized interest for the quarter and nine months ended September 30, 2018 was approximately $2 million and $4 million, respectively. Capitalized interest for the quarter and nine months ended September 30, 2017 was approximately $1 million and $3 million, respectively.



10


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

 
$
595

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

 
21

Due April 30, 2019(4)
Variable
 
8

 
8

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

 

Due November 29, 2024
8.00%
 
500

 
500

Due February 15, 2025
8.00%
 
1,000

 
1,000

Due May 15, 2026
7.75%
 
1,000

 

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

 
1,200

Due September 1, 2022
7.75%
 
195

 
250

Due June 15, 2023
6.375%
 
362

 
519

Total debt
 
 
4,403

 
4,093

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

 
4,072

Less debt discount and non-current portion of unamortized debt issue costs(5)
 
 
(100
)
 
(50
)
Total long-term debt, net
 
 
$
4,295

 
$
4,022

 
(1)
Carries interest at a specified margin over LIBOR of 2.50% to 3.50%, based on borrowing utilization.
(2)                                    Issued at 99% of par and carries interest at a specified margin over LIBOR of 2.75%, with a minimum LIBOR floor of 0.75%. As of December 31, 2017, the effective interest rate of the term loan was 4.23%.
(3)
In April 2018, we retired the term loan in full.
(4)                                     Carries interest at a specified margin over the LIBOR of 3.50%, with a minimum LIBOR floor of 1.00%. As of September 30, 2018 and December 31, 2017, the effective interest rate for the term loan was 5.81% and 4.98%, respectively.
(5)
Includes debt discount of $44 million and less than $1 million as of September 30, 2018 and December 31, 2017, respectively, associated with our senior secured notes maturing in 2024 and unamortized debt issue costs of $64 million and $56 million as of September 30, 2018 and December 31, 2017, respectively.

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

During the first quarter of 2018, we completed an exchange of 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.

    







11


In 2018 and 2017, we also repurchased additional debt as follows:
 
 
Quarter ended September 30,
 
Nine months ended September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(in millions)
Debt repurchased - face value(1)
 

 
101

 
19

 
157

Cash paid
 

 
76

 
10

 
118

Gain on extinguishment of debt(2)
 

 
24

 
9

 
37

 
(1)
In 2018 and 2017, repurchases were associated with 2022 and 2023 senior unsecured notes and 2020 and 2023 senior unsecured notes, respectively.
(2) Includes $1 million and $2 million for the quarter and nine months ended September 30, 2017, respectively, of non-cash expense related to eliminating associated
unamortized debt issue costs.

In 2017, we issued $1 billion of 8.00% senior secured notes maturing in 2025, using the proceeds to repay certain senior secured term loans and notes and repay a portion of the amounts outstanding under our RBL Facility. In conjunction with these transactions, we recorded a loss on extinguishment of debt of approximately $53 million (including $30 million in non-cash expense related to eliminating associated unamortized debt issue costs and debt discounts).

Reserve-based Loan Facility. We have an RBL Facility which allows us to borrow funds or issue letters of credit (LCs) up to $629 million. The RBL Facility matures in November 2021. As of September 30, 2018, we had $610 million of capacity remaining with approximately $19 million of LCs issued and no amounts outstanding under the RBL Facility.

The RBL Facility is collateralized by certain of our oil and natural gas properties and has a borrowing base subject to semi-annual redetermination. In November 2018, 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.

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. As part of our RBL Facility amendment in May 2018, we (i) extended our first lien debt to EBITDAX financial covenant and reduced the ratio to 2.25 to 1.00 and (ii) included a financial covenant for a current ratio (as defined in the RBL Facility) to be not less than 1.00 to 1.00. As of September 30, 2018, we were in compliance with our debt covenants.
Under our various debt agreements, we are limited in our ability to repurchase certain tranches of non-RBL Facility debt. Certain other covenants and restrictions, among other things, also limit or place certain conditions on our ability to incur or guarantee additional indebtedness, make restricted payments, pay dividends on equity interests, redeem, repurchase or retire 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 September 30, 2018, 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

12


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 the court has ordered briefing on the merits. 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 May 13, 2019. At this time, we are unable to estimate the amount or range of possible loss, if any, on this matter.
Indemnifications and Other Matters. We periodically enter into indemnification arrangements as part of the divestiture of assets or businesses. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes, environmental and other contingent matters. In addition, under various laws or regulations, we could be subject to the imposition of certain liabilities. For example, the decline in commodity prices has created an environment where there is an increased risk that owners and/or operators of assets previously purchased from us may no longer be able to satisfy plugging and abandonment obligations that attach to such assets. In that event, under various laws or regulations, we could be required to assume all, or a portion of the plugging or abandonment obligations on assets we no longer own or operate. As of September 30, 2018, we had approximately $4 million accrued related to these indemnifications and other matters.
Non-Income Tax Matters. We are under a number of examinations by taxing authorities related to non-income tax matters. As of September 30, 2018, we had approximately $43 million accrued (in other accrued liabilities in our consolidated balance sheet) in connection with ongoing examinations related to certain prior period non-income tax matters.

Environmental Matters
We are subject to existing federal, state and local laws and regulations governing environmental quality, pollution control and greenhouse gas (GHG) emissions.  Numerous governmental agencies, such as the Environmental Protection Agency (EPA), issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. Our management believes that we are in substantial compliance with applicable environmental laws and regulations, and we have not experienced any material adverse effect from compliance with these environmental requirements. For additional details on certain environmental matters, including matters related to climate change, air quality and other emissions, hydraulic fracturing regulations and waste handling, refer to the Risk Factors section of our 2017 Annual Report on Form 10-K.
While our reserves for environmental matters are currently not material, there are still uncertainties related to the ultimate costs we may incur in the future in order to comply with increasingly strict environmental laws, regulations, and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations. Based upon our evaluation and experience to date, however, we believe our accruals for these matters are adequate. It is possible that new information or future developments could result in substantial additional costs and liabilities which could require us to reassess our potential exposure related to these matters and to adjust our accruals accordingly, and these adjustments could be material.


13


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

 
$
4.93

Granted
 
6,905,525

 
$
1.94

Vested
 
(1,891,999
)
 
$
5.65

Forfeited
 
(1,411,984
)
 
$
4.27

Non-vested at September 30, 2018
 
8,885,528

 
$
2.56

Performance Share Units. In May 2018, we granted 599,040 PSUs to certain EP Energy employees. The grant date fair value of the 2018 awards was approximately $4 million as determined by a Monte Carlo simulation, utilizing an expected volatility of approximately 90% and a risk free rate of approximately 3%. As of September 30, 2018, we had a total of 1,501,920 PSUs outstanding. PSUs will be earned based upon the achievement of specified stock price goals over a four-year performance period and will vest over a weighted average period of five years. Our PSUs are treated as an equity award with the expense recognized on an accelerated basis over the life of the award.
Performance Units. Our performance units become payable upon achievement of a level of total shareholder return and may be settled in either stock or cash at the election of the Board of Directors. These awards are treated as a liability award for accounting purposes with the expense recognized on an accelerated basis over the life of the award and fair value remeasured at each reporting period. During the nine months ended September 30, 2018, we made no payments in connection with awards that vested and had less than $1 million accrued related to unvested outstanding performance unit awards.
We record compensation expense on all of our 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 $5 million for both of the quarters ended September 30, 2018 and 2017, and $10 million for both of the nine months ended September 30, 2018 and 2017. Included in pre-tax compensation expense for the nine months ended September 30, 2017 was approximately $7 million of forfeitures recorded during the quarter ended March 31, 2017. As of September 30, 2018, we had unrecognized compensation expense of $28 million.  We will recognize an additional $4 million related to our outstanding awards during the remainder of 2018, $22 million over the remaining requisite service periods subsequent to 2018 and $2 million should a specified capital transaction occur and the right to such amounts become non-forfeitable.

10. Related Party Transactions
 
Joint Venture. In 2017, we entered into a drilling joint venture with Wolfcamp Drillco Operating L.P. (the Investor), which is managed and controlled by an affiliate of Apollo Global Management LLC, to fund future oil and natural gas development in the Permian basin. Subsequently, Access Industries acquired an indirect minority ownership interest in the Investor and therefore is also indirectly responsible for funding a portion of the Investor’s capital commitment. The Investor agreed to fund 60 percent of the estimated drilling, completion and equipping costs in the joint venture wells, divided into two approximately $225 million investment tranches, in exchange for a 50 percent working interest. Once the Investor achieves a 12 percent internal rate of return on its invested capital in each tranche, its working interest reverts to 15 percent. We have substantially completed the planned activity in the first tranche. In April 2018, we amended the drilling joint venture to direct the second tranche investment to the Eagle Ford. The first wells in the second tranche began producing in the third quarter of 2018. We are the operator of the joint venture assets. At September 30, 2018 and December 31, 2017, we had accounts receivable of $46 million and $5 million, respectively, from our Investor and accounts payable of $13 million and $10 million, respectively, to our Investor reflected in our consolidated balance sheet.

14


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Our Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the financial statements and the accompanying notes presented in Item 1 of Part I of this Quarterly Report on Form 10-Q. This discussion contains forward-looking statements and involves numerous risks and uncertainties, including, but not limited to, those described in the “Risk Factors” section of our 2017 Annual Report on Form 10-K. Actual results may differ materially from those contained in any forward-looking statements.  Unless otherwise indicated or the context otherwise requires, references in this MD&A section to “we”, “our”, “us” and “the Company” refer to EP Energy 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, the Permian basin in West Texas, and Northeastern Utah (NEU), formerly Altamont, in the Uinta basin. 

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

During 2018, we completed acquisitions of producing properties and proved undeveloped acreage in Eagle Ford, primarily in La Salle County, for approximately $277 million, subject to customary post-closing adjustments. The acquisitions represent a 30 percent expansion of our Eagle Ford acreage position at December 31, 2017 or approximately 27,700 net acres. We also completed the sale of certain assets in NEU for approximately $177 million, after customary closing adjustments. The divestiture represents approximately 13 percent of our NEU acreage position at December 31, 2017, or approximately 23,330 net acres.
Factors Influencing Our Profitability.  Our profitability is dependent on the prices we receive for our oil and natural gas, the costs to explore, develop, and produce our oil and natural gas, and the volumes we are able to produce, among other factors. Our long-term profitability will be influenced primarily by: 

growing our proved reserve base and production volumes through the successful execution of our drilling
programs or through acquisitions; 
finding and producing oil and natural gas at reasonable costs; 
managing operating costs; and
managing commodity price risks on our oil and natural gas production. 
In addition to these factors, our future profitability and performance will be affected by volatility in the financial and commodity markets, changes in the cost of drilling and oilfield services, operating and capital costs, and our debt level and related interest costs. Future commodity price changes may affect our future capital spending levels, production rates and/or related operating revenues (net of any associated royalties), levels of proved reserves and development plans, all of which impact performance. Additionally, we may be impacted by weather events, regulatory issues or other third party actions outside of our control.
 
Forward commodity prices play a significant role in determining the recoverability of proved or unproved property
costs on our balance sheet. While prices have generally improved over the past two years, future price declines, along with changes to our future capital spending levels, production rates, levels of proved reserves and development plans may result in an impairment of the carrying value of our proved and/or unproved properties in the future, and such charges could be significant.

15



 Derivative Instruments.  Our realized prices from the sale of our oil, natural gas and NGLs are affected by (i) commodity price movements, including locational or basis price differences that exist between the commodity index price (e.g., WTI) and the actual price at which we sell our commodities and (ii) other contractual pricing adjustments contained in our underlying sales contracts.  In order to stabilize cash flows and protect the economic assumptions associated with our capital investment programs, we enter into financial derivative contracts to reduce the financial impact of downward commodity price movements and unfavorable movements in locational prices. Adjustments to our strategy and the decision to enter into new contracts or positions to alter existing contracts or positions are made based on the goals of the overall company. Because we apply mark-to-market accounting on our derivative contracts, our reported results of operations and financial position can be impacted significantly by commodity price movements from period to period.
During the nine months ended September 30, 2018, we settled commodity index hedges on approximately 88% of our oil production, 77% of our total liquids production and 57% of our natural gas production at average floor prices of $58.47 per barrel of oil, $0.45 per gallon of NGLs and $3.04 per MMBtu of natural gas, respectively. To the extent our oil, natural gas and NGLs production is unhedged, either from a commodity index or locational price perspective, our operating revenues will be impacted from period to period. The following table and discussion reflects the contracted volumes and the prices we will receive under derivative contracts we held as of September 30, 2018.
 
 
2018
 
2019
 
 
Volumes(1)
 
Average
Price(1)
 
Volumes(1)
 
Average
Price(1)
Oil
 
 

 
 

 
 
 
 
Fixed Price Swaps
 
 

 
 

 
 
 
 
WTI
 
1,288

 
$
56.49

 
730

 
$
55.88

Collars
 
 
 
 
 
 
 
 
Ceiling - WTI
 
276

 
$
64.98

 
1,275

 
$
65.80

Floors - WTI
 
276

 
$
55.00

 
1,275

 
$
55.00

Three Way Collars
 
 
 
 
 
 
 
 
Ceiling - WTI
 
2,233

 
$
68.15

 
7,300

 
$
68.66

Floors - WTI
 
2,233

 
$
60.00

 
7,300

 
$
58.50

 Sub-Floor - WTI
 
2,233

 
$
50.00

 
7,300

 
$
45.00

Basis Swaps
 
 
 
 
 
 
 
 
LLS vs. WTI(2)
 
1,288

 
$
2.84

 

 
$

Midland vs. Cushing(3) 
 
920

 
$
(1.02
)
 
1,095

 
$
(6.47
)
NYMEX Roll(4) 
 
920

 
$
0.09

 

 
$

Natural Gas
 
 
 
 
 
 
 
 
Fixed Price Swaps
 
7

 
$
3.04

 
7

 
$
2.97

Basis Swaps
 
 
 
 
 
 
 
 
WAHA vs. Henry Hub(5)
 
4

 
$
(0.46
)
 
7

 
$
(0.39
)
NGLs
 
 
 
 
 
 
 
 
Fixed Price Swaps - Ethane
 
15

 
$
0.30

 

 
$

Fixed Price Swaps - Propane
 
8

 
$
0.75

 

 
$

 
(1)
Volumes presented are MBbls for oil, TBtu for natural gas and MMGal for NGLs. Prices presented are per Bbl of oil, MMBtu of natural gas and Gal for NGLs.
(2)
EP Energy receives WTI plus the basis spread listed and pays LLS.
(3)
EP Energy receives Cushing plus the basis spread listed and pays Midland. These positions do not include 184 MBbls of oil at an average price of $1.08 per barrel of oil, which offset our 1.1 MBbls Midland vs. Cushing basis swaps positions.
(4)
These positions hedge the timing risk associated with our physical sales. We generally sell oil for the delivery month at a sales price based on the average NYMEX WTI
price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month
during the period when the delivery month is prompt (the “trade month roll”).
(5)
EP Energy receives Henry Hub plus the basis spread listed and pays WAHA.







16


For the period from October 1, 2018 through November 2, 2018, we entered into additional derivative contracts on 0.4 MMBbls of 2019 WTI collars with a ceiling price of $81.85 and a floor price of $65.00 per barrel of oil.

For our three-way collar contracts in the tables above, the sub-floor prices represent the price below which we receive WTI plus a weighted average spread of $10.00 in 2018 and $13.50 in 2019 on the indicated volumes. If WTI is above our sub-floor prices, we receive the noted floor price until WTI exceeds that floor price. Above the floor price, we receive WTI until prices exceed the noted ceiling price in our three-way collars, at which time we receive the fixed ceiling price. As of September 30, 2018, the average forward price of oil was $73.00 per barrel of oil for the remainder of 2018 and $71.12 per barrel of oil for 2019.

Summary of Liquidity and Capital Resources.  As of September 30, 2018, we had available liquidity of $666 million, reflecting $610 million of available liquidity on our Reserve-Based Loan facility (RBL Facility) borrowing base and $56 million of available cash. Our RBL Facility is our primary source of liquidity beyond our operating cash flow and matures in November 2021. In 2018, we have taken a number of steps to improve our liquidity, expand our financial flexibility and manage our leverage by (i) exchanging approximately $1,147 million of the outstanding amounts of our senior unsecured notes maturing in 2020, 2022 and 2023 for new 9.375% senior secured notes maturing in 2024, (ii) issuing $1 billion of 7.75% senior secured notes which mature in 2026 and using the net proceeds to repay in full the outstanding amounts at that time under our RBL Facility and (iii) extending the maturity of our RBL Facility from May 2019 to November 2021.

During 2018, we also (i) completed our largest acquisition to date in the Eagle Ford for approximately $246 million, after customary adjustments, (ii) completed the sale of certain assets in NEU for approximately $177 million after customary adjustments and (iii) completed an acquisition of additional working interests in certain producing properties in Eagle Ford for approximately $31 million, subject to customary post-closing adjustments. For a further discussion of our liquidity and capital resources, including factors that could impact our liquidity, see Liquidity and Capital Resources.

Outlook. For the full year 2018, we expect to spend approximately $630 million to $670 million in capital (excluding approximately $332 million in acquisition capital and capital adjustments under a joint venture agreement) in our programs, with approximately 65% allocated to the Eagle Ford Shale, approximately 15% allocated to the Permian basin and approximately 20% allocated to NEU. We anticipate our average daily production volumes for the year to be approximately 79 MBoe/d to 82 MBoe/d, including average daily oil production volumes of approximately 45 MBbls/d to 47 MBbls/d.










17


Production Volumes and Drilling Summary
 
Production Volumes. Below is an analysis of our production volumes for the quarter and nine months ended September 30:
 
 
Quarter ended 
 September 30,
 
Nine months ended  
 September 30,
 
2018
 
2017
 
2018
 
2017
Equivalent Volumes (MBoe/d)
 
 
 
 
 

 
 

Eagle Ford Shale
35.8

 
32.9

 
37.0

 
37.4

Permian
27.1

 
29.9

 
26.8

 
27.6

Northeastern Utah (formerly Altamont)
17.5

 
18.2

 
17.2

 
17.8

Total
80.4

 
81.0

 
81.0

 
82.8

 
 
 
 
 
 
 
 
Oil (MBbls/d)
 
 
 
 
 
 
 
Eagle Ford Shale
25.6

 
20.0

 
25.2

 
23.4

Permian
8.8

 
12.6

 
9.4

 
11.2

Northeastern Utah
12.0

 
12.5

 
11.8

 
12.4

Total
46.4

 
45.1

 
46.4

 
47.0

 
 
 
 
 
 
 
 
Natural Gas (MMcf/d)
 
 
 
 
 
 
 
Eagle Ford Shale(1)
30

 
37

 
35

 
41

Permian
58

 
55

 
56

 
52

Northeastern Utah
33

 
34

 
32

 
33

Total
121

 
126

 
123

 
126

 
 
 
 
 
 
 
 
NGLs (MBbls/d)
 
 
 
 
 
 
 
Eagle Ford Shale
5.2

 
6.7

 
6.0

 
7.2

Permian
8.7

 
8.2

 
8.1

 
7.6

Northeastern Utah

 

 

 

Total
13.9

 
14.9

 
14.1

 
14.8

 
(1)     Production volume excludes 8 MMcf/d and 6 MMcf/d of reinjected gas volumes used in operations during the quarter and nine months ended September 30, 2018.

Drilling Summary. During the nine months ended September 30, 2018, we (i) frac’d (wells fracture stimulated) 63 gross wells in the Eagle Ford, of which 62 wells were completed for a total of 791 net operated wells, (ii) frac’d 24 gross wells in the Permian, all of which were completed for a total of 350 net operated wells and (iii) frac’d 22 gross wells in NEU, all of which were completed for a total of 339 net operated wells. In addition, we recompleted 81 gross wells in NEU during 2018.

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.

18


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

 
 

 
 

 
 

Oil
$
287

 
$
189

 
$
820

 
$
595

Natural gas
15

 
27

 
55

 
84

NGLs
36

 
26

 
92

 
71

Total physical sales
338

 
242

 
967

 
750

Financial derivatives
(44
)
 
(23
)
 
(122
)
 
92

Total operating revenues
294

 
219

 
845

 
842

 
 
 
 
 
 
 
 
Operating expenses
 

 
 

 
 

 
 

Oil and natural gas purchases
3

 

 
3

 
2

Transportation costs
25

 
29

 
76

 
86

Lease operating expense
46

 
42

 
123

 
121

General and administrative
21

 
25

 
68

 
71

Depreciation, depletion and amortization
127

 
118

 
376

 
368

Gain on sale of assets
(1
)
 

 
(1
)
 

Impairment charges

 
1

 

 
2

Exploration and other expense
2

 
6

 
3

 
10

Taxes, other than income taxes
22

 
16

 
63

 
50

Total operating expenses
245

 
237

 
711

 
710

 
 
 
 
 
 
 
 
Operating income (loss)
49

 
(18
)
 
134

 
132

Other income
2

 

 
2

 

Gain (loss) on extinguishment/modification of debt

 
24

 
48

 
(16
)
Interest expense
(95
)
 
(80
)
 
(268
)
 
(245
)
Loss before income taxes
(44
)
 
(74
)
 
(84
)
 
(129
)
Income tax benefit

 
2

 

 
7

Net loss
$
(44
)
 
$
(72
)
 
$
(84
)
 
$
(122
)


19


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

 
 

 
 

 
 

Oil
$
287

 
$
189

 
$
820

 
$
595

Natural gas
15

 
27

 
55

 
84

NGLs
36

 
26

 
92

 
71

Total physical sales
338

 
242

 
967

 
750

Financial derivatives
(44
)
 
(23
)
 
(122
)
 
92

Total operating revenues
$
294

 
$
219

 
$
845

 
$
842

 
 
 
 
 
 
 
 
Volumes:
 

 
 

 
 

 
 

Oil (MBbls)
4,262


4,153

 
12,648

 
12,824

Natural gas (MMcf)
11,121


11,563

 
33,730

 
34,381

NGLs (MBbls)
1,285


1,376

 
3,851

 
4,058

Equivalent volumes (MBoe)
7,401


7,456

 
22,121

 
22,612

Total MBoe/d
80.4


81.0

 
81.0

 
82.8

 
 
 
 
 
 
 
 
Prices per unit(1):
 

 
 

 
 

 
 

Oil
 

 
 

 
 

 
 

Average realized price on physical sales ($/Bbl)(2) 
$
66.61


$
45.49

 
$
64.61

 
$
46.38

Average realized price, including financial derivatives ($/Bbl)(2)(3) 
$
63.37


$
51.75

 
$
61.55

 
$
52.82

Natural gas
 

 
 
 
 
 
Average realized price on physical sales ($/Mcf)(2) 
$
1.34


$
2.26

 
$
1.62

 
$
2.38

Average realized price, including financial derivatives ($/Mcf)(2)(3)
$
1.69


$
2.49

 
$
1.89

 
$
2.48

NGLs
 

 
 
 
 
 
Average realized price on physical sales ($/Bbl)
$
27.74


$
18.98

 
$
23.80

 
$
17.53

Average realized price, including financial derivatives ($/Bbl)(3)
$
24.79


$
18.45

 
$
22.60

 
$
17.58

 
(1)
Oil prices for both of the quarter and nine months ended September 30, 2018 reflect operating revenues for oil reduced by $3 million for oil purchases associated with managing our physical oil sales. For both of the quarter and nine months ended September 30, 2017, there were no oil purchases associated with managing our physical oil sales. Natural gas prices for both of the quarter and nine months ended September 30, 2018 reflect operating revenues for natural gas reduced by less than $1 million for natural gas purchases associated with managing our physical sales. Natural gas prices for the quarter and nine months ended September 30, 2017 reflect operating revenues for natural gas reduced by less than $1 million and approximately $2 million, respectively, for natural gas purchases associated with managing our physical sales.
(2)
Changes in realized oil and natural gas prices reflect the effects of unhedged locational or basis differentials, unhedged volumes and contractual deductions between the commodity price index and the actual price at which we sold our oil and natural gas.
(3)
The quarters ended September 30, 2018 and 2017, include cash paid of approximately $14 million and cash received of approximately $26 million, respectively, for the settlement of crude oil derivative contracts and approximately $4 million and $2 million of cash received, respectively, for the settlement of natural gas financial derivatives. The nine months ended September 30, 2018 and 2017, include cash paid of approximately $39 million and cash received of approximately $83 million, respectively, for the settlement of crude oil derivative contracts and approximately $9 million and $3 million of cash received, respectively, for the settlement of natural gas financial derivatives. The quarters ended September 30, 2018 and 2017 include approximately $4 million and $1 million of cash paid, respectively, for the settlement of NGLs derivative contracts. The nine months ended September 30, 2018 and 2017, include cash paid of approximately $5 million and cash received of less than $1 million, respectively, for the settlement of NGLs derivative contracts.









20


Physical sales.  Physical sales represent accrual-based commodity sales transactions with customers. For the quarter and nine months ended September 30, 2018, physical sales increased by $96 million (40%) and $217 million (29%), respectively, compared to the same periods in 2017. The table below displays the price and volume variances on our physical sales when comparing the quarter and nine months ended September 30, 2018 and 2017.
 
Quarter ended
 
Oil
 
Natural gas
 
NGLs
 
Total
 
(in millions)
September 30, 2017 sales
$
189

 
$
27

 
$
26

 
$
242

Change due to prices
93

 
(11
)
 
12

 
94

Change due to volumes
5

 
(1
)
 
(2
)
 
2

September 30, 2018 sales
$
287

 
$
15

 
$
36

 
$
338

 
Nine months ended
 
Oil
 
Natural gas
 
NGLs
 
Total
 
(in millions)
September 30, 2017 sales
$
595

 
$
84

 
$
71

 
$
750

Change due to prices
233

 
(27
)
 
24

 
230

Change due to volumes
(8
)
 
(2
)
 
(3
)
 
(13
)
September 30, 2018 sales
$
820

 
$
55

 
$
92

 
$
967


Oil sales for the quarter and nine months ended September 30, 2018, compared to the same periods in 2017, increased by $98 million (52%) and $225 million (38%), respectively, due primarily to higher oil prices in all areas. 
 
Natural gas sales decreased by