EP ENERGY CORPORATION
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 8 of this Annual Report on
Form 10-K. This discussion contains forward-looking statements and involves
numerous risks and uncertainties, including, but not limited to, those described
in "Risk Factors". Actual results may differ materially from those contained in
any forward-looking statements. See "Cautionary Statement Regarding
Forward-Looking Statements" in the front of this report. Unless otherwise
indicated or the context otherwise requires, references in this MD&A section to
"we", "our", "us" and "the Company" refer to EP Energy Corporation and each of
its consolidated subsidiaries.
Our Business
Overview. We are an independent exploration and production company engaged in
the acquisition and development of unconventional onshore oil and natural gas
properties in the United States . We operate through a diverse base of producing
assets through the development of our drilling inventory located in three areas:
the Eagle Ford Shale in South Texas , Northeastern Utah (NEU) in the Uinta basin,
and the Permian basin in West Texas , which are further described in Part I, Item
I. "Business".
Chapter 11 Cases. On October 3, 2019 , we and certain of our direct and indirect
subsidiaries filed voluntary petitions in the United States Bankruptcy Court for
the Southern District of Texas seeking relief under chapter 11 of title 11 of
the United States Code as further described in Part I, Item 1. "Business" and
Liquidity and Capital Resources.
Strategy. Our strategy is to invest in opportunities that provide the highest
return across our asset base, continually seek out operating and capital
efficiencies, effectively manage costs, and identify accretive acquisition
opportunities and divestitures, all with the objective of enhancing our
portfolio, growing asset value, improving cash flow and increasing financial
flexibility. We evaluate opportunities in our portfolio that are aligned with
this strategy and our core competencies and that offer a competitive advantage.
In addition to opportunities in our current portfolio, strategic acquisitions of
leasehold acreage or acquisitions of producing assets allow us to leverage
existing expertise in our areas, balance our exposure to regions, basins and
commodities, help us to achieve or enhance risk-adjusted returns competitive
with those available in our existing programs and increase our reserves. We also
continuously evaluate our asset portfolio and will sell oil and natural gas
properties if they no longer meet our long-term objectives.
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 profitability is and will continue to 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
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• managing debt levels and related interest costs.
In addition to these factors, our 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. Future price declines, along with changes to our future capital spending levels, production rates, levels of proved reserves and development plans may result in an impairment of the carrying value of our proved properties in the future, and such charges could be significant. Derivative Instruments. Our realized prices from the sale of our oil, natural gas and NGLs are affected by (i) commodity price movements, including locational or basis price differences that exist between the commodity index price (e.g., WTI) and the actual price at which we sell our commodity 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. The following table and discussion reflects the contracted volumes and the prices we will receive under derivative contracts we held as ofDecember 31, 2019 . 2020 2021 Average Average Volumes(1) Price(1) Volumes(1) Price(1) Oil Fixed Price Swaps WTI 1,849$ 55.80 90$ 55.52 Three Way Collars Ceiling - WTI 11,712$ 65.11 - $ - Floors - WTI 11,712$ 55.90 - $ - Sub-Floor - WTI 11,712$ 45.00 - $ - Basis Swaps Midland vs. Cushing(2) 1,464$ 0.46 - $ -
(1) Volumes presented are MBbls for oil and prices presented are per Bbl of oil.
(2) EP Energy receives
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$10.90 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 ofDecember 31, 2019 , the average forward price of oil was$58.46 per barrel of oil for 2020 and$54.04 per barrel of oil for 2021. During 2019, we (i) settled commodity index hedges on approximately 97% of our oil production, 73% of our total liquids production and 61% of our natural gas production at average floor prices of$55.93 per barrel of oil and$2.86 per MMBtu of natural gas, respectively. As ofDecember 31, 2019 , approximately 86% of our 2020 future crude oil contracts allow for upside participation (with a weighted average price of approximately$65.11 per barrel for 2020) while containing 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. For the period fromJanuary 1, 2020 throughMarch 20, 2020 , we unwound 4,026 MBbls of 2020 WTI oil three-way collars with a ceiling price of$64.97 , a floor price of$55.00 and a sub-floor price of$45.00 per barrel of oil and replaced it with 4,148 MBbls of 2020 WTI oil fixed price swaps with an average price of$59.98 per barrel of oil. In addition, we entered into derivative contracts on 90 MBbls of 2021 WTI oil fixed price swaps with an average price of$55.05 per barrel of oil and 39
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900 MBbls of 2021 WTI oil three-way collars with a ceiling price of
Liquidity and Capital Resources
Overview. As of December 31, 2019 , our primary sources of liquidity are cash
generated by our operations and borrowings under our debtor-in-possession
facility ("DIP Facility"). Our primary uses of cash are capital expenditures,
debt service, including interest, and working capital requirements. The
following table provides a summary of our total available liquidity as of
December 31, 2019 :
Year Ended December 31, 2019
(in millions)
Cash and cash equivalents $ 32
Availability under DIP Facility 150
Total available liquidity $ 182
Chapter 11 Cases. In the second quarter 2019, our Board of Directors appointed a
Special Committee which engaged financial and legal advisors to consider a
number of potential actions and evaluate certain strategic alternatives to
address our liquidity and balance sheet issues. On August 15, 2019 , we did not
make the approximately $40 million cash interest payment due and payable with
respect to the 8.000% Senior Secured Notes due 2025. On September 3, 2019 , we
did not make the approximately $7 million cash interest payment due and payable
with respect to the 7.750% Senior Notes due 2022.
On October 3, 2019 , we and certain of our direct and indirect subsidiaries
(collectively with the Company, the "Debtors") filed the Chapter 11 Cases in the
United States Bankruptcy Court for the Southern District of Texas seeking relief
under chapter 11 of title 11 of the United States Code. To ensure ordinary
course operations, the Debtors obtained approval from the Bankruptcy Court for a
variety of "first day" motions, including motions to obtain customary relief
intended to assure our ability to continue our ordinary course operations after
the filing date. In addition, the Debtors received authority to use cash
collateral of the lenders under the Reserve-Based Facility ("RBL Facility").
The commencement of the Chapter 11 Cases constituted an immediate event of
default, and caused the automatic and immediate acceleration of all debt
outstanding under or in respect of a number of our instruments and agreements
relating to our direct financial obligations, including our RBL Facility and
indentures governing the 8.000% Senior Secured Notes due 2025, 7.750% Senior
Secured Notes due 2026, 8.000% Senior Secured Notes due 2024, 9.375% Senior
Secured Notes due 2024, 9.375% Senior Notes due 2020, 7.750% Senior Notes due
2022 and 6.375% Senior Notes due 2023 (collectively, the "Senior Notes"). Any
efforts to enforce such payment obligations were automatically stayed as a
result of the filing of the Chapter 11 Cases and the creditors' rights of
enforcement in respect of the Senior Notes and the RBL Facility are subject to
the applicable provisions of the Bankruptcy Code.
On October 18, 2019 , the Debtors entered into the PSA with the Supporting
Noteholders to support a restructuring on the terms of a chapter 11 plan
described therein (the "Plan"). On October 18, 2019 , the Debtors also entered
into the BCA with the Supporting Noteholders, pursuant to which the Supporting
Noteholders agreed to backstop $463 million (to consist of $325 million in cash
and $138 million in exchanged reinstated 1.25L Notes) of the Rights Offering. On
March 6, 2020 , after a hearing to confirm the Plan, the Bankruptcy Court stated
that it would confirm the Plan. On March 12, 2020 , pursuant to its ruling on
March 6, 2020 , the Bankruptcy Court entered an order confirming the Plan (ECF
No. 1049).
On March 18, 2020 , the Debtors and the Supporting Noteholders under the PSA
and in their capacities as the Commitment Parties under the BCA, mutually agreed
to amend and terminate the PSA and the BCA pursuant the terms of a Stipulation
of Settlement Regarding Backstop Agreement and Plan Support Agreement (the
"Stipulation"). On March 23, 2020 , the Bankruptcy Court approved the
Stipulation. The Debtors are working with their constituents to explore various
alternatives.
Debtor-in-Possession Agreement. On November 25, 2019 , EPE Acquisition, LLC and
EP Energy LLC entered into a Senior Secured Superpriority Debtor-In-Possession
Credit Agreement (as amended or modified from time to time, the "DIP Credit
Agreement) with JPMorgan Chase Bank, N.A ., as administrative agent, collateral
agent and an issuing bank and the RBL Lenders which are party thereto as lenders
(in such capacity, the "DIP Lenders"). Under the DIP Credit Agreement and the
DIP Order, a portion of the RBL Facility was converted into revolving
commitments under the DIP Credit Agreement which provides for an approximately
$315 million debtor-in-possession senior secured superpriority revolving credit
facility (the "DIP
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Facility", and the loans thereunder, the "DIP Loans"), and which includes a letter of credit sublimit of$50 million . As ofDecember 31, 2019 , we had$150 million capacity remaining with approximately$17 million of letters of credit issued and$148 million outstanding under the DIP Facility. For a further discussion of the additional terms of the DIP Facility, see Part II, Item 8. "Financial Statements and Supplementary Data", Note 8.EP Energy LLC will use the proceeds of the DIP Facility for, among other things, (i) the acquisition, development and exploration of oil and gas properties, for working capital and general corporate purposes, (ii) the payment of professional fees as provided for in the DIP Order, (iii) the payment of expenses incurred in the administration of the Chapter 11 Cases or as permitted by the certain orders and (iv) payments due thereunder or under the DIP Order. The maturity date of the DIP Facility is the earlier of (a)November 25, 2020 , (b) the effective date of an "Acceptable Plan of Reorganization" (as defined in the DIP Credit Agreement), (c) the closing of a sale of substantially all of the equity or assets ofEP Energy LLC (unless consummated pursuant to an Acceptable Plan of Reorganization), or (d) the termination of the DIP Facility during the continuation of an event of default thereunder. OnMarch 12, 2020 ,EP Energy LLC ,EPE Acquisition, LLC , the agent and certain of the lenders under the RBL Facility, the DIP Agent and certain of the DIP Lenders entered into that certain Waiver of Credit Agreements which waived the occurrence of any event of default triggered under the RBL Credit Agreement and the DIP Credit Agreement as a result of a going concern or like qualification or exception to the audited financials for the year endingDecember 31, 2019 . Exit Facility. The Debtors have received an underwritten commitment from the DIP Lenders to convert their DIP Loans and their remaining claims under the RBL Facility into an approximately$629 million exit senior secured reserve-based revolving credit facility (the "Exit Facility") subject to certain conditions set forth therein, which will be evidenced by a senior secured revolving credit agreement, by and amongEP Energy LLC , as borrower,EPE Acquisition, LLC , as holdings, the lenders party thereto from time to time, andJPMorgan Chase Bank, N.A ., as administrative agent, collateral agent and an issuing bank. Ability to Continue as a Going Concern. The significant risks and uncertainties related to the Company's liquidity and Chapter 11 Cases described above raise substantial doubt about the Company's ability to continue as a going concern. Our operations and our ability to develop and execute our business plan are subject to a high degree of risks and uncertainty associated with the Chapter 11 Cases which are dependent upon factors that are outside of the Company's control, including actions of theBankruptcy Court and the Company's creditors. Any plan of reorganization could materially change the amounts and classifications of assets and liabilities reported in the consolidated financial statements.
For a further discussion of all Chapter 11 related matters, see Part II, Item 8. "Financial Statements and Supplementary Data", Notes 1A, 8 and 9.
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Overview of Cash Flow Activities. Our cash flows are summarized as follows:
Year ended December 31,
2019 2018
(in millions)
Cash Inflows
Operating activities
Net loss $ (943 ) $ (1,003 )
Impairment charges 458 1,103
Gain on sale of assets - (3 )
Gain on extinguishment/modification of debt (10 ) (73 )
Write-off of debt discount and deferred issue costs 90 -
Reorganization items, net 24 -
Other income adjustments 441 537
Change in assets and liabilities 167 (139 )
Total cash flow from operations $ 227 Investing activities Proceeds from the sale of assets $ -$ 192 Cash inflows from investing activities $ -
Financing activities Proceeds from issuance of long-term debt$ 923 $ 2,090 Proceeds from borrowing under DIP Facility 298
-
Cash inflows from financing activities$ 1,221 $ 2,090 Total cash inflows$ 1,448 $ 2,704 Cash Outflows Investing activities Cash paid for capital expenditures$ 497 $ 690 Cash paid for acquisitions 21
292
Cash outflows from investing activities$ 518
Financing activities Repayments and repurchases of long-term debt$ 765 $ 1,654 Repayment of borrowings from DIP Facility 150 - DIP Facility costs 6 - Fees/costs on debt exchange - 62 Other debt issue costs 2 22 Other 1 2 Cash outflows from financing activities$ 924 $ 1,740 Total cash outflows$ 1,442 $ 2,722
Net change in cash, cash equivalents and restricted cash $ 6
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Production Volumes and Drilling Summary
Production Volumes. Below is a summary of our production volumes for the years
ended
2019 2018
Equivalent Volumes (MBoe/d)
Eagle Ford Shale 33.7 37.1
Northeastern Utah 15.7 17.1
Permian 21.5 26.5
Total 70.9 80.7
Oil (MBbls/d)
Eagle Ford Shale 22.2 25.0
Northeastern Utah 10.2 11.7
Permian 6.2 9.1
Total 38.6 45.8
Natural Gas (MMcf/d)
Eagle Ford Shale(1) 34 36
Northeastern Utah 33 32
Permian 48 55
Total 115 123
NGLs (MBbls/d)
Eagle Ford Shale 5.8 6.1
Northeastern Utah - -
Permian 7.3 8.2
Total 13.1 14.3
(1) Production volume excludes 8 MMcf/d of reinjected gas volumes used in
operations during the year ended December 31, 2019 .
Production Summary. For the year ended December 31, 2019 compared to the same
period in 2018, (i) Eagle Ford equivalent volumes decreased 3.4 MBoe/d or
(approximately 9%) due to fewer wells placed on production in the second half of
2018 through 2019, (ii) NEU equivalent volumes decreased 1.4 MBoe/d or
(approximately 8%) due to reduced drilling activity in 2019, and (iii) Permian
equivalent volumes decreased 5.0 MBoe/d or (approximately 19%) reflecting the
slower pace of development due to a significant reduction in capital allocated
to the Permian. In Eagle Ford and Permian, our 2019 production volumes were also
negatively impacted by downstream third-party operational issues and constraints
and more reinjected gas as compared to the same period in 2018.
Drilling Summary. During 2019, we (i) frac'd (wells fracture stimulated) 54
gross wells in Eagle Ford, all of which came online for a total of 847 net
operated wells, and (ii) frac'd 14 gross wells in NEU, 13 of which came online
for a total of 345 net operated wells. We did not frac any wells in the Permian
during the year ended December 31, 2019 , and currently operate 353 net wells in
the area. As of December 31, 2019 , we also had a total of 41 gross wells in
progress, all of which were drilled, but not completed across our programs.
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Capital Expenditures. Our capital expenditures and average drilling rigs for
the twelve months ended
Capital
Expenditures(1) Average Drilling
(in millions) Rigs
Eagle Ford Shale $ 368 1.8
Northeastern Utah 144 1.7
Permian 5 -
Total $ 517 3.5
Acquisition capital $ 19
Total capital expenditures $ 536
(1) Represents accrual-based capital expenditures.
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Results of Operations
The information below reflects financial results for
Year ended December 31,
2019 2018
(in millions)
Operating revenues:
Oil $ 790 $ 1,045
Natural gas 49 75
NGLs 62 120
Total physical sales 901 1,240
Financial derivatives (81 ) 84
Total operating revenues 820 1,324
Operating expenses:
Oil and natural gas purchases - 3
Transportation costs 93 100
Lease operating expense 138 158
General and administrative 123 89
Depreciation, depletion and amortization 418 507
Gain on sale of assets - (3 )
Impairment charges 458 1,103
Exploration and other expense 7 5
Taxes, other than income taxes 56 77
Total operating expenses 1,293 2,039
Operating loss (473 ) (715 )
Other income 4 4
Gain on extinguishment/modification of debt 10 73
Interest expense (419 ) (365 )
Reorganization items, net (65 ) -
Loss before income taxes (943 ) (1,003 )
Income tax expense - -
Net loss $ (943 ) $ (1,003 )
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Operating Revenues The table below provides our operating revenues, volumes and prices per unit for the years endedDecember 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. Year ended December 31, 2019 2018 (in millions) Operating revenues: Oil$ 790 $ 1,045 Natural gas 49 75 NGLs 62 120 Total physical sales 901 1,240 Financial derivatives (81 ) 84 Total operating revenues$ 820 $ 1,324 Volumes: Oil (MBbls) 14,083 16,726 Natural gas (MMcf) 42,059 44,913 NGLs (MBbls) 4,785 5,227 Equivalent volumes (MBoe) 25,878 29,439 Total MBoe/d 70.9 80.7 Prices per unit(1): Oil Average realized price on physical sales ($/Bbl)(2)$ 56.08
$ 56.67 $ 60.37 Natural gas Average realized price on physical sales ($/Mcf)(2)$ 1.16
$ 1.56 $ 1.96 NGLs Average realized price on physical sales ($/Bbl)$ 13.02 $ 22.88 Average realized price, including financial derivatives ($/Bbl)(3)$ 13.02 $ 21.79
(1) For the year ended
associated with managing our physical oil sales. Oil prices for the year
ended
million for oil purchases associated with managing our physical sales.
Natural gas prices for both the years ended
reflect operating revenues for natural gas reduced by less than
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 andcontractual deductions between the commodity price index and the actual
price at which we sold our oil and natural gas.
(3) The years ended December 31, 2019 and 2018 include approximately $8
million of cash received and $33 million of cash paid, respectively, for
the settlement of crude oil derivative contracts. The years ended
December 31, 2019 and 2018 include approximately $17 million and $14 million, respectively, of cash received for the settlement of natural gas
financial derivatives. The year ended December 31, 2018 includes
approximately $6 million of cash paid for the settlement of NGLs
derivative contracts. No cash premiums were received or paid for the years
ended December 31, 2019 and 2018.
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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 years ended
Oil Natural gas NGLs Total
(in millions)
(5 ) (10 ) (180 )
Oil sales for the year endedDecember 31, 2019 , compared to the year endedDecember 31, 2018 , decreased by$255 million (24%), due primarily to lower oil prices and lower production in all areas reflecting lower capital spending in 2019. In 2019,Eagle Ford , NEU and Permian oil production volumes decreased by 11% (2.8 MBbls/d), 13% (1.5 MBbls/d) and 32% (2.9 MBbls/d), respectively, compared with the year endedDecember 31, 2018 . Natural gas sales decreased by$26 million (35%) for the year endedDecember 31, 2019 compared to the year endedDecember 31, 2018 , due primarily to lower natural gas prices and lower production in the Eagle Ford and Permian. Our oil, natural gas and NGLs are sold at index prices (WTI, Brent, LLS,Henry Hub and Mt. Belvieu) or refiners' posted prices at various delivery points across our producing basins. Realized prices received (not considering the effects of hedges) are generally less than the stated index price as a result of fixed or variable contractual deductions, differentials from the index to the delivery point, adjustments for time, and/or discounts for quality or grade. In the Eagle Ford, our oil is sold at prices tied primarily to benchmark Magellan East Houston crude oil. In NEU, market pricing of our oil is based upon NYMEX based agreements, which reflect a locational difference at the wellhead. In the Permian, physical barrels are generally sold at the WTI Midland Index, which trades at a spread to WTI Cushing. Across all regions, natural gas realized pricing is influenced by factors such as excess royalties paid on flared gas and the percentage of proceeds retained under processing contracts, in addition to the normal seasonal supply and demand influences and those factors discussed above. The table below displays the weighted average differentials and deducts on our oil and natural gas sales on an average NYMEX price. Year ended December 31, 2019 2018 Oil Natural gas Oil Natural gas (Bbl) (MMBtu) (Bbl) (MMBtu) Differentials and deducts$ (0.97 ) $ (1.41 ) $ (1.81 ) $ (1.32 ) NYMEX$ 57.03 $ 2.63 $ 64.77 $ 3.09 Net back realization % 98.3 % 46.4 % 97.2 % 57.3 % The oil realization percentage in the year endedDecember 31, 2019 was higher as compared to 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 in the year endedDecember 31, 2019 was primarily a result of weaker Permian basin natural gas pricing. NGLs sales decreased by$58 million (48%) for the year endedDecember 31, 2019 compared with 2018 as a result of lower average realized prices due to lower pricing on all liquid components. Future growth in our overall oil, natural gas and NGLs sales (including the impact of financial derivatives) will largely be impacted by commodity pricing, our level of hedging, our ability to maintain or grow oil volumes and by the location of our production and the nature of our sales contracts. For further discussion on our derivative instruments, see Our Business and Liquidity and Capital Resources. 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 years endedDecember 31, 2019 and 2018, we recorded a derivative loss of$81 million and a derivative gain of$84 million , respectively. 47
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Operating Expenses
The tables below provide our operating expenses, volumes and operating expenses
per unit for each of the periods presented:
Year ended December 31,
2019 2018
Total Per Unit(1) Total Per Unit(1)
(in millions, except per unit costs)
Operating expenses
Oil and natural gas purchases $ - $ - $ 3 $ 0.10
Transportation costs 93 3.59 100 3.41
Lease operating expense(2) 138 5.34 158 5.35
General and administrative(3) 123 4.73 89 3.03
Depreciation, depletion and amortization 418 16.15 507 17.23
Gain on sale of assets - - (3 ) (0.13 )
Impairment charges 458 17.72 1,103 37.47
Exploration and other expense 7 0.27 5 0.18
Taxes, other than income taxes 56 2.17 77 2.61
Total operating expenses $ 1,293 $ 49.97 $
2,039
Total equivalent volumes (MBoe) 25,878 29,439
(1) Per unit costs are based on actual amounts rather than the rounded totals
presented.
(2) Includes approximately
$0.07 per Boe of adjustments under a joint venture agreement. (3) For the year endedDecember 31, 2019 , amount includes approximately$20 million or$0.76 per Boe of transition, severance and other costs,$18
million or
legacy litigation accruals or settlements. For the year ended
2018, amount includes approximately $9 million or $0.32 per Boe of
transition and severance costs related to workforce reductions, $13
million or $0.47 per Boe of incentive compensation expense.
Transportation costs. Transportation costs for the year ended December 31, 2019
decreased by $7 million as compared to 2018 primarily as a result of (i) lower
fees associated with revised transportation agreements in the Permian in 2019,
(ii) an increase in wells drilled with our drilling joint venture partner in the
Eagle Ford in 2019 (see Part II, Item 8. "Financial Statements and Supplementary
Data", Note 11), and (iii) lower transportation cost associated with the
rejection of certain transportation contracts during the fourth quarter of 2019
in conjunction with our Chapter 11 Cases.
Lease operating expense. Lease operating expense for the year ended
December 31, 2019 decreased by $20 million compared to 2018. The decrease in
2019 compared to 2018 is due primarily to lower disposal costs in all areas and
lower chemical costs in the Permian and NEU. Lease operating expense for the
year ended December 31, 2018 includes approximately $2 million in adjustments
under a joint venture agreement.
General and administrative expenses. General and administrative expenses for
the year ended December 31, 2019 increased by $34 million compared to 2018.
Higher costs during the year ended December 31, 2019 compared to 2018 were
primarily due to higher professional and legal fees of $19 million related to
legal and financial advisory fees associated with bankruptcy related matters
incurred prior to our Chapter 11 filing. Legal and financial advisory fees
incurred after our Chapter 11 filing are recorded as reorganization costs as
further noted below. Also impacting the year ended December 31, 2019 was an
accrual of $21 million related to legacy legal matters (see Part II, Item 8.
"Financial Statements and Supplementary Data", Note 9) offset by $6 million in
lower severance costs.
Depreciation, depletion and amortization expense. Depreciation, depletion and
amortization expense for the year ended December 31, 2019 decreased by $89
million compared to 2018 primarily due to non-cash impairment charges recorded
in the fourth quarter of 2018 and third quarter of 2019 on our proved properties
in the Permian and NEU, respectively, decreased capital spending and lower
production volumes. Our depreciation, depletion and amortization rate in the
future will be impacted by the level, the location, and timing of capital
spending, the overall cost of capital and the level and type of reserves
recorded on completed projects. Our average depreciation, depletion and
amortization costs per unit for the year-to-date periods were:
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Year ended December 31,
2019 2018
Depreciation, depletion and amortization ($/Boe) $ 16.15 $ 17.23
Impairment charges. For the year ended December 31, 2019 , we recorded a non-cash
impairment charge of
approximately $458 million on our NEU proved properties as a result of the
filing of our Chapter 11 Cases (see Part II, Item 8. "Financial Statements and
Supplementary Data", Note 1A) and the uncertainties surrounding the availability
of financing needed to develop our proved undeveloped reserves.
For the year ended December 31, 2018 , we recorded non-cash impairment charges of
approximately $1,044 million and $59 million on our proved and unproved
properties, respectively, in the Permian basin as a result of the decline in
commodity prices and the significant reduction in future development capital
allocated to the Permian during 2018. See Part II, Item 8. "Financial Statements
and Supplementary Data", Note 3 for more information on impairment.
Taxes, other than income taxes. Taxes, other than income taxes for the year
ended December 31, 2019 decreased by $21 million from 2018. The decrease in 2019
compared to 2018 is 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 (loss) on extinguishment/modification of debt. During the year ended
December 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.
For the year ended December 31, 2018 , we recorded a total gain on extinguishment
of debt of $73 million as a result of (i) exchanging certain senior unsecured
notes for $1,092 million in new senior secured notes and (ii) repurchasing a
portion of our senior unsecured notes due 2020, 2022 and 2023.
Interest expense. Interest expense for the year ended December 31, 2019
increased by $54 million compared to the same period in 2018 due to
reclassifying our debt as current and writing off approximately $90 million in
unamortized debt discount and debt issue costs in the third quarter 2019 as a
result of uncertainties regarding default, event of default and cross-default
provisions under our indentures and RBL Facility as of September 30, 2019
(including those discussed in Part I1, Item 8. "Financial Statements and
Supplementary Data", Note 1A). This was partially offset by discontinuing the
accrual of interest during substantially all of the fourth quarter of 2019
associated with the 1.5 lien notes and senior unsecured notes classified as
liabilities subject to compromise as a result of filing the Chapter 11 Cases on
October 3, 2019 . Also impacting interest expense for the year ended December 31,
2019 was the issuance of our senior secured notes due 2026 in May 2018 .
Reorganization items, net. Reorganization items, net were $65 million for the
year ended December 31, 2019 . The reorganization items primarily consisted of
expenses and gains/(losses) realized or incurred subsequent to our bankruptcy
filing petition date and that are a direct result of the Chapter 11 Cases. These
costs include professional fees incurred subsequent to the filing of the date of
the Chapter 11 Cases, amounts recorded associated with the rejection of
executory contracts approved by the Bankruptcy Court and DIP Facility costs.
Income taxes. Our effective tax rate for both the years ended December 31, 2019
and 2018 was 0%, which differed from the statutory rate of 21% primarily due to
recording a full valuation allowance on our net deferred tax assets,
non-deductible compensation expenses, and a non-deductible loss carryover.
Changes in our deferred taxes from year to year are offset by changes to our
related valuation allowance and thus have the effect of eliminating the impact
of federal taxes on our income. For additional details on our income taxes, see
Part II, Item 8. "Financial Statements and Supplementary Data", Note 4.
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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), incentive compensation expense
(which represents non-cash compensation expense under our long-term incentive
programs), transition, severance and other costs that affect comparability,
reorganization items, fees paid to our Sponsors, legacy litigation settlements,
gains and losses on sale of assets, gains and losses on
extinguishment/modification of debt and impairment charges.
We believe that the presentation of EBITDAX and Adjusted EBITDAX is important to
provide management and investors with additional information (i) to evaluate our
ability to service debt, adjusting for items required or permitted in
calculating covenant compliance under our debt agreements, (ii) to provide an
important supplemental indicator of the operational performance of our business
without regard to financing methods and capital structure, (iii) for evaluating
our performance relative to our peers, (iv) to measure our liquidity (before
cash capital requirements and working capital needs) and (v) to provide
supplemental information about certain material non-cash and/or other items that
may not continue at the same level in the future. EBITDAX and Adjusted EBITDAX
have limitations as analytical tools and should not be considered in isolation
or as a substitute for analysis of our results as reported under GAAP or as an
alternative to net income (loss), operating income (loss), operating cash flows
or other measures of financial performance or liquidity presented in accordance
with GAAP.
Below is a reconciliation of our consolidated net income (loss) to EBITDAX and
Adjusted EBITDAX:
Year ended December 31,
2019 2018
(in millions)
Net loss $ (943 ) $ (1,003 )
Income tax expense - -
Interest expense, net of capitalized interest(1) 419 365
Depreciation, depletion and amortization 418 507 Exploration expense 4 4 EBITDAX (102 ) (127 ) Mark-to-market on financial derivatives(2) 81 (84 ) Cash settlements and cash premiums on financial derivatives(3) 25 (25 ) Incentive compensation expense(4) 18 13 Transition, severance and other costs 20 9 Reorganization items, net(5) 65 - Fees paid to Sponsors 1 - Legacy litigation settlements(6) 24 - Gain on sale of assets - (3 ) Gain on extinguishment/modification of debt (10 ) (73 ) Impairment charges 458 1,103 Adjusted EBITDAX$ 580 $ 813 (1) Includes approximately$90 million at December 31, 2019 related to the write-off of unamortized debt discount and debt issue costs during the
third quarter 2019 due to reclassifying our debt as current as a result of
uncertainties regarding default, event of default and cross-default
provisions under our indentures and RBL Facility as of
Amounts written off are included in interest expense in the consolidated
statement of operations.
(2) Represents the income statement impact of financial derivatives.
(3) Represents actual cash settlements related to financial derivatives. No
cash premiums were received or paid for the years ended December 31, 2019
and 2018.
(4) For the year ended December 31, 2019 , incentive compensation expense
includes
"KERP", in lieu of long-term incentive compensation. For additional
details on the KERP, see Part II, Item 8. "Financial Statements and
Supplementary Data", Note 10.
(5) Includes expenses and gains/(losses) realized or incurred subsequent to
our bankruptcy filing petition date and that are a direct result of the
Chapter 11 Cases. These costs include professional fees incurredsubsequent to the filing date of the Chapter 11 Cases, amounts recorded
associated with the rejection of executory contracts approved by the
Bankruptcy Court and DIP Facility costs. For additional details on
reorganization items, see Part II, Item 8. "Financial Statements and
Supplementary Data", Note 1A.
(6) Reflects amounts accrued primarily related to our Fairfield legal case.For additional details on our legacy legal matters, see Part II, Item 8.
"Financial Statements and Supplementary Data", Note 9.
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Commitments and ContingenciesFor a further discussion of our commitments and contingencies, see Part II, Item 8. "Financial Statements and Supplementary Data", Note 9.
Off-Balance Sheet Arrangements
We have no investments in unconsolidated entities or persons that could
materially affect our liquidity or the availability of capital resources. We do
not have any off-balance sheet arrangements that have, or are reasonably likely
to have, a material effect on our financial condition or results of operations.
Critical Accounting Estimates
Our significant accounting policies are described in Part II, Item 8. "Financial
Statements and Supplementary Data", Note 1 of our consolidated financial
statements included elsewhere in this Annual Report on Form 10-K. The
preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amount of assets, liabilities, revenue and expense and the
disclosures of contingent assets and liabilities. We consider our critical
accounting estimates to be those estimates that require complex or subjective
judgment in the application of the accounting policy and that could
significantly impact our financial results based on changes in those judgments.
Changes in facts and circumstances may result in revised estimates and actual
results may differ materially from those estimates. Our management has
identified the following critical accounting estimates:
Accounting for Oil and Natural Gas Producing Activities. We apply the
successful efforts method of accounting for our oil and natural gas exploration
and development activities. Under this method, non-drilling exploratory costs
and costs of carrying and retaining undeveloped properties are charged to
expense as incurred while acquisition costs, development costs and the costs of
drilling and completing wells are capitalized. If a well is exploratory in
nature, such costs are capitalized, pending the determination of proved oil and
natural gas reserves. As a result, at any point in time, we may have capitalized
costs on our consolidated balance sheet associated with exploratory wells that
may be charged to exploration expense in a future period. Costs of drilling
exploratory wells that do not result in proved reserves are expensed. Under the
successful efforts method, we also capitalize salaries and benefits that we
determine are directly attributable to our oil and natural gas activities.
Depreciation, depletion, amortization and the impairment of oil and natural gas
properties is calculated on a depletable unit basis based on estimates of proved
quantities of proved oil and natural gas reserves. Revisions to these estimates
can alter our depletion rates in the future and affect our future depletion
expense or assessment of impairment.
We evaluate capitalized costs related to proved properties at least annually or
upon a triggering event (such as a significant decline in forward commodity
prices or change in development plans, among other items) to determine if
impairment of such properties has occurred. Our evaluation of whether costs are
recoverable is made based on common geological structure or stratigraphic
conditions (for example, we evaluate proved property for impairment separately
for each of our operating areas), and the evaluation considers estimated future
cash flows for all proved developed (producing and non-producing), proved
undeveloped reserves and risk-weighted non-proved reserves in comparison to the
carrying amount of the proved properties. Important assumptions in the
determination of these cash flows are estimates of future oil and gas
production, estimated forward commodity prices as of the date of the estimate,
adjusted for geographical location and contractual and quality differentials and
estimates of future operating and development costs. If the carrying amount of a
property exceeds the estimated undiscounted future cash flows of its reserves,
the carrying amount is reduced to estimated fair value through a charge to
income. Fair value is calculated by discounting those estimated future cash
flows using a risk-adjusted discount rate. The discount rate is based on rates
utilized by market participants that are commensurate with the risks inherent in
the development and production of the underlying crude oil and natural gas. Each
of these estimates involves a high degree of judgment.
Capitalized costs associated with unproved properties (e.g., leasehold
acquisition costs associated with non-producing areas) are also assessed for
impairment based on estimated drilling plans and capital expenditures, which may
also change relative to forward commodity prices and/or potential lease
expirations. Generally, economic recovery of unproved reserves in non-producing
areas are not yet supported by actual production or conclusive formation tests,
but must be confirmed by continued exploration and development activities. Our
allocation of capital to the development of unproved properties may be
influenced by changes in commodity prices (e.g., a low oil price environment),
the availability of oilfield services and the relative returns of our unproved
property development in comparison to the use of capital for other strategic
objectives.
During the year ended December 31, 2019 , we recorded a non-cash impairment
charge of approximately $458 million on our NEU proved properties as a result of
the filing of our Chapter 11 Cases (see Part II, Item 8. "Financial Statements
and Supplementary Data", Note 1A) and the uncertainties surrounding the
availability of financing needed to develop our proved undeveloped reserves.
During the year ended December 31, 2018 , we recorded non-cash impairment charges
of approximately
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$1,044 million and$59 million on our proved and unproved properties, respectively, in the Permian basin due to the decline in commodity prices during the year as well as the significant reduction in future development capital allocated to the Permian during 2018. As ofDecember 31, 2019 , our remaining net capitalized costs related to proved properties were approximately$1,961 million in Eagle Ford,$721 million in NEU, and$716 million in the Permian basin. The proved oil and gas reserve estimates as ofDecember 31, 2019 have been prepared byRyder Scott Company, L.P. ("Ryder Scott"), our independent third party reserve engineers. Estimates of proved reserves reflect quantities of oil, natural gas and NGLs, which geological and engineering data demonstrate, with reasonable certainty, will be recoverable in future years from known reservoirs under existing economic conditions. These estimates of proved oil and natural gas reserves primarily impact our property, plant and equipment amounts on our balance sheets and the depreciation, depletion and amortization amounts, including any impairment charges, on our consolidated income statements, among other items. The process of estimating oil and natural gas reserves is complex and requires significant judgment to evaluate all available geological, geophysical engineering and economic data. Significant assumptions used in the proved oil and gas reserve estimates are assessed by both Ryder Scott and our internal reserve team. All reserve reports prepared by Ryder Scott were reviewed by our internal reserve and management teams. Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. As ofDecember 31, 2019 , 100% of our total proved reserves were proved developed reserves. The data for a given field may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. In addition, the subjective decisions and variances in available data for various fields increase the likelihood of significant changes in these estimates. As a result, material revisions to existing reserve estimates occur from time to time. For example, in 2018 we adjusted our PUD booking methodology from a five-year to a three-year timeframe and in 2019, we recorded no PUD reserves due to uncertainty regarding the Company's availability of capital prior to emerging from bankruptcy that would be required to develop the PUD reserves (see Part II, Item 8. "Financial Statements and Supplementary Data", Note 1A). See Part I, Item 1. "Business" under the headingOil and Natural Gas Properties for further discussion on our proved reserves. Deferred Taxes and Valuation Allowances. We record deferred income tax assets and liabilities reflecting the tax consequences of differences between the financial statement carrying value of assets and liabilities and the tax basis of those assets and liabilities. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. Our deferred tax assets and liabilities reflect our conclusions about which positions are more likely than not to be sustained if they are audited by taxing authorities. We assess the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of existing deferred tax assets. When it is more likely than not that we will not be able to realize all or a portion of such asset, we record a valuation allowance. Based upon the evaluation of the available evidence, we maintained a valuation allowance against our net deferred tax assets of$1,064 million as ofDecember 31, 2019 . We evaluate our valuation allowances each reporting period and the level of such allowance will change as our deferred tax balances change. Key estimates and assumptions include expectations of future taxable income and the ability and our intent to undertake transactions that will allow us to realize the asset, all of which involve judgment. Changes in these estimates or assumptions can have a significant effect on our operating results. ITEM 7A. Qualitative and Quantitative Disclosures About Market Risk We are exposed to market risks in our normal business activities. Market risk is the potential loss that may result from market changes associated with an existing or forecasted financial or commodity transaction. The types of market risks we are exposed to and examples of each are: Commodity Price Risk • changes in oil, natural gas and NGLs prices impact the amounts at which we sell our production and affect the fair value of our oil and natural gas derivative contracts; and • changes in locational price differences also affect amounts at which we sell our oil, natural gas and NGLs production, and the fair values of any related derivative products. 52
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Interest Rate Risk
• changes in interest rates affect the interest expense we incur on
our variable-rate debt and the fair value of fixed-rate debt; and
• changes in interest rates used to discount liabilities result in
higher or lower recorded amount of liabilities and accretion expense
over time.
Risk Management Activities
Where practical, we manage commodity price risks by entering into contracts
involving physical or financial settlement that attempt to limit exposure
related to future market movements on our cash flows. The timing and extent of
our risk management activities are based on a number of factors, including our
market outlook, risk tolerance and liquidity. Our risk management activities
typically involve the use of the following types of contracts:
• forward contracts, which commit us to purchase or sell energy
commodities in the future;
• option contracts, which convey the right to buy or sell a commodity,
financial instrument or index at a predetermined price;
• swap contracts, which require payments to or fromcounterparties
based upon the differential between two prices or rates for a
predetermined contractual (notional) quantity; and
• structured contracts, which may involve a variety of the above
characteristics.
Many of the contracts we use in our risk management activities qualify as
derivative financial instruments. A discussion of our accounting policies for
derivative instruments is included in Part II Item 8. "Financial Statements and
Supplementary Data", Notes 1 and 6.
For information regarding changes in commodity prices during 2019, please see
Part II, Item 7. "Management's Discussion and Analysis of Financial Condition
and Results of Operations".
Commodity Price Risk
Oil, Natural Gas and NGLs Derivatives. We attempt to mitigate commodity price
risk and stabilize cash flows associated with our forecasted sales of oil and
natural gas production through the use of derivative oil and natural gas swaps,
basis swaps and option contracts. These contracts impact our earnings as the
fair value of these derivatives changes. Our derivatives do not mitigate all of
the commodity price risks of our forecasted sales of oil and natural gas
production and, as a result, we are subject to commodity price risks on our
remaining forecasted production.
Sensitivity Analysis. 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 December 31, 2019 :
Oil and Natural Gas Derivatives
10 Percent Increase 10 Percent Decrease
Fair Value Fair Value Change Fair Value Change
(in millions)
Price impact(1) $ 9 $ (42 ) $ (51 ) $ 52 $ 43 Oil and Natural Gas Derivatives
1 Percent Increase 1 Percent Decrease
Fair Value Fair Value Change Fair Value Change
(in millions)
Discount Rate(2) $ 9 $ 8 $ (1 ) $ 9 $ -
Credit rate(3) $ 9 $ 8 $ (1 ) $ 9 $ -
(1) Presents the hypothetical sensitivity of our commodity-based derivatives to
changes in fair values arising from changes in oil and natural gas 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
Interest Rate Risk
Certain of our debt agreements are sensitive to changes in interest rates. The
table below shows the maturity of the carrying amounts and related
weighted-average effective interest rates on our long-term interest-bearing debt
by expected
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maturity date as well as the total fair value of the debt. The fair value of
our long-term debt has been estimated primarily based on quoted market prices
for the same or similar issues.
December 31, 2019 December 31, 2018
Expected Fiscal Year of Maturity of Carrying Amounts
2020 2021 2022 2023 2024 Thereafter Total Fair Value Carrying Amounts Fair Value
(in millions)
Fixed rate
debt $ 182 $ - $ 182 $ 324 $ 1,592 $ 2,000 $ 4,280 $ 1,023 $ 4,330 $ 2,468
Average
interest rate 8.2 % 8.2 % 8.2 % 8.3 % 8.1 % 7.8 %
Variable rate
debt $ 148 $ 315 - - - - $ 463 $ 463 $ 108 $ 108
Average
interest rate 5.3 % 5.3 % - % - % - % - %
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