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MarketScreener Homepage  >  Equities  >  OTC Bulletin Board - Other OTC  >  EP Energy Corporation    EPEGQ

EP ENERGY CORPORATION

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EP ENERGY : Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-Q)

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11/12/2019 | 04:50pm EST
Our Management's Discussion and Analysis of Financial Condition and Results of
Operations ("MD&A") should be read in conjunction with the financial statements
and the accompanying notes presented in Item 1 of Part I of this Quarterly
Report on Form 10-Q. This discussion contains forward-looking statements and
involves numerous risks and uncertainties, including, but not limited to, those
described in the "Risk Factors" section of this Quarterly Report on Form 10-Q
and our 2018 Annual Report on Form 10-K. Actual results may differ materially
from those contained in any forward-looking statements.  Unless otherwise
indicated or the context otherwise requires, references in this MD&A section to
"we", "our", "us" and "the Company" refer to EP Energy Corporation and each of
its consolidated subsidiaries.

                                  Our Business
Overview.  We are an independent exploration and production company engaged in
the acquisition and development of unconventional onshore oil and natural gas
properties in the United States.  We operate through a diverse base of producing
assets through the development of our drilling inventory located in three
areas: the Eagle Ford Shale in South Texas, Northeastern Utah (NEU) in the Uinta
basin, and the Permian basin in West Texas.
Recent Developments - Chapter 11 Proceedings. On October 3, 2019, the Debtors
filed the Chapter 11 Cases in the Bankruptcy Court seeking relief under the
Bankruptcy Code. We expect to continue operations in the normal course during
the pendency of the Chapter 11 Cases. To ensure ordinary course operations, the
Debtors have obtained approval from the Bankruptcy Court for a variety of "first
day" motions, including motions to obtain customary relief intended to assure
our ability to continue our ordinary course operations after the filing date. In
addition, the Debtors have received authority to use cash collateral of the
lenders under the Reserve-Based Loan Facility (RBL Facility). For a further
discussion of the Chapter 11 Cases and related matters, see Liquidity and
Capital Resources and Part I, Item 1, Financial Statements, Notes 1A, 7 and 8.
Strategy. Our strategy is to invest in opportunities that provide the highest
return across our asset base, continually seek out operating and capital
efficiencies, effectively manage costs, and identify accretive acquisition
opportunities and divestitures, all with the objective of enhancing our
portfolio, growing asset value, improving cash flow and increasing financial
flexibility. We evaluate opportunities in our portfolio that are aligned with
this strategy and our core competencies and that offer a competitive advantage.
In addition to opportunities in our current portfolio, strategic acquisitions of
leasehold acreage or acquisitions of producing assets allow us to leverage
existing expertise in our areas, balance our exposure to regions, basins and
commodities, help us to achieve or enhance risk-adjusted returns competitive
with those available in our existing programs and increase our reserves. We also
continuously evaluate our asset portfolio and will sell oil and natural gas
properties if they no longer meet our long-term objectives.
We are party to a drilling joint venture agreement in the Eagle Ford with a
total anticipated joint venture investment of $225 million. As of the second
quarter 2019, we had drilled and completed all wells under the amended
agreement. Additionally, subject to certain time limits, we will provide our
joint venture partner the option to participate in additional wells in the
development areas. For a further discussion on this joint venture, see Part I,
Item 1, Financial Statements, Note 10. In NEU, we are also party to a drilling
joint venture agreement under which our joint venture partner is participating
in the development of 53 wells. As of September 30, 2019, we have drilled and
completed 51 wells under the NEU joint venture agreement.

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

•growing our proved reserve base and production volumes through the successful
execution of our drilling
programs or through acquisitions;
•finding and producing oil and natural gas at reasonable costs;
•managing operating and capital costs;
•managing commodity price risks on our oil and natural gas production; and
•managing debt levels and related interest costs.
In addition to these factors, our future profitability and performance is
affected by volatility in the financial and commodity markets. Commodity price
changes may affect our future capital spending levels, production rates and/or
related

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operating revenues (net of any associated royalties), levels of proved reserves and development plans, all of which impact performance and profitability.


Forward commodity prices play a significant role in determining the
recoverability of proved property costs on our balance sheet. While prices have
generally stabilized over recent years, future price declines, along with
changes to our future capital spending levels, production rates, levels of
proved reserves and development plans may result in an impairment of the
carrying value of our proved properties in the future, and such charges could be
significant.

 Derivative Instruments.  Our realized prices from the sale of our oil, natural
gas and NGLs are affected by (i) commodity price movements, including locational
or basis price differences that exist between the commodity index price (e.g.,
WTI) and the actual price at which we sell our commodities and (ii) other
contractual pricing adjustments contained in our underlying sales contracts.  In
order to stabilize cash flows and protect the economic assumptions associated
with our capital investment programs, we enter into financial derivative
contracts to reduce the financial impact of downward commodity price movements
and unfavorable movements in locational prices. Adjustments to our strategy and
the decision to enter into new contracts or positions or to alter existing
contracts or positions are made based on the goals of the overall company.
Because we apply mark-to-market accounting on our derivative contracts, our
reported results of operations and financial position can be impacted
significantly by commodity price movements from period to period.
The following table and discussion reflects the contracted volumes and the
prices we will receive under derivative contracts we held as of September 30,
2019.
                                    2019                       2020
                                         Average                     Average
                          Volumes(1)     Price(1)    Volumes(1)     Price(1)
Oil
Collars
Ceiling - WTI                    368    $  69.78              -    $        -
Floors - WTI                     368    $  57.50              -    $        -
Three Way Collars
Ceiling - WTI                  3,036    $  66.01         11,712    $    65.11
Floors - WTI                   3,036    $  55.76         11,712    $    55.90
 Sub-Floor - WTI               3,036    $  45.00         11,712    $    45.00
Basis Swaps
Midland vs. Cushing(2)           368    $  (5.23 )        1,464    $     0.46
NYMEX Roll(3)                    184    $   0.25              -    $        -
Natural Gas
Fixed Price Swaps                  3    $   3.01              -    $        -
Collars
Ceiling                            3    $   4.26              -    $        -
    Floors                         3    $   2.75              -    $        -





(1)    Volumes presented are MBbls for oil and TBtu for natural gas. Prices
       presented are per Bbl of oil and MMBtu of natural gas.


(2) EP Energy receives Cushing plus the basis spread listed and pays Midland.

(3) These positions hedge the timing risk associated with our physical sales.

We generally sell oil for the delivery month at a sales price based on the

average NYMEX WTI price during that month, plus an adjustment calculated

as a spread between the weighted average prices of the delivery month, the

next month and the following month during the period when the delivery

month is prompt (the "trade month roll").

(4) EP Energy receives Henry Hub plus the basis spread listed and pays WAHA.




For our three-way collar contracts in the tables above, the sub-floor prices
represent the price below which we receive WTI plus a weighted average spread of
$10.76 in 2019 and $10.90 in 2020 on the indicated volumes. If WTI is above our
sub-floor prices, we receive the noted floor price until WTI exceeds that floor
price. Above the floor price, we receive WTI until prices exceed the noted
ceiling price in our three-way collars, at which time we receive the fixed
ceiling price. As of September 30, 2019, the average forward price of oil was
$53.84 per barrel of oil for the remainder of 2019 and $51.46 per barrel of oil
for 2020.

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

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crude oil contracts allow for upside participation (to a weighted average price
of approximately $66.41 per barrel for 2019 and $65.11 per barrel for 2020)
while containing certain sub-floor prices (weighted average prices of $45.00 per
barrel) that limit the amount of our derivative settlements under these
three-way contracts should prices drop below the sub-floor prices. To the extent
our oil, natural gas and NGLs production is unhedged, either from a commodity
index or locational price perspective, our operating revenues will be impacted
from period to period.


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                        Liquidity and Capital Resources

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

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

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

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

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

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

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

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


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We expect to continue operations in the normal course during the pendency of the
Chapter 11 Cases. To ensure ordinary course operations, the Debtors have
obtained approval from the Bankruptcy Court for a variety of "first day"
motions, including motions to obtain customary relief intended to assure our
ability to continue our ordinary course operations after the filing date. In
addition, the Debtors have received authority to use cash collateral of the
lenders under the RBL Facility.

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

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

Capital Expenditures. Our capital expenditures and average drilling rigs by area for the nine months ended September 30, 2019 were:

                                Capital
                            Expenditures(1)     Average Drilling
                             (in millions)            Rigs
Eagle Ford Shale           $             348                 2.3
Northeastern Utah                         92                 1.6
Permian                                    4                   -
Total                      $             444                 3.9
  Acquisition capital      $              18
Total Capital Expenditures $             462





(1) Represents accrual-based capital expenditures.






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Overview of Cash Flow Activities.  Our cash flows are summarized as follows (in
millions):

                                                            Nine months ended
                                                              September 30,
                                                            2019         2018
Cash Inflows
Operating activities
Net loss                                                 $    (810 )$   (84 )
Gain on sale of assets                                           -          (1 )
Gain on extinguishment/modification of debt                    (10 )       (48 )
Write-off of debt discount and deferred issue costs             90          

-

Other income adjustments                                       782         

398

Changes in assets and liabilities                               97         

115

Total cash flow from operations                                149         

380


Investing activities
Proceeds from the sale of assets                                 -         

175

Cash inflows from investing activities                           -         

175


Financing activities
Proceeds from issuance of long-term debt                       923       

1,805

Cash inflows from financing activities                         923       1,805

Total cash inflows                                       $   1,072$ 2,360

Cash Outflows
Investing activities
Capital expenditures                                     $     422$   559
Cash paid for acquisitions                                      18         275
Cash outflows from investing activities                        440         

834


Financing activities
Repayments and repurchases of long-term debt                   468       

1,431

Fees/costs on debt exchange                                      -          62
Debt issue costs                                                 -          21
Other                                                            2           1
Cash outflows from financing activities                        470       1,515

Total cash outflows                                      $     910$ 2,349

Net change in cash, cash equivalents and restricted cash $ 162$ 11





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                    Production Volumes and Drilling Summary

Production Volumes. Below is an analysis of our production volumes for the nine months ended September 30:


                            2019    2018
Equivalent Volumes (MBoe/d)
Eagle Ford                  32.9    37.0
Northeastern Utah           15.5    17.2
Permian                     21.6    26.8
Total                       70.0    81.0

Oil (MBbls/d)
Eagle Ford                  21.8    25.2
Northeastern Utah           10.1    11.8
Permian                      6.4     9.4
Total                       38.3    46.4

Natural Gas (MMcf/d)
Eagle Ford(1)                 33      35
Northeastern Utah             32      32
Permian                       48      56
Total                        113     123

NGLs (MBbls/d)
Eagle Ford                   5.6     6.0
Northeastern Utah              -       -
Permian                      7.2     8.1
Total                       12.8    14.1





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



Production Summary. For the nine months ended September 30, 2019 compared to the
same period in 2018, (i) Eagle Ford equivalent volumes decreased 4.1 MBoe/d or
(approximately 11%) due to fewer wells placed on production in the second half
of 2018 through 2019, (ii) NEU equivalent volumes decreased 1.7 MBoe/d or
(approximately 10%) due to reduced drilling activity in 2019, and (iii) Permian
equivalent volumes decreased 5.2 MBoe/d or (approximately 19%) reflecting the
slower pace of development due to a significant reduction in capital allocated
to the Permian. In Eagle Ford and Permian, our 2019 production volumes were also
negatively impacted by downstream third-party operational issues and constraints
and more reinjected gas as compared to the same period in 2018.

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



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                             Results of Operations

The information in the table below provides a summary of our financial results.
                                               Quarter ended         Nine months ended
                                               September 30,           September 30,
                                              2019       2018         2019         2018
                                                            (in millions)
Operating revenues
Oil                                         $   193$ 287$     590$ 820
Natural gas                                      10        15            36          55
NGLs                                             12        36            45          92
Total physical sales                            215       338           671         967
Financial derivatives                            32       (44 )         (34 )      (122 )
Total operating revenues                        247       294           637         845

Operating expenses
Oil and natural gas purchases                     -         3             -           3
Transportation costs                             23        25            71          76
Lease operating expense                          34        46           101         123
General and administrative                       38        21           102          68
Depreciation, depletion and amortization        116       127           304         376
Gain on sale of assets                            -        (1 )           -          (1 )
Impairment charges                              458         -           458           -
Exploration and other expense                     1         2             3 

3

Taxes, other than income taxes                   12        22            43          63
Total operating expenses                        682       245         1,082         711

Operating (loss) income                        (435 )      49          (445 )       134
Other income                                      4         2             4           2
Gain on extinguishment/modification of debt       -         -            10          48
Interest expense                               (189 )     (95 )        (379 )      (268 )
Loss before income taxes                       (620 )     (44 )        (810 )       (84 )
Income tax expense                                -         -             -           -
Net loss                                    $  (620 )$ (44 )$    (810 )$ (84 )




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Operating Revenues


The table below provides our operating revenues, volumes and prices per unit for
the quarters and nine months ended September 30, 2019 and 2018. We present
(i) average realized prices based on physical sales of oil, natural gas and NGLs
as well as (ii) average realized prices inclusive of the impacts of financial
derivative settlements and premiums which reflect cash received or paid during
the respective period.

                                                Quarter ended             Nine months ended
                                                September 30,               September 30,
                                             2019          2018           2019          2018
                                                              (in millions)
Operating revenues:
Oil                                       $     193$     287$      590$     820
Natural gas                                      10            15             36            55
NGLs                                             12            36             45            92
Total physical sales                            215           338            671           967
Financial derivatives                            32           (44 )          (34 )        (122 )
Total operating revenues                  $     247$     294$      637$     845

Volumes:
Oil (MBbls)                                   3,487         4,262         10,457        12,648
Natural gas (MMcf)                            9,654        11,121         30,931        33,730
NGLs (MBbls)                                  1,090         1,285          3,518         3,851
Equivalent volumes (MBoe)                     6,186         7,401         19,130        22,121
Total MBoe/d                                   67.2          80.4           70.0          81.0

Prices per unit(1):
Oil
Average realized price on physical sales
($/Bbl)(2)                                $   55.25$   66.61$    56.40$   64.61
Average realized price, including
financial derivatives ($/Bbl)(2)(3)       $   55.50$   63.37$    57.10$   61.55
Natural gas
Average realized price on physical sales
($/Mcf)(2)                                $    1.04$    1.34$     1.16$    1.62
Average realized price, including
financial derivatives ($/Mcf)(2)(3)       $    1.74$    1.69$     1.62$    1.89
NGLs
Average realized price on physical sales
($/Bbl)                                   $   10.98$   27.74$    12.93$   23.80
Average realized price, including
financial derivatives ($/Bbl)(3)          $   10.98$   24.79$    12.93$   22.60





(1)    For the quarter and nine months ended September 30, 2019, there were no
       oil purchases associated with managing our physical oil sales. For both

the quarter and nine months ended September 30, 2018, oil prices reflect

       operating revenues for oil reduced by $3 million for oil purchases
       associated with managing our physical oil sales. Natural gas prices for
       both the quarters and nine months ended September 30, 2019 and 2018

reflect operating revenues for natural gas reduced by less than $1 million

for natural gas purchases associated with managing our physical sales.


(2)    Changes in realized oil and natural gas prices reflect the effects of
       unhedged locational or basis differentials, unhedged volumes and

contractual deductions between the commodity price index and the actual

price at which we sold our oil and natural gas.

(3) The quarters ended September 30, 2019 and 2018, include cash received of

approximately $1 million and cash paid of approximately $14 million,

respectively, for the settlement of crude oil derivative contracts and

approximately $7 million and $4 million of cash received, respectively,

for the settlement of natural gas financial derivatives. The nine months

ended September 30, 2019 and 2018, include cash received of approximately

       $7 million and cash paid of approximately $39 million, respectively, for
       the settlement of crude oil derivative contracts and approximately $14

million and $9 million of cash received, respectively, for the settlement

of natural gas financial derivatives. The quarter and nine months ended

September 30, 2018 also include $4 million and $5 million, respectively,

       of cash paid for the settlement of NGLs derivative contracts.














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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 quarter and nine months ended September 30, 2019 and 2018.

                                        Quarter ended
                           Oil      Natural gas      NGLs     Total
                                        (in millions)

September 30, 2018 sales $ 287$ 15$ 36$ 338 Change due to prices (42 )

           (3 )      (18 )     (63 )
Change due to volumes      (52 )           (2 )       (6 )     (60 )

September 30, 2019 sales $ 193$ 10$ 12$ 215



                                      Nine months ended
                           Oil      Natural gas      NGLs     Total
                                        (in millions)

September 30, 2018 sales $ 820$ 55$ 92$ 967 Change due to prices (88 ) (14 ) (39 ) (141 ) Change due to volumes (142 )

           (5 )       (8 )    (155 )

September 30, 2019 sales $ 590$ 36$ 45$ 671




Oil sales for the quarter and nine months ended September 30, 2019, compared to
the same periods in 2018, decreased by $94 million (33%) and $230 million (28)%,
respectively, due primarily to lower oil prices and production in all areas
reflecting lower capital spending in 2019.

Natural gas sales decreased by $5 million (33%) and $19 million (35)%,
respectively, for the quarter and nine months ended September 30, 2019 compared
to the same periods in 2018 primarily due to lower natural gas prices and lower
production primarily in the Eagle Ford and Permian.

Our oil, natural gas and NGLs are sold at index prices (WTI, Brent, LLS, Henry
Hub and Mt. Belvieu) or refiners' posted prices at various delivery points
across our producing basins.  Realized prices received (not considering the
effects of hedges) are generally less than the stated index price as a result of
fixed or variable contractual deductions, differentials from the index to the
delivery point, adjustments for time, and/or discounts for quality or grade.

In the Eagle Ford, our oil is sold at prices tied primarily to benchmark
Magellan East Houston crude oil. In NEU, market pricing of our oil is based upon
NYMEX-based agreements, which reflect a locational difference at the wellhead.
In the Permian, physical barrels are generally sold at the WTI Midland Index,
which trades at a spread to WTI Cushing. Across all regions, natural gas
realized pricing is influenced by factors such as regional basis differentials,
excess royalties paid on flared gas and the percentage of proceeds retained
under processing contracts, in addition to the normal seasonal supply and demand
influences and those factors discussed above. The table below displays the
weighted average differentials and deducts on our oil and natural gas sales on
an average NYMEX price.
                                       Quarter ended September 30,
                                    2019                        2018
                             Oil       Natural gas       Oil       Natural gas
                            (Bbl)        (MMBtu)        (Bbl)        (MMBtu)
Differentials and deducts $ (0.82 )$     (1.21 )$ (2.67 )$     (1.39 )
NYMEX                     $ 56.45$      2.23$ 69.50$      2.91
Net back realization %       98.5 %          45.7 %      96.2 %          52.2 %


                                     Nine months ended September 30,
                                    2019                        2018
                             Oil       Natural gas       Oil       Natural gas
                            (Bbl)        (MMBtu)        (Bbl)        (MMBtu)
Differentials and deducts $ (0.73 )$     (1.48 )$ (1.99 )$     (1.17 )
NYMEX                     $ 57.06$      2.67$ 66.75$      2.90
Net back realization %       98.7 %          44.6 %      97.0 %          59.7 %



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The oil realization percentages for the quarter and nine months ended
September 30, 2019 were higher as compared to the same periods in 2018 primarily
as a result of the improvement of Magellan East Houston and Midland basis
pricing and physical sales contracts relative to lower NYMEX WTI pricing. The
lower natural gas realization percentage for the quarter and nine months ended
September 30, 2019 were primarily a result of weaker Permian basin natural gas
pricing.

NGLs sales decreased by $24 million (67%) and $47 million (51)%, respectively,
for the quarter and nine months ended September 30, 2019 compared with the same
periods in 2018 as a result of lower average realized prices due to lower
pricing on all liquid components.
Future growth in our overall oil, natural gas and NGLs sales (including the
impact of financial derivatives) will largely be impacted by commodity prices,
our level of hedging, our capital expenditures, our ability to maintain or grow
oil volumes and by the location of our production and the nature of our sales
contracts. See Our Business and Liquidity and Capital Resources for further
information on our derivative instruments.
Gains or losses on financial derivatives.  We record gains or losses due to
changes in the fair value of our derivative contracts based on forward commodity
prices relative to the prices in the underlying contracts. We realize such gains
or losses when we settle the derivative position. During the quarters ended
September 30, 2019 and 2018, we recorded $32 million and $44 million of
derivative gains and losses, respectively. For the nine months ended
September 30, 2019 and 2018, we recorded $34 million and $122 million of
derivative losses, respectively.
Operating Expenses
The table below provides our operating expenses, volumes and operating expenses
per unit for each of the periods presented:
                                                     Quarter ended September 30,
                                                   2019                       2018
                                          Total     Per Unit(1)      Total      Per Unit(1)
                                                (in millions, except per unit costs)
Operating expenses
Oil and natural gas purchases            $    -    $           -    $    3$      0.36
Transportation costs                         23             3.69        25            3.41
Lease operating expense                      34             5.54        46            6.16
General and administrative(2)                38             6.09        21            2.91
Depreciation, depletion and amortization    116            18.62       127           17.11
Gain on sale of assets                        -                -        (1 )         (0.13 )
Impairment charges                          458            74.10         -               -
Exploration and other expense                 1             0.12         2  

0.29

Taxes, other than income taxes               12             1.98        22  

3.02

Total operating expenses                 $  682$      110.14$  245

$ 33.13


Total equivalent volumes (MBoe)           6,186                      7,401




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                                                          Nine months ended September 30,
                                                        2019                              2018
                                              Total           Per Unit(1)         Total        Per Unit(1)
                                                        (in millions, except per unit costs)
Operating expenses
Oil and natural gas purchases            $         -        $           -     $         3     $      0.13
Transportation costs                              71                 3.70              76            3.44
Lease operating expense                          101                 5.30             123            5.53
General and administrative(2)                    102                 5.31              68            3.09
Depreciation, depletion and amortization         304                15.89             376           17.00
Gain on sale of assets                             -                    -              (1 )         (0.07 )
Impairment charges                               458                23.96               -               -
Exploration and other expense                      3                 0.10               3            0.14
Taxes, other than income taxes                    43                 2.25              63            2.86
Total operating expenses                 $     1,082$       56.51

$ 711$ 32.12


Total equivalent volumes (MBoe)               19,130                               22,121




(1) Per unit costs are based on actual amounts rather than the rounded totals

presented.

(2) For the quarter and nine months ended September 30, 2019, amount includes

       approximately $6 million or $1.02 per Boe and $13 million or $0.68 per
       Boe, respectively, of incentive compensation expense and $15 million or
       $2.53 per Boe and $19 million or $1.00 per Boe, respectively, of

transition, severance and other costs. For the nine months ended September

30, 2019, amount also includes approximately $1 million or $0.02 per Boe

of fees paid to Sponsors and $24 million or $1.25 per Boe of legacy

litigation accruals and settlements. For the quarter and nine months ended

September 30, 2018, amount includes approximately $5 million or $0.70 per

Boe and $9 million or $0.44 per Boe, respectively, of incentive

compensation expense and approximately $1 million or $0.16 per Boe and $7

million or $0.32 per Boe, respectively, of transition, severance and other

costs.



Transportation costs. Transportation costs for the quarter and nine months ended
September 30, 2019 decreased by $2 million and $5 million, respectively,
compared to the same periods in 2018 as a result of (i) lower fees associated
with revised transportation agreements in the Permian in 2019, and (ii) an
increase in wells drilled with our drilling joint venture partner in the Eagle
Ford in 2019 (see Part I, Item 1, Financial Statements, Note 10).

Lease operating expense.  Lease operating expense decreased by $12 million and
$22 million for the quarter and nine months ended September 30, 2019,
respectively, compared to the same periods in 2018. The decrease for the quarter
ended September 30, 2019 compared to 2018 is due primarily to lower disposal and
chemical costs in the Eagle Ford and Permian and lower maintenance costs in the
Eagle Ford. The decrease for the year ended September 30, 2019 compared to 2018
is due primarily to lower disposal and maintenance costs in the Eagle Ford and
Permian and lower chemical costs in the Permian.

General and administrative expenses.  General and administrative expenses for
the quarter and nine months ended September 30, 2019 increased by $17 million
and $34 million, respectively, compared to the same periods in 2018. Higher
costs during the quarter and nine months ended September 30, 2019 compared to
the same periods in 2018 were primarily due to higher professional and legal
fees of $15 million and $18 million, respectively, related to legal and
financial advisory fees associated with bankruptcy related matters prior to our
Chapter 11 filing. Also impacting the nine months ended September 30, 2019 was
an accrual of $21 million related to legacy legal matters (see Part 1, Item 1,
Financial Statements, Note 8) offset by $6 million in lower severance costs.

Depreciation, depletion and amortization expense. Depreciation, depletion and
amortization expense decreased for the quarter and nine months ended
September 30, 2019 primarily due to a non-cash impairment charge recorded in the
fourth quarter of 2018 on our proved properties in the Permian, decreased
capital spending and lower production volumes when compared to the same periods
in 2018. Our depreciation, depletion and amortization rate in the future will be
impacted by the level, the location, and timing of capital spending, the overall
cost of capital and the level and type of reserves recorded on completed
projects. Our average depreciation, depletion and amortization costs per unit
for the quarter and nine months ended September 30 were:

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                                            Quarter ended                 Nine months ended
                                            September 30,                   September 30,
                                         2019           2018             2019             2018
Depreciation, depletion and
amortization ($/Boe)                 $    18.62$    17.11$     15.89$    17.00



Impairment charges. For both the quarter and nine months ended September 30,
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 I, Item 1, Financial Statements, Note 1A) and the uncertainties surrounding
the availability of financing needed to develop our proved undeveloped reserves.
See Part I, Item 1, Financial Statements, Note 2, for more information on
impairment.

Taxes, other than income taxes. Taxes, other than income taxes, for the quarter
and nine months ended September 30, 2019, decreased by $10 million and $20
million, respectively, compared to the same periods in 2018, primarily due to a
decrease in severance taxes as a result of lower commodity prices and the
realization of severance tax credits.

Other Income Statement Items.


Gain on extinguishment/modification of debt. During the nine months ended
September 30, 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.

During the nine months ended September 30, 2018, we recorded a total gain on
extinguishment of debt of $48 million primarily as a result of exchanging
certain senior unsecured notes for approximately $1.1 billion in new 1.5 Lien
Notes due 2024. See Part 1, Item 1, Financial Statements, Note 7 for more
information on our long-term debt.

Interest expense. Interest expense for the quarter and year ended September 30,
2019 increased by $94 million and $111 million, respectively, compared to the
same periods in 2018 due to reclassifying our debt as current and writing off
approximately $90 million in unamortized debt discount and debt issue costs as a
result of uncertainties regarding default, event of default and cross-default
provisions under our indentures and RBL Facility (including those discussed in
Part 1, Item 1, Financial Statements, Note 1A). Also impacting interest expense
for the nine months ended September 30, 2019 was the issuance of our senior
secured notes due 2026 in May 2018, partially offset by lower average borrowings
under our RBL Facility and the repurchases of a portion of our senior unsecured
notes due 2020, 2022 and 2023.

Income taxes. For both the quarters and nine months ended September 30, 2019 and
2018, our effective tax rates were approximately 0%. Our effective tax rates in
2019 and 2018 differed from the statutory rate of 21% primarily as a result of
our recognition of a full valuation allowance on our net deferred tax assets. In
addition, we recorded adjustments to the valuation allowance on our net deferred
tax assets, which offset deferred income tax benefits by $135 million and $10
million, for the quarters ended September 30, 2019 and 2018, respectively, and
by $174 million and $18 million for the nine months ended September 30, 2019 and
2018, respectively.




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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,
management and other fees paid to 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 (loss) income to EBITDAX and
Adjusted EBITDAX:
                                                Quarter ended               Nine months ended
                                                September 30,                 September 30,
                                              2019          2018           2019            2018
                                                                (in millions)
Net loss                                  $     (620 )$     (44 )$     (810 )$     (84 )
Income tax expense                                 -             -              -               -
Interest expense, net of capitalized
interest(1)                                      189            95            379             268
Depreciation, depletion and amortization         116           127            304             376
Exploration expense                                1             1              3               3
EBITDAX                                         (314 )         179           (124 )           563
Mark-to-market on financial
derivatives(2)                                   (32 )          44             34             122
Cash settlements and cash premiums on
financial derivatives(3)                           8           (14 )           22             (34 )
Incentive compensation expense(4)                  6             5             13               9
Transition, severance and other costs             15             1             19               7
Fees paid to Sponsors                              -             -              1               -
Legacy litigation settlements(5)                   -             -             24               -
Gain on sale of assets                             -            (1 )            -              (1 )
Gain on extinguishment/modification of
debt                                               -             -            (10 )           (48 )
Impairment charges                               458             -            458               -
Adjusted EBITDAX                          $      141$     214$      437$     618






(1)    Includes approximately $90 million at September 30, 2019 related to the
       write-off of unamortized debt discount and debt issue costs 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 (including those discussed in Part 1, Item 1,

Financial Statements, Note 1A).

(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 quarters and nine months ended
       September 30, 2019 and 2018.


(4)    For the quarter and nine months ended September 30, 2019, incentive

compensation expense includes $5 million and $6 million, respectively, in

amounts under the Key Employee Retention Program, "KERP", in lieu of

long-term incentive compensation. For additional details on the KERP, see

       Part I, Item 1, Financial Statements, Note 9.


(5)    Reflects amounts accrued related to Fairfield and Weyerhaeuser legal
       cases. For additional details on our legacy legal matters, see Part I,
       Item 1, Financial Statements, Note 8.






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                         Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Part I, Item 1, Financial Statements, Note 8.

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