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MarketScreener Homepage  >  Equities  >  Nyse  >  Range Resources    RRC

RANGE RESOURCES

(RRC)
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RANGE RESOURCES : MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-K)

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02/27/2020 | 05:30pm EDT
The following discussion is intended to assist you in understanding our business
and results of operations together with our present financial condition and
should be read in conjunction with the information under Item 8. Financial
Statements and Supplementary Data and other financial information found
elsewhere in this Form 10-K. See also matters referenced in the foregoing pages
under "Disclosures Regarding Forward-Looking Statements."

The following tables and discussions set forth key operating and financial data
for the years ended December 31, 2019 and 2018. For similar discussions of the
year ended December 31, 2018 compared to December 31, 2017 results, refer to
Item 7. "Managements' Discussion and Analysis of Financial Condition and Results
of Operations" under Part II of our annual report on Form 10-K for the year
ended December 31, 2018 which was filed with the SEC on February 25, 2019.

Overview of Our Business


We are an independent natural gas, natural gas liquids ("NGLs,") crude oil and
condensate company engaged in the exploration, development and acquisition of
natural gas and crude oil properties located primarily in the Appalachian and
North Louisiana regions of the United States. We operate in one segment and have
a single company-wide management team that administers all properties as a whole
rather than by discrete operating segments. We track only basic operational data
by area. We do not maintain complete separate financial statements information
by area. We measure financial performance as a single enterprise and not on an
area-by-area basis.

Our overarching business objective is to build stockholder value through returns
focused development, measured on a per share debt adjusted basis. Our strategy
to achieve our business objective is to generate consistent cash flow from
reserves and production through internally generated drilling projects
occasionally coupled with complementary acquisitions and divestitures of
non-core or, at times, core assets. Our revenues, profitability and future
growth depend substantially on prevailing prices for natural gas, NGLs, crude
oil and condensate and on our ability to economically find, develop, acquire and
produce natural gas, NGLs and oil reserves.

Commodity prices have been and are expected to remain volatile. We believe we are well-positioned to manage the challenges presented in such a volatile pricing environment by:

     •  exercising discipline in our capital program as we target funding our
        capital spending within operating cash flows and, if required, with
        borrowing under our bank credit facility;

• continuing to optimize drilling, completion and operational efficiencies;


  • continuing to manage price risk by hedging our production; and


  • continuing to manage our balance sheet.

Prices for natural gas, NGLs, crude oil and condensate fluctuate widely and affect:

• our revenues, profitability and cash flow;

• the quantity of natural gas, NGLs and oil that we can economically produce;


  • the quantity of natural gas, NGLs and oil shown as proved reserves;


  • the amount of cash flow available to us for capital expenditures; and


  • our ability to borrow and raise additional capital.


We prepare our financial statements in conformity with U.S. GAAP, which require
us to make estimates and assumptions that affect our reported results of
operations and the amount of our reported assets, liabilities and proved natural
gas, NGLs and oil reserves. We use the successful efforts method of accounting
for our natural gas, NGLs and oil activities. Our corporate headquarters is
located in Fort Worth, Texas.

Potential for Future Impairments


We have in the past, and may incur in the future, impairments of proved and
unproved property. As discussed elsewhere in this Form 10-K, we recorded both
proved and unproved impairments of our North Louisiana properties at December
31, 2019. Through acquisition accounting, acquired asset values are recorded at
their estimated fair market value at the time of closing. In 2016, when we
acquired our North Louisiana properties, commodity prices were significantly
higher when compared to the current environment. Our impairment assessment as of
December 31, 2019 indicated the carrying amounts of our Marcellus properties
were not impaired and that estimated undiscounted cash flows significantly
exceeded their carrying value.



                                       48

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Sources of Our Revenues


We derive our revenues from the sale of natural gas, NGLs, crude oil and
condensate that is produced from our properties. Revenues from product sales are
a function of the volumes produced, prevailing market prices, product quality,
gas Btu content and transportation costs. Our revenues are generally recognized
when control of the product is transferred to the customer and collectability is
reasonably assured. Cash settlements of derivative contracts are included in
derivative fair value in the accompanying statements of operations. Brokered
natural gas, marketing and other revenues include revenue we receive as a result
of selling natural gas that is not our production (brokered), revenue from the
release of transportation capacity where we have taken capacity ahead of our
production and marketing fees we receive from third parties.

Principal Components of Our Cost Structure


     •  Direct operating. These are day-to-day costs incurred to bring
        hydrocarbons out of the ground along with the daily costs incurred to
        maintain our producing properties. Such costs include compensation of
        our field employees, maintenance, repairs and workover expenses
        related to our natural gas and oil properties. The majority of these
        costs are expected to remain a function of supply and demand. Direct
        operating expenses also include stock-based compensation expense
        (non-cash) associated with the amortization of equity grants as part
        of the compensation of our field employees.


     •  Transportation, gathering, processing and compression. Under some of
        our sales arrangements, we sell natural gas and NGLs at a specific
        delivery point, pay transportation, gathering, processing and
        compression costs to a third party and receive proceeds from the
        purchaser with no deduction. Transportation, gathering, processing
        and compression expense represents costs paid by Range to third
        parties under these arrangements.


     •  Production and ad valorem taxes. Production taxes are paid on
        produced natural gas and oil based on a percentage of sales revenue
        (excluding derivatives) or at fixed rates established by the

applicable federal, state or local taxing authorities. In Louisiana,

        ad valorem tax assessments are based on capital costs, well age,
        depth and production. The Pennsylvania impact fee on unconventional
        natural gas and oil production, which includes the Marcellus Shale,
        is also included in this category.

• Brokered natural gas and marketing. These expenses are gas purchases

        for brokered natural gas that is not part of our production that we
        buy and sell plus the overhead, including payroll and benefits for
        our marketing staff. These expenses also include costs related to
        transportation capacity we have taken ahead of our production.

Brokered natural gas and marketing expenses also include stock-based

        compensation expense (non-cash) associated with the amortization of
        equity grants as part of our marketing staff compensation.

• Exploration. These costs are geological and geophysical costs, such

as payroll and benefits for the geological and geophysical staff,

seismic costs, delay rentals and the costs of unsuccessful

exploratory dry holes. Exploration expenses also include stock-based

        compensation expense (non-cash) associated with the amortization of
        equity grants as part of the compensation of our exploration staff.


     •  Abandonment and impairment of unproved properties. This category
        includes unproved property impairment expense associated with oil and
        gas lease expirations, shifts in business strategy which may impact
        our number of drilling locations or changing economic factors.
        Impairment on a majority of our unproved properties is assessed and
        amortized on an aggregate basis based on average holding period,
        expected forfeiture rate and anticipated drilling success.


     •  General and administrative. These costs include overhead, such as
        payroll and benefits for our corporate staff, costs of maintaining
        our headquarters, costs of managing our production and development
        operations, franchise taxes, audit and other professional fees, legal
        compliance and legal settlements. Included in this category are
        overhead expense reimbursements we receive from working interest
        owners of properties, for which we serve as the operator. These

reimbursements are received during both the drilling and operational

        stages of a property's life. General and administrative expenses also
        include stock-based compensation expense (non-cash) associated with
        the amortization of equity grants as part of the compensation of our
        corporate staff and our non-employee directors.


     •  Deferred compensation plan. These costs relate to the increase or
        decrease in the value of the liability associated with our deferred
        compensation plan. Our deferred compensation plan gives directors,
        officers and key employees the ability to defer all or a portion of
        their salaries and bonuses and invest in our common stock or make
        other investments at the individual's discretion. The assets of this
        plan are held in a grantor trust, are funded on the grant date and
        are available to satisfy the claims of our creditors in the event of
        bankruptcy or insolvency. We do not maintain a defined benefit

retirement plan for any of our employees. However, in fourth quarter

2017, we implemented a succession plan enhancement for officers which

includes a post-retirement benefit plan to assist in providing health

        care to officers who are active employees and have met certain age
        and service requirements. These benefits are provided up to age 65 or
        on the date they become eligible for Medicare.


                                       49
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• Interest. We have typically financed a portion of our cash

        requirements with borrowings under our bank credit facility and with
        longer-term debt securities. Also included in our interest expense
        are administrative fees associated with our bank credit facility and
        the amortization of deferred financing costs. As a result, we incur
        interest expense that is affected by both fluctuations in interest
        rates and our financing decisions. We currently have no capitalized
        interest.

• Depreciation, depletion and amortization. This category of expenses

        includes the systematic expensing of the capitalized costs incurred
        to acquire, explore and develop natural gas, NGLs and oil. As a
        successful efforts company, we capitalize all costs associated with
        our acquisition and development efforts and all successful
        exploration efforts, and apportion these costs to each unit of

production through depreciation, depletion and amortization expense.

        This expense also includes the systematic, monthly accretion of the
        future abandonment costs of tangible assets such as wells, service
        assets, pipelines and other facilities.


     •  Income tax. We are subject to state and federal income taxes but are
        currently not in a cash taxpaying position for federal income taxes,
        primarily due to the current deductibility and/or accelerated
        amortization of intangible drilling costs ("IDC"). At this time, we
        generally do not pay significant state income taxes due to our state
        net operating loss carryovers and our ability to follow the federal

treatment of deducting IDC in most of the states in which we operate.

        Currently, all of our federal taxes are deferred. As of December 31,
        2019, we have federal valuation allowances of $32.5 million and state
        valuation allowances of $158.3 million. For more information, see

Item 1A. Risk Factors-Certain federal income tax deductions currently

        available with respect to natural gas and oil exploration and
        development may be eliminated or postponed and additional federal or
        state taxes on natural gas extraction may be imposed, as a result of
        future legislation.

Management's Discussion and Analysis of Results of Operations


Commodity prices have remained volatile. Natural gas, oil and NGLs benchmarks
decreased in 2019 compared to 2018. As a result, we experienced significant
decreases in our price realizations. While operating in this lower commodity
price environment, we had many operational, financial and strategic successes in
2019. During 2019, we continued our focus on enhancing margins and returns,
driving operational efficiencies, simplifying our portfolio and maintaining
liquidity. We believe we have positioned ourselves for long-term success through
the natural gas and oil business cycle. In summary, we exited 2019 with
operational momentum, investment flexibility and a robust financial liquidity
position, which we expect to carry over to 2020.

Overview of 2019 Results


For the year ended December 31, 2019, we experienced a decrease in revenue from
the sale of natural gas, NGLs and oil due to 25% decrease in net realized prices
(average prices including all derivative settlements and third-party
transportation costs paid by us) partially offset by 4% higher production
volumes when compared to 2018. Daily production in 2019 averaged 2.3 Bcfe
compared to 2.2 Bcfe in 2018 as a result of drilling and completions in
Pennsylvania. Average natural gas differentials were below NYMEX while operating
costs were lower when compared to 2018.

During 2019, we recognized net loss of $1.7 billion, or $6.92 per diluted common
share compared to net loss of $1.7 billion, or $7.10 per diluted common share
during 2018. The year ended 2019 includes a $1.1 billion impairment of proved
property compared to a $1.6 billion goodwill impairment in the prior year,
significantly higher abandonment and impairment of unproved property and lower
realized prices.

During 2019, we achieved the following financial and operating performance results:

     •  received $784.9 million of proceeds, primarily from the sale, in
        three separate transactions, of a proportionately reduced 2.5%
        overriding royalty primarily in our Washington County, Pennsylvania
        properties where we received proceeds of $750.0 million;


     •  repurchased $201.6 million face value of our senior notes at a
        discount and recorded a gain on early extinguishment of debt;


  • achieved 4% production growth from 2018;


     •  achieved 1% annual proved reserve growth, despite our royalty sales,
        with a 40% decrease in the standardized after-tax measure of
        discounted future net cash flows when compared to 2018 primarily due
        to lower prices;


  • capital spending was 4% lower than original 2019 budget;


  • drilled 92.6 net wells with a 100% success rate;


     •  continued expansion of our activities in the Marcellus Shale by
        growing production, proving up acreage and acquiring additional
        unproved acreage;


  • reduced general and administrative expenses per mcfe 15% from 2018;


  • reduced interest expense per mcfe 12% from 2018;


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  • reduced our DD&A rate per mcfe 16% from 2018;


  • reduced total debt by $667.6 million;


     •  achieved a debt per mcfe of proved reserves of $0.18 compared to
        $0.21 in 2018;

• entered into additional commodity-based derivative contracts for 2020

        and 2021;


  • realized $681.8 million of cash flow from operating activities; and


  • ended the year with stockholders' equity of $2.3 billion.


In 2019, operationally we continued to focus on flexibility, efficiencies and
controlling costs. As evidenced by history and our current industry environment,
the prices at which we sell our production are volatile and we have little
control over them. Therefore, to improve our profitability, we focus our efforts
on improving operating efficiency. We continue to focus on material reductions
in unit costs. As reservoirs are depleted and production rates decline, per unit
production costs will generally increase. To lessen this effect, we concentrate
our production in core areas with low base decline rates where we can achieve
economies of scale to help manage our operating costs.

We generated $681.8 million of cash flow from operating activities in 2019, a
decrease of $308.8 million from 2018 which reflects significantly lower realized
prices partially offset by higher production volumes and lower comparative
working capital outflows ($2.5 million inflow during 2019 compared to $8.2
million outflow in 2018). We ended 2019 with $1.7 billion of available committed
borrowing capacity, with an additional $600.0 million in borrowing base capacity
available.

Acquisitions

During 2019, we spent $57.3 million to acquire unproved acreage compared to $62.4 million in 2018. We continue selective acreage leasing and lease renewals to consolidate our acreage positions in the Marcellus Shale play in Pennsylvania.

Divestitures


Pennsylvania. In third quarter 2019, we sold, in three separate transactions, a
proportionately reduced 2.5% overriding royalty primarily in our Washington
County, Pennsylvania leases for gross proceeds of $750.0 million and we recorded
a loss of $36.5 million which represents closing adjustments and transaction
fees. In second quarter 2019, we sold natural gas and oil property, primarily
representing over 20,000 unproved acres, for proceeds of $34.0 million and
recognized a gain of $5.9 million. In fourth quarter 2018, we sold a
proportionately reduced 1% overriding royalty in our Washington County,
Pennsylvania leases for gross proceeds of $300.0 million and we recorded a loss
of $10.2 million which represents closing adjustments and transaction fees.

Oklahoma. In 2018, we sold various properties in Northern Oklahoma for proceeds of $23.3 million and we recognized a net loss of $39,000, after closing adjustments.

2020 Outlook


As we enter 2020, we believe we are positioned for sustainable long-term
success. For 2020, our board of directors approved a $520.0 million capital
budget for natural gas, NGLs, crude oil and condensate related activities,
excluding proved property acquisitions, for which we do not budget. Our 2020
capital budget is 98% allocated to our Appalachian division. As has been our
historical practice, we will periodically review our capital expenditures
throughout the year and may adjust the budget based on commodity prices,
drilling success and other factors. We expect our 2020 capital budget to achieve
production similar to our 2019 production, as we target limiting our capital
spending to at or below cash flow and, if required, with borrowings under our
bank credit facility. Our 2020 capital budget is designed to focus on continuing
to improve corporate returns and generating free cash flow. To the extent
commodity prices decline, we may reduce the capital budget with the intent of
limiting capital spending to at or below cash flow. The prices we receive for
our natural gas, NGLs and oil production are largely based on current market
prices, which are beyond our control. The price risk on a portion of our
forecasted natural gas, NGLs and oil production for 2020 is mitigated by
entering into commodity derivative contracts and we intend to continue to enter
into these types of contracts. We believe it is likely that commodity prices
will continue to be volatile during 2020.

Market Conditions


Prices for various quantities of natural gas, NGLs and oil that we produce
significantly impact our revenues and cash flows. Prices for commodities, such
as hydrocarbons, are inherently volatile. Significant commodity price declines
decreased our average realized prices. Recently, natural gas prices have
decreased, when compared to December 2019, with the average NYMEX monthly
settlement price for natural gas decreasing to $1.88 per mcf for February 2020.
Crude oil prices have also decreased, when compared to December 2019, to $57.53
per barrel in January 2020. The following table lists related benchmarks for
natural gas, oil and NGLs composite prices for the years ended December 31, 2019
and 2018.



                                       51
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                                                Year Ended December 31,
                                                2019               2018
Benchmarks:
Average NYMEX prices (a)
Natural gas (per mcf)                       $       2.62$       3.07
Oil (per bbl)                               $      57.21$      65.49

Mont Belvieu NGL composite (per gallon) (b) $ 0.45$ 0.67

(a) Based on average of bid week prompt month prices on the New York Mercantile Exchange ("NYMEX").

(b) Based on our estimated NGLs product composition per barrel.


Our price realizations (not including the impact of our derivatives) may differ
from the benchmarks for many reasons, including quality, location, or production
being sold at different indices.

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations


Our revenues vary from year to year as a result of changes in realized commodity
prices and production volumes. For more information, see "Sources of Our
Revenues" above. In 2019, natural gas NGLs and oil sales decreased 21% from 2018
with a 4% increase in production and a 24% decrease in realized prices
(excluding cash settlements on our derivatives). The following table illustrates
the primary components of natural gas, NGLs, crude oil and condensate sales for
the last two years (in thousands):

                                         2019            2018
Natural gas, NGLs and Oil sales
Natural gas                           $ 1,388,838$ 1,663,832
NGLs                                      681,134         931,360
Oil and condensate                        185,453         255,885

Total natural gas, NGLs and oil sales $ 2,255,425$ 2,851,077



Our production continues to grow through drilling success as we place new wells
on production which is partially offset by the natural decline of our natural
gas and oil reserves through production and asset sales. For 2019, our
production increased 10% in our Appalachian region when compared to 2018.
Production from our North Louisiana properties was 76.5 Bcfe in 2019 compared to
110.6 Bcfe in 2018. Our production for the last two years is set forth in the
following table:

                                     2019              2018
Production (a)
Natural gas (mcf)                 578,114,351       548,085,437
NGLs (bbls)                        38,850,130        38,325,251

Crude oil and condensate (bbls) 3,689,805 4,228,439 Total (mcfe) (b)

                  833,353,961       803,407,577
Average daily production (a)
Natural gas (mcf)                   1,583,875         1,501,604
NGLs (bbls)                           106,439           105,001
Crude oil and condensate (bbls)        10,109            11,585
Total (mcfe) (b)                    2,283,162         2,201,117


(a) Represents volumes sold regardless of when produced.

(b) Oil and NGLs volumes are converted to mcfe at the rate of one barrel

     equals six mcf based upon the approximate relative energy content of
     oil and natural gas, which is not indicative of the relationship
     between oil and natural gas prices.


                                       52
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Our average realized price (including all derivative settlements and third-party
transportation costs paid by Range) received during 2019 was $1.49 per mcfe
compared to $1.99 per mcfe in 2018. Because we record transportation costs on
two separate bases, as required by U.S. GAAP, we believe computed final realized
prices should include the impact of transportation, gathering, processing and
compression expense. Average sales prices (excluding derivative settlements) do
not include any derivative settlements or third-party transportation costs which
are reported in transportation, gathering and compression expense on the
accompanying consolidated statements of operations. Average sales prices
(excluding derivative settlements) do include transportation costs where we
receive net proceeds from the purchaser. Our average realized price (including
all derivative settlements and third-party transportation costs paid by Range)
calculation includes all cash settlements for derivatives. Average realized
price calculations for the last two years are shown below:

                                                                 2019       

2018

Average Prices
Average sales prices (excluding derivative settlements):
Natural gas (per mcf)                                           $  2.40$  3.04
NGLs (per bbl)                                                    17.53       24.30
Crude oil (per bbl)                                               50.26       60.52
Total (per mcfe) (a)                                               2.71        3.55
Average realized prices (including all derivative settlements):
Natural gas (per mcf)                                           $  2.64$  2.98
NGLs (per bbl)                                                    18.85       22.62
Crude oil (per bbl)                                               49.74       51.60
Total (per mcfe) (a)                                               2.93        3.39
Average realized prices (including all derivative settlements
and third-party transportation costs paid by Range):
Natural gas (per mcf)                                           $  1.36$  1.74
NGLs (per bbl)                                                     7.03       11.15
Crude oil (per bbl)                                               49.74       51.60
Total (per mcfe) (a)                                               1.49        1.99

(a) Oil and NGLs volumes are converted at the rate of one barrel equals six mcf

based upon the approximate relative energy content of oil to natural gas,

which is not indicative of the relationship between oil and natural gas

prices.



Realized prices include the impact of basis differentials and gains or losses
realized from our basis hedging. The prices we receive for our natural gas can
be more or less than the NYMEX price because of adjustments for delivery
location, relative quality and other factors. The following table provides this
impact on a per mcf basis:

                                                  Year Ended December 31,
                                                   2019               2018

Average natural gas differentials below NYMEX $ (0.22 )$ (0.03 ) Realized gains (losses) on basis hedging $ 0.03$ (0.02 )

The following tables reflect our production and average realized commodity prices (excluding derivative settlements and third-party transportation costs paid by Range) (in thousands, except prices):

                                    Year Ended December 31,
                                     Price          Volume
                      2018          Variance       Variance         2019
Natural gas
Price (per mcf)   $      3.04$    (0.64 )   $        -     $      2.40
Production (Mmcf)     548,085              -         30,029         578,114

Natural gas sales $ 1,663,832$ (366,154 )$ 91,160$ 1,388,838




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                                   Year Ended December 31,
                                    Price          Volume
                      2018         Variance       Variance        2019
NGLs
Price (per bbl)    $   24.30$    (6.77 )   $        -     $   17.53
Production (Mbbls)    38,325              -            525        38,850
NGLs sales         $ 931,360$ (262,981 )$   12,755$ 681,134




                                   Year Ended December 31,
                                    Price          Volume
                      2018         Variance       Variance        2019
Crude oil
Price (per bbl)    $   60.52$   (10.26 )   $        -     $   50.26
Production (Mbbls)     4,228              -           (538 )       3,690
Crude oil sales    $ 255,885$  (37,836 )$  (32,596 )$ 185,453




                                                         Year Ended December 31,
                                                          Price          Volume
                                           2018          Variance       Variance         2019
Consolidated
Price (per mcfe)                       $      3.55$    (0.84 )   $        -     $      2.71
Production (Mmcfe)                         803,408              -        

29,946 833,354 Total natural gas, NGLs and oil sales $ 2,851,077$ (701,923 )$ 106,271$ 2,255,425



Transportation, gathering, processing and compression expense was $1.2 billion
in 2019 compared to $1.1 billion in 2018. These third-party costs are higher due
to our production growth in the Marcellus Shale where we have third-party
gathering, compression, processing and transportation agreements. Additionally,
we experienced higher costs resulting from new in-service pipelines, higher NGLs
costs due to higher production and higher NGLs expense in North Louisiana due to
fully utilizing amounts that were previously accrued for as capacity
commitments. We have included these costs in the calculation of average realized
prices (including all derivative settlements and third-party transportation
expenses paid by Range). The following table summarizes transportation,
gathering, processing and compression expense for the last two years (in
thousands) and on a per mcf and per barrel basis:

                          2019             2018
Natural gas           $    740,061$    678,489
NGLs                       459,236          439,327
Total                  $ 1,199,297$ 1,117,816

Natural gas (per mcf) $ 1.28$ 1.24 NGLs (per bbl) $ 11.82$ 11.46



Derivative fair value income (loss) was income of $226.7 million in 2019
compared to loss of $51.2 million in 2018. All of our derivatives are accounted
for using the mark-to-market accounting method. Mark-to-market accounting
treatment creates volatility in our revenues as unrealized gains and losses from
derivatives are included in total revenues. As commodity prices increase or
decrease, such changes will have an opposite effect on the mark-to-market value
of our derivatives. Gains on our derivatives generally indicate lower wellhead
revenues in the future while losses indicate higher future wellhead revenues. At
December 31, 2019, our commodity derivative contracts were recorded at their
fair value, which was a net derivative asset of $126.7 million, an increase of
$45.8 million from the $80.9 million net derivative asset recorded as of
December 31, 2018. We have also entered into basis swap agreements to limit
volatility caused by changing differentials between NYMEX and regional prices
received. These basis swaps are marked to market and we recognized a net
derivative asset of $9.4 million as of December 31, 2019 compared to a net
derivative asset of $4.8 million as of December 31, 2018. As of December 31,
2019, we have propane basis swaps to limit the volatility caused by changing
differentials between Mont Belvieu and international propane indexes which are
recognized as a net derivative liability of $14.1 million as of December 31,
2019 compared to a net derivative asset of $117,000 as of December 31, 2018. In
connection with our international propane swaps, we also have freight swap
contracts which lock in the freight rate for a specific trade route on the
Baltic Exchange which are recognized as a net derivative asset of $1.5 million
compared to a net derivative liability of $561,000 as of December 31, 2018. The
following table summarizes the impact of our commodity derivatives for the last
two years (in thousands):



                                       54
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                                                                2019        

2018

Derivative fair value income (loss) per consolidated statements of operations

                                     $ 226,681

$ (51,192 )


Non-cash fair value gain (loss): (1)
Natural gas derivatives                                      $ 135,012$  (84,889 )
Oil derivatives                                                (35,950 )       57,149
NGLs derivatives                                               (62,856 )      108,908
Freight derivatives                                              2,091           (838 )
Total non-cash fair value gain (1)                           $  38,297

$ 80,330


Net cash receipt (payment) on derivative settlements:
Natural gas derivatives                                      $ 139,253$  (29,291 )
Oil derivatives                                                 (1,937 )      (37,709 )
NGLs derivatives                                                51,068        (64,522 )
Total net cash receipt (payment)                             $ 188,384

$ (131,522 )

(1) Non-cash fair value adjustments on commodity derivatives is a non-GAAP

measure. Non-cash fair value adjustments on commodity derivatives only

represent the net change between periods of the fair market values of

commodity derivative positions and exclude the impact of settlements on

commodity derivatives during the period. We believe that non-cash fair value

adjustments on commodity derivatives is a useful supplemental disclosure to

differentiate non-cash fair market value adjustments from settlements on

commodity derivatives during the period. Non-cash fair value adjustments on

commodity derivatives is not a measure of financial or operating performance

      under GAAP, nor should it be considered a substitute for derivative fair
      value income or loss as reported in our consolidated statements of
      operations.


Brokered natural gas, marketing and other revenue was $345.5 million in 2019
compared to $482.8 million in 2018. We enter into purchase transactions with
third parties and separate sale transactions with third parties at different
times to satisfy unused pipeline capacity commitments. The 2019 period includes
$332.0 million of revenue from the sale of natural gas that is not related to
our production (brokered) and $1.7 million of revenue from the sale of NGLs that
is not related to our production. These revenues both decreased compared to 2018
due to lower brokered volumes and lower sales prices. Fourth quarter 2018 also
included a production volume shortfall due to third-party processing facility
plant repairs with additional volumes being purchased and sold to satisfy our
commitments.

Costs and Expenses per mcfe

We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about certain of our expenses on a per mcfe basis for the last two years:


                                                          Year Ended December 31,
                                                                                      %
                                                  2019       2018      Change       Change
Direct operating expense                         $ 0.16$ 0.17$ (0.01 )         (6 %)
Production and ad valorem tax expense              0.05       0.06       (0.01 )        (17 %)
General and administrative expense                 0.22       0.26       (0.04 )        (15 %)
Interest expense                                   0.23       0.26       

(0.03 ) (12 %) Depletion, depreciation and amortization expense 0.66 0.79 (0.13 ) (16 %)



Direct operating expense was $136.3 million in 2019 compared to $139.5 million
in 2018. Direct operating expenses include normally recurring expenses to
operate and produce our wells, non-recurring workovers and repair-related
expenses. On an absolute basis, our direct operating expenses for 2019 decreased
2% from the prior year primarily due to lower water hauling/handling costs,
utilities, equipment rentals and pumper costs and the impact from the sale of
our Northern Oklahoma properties in the prior year partially offset by higher
workover costs. We incurred $24.3 million of workover costs in 2019 compared to
$9.8 million of workover costs in 2018.

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On a per mcfe basis, operating expense for 2019 decreased $0.01, or 6% from the
same period of 2018, with the decrease due to the impact from the sale of
certain non-core assets in 2018 and lower water hauling/handling costs partially
offset by higher workover costs. We have experienced lower costs per mcfe as we
have increased production from our Marcellus Shale wells due to their lower
operating cost relative to our other operating areas. Stock-based compensation
expense represents the amortization of equity grants as part of the compensation
of field employees. The following table summarizes direct operating expenses per
mcfe for the last two years:

                                             Year Ended December 31,
                                                                         %
                                     2019       2018      Change       Change
Lease operating expense             $ 0.13$ 0.16$ (0.03 )        (19 %)
Workovers                             0.03       0.01        0.02          200 %
Stock-based compensation (non-cash)      -          -           -           

- % Total direct operating expense $ 0.16$ 0.17$ (0.01 ) (6 %)



Production and ad valorem taxes are paid based on market prices, not hedged
prices. This expense category also includes the Pennsylvania impact fee. In
February 2012, the Commonwealth of Pennsylvania enacted an "impact fee" on
unconventional natural gas and oil production which includes the Marcellus
Shale. The impact fee is based upon the year wells are drilled and the fee
varies, like a severance tax, based upon natural gas prices. The year ended
December 31, 2019 includes a $25.9 million impact fee compared to $32.4 million
in the year ended December 31, 2018 with the decline primarily due to lower
natural gas prices. Production and ad valorem taxes (excluding the impact fee)
were $12.0 million in 2019 compared to $13.7 million in 2018 with the decline
also due to lower natural gas prices. The following table summarizes production
and ad valorem taxes per mcfe for the last two years:

                                          Year Ended December 31,
                                                                      %
                                 2019       2018      Change        Change
Production taxes                $ 0.01$ 0.01     $     -             - %
Ad valorem taxes                     -          -           -             - %
Impact fee                        0.04       0.05       (0.01 )         (20 %)

Total production and ad valorem $ 0.05$ 0.06$ (0.01 ) (17 %)



General and administrative expense was $181.1 million for 2019 compared to
$209.8 million for 2018. The decrease in 2019, when compared to 2018, is
primarily due to lower stock-based compensation of $8.7 million, lower legal
costs (including settlements) of $14.4 million, lower salaries and benefits of
$8.0 million and lower technology costs which were partially offset by higher
bad debt expenses of $5.3 million and higher franchise taxes.

On a per mcfe basis, general and administrative expense for 2019 decreased 15%
from the same period of 2018, with the decrease due to lower salaries and
benefits and lower legal costs (including settlements). Stock-based compensation
expense represents the amortization of stock-based compensation awards granted
to our employees and our non-employee directors as part of their compensation.
The following table summarizes general and administrative expenses per mcfe for
the last two years:

                                                  Year Ended December 31,
                                                                              %
                                          2019       2018      Change       Change
General and administrative               $ 0.18$ 0.21$ (0.03 )        (14 %)
Stock-based compensation (non-cash)        0.04       0.05       (0.01 )        (20 %)
Total general and administrative expense $ 0.22$ 0.26$ (0.04 )        (15 %)






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Interest expense was $194.3 million for 2019 compared to $210.2 million for
2018. The following table presents information about interest expense per mcfe
for the last two years:

                                                     Year Ended December 31,
                                                       2019            2018
Bank credit facility                                $      0.04$      0.06
Senior notes                                               0.18            0.19
Amortization of deferred financing costs and other         0.01            

0.01

Total interest expense                              $      0.23     $      

0.26


Average debt outstanding (in thousands)             $ 3,640,819$ 4,182,340
Average interest rate (a)                                   5.1 %           4.9 %

(a) Includes commitment fees but excludes amortization of debt issue costs and

amortization of discount.



On an absolute basis, the decrease in interest expense for 2019 from the same
period of 2018 was primarily due to lower average outstanding debt balances
partially offset by slightly higher average interest rates. See Note 8 to our
consolidated financial statements for additional information. Average debt
outstanding on the bank credit facility for 2019 was $772.1 million compared to
$1.3 billion for 2018 and the weighted average interest rate on the bank credit
facility was 3.8% for 2019 compared to 3.7% in 2018.

Depletion, depreciation and amortization ("DD&A") was $548.8 million in 2019
compared to $635.5 million in 2018. The decrease in 2019 when compared to 2018
is due to a 16% decrease in depletion rates partially offset by a 4% increase in
production volumes.

On a per mcfe basis, DD&A decreased to $0.66 in 2019 compared to $0.79 in 2018.
Depletion expense, the largest component of DD&A, was $0.63 per mcfe in 2019
compared to $0.75 per mcfe in 2018. We have historically adjusted our depletion
rates in the fourth quarter of each year based on our year-end reserve report
and at other times during the year when circumstances indicate there has been a
significant change in reserves or costs. We currently expect our DD&A rate to be
approximately $0.50 per mcfe in 2020, based on our current production estimates.
In areas where we are actively drilling, such as the Marcellus Shale area, our
fourth quarter adjusted 2019 depletion rates were lower than the fourth quarter
2018 and 2017 depletion rates. Depletion rates in new plays tend to be higher in
the beginning as increased initial outlays are amortized over proved reserves
based on early stages of evaluations. The decrease in DD&A per mcfe in 2019 when
compared to 2018 is due to the mix of our production from our properties with
lower depletion rates. The following table summarizes DD&A expenses per mcfe for
the last two years:

                                     Year Ended December 31,
                                                                 %
                            2019       2018      Change        Change
Depletion and amortization $ 0.63$ 0.75$ (0.12 )         (16 %)
Depreciation                 0.01       0.01           -             - %
Accretion and other          0.02       0.03       (0.01 )         (33 %)
Total DD&A expenses        $ 0.66$ 0.79$ (0.13 )         (16 %)


Other Operating Expenses

Our total operating expenses also include other expenses that generally do not
trend with production. These expenses include stock-based compensation, brokered
natural gas and marketing, exploration expense, abandonment and impairment of
unproved properties, termination costs, deferred compensation plan expenses,
gain on early extinguishment of debt, impairment of proved properties and
impairment of goodwill.

The following table details stock-based compensation that is allocated to functional expense categories for the last two years (in thousands):


                                                             2019         

2018

Direct operating expense                                   $  1,928     $  

2,109

Brokered natural gas and marketing expense                    1,856        

1,452

Exploration expense                                           1,566        

1,921

Exploration expense - one-time acceleration                       -         

-

General and administrative expense                           35,061       

43,806

General and administrative expense - one-time acceleration -

-

Termination costs                                             1,971         

-

Total stock-based compensation                             $ 42,382$ 49,288


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Stock-based compensation includes the amortization of restricted stock and PSUs grants.


Brokered natural gas and marketing expense was $359.9 million in 2019 compared
to $496.0 million in 2018. We enter into purchase transactions with third
parties and separate sale transactions with third parties at different times to
satisfy unused capacity commitments. The decrease in these costs reflects lower
broker purchase volumes and lower purchase prices. Fourth quarter 2018 also
included a production shortfall due to a third-party processing facility plant
repairs with additional volumes being purchased and sold to satisfy our
commitments. The following table details our brokered natural gas, marketing and
other net margin which includes the net effect of these third-party transactions
for the two-year period ended December 31, 2019 (in thousands):

                                                     2019            2018
Brokered natural gas sales                        $  332,006$  460,349
Brokered NGLs sales                                    1,661           9,018
Other marketing revenue                               11,842          13,393
Brokered natural gas purchases and transportation   (347,448 )      (477,962 )
Brokered NGLs purchases                               (1,592 )        (7,727 )
Other marketing expense                              (10,852 )      

(10,358 ) Net brokered natural gas and marketing net margin $ (14,383 )$ (13,287 )



Exploration expense was $36.7 million in 2019 compared to $34.1 million in 2018.
Exploration expense in 2019 was higher compared to the prior year due to higher
delay rentals and other costs somewhat offset by lower personnel costs.
Stock-based compensation represents the amortization of equity stock grants as
part of the compensation of our exploration staff. The following table details
our exploration related expenses for the last two years (in thousands):

                                             Year Ended December 31,
                                                                            %
                                   2019          2018        Change      Change
Seismic                          $   (482 )$     67$   (549 )      (819 %)
Delay rentals and other            26,137        19,742        6,395          32 %
Personnel expense                   9,473        12,383       (2,910 )       (23 %)
Stock-based compensation expense    1,566         1,921         (355 )       (18 %)
Exploratory dry hole expense          (11 )           4          (15 )      (375 %)
Total exploration expense        $ 36,683$ 34,117$  2,566

8 %



Abandonment and impairment of unproved properties was $1.2 billion in 2019
compared to $515.0 million in 2018. Impairment of individually insignificant
unproved properties is assessed and amortized on an aggregate basis based on our
average holding period, expected forfeiture rate and anticipated drilling
success. We assess individually significant unproved properties for impairment
on a quarterly basis and recognize a loss where circumstances indicate
impairment in value. In determining whether a significant unproved property is
impaired we consider numerous factors including, but not limited to, current
exploration plans, favorable or unfavorable activity on the property being
evaluated and/or adjacent properties, our geologists' evaluation of the property
and the remaining months in the lease term for the property. In certain
circumstances, our future plans to develop acreage may accelerate our
impairment. In 2019, an impairment of $1.2 billion was recorded in relation to
North Louisiana unproved property value allocated to previously acquired
probable and possible reserves that we no longer have the intent to drill based
on a shift in capital allocation which materially impacted our drilling
inventory compared to a similar impairment in North Louisiana of $436.0 million
in 2018. As we continue to review our acreage positions and high grade our
drilling inventory based on the price environment or for other operational
changes, additional leasehold impairments and abandonments may be recorded.

Termination costs in 2019 include $7.5 million of estimated severance costs and $2.0 million of accelerated vesting of equity grants compared to favorable severance accrual adjustments of $373,000 in 2018. In 2019, we continued to implement work force reductions in response to the lower commodity price environment including the closing of our Houston office.


Deferred compensation plan expense was a gain of $15.5 million in 2019 compared
to $18.6 million in 2018. Our stock price decreased to $4.85 at December 31,
2019 from $9.57 at December 31, 2018. This non-cash item relates to the increase
or decrease in value of the liability associated with our common stock that is
vested and held in our deferred compensation plan. The deferred compensation
liability is adjusted to fair value by a charge or a credit to deferred
compensation plan expense. Common shares are placed in the deferred compensation
plan when granted.

Gain on early extinguishment of debt was $5.4 million in 2019. We repurchased
$201.6 million face value of our 5.75% senior notes due 2021, our 5.875% senior
notes due 2022 and our 5.00% senior notes due 2022. We repurchased these notes
at a discount and recorded a gain on early extinguishment after transaction
costs and expensing the remaining deferred financing costs.

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Impairment of proved properties increased to $1.1 billion in 2019 compared to
$22.6 million in 2018. We assess our long-lived assets whenever events or
circumstances indicate the carrying value may not be recoverable. Fair value is
generally determined using an income approach based on internal estimates of
future production levels, prices, drilling and operating costs and discount
rates. In some cases, we may also use a market approach, based on either
anticipated sales proceeds less costs to sell or a market comparable sales
price. See Note 11 to our consolidated financial statements for details. The
year ended 2019 included an impairment related to our North Louisiana assets due
to a shift in business strategy employed by management and the possibility of a
divestiture of these assets. As a result of our impairment assessments, we
recorded non-cash impairment charges to reduce the carrying values of oil and
gas properties as follows:

  ? 2019: North Louisiana assets ($1.1 billion)


  ? 2018: Northwest Pennsylvania shallow legacy assets ($15.3 million)


  ? 2018: Oklahoma assets ($7.3 million)


Impairment of goodwill was $1.6 billion in 2018. During fourth quarter 2018, due
to the significant decline in our stock price, we performed a quantitative
impairment assessment of our goodwill. Fair value was estimated based on a
combination of a market and an income approach. Goodwill is related to the
excess purchase price over amounts assigned to assets acquired and liabilities
assumed in a business acquisition. Our estimate of fair value required us to use
significant unobservable inputs including assumptions for commodity prices,
production, forward pricing curves, operating and development costs and other
factors. Based on this analysis, we determined the fair value of goodwill was
zero and goodwill was fully impaired.

Income tax benefit was $500.3 million in 2019 compared to $30.5 million in 2018.
The 2019 increase reflects a $439.6 million additional loss before income taxes
when compared to 2018. The year ended December 31, 2018 included a goodwill
impairment of $1.6 billion that was not benefited for tax. The effective tax
rate was 22.6% in 2019 compared to 1.7% in 2018. The 2019 and 2018 effective tax
rates were different than the statutory tax rate due to state income taxes and
other discrete tax items which are detailed below. For each of the two years
ended December 31, 2019 and 2018, current income tax expense relates to state
income taxes. The following table summarizes our tax activity for the last two
years (in thousands):

                                                          2019             2018
Total (loss) income before income taxes              $ (2,216,588 )$ (1,776,970 )
U.S. federal statutory rate                                    21 %             21 %
Total tax (benefit) expense at statutory rate            (465,483 )       

(373,164 )


Federal rate change                                             -           

-

State and local income taxes, net of federal benefit (83,348 )

4,427

State rate and law change                                 (40,574 )        (17,231 )
Non-deductible goodwill impairment                              -          

344,651

Non-deductible executive compensation                         474           

759

Tax less than book equity compensation                      4,625           

2,095

Change in valuation allowances:
Federal valuation allowances & other                       27,922           

20

State valuation allowances & other                         56,925           

7,638

Permanent differences and other                              (832 )         

316

Total benefit for income taxes                       $   (500,291 )$    (30,489 )
Effective tax rate                                           22.6 %            1.7 %


We estimate our ability to utilize our deferred tax assets by analyzing the
reversal patterns of our temporary differences, our loss carryforward periods
and the Pennsylvania and Louisiana net operating loss carryforward limitations.
Uncertainties such as future commodity prices can affect our calculations and
the expiration of loss carryforwards prior to utilization can result in
recording a partial as opposed to a full valuation allowance.



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Management's Discussion and Analysis of Financial Condition, Cash Flows, Capital Resources and Liquidity


Cash Flows

The following table presents sources and uses of cash and cash equivalents for the last two years (in thousands):


                                                 2019             2018
Sources of cash and cash equivalents
Operating activities                        $    681,843$    990,690
Disposal of assets                               784,937          324,549
Borrowing on credit facility                   2,311,000        2,070,000
Other                                             22,672           58,937

Total sources of cash and cash equivalents $ 3,800,452$ 3,444,176


Uses of cash and cash equivalents
Additions to natural gas and oil properties $   (687,277 )$   (960,916 )
Acreage purchases                                (59,986 )        (60,603 )
Other property                                    (1,162 )         (1,477 )
Repayments on credit facility                 (2,777,000 )     (2,338,000 )
Repayment of senior notes                       (195,432 )              -
Dividends paid                                   (20,070 )        (19,940 )
Repurchases of treasury stock                     (6,908 )              -
Other                                            (52,616 )        (63,143 )

Total uses of cash and cash equivalents $ (3,800,451 )$ (3,444,079 )



Cash flows from operating activities are primarily affected by production
volumes and commodity prices, net of the effects of settlements of our
derivatives. Our cash flows from operating activities are also impacted by
changes in working capital. We generally maintain low cash and cash equivalent
balances because we use available funds to reduce our bank debt. Short-term
liquidity needs are satisfied by borrowings under our bank credit facility.
Because of this, and because our principal source of operating cash flows
(proved reserves to be produced in the following year) cannot be reported as
working capital, we often have low or negative working capital. We sell a
portion of our production at the wellhead under floating market contracts. From
time to time, we enter into various derivative contracts to provide an economic
hedge of our exposure to commodity price risk associated with anticipated future
natural gas, NGLs and oil production. The production we hedge has and will
continue to vary from year to year depending on, among other things, our
expectation of future commodity prices. Since year-end 2019, we have entered
into additional natural gas and NGLs hedges for 2020 and 2021. Any payments due
to counterparties under our derivative contracts should ultimately be funded by
prices received from the sale of our production. However, production receipts
often lag payments to the counterparties. Any interim cash needs are funded by
borrowings under the bank credit facility. As of December 31, 2019, we have
entered into derivative agreements covering 387.2 Bcfe for 2020 and 20.4 Bcfe
for 2021, not including our basis swaps.

Net cash provided from operating activities in 2019 was $681.8 million compared
to $990.7 million in 2018. The decrease in cash provided from operating
activities is the result of a 25% decrease in realized prices partially offset
by a 4% increase in production volumes. Net cash provided from operating
activities is also affected by working capital changes or the timing of cash
receipts and disbursements. Changes in working capital (as reflected in our
consolidated statements of cash flows) for 2019 was an inflow of
$2.5 million compared to an outflow of $8.2 million for 2018.

Disposal of assets in 2019 included proceeds of $750.0 million from the sale, in
three separate transactions, of a proportionately reduced 2.5% overriding
royalty in our Washington County, Pennsylvania leases and $34.0 million of
proceeds from the sale of unproved property in Pennsylvania. In 2018, we
received proceeds of $300.0 million from the sale of a proportionately reduced
1% overriding royalty in our Washington County, Pennsylvania leases and $23.3
million of proceeds from the sale of certain properties in Northern Oklahoma.

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Additions to natural gas and oil properties are our most significant use of cash
and cash equivalents. These cash outlays are associated with our drilling and
completion capital budget program. The following table shows capital
expenditures by region and reconciles to additions to natural gas and oil
properties as presented on our consolidated statements of cash flows for the
last two years (in thousands):

                                                               2019          2018
Appalachian                                                 $ 604,721$ 715,690
North Louisiana                                                65,846       131,188
Other                                                               -          (561 )
Total                                                         670,567       846,317

Change in capital expenditure accrual for proved properties 16,710 114,599 Additions to natural gas and oil properties

                 $ 687,277     $ 

960,916

Repayment of senior notes for 2019 includes open market purchases of $101.8 million principal amount of our 5.75% senior notes due 2021, $68.1 million principal amount of our 5.00% senior notes due 2022 and $31.6 million principal amount of our 5.875% senior notes due 2022.

Liquidity and Capital Resources


Our main sources of liquidity and capital resources are internally generated
cash flow from operating activities, a bank credit facility with uncommitted and
committed availability, asset sales and access to the debt and equity capital
markets. In April 2018, we entered into an amended and restated bank credit
facility with a maturity date of April 13, 2023. We must find new and develop
existing reserves to maintain and grow our production and cash flows. We
accomplish this primarily through successful drilling programs which require
substantial capital expenditures. Lower prices for natural gas, NGLs and oil may
reduce the amount of natural gas, NGLs and oil we can economically produce and
can also affect the amount of cash flow available for capital expenditures and
our ability to borrow or raise additional capital.

We currently believe that net cash generated from operating activities, unused
committed borrowing capacity under our bank credit facility and proceeds from
asset sales combined with our natural gas, NGLs and oil derivatives currently in
place will be adequate to satisfy near-term financial obligations and liquidity
needs. While our expectation is to operate within our internally generated cash
flow, to the extent our capital requirements exceed our internally generated
cash flow and proceeds from asset sales, we will use borrowings under our credit
facility or debt or equity may be issued to fund these requirements. Long-term
cash flows are subject to a number of variables including the level of
production and prices as well as various economic conditions that have
historically affected the natural gas and oil business. We establish a capital
budget at the beginning of each calendar year and review it during the course of
the year. Our 2020 capital budget is $520.0 million. Actual capital expenditure
levels may vary due to many factors, including drilling results, natural gas,
NGLs, crude oil and condensate prices, industry conditions, the prices and
availability of goods and services and the extent to which properties are
acquired or assets are sold.

Commodity prices have remained volatile. We have adjusted and must continue to
adjust our business through efficiencies and cost reductions to compete in the
current price environment which also requires reductions in overall debt levels
over time. We plan to continue to work towards profitable growth within our cash
flows. We would expect to monitor the market and look for opportunities to
refinance or reduce debt based on market conditions. We believe we are
well-positioned to manage the challenges presented in a low commodity price
environment and that we can endure continued volatility in current and future
commodity prices by:

    •   exercising discipline in our capital program with our goal to
        target funding our capital spending within operating cash flows
        and, if required, with borrowings under our bank credit facility;


    •   continuing to optimize our drilling, completion and operational
        efficiencies;

• continuing to manage price risk by hedging our production volumes; and

• continuing to manage our balance sheet.



We believe that we will have adequate capital resources and liquidity for the
foreseeable future because (1) we have significant borrowing capacity under our
bank credit facility with a maturity in 2023 (2) we have commodity derivatives
in place which cover a portion of our 2020 and 2021 production (3) we can reduce
our capital expenditures for extended periods of time if necessary and (4) as of
December 31, 2019, the maturity of our senior and senior subordinated notes
extend one year or more and such notes carry attractive fixed interest rates
ranging from 4.875% to 5.875%. In January 2020, we issued $550.0 million
aggregate principal amount of 9.25% senior notes due 2026 for an estimated net
proceeds of $541.6 million. On the closing of the 9.25% senior notes, we used
the proceeds to redeem $324.1 million of our 5.75% senior notes due 2021 and
$175.9 million of our 5.875% senior notes due 2022, which was completed in
February 2020. For additional information, see Note 8 to our consolidated
financial statements.

From time to time, we may seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if

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any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts may be material.

Credit Arrangements


Long-term debt at December 31, 2019 totaled $3.2 billion, including $477.0
million of bank credit facility debt, $2.7 billion of senior notes and $49.0
million of senior subordinated notes. As of December 31, 2019, we maintain a
bank credit facility with a borrowing base of $3.0 billion and aggregate lender
commitments of $2.4 billion. As of December 31, 2019, we also have
$250.2 million of undrawn letters of credit. The bank credit facility is secured
by substantially all of our assets and has a maturity date of April 13, 2023.
Availability under the bank credit facility, during a non-investment grade
period, is subject to a borrowing base set by the lenders annually (at their
discretion) with an option to reset the borrowing base more often in certain
circumstances. Availability under the bank credit facility during an investment
grade period is limited to the aggregate lender commitments. The borrowing base
is dependent on a number of factors, but primarily the lenders' assessments of
future cash flows. Redeterminations of the borrowing base to maintain or reduce
the amount thereof require approval of two-thirds of the lenders and increases
require 95% approval of the lenders.

Our bank credit facility imposes limitations on the payment of dividends and
other restricted payments (as defined under the debt agreements for our bank
debt). The debt agreements also contain customary covenants relating to debt
incurrence, liens, investments and financial ratios. We were in compliance with
all covenants at December 31, 2019.

Proved Reserves


To maintain and grow production and cash flow, we must continue to develop
existing proved reserves and locate or acquire new natural gas, NGLs and oil
reserves. The following is a discussion of proved reserves, reserve additions
and revisions and future net cash flows from proved reserves.

                               Year End December 31,
                               2019             2018
                                               (Mmcfe)
Proved Reserves:
Beginning of year            18,072,406       15,262,361
Reserve additions             1,161,274        3,143,898
Reserve revisions               303,068          731,735
Purchases                             -                -
Sales                          (511,811 )       (262,180 )
Production                     (833,354 )       (803,408 )
End of year                  18,191,583       18,072,406

Proved Developed Reserves:
Beginning of year             9,756,870        8,348,074
End of year                   9,902,467        9,756,870


Our proved reserves at year-end 2019 were 18.2 Tcfe compared to 18.1 Tcfe at
year-end 2018. Natural gas comprised approximately 67% of our proved reserves at
year-end 2019, 2018 and 2017.

Reserve Additions and Revisions. During 2019, we added 1.2 Tcfe of proved
reserves from drilling activities and evaluation of proved areas primarily in
the Marcellus Shale. Approximately 83% of 2019 reserve additions was
attributable to natural gas. Included in 2019 proved reserves is a total of
475.0 Mmbbls of ethane reserves (2,102 Bcfe) in the Marcellus Shale, which
represents reserves that match volumes delivered under our existing long-term,
extendable contracts. Revisions of previous estimates of 303.1 Bcfe includes
positive performance revisions of 922.2 Bcfe somewhat offset by 601.3 Bcfe
reserves reclassified to unproved due to drilling plans and negative pricing
revisions of 17.8 Bcfe.

During 2018, we added 3.1 Tcfe of proved reserves from drilling activities and
evaluation of proved areas primarily in the Marcellus Shale. Approximately 72%
of 2018 reserve additions was attributable to natural gas. Included in 2018
proved reserves is a total of 468.9 Mmbbls of ethane reserves (2,074 Bcfe) in
the Marcellus Shale, which represents reserves that match volumes delivered
under our existing long-term, extendable contracts. Revisions of previous
estimates of 731.7 Bcfe include positive pricing revisions of 11.0 Bcfe,
improved recovery for our Marcellus Shale properties of 154.0 Bcfe and positive
performance revisions of 945.5 Bcfe somewhat offset by 378.8 Bcfe reserves
reclassified to unproved due to drilling plans.

Sales. In 2019, we sold 511.8 Bcfe of reserves in Pennsylvania. In 2018, we sold 143.6 Bcfe of reserves in Pennsylvania and 118.2 Bcfe of reserves in Oklahoma.

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Future Net Cash Flows. At December 31, 2019, the present value (discounted at
10%) of estimated future net cash flows from our proved reserves was $7.6
billion. The present value of our estimated future net cash flows at
December 31, 2018 was $13.2 billion. This present value was calculated based on
the unweighted average first-day-of-the-month oil and gas prices for the prior
twelve months held flat for the life of the reserves, in accordance with SEC
rules. At December 31, 2019, the after-tax present value of estimated future net
cash flows from our proved reserves was $6.6 billion compared to $11.1 billion
at December 31, 2018.

The present value of future net cash flows does not purport to be an estimate of
the fair market value of our proved reserves. An estimate of fair value would
also take into account, among other things, anticipated changes in future prices
and costs, the expected recovery of reserves in excess of proved reserves and a
discount factor more representative of the time value of money to the evaluating
party and the perceived risks inherent in producing oil and gas.

Capitalization and Dividend Payments


As of December 31, 2019 and 2018, our total debt and capitalization were as
follows (in thousands):

                                2019            2018
Bank debt                    $   464,319$   932,018
Senior notes                   2,659,844       2,856,166
Senior subordinated notes         48,774          48,677
Total debt                     3,172,937       3,836,861
Stockholders' equity           2,347,488       4,059,431

Total capitalization $ 5,520,425$ 7,896,292 Debt to capitalization ratio 57.5 % 48.6 %



The amount of future dividends is subject to declaration by the board of
directors and primarily depends on earnings, capital expenditures and various
other factors. In 2019, we paid $20.1 million in dividends to our stockholders
($0.02 per share per quarter) compared to $19.9 million in 2018 ($0.02 per share
per quarter). In January 2020, we announced that the board has suspended the
dividend.

Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, derivative
obligations, asset retirement obligations, and transportation, gathering and
processing commitments. As of December 31, 2019, we do not have any capital
leases or any significant off-balance sheet debt or other such unrecorded
obligations and we have not guaranteed any debt of any unrelated party. As of
December 31, 2019, we had a total of $250.2 million of letters of credit
outstanding under our bank credit facility. The table below provides estimates
of the timing of future payments that we are obligated to make based on
agreements in place at December 31, 2019. In addition to the contractual
obligations listed on the table below, our consolidated balance sheet at
December 31, 2019 reflects accrued interest payable on our bank debt of $2.2
million, which is payable in first quarter 2020. We expect to make interest
payments through the end of each note maturity, based upon the amounts
outstanding at December 31, 2019, of $23.0 million per year on our 5.75% senior
and senior subordinated notes, $64.0 million per year on our 5.0% senior and
senior subordinated notes, $36.6 million per year on our 4.875% senior notes and
$17.5 million on our 5.875% senior notes.

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The following summarizes our contractual financial obligations at December 31,
2019 and their future maturities. We expect to fund these contractual
obligations with cash generated from operating activities, borrowings under our
bank credit facility, additional debt issuances and proceeds from asset sales
(in thousands).

                                                                    Payment due by period
                                                                                   2023
                                   2020           2021            2022           and 2024       Thereafter          Total
Debt:
Bank debt due 2023 (a)           $       -     $         -     $         -      $   477,000     $         -      $    477,000
5.75% senior subordinated notes          -          22,214               -                -               -
due 2021                                                                                                               22,214
5.0% senior subordinated notes           -               -          19,054                -               -
due 2022                                                                                                               19,054
5.0% senior subordinated notes           -               -               -            7,712               -
due 2023                                                                                                                7,712
5.75% senior notes due 2021              -         374,139               -                -               -           374,139
5.00% senior notes due 2022              -               -         511,886                -               -           511,886
5.00% senior notes due 2023              -               -               -          741,531               -           741,531
5.875% senior notes due 2022             -               -         297,617                -               -           297,617
4.875% senior notes due 2025             -               -               -                -         750,000           750,000
Other obligations:
Operating leases, net               31,245          14,252           7,023           12,968          15,262            80,750
Software licenses and other          3,966             524             226              226               -             4,942
Transportation and gathering       945,392
commitments (b)                                    949,126         905,920        1,723,519       5,154,987         9,678,944
Asset retirement obligation          2,394
liability (c)                                            -              11                -         250,986           253,391
Total contractual obligations      982,997
(d)                              $             $ 1,360,255$ 1,741,737

$ 2,962,956$ 6,171,235$ 13,219,180

(a) Due at termination date of our bank credit facility. Interest paid on our

bank credit facility would be approximately $14.3 million each year assuming

no change in the interest rate or outstanding balance.

(b) Amounts included transportation and gathering commitments after 2024 will

decline as follows: $764.0 million in 2025; $688.0 million in 2026; $618.0

million in 2027; $580.0 million in 2028; $500.0 million in 2029; declining to

$167.0 million in 2033 until the final year of $7.0 million in 2039.

(c) The ultimate settlement amount and timing cannot be precisely determined in

advance. See Note 9 to our consolidated financial statements.

(d) This table excludes the liability for the deferred compensation plans since

these obligations will be funded with existing plan assets.



In addition to the amounts included in the above table, we have entered into
additional agreements which are contingent on certain pipeline modifications
and/or construction for natural gas volumes of 25,000 mcf per day, which is
expected to begin in 2022 and has a six-year term.

Delivery Commitments


We have various volume delivery commitments that are related to our Marcellus
Shale and North Louisiana areas. We expect to be able to fulfill our contractual
obligations from our own production; however, we may purchase third-party
volumes to satisfy our commitments or pay demand fees for commitment shortfalls,
should they occur. As of December 31, 2019, our delivery commitments through
2031 were as follows:

           Year Ending                  Natural Gas            Ethane and Propane
            December 31,              (mmbtu per day)            (bbls per day)
               2020                            528,607               81,000
               2021                            491,313               65,932
               2022                            370,179               43,000
               2023                            167,970               35,000
           2024 - 2028                         100,000               35,000
               2029                            100,000               20,000
           2030 - 2031                               -               20,000


In addition to the amounts included in the above table, we have contracted with
a pipeline company through 2035 to deliver ethane production volumes from our
Marcellus Shale wells. These agreements and related fees, which are contingent
upon pipeline construction and/or modification, are for 3,000 bbls per day
starting in 2021 and increasing to 10,000 bbls per day through 2035. In
addition, we have agreements in place to deliver natural gas volumes from our
Marcellus Shale wells, which are also contingent upon pipeline construction
and/or modification, for 35,000 mcf per day starting late 2020, increasing to
50,000 mcf per day in 2021 and decreasing to 15,000 mcf per day in 2025.



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Other


We have various midstream service agreements in North Louisiana for gathering,
processing and transporting of natural gas and NGLs. Pursuant to the gas
processing agreement, we must pay a quarterly deficiency payment based on the
firm-commitment fixed fee if the cumulative minimum volume commitment as of the
end of a quarter exceeds the sum of (i) the cumulative volumes processed under
the processing agreement as of the end of the quarter plus (ii) volumes
corresponding to deficiency payments incurred prior to each quarter. In the
event these properties are sold in the future and any or all of these charges
are retained by us, we would recognize and accrue these future
divestiture-related charges, which could be significant.

We lease acreage that is generally subject to lease expiration if initial wells
are not drilled within a specified period, generally between three and five
years. We do not expect to lose significant lease acreage because of failure to
drill due to inadequate capital, equipment or personnel. However, based on our
evaluation of prospective economics, including the cost of infrastructure to
connect production, we have allowed acreage to expire and will allow additional
acreage to expire in the future. To date, our expenditures to comply with
environmental or safety regulations have not been a significant component of our
cost structure and are not expected to be significant in the future. However,
new regulations, enforcement policies, claims for damages, or other events could
result in significant future costs.

Hedging - Natural Gas, Oil and NGLs Prices


We use commodity-based derivative contracts to help manage exposures to
commodity price fluctuations. We do not enter into these arrangements for
speculative or trading purposes. We do not utilize complex derivatives as we
typically utilize commodity swaps, swaptions and calls to (1) reduce the effect
of price volatility on the commodities we produce and sell and (2) support our
annual capital budget and expenditure plans. In addition, we may utilize basis
contracts to hedge the differential between NYMEX and those of our physical
pricing points or between Mont Belvieu and international propane indexes. For
more discussion of our derivative activities, see Management's Discussion of
Critical Accounting Estimates - Natural Gas and Oil Derivatives below and Item
7A. Quantitative and Qualitative Disclosures about Market Risk - Commodity Price
Risk and Other Commodity Risk. For more information regarding the accounting for
our derivatives, see the discussion in Notes 2, 10 and 11 to our consolidated
financial statements. While there is a risk that the financial benefit of rising
natural gas, NGLs and oil prices may not be captured, we believe the benefits of
stable and predictable cash flow are more important. Among these benefits are a
more efficient utilization of existing personnel and planning for future staff
additions, the flexibility to enter into long-term projects requiring
substantial committed capital, smoother and more efficient execution of our
ongoing development drilling and production enhancement programs, more
consistent returns on invested capital and better access to bank and other
credit markets.

Interest Rates


At December 31, 2019, we had $3.2 billion of debt outstanding. Of this amount,
$2.7 billion bears interest at fixed rates averaging 5.2%. Bank debt totaling
$477.0 million bears interest at floating rates, which averaged 3.0% at year-end
2019. The 30-day LIBOR rate on December 31, 2019 was 1.8%. A 1% increase in
short-term interest rates on the floating-rate debt outstanding at December 31,
2019 would cost us approximately $4.8 million in additional annual interest
expense.

Off-Balance Sheet Arrangements


We do not currently utilize any off-balance sheet arrangements with
unconsolidated entities to enhance our liquidity or capital resources position.
However, as is customary in the natural gas and oil industry, we have various
contractual work commitments which are described above under cash contractual
obligations.

Inflation and Changes in Prices


Our revenues, the value of our assets and our ability to obtain bank loans or
additional capital on attractive terms have been and will continue to be
affected by changes in natural gas, NGLs and oil prices and the costs to produce
our reserves. Natural gas, NGLs and oil prices are subject to significant
fluctuations that are beyond our ability to control or predict. Although certain
of our costs and expenses are affected by general inflation, inflation does not
normally have a significant effect on our business. We expect costs in 2020 to
continue to be a function of supply and demand. Natural gas and oil prices have
remained depressed. We continue to experience a decline in our cost structure.

Management's Discussion of Critical Accounting Estimates


Our discussion and analysis of our financial condition and results of operations
are based upon our consolidated financial statements, which have been prepared
in accordance with accounting principles generally accepted in the United
States. The preparation of our financial statements requires us to make
estimates and assumptions that affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities at year-end and
the reported amounts of revenues and expenses during the year. Accounting
estimates are considered to be critical if (1) the nature of the estimates and
assumptions is material due to the levels of subjectivity and judgment necessary
to account for highly uncertain matters or the susceptibility of such matters to
changes; and

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(2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used.

Estimated Quantities of Net Reserves


We use the successful efforts method of accounting for natural gas and oil
producing activities as opposed to the alternate acceptable full cost method. We
believe that net assets and net income are more conservatively measured under
the successful efforts method of accounting than under the full cost method,
particularly during periods of active exploration. One difference between the
successful efforts method of accounting and the full cost method is that under
the successful efforts method, all exploratory dry holes and geological and
geophysical costs are charged against earnings during the periods they occur;
whereas, under the full cost method of accounting, such costs are capitalized as
assets, pooled with the costs of successful wells and charged against earnings
of future periods as a component of depletion expense. Under the successful
efforts method of accounting, successful exploration drilling costs and all
development costs are capitalized and these costs are systematically charged to
expense using the units of production method based on proved developed natural
gas and oil reserves as estimated by our engineers and audited by independent
engineers. Costs incurred for exploratory wells that find reserves that cannot
yet be classified as proved are capitalized on our balance sheet if (1) the well
has found a sufficient quantity of reserves to justify its completion as a
producing well and (2) we are making sufficient progress assessing the reserves
and the economic and operating viability of the project. Proven property
leasehold costs are amortized to expense using the units of production method
based on total proved reserves. Properties are assessed for impairment as
circumstances warrant (at least annually) and impairments to value are charged
to expense. The successful efforts method inherently relies upon the estimation
of proved reserves, which includes proved developed and proved undeveloped
volumes.

Proved reserves are defined by the SEC as those volumes of natural gas, NGLs,
condensate and crude oil that geological and engineering data demonstrate with
reasonable certainty are recoverable in future years from known reservoirs under
existing economic and operating conditions. Proved developed reserves are
volumes expected to be recovered through existing wells with existing equipment
and operating methods. Proved undeveloped reserves include reserves for which a
development plan has been adopted indicating each location is scheduled to be
drilled within five years from the date it was booked as proved reserves, unless
specific circumstances justify a longer time. Although our engineers are
knowledgeable of and follow the guidelines for reserves established by the SEC,
the estimation of reserves requires engineers to make a significant number of
assumptions based on professional judgment. Reserve estimates are updated at
least annually and consider recent production levels and other technical
information. Estimated reserves are often subject to future revisions, which
could be substantial, based on the availability of additional information,
including reservoir performance, new geological and geophysical data, additional
drilling, technological advancements, price and cost changes and other economic
factors. Changes in natural gas, NGLs and oil prices can lead to a decision to
start up or shut in production, which can lead to revisions to reserve
quantities. Reserve revisions in turn cause adjustments in our depletion rates.
We cannot predict what reserve revisions may be required in future periods.
Reserve estimates are reviewed and approved by our Senior Vice President of
Reservoir Engineering and Economics, who reports directly to our President and
Chief Executive Officer. To further ensure the reliability of our reserve
estimates, we engage independent petroleum consultants to audit our estimates of
proved reserves. Estimates prepared by third parties may be higher or lower than
those included herein. Independent petroleum consultants audited approximately
90% of our reserves in 2019 compared to 94% in 2018. Historical variances
between our reserve estimates and the aggregate estimates of our consultants
have been less than 5%. The reserves included in this report are those reserves
estimated by our petroleum engineering staff. For additional discussion, see
Items 1 & 2. Business and Properties - Proved Reserves.

Depletion rates are determined based on reserve quantity estimates and the
capitalized costs of producing properties. As the estimated reserves are
adjusted, the depletion expense for a property will change, assuming no change
in production volumes or the capitalized costs. While total depletion expense
for the life of a property is limited to the property's total cost, proved
reserve revisions result in a change in the timing of when depletion expense is
recognized. Downward revisions of proved reserves may result in an acceleration
of depletion expense, while upward revisions tend to lower the rate of depletion
expense recognition. Based on proved reserves at December 31, 2019, we estimate
that a 1% change in proved reserves would increase or decrease 2020 depletion
expense by approximately $4.0 million (based on current production estimates).
Estimated reserves are used as the basis for calculating the expected future
cash flows from property asset groups, which are used to determine whether that
property may be impaired. Reserves are also used to estimate the supplemental
disclosure of the standardized measure of discounted future net cash flows
relating to natural gas and oil producing activities and reserve quantities in
Note 18 to our consolidated financial statements. Changes in the estimated
reserves are considered a change in estimate for accounting purposes and are
reflected on a prospective basis. It should not be assumed that the standardized
measure is the current market value of our estimated proved reserves.

Fair Value Estimates


Fair value is the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at
the measurement date. There are three approaches for measuring the fair value of
assets and liabilities: the market approach, the income approach and the cost
approach, each of which includes multiple valuation techniques. The market
approach uses prices and other relevant information generated by market
transactions involving identical or comparable assets or liabilities. The income
approach uses valuation techniques to measure fair value by converting future
amounts, such as cash flows or earnings, into a single present value, or range
of present values, using current market expectations about those future amounts.
The cost approach is based on the amount that would currently be required to
replace the service capacity of an asset. This is often referred

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to as current replacement cost. The cost approach assumes that the fair value
would not exceed what it would cost a market participant to acquire or construct
a substitute asset of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique
should be used when measuring fair value and does not prioritize among the
techniques. These standards establish a fair value hierarchy that prioritizes
the inputs used in applying the various valuation techniques. Inputs broadly
refer to the assumptions that market participants use to make pricing decisions,
including assumptions about risk. Level 1 inputs are given the highest priority
in the fair value hierarchy, while Level 3 inputs are given the lowest priority.
The three levels of the fair value hierarchy are as follows:

     •  Level 1-Observable inputs that reflect unadjusted quoted prices for
        identical assets or liabilities in active markets as of the
        measurement date. Active markets are those in which transactions for
        the asset or liability occur in sufficient frequency and volume to
        provide pricing information on an ongoing basis.


     •  Level 2-Observable market-based inputs or unobservable inputs that
        are corroborated by market data. These are inputs other than quoted
        prices in active markets included in Level 1, which are either
        directly or indirectly observable as of the measurement date.


     •  Level 3-Unobservable inputs for which there is little, if any, market
        activity for the asset or liability being measured. These inputs
        reflect management's best estimates of the assumptions market
        participants would use in determining fair value. Our Level 3
        measurements consist of instruments using standard pricing models and
        other valuation methods that utilize unobservable pricing inputs that
        are significant to the overall value.


Valuation techniques that maximize the use of observable inputs are favored.
Assets and liabilities are classified in their entirety based on the lowest
priority level of input that is significant to the fair value measurement. The
assessment of the significance of a particular input to the fair value
measurement requires judgment and may affect the placement of assets and
liabilities within the levels of the fair value hierarchy. See Note 11 to the
consolidated financial statements for disclosures regarding our fair value
measurements.

Impairment Assessments of Natural Gas and Oil Properties


Long-lived assets in use are assessed for impairment whenever changes in facts
and circumstances indicate that the carrying value of the assets may not be
recoverable, including a significant reduction in prices of natural gas, oil,
condensate and NGLs, reductions to our capital budget, unfavorable adjustments
to reserves, significant changes in the expected timing of production and other
changes to contracts or changes in the regulatory environment in which a
property is located. For purposes of an impairment evaluation, long-lived assets
must be grouped at the lowest level for which independent cash flows can be
identified, which generally is field-by-field, in certain instances, by logical
grouping of assets if there is significant shared infrastructure or contractual
terms that cause economic interdependency amongst separate, discrete fields. If
the sum of the undiscounted estimated cash flows from the use of the asset group
and its eventual disposition is less than the carrying value of an asset group,
the carrying value is written down to the estimated fair value. During 2019, a
change in business strategy employed by management in North Louisiana and the
possibility of a divestiture of these assets triggered an assessment of these
long-lived assets for impairment. We estimated the fair values using a
discounted net cash flow model or an income approach and we recognized an
impairment. As of December 31, 2019, our estimated undiscounted cash flows
relating to our remaining long-lived assets significantly exceeded their
carrying values. See Note 11 to the consolidated financial statements for
discussion of impairments recorded in 2019, 2018 and 2017 and the related fair
value measurements.

Fair value calculated for the purpose of testing our natural gas and oil properties for impairment is estimated using the present value of expected future cash flows method and comparative market prices when appropriate. Significant judgment is involved in performing these fair value estimates since the results are based on forecasted assumptions. Significant assumptions include:

• Future crude oil and condensate, NGLs and natural gas prices. Our

estimates of future prices are based on market information including

published futures prices. Although these commodity prices may experience

extreme volatility in any given year, we believe long-term industry

prices are driven by market supply and demand. The prices we use in our

fair value estimates are consistent with those used in our planning and

capital investment reviews. There has been significant volatility in

crude oil and condensate, NGLs and natural gas prices and estimates of

          such future prices are inherently imprecise. See Item 1A. Risk Factors
          for further discussion on commodity prices.

• Estimated quantities of crude oil and condensate, NGLs and natural gas.

          Such quantities are based on risk adjusted proved and probable reserves
          and resources such that the combined volumes represent the most likely
          expectation of recovery. See Item 1A. Risk Factors for further
          discussion on reserves.

• Expected timing of production. Production forecasts are the outcome of

          engineering studies which estimate reserves, as well as expected capital
          programs. The actual timing of the production could be different than

the projection. Cash flows realized later in the projection period are

          less valuable than those realized earlier due to the time value of
          money. The expected timing of production that we use in our fair value
          estimates is consistent with that used in our planning and capital
          investment reviews.


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• Discount rate commensurate with the risks involved. We apply a discount

rate to our expected cash flows based on a variety of factors, including

          market and economic conditions, operational risk, regulatory risk and
          political risk. A higher discount rate decreases the net present value
          of cash flows.


       •  Future capital requirements. Our estimates of future capital
          requirements consider the assumptions utilized by management for
          internal planning and budgeting.


We base our fair value estimates on projected financial information which we
believe to be reasonably likely to occur. An estimate of the sensitivity to
changes in assumptions in our undiscounted cash flow calculations is not
practicable, given the numerous assumptions (e.g. reserves, pace and timing of
development plans, commodity prices, capital expenditures, operating costs,
drilling and development costs, inflation and discount rates) that can
materially affect our estimates. Unfavorable adjustments to some of the above
listed assumptions would likely be offset by favorable adjustments in other
assumptions. For example, the impact of sustained reduced commodity prices on
future undiscounted cash flows would likely be partially offset by lower costs.

We also evaluate our unproved property investment periodically for impairment.
The majority of these costs generally relate to the acquisition of leaseholds
and allocated probable and possible reserve value resulting from acquisitions.
The costs are capitalized and evaluated (at least quarterly) as to
recoverability based on changes brought about by economic factors and potential
shifts in business strategy employed by management. Impairment of a significant
portion of our unproved properties is assessed and amortized on an aggregate
basis based on our average holding period, expected forfeiture rate and
anticipated drilling success. Potential impairment of individually significant
unproved property is assessed on a property-by-property basis considering a
combination of time, geologic and engineering factors. A portion of unproved
property may relate to probable and possible reserves whose recoverability is
evaluated based on management expectations and ability to drill these locations.
In certain circumstances, our future plans to develop acreage may accelerate our
impairment. In 2019, a $1.2 billion impairment was recorded associated with our
North Louisiana assets where we no longer have the intent to drill locations
based on a shift in capital allocation which materially impacted our drilling
inventory. We have recorded abandonment and impairment expense related to
unproved properties of $1.2 billion in 2019 compared to $515.0 million in 2018.

Natural Gas, NGLs and Oil Derivatives


All derivative instruments are recorded on our consolidated balance sheets as
either an asset or a liability measured at its fair value. Fair value
measurements for all of our derivatives are based upon, among other things,
option pricing models, futures, volatility, time to maturity and credit risk and
are discussed in Note 11 to our consolidated financial statements. Additional
information about derivatives and their valuation may be found in Item 7A.
Quantitative and Qualitative Disclosures about Market Risk.

Asset Retirement Obligations


We have significant obligations to remove tangible equipment and restore the
surface at the end of natural gas and oil production operations. Removal and
restoration obligations are primarily associated with plugging and abandoning
wells. Estimating the future asset removal costs is difficult and requires us to
make estimates and judgments because most of the removal obligations are many
years in the future and contracts and regulations often have vague descriptions
of what constitutes removal. Asset removal technologies and costs are constantly
changing, as are regulatory, political, environmental, safety and public
relations considerations.

Inherent in the fair value calculation are numerous assumptions and judgments
including the ultimate retirement costs, inflation factors, credit-adjusted
discount rates, timing of retirement, and changes in the legal, regulatory,
environmental and political environments. To the extent future revisions to
these assumptions impact the present value of the existing asset retirement
obligation ("ARO"), a corresponding adjustment is made to the natural gas and
oil property balance. For example, as we analyze actual plugging and abandonment
information, we may revise our estimate of current costs, the assumed annual
inflation of the costs and/or the assumed productive lives of our wells. During
2019, we increased our existing ARO by $7.1 million or approximately 2% of the
ARO balance at December 31, 2018 primarily related to increases in our estimated
costs to plug and abandon wells in North Louisiana. During 2018, we increased
our existing ARO by $12.0 million or approximately 4% of the ARO balance at
December 31, 2017 primarily related to an increase in our estimated costs to
plug and abandon wells in Pennsylvania. See Note 9 to the consolidated financial
statements for disclosures regarding our asset retirement obligation estimates.
In addition, increases in the discounted ARO resulting from the passage of time
are reflected as accretion expense, a component of depletion, depreciation and
amortization in the accompanying consolidated statements of operations. Because
of the subjectivity of assumptions and the relatively long lives of most of our
wells, the costs to ultimately retire our wells may vary significantly from
prior estimates. An estimate of the sensitivity to operating results of other
assumptions that had been used in recording these liabilities is not practical
because of the number of obligations that must be assessed, the number of
underlying assumptions and the wide range of possible assumptions.

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Income Taxes

We are subject to income and other taxes in all areas in which we operate. For financial reporting purposes, we provide taxes at rates applicable for the appropriate tax jurisdictions. Estimates of amounts of income tax involve interpretation of complex tax laws, including the 2017 Tax Act.


Our consolidated balance sheets include deferred tax assets. Deferred tax assets
arise when expenses are recognized in the financial statements before they are
recognized in the tax returns or when income items are recognized in the tax
returns before they are recognized in the financial statements. Deferred tax
assets also arise when operating losses or tax credits are available to offset
tax payments due in future years. Ultimately, realization of a deferred tax
asset depends on the existence of sufficient taxable income within the future
periods to absorb future deductible temporary differences, loss carryforwards or
credits.

In assessing the realizability of deferred tax assets, management must consider
whether it is more likely than not that some portion or all of the deferred tax
assets will not be realized. Management considers all available evidence (both
positive and negative) in determining whether a valuation allowance is required.
Such evidence includes the scheduled reversal of deferred tax liabilities,
projected future taxable income and tax planning strategies in making this
assessment and judgment is required in considering the relative weight of
negative and positive evidence. We continue to monitor facts and circumstances
in the reassessment of the likelihood that operating loss carryforwards, credits
and other deferred tax assets will be utilized prior to their expiration. As a
result, we may determine that an additional deferred tax asset valuation
allowance should be established.

In assessing facts and circumstances surrounding the realizability of our
deferred tax assets, we are required to apply judgment to determine the weight
of both positive and negative evidence in order to conclude whether the
valuation allowance is necessary to net operating loss carryforwards and other
deferred tax assets. In determining whether a valuation allowance is required
for our deferred tax asset balances, we consider, among other factors, current
financial position, results of operations, projected future taxable income, tax
planning strategies and new legislation. Significant judgment is involved in
this determination as we are required to make assumptions about future commodity
prices, projected production, development activities, profitability of future
business strategies and forecasted economics in the oil and gas industry.
Additionally, changes in the effective tax rate resulting from changes in tax
law and our level of earnings may limit utilization of deferred tax assets and
will affect valuation of deferred tax balances in the future. Changes in
judgment regarding future realization of deferred tax assets may result in a
reversal of all or a portion of the valuation allowance. In the period that
determination is made, our net income will benefit from a lower effective tax
rate.

We believe our net deferred tax assets, after valuation allowances, will
ultimately be realized. During 2019, we increased our valuation allowances
against our state net operating loss carryforwards, basis differences and
credits from $101.4 million as of December 31, 2018 to $158.3 million as of
December 31, 2019. The federal valuation allowances increased from $19.0 million
as of December 31, 2018 to $32.5 million as of December 31, 2019. See Note 6 to
our consolidated financial statements for further information concerning our
income taxes.

An estimate of the sensitivity to changes in our assumptions resulting in future
income calculations is not practical, given the numerous assumptions that can
materially affect our estimates. Unfavorable adjustments to some of the
assumptions would likely be offset by favorable adjustments in other
assumptions. For example, the impact of sustained reduced commodity prices on
future taxable income would likely be partially offset by lower capital
expenditures.

We may be challenged by taxing authorities over the amount and/or timing of
recognition of revenues and deductions in our various income tax returns.
Although we believe that we have adequately provided for all taxes, income or
losses could occur in the future due to changes in estimates or resolution of
outstanding tax matters.

Contingent Liabilities

A provision for legal, environmental and other contingent matters is charged to
expense when the loss is probable and the cost or range of cost can be
reasonably estimated. Judgment is often required to determine when expenses
should be recorded for legal, environmental and contingent matters. In addition,
we often must estimate the amount of such losses. In many cases, our judgment is
based on the input of our legal advisors and on the interpretation of laws and
regulations, which can be interpreted differently by regulators and/or the
courts. Actual costs can differ from estimates for many reasons. We monitor
known and potential legal, environmental and other contingent matters and make
our best estimate of when to record losses for these matters based on available
information. Although we continue to monitor all contingencies closely,
particularly our outstanding litigation, we currently have no material accruals
for contingent liabilities. We generally record losses related to these type of
contingencies as general and administrative expense in the consolidated
statements of operations.

                                       69

--------------------------------------------------------------------------------

Stock-based Compensation Arrangements


The fair value of performance-based share awards (where the performance
condition is based on market conditions) is estimated on the date of grant using
a Monte Carlo simulation method. A Monte Carlo simulation model utilizes
multiple input variables that determine the probability of satisfying the market
condition stipulated in the award grant. The fair value of restricted stock
awards and performance-based awards where the performance condition is based on
internal performance metrics is determined based on the fair market value of our
common stock on the date of grant.

We recognize stock-based compensation expense on a straight-line basis over the
requisite service period for the entire award. The expense we recognize is net
of estimated forfeitures. We estimate our forfeiture rate based on prior
experience and adjust it as circumstances warrant. See Note 12 to our
consolidated financial statements for more information.

Accounting Standards Not Yet Adopted

Refer to Note 2 to our consolidated financial statements for a discussion of new accounting pronouncements that may affect us in the future.

© Edgar Online, source Glimpses

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