SM Energy Company

Equities

SM

US78454L1008

Oil & Gas Exploration and Production

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SM ENERGY : MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-K)

February 18, 2021 at 08:58 am EST

The following discussion includes forward-looking statements. Please refer to
the Cautionary Information about Forward-Looking Statements section of this
report for important information about these types of statements.
Overview of the Company
General Overview
Our purpose is to make people's lives better by responsibly producing energy
supplies, contributing to domestic energy security and prosperity, and having a
positive impact in the communities where we live and work. Our short-term
operational and financial goals include generating positive cash flows while
strengthening our balance sheet through absolute debt reduction and improved
leverage metrics, and increasing the value of our capital project inventory
through exploration and development optimization. Our long-term vision is to
sustainably grow value for all of our stakeholders. We believe that in order to
accomplish this vision, we must be a premier operator of top tier assets. Our
investment portfolio is comprised of oil and gas producing assets in the state
of Texas, specifically in the Midland Basin of West Texas and in the Maverick
Basin of South Texas.
The Pandemic and associated macroeconomic events have had a significant impact
on supply and demand for oil, gas, and NGLs, and affected the realized prices we
received for our production throughout 2020. These impacts continue to be
unpredictable, and given the dynamic nature of the Pandemic, we are unable to
reasonably estimate the period of time that the related market conditions will
exist or the extent to which they will continue to impact our business, results
of operations, and financial condition, or the timing of any further recovery.
Future infection rate surges or outbreaks could have further negative impacts,
and as a result, we may be required to adjust our business plan. For additional
detail, please refer to Risk Factors in Part I, Item 1A of this report.
The safety of our employees, contractors, and the communities where we work
remains our first priority as we continue to operate during the Pandemic. While
our core business operations require certain individuals to be physically
present at well site locations, substantially all of our office-based employees
have continued working remotely in order to limit physical interactions and to
mitigate the spread of COVID-19, and will continue to do so well into 2021. For
individuals who are unable to perform their jobs remotely, we maintain and
continually assess procedures designed to limit the spread of COVID-19,
including social distancing and enhanced sanitization measures, and we continue
to communicate to and train all of our employees regarding best practices for
maintaining a healthy and safe work environment. We believe that we meet or
exceed CDC and OSHA guidelines related to the prevention of the transmission of
COVID-19. Since these measures were initially implemented in the first quarter
of 2020, we have continued to operate without significant disruptions to our
business operations. Our pre-existing control environment and internal controls
continue to be effective and we continue to address new risks directly related
to the Pandemic as we identify them.
Despite continuing negative impacts and future uncertainty, we expect to
maintain our ability to sustain strong operational performance and financial
stability while maximizing returns, improving leverage metrics, and increasing
the value of our top tier Midland Basin and South Texas assets. Our financial
risk management program significantly reduced the impact of substantially lower
oil prices in 2020, and as a result of this program, we recorded a net oil
derivative settlement gain of $14.40 per barrel for the year ended December 31,
2020. Our realized oil price before the effects of derivative settlements was
$37.08 per barrel for the year ended December 31, 2020. In response to the
economic environment during 2020, we renegotiated certain contracts resulting in
realized and future cost savings that directly support our objective of
maximizing cash flows. As a result of these cost saving measures and improving
operational efficiencies, average well costs for 2020 were lower than our
preliminary expectations for the year. We entered 2020 with a total capital
program budget between $825 million and $850 million. However, given the impacts
of the Pandemic and the related circumstances discussed above, we reduced our
2020 capital program by more than 25 percent. Please refer to the caption Costs
Incurred below for additional discussion.
Our vision to sustainably grow value for all of our stakeholders includes
near-term operational and financial goals of generating positive cash flows
while strengthening our balance sheet through absolute debt reduction and
improved leverage metrics. Our long-term plan is to deliver cash flow growth
that is supported by our high-quality asset base and ability to generate
favorable returns. We remain committed to exceptional safety, health, and
environmental stewardship; supporting the professional development of a diverse
and thriving team of employees; making a positive difference in the communities
where we live and work; and transparency in reporting on our progress in these
areas. The Environmental, Social and Governance Committee of our Board of
Directors oversees, among other things, the development and implementation of
the Company's environmental, social and governance policies, programs and
initiatives, and reports to our Board of Directors regarding such matters.
Further demonstrating our commitment to sustainable operations, compensation for
our executives and employees under our short-term and long-term incentive plans
is calculated based on metrics that include environmental, health, and safety
measures. Please refer to our Definitive Proxy Statement on Schedule 14A for the
2021 annual meeting of stockholders to be filed within 120 days from
December 31, 2020, for additional discussion.
2020 Financial and Operational Highlights
We remain focused on maximizing returns and increasing the value of our top tier
Midland Basin and South Texas assets. We expect to do this through continued
development optimization of our Midland Basin assets and through further
development of our Austin Chalk formation in South Texas. We believe our assets
provide strong returns and are capable of providing for growth of
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internally generated cash flows while allowing for flexibility of production
levels, which aligns with our priorities of improving leverage metrics and
maintaining strong financial flexibility.
The financial results and operational activities discussed throughout this
report reflect the impacts of the Pandemic during 2020, and the misalignment of
supply and demand caused by competition among oil producing nations for crude
oil market share during the first half of 2020. We will continue to monitor the
macroeconomic environment and maintain flexibility to adjust our financial and
operational plans as warranted.
Financial and Operational Results. Average net daily production for the year
ended December 31, 2020, was 126.9 MBOE, compared with 132.3 MBOE for 2019. This
decrease was primarily driven by a 21 percent decrease in daily production
volumes from our South Texas assets, partially offset by a 10 percent increase
in daily production volumes from our Midland Basin assets. During the year ended
December 31, 2020, as compared with 2019, net daily production volumes decreased
four percent as a result of proactive measures taken to respond to the lower
commodity price environment experienced in 2020 compared with 2019. This
included voluntary production curtailments and less costs incurred as a result
of intentionally reducing the number of new wells completed and brought on
production. Realized prices before the effects of derivative settlements for
oil, gas, and NGLs decreased 31 percent, 25 percent, and 19 percent,
respectively, for the year ended December 31, 2020, compared with 2019. As a
result of decreased realized prices, oil, gas, and NGL production revenue
decreased 29 percent to $1.1 billion for the year ended December 31, 2020,
compared with $1.6 billion for 2019. We recorded a net derivative gain of $161.6
million for the year ended December 31, 2020, compared to a net derivative loss
of $97.5 million for 2019. These amounts include derivative settlement gains of
$351.3 million and $39.2 million for the years ended December 31, 2020, and
2019, respectively. Overall financial and operational activities during the year
ended December 31, 2020, resulted in the following:
•a net loss of $764.6 million, or $6.72 per diluted share, for the year ended
December 31, 2020, compared with a net loss of $187.0 million, or $1.66 per
diluted share, for 2019. The net loss for the year ended December 31, 2020, was
primarily driven by impairment expense of $1.0 billion, partially offset by a
net gain on extinguishment of debt of $280.1 million, and a net derivative gain
of $161.6 million. Please refer to Comparison of Financial Results and Trends
Between 2020 and 2019 and Between 2019 and 2018 below for additional discussion
regarding the components of net income (loss) for each period presented;
•a $492.1 million decrease in the principal balance of our total outstanding
long-term debt from December 31, 2019, to December 31, 2020, primarily driven by
the Exchange Offers and open market repurchases of certain of our senior notes
at a discount and net cash provided by operating activities of $790.9 million
for the year ended December 31, 2020, which was in excess of net cash used in
investing activities of $555.6 million for the year ended December 31, 2020.
Please refer to Analysis of Cash Flow Changes Between 2020 and 2019 and Between
2019 and 2018 and to Note 5 - Long-Term Debt in Part II, Item 8 of this report
below for additional discussion including the definition of Exchange Offers;
•adjusted EBITDAX, a non-GAAP financial measure, for the year ended December 31,
2020, of $975.4 million, compared with $993.4 million for 2019, primarily
resulted from decreased revenue resulting from depressed commodity prices during
the year ended December 31, 2020, largely offset by increased derivative
settlement gains, combined with lower operating costs during 2020. Please refer
to Non-GAAP Financial Measures below for additional discussion, including our
definition of adjusted EBITDAX and reconciliations to our net income (loss) and
net cash provided by operating activities; and
•total estimated proved reserves as of December 31, 2020, decreased 12 percent
from December 31, 2019, to 404.6 MMBOE, of which, 57 percent were liquids (oil
and NGLs) and 57 percent were characterized as proved developed. The decrease in
total proved reserves primarily related to 46.4 MMBOE produced during 2020 and
32.6 MMBOE removed as a result of lower commodity prices experienced in 2020
compared with 2019, using pricing estimates determined in accordance with SEC
rules. Our proved reserve life index decreased to 8.7 years as of December 31,
2020, compared with 9.6 years as of December 31, 2019. Please refer to Reserves
in Part I, Items 1 and 2 of this report for additional discussion. The
standardized measure of discounted future net cash flows was $2.7 billion as of
December 31, 2020, compared with $4.1 billion as of December 31, 2019, which was
a decrease of 35 percent year-over-year. Please refer to Supplemental Oil and
Gas Information (unaudited) in Part II, Item 8 of this report for additional
discussion.
Operational Activities. The performance of the RockStar area of our Midland
Basin position continues to exceed our pre-acquisition expectations and was key
to driving significant growth in our operating margin and cash flows from
operations in 2020 due to the high percentage of oil that wells in this area
produce. Our operational execution and development strategy in this area have
resulted in strong well performance due to enhanced completion designs and our
ability to drill long laterals given the increasingly contiguous nature of our
acreage position as a result of successful infill leasing and acreage trades.
Efficiency and optimization in completions and operations continued in 2020. A
large portion of our water transportation and disposal needs continue to be
satisfied by the water facilities we operate in a core area of our RockStar
acreage, and strong partnerships with our key service providers allowed us to
maintain continuity of operations during the lower commodity price environment
and the Pandemic.
Our Midland Basin program averaged four drilling rigs and two completion crews
during 2020. We completed 80 gross (73 net) operated wells during 2020 and
increased production volumes year-over-year by 11 percent to 29.1 MMBOE, 73
percent of which
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was oil production. 80 percent of our total 2020 costs incurred related to our
Midland Basin program. Drilling and completion activities within our RockStar
and Sweetie Peck positions in the Midland Basin continue to focus primarily on
delineating and developing the Spraberry and Wolfcamp formations.
Our South Texas program averaged one drilling rig and operated one completion
crew at times during 2020. We completed 4 gross (4 net) wells during 2020. Total
production for 2020 was 17.3 MMBOE, a 21 percent decrease from 2019. 13 percent
of our total 2020 costs incurred related to our South Texas program. Drilling
and completion activities in South Texas during 2020 primarily focused on
delineating and developing the Austin Chalk formation.
The table below provides a summary of changes in our drilled but not completed
well count and current year drilling and completion activity in our operated
programs for the year ended December 31, 2020:
                                         Midland Basin                South Texas                  Total
                                     Gross             Net       Gross             Net       Gross         Net
Wells drilled but not completed at
December 31, 2019                     51                48        21               21         72           69
Wells drilled                         95                84        14               14        109           98
Wells completed                      (80)              (73)       (4)              (4)       (84)         (77)

Other (1)                              -                (1)        -               (3)         -           (4)
Wells drilled but not completed at
December 31, 2020 (2)                 66                58        31               28         97           86

____________________________________________


(1)  Includes adjustments related to normal business activities, including
working interest changes for existing drilled but not completed wells. Working
interest changes can result from divestitures, joint development agreements,
farmouts, and other activities.
(2)  The South Texas drilled but not completed well count as of December 31,
2020, includes 13 gross (13 net) wells that are not included in our five-year
development plan, 12 of which are in the Eagle Ford shale.
Costs Incurred. Costs incurred in oil and gas property acquisition, exploration,
and development activities, whether capitalized or expensed, are summarized as
follows:
                                                       For the Year Ended
                                                        December 31, 2020
                                                          (in millions)
Development costs                                     $             490.9
Exploration costs                                                    77.9
Acquisitions
Proved properties                                                     5.6
Unproved properties                                                  10.9
Total, including asset retirement obligations (1)     $             585.3

____________________________________________


Note: Total may not calculate due to rounding.
(1)  Please refer to the caption Costs Incurred in Supplemental Oil and Gas
Information (unaudited) in Part II, Item 8 of this report.
The majority of our development and exploration costs were incurred in our
Midland Basin and South Texas programs for the year ended December 31, 2020. Of
these costs, $454.5 million was incurred in the development of our Midland Basin
assets, which resulted in 84 net wells drilled and 73 net wells completed, while
$75.0 million was incurred in the development of our South Texas assets, which
resulted in 14 net wells drilled and 4 net wells completed. Costs incurred for
acquisitions during the year related to transactions in the Midland Basin, as
well as payments made to extend certain lease terms and to acquire new leases.
Please refer to Operational Activities above and Acquisition Activity below for
additional information.
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Production Results. The table below presents the disaggregation of our
production by product type for each of our programs for the year ended
December 31, 2020:
                                     Midland Basin      South Texas       Total
Production:
Oil (MMBbl)                                 21.3              1.7         23.0
Gas (Bcf)                                   46.6             57.3        103.9
NGLs (MMBbl)                                   -              6.1          6.1
Equivalent (MMBOE)                          29.1             17.3         46.4
Avg. daily equivalents (MBOE/d)             79.5             47.4        126.9
Relative percentage                           63  %            37  %       100  %

____________________________________________


Note: Amounts may not calculate due to rounding.
Production decreased four percent for the year ended December 31, 2020, compared
with 2019. This decrease was primarily driven by a 21 percent decrease in
production volumes from our South Texas assets, partially offset by an 11
percent increase in production volumes from our Midland Basin assets for the
year ended December 31, 2020, compared with 2019. Please refer to A Year-to-Year
Overview of Selected Production and Financial Information, Including Trends and
Comparison of Financial Results and Trends Between 2020 and 2019 and Between
2019 and 2018 below for additional discussion on production.
Acquisition Activity. During 2020, we completed a non-monetary acreage trade of
primarily undeveloped properties located in Upton County, Texas, as well as
acreage acquisitions in Martin County, Texas, in order to continue maximizing
our operational efficiencies in our Midland Basin program. Please refer to Note
3 - Acquisitions, Divestitures, and Assets Held for Sale in Part II, Item 8 of
this report for additional discussion.
Oil, Gas, and NGL Prices
Our financial condition and the results of our operations are significantly
affected by the prices we receive for our oil, gas, and NGL production, which
can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices
below, the disclosed price represents the average price for the respective
period, before the effects of derivative settlements, unless otherwise
indicated. While quoted NYMEX oil and gas and OPIS NGL prices are generally used
as a basis for comparison within our industry, the prices we receive are
affected by quality, energy content, location and transportation differentials,
and contracted pricing benchmarks for these products.
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The following table summarizes commodity price data, as well as the effects of
derivative settlements, for the years ended December 31, 2020, 2019, and 2018:
                                                         For the Years Ended December 31,
                                                          2020              2019         2018
Oil (per Bbl):
Average NYMEX contract monthly price               $      39.40           $ 57.03      $ 64.77
Realized price, before the effect of derivative
settlements                                        $      37.08           $ 54.10      $ 56.80
Effect of oil derivative settlements               $      14.40           $

(0.90) $ (3.67)

Gas:


Average NYMEX monthly settle price (per MMBtu)     $       2.08           $  2.63      $  3.09
Realized price, before the effect of derivative
settlements (per Mcf)                              $       1.80           $  2.39      $  3.43
Effect of gas derivative settlements (per Mcf)     $       0.11           $  0.21      $ (0.12)

NGLs (per Bbl):
Average OPIS price (1)                             $      17.96           $ 22.34      $ 32.96
Realized price, before the effect of derivative
settlements                                        $      13.96           $ 17.26      $ 27.22
Effect of NGL derivative settlements               $       1.28           $

4.43 $ (6.78)

____________________________________________


(1)  Average OPIS prices per barrel of NGL, historical or strip, assumes a
composite barrel product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11%
Normal Butane, and 14% Natural Gasoline for all periods presented. This product
mix represents the industry standard composite barrel and does not necessarily
represent our product mix for NGL production. Realized prices reflect our actual
product mix.
During 2020, benchmark prices for oil were impacted by the misalignment of
supply and demand caused by the Pandemic and other macroeconomic events. In
addition to supply and demand fundamentals, as a global commodity, the price of
oil is affected by real or perceived geopolitical risks in various regions of
the world as well as the relative strength of the United States dollar compared
to other currencies. We expect future benchmark prices for oil, gas, and NGLs to
remain volatile for the foreseeable future. Our realized prices at local sales
points may also be affected by infrastructure capacity in the area of our
operations and beyond.
The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX
Henry Hub gas, and OPIS NGLs as of February 4, 2021, and December 31, 2020:
                                   As of February 4, 2021        As of December 31, 2020
NYMEX WTI oil (per Bbl)          $                  54.27      $

48.36


NYMEX Henry Hub gas (per MMBtu)  $                   3.03      $                    2.65
OPIS NGLs (per Bbl)              $                  26.27      $                   22.99


We use financial derivative instruments as part of our financial risk management
program. We have a financial risk management policy governing our use of
derivatives, and decisions regarding entering into commodity derivative
contracts are overseen by a financial risk management committee consisting of
senior executive officers and finance personnel. The amount of our production
covered by derivatives is driven by the amount of debt on our balance sheet, the
level of capital commitments and long-term obligations we have in place, and our
ability to enter into favorable commodity derivative contracts. With our current
commodity derivative contracts, we believe we have partially reduced our
exposure to volatility in commodity prices and basis differentials in the near
term. Our use of costless collars for a portion of our derivatives allows us to
participate in some of the upward movements in oil and gas prices while also
setting a price floor for a portion of our oil and gas production. Please refer
to Note 10 - Derivative Financial Instruments in Part II, Item 8 of this report
and to Commodity Price Risk in Overview of Liquidity and Capital Resources below
for additional information regarding our oil, gas, and NGL derivatives.
Outlook
Our total 2021 capital program is budgeted between $650.0 million and $675.0
million, which we expect to fund with cash flows from operations. We expect to
focus our 2021 capital program on highly economic oil development projects in
both our Midland Basin assets and our South Texas assets. In South Texas, we
intend to primarily target the Austin Chalk formation. None of these assets are
located on federal lands, and therefore our operations will not be impacted by
the recent suspension of the issuance of federal drilling permits.
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Financial Results of Operations and Additional Comparative Data
The tables below provide information regarding selected production and financial
information for the three months ended December 31, 2020, and the preceding
three quarters.
                                                         For the Three Months Ended
                                       December 31,       September 30,       June 30,      March 31,
                                           2020                2020             2020          2020
                                                               (in millions)
Production (MMBOE)                             11.3                11.6          11.2           12.4

Oil, gas, and NGL production revenue $ 320.2 $ 282.0

  $  169.8      $   354.2
Oil, gas, and NGL production expense  $        96.0      $         95.3      $   80.4      $   119.6
Depletion, depreciation,
amortization, and asset retirement
obligation liability accretion        $       188.9      $        181.7      $  180.9      $   233.5
Exploration                           $        11.3      $          8.5      $    9.8      $    11.3
General and administrative            $        20.0      $         24.5      $   27.2      $    27.4
Net loss                              $      (165.2)     $        (98.3)     $  (89.3)     $  (411.9)

____________________________________________


Note: Amounts may not calculate due to rounding.
Selected Performance Metrics
                                                           For the Three Months Ended
                                          December 31,      September 30,      June 30,      March 31,
                                              2020              2020             2020          2020
Average net daily equivalent production
(MBOE per day)                                 122.4              126.3         122.9          135.9
Lease operating expense (per BOE)        $      4.10       $       3.65       $  3.30       $   4.75
Transportation costs (per BOE)           $      2.89       $       3.11       $  3.12       $   3.11
Production taxes as a percent of oil,
gas, and NGL production revenue                  4.0  %             4.3  %        3.7  %         4.2  %
Ad valorem tax expense (per BOE)         $      0.38       $       0.40       $  0.22       $   0.60
Depletion, depreciation, amortization,
and asset retirement obligation
liability accretion (per BOE)            $     16.77       $      15.64       $ 16.17       $  18.88
General and administrative (per BOE)     $      1.78       $       2.10

$ 2.43 $ 2.22

____________________________________________

Note: Amounts may not calculate due to rounding.


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A Year-to-Year Overview of Selected Production and Financial Information,
Including Trends
                                    For the Years Ended                   Amount Change Between           Percent Change Between
                                       December 31,
                            2020           2019           2018          2020/2019        2019/2018       2020/2019      2019/2018
Net production volumes:
(1)
Oil (MMBbl)                   23.0           21.9           18.8               1.1             3.1             5  %          17  %
Gas (Bcf)                    103.9          109.8          103.2              (5.9)            6.6            (5) %           6  %
NGLs (MMBbl)                   6.1            8.1            7.9              (2.0)            0.2           (25) %           2  %
Equivalent (MMBOE)            46.4           48.3           43.9              (1.9)            4.4            (4) %          10  %
Average net daily
production: (1)
Oil (MBbl per day)            62.9           59.9           51.4               3.0             8.5             5  %          17  %
Gas (MMcf per day)           283.9          300.8          282.7             (17.0)           18.1            (6) %           6  %
NGLs (MBbl per day)           16.7           22.2           21.8              (5.6)            0.5           (25) %           2  %
Equivalent (MBOE per
day)                         126.9          132.3          120.3              (5.4)           12.0            (4) %          10  %
Oil, gas, and NGL production revenue
(in millions): (1)
Oil production revenue   $   853.6      $ 1,183.2      $ 1,065.7      $     (329.6)     $    117.5           (28) %          11  %
Gas production revenue       187.5          262.5          354.5             (75.1)          (91.9)          (29) %         (26) %
NGL production revenue        85.2          140.0          216.2             (54.8)          (76.2)          (39) %         (35) %
Total oil, gas, and NGL
production revenue       $ 1,126.2      $ 1,585.8      $ 1,636.4      $     (459.6)     $    (50.6)          (29) %          (3) %
Oil, gas, and NGL production expense
(in millions): (1)
Lease operating expense  $   184.2      $   225.5      $   208.1      $      (41.3)     $     17.4           (18) %           8  %
Transportation costs         142.0          187.1          191.5             (45.1)           (4.4)          (24) %          (2) %
Production taxes              46.1           65.0           66.9             (18.9)           (1.9)          (29) %          (3) %
Ad valorem tax expense        18.9           23.1           20.9              (4.2)            2.2           (18) %          10  %
Total oil, gas, and NGL
production expense       $   391.2      $   500.7      $   487.4      $     (109.5)     $     13.3           (22) %           3  %
Realized price, before the effect of derivative
settlements:
Oil (per Bbl)            $   37.08      $   54.10      $   56.80      $     (17.02)     $    (2.70)          (31) %          (5) %
Gas (per Mcf)            $    1.80      $    2.39      $    3.43      $      (0.59)     $    (1.04)          (25) %         (30) %
NGLs (per Bbl)           $   13.96      $   17.26      $   27.22      $      (3.30)     $    (9.96)          (19) %         (37) %
Per BOE                  $   24.26      $   32.84      $   37.27      $      (8.58)     $    (4.43)          (26) %         (12) %
Per BOE data: (1)
Production costs:
Lease operating expense  $    3.97      $    4.67      $    4.74      $      (0.70)     $    (0.07)          (15) %          (1) %
Transportation costs          3.06           3.88           4.36             (0.82)          (0.48)          (21) %         (11) %
Production taxes              0.99           1.35           1.52             (0.36)          (0.17)          (27) %         (11) %
Ad valorem tax expense        0.41           0.48           0.48             (0.07)              -           (15) %           -  %
Total production costs   $    8.43      $   10.38      $   11.10      $      (1.95)     $    (0.72)          (19) %          (6) %
Depletion, depreciation,
amortization, and asset
retirement obligation
liability accretion      $   16.91      $   17.06      $   15.15      $      (0.15)     $     1.91            (1) %          13  %
General and
administrative           $    2.14      $    2.75      $    2.65      $      (0.61)     $     0.10           (22) %           4  %
Derivative settlement
gain (loss) (2)          $    7.57      $    0.81      $   (3.09)     $       6.76      $     3.90           835  %         126  %
Earnings per share
information:
Basic weighted-average
common shares
outstanding (in
thousands)                 113,730        112,544        111,912             1,186             632             1  %           1  %
Diluted weighted-average
common shares
outstanding (in
thousands)                 113,730        112,544        113,502             1,186            (958)            1  %          (1) %
Basic net income (loss)
per common share         $   (6.72)     $   (1.66)     $    4.54      $      (5.06)     $    (6.20)         (305) %        (137) %
Diluted net income
(loss) per common share  $   (6.72)     $   (1.66)     $    4.48      $      (5.06)     $    (6.14)         (305) %        (137) %

____________________________________________


(1)  Amounts and percentage changes may not calculate due to rounding.
(2)  Derivative settlements for the years ended December 31, 2020, 2019, and
2018, are included within the net derivative (gain) loss line item in the
accompanying consolidated statements of operations ("accompanying statements of
operations").
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Average net daily equivalent production for the year ended December 31, 2020,
decreased four percent compared with 2019, as a result of proactive measures
taken to respond to the lower commodity price environment experienced in 2020
compared with 2019. This included voluntary production curtailments and less
costs incurred as a result of intentionally reducing the number of new wells
completed and brought on production. The decrease in average net daily
equivalent production volumes was primarily driven by a 21 percent decrease in
daily production volumes from our South Texas assets, partially offset by a 10
percent increase in daily production volumes from our Midland Basin assets. We
expect both total production volumes and oil volumes as a percentage of our
total production mix to increase in 2021 compared with 2020. Please refer to
Comparison of Financial Results and Trends Between 2020 and 2019 and Between
2019 and 2018 below for additional discussion.
We present certain information on a per BOE basis in order to evaluate our
performance relative to our peers and to identify and measure trends we believe
may require additional analysis and discussion.
Our realized price before the effect of derivative settlements on a per BOE
basis decreased $8.58 per BOE for the year ended December 31, 2020, compared
with 2019, primarily driven by lower benchmark commodity prices for oil, gas,
and NGLs resulting from the Pandemic and other macroeconomic events. Regional
pricing differentials in the Midland Basin negatively affected our realized
prices in 2020 and 2019. The negative impacts on revenue associated with the
decrease in our realized price before the effect of derivative settlements on a
per BOE basis was partially offset by an increase in the gain we recognized on
the settlement of our derivative contracts of $6.76 per BOE for the year ended
December 31, 2020, compared with 2019. Benchmark commodity prices improved
toward the end of 2020 and into early 2021, however, negative impacts on our
realized pricing resulting from the Pandemic and associated macroeconomic events
could occur during 2021.
Lease operating expense ("LOE") on a per BOE basis decreased 15 percent for the
year ended December 31, 2020, compared with 2019. This decrease was primarily
driven by reduced costs, reduced workover activity, and increased operational
efficiencies during 2020. For 2021, we expect LOE on a per BOE basis to be
relatively flat, compared with 2020, as we expect the benefit received from our
cost reduction efforts and operational efficiencies to be offset by the expected
increase in oil volumes as a percentage of our 2021 total production mix.
Transportation costs on a per BOE basis decreased 21 percent for the year ended
December 31, 2020, compared with 2019. This decrease was driven by a 21 percent
reduction in production volumes from our South Texas assets, which incur the
majority of our transportation costs, for the year ended December 31, 2020,
compared with 2019. We expect total transportation costs to fluctuate relative
to changes in production from our South Texas assets. On a per BOE basis, we
expect transportation costs to decrease in 2021, compared with 2020, as
production from our Midland Basin assets, which is sold at or near the wellhead
and incurs minimal transportation costs, continues to become a larger portion of
our total production. Further, we anticipate natural declines in production from
our Eagle Ford shale wells in South Texas, which incur higher transportation
costs on a per BOE basis, and we intend to focus on new wells with higher
liquids content in the Austin Chalk, which have lower transportation costs on a
per BOE basis. In addition, we expect to benefit from certain transportation
contract cost reductions which are expected to further reduce our transportation
expense per BOE in 2021.
Production taxes on a per BOE basis for the year ended December 31, 2020,
decreased 27 percent compared with 2019, primarily driven by a decrease in
realized prices. Our overall production tax rate for both of the years ended
December 31, 2020, and 2019, was 4.1 percent. We expect our total production tax
expense to increase in 2021, compared with 2020, as we expect oil, gas, and NGL
production revenue to increase due to higher expected pricing based on 12-month
strip prices as of February 4, 2021, and increased volumes. We generally expect
production tax expense to correlate with oil, gas, and NGL production revenue on
an absolute and per BOE basis. Product mix, the location of production, and
incentives to encourage oil and gas development can also impact the amount of
production tax we recognize.
Ad valorem tax expense on a per BOE basis decreased 15 percent for the year
ended December 31, 2020, compared with 2019, primarily due to changes in the
assessed values of our producing properties recognized by respective tax
authorities in 2020. We anticipate volatility in ad valorem tax expense on a per
BOE and absolute basis as the valuation of our producing properties change.
Depletion, depreciation, amortization, and asset retirement obligation liability
accretion ("DD&A") expense on a per BOE basis remained relatively flat for the
year ended December 31, 2020, compared with 2019. During 2020, decreases in DD&A
expense, which were driven by the reduction in the depletable cost basis of our
South Texas proved oil and gas properties as a result of proved property
impairments recognized during the first quarter of 2020, were partially offset
by higher production volumes from our oil producing Midland Basin assets as
these assets have higher depletion rates than our primarily gas and NGL
producing South Texas assets. Our DD&A rate fluctuates as a result of
impairments, divestiture activity, carrying cost funding and sharing
arrangements with third parties, changes in our production mix, and changes in
our total estimated proved reserve volumes. In general, we expect the DD&A rate
for 2021 to be relatively flat compared with 2020 and DD&A expense on an
absolute basis to be higher compared with 2020, primarily as a result of
anticipated higher production volumes.
General and administrative ("G&A") expense on a per BOE basis for the year ended
December 31, 2020, decreased 22 percent, compared with 2019. This decrease was
primarily due to reduced overhead costs resulting from the reorganization of
certain functions in the fourth quarter of 2019 that eliminated duplicative
regional operational functions, as well as actions taken to reduce costs
                                       45
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as a result of the Pandemic. For 2021, we expect G&A expense to remain
relatively flat on an absolute basis and to decrease on a per BOE basis,
compared with 2020.
Please refer to Comparison of Financial Results and Trends Between 2020 and 2019
and Between 2019 and 2018 for additional discussion of operating expenses.
Please refer to Note 9 - Earnings Per Share in Part II, Item 8 of this report
for additional discussion on the types of shares included in our basic and
diluted net income (loss) per common share calculations. We recorded a net loss
for each of the years ended December 31, 2020, and 2019. Consequently, all
potentially dilutive shares were anti-dilutive and were excluded from the
calculation of diluted net loss per common share for the years ended
December 31, 2020, and 2019. For the year ended December 31, 2018, we recorded
net income and thus, considered dilutive shares in the calculation of diluted
net income per common share.
Comparison of Financial Results and Trends Between 2020 and 2019 and Between
2019 and 2018
Please refer to Comparison of Financial Results and Trends Between 2019 and 2018
and Between 2018 and 2017 in Management's Discussion and Analysis of Financial
Condition and Results of Operations in Part II, Item 7 of our 2019 Annual Report
on Form 10-K, filed with the SEC on February 20, 2020, for a detailed discussion
of certain comparisons of our financial results and trends for the year ended
December 31, 2019, compared with the year ended December 31, 2018.
Net equivalent production, production revenue, and production expense
The following table presents the changes in our net equivalent production,
production revenue, and production expense, by area, between the years ended
December 31, 2020, and 2019:
                  Net Equivalent Production       Production Revenue        Production Expense
                     Increase (Decrease)               Decrease                  Decrease
                        (MBOE per day)              (in millions)             (in millions)
Midland Basin                  7.5              $             (316.2)     $              (34.1)
South Texas                  (12.9)                           (143.4)                    (75.4)
Total                         (5.4)             $             (459.6)     $             (109.5)

____________________________________________


Note: Amounts may not calculate due to rounding.
Average net daily equivalent production volumes for the year ended December 31,
2020, decreased four percent compared with 2019. Realized prices before the
effects of derivative settlements for oil, gas, and NGLs decreased 31 percent,
25 percent, and 19 percent, respectively, for the year ended December 31, 2020,
compared with 2019. As a result of the decreases in production and pricing, oil,
gas, and NGL production revenue decreased 29 percent for the year ended
December 31, 2020, compared with 2019. Total production expense for the year
ended December 31, 2020, decreased 22 percent, compared with 2019. Please refer
to A Year-to-Year Overview of Selected Production and Financial Information,
Including Trends for additional discussion of the components of production
expense.
The following table presents the changes in our net equivalent production,
production revenue, and production expense, by area, between the years ended
December 31, 2019, and 2018:
                        Net Equivalent
                     Production Increase       Production Revenue          Production Expense
                          (Decrease)           Increase (Decrease)        Increase (Decrease)
                        (MBOE per day)            (in millions)              (in millions)
Midland Basin                14.6            $               131.1      $                 31.5
South Texas                   0.4                           (124.5)                        5.2
Rocky Mountain (1)           (3.1)                           (57.2)                      (23.3)
Total                        12.0            $               (50.6)     $                 13.3

____________________________________________


Note: Amounts may not calculate due to rounding.
(1)  We divested all remaining producing assets in the Rocky Mountain region in
the first half of 2018. As a result, there have been no production volumes from
this region after the second quarter of 2018.
Average net daily equivalent production volumes for the year ended December 31,
2019, increased 10 percent compared with 2018, primarily as a result of
increased production from our Midland Basin assets. As a result of increased
Midland Basin production, oil production as a percentage of our overall product
mix increased from 43 percent in 2018, to 45 percent in 2019. Oil, gas, and NGL
production revenues decreased three percent for the year ended December 31,
2019, compared with 2018, as a result of lower
                                       46
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commodity pricing and the divestiture in the first half of 2018 of our remaining
producing assets in the Rocky Mountain region. Total production expense for the
year ended December 31, 2019, increased three percent compared with 2018, due to
increased LOE and ad valorem tax expense, partially offset by decreased
production taxes and transportation costs. Production expense on a per BOE basis
decreased six percent for the year ended December 31, 2019, compared with 2018,
primarily due to increased production volumes, decreased transportation costs,
and decreased production taxes resulting from lower oil, gas, and NGL production
revenues.
Net gain on divestiture activity
                                             For the Years Ended December 31,
                                               2020                 2019        2018
                                                       (in millions)
Net gain on divestiture activity    $      0.1                     $ 0.9

$ 426.9




No material divestitures occurred during 2020 or 2019. For the year ended
December 31, 2018, we recorded a total net gain of $410.6 million for the
divestiture of our Powder River Basin assets (the "PRB Divestiture"), and a
combined total net gain of $15.4 million for the completed divestitures of our
remaining assets in the Williston Basin located in Divide County, North Dakota
(the "Divide County Divestiture") and our Halff East assets in the Midland Basin
(the "Halff East Divestiture"). Please refer to Note 3 - Acquisitions,
Divestitures, and Assets Held for Sale in Part II, Item 8 of this report for
additional discussion.
Depletion, depreciation, amortization, and asset retirement obligation liability
accretion
                                                         For the Years Ended December 31,
                                                          2020             2019         2018
                                                                  (in millions)

Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 785.0 $ 823.8 $ 665.3




DD&A expense for the year ended December 31, 2020, decreased five percent
compared with 2019. The decrease was primarily driven by the reduction in the
depletable cost basis of our South Texas proved oil and gas properties as a
result of proved property impairments recognized during the first quarter of
2020, partially offset by higher production volumes from our oil producing
Midland Basin assets as these assets have higher depletion rates than our
primarily gas and NGL producing South Texas assets. DD&A expense for the year
ended December 31, 2019, increased 24 percent compared with 2018, primarily
driven by a 25 percent increase in production volumes from our Midland Basin
assets during the same period. Please refer to A Year-to-Year Overview of
Selected Production and Financial Information, Including Trends above for
discussion of DD&A expense on a per BOE basis.
Exploration
                                                For the Years Ended December 31,
                                                  2020                  2019        2018
                                                          (in millions)
Geological and geophysical expenses    $       4.3                    $  2.9      $  5.6
Exploratory dry hole                             -                       4.8           -
Overhead and other expenses                   36.7                      43.8        49.6
Total                                  $      41.0                    $ 51.5      $ 55.2


Exploration expense decreased 20 percent for the year ended December 31, 2020,
compared with 2019. The decrease for the year ended December 31, 2020, was
primarily driven by the reorganization of certain functions in the fourth
quarter of 2019 that eliminated duplicative regional operational functions and
reduced overhead costs. Exploration expense is impacted by actual geological and
geophysical studies we perform and the potential for exploratory dry hole
expense.
                                       47
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Impairment
                                                          For the Years Ended December 31,
                                                            2020               2019        2018
                                                                   (in millions)
Impairment of proved oil and gas properties and
related support equipment                          $         956.7           $    -      $    -
Abandonment and impairment of unproved properties             59.3             33.8        49.9
Total                                              $       1,016.0           $ 33.8      $ 49.9


As a result of the decrease in commodity price forecasts at the end of the first
quarter of 2020, specifically decreases in oil and NGL prices, we recorded
impairment expense related to our South Texas proved oil and gas properties and
related support facilities. There were no proved oil and gas property
impairments recorded in 2019, and 2018. Unproved property abandonments and
impairments recorded during the years ended December 31, 2020, 2019, and 2018,
related to actual and anticipated lease expirations, as well as actual and
anticipated losses of acreage due to title defects, changes in development
plans, and other inherent acreage risks.
We expect proved property impairments to occur more frequently in periods of
declining or depressed commodity prices, and that the frequency of unproved
property abandonments and impairments will fluctuate with the timing of lease
expirations or title defects, and changing economics associated with decreases
in commodity prices. Additionally, changes in drilling plans, unsuccessful
exploration activities, and downward engineering revisions may result in proved
and unproved property impairments.
Reserve estimates and related impairments of proved and unproved properties are
difficult to predict in a volatile price environment. If commodity prices for
the products we produce decline as a result of supply and demand fundamentals
associated with the Pandemic or other macroeconomic events, we may experience
additional proved and unproved property impairments in the future. Future
impairments of proved and unproved properties are difficult to predict; however,
based on our commodity price assumptions as of February 4, 2021, we do not
expect any material oil and gas property impairments in the first quarter of
2021 resulting from commodity price impacts.
Please refer to Critical Accounting Policies and Estimates below for additional
discussion.
General and administrative
                                       For the Years Ended December 31,
                                        2020                2019         2018
                                                (in millions)
General and administrative    $     99.2                  $ 132.8      $ 116.5


G&A expense decreased 25 percent for the year ended December 31, 2020, compared
with 2019. Please refer to A Year-to-Year Overview of Selected Production and
Financial Information, Including Trends above for discussion of G&A expense.
Net derivative (gain) loss
                                       For the Years Ended December 31,
                                        2020                 2019         2018
                                                 (in millions)
Net derivative (gain) loss    $      (161.6)               $ 97.5      $ (161.8)


We recognized a net derivative gain of $161.6 million for the year ended
December 31, 2020. The gain was primarily driven by gains on the settlement of
derivative contracts of $351.3 million offset by $189.7 million in downward
mark-to-market adjustments due to the strengthening of commodity prices towards
the end of 2020.
We recognized a net derivative loss of $97.5 million for the year ended
December 31, 2019. The loss was primarily driven by $136.7 million in downward
mark-to-market adjustments offset by gains on the settlement of derivative
contracts of $39.2 million.
We recognized a net derivative gain of $161.8 million for the year ended
December 31, 2018. The gain was primarily driven by upward mark-to market
adjustments of $297.6 million offset by losses on the settlement of derivative
contracts of $135.8 million.
Please refer to Note 10 - Derivative Financial Instruments in Part II, Item 8 of
this report for additional discussion.
                                       48
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Interest expense
                              For the Years Ended December 31,
                              2020                2019          2018
                                       (in millions)
Interest expense     $     (163.9)             $ (159.1)     $ (160.9)


Interest expense increased three percent for the year ended December 31, 2020,
compared with 2019, primarily due to an increase in interest expense associated
with borrowings under our revolving credit facility and a decrease in interest
expense capitalized to wells. We expect interest expense related to our Senior
Notes to be relatively flat in 2021 compared with 2020 as the increase related
to the higher interest rate on the 2025 Senior Secured Notes will be mostly
offset by the decreased interest associated with the reduction in the aggregate
principal amount of Senior Notes resulting from exchanges and redemptions in
2020. Total interest expense is impacted by, and can vary based on, the timing
and amount of borrowings under our revolving credit facility. Please refer to
Overview of Liquidity and Capital Resources below, and to Note 5 - Long-Term
Debt in Part II, Item 8 of this report for additional discussion, including the
definitions of 2025 Senior Secured Notes and Senior Notes.
Net gain (loss) on extinguishment of debt
                                                     For the Years Ended December 31,
                                                        2020                2019       2018
                                                               (in millions)
Net gain (loss) on extinguishment of debt    $        280.1

$ - $ (26.7)




The Exchange Offers executed during the second quarter of 2020 resulted in a net
gain on extinguishment of debt of $227.3 million, which was primarily comprised
of the gain on the partial principal redemption of Old Notes and the debt
discount associated with the issuance of the 2025 Senior Secured Notes.
Additionally, during the year ended December 31, 2020, we repurchased certain of
our 6.125% Senior Notes due 2022 ("2022 Senior Notes") and 5.0% Senior Notes due
2024 ("2024 Senior Notes") in open market transactions, resulting in a net gain
on extinguishment of debt of $52.8 million, $15.5 million of which was recorded
in the fourth quarter of 2020. Please refer to Note 5 - Long-Term Debt in Part
II, Item 8 of this report for additional discussion, including the definitions
of Exchange Offers and Old Notes.
Income tax (expense) benefit
                                          For the Years Ended December 31,
                                      2020                   2019

2018


                                           (in millions, except tax rate)
Income tax (expense) benefit     $    192.1                $ 44.0       $ (143.4)
Effective tax rate                     20.1   %              19.1  %        22.0  %


The increase in the effective tax benefit rate for the year ended December 31,
2020, compared with 2019, was primarily due to the differing effects of
permanent items on the loss before income taxes for each of the years ended
December 31, 2020, and 2019. The valuation allowance recorded on our deferred
tax assets combined with the effects of excess tax deficiencies from stock-based
compensation awards, limits on expensing of certain covered individuals'
compensation, and other permanent expense items decreased the tax benefit rate
for the year ended December 31, 2020, compared with 2019. This decrease was
partially offset by state permanent items reflecting state planning strategies
which increased the tax benefit rate for the year ended December 31, 2020.
Changes to the Internal Revenue Code ("IRC") could eliminate or reduce certain
oil and gas industry deductions and could increase the overall corporate income
tax rate.
The decrease in the effective tax rate for the year ended December 31, 2019,
compared with 2018, was primarily due to the differing effects of permanent
items on the loss before income taxes for the year ended December 31, 2019,
compared to the impact of these items on income before income taxes for 2018.
Excess tax deficiencies from stock-based compensation awards, limits on
expensing of certain covered individual's compensation, and other permanent
expense items reduced the tax benefit rate for the year ended December 31, 2019.
These same items increased the tax expense rate for the year ended December 31,
2018. The reduction in the tax expense rate also reflects a cumulative effect in
2018 from divestitures, and the impact of a correlative change to our state
apportionment rate.
Please refer to Overview of Liquidity and Capital Resources and Critical
Accounting Policies and Estimates below as well as Note 4 - Income Taxes in
Part II, Item 8 of this report for further discussion.
                                       49
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Overview of Liquidity and Capital Resources
Based on the current commodity price environment, we believe we have sufficient
liquidity and capital resources to execute our business plan while continuing to
meet our current financial obligations in a challenging commodity price
environment. We continue to manage the duration and level of our drilling and
completion service commitments in order to maintain flexibility with regard to
our activity level and capital expenditures, and we have successfully
renegotiated certain contracts allowing us to realize cost savings that directly
support our objective of maximizing cash flows.
Sources of Cash
We expect our 2021 capital program to be funded by cash flows from operations.
Although we expect cash flows from operations to be sufficient to fund our
expected 2021 capital program, we may also use borrowings under our revolving
credit facility or may elect to raise funds through new debt or equity offerings
or from other sources of financing. If we raise additional funds through the
issuance of equity or convertible debt securities, the percentage ownership of
our current stockholders could be diluted, and these newly issued securities may
have rights, preferences, or privileges senior to those of existing stockholders
and bondholders. Additionally, we may enter into carrying cost and sharing
arrangements with third parties for certain exploration or development programs.
All of our sources of liquidity can be affected by the general conditions of the
broader economy, force majeure events, fluctuations in commodity prices,
operating costs, tax law changes and volumes produced, all of which affect us
and our industry.
As a result of the current macroeconomic environment, our credit ratings were
downgraded during 2020 by three major credit rating agencies. These downgrades
and any future downgrades in our credit ratings could make it more difficult or
expensive for us to borrow additional funds.
We have no control over the market prices for oil, gas, or NGLs, although we may
be able to influence the amount of our realized revenues from our oil, gas, and
NGL sales through the use of derivative contracts as part of our commodity price
risk management program. Commodity derivative contracts may limit the prices we
receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise
substantially over the price established by the commodity derivative contract.
Please refer to Note 10 - Derivative Financial Instruments in Part II, Item 8 of
this report for additional information about our oil, gas, and NGL derivative
contracts currently in place and the timing of settlement of those contracts.
Credit Agreement
Our Credit Agreement provides for a senior secured revolving credit facility
with a maximum loan amount of $2.5 billion, and a borrowing base and aggregate
lender commitments of $1.1 billion. The borrowing base under the Credit
Agreement is subject to regular, semi-annual redetermination, and considers the
value of both our (a) proved oil and gas properties reflected in the most recent
reserve report provided to our lenders under the Credit Agreement; and (b)
commodity derivative contracts, each as determined by our lender group. During
the fourth quarter of 2020, we completed the fall semi-annual borrowing base
redetermination with our lenders, and entered into the Fifth Amendment to the
Credit Agreement, which among other items, reaffirmed the borrowing base and
aggregate lender commitments at existing levels and extended the date through
which we may incur Permitted Second Lien Debt, as defined in Note 5 - Long-Term
Debt in Part II, Item 8 of this report. As of December 31, 2020, we had
$380.8 million of Permitted Second Lien Debt capacity available until the next
scheduled redetermination date of April 1, 2021, provided that all principal
amounts of such debt are used to redeem unsecured senior debt of the Company for
less than or equal to 80% of par value. As of December 31, 2020, the remaining
available borrowing capacity under our Credit Agreement provided $965.0 million
in liquidity. Our borrowing base can be adjusted as a result of changes in
commodity prices, acquisitions or divestitures of proved properties, or
financing activities, all as provided for in the Credit Agreement. No individual
bank participating in our Credit Agreement represents more than 10 percent of
the lender commitments under the Credit Agreement. Please refer to Note 5 -
Long-Term Debt in Part II, Item 8 of this report for additional discussion as
well as the presentation of the outstanding balance, total amount of letters of
credit, and available borrowing capacity under our Credit Agreement as of
February 4, 2021, December 31, 2020, and December 31, 2019.
We must comply with certain financial and non-financial covenants under the
terms of the Credit Agreement, including covenants limiting dividend payments
and requiring that we maintain certain financial ratios, as set forth in the
Credit Agreement. We were in compliance with all financial and non-financial
covenants as of December 31, 2020, and through the filing of this report. Please
refer to Note 5 - Long-Term Debt in Part II, Item 8 of this report for
additional discussion.
Our daily weighted-average revolving credit facility debt balance was
approximately $145.6 million and $115.2 million for the years ended December 31,
2020, and 2019, respectively. Cash flows provided by our operating activities,
proceeds received from divestitures of properties, capital markets activities,
including open market debt repurchases, repayment of scheduled debt maturities,
and our capital expenditures, including acquisitions, all impact the amount we
borrow under our revolving credit facility.
Under our Credit Agreement, borrowings in the form of Eurodollar loans accrue
interest based on LIBOR. The use of LIBOR as a global reference rate is expected
to be discontinued after 2021. Our Credit Agreement specifies that if LIBOR is
no longer a widely used benchmark rate, or if it is no longer used for
determining interest rates for loans in the United States, a replacement
interest rate that fairly reflects the cost to the lenders of funding loans
shall be established by the Administrative Agent, as defined in the Credit
Agreement, in consultation with us. We currently do not expect the transition
from LIBOR to have a material impact on interest expense
                                       50
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or borrowing activities under the Credit Agreement, or to otherwise have a
material adverse impact on our business. Please refer to Note 1 - Summary of
Significant Accounting Policies in Part II, Item 8 of this report for discussion
of FASB ASU 2020-04 which provides guidance related to reference rate reform.
Weighted-Average Interest and Weighted-Average Borrowing Rates
Our weighted-average interest rate includes paid and accrued interest, fees on
the unused portion of the aggregate commitment amount under the Credit
Agreement, letter of credit fees, the non-cash amortization of deferred
financing costs, and the non-cash amortization of the discounts related to the
2025 Senior Secured Notes and 2021 Senior Secured Convertible Notes, each as
defined in Note 5 - Long-Term Debt in Part II, Item 8 of this report. Our
weighted-average borrowing rate includes paid and accrued interest only.
The following table presents our weighted-average interest rates and our
weighted-average borrowing rates for the years ended December 31, 2020, 2019,
and 2018:
                                             For the Years Ended December 31,
                                                2020                   2019       2018
Weighted-average interest rate                              7.0  %     6.4  %     6.4  %
Weighted-average borrowing rate                             6.1  %     5.7

% 5.8 %




Our weighted-average interest rates and weighted-average borrowing rates are
impacted by the timing of long-term debt issuances and redemptions and the
average outstanding balance on our revolving credit facility. Additionally, our
weighted-average interest rates are impacted by the fees paid on the unused
portion of our aggregate lender commitments. For the year ended December 31,
2020, our weighted-average interest rate and our weighted-average borrowing rate
increased, compared with 2019, primarily as a result of the higher interest rate
on our 2025 Senior Secured Notes issued during the second quarter of 2020. The
rates disclosed in the above table do not reflect amounts associated with the
early redemption of certain of our Old Notes, such as the acceleration of
unamortized deferred financing costs, as these amounts are netted against the
associated gain or loss on extinguishment of debt. Please refer to Note 5 -
Long-Term Debt in Part II, Item 8 of this report for additional discussion
including the definition of Old Notes.
Uses of Cash
We use cash for the development, exploration, and acquisition of oil and gas
properties and for the payment of operating and general and administrative
costs, income taxes, dividends, and debt obligations, including interest.
Expenditures for the development, exploration, and acquisition of oil and gas
properties are the primary use of our capital resources. During 2020, we spent
approximately $555.7 million on capital expenditures and on acquiring proved and
unproved oil and gas properties. This amount differs from the costs incurred
amount of $585.3 million for the year ended December 31, 2020, as costs incurred
is an accrual-based amount that also includes asset retirement obligations,
geological and geophysical expenses, and exploration overhead amounts. Please
refer to Costs Incurred in Supplemental Oil and Gas Information (unaudited) in
Part II, Item 8 of this report for additional discussion.
The amount and allocation of our future capital expenditures will depend upon a
number of factors, including our cash flows from operating, investing, and
financing activities, our ability to execute our development program, and the
number and size of acquisitions. In addition, the impact of oil, gas, and NGL
prices on investment opportunities, the availability of capital, tax law
changes, and the timing and results of our exploration and development
activities may lead to changes in funding requirements for future development.
We periodically review our capital expenditure budget to assess if changes are
necessary based on current and projected cash flows, acquisition and divestiture
activities, debt requirements, and other factors. The macroeconomic events
discussed throughout this report impacted our capital program in 2020. We are
unable to reasonably estimate the period of time that these market conditions
will exist, the extent of the impact they will have on our business, liquidity,
results of operations, financial condition, or the timing of any subsequent
recovery.
Changes to the IRC could increase the corporate income tax rate and could
eliminate or reduce current tax deductions for intangible drilling costs,
depreciation of equipment costs, and other deductions which currently reduce our
taxable income. Future legislation regarding these issues could reduce our net
cash provided by operating activities over time, and could therefore result in a
reduction of funding available for the items discussed above.
We may from time to time repurchase or redeem all or portions of our outstanding
debt securities for cash, through exchanges for other securities, or a
combination of both. Such repurchases or redemptions may be made in open market
transactions, privately negotiated transactions, or otherwise. Any such
repurchases or redemptions will depend on prevailing market conditions, our
liquidity requirements, contractual restrictions, compliance with securities
laws, and other factors. The amounts involved in any such transaction may be
material. During 2020, we completed the Exchange Offers, as defined in Note 5 -
Long-Term Debt in Part II, Item 8 of this report, and we repurchased certain of
our 2022 Senior Notes and 2024 Senior Notes in open market transactions.
                                       51
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The balance of our revolving credit facility decreased $29.5 million from
$122.5 million at December 31, 2019, to $93.0 million at December 31, 2020,
notwithstanding repurchases of $243.8 million in aggregate principal amount of
our Senior Unsecured Notes, as defined in Note 5 - Long-Term Debt in Part II,
Item 8 of this report, and 2021 Senior Convertible Notes for $190.0 million in
cash during the twelve months ended December 31, 2020.
Please refer to Note 5 - Long-Term Debt and Note 11 - Fair Value Measurements in
Part II, Item 8 of this report for additional discussion. As part of our
strategy for 2021, we will continue to focus on improving our debt metrics,
which may include reducing the amount of our outstanding debt.
As of the filing of this report, we could repurchase up to 3,072,184 shares of
our common stock under our stock repurchase program, subject to the approval of
our Board of Directors. Shares may be repurchased from time to time in the open
market, or in privately negotiated transactions, subject to market conditions
and other factors, including certain provisions of our Credit Agreement, the
indentures governing each series of our outstanding Senior Notes, as defined in
Note 5 - Long-Term Debt in Part II, Item 8 of this report, compliance with
securities laws, and the terms and provisions of our stock repurchase program.
Our Board of Directors periodically reviews this program as part of the
allocation of our capital. During 2020, we did not repurchase any shares of our
common stock, and we currently do not plan to repurchase any outstanding shares
of our common stock during 2021.
During the years ended December 31, 2020, 2019, and 2018, we paid $2.3 million,
$11.3 million, and $11.2 million, respectively, in dividends to our
stockholders. These amounts reflect a dividend of $0.02 per share for the year
ended December 31, 2020, and a dividend of $0.10 per share for each of the years
ended December 31, 2019, and 2018. Our current intention is to continue to make
dividend payments for the foreseeable future, subject to our future earnings,
our financial condition, covenants under our Credit Agreement and indentures
governing each series of our outstanding Senior Notes, other covenants, and
other factors that could arise. The payment and amount of future dividends
remains at the discretion of our Board of Directors.
Analysis of Cash Flow Changes Between 2020 and 2019 and Between 2019 and 2018
The following tables present changes in cash flows between the years ended
December 31, 2020, 2019, and 2018, for our operating, investing, and financing
activities. The analysis following each table should be read in conjunction with
our accompanying consolidated statements of cash flows ("accompanying statements
of cash flows") in Part II, Item 8 of this report.
Operating Activities
                                   For the Years Ended December 31,              Amount Change Between
                                    2020             2019         2018         2020/2019        2019/2018
                                                              (in millions)
Net cash provided by
operating activities          $      790.9         $ 823.6      $ 720.6      $     (32.7)      $    103.0


Net cash provided by operating activities decreased for the year ended
December 31, 2020, compared with the same period in 2019 primarily due to a
$316.9 million decrease in cash received from oil, gas, and NGL production
revenues, net of transportation costs and production taxes, offset by an
increase in cash received from settled derivative trades of $290.7 million. Net
cash provided by operating activities is affected by working capital changes and
the timing of cash receipts and disbursements.
Derivative settlements increased $202.9 million for the year ended December 31,
2019, compared with 2018. This increase was partially offset by decreased cash
received from oil, gas, and NGL production revenues, net of transportation costs
and production taxes of $73.4 million, and increased cash paid for LOE and ad
valorem taxes of $22.0 million for the year ended December 31, 2019, compared
with 2018. Cash paid for interest decreased $8.8 million for the year ended
December 31, 2019, compared with 2018, due to the redemption and repurchase of
certain senior notes in the third quarter of 2018, partially offset by increased
interest paid on our 6.625% Senior Notes due 2027 ("2027 Senior Notes") and
interest paid on revolving credit facility borrowings during the year ended
December 31, 2019.
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Investing Activities
                                 For the Years Ended December 31,               Amount Change Between
                                2020              2019           2018          2020/2019        2019/2018
                                                            (in millions)
Net cash used in investing
activities                 $    (555.6)       $ (1,013.3)     $ (587.9)     $     457.7        $  (425.4)


Net cash used in investing activities decreased for the year ended December 31,
2020, compared with the same period in 2019, primarily due to reduced capital
expenditures of $476.0 million. Net cash used in investing activities during the
year ended December 31, 2020, was funded by net cash provided by operating
activities.
Net cash used in investing activities increased for the year ended December 31,
2019, compared with 2018. Proceeds received from the sale of oil and gas
properties were $735.5 million lower in 2019 than in 2018 as no material
divestitures occurred during 2019. This was partially offset by lower capital
expenditures of $279.4 million and less cash paid to acquire proved and unproved
oil and gas properties of $30.7 million.
Financing Activities
                                   For the Years Ended December 31,              Amount Change Between
                                   2020            2019          2018          2020/2019        2019/2018
                                                              (in millions)

Net cash provided by (used in) financing activities $ (235.4) $ 111.8 $ (368.7) $ (347.2) $ 480.5

During the year ended December 31, 2020, we paid $136.5 million to repurchase
certain of our 2022 Senior Notes and 2024 Senior Notes in open market
transactions, and we paid $53.5 million to certain holders of the 2021 Senior
Convertible Notes in connection with the Private Exchange. Please refer to Note
5 - Long-Term Debt in Part II, Item 8 of this report for additional discussion
and definitions. For the year ended December 31, 2020, we had net repayments to
our revolving credit facility of $29.5 million, compared to net borrowings of
$122.5 million for the year ended December 31, 2019.
During the year ended December 31, 2018, we paid approximately $845.0 million,
including premiums, to redeem or repurchase certain of our senior notes, and we
received net proceeds of $492.1 million upon the issuance of our 2027 Senior
Notes, as defined in Note 5 - Long-Term Debt in Part II, Item 8 of this report.
There were no such debt transactions during 2019. Net borrowings under our
revolving credit facility were $122.5 million for the year ended December 31,
2019, compared with no borrowings on our revolving credit facility during 2018.
Interest Rate Risk
We are exposed to market risk due to the floating interest rate associated with
any outstanding balance on our revolving credit facility. As of December 31,
2020, we had a $93.0 million balance on our revolving credit facility. Our
Credit Agreement allows us to fix the interest rate for all or a portion of the
principal balance of our revolving credit facility for a period up to six
months. To the extent that the interest rate is fixed, interest rate changes
will affect the revolving credit facility's fair value but will not impact
results of operations or cash flows. Conversely, for the portion of the
revolving credit facility that has a floating interest rate, interest rate
changes will not affect the fair value but will impact future results of
operations and cash flows. Changes in interest rates do not impact the amount of
interest we pay on our fixed-rate Senior Unsecured Notes or fixed-rate Senior
Secured Notes but can impact their fair values. As of December 31, 2020, our
outstanding principal amount of fixed-rate debt totaled $2.2 billion and our
floating-rate debt outstanding totaled $93.0 million. Please refer to Note 11 -
Fair Value Measurements in Part II, Item 8 of this report for additional
discussion on the fair values of our Senior Notes.
Commodity Price Risk
The prices we receive for our oil, gas, and NGL production directly impact our
revenue, profitability, access to capital, and future rate of growth. Oil, gas,
and NGL prices are subject to unpredictable fluctuations resulting from a
variety of factors, including changes in supply and demand and the macroeconomic
environment, all of which are typically beyond our control. The markets for oil,
gas, and NGLs have been volatile, especially over the last several years. During
the first half of 2020, oil, gas, and NGL prices weakened to historic lows as a
result of the Pandemic and other macroeconomic events and will likely continue
to be volatile in the future. The realized prices we receive for our production
also depend on numerous factors that are typically beyond our control. Based on
our 2020 production, a 10 percent decrease in our average realized oil, gas, and
NGL prices, before the effects of derivative settlements, would have reduced our
oil, gas, and NGL production revenues by approximately $85.4 million, $18.7
million, and $8.5 million, respectively. If commodity prices had been 10 percent
lower, our net derivative settlements for the year ended December 31, 2020,
would have offset the declines in oil, gas, and NGL production revenue by
approximately $85.2 million.
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We enter into commodity derivative contracts in order to reduce the risk of
fluctuations in commodity prices. The fair value of our commodity derivative
contracts is largely determined by estimates of the forward curves of the
relevant price indices. As of December 31, 2020, a 10 percent increase or
decrease in the forward curves associated with our oil, gas, and NGL commodity
derivative instruments would have changed our net derivative positions for these
products by approximately $135.3 million, $28.0 million, and $7.5 million,
respectively.
Off-Balance Sheet Arrangements
As part of our ongoing business, we have not participated in transactions that
generate relationships with unconsolidated entities or financial partnerships,
such as entities often referred to as structured finance or special purpose
entities ("SPEs"), which would have been established for the purpose of
facilitating off-balance sheet arrangements or other contractually narrow or
limited purposes.
We evaluate our transactions to determine if any variable interest entities
exist. If we determine that we are the primary beneficiary of a variable
interest entity, that entity is consolidated into our consolidated financial
statements. We have not been involved in any unconsolidated SPE transactions
during 2020 or 2019, or through the filing of this report.
Critical Accounting Policies and Estimates
Our discussion of financial condition and results of operations is based upon
the information reported in our consolidated financial statements. The
preparation of these consolidated financial statements in conformity with GAAP
requires us to make assumptions and estimates that affect the reported amounts
of assets, liabilities, revenues, and expenses, as well as the disclosure of
contingent assets and liabilities as of the date of our consolidated financial
statements. We base our assumptions and estimates on historical experience and
various other sources that we believe to be reasonable under the circumstances.
Actual results may differ from the estimates we calculate due to changes in
circumstances, global economics and politics, and general business conditions. A
summary of our significant accounting policies is detailed in Note 1 - Summary
of Significant Accounting Policies in Part II, Item 8 of this report. We have
outlined below, those policies identified as being critical to the understanding
of our business and results of operations and that require the application of
significant management judgment.
Successful Efforts Method of Accounting. GAAP provides two alternative methods
for the oil and gas industry to use in accounting for oil and gas producing
activities. These two methods are generally known in our industry as the full
cost method and the successful efforts method. Both methods are widely used. The
methods are different enough that in many circumstances the same set of facts
will provide materially different financial statement results within a given
year. We have chosen the successful efforts method of accounting for our oil and
gas producing activities. A more detailed description is included in Note 1 -
Summary of Significant Accounting Policies of Part II, Item 8 of this report.
Oil and Gas Reserve Quantities. Our estimated proved reserve quantities and
future net cash flows are critical to understanding the value of our business.
They are used in comparative financial ratios and are the basis for significant
accounting estimates in our consolidated financial statements, including the
calculations of DD&A expense, impairment of proved and unproved oil and gas
properties, and asset retirement obligations. Please refer to Oil and Gas
Producing Activities in Note 1 - Summary of Significant Accounting Policies of
Part II, Item 8 of this report for additional discussion on our accounting
policies impacted by estimated reserve quantities.
Future cash inflows and future production and development costs are determined
by applying prices and costs, including transportation, quality differentials,
and basis differentials, applicable to each period to the estimated quantities
of proved reserves remaining to be produced as of the end of that period.
Expected cash flows are discounted to present value using an appropriate
discount rate. For example, the standardized measure of discounted future net
cash flows calculation requires that a 10 percent discount rate be applied.
Although reserve estimates are inherently imprecise, and estimates of new
discoveries and undeveloped locations are more imprecise than those of
established producing oil and gas properties, we make a considerable effort in
estimating our reserves. We engage Ryder Scott, an independent reservoir
evaluation consulting firm, to audit at least 80 percent of our total calculated
proved reserve PV-10. We expect proved reserve estimates will change as
additional information becomes available and as commodity prices and operating
and capital costs change. We evaluate and estimate our proved reserves each year
end. It should not be assumed that the standardized measure of discounted future
net cash flows (GAAP) or PV-10 (non-GAAP) as of December 31, 2020, is the
current market value of our estimated proved reserves. In accordance with SEC
requirements, we based these measures on the unweighted arithmetic average of
the first-day-of-the-month price of each month within the trailing 12-month
period ended December 31, 2020. Actual future prices and costs may be materially
higher or lower than the prices and costs utilized in the estimates. Please
refer to Risk Factors in Part I, Item 1A of this report.
If the estimates of proved reserves decline, the rate at which we record DD&A
expense will increase, which would reduce future net income. Changes in DD&A
rate calculations caused by changes in reserve quantities are made
prospectively. In addition, a decline in reserve estimates may impact the
outcome of our assessment of proved and unproved properties for impairment.
Impairments are recorded in the period in which they are identified.
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The following table presents information about proved reserve changes from
period to period due to items we do not control, such as price, and from changes
due to production history and well performance. These changes do not require a
capital expenditure on our part, but may have resulted from capital expenditures
we incurred to develop other estimated proved reserves.
For the Years Ended December 31,
2020 2019 2018
MMBOE Change MMBOE Change MMBOE Change
Revisions resulting from
performance 3.6 (14.9) (59.7)
Removal of proved undeveloped
reserves no longer in our
five-year development plan (65.0) (9.8) (22.6)
Revisions resulting from
price changes (32.6) (70.0) 13.5
Total (94.0) (94.7) (68.8)

____________________________________________


Note: Amounts may not calculate due to rounding.
As previously noted, commodity prices are volatile and estimates of reserves are
inherently imprecise. Consequently, we expect to continue experiencing these
types of changes.
We cannot reasonably predict future commodity prices, although we believe that
together, the below analyses provide reasonable information regarding the impact
of changes in pricing and trends on total estimated proved reserves. The
following table reflects the estimated MMBOE change and percentage change to our
total reported estimated proved reserve volumes from the described hypothetical
changes:
                                               For the year ended December 31, 2020
                                                MMBOE Change            Percentage Change
10 percent decrease in SEC pricing (1)                       (9.1)                   (2) %
Average NYMEX strip pricing as of fiscal
year end (2)                                                 13.3                     3  %
10 percent decrease in proved
undeveloped reserves (3)                                    (17.5)

(4) %

____________________________________________


(1)  The change solely reflects the impact of a 10 percent decrease in SEC
pricing to the total reported estimated proved reserve volumes as of
December 31, 2020, and does not include additional impacts to our estimated
proved reserves that may result from our internal intent to drill hurdles or
changes in future service or equipment costs.
(2)  The change solely reflects the impact of replacing SEC pricing with the
five-year average NYMEX strip pricing as of December 31, 2020, and does not
include additional impacts to our estimated proved reserves that may result from
our internal intent to drill hurdles or changes in future service or equipment
costs. As of December 31, 2020, SEC pricing was $39.57 per Bbl for oil, $1.99
per MMBtu for gas, and $17.64 per Bbl for NGLs, and five-year average NYMEX
strip pricing was $46.16 per Bbl for oil, $2.54 per MMBtu for gas, and $20.45
per Bbl for NGLs.
(3)  The change solely reflects a 10 percent decrease in proved undeveloped
reserves as of December 31, 2020, and does not include any additional impacts to
our estimated proved reserves.
Additional reserve information can be found in Reserves in Part I, Items 1 and 2
of this report, and in Supplemental Oil and Gas Information (unaudited) in Part
II, Item 8 of this report.
Impairment of Oil and Gas Properties. Proved oil and gas properties are
evaluated for impairment on a pool-by-pool basis and reduced to fair value when
events or changes in circumstances indicate that their carrying amount may not
be recoverable. We estimate the expected future cash flows of our proved oil and
gas properties and compare these undiscounted cash flows to the carrying amount
to determine if the carrying amount is recoverable. If the carrying amount
exceeds the estimated undiscounted future cash flows, we will write down the
carrying amount of the proved oil and gas properties to fair value (or
discounted future cash flows). Management estimates future cash flows from all
proved reserves and risk adjusted probable and possible reserves using various
factors, which are subject to our judgment and expertise, and include, but are
not limited to, commodity price forecasts, estimated future operating and
capital costs, development plans, and discount rates to incorporate the risk and
current market conditions associated with realizing the expected cash flows.
Unproved oil and gas properties are evaluated for impairment and reduced to fair
value when there is an indication that the carrying costs may not be
recoverable. Lease acquisition costs that are not individually significant are
aggregated by asset group and the portion of such costs estimated to be
nonproductive prior to lease expiration are amortized over the appropriate
period. The estimate of what could be nonproductive is based on historical
trends or other information, including current drilling plans and our intent to
renew leases. We estimate the fair value of unproved properties using a market
approach, which takes into account the following significant assumptions:
remaining lease terms, future development plans, risk weighted potential
resource recovery, estimated reserve
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values, and estimated acreage value based on price(s) received for similar,
recent acreage transactions by us or other market participants.
We cannot predict when or if future impairment charges will be recorded because
of the uncertainty in the factors discussed above. Despite any amount of future
impairment being difficult to predict, based on our commodity price assumptions
as of February 4, 2021, we do not expect any material oil and gas property
impairments in the first quarter of 2021 resulting from commodity price impacts.
Please refer to Note 1 - Summary of Significant Accounting Policies and Note 11
- Fair Value Measurements in Part II, Item 8 of this report for discussion of
impairments of oil and gas properties recorded for the years ended December 31,
2020, 2019, and 2018.
Fair Value of the Debt Exchange Transactions. The Exchange Offers executed in
the second quarter of 2020 required significant judgment in evaluating the
application of the applicable accounting guidance, and significant assumptions
were made in estimating the fair value of the 2025 Senior Secured Notes and
warrants issued. Please refer to Note 5 - Long-Term Debt and Note 11 - Fair
Value Measurements in Part II, Item 8 of this report for additional discussion
and definitions.
Revenue Recognition. Effective January 1, 2018, our revenue recognition policy
was updated to reflect the adoption of new accounting guidance. Our revenue
recognition policy is a critical accounting policy because revenue is a key
component of our results of operations and our forward-looking statements
contained in our analysis of liquidity and capital resources. Our primary source
of revenue is derived by the sale of produced oil, gas, and NGLs. Revenue is
recognized at the point in time when custody and title ("control") of the
product, as defined by contractual terms, transfers to the purchaser. Payment
for these sales is typically received between 30 and 90 days after the date of
production. At the end of each month, we make estimates of the amount of
production delivered to the purchaser and the price we will receive. We use our
knowledge of our properties, contractual arrangements, historical performance,
NYMEX, local spot market, and OPIS prices, and other factors as the basis for
these estimates. Variances between our estimates and the actual amounts received
are recorded in the month payment is received. A 10 percent change in our
revenue accrual at year end 2020 would have impacted total operating revenues by
approximately $10.9 million in 2020. Please refer to Note 2 - Revenue from
Contracts with Customers in Part II, Item 8 of this report for additional
discussion.
Derivative Financial Instruments. We periodically enter into commodity
derivative contracts to manage our exposure to oil, gas, and NGL price
volatility and location differentials. We recognize all gains and losses from
changes in commodity derivative fair values immediately in earnings rather than
deferring any such amounts in accumulated other comprehensive income (loss). The
estimated fair value of our derivative instruments requires substantial
judgment. These values are based upon, among other things, option pricing
models, futures prices, volatility, time to maturity, and credit risk. The
values we report in our consolidated financial statements change as these
estimates are revised to reflect actual results, changes in market conditions or
other factors, many of which are beyond our control. Please refer to Note 1 -
Summary of Significant Accounting Policies and Note 10 - Derivative Financial
Instruments in Part II, Item 8 of this report for additional discussion.
Income Taxes. We account for deferred income taxes, whereby deferred tax assets
and liabilities are recognized based on the tax effects of temporary differences
between the carrying amounts on the consolidated financial statements and the
tax basis of assets and liabilities, as measured using currently enacted tax
rates. These differences will result in taxable income or deductions in future
years when the reported amounts of the assets or liabilities are recovered or
settled, respectively. Considerable judgment is required in predicting when
these events may occur and whether recovery of an asset is more likely than not.
We record deferred tax assets and associated valuation allowances, when
appropriate, to reflect amounts more likely than not to be realized based upon
Company analysis. Additionally, our federal and state income tax returns are
generally not filed before the consolidated financial statements are prepared.
Therefore, we estimate the tax basis of our assets and liabilities at the end of
each period, as well as the effects of tax rate changes, tax credits, and net
operating and capital loss carryforwards and carrybacks. Adjustments related to
differences between the estimates we use and actual amounts we report are
recorded in the periods in which we file our income tax returns. These
adjustments and changes in our estimates of asset recovery and liability
settlement as well as significant enacted tax rate changes could have an impact
on our results of operations. A one percent change in our effective tax rate
would have changed our calculated income tax benefit by approximately $9.6
million for the year ended December 31, 2020. Please refer to Note 1 - Summary
of Significant Accounting Policies and Note 4 - Income Taxes in Part II, Item 8
of this report for additional discussion.
Accounting Matters
Please refer to Recently Issued Accounting Standards in Note 1 - Summary of
Significant Accounting Policies in Part II, Item 8 of this report for
information on new authoritative accounting guidance.
Environmental
We believe we are in substantial compliance with environmental laws and
regulations and do not currently anticipate that material future expenditures
will be required under the existing regulatory framework. However, environmental
laws and regulations are subject to frequent changes, and we are unable to
predict the impact that compliance with future laws or regulations, such as
those currently being considered as discussed below, may have on future capital
expenditures, liquidity, and results of operations.
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Hydraulic Fracturing. Hydraulic fracturing is an important and common practice
that is used to stimulate production of hydrocarbons from tight formations. For
additional information about hydraulic fracturing and related environmental
matters, please refer to Risk Factors - Risks Related to Oil and Gas Operations
and the Industry - Federal and state legislative and regulatory initiatives
relating to hydraulic fracturing could result in increased costs and additional
operating restrictions or delays.
Climate Change. In June 2013, President Obama announced a Climate Action Plan
designed to further reduce GHG emissions and prepare the nation for the physical
effects that may occur as a result of climate change. The Climate Action Plan
targeted methane reductions from the oil and gas sector as part of a
comprehensive interagency methane strategy. As part of the Climate Action Plan,
on May 12, 2016, the EPA issued final regulations that amend and expand 2012
regulations for the oil and gas sector by setting emission limits for VOCs and
methane, a GHG, and added requirements for previously unregulated sources. The
2016 NSPS requires reduction of methane and VOCs from certain activities in oil
and gas production, processing, transmission and storage and applies to
facilities constructed, modified, or reconstructed after September 18, 2015. The
regulation requires, among other things, GHG and VOC emission limits for certain
equipment, such as centrifugal compressors and reciprocating compressors;
semi-annual leak detection and repair for well sites and quarterly boosting and
garnering compressor stations and gas transmission compressor stations; control
requirements and emission limits for pneumatic pumps; and additional
requirements for control of GHGs and VOCs from well completions. On September
14, and 15, 2020, the EPA finalized amendments to the 2012 and 2016 NSPS that
removed transmission and storage infrastructure from regulation of methane
emissions and other VOCs, as well as removed methane control requirements. The
Biden administration has directed the EPA to review and consider revising or
rescinding these 2020 amendments, which could result in reinstatement of the
previously adopted regulations or potentially more stringent requirements. On
November 16, 2016, the BLM finalized regulations to address methane emissions
from oil and gas operations on federal and tribal lands, as part of President
Obama's Climate Action Plan. The regulations were intended to reduce the waste
of gas from flaring, venting, and leaks by oil and gas production. The rule
included requirements that prohibits venting of gas except in limited
circumstances and limits flaring of gas and includes requirements for leak
detection and repair. The rule also increased royalty payments for "waste" gas
that is released in contravention of the rule requirements. After continuous
court challenges, the BLM issued a final rule in September 2018 that rescinded
most of the 2016 rule, including most of the methane control requirements. The
2016 rule was vacated by the District Court for the District of Wyoming. Any
future regulations requiring similar capture standards may increase our
operational costs, or restrict our production, which could materially and
adversely affect our financial condition, results of operations, and cash flows.
In August of 2015, the EPA finalized existing source performance standards as
stringent state emission "goals" for utilities to reduce GHG emissions. The
proposed standards focus on re-dispatching electricity from coal-fired units to
gas combined cycle plants and renewables. In February 2016, however, the Supreme
Court stayed these rules pending judicial review. The Trump EPA proposed a
repeal of the rule based on a new legal interpretation of the EPA's authority.
The Trump EPA also proposed a replacement rule, the Affordable Clean Energy
Rule, in August 2018 and finalized the rule in June 2019. The D.C. Circuit
struck down the Affordable Clean Energy Rule in January 2021.
The United States Congress has from time to time considered adopting legislation
to reduce emissions of GHGs and many of the states have already taken legal
measures to reduce emissions of GHGs primarily through the planned development
of GHG emission inventories and/or regional GHG cap and trade programs. Most of
these cap and trade programs work by requiring major sources of emissions, such
as electric power plants, or major producers of fuels, such as refineries and
gas processing plants, to acquire and surrender emission allowances. The number
of allowances available for purchase is reduced each year in an effort to
achieve the overall GHG emission reduction goal. In addition, there have been
international conventions and efforts to establish standards for the reduction
of GHGs globally, including the Paris accords in December 2015. The conditions
for entry into force of the Paris accords were met on October 5, 2016 and the
Agreement went into force 30 days later on November 4, 2016. On November 4,
2019, President Trump formally notified the United Nations that the United
States would withdraw from the Paris Agreement. The November 4, 2019 formal
notice triggered the start of a year-long withdrawal process. However, President
Biden has signed a document pledging the United States' entry back into the
agreement.
The adoption of legislation or regulatory programs to reduce emissions of GHGs
could require us to incur increased operating costs, such as costs to purchase
and operate emissions control systems, to acquire emissions allowances, or
comply with new regulatory or reporting requirements. Any such legislation or
regulatory programs could also increase the cost of consuming, and thereby
reduce demand for, the oil and gas we produce. Consequently, legislation and
regulatory programs to reduce emissions of GHGs could have an adverse effect on
our business, financial condition, and results of operations. Judicial
challenges to new regulatory measures are likely and we cannot predict the
outcome of such challenges. New regulatory suspensions, revisions, or
rescissions and conflicting state and federal regulatory mandates may inhibit
our ability to accurately forecast the costs associated with future regulatory
compliance. Finally, scientists have concluded that increasing concentrations of
GHGs in the earth's atmosphere produce climate changes that likely have
significant physical effects, such as increased frequency and severity of
storms, droughts, floods, and other climatic events. Such effects could have an
adverse effect on our financial condition and results of operations.
In terms of opportunities, the regulation of GHG emissions and the introduction
of alternative incentives, such as enhanced oil recovery, carbon sequestration,
and low carbon fuel standards, could benefit us in a variety of ways. For
example, although federal regulation and climate change legislation could reduce
the overall demand for the oil and gas that we produce, the relative demand for
gas may increase because the burning of gas produces lower levels of emissions
than other readily available fossil fuels such as oil and coal. In addition, if
renewable resources, such as wind or solar power become more prevalent,
gas-fired electric plants may provide an
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alternative backup to maintain consistent electricity supply. Also, if states
adopt low-carbon fuel standards, gas may become a more attractive transportation
fuel. Approximately 37 percent and 38 percent of our production on a BOE basis
in 2020 and 2019, respectively, was gas. Market-based incentives for the capture
and storage of carbon dioxide in underground reservoirs, particularly in oil and
gas reservoirs, could also benefit us through the potential to obtain GHG
emission allowances or offsets from or government incentives for the
sequestration of carbon dioxide.
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Non-GAAP Financial Measures
Adjusted EBITDAX represents net income (loss) before interest expense, interest
income, income taxes, depletion, depreciation, amortization and asset retirement
obligation liability accretion expense, exploration expense, property
abandonment and impairment expense, non-cash stock-based compensation expense,
derivative gains and losses net of settlements, gains and losses on
divestitures, gains and losses on extinguishment of debt, and certain other
items. Adjusted EBITDAX excludes certain items that we believe affect the
comparability of operating results and can exclude items that are generally
non-recurring in nature or whose timing and/or amount cannot be reasonably
estimated. Adjusted EBITDAX is a non-GAAP measure that we believe provides
useful additional information to investors and analysts, as a performance
measure, for analysis of our ability to internally generate funds for
exploration, development, acquisitions, and to service debt. We are also subject
to financial covenants under our Credit Agreement based on adjusted EBITDAX
ratios as further described in the Credit Agreement section in Overview of
Liquidity and Capital Resources above. In addition, adjusted EBITDAX is widely
used by professional research analysts and others in the valuation, comparison,
and investment recommendations of companies in the oil and gas exploration and
production industry, and many investors use the published research of industry
research analysts in making investment decisions. Adjusted EBITDAX should not be
considered in isolation or as a substitute for net income (loss), income (loss)
from operations, net cash provided by operating activities, or other
profitability or liquidity measures prepared under GAAP. Because adjusted
EBITDAX excludes some, but not all items that affect net income (loss) and may
vary among companies, the adjusted EBITDAX amounts presented may not be
comparable to similar metrics of other companies. Our revolving credit facility
provides a material source of liquidity for us. Under the terms of our Credit
Agreement, if we failed to comply with the covenants that establish a maximum
permitted ratio of total funded debt, as defined in the Credit Agreement, to
adjusted EBITDAX, we would be in default, an event that would prevent us from
borrowing under our revolving credit facility and would therefore materially
limit a significant source of our liquidity. In addition, if we are in default
under our revolving credit facility and are unable to obtain a waiver of that
default from our lenders, lenders under the revolving credit facility and under
the indentures governing each series of our outstanding Senior Notes, as defined
in Note 5 - Long-Term Debt in Part II, Item 8 of this report, would be entitled
to exercise all of their remedies for default.
The following table provides reconciliations of our net income (loss) (GAAP) and
net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP)
for the periods presented:
                                                        For the Years Ended December 31,
                                                      2020               2019           2018
                                                                 (in thousands)
Net income (loss) (GAAP)                        $   (764,614)        $ (187,001)     $ 508,407
Interest expense                                     163,892            159,102        160,906
Income tax expense (benefit)                        (192,091)           (44,043)       143,370
Depletion, depreciation, amortization, and
asset retirement obligation liability accretion      784,987            823,798        665,313
Exploration (1)                                       37,541             46,995         49,627
Impairment                                         1,016,013             33,842         49,889
Stock-based compensation expense                      14,999             24,318         23,908
Net derivative (gain) loss                          (161,576)            97,539       (161,832)
Derivative settlement gain (loss)                    351,261             39,222       (135,803)
Net gain on divestiture activity                         (91)              (862)      (426,917)
(Gain) loss on extinguishment of debt               (280,081)                 -         26,740
Other, net                                             5,165                481         (3,214)
Adjusted EBITDAX (non-GAAP)                          975,405            993,391        900,394
Interest expense                                    (163,892)          (159,102)      (160,906)
Income tax (expense) benefit                         192,091             44,043       (143,370)
Exploration (1)                                      (37,541)           (46,995)       (49,627)
Amortization of debt discount and deferred
financing costs                                       17,704             15,474         15,258
Deferred income taxes                               (192,540)           (41,835)       141,708
Other, net                                           (11,874)             1,739          3,501
Net change in working capital                         11,591             16,852         13,671
Net cash provided by operating activities
(GAAP)                                          $    790,944         $

823,567 $ 720,629

____________________________________________


(1)  Stock-based compensation expense is a component of the exploration expense
and general and administrative expense line items on the accompanying statements
of operations. Therefore, the exploration line items shown in the reconciliation
above will vary from the amount shown on the accompanying statements of
operations for the component of stock-based compensation expense recorded to
exploration expense.
                                       59

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

Latest news about SM Energy Company

KeyBanc Adjusts SM Energy's Price Target to $65 From $62, Maintains Overweight Rating	Apr. 22	MT
Susquehanna Adjusts Price Target on SM Energy to $51 From $42, Maintains Neutral Rating	Apr. 22	MT
Wells Fargo Adjusts SM Energy Price Target to $51 From $45, Maintains Equal Weight Rating	Apr. 18	MT
KeyBanc Adjusts SM Energy Company Price Target to $62 From $51, Maintains Overweight Rating	Apr. 12	MT
JPMorgan Raises Price Target on SM Energy to $54 From $49, Maintains Overweight Rating	Apr. 09	MT
Mizuho Securities Raises SM Energy's Price Target to $57 From $51, Maintains Buy Rating	Apr. 05	MT
SM Energy Keeps Quarterly Dividend at $0.18 a Share, Payable May 3 to Holders of Record April 19	Mar. 26	MT
SM Energy Company Declares Quarterly Cash Dividend, Payable on May 3, 2024	Mar. 26	CI
RBC Boosts Price Target on SM Energy to $50 From $45, Keeps Sector Perform Rating	Mar. 08	MT
Mizuho Adjusts Price Target on SM Energy to $51 From $44, Maintains Buy Rating	Mar. 06	MT
Susquehanna Adjusts Price Target on SM Energy to $42 From $38, Maintains Neutral Rating	Feb. 26	MT
Transcript : SM Energy Company, Q4 2023 Earnings Call, Feb 22, 2024	Feb. 22
Tranche Update on SM Energy Company (NYSE:SM)'s Equity Buyback Plan announced on September 7, 2022.	Feb. 22	CI
SM Energy Expects 'Sustainable' Fixed Annual Dividend of $0.72/Share to Contribute Toward Total Shareholders Return in 2024	Feb. 21	MT
SM Energy Says $214.9 Million Remaining Under Share Buyback Program	Feb. 21	MT
SM Energy Q4 Non-GAAP Earnings Increase, Revenue Declines	Feb. 21	MT
Sm Energy Company Provides Production Guidance for Full Year 2024	Feb. 21	CI
Sm Energy Company Announces Production Results for the Fourth Quarter and Full Year of 2023	Feb. 21	CI
SM Energy Company Reports Earnings Results for the Fourth Quarter Ended December 31, 2023	Feb. 21	CI
SM Energy Company Announces Executive Changes	Feb. 21	CI
Earnings Flash (SM) SM ENERGY COMPANY Reports Q4 EPS $1.56, vs. Street Est of $1.38	Feb. 21	MT
Earnings Flash (SM) SM ENERGY COMPANY Reports Q4 Revenue $608.7M, vs. Street Est of $611.2M	Feb. 21	MT
SM Energy Company Reports Earnings Results for the Full Year Ended December 31, 2023	Feb. 21	CI
Transcript : SM Energy Company, Q4 2023 Pre Recorded Earnings Call, Feb 21, 2024	Feb. 21
SM Energy Company (NYSE:SM) acquired 20,700 acres located in north Martin & Dawson Counties.	Feb. 20	CI

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Company Profile

SM Energy Company s an independent energy company. The Company is engaged in the acquisition, exploration, development, and production of oil, gas, and natural gas liquid (NGL) in the state of Texas. The Companyâs asset portfolio is comprised of assets in the Midland Basin of West Texas and in the Maverick Basin of South Texas. The Companyâs Midland Basin assets are located in the Permian Basin in West Texas is comprised of approximately 110,000 net acres and include its RockStar assets in Howard and Martin Counties, Texas, its Sweetie Peck assets in Upton and Midland Counties, and Klondike assets in Dawson and northern Martin counties (Midland Basin). Its South Texas assets are comprised of approximately 155,000 net acres located in Dimmit and Webb Counties, Texas (South Texas). The Companyâs operations in South Texas are focused on production from the Eagle Ford shale formation and Austin Chalk formation, and further development of the Austin Chalk formation.

Sector

Oil & Gas Exploration and Production

Calendar

2024-05-02 - Q1 2024 Earnings Call - Pre-Recorded

Related indices

Russell 2000

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Ratings for SM Energy Company

Trading Rating

Investor Rating

ESG Refinitiv

B-

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Analysts' Consensus

Sell

Buy

Mean consensus

OUTPERFORM

Number of Analysts

Last Close Price

48.85 USD

Average target price

57.93 USD

Spread / Average Target

+18.58%

Consensus

EPS Revisions

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Quarterly earnings - Rate of surprise

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