CONTINENTAL RESOURCES, INC Management’s Discussion and Analysis of Financial Condition and Results of Operations (Form 10-K)

The following discussion and analysis should be read in conjunction with our
consolidated financial statements and notes included elsewhere in this report.
Results attributable to noncontrolling interests are not material relative to
consolidated results and are not separately presented or discussed below.
The following discussion and analysis includes forward-looking statements and
should be read in conjunction with Part I, Item 1A. Risk Factors in this report,
along with Cautionary Statement for the Purpose of the "Safe Harbor" Provisions
of the Private Securities Litigation Reform Act of 1995 at the beginning of this
report, for information about the risks and uncertainties that could cause our
actual results to be materially different than our forward-looking statements.
Overview
We are an independent crude oil and natural gas company engaged in the
exploration, development, management, and production of crude oil and natural
gas and associated products. Additionally, we pursue the acquisition and
management of perpetually owned minerals located in our key operating areas. We
derive the majority of our operating income and cash flows from the sale of
crude oil and natural gas and expect this to continue in the future. We are the
largest leaseholder and the largest producer in the Bakken field of North Dakota
and Montana. We also have significant positions in the SCOOP and STACK plays in
Oklahoma and recently acquired positions in the Permian Basin of Texas and
Powder River Basin of Wyoming. Our common stock trades on the New York Stock
Exchange under the symbol "CLR" and our corporate internet website is
www.clr.com.
2021 Highlights
Financial and operating highlights for 2021 are summarized below. Our 2021
results underscore our continued focus on maximizing cash flow generation,
maintaining low-cost capital efficient operations in an environmentally
responsible manner, achieving consistent asset performance, and delivering
capital and corporate returns to shareholders.
•Generated $1.25 billion in operating cash flows in the fourth quarter, bringing
year-to-date operating cash flows to a Company record $3.97 billion;
•Completed strategic acquisitions to expand our operations into the Permian
Basin for cash consideration of $3.06 billion and the Powder River Basin for
cash consideration totaling $453 million;
•Sequentially increased our quarterly fixed dividend throughout year, paying
$166 million of dividends in 2021 with an additional $82 million of declared
dividends to be paid in the first quarter of 2022;
•Repurchased 3.2 million shares of common stock in 2021 under our share
repurchase program at an aggregate cost of $124 million; and
•Continued to maintain low cost operations with production expenses averaging
$3.38 per Boe for 2021.
With our acquisitions in the Permian Basin and Powder River Basin in 2021 we now
have substantial strategic positions in four leading basins in the United
States, providing our Company and shareholders with enhanced geologic and
geographic diversity and commodity optionality. We believe these transactions
will be accretive on financial metrics and will complement our existing deep
portfolio of assets in the Bakken and Oklahoma. We expect enhanced cash flows
from the acquisitions will provide continued support for additional returns to
shareholders via debt reduction, dividend increases, share repurchases, and
increased returns on capital employed. See Part I, Item 1. Business-Acquisition
Activities and Part II, Item 8. Notes to Consolidated Financial Statements-Note
2. Property Acquisitions and Dispositions for additional information on the
acquisitions.
Financial and Operating Metrics
Our operating results for 2020 were severely impacted by the economic effects
from the COVID-19 pandemic on crude oil demand and prices. In response to the
significant reduction in crude oil prices during 2020, we curtailed
approximately 55% of our operated crude oil production and associated natural
gas in the 2020 second quarter and significantly reduced our capital spending.
In July 2020 we began to gradually restore our curtailed production and
subsequently brought our remaining curtailed production back online in September
2020. These actions resulted in material reductions in our production, revenues,
and cash flows for 2020.
Crude oil and natural gas prices have increased significantly in 2021 compared
to 2020 levels in response to the lifting of COVID-19 restrictions, the
resumption of normal economic activity, and the resulting improvement in supply
and demand fundamentals. The increase in commodity prices and resumption of our
operations resulted in significantly improved operating results in 2021 compared
to 2020 as further described below.
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The following table contains financial and operating highlights for the periods
presented. Average net sales prices exclude any effect of derivative
transactions. Per-unit expenses have been calculated using sales volumes.
The previously described Permian Basin acquisition closed on December 21, 2021
and thus had a limited impact on fourth quarter and full year 2021 operating
results given our short duration of ownership. The acquired Permian assets
contributed 460 MBoe of production (42,000 Boe per day on average of which 78%
was oil), $29.4 million of revenues, and $14.1 million ($0.04 per basic and
diluted share) of net income to our consolidated results during the period of
ownership from December 21, 2021 to December 31, 2021.
                                                                               Year ended December 31,
                                                                   2021                  2020                 2019
Average daily production:
Crude oil (Bbl per day)                                            160,647              160,505              197,991
Natural gas (Mcf per day)                                        1,014,000              837,509              854,424
Crude oil equivalents (Boe per day)                                329,647              300,090              340,395
Average net sales prices: (1)
Crude oil ($/Bbl)                                             $      64.06          $     34.71          $     51.82
Natural gas ($/Mcf)                                           $       4.88          $      1.04          $      1.77
Crude oil equivalents ($/Boe)                                 $      46.24          $     21.47          $     34.56
Crude oil net sales price discount to NYMEX ($/Bbl)           $      (4.00) 

$(5.80) $(5.15)
Premium (rebate) on the net selling price of natural gas on NYMEX ($/MMcf)

                                                       $       1.00          $     (1.10)         $     (0.86)
Production expenses ($/Boe)                                   $       3.38  

$3.27 $3.58
Production taxes (% of net sales of crude oil and natural gas)

                                                                 7.3  %               8.2  %               8.3  %
DD&A ($/Boe)                                                  $      15.76          $     17.12          $     16.25
Total general and administrative expenses ($/Boe)             $       1.94  

$1.79 $1.57


(1)   See the subsequent section titled Non-GAAP Financial Measures for a
discussion and calculation of net sales prices, which are non-GAAP measures.
Results of Operations
The following table presents selected financial and operating information for
the periods presented.
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                                                                             Year Ended December 31,
In thousands, except sales price data                             2021                 2020                 2019
Crude oil and natural gas sales                              $ 5,793,741          $ 2,555,434          $ 4,514,389
Gain (loss) on derivative instruments, net                      (128,864)             (14,658)              49,083
Crude oil and natural gas service operations                      54,441               45,694               68,475
Total revenues                                                 5,719,318            2,586,470            4,631,947
Operating costs and expenses                                  (3,257,638)          (3,140,362)          (3,374,535)
Other expenses, net                                             (275,542)            (220,859)            (270,250)
Income (loss) before income taxes                              2,186,138             (774,751)             987,162
(Provision) benefit for income taxes                            (519,730)             169,190             (212,689)
Net income (loss)                                              1,666,408             (605,561)             774,473
Net income (loss) attributable to noncontrolling
interests                                                          5,440               (8,692)              (1,168)
Net income (loss) attributable to Continental
Resources                                                    $ 1,660,968          $  (596,869)         $   775,641
Diluted net income (loss) per share attributable to
Continental Resources                                        $      4.56          $     (1.65)         $      2.08
Production volumes:
Crude oil (MBbl)                                                  58,636               58,745               72,267
Natural gas (MMcf)                                               370,110              306,528              311,865
Crude oil equivalents (MBoe)                                     120,321              109,833              124,244
Sales volumes:
Crude oil (MBbl)                                                  58,757               58,793               72,136
Natural gas (MMcf)                                               370,110              306,528              311,865
Crude oil equivalents (MBoe)                                     120,442              109,881              124,113


Year ended December 31, 2021 compared to the year ended December 31, 2020
Below is a discussion of changes in our results of operations for 2021 compared
to 2020. A discussion of changes in our results of operations for 2020 compared
to 2019 has been omitted from this Form 10-K, but may be found in Part II, Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations of our Form 10-K for the year ended December 31, 2020 as filed with
the SEC on February 16, 2021.
Production
The following table summarizes the changes in our average daily Boe production
by major operating area for the periods presented.
                                                                Fourth Quarter                                                  Year Ended December 31,
Boe production per day                         2021                    2020                % Change                 2021                  2020                % Change
Bakken                                            175,585             183,141                    (4  %)              169,636             158,604                     7  %
Oklahoma                                          146,131             149,341                    (2  %)              147,249             134,506                     9  %

Powder River Basin                                  7,189                   -                     -  %                 5,161                   -                     -  %
Permian Basin (1)                                   4,997                   -                     -  %                 1,260                   -                     -  %
All other                                           6,266              
6,825                    (8  %)                6,341               6,980                    (9  %)
Total                                             340,168             339,307                     -  %               329,647             300,090                    10  %


(1)The presentation of average daily production represents production during the
period from the closing of our acquisition of Permian properties on December 21,
2021 through December 31, 2021 averaged over the respective fourth quarter and
full year periods. At the time of closing, our Permian properties produced on
average approximately 42,000 Boe per day based on two-stream reporting.
The following tables reflect our production by product and region for the
periods presented.
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                                                                    Year Ended December 31,                                                                      Volume
                                                      2021                                           2020                          Volume increase          percent increase
                                          Volume                  Percent                Volume                 Percent               (decrease)               (decrease)
Crude oil (MBbl)                              58,636                    49  %               58,745                    53  %              (109)                           -  %
Natural gas (MMcf)                           370,110                    51  %              306,528                    47  %            63,582                           21  %
Total (MBoe)                                 120,321                   100  %              109,833                   100  %            10,488                           10  %



                                      Year Ended December 31,                                               Volume
                                  2021                             2020                                    percent
                           MBoe               Percent        MBoe       
Percent      Volume increase      increase
North Region                     66,105          55  %      60,591          55  %         5,514                 9  %
South Region                     54,216          45  %      49,242          45  %         4,974                10  %
Total                           120,321         100  %     109,833         100  %        10,488                10  %


Over the past year we increased our allocation of capital to gas-weighted
projects to capitalize on improvements in market prices for natural gas and
natural gas liquids. These actions contributed to an increase in our natural gas
production as a percentage of total production and led to a 21% increase in
natural gas production in 2021 compared to 2020. Natural gas production in
Oklahoma increased 37,345 MMcf, or 18%, and natural gas production in the Bakken
increased 23,122 MMcf, or 23%, over the prior year. Additionally, properties
acquired in the Powder River Basin in March and November 2021 added 2,517 MMcf
to our natural gas production, while properties acquired in the Permian Basin
added 614 MMcf during the short duration of our ownership of the properties in
late 2021.
Our crude oil production was flat in 2021 compared to 2020 resulting from our
change in allocation of capital from oil-weighted projects to gas-weighted
projects over the past year and the timing of well completions. Crude oil
production in the Bakken was flat between years, while oil production in
Oklahoma decreased 1,708 MBbls, or 12%, compared to 2020. This decrease was
offset by new production added from our 2021 acquisitions. Properties acquired
in the Powder River Basin in March and November 2021 added 1,464 MBbls to our
crude oil production, while properties acquired in the Permian Basin added 357
MBbls during the short duration of our ownership of the properties in late 2021.
Revenues
Our revenues consist of sales of crude oil and natural gas, gains and losses
resulting from changes in the fair value of our derivative instruments, and
revenues associated with crude oil and natural gas service operations.
Net crude oil and natural gas sales and related net sales prices presented below
are non-GAAP measures. See the subsequent section titled Non-GAAP Financial
Measures for discussion and calculation of these measures.
Net crude oil and natural gas sales. Net crude oil and natural gas sales for
2021 totaled $5.57 billion, a 136% increase compared to net sales of $2.36
billion for 2020 due to significant increases in net sales prices and natural
gas sales volumes as discussed below.
Total sales volumes for 2021 increased 10,561 MBoe, or 10%, compared to 2020,
reflecting reduced sales in the prior period from the previously described
production curtailments in the second and third quarters of 2020 and our
subsequent resumption of usual operations. For 2021, our crude oil sales volumes
were flat compared to 2020, while our natural gas sales volumes increased 21%
driven by our increased allocation of capital toward gas-weighted projects over
the past year.
Our crude oil net sales prices averaged $64.06 per barrel for 2021, an increase
of 85% compared to $34.71 per barrel for 2020 due to a significant increase in
market prices driven by improved supply and demand fundamentals along with
improved price differentials. The differential between NYMEX West Texas
Intermediate calendar month crude oil prices and our realized crude oil net
sales prices averaged $4.00 per barrel in 2021 compared to $5.80 per barrel in
2020. Crude oil prices for 2020 were severely impacted by adverse changes in
supply and demand fundamentals from the economic effects of the COVID-19
pandemic, which negatively impacted location differentials and price
realizations in the 2020 period with no similar impacts in 2021.
Our natural gas net sales prices averaged $4.88 per Mcf for 2021 compared to
$1.04 per Mcf for 2020 due to a significant increase in market prices and
improved price differentials. The difference between our net sales prices and
NYMEX Henry Hub calendar month natural gas prices was a premium of $1.00 per Mcf
for 2021 compared to a discount of $1.10 per Mcf for 2020.
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In February 2021, severe winter weather and freezing temperatures in the
southern United States led to a period of increased spot prices for residue
natural gas that resulted in a significant improvement in our price realizations
in the 2021 first quarter compared to the prior year. Additionally, prices for
natural gas liquids have increased significantly in 2021 compared to 2020 levels
in conjunction with increased crude oil prices and other factors, resulting in
improved price realizations for our natural gas sales stream. For the fourth
quarter of 2021, the difference between our net sales prices and NYMEX Henry Hub
prices was a premium of $0.49 per Mcf.
Derivatives. The significant improvement in commodity prices in 2021 had an
overall unfavorable impact on the fair value of our derivatives, which resulted
in negative revenue adjustments of $128.9 million for the year, representing
$149.7 million of cash losses partially offset by $20.8 million of unsettled
non-cash gains. For 2020, we recognized negative revenue adjustments of $14.7
million resulting from changes in market prices that had an unfavorable impact
on the fair value of our derivatives.
Crude oil and natural gas service operations. Our crude oil and natural gas
service operations consist primarily of revenues associated with water
gathering, recycling, and disposal activities, which are impacted by our
production volumes and the timing and extent of our drilling and completion
projects. Revenues associated with such activities increased $8.7 million, or
19%, from $45.7 million for 2020 to $54.4 million for 2021 due to increased
water handling activities resulting from increases in completion activities and
production volumes compared to 2020.
Operating Costs and Expenses
Production expenses. Production expenses increased $47.6 million, or 13%, to
$406.9 million for 2021 compared to $359.3 million for 2020 primarily due to the
previously described 10% increase in total sales volumes. Production expenses on
a per-Boe basis averaged $3.38 per Boe for 2021, consistent with $3.27 per Boe
for 2020.
Production taxes. Production taxes increased $211.6 million, or 110%, to $404.4
million for 2021 compared to $192.7 million for 2020 due to the previously
described increase in crude oil and natural gas sales partially offset by a
decrease in our average production tax rate. Our production taxes as a
percentage of net crude oil and natural gas sales decreased to 7.3% for 2021
compared to 8.2% for 2020 primarily resulting from an increase in the proportion
of our revenues being generated in Oklahoma in the current period, which has
lower production tax rates compared to North Dakota.
Depreciation, depletion, amortization and accretion ("DD&A"). Total DD&A
amounted to $1.90 billion for 2021, consistent with $1.88 billion for 2020,
reflecting a 10% increase in total sales volumes the impact of which was nearly
offset by a decrease in our DD&A rate per Boe as further discussed below. The
following table shows the components of our DD&A on a unit of sales basis for
the periods presented.
                                                               Year ended December 31,
$/Boe                                                             2021                2020
Crude oil and natural gas properties                     $      15.45               $ 16.84
Other equipment                                                  0.22                  0.19
Asset retirement obligation accretion                            0.09                  0.09

Depreciation, depletion, amortization and accretion $15.76

$17.12


Estimated proved reserves are a key component in our computation of DD&A
expense. Proved reserves are determined using the unweighted arithmetic average
of the first-day-of-the-month commodity prices for the preceding twelve months
as required by SEC rules. Holding all other factors constant, if proved reserves
are revised downward due to commodity price declines or other reasons, the rate
at which we record DD&A expense increases. Conversely, if proved reserves are
revised upward, the rate at which we record DD&A expense decreases.
Our proved reserves were revised upward in 2021 prompted by significant
increases in first-day-of-the-month commodity prices and other factors, which
resulted in a decrease in our DD&A rate for crude oil and natural gas properties
in the current period. As a result of these upward revisions, our DD&A rate
decreased to $14.34 per Boe for the 2021 fourth quarter compared to $19.01 per
Boe for the 2020 fourth quarter, the impact of which helped offset higher DD&A
recognized in 2021 from increased sales volumes.
NYMEX WTI crude oil and Henry Hub natural gas first-day-of-the-month commodity
prices for January 1, 2022 and February 1, 2022 averaged $81.71 per barrel and
$4.65 per MMBtu, respectively, which are notably higher than average prices in
2021. If commodity prices remain at current levels for an extended period,
additional upward price-related revisions of proved reserves may occur in the
future, which may be significant and could result in a further decrease in our
DD&A rate relative to the 2021 fourth quarter. We are unable to predict the
timing and amount of future reserve revisions or the impact such revisions may
have on our future DD&A rate.
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Property impairments. Property impairments decreased $239.6 million to $38.4
million for 2021 compared to $277.9 million for 2020, primarily reflecting lower
proved property impairments in the current period. No proved property
impairments were recognized in 2021 as estimated future net cash flows were
determined to be in excess of cost basis due to improved commodity prices, while
proved property impairments totaled $207.1 million in 2020. Additionally,
impairments of unproved properties decreased $32.5 million in 2021 compared to
2020 reflecting a decrease in the amortization of undeveloped leasehold costs
from changes in management's estimates of properties not expected to be
developed before lease expiration in response to significantly improved
commodity prices compared to the prior year. Our unamortized balance of unproved
properties increased significantly in late 2021 in connection with our 2021
fourth quarter property acquisitions and now totals $1.36 billion at
December 31, 2021. Accordingly, our amortized impairments of unproved property
costs are expected to increase in 2022 relative to 2021 levels, the amount of
which is uncertain.
General and administrative ("G&A") expenses. G&A expenses increased $37.0
million, or 19%, to $233.6 million for 2021 compared to $196.6 million for 2020.
Total G&A expenses include non-cash charges for equity compensation of $63.2
million and $64.6 million for 2021 and 2020, respectively. G&A expenses other
than equity compensation totaled $170.4 million for 2021, an increase of $38.4
million, or 29%, compared to $132.0 million for 2020 due to an increase in
employee benefits partially offset by higher overhead recoveries from joint
interest owners driven by increased drilling, completion, and production
activities compared to 2020.
The following table shows the components of G&A expenses on a unit of sales
basis for the periods presented.
                                                      Year ended December 

31,

$/Boe                                                    2021               

2020

General and administrative expenses            $       1.42                 $ 1.20
Non-cash equity compensation                           0.52                 

0.59

Total general and administrative expenses      $       1.94                 

$1.79


Acquisition costs. We incurred $13.9 million of expenses in connection with our
December 2021 acquisition of properties in the Permian Basin, which are
reflected in the caption "Acquisition costs" in the consolidated statements of
comprehensive income (loss) for 2021.
Interest expense. Interest expense decreased $6.6 million, or 3%, to $251.6
million for 2021 compared to $258.2 million for 2020 due to a decrease in our
annual weighted average outstanding debt from $5.8 billion in 2020 to $5.6
billion in 2021. Our outstanding debt totaled $6.8 billion at December 31, 2021,
reflecting an increase of $2.1 billion in the 2021 fourth quarter due to credit
facility and senior note borrowings incurred to fund a portion of our December
2021 acquisition of properties in the Permian Basin.
Gain (loss) on extinguishment of debt. See Part II, Item 8. Notes to
Consolidated Financial Statements-Note 8. Long-Term Debt for discussion of gains
and losses recognized on debt extinguishments in 2021 and 2020.
Other non-operating expense. As discussed in Part II, Item 8. Notes to
Consolidated Financial Statements-Note 13. Commitments and Contingencies-Pledge
commitment, we recognized a $25.0 million charge to earnings upon execution of
an irrevocable ten-year pledge commitment in December 2021, which is reflected
in the caption "Other income (expense)-Other" in the consolidated statements of
comprehensive income (loss) for 2021.
Income Taxes. For 2021 and 2020 we provided for income taxes at a combined
federal and state tax rate of 24.5% of pre-tax income/loss. We recorded an
income tax provision of $519.7 million and an income tax benefit of $169.2
million for 2021 and 2020, respectively, which resulted in effective tax rates
of 23.8% and 21.8%, respectively, after taking into account the application of
statutory tax rates, permanent taxable differences, tax effects from equity
compensation, changes in valuation allowances, and other items. See Part II,
Item 8. Notes to Consolidated Financial Statements-Note 11. Income Taxes for a
summary of the sources and tax effects of items comprising our income tax
provision and resulting effective tax rates for 2021 and 2020.
Liquidity and Capital Resources
Our primary sources of liquidity have historically been cash flows generated
from operating activities, financing provided by our credit facility and the
issuance of debt securities. Additionally, asset dispositions and joint
development arrangements have provided a source of cash flow for use in reducing
debt and enhancing liquidity. We are committed to operating in a responsible
manner to preserve financial flexibility, liquidity, and the strength of our
balance sheet.
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At January 31, 2022, we had approximately $1.76 billion of borrowing
availability under our credit facility after considering outstanding borrowings
and letters of credit, which represents a $260 million increase in availability
compared to year-end 2021. Our credit facility, which is unsecured and has no
borrowing base subject to redetermination, does not mature until October 2026.
Based on our planned capital spending, including our pending property
acquisition described below, our forecasted cash flows and projected levels of
indebtedness, we expect to maintain compliance with the covenants under our
credit facility and senior note indentures. Further, based on current market
indications, we expect to meet our contractual cash commitments to third parties
subsequently described under the heading Future Capital Requirements,
recognizing we may be required to meet such commitments even if our business
plan assumptions were to change. We monitor our capital spending closely based
on actual and projected cash flows and have the ability to reduce spending or
dispose of assets if needed to preserve liquidity and financial flexibility to
fund our operations.
Cash Flows
Cash flows from operating activities
Net cash provided by operating activities increased $2.55 billion, or 179%, to
$3.97 billion for 2021 compared to $1.42 billion for 2020 primarily due to a
$3.24 billion increase in crude oil and natural gas revenues due to the
previously described increases in commodity prices and natural gas sales volumes
in the current period. This increase was partially offset by a $211.6 million
increase in production taxes associated with higher crude oil and natural gas
revenues and a $121.5 million increase in realized cash losses on matured
commodity derivatives in the current period. Additionally, we experienced an
increase in certain cash operating expenses primarily due to an increase in
total sales volumes, which included a $47.6 million increase in production
expenses and a $28.3 million increase in transportation expenses.
Cash flows used in investing activities
Net cash used in investing activities totaled $4.99 billion and $1.51 billion
for 2021 and 2020, respectively, the $3.48 billion increase of which reflects
our 2021 property acquisition activities discussed in Part II, Item 8. Notes to
Consolidated Financial Statements-Note 2. Property Acquisitions and
Dispositions.
Cash flows from financing activities
Net cash provided by financing activities for 2021 totaled $989.1 million,
primarily consisting of $1.59 billion of net proceeds received from our November
2021 issuances of senior notes and $340 million of net credit facility
borrowings incurred to fund a portion of our December 2021 Permian Basin
acquisition. These increases were partially offset by $630.8 million of senior
note redemptions during the year, $123.9 million of cash used to repurchase
shares of our common stock, and $165.9 million of cash dividends paid on common
stock.
Net cash provided by financing activities for 2020 totaled $97.1 million,
primarily resulting from $1.48 billion of net proceeds received from our
November 2020 issuance of senior notes due 2031, $105.0 million of net credit
facility borrowings, and net proceeds of $26.0 million from term loans executed
during 2020. These increases were partially offset by $1.34 billion of senior
note repurchases and redemptions during 2020 using available cash and proceeds
from our issuance of 2031 Notes, $25.2 million of premiums and costs paid upon
the redemptions and repurchases, $126.9 million of cash used to repurchase
shares of our common stock, and $18.5 million of cash dividends paid on common
stock.
Future Sources of Financing
Although we cannot provide any assurance, we believe funds from operating cash
flows, our cash balance, and availability under our credit facility should be
sufficient to meet our normal operating needs, debt service obligations,
budgeted capital expenditures, the pending property acquisition described below,
cash payments for income taxes, and dividend payments for at least the next 12
months and to meet our contractual cash commitments to third parties described
under the heading Future Capital Requirements beyond 12 months.
Based on current market indications, our budgeted capital spending plans for
2022 are expected to be funded from operating cash flows. Any deficiencies in
operating cash flows relative to budgeted spending are expected to be funded by
borrowings under our credit facility. If cash flows are materially impacted by
declines in commodity prices, we have the ability to reduce our capital
expenditures or utilize the availability of our credit facility if needed to
fund our operations and business plans.
We may choose to access banking or capital markets for additional financing or
capital to fund our operations or take advantage of business opportunities that
may arise. Further, we may sell assets or enter into strategic joint development
opportunities in order to obtain funding if such transactions can be executed on
satisfactory terms. However, no assurance can be given that such transactions
will occur.
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Credit facility
We have an unsecured credit facility, maturing in October 2026, with aggregate
lender commitments totaling $2.0 billion. The commitments are from a syndicate
of 12 banks and financial institutions. We believe each member of the current
syndicate has the capability to fund its commitment. As of January 31, 2022, we
had $1.76 billion of borrowing availability on our credit facility after
considering outstanding borrowings and letters of credit.
The commitments under our credit facility are not dependent on a borrowing base
calculation subject to periodic redetermination based on changes in commodity
prices and proved reserves. Additionally, downgrades or other negative rating
actions with respect to our credit rating do not trigger a reduction in our
current credit facility commitments, nor do such actions trigger a security
requirement or change in covenants. Downgrades of our credit rating will,
however, trigger increases in our credit facility's interest rates and
commitment fees paid on unused borrowing availability under certain
circumstances.
Our credit facility contains restrictive covenants that may limit our ability
to, among other things, incur additional indebtedness, incur liens, engage in
sale and leaseback transactions, or merge, consolidate or sell all or
substantially all of our assets. Our credit facility also contains a requirement
that we maintain a consolidated net debt to total capitalization ratio of no
greater than 0.65 to 1.00. See Part II, Item 8. Notes to Consolidated Financial
Statements-Note 8. Long-Term Debt for a discussion of how this ratio is
calculated pursuant to our credit agreement.
We were in compliance with our credit facility covenants at December 31, 2021
and expect to maintain compliance. At December 31, 2021, our consolidated net
debt to total capitalization ratio was 0.43. We do not believe the credit
facility covenants are reasonably likely to limit our ability to undertake
additional debt financing if needed to support our business.
Future Capital Requirements
Our material future cash requirements are summarized below. Based on current
market indications, we expect to meet our contractual cash commitments to third
parties as of December 31, 2021, recognizing we may be required to meet such
commitments even if our business plan assumptions were to change.
Senior notes
Our debt includes outstanding senior note obligations totaling $6.36 billion at
December 31, 2021, exclusive of interest payment obligations thereon. Our senior
notes are not subject to any mandatory redemption or sinking fund requirements.
The earliest scheduled senior note maturity is our $649.6 million of 2023 Notes
due in April 2023. For further information on the face values, maturity dates,
semi-annual interest payment dates, optional redemption periods and covenant
restrictions related to our senior notes, refer to Note 8. Long-Term Debt in
Part II, Item 8. Notes to Consolidated Financial Statements.
We were in compliance with our senior note covenants at December 31, 2021 and
expect to maintain compliance. We do not believe the senior note covenants will
materially limit our ability to undertake additional debt financing. Downgrades
or other negative rating actions with respect to the credit ratings assigned to
our senior unsecured debt do not trigger additional senior note covenants.
Credit facility borrowings
As of January 31, 2022, we had $240 million of outstanding borrowings on our
credit facility, which represents a decrease of $260 million compared to $500
million outstanding at year-end 2021. Our credit facility matures in October
2026.
Transportation, gathering, and processing commitments
We have entered into transportation, gathering, and processing commitments to
guarantee capacity on crude oil and natural gas pipelines and natural gas
processing facilities that require us to pay per-unit charges regardless of the
amount of capacity used. Future commitments remaining as of December 31, 2021
under the arrangements amount to approximately $1.31 billion. See Part II, Item
8. Notes to Consolidated Financial Statements-Note 13. Commitments and
Contingencies for additional information.
Capital Expenditures
2021 Capital Spending
For the year ended December 31, 2021, we invested $1.54 billion in our capital
program excluding $3.58 billion of unbudgeted acquisitions, excluding $21.3
million of mineral acquisitions attributable to Franco-Nevada, and including
$114.1 million of capital costs associated with increased accruals for capital
expenditures as compared to December 31, 2020. Our 2021 capital
                                       50
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expenditures were allocated as follows by quarter. See Part II, Item 8. Notes to
Consolidated Financial Statements-Note 2. Property Acquisitions and Dispositions
for discussion of our notable property acquisitions executed in 2021.
In millions                                      1Q 2021     2Q 2021     3Q 2021     4Q 2021     Total 2021
Exploration and development drilling           $  255.6    $  216.2    $  312.3    $   382.6    $  1,166.7
Land costs                                          7.5        14.5        18.5        111.1         151.6
Mineral acquisitions attributable to
Continental                                         0.2         1.3         1.5          2.9           5.9
Capital facilities, workovers, water
infrastructure, and other corporate assets         27.4        57.3        51.0         68.4         204.1
Seismic                                             2.7         0.2         0.4          9.2          12.5
Capital expenditures attributable to
Continental, excluding unbudgeted acquisitions $  293.4    $  289.5    $  383.7    $   574.2    $  1,540.8
Acquisitions of producing properties (1)          183.3        (5.4)        0.3      2,390.3       2,568.5
Acquisitions of non-producing properties (1)       24.3        18.7         3.0        967.5       1,013.5
Total unbudgeted acquisitions                     207.6        13.3         3.3      3,357.8       3,582.0
Total capital expenditures attributable to
Continental                                       501.0       302.8       387.0      3,932.0       5,122.8
Mineral acquisitions attributable to
Franco-Nevada                                       0.9         2.8         6.0         11.6          21.3
Total capital expenditures                        501.9       305.6       

393.0 3,943.6 5,144.1


(1)  Fourth quarter amounts primarily represent our December 2021 Permian Basin
acquisition. See Part II, Item 8. Notes to Consolidated Financial
Statements-Note 2. Property Acquisitions and Dispositions for additional
information.
2022 Capital Budget
In 2022, we will remain committed to operating in a disciplined,
capital-efficient manner to maximize cash flow generation and capital and
corporate returns to shareholders. Our 2022 capital budget is expected to be
allocated as reflected in the table below. Acquisition expenditures are not
budgeted, with the exception of planned levels of spending for mineral
acquisitions made in conjunction with our relationship with Franco-Nevada.
In millions                                                                    2022 Budget
Exploration and development                                                 $         1,800
Land costs                                                                              127
Mineral acquisitions attributable to Continental (1)                                     23

Fixed assets, refurbishments, hydraulic infrastructures and other company assets

                                                                                  344
Seismic                                                                                   6
2022 capital budget attributable to Continental                             $         2,300
Mineral acquisitions attributable to Franco-Nevada (1)                                   91
Total 2022 capital budget (2)                                               $         2,391


(1)  Represents planned spending for mineral acquisitions by TMRC II under our
relationship with Franco-Nevada Corporation. Continental holds a controlling
financial interest in TMRC II and therefore consolidates the financial results
and capital expenditures of the entity. With a carry structure in place,
Continental will fund 20% of 2022 planned spending, or $23 million, and
Franco-Nevada will fund the remaining 80%, or $91 million.
(2)  Excludes the $450 million purchase price for our pending acquisition of
properties in the Powder River Basin discussed below under the caption Pending
Property Acquisition.
Our drilling and completion activities and the actual amount and timing of our
capital expenditures may differ materially from our budget as a result of, among
other things, available cash flows, unbudgeted acquisitions, actual drilling and
completion results, operational process improvements, the availability of
drilling and completion rigs and other services and equipment, cost inflation,
the availability of transportation, gathering and processing capacity, changes
in commodity prices, and regulatory, technological and competitive developments.
We monitor our capital spending closely based on actual and projected cash flows
and may scale back our spending should commodity prices materially decrease from
current levels.
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Pending Property Acquisition
As discussed in Note 20. Subsequent Events in Part II, Item 8. Notes to
Consolidated Financial Statements, on January 24, 2022, we executed a definitive
agreement to acquire oil and gas properties in the Powder River Basin for
$450 million of cash, subject to customary closing price adjustments. The
properties include approximately 172,000 net leasehold acres and producing
properties with production totaling approximately 16,000 barrels of oil
equivalent per day based on two-stream reporting. Closing of the acquisition is
expected to occur in late March 2022 and remains subject to the completion of
customary due diligence procedures and closing conditions.
We expect to continue participating as a buyer of properties when and if we have
the ability to increase our position in strategic plays at attractive terms.
Cash Payments for Income Taxes
As of February 10, 2022, the publicly available forward commodity strip prices
for the remainder of 2022 averaged $83.38 per barrel for crude oil and $4.09 per
Mcf for natural gas. If commodity prices remain at these levels for the year, we
could potentially utilize the full amount of our federal net operating loss
carryforwards and certain state net operating loss carryforwards and generate
significant taxable income in 2022, which could result in us making cash
payments for income taxes in the upcoming year. Because of the significant
uncertainty inherent in numerous factors utilized in projecting taxable income,
including future commodity prices, production levels, development activities,
capital spending, profitability, and general economic conditions, we cannot
predict the amount of future income tax payments with certainty, but such
payments could be significant.
Dividend Declaration
On February 9, 2022, the Company declared a quarterly cash dividend of $0.23 per
share on its outstanding common stock, which will be paid on March 4, 2022 to
shareholders of record as of February 22, 2022.
Delivery Commitments
We have various natural gas volume delivery commitments that are related to our
North and South areas. We expect to primarily fulfill our contractual
obligations with production from our proved reserves. However, we may purchase
third-party volumes to satisfy our commitments. The volumes disclosed herein
represent gross production associated with properties operated by us and do not
reflect our net proportionate share of such amounts. Additionally, in the South
region certain of our firm sales contracts for oil include delivery commitments
that specify the delivery of a fixed and determinable quantity. We expect to
primarily fulfill our contractual obligations with production from our proved
reserves. As of December 31, 2021, we were committed to deliver the following
fixed quantities of natural gas production.
                        Year Ending       Natural Gas       Crude Oil
                        December 31,          Bcf             MMBo
                            2022              146              13
                            2023               84              13
                            2024               73               3
                            2025               18               -
                            2026               15               -


Derivative Instruments
See Note 6. Derivative Instruments in Part II, Item 8. Notes to Consolidated
Financial Statements for discussion of our hedging activities, including a
summary of derivative contracts in place as of December 31, 2021. Between
January 1, 2022 and February 10, 2022 we entered into additional derivative
instruments as summarized in the tables below.
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Natural gas derivatives

                                                                                                        Weighted Average Hedge Price ($/MMBtu)
Period and Type of Contract                             Average Volumes Hedged                        Swaps                Floor            Ceiling
April 2022 - September 2022
Swaps - Henry Hub                                 200,000       MMBtus/day                      $         4.03
April 2022 - September 2022
Collars - Henry Hub                               110,000       MMBtus/day                                              $   4.50          $    6.00
July 2022 - December 2022
Swaps - WAHA                                       45,000       MMBtus/day                      $         3.41
October 2022 - March 2023
Collars - Henry Hub                               210,000       MMBtus/day                                              $   4.12          $    5.52
January 2023 - December 2023
Swaps - WAHA                                       40,000       MMBtus/day                      $         2.69
April 2023 - September 2023
Swaps - Henry Hub                                 100,000       MMBtus/day                      $         3.25
October 2023 - March 2024
Collars - Henry Hub                               100,000       MMBtus/day                                              $   3.14          $    4.00
April 2024 - December 2024
Swaps - Henry Hub                                 100,000       MMBtus/day                      $         3.11


Crude oil derivatives

                                                                                                               Weighted Average Hedge
Period and Type of Contract                                          Average Volumes Hedged                        Price ($/Bbl)

March 2022 - December 2022
NYMEX Roll Swaps                                                 24,000       Bbls/day                       $                  1.10


Share repurchase program
In May 2019 our Board of Directors approved the initiation of a share repurchase
program to acquire up to $1 billion of our common stock beginning in June 2019.
On February 8, 2022, our Board of Directors approved an increase in the size of
the share repurchase program to $1.5 billion, inclusive of cumulative amounts
repurchased to date. As of the date of this filing, we have repurchased and
retired a cumulative total of approximately 17.0 million shares under the
program at an aggregate cost of $441.1 million, leaving approximately
$1.06 billion of authorized repurchasing capacity under the modified program.
The timing and amount of the Company's share repurchases are subject to market
conditions and management discretion. The share repurchase program does not
require the Company to repurchase a specific number of shares and may be
modified, suspended, or terminated by the Board of Directors at any time.
Senior note repurchases and redemptions
As discussed in Note 8. Long-Term Debt in Part II, Item 8. Notes to Consolidated
Financial Statements, in recent years we have repurchased or redeemed a portion
of our outstanding senior notes. From time to time, we may seek to execute
additional repurchases or redemptions of our senior notes for cash in open
market transactions, privately negotiated transactions, or otherwise. Such
repurchases or redemptions will depend on prevailing market conditions, our
liquidity and prospects for future access to capital, and other factors. The
amounts involved in any such transactions, individually or in the aggregate, may
be material.
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Critical Accounting Policies and Estimates
Our consolidated financial statements and related footnotes contain information
that is pertinent to our management's discussion and analysis of financial
condition and results of operations. The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
select appropriate accounting policies and to make estimates and assumptions
that affect the reported amounts of assets, liabilities, revenues, expenses, and
the disclosure and estimation of contingent assets and liabilities. See Part II,
Item 8. Notes to Consolidated Financial Statements-Note 1. Organization and
Summary of Significant Accounting Policies and Note 9. Revenues for descriptions
of our major accounting policies. Certain of these accounting policies involve
judgments and uncertainties to such an extent that there is a reasonable
likelihood that materially different amounts could have been reported under
different conditions or if different assumptions had been used.
In management's opinion, the most significant reporting areas impacted by
management's judgments and estimates are crude oil and natural gas reserve
estimations, revenue recognition, the choice of accounting method for crude oil
and natural gas activities and derivatives, impairment of assets, income taxes
and contingent liabilities. These areas are discussed below. Management's
judgments and estimates in these areas are based on information available from
both internal and external sources, including engineers, geologists and
historical experience in similar matters and are believed to be reasonable under
the circumstances. We evaluate our estimates and assumptions on a regular basis.
Actual results could differ from the estimates as additional information becomes
known.
Crude Oil and Natural Gas Reserves Estimation and Standardized Measure of Future
Cash Flows
Our external independent reserve engineers, Ryder Scott, and internal technical
staff prepare the estimates of our crude oil and natural gas reserves and
associated future net cash flows. Even though Ryder Scott and our internal
technical staff are knowledgeable and follow authoritative guidelines for
estimating reserves, they must make a number of subjective assumptions based on
professional judgments in developing the reserve estimates. Estimates of
reserves and their values, future production rates, and future costs and
expenses are inherently uncertain for various reasons, including many factors
beyond the Company's control. Reserve estimates are updated by us at least
semi-annually and take into account recent production levels and other technical
information about each of our properties.
Crude oil and natural gas reserve engineering is a subjective process of
estimating underground accumulations of crude oil and natural gas that cannot be
precisely measured. The accuracy of any reserve estimate is a function of the
quality of available data and of engineering and geological interpretation and
judgment. Periodic revisions or removals of estimated reserves and future cash
flows may be necessary as a result of a number of factors, including reservoir
performance, new drilling, crude oil and natural gas prices, changes in costs,
technological advances, new geological or geophysical data, changes in business
strategies, or other economic factors. Accordingly, reserve estimates may differ
significantly from the quantities of crude oil and natural gas ultimately
recovered. For the years ended December 31, 2021, 2020, and 2019, net upward
(downward) revisions of our proved reserves totaled approximately 54 MMBoe,
(505) MMBoe, and (149) MMBoe, respectively. We cannot predict the amounts or
timing of future reserve revisions or removals.
Estimates of proved reserves are key components of the Company's most
significant financial estimates including the computation of depreciation,
depletion, amortization and impairment of proved crude oil and natural gas
properties. Holding all other factors constant, if proved reserves are revised
downward, the rate at which we record DD&A expense would increase, reducing net
income. Conversely, if proved reserves are revised upward, the rate at which we
record DD&A expense would decrease. Future revisions of reserves may be material
and could significantly alter future depreciation, depletion, and amortization
expense and may result in material impairments of assets.
At December 31, 2021, our proved reserves totaled 1,645 MMBoe as determined
using 12-month average first-day-of-the-month prices of $66.56 per barrel for
crude oil and $3.60 per MMBtu for natural gas. Actual future prices may be
materially higher or lower than those used in our year-end estimates. NYMEX WTI
crude oil and Henry Hub natural gas first-day-of-the-month commodity prices for
January 1, 2022 and February 1, 2022 averaged $81.71 per barrel and $4.65 per
MMBtu, respectively.
Holding all other factors constant, if crude oil prices used in our year-end
reserve estimates were increased to $80 per barrel our proved reserves at
December 31, 2021 could increase by approximately 21 MMBoe, or 1%. If the
increase in proved reserves under this oil price sensitivity existed throughout
2021, our DD&A expense for 2021 would have decreased by approximately 2%.
Holding all other factors constant, if natural gas prices used in our year-end
reserve estimates were increased to $4.50 per MMBtu our proved reserves at
December 31, 2021 could increase by approximately 8 MMBoe, or less than 1%. If
the increase in proved reserves under this gas price sensitivity existed
throughout 2021, our DD&A expense for 2021 would have decreased by approximately
1%.
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Our DD&A calculations for oil and gas properties are performed on a field basis
and revisions to proved reserves will not necessarily be applied ratably across
all fields and may not be applied to some fields at all. Further, reserve
revisions in significant fields may individually affect our DD&A rate. As a
result, the impact on DD&A expense from revisions in reserves cannot be
predicted with certainty and may result in changes in expense that are greater
or less than the underlying changes in reserves.
See Part I, Item 1. Business-Crude Oil and Natural Gas Operations-Proved
Reserves-Proved Reserves, Standardized Measure, and PV-10 Sensitivities for
additional proved reserve sensitivities under certain increasing and decreasing
commodity price scenarios for crude oil and natural gas.
Revenue Recognition
We derive substantially all of our revenues from the sale of crude oil and
natural gas. See Part II, Item 8. Notes to Consolidated Financial
Statements-Note 9. Revenues for discussion of our accounting policies governing
the recognition and presentation of revenues.
Operated crude oil and natural gas revenues are recognized during the month in
which control transfers to the customer and it is probable the Company will
collect the consideration it is entitled to receive. For non-operated
properties, the Company's proportionate share of production is generally
marketed at the discretion of the operators. Non-operated revenues are
recognized by the Company during the month in which production occurs and it is
probable the Company will collect the consideration it is entitled to receive.
At the end of each month, to record revenues we estimate the amount of
production delivered and sold to customers and the prices at which they were
sold. Variances between estimated revenues and actual amounts received for all
prior months are recorded in the month payment is received and are reflected in
our financial statements as crude oil and natural gas sales. These variances
have historically not been material.
For the sale of crude oil and natural gas, we evaluate whether we are the
principal, and report revenues on a gross basis (revenues presented separately
from associated expenses), or an agent, and report revenues on a net basis. In
this assessment, we consider if we obtain control of the products before they
are transferred to the customer as well as other indicators. Judgment may be
required in determining the point in time when control of products transfers to
customers.
Successful Efforts Method of Accounting
Our business is subject to accounting rules that are unique to the crude oil and
natural gas industry. Two generally accepted methods of accounting for oil and
gas activities are available-the successful efforts method and the full cost
method. The most significant differences between these two methods are the
treatment of exploration costs and the manner in which the carrying value of oil
and gas properties are amortized and evaluated for impairment. We use the
successful efforts method of accounting for our oil and gas properties. See Part
II, Item 8. Notes to Consolidated Financial Statements-Note 1. Organization and
Summary of Significant Accounting Policies for further discussion of the
accounting policies applicable to the successful efforts method of accounting.
Derivative Activities
From time to time we may utilize derivative contracts to hedge against the
variability in cash flows associated with the forecasted sale of future crude
oil and natural gas production and for other purposes. We have elected not to
designate any of our price risk management activities as cash flow hedges. As a
result, we mark our derivative instruments to fair value and recognize the
changes in fair value in current earnings.
In determining the amounts to be recorded for outstanding derivative contracts,
we are required to estimate the fair value of the derivatives. We use an
independent third party to provide our derivative valuations. The third party's
valuation models for derivative contracts are industry-standard models that
consider various inputs including quoted forward prices for commodities, time
value, volatility factors, and current market and contractual prices for the
underlying instruments, as well as other relevant economic measures. The fair
value calculations for collars requires the use of an option-pricing model. The
estimated future prices are compared to the prices fixed by the derivative
agreements and the resulting estimated future cash inflows or outflows over the
lives of the derivatives are discounted to calculate the fair value of the
derivative contracts. These pricing and discounting variables are sensitive to
market volatility as well as changes in future price forecasts and interest
rates.
We validate our derivative valuations through management review and by
comparison to our counterparties' valuations for reasonableness. Differences
between our fair value calculations and counterparty valuations have
historically not been material.
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Impairment of Assets
All of our long-lived assets are monitored for potential impairment when
circumstances indicate the carrying value of an asset may be greater than its
future net cash flows, including cash flows from risk-adjusted proved reserves.
Risk-adjusted probable and possible reserves may be taken into consideration
when determining estimated future net cash flows and fair value when such
reserves exist and are economically recoverable.
Proved crude oil and natural gas properties are reviewed for impairment on a
field-by-field basis. If the carrying amount of a field exceeds its estimated
undiscounted future cash flows, the carrying amount of the field is reduced to
its estimated fair value using a discounted cash flow model. For producing
properties, the impairment evaluations involve a significant amount of judgment
since the results are based on estimated future events, such as future sales
prices for crude oil and natural gas, future costs to produce those products,
estimates of future crude oil and natural gas reserves to be recovered and the
timing thereof, the economic and regulatory climates and other factors. The need
to test a field for impairment may result from significant declines in sales
prices or downward revisions or removals of crude oil and natural gas reserves.
Estimates of anticipated sales prices and recoverable reserves are highly
judgmental and are subject to material revision in future periods.
No impairments were recognized for our proved crude oil and natural gas
properties for the year ended December 31, 2021 as estimated future net cash
flows were determined to be in excess of cost basis. Commodity price assumptions
used for the year-end December 31, 2021 impairment calculations were based on
publicly available average annual forward commodity strip prices through
year-end 2026 and were then escalated at 3% per year thereafter. Holding all
other factors constant, as forward commodity prices decrease, our probability
for recognizing producing property impairments may increase, or the magnitude of
impairments to be recognized may increase. Conversely, as forward commodity
prices increase, our probability for recognizing producing property impairments
may decrease, or the magnitude of impairments to be recognized may decrease or
be eliminated. As of December 31, 2021, the publicly available forward commodity
strip prices for the year 2026 used in our fourth quarter impairment
calculations averaged $58.42 per barrel for crude oil and $3.03 per Mcf for
natural gas. If forward commodity prices materially decrease from current levels
for an extended period, impairments of producing properties may be recognized in
the future. Because of the uncertainty inherent in the numerous factors utilized
in determining the fair value of producing properties, we cannot predict the
timing and amount of future impairment charges, if any.
Impairment losses for unproved properties are generally recognized by amortizing
the portion of the properties' costs which management estimates will not be
transferred to proved properties over the lives of the leases based on drilling
plans, experience of successful drilling, and the average holding period. The
impairment assessments are affected by economic factors such as the results of
exploration activities, commodity price outlooks, anticipated drilling programs,
remaining lease terms, and potential shifts in business strategy employed by
management. The estimated timing and rate of successful drilling is highly
judgmental and is subject to material revision in future periods as better
information becomes available.
Income Taxes
Income taxes are accounted for using the asset and liability method. Deferred
tax assets and liabilities are measured using enacted tax rates expected to
apply to taxable income in the years in which those differences are expected to
be recovered or settled. The effect on deferred tax assets and liabilities of a
change in tax rates is recognized in income in the period that includes the
enactment date.
In assessing the realizability of deferred tax assets, management must consider
whether it is more likely than not that some portion or all of the deferred tax
assets will not be realized. We apply judgment to determine the weight of both
positive and negative evidence in order to conclude whether a valuation
allowance is necessary for our deferred tax assets. In determining whether a
valuation allowance is required, we consider, among other factors, our financial
position, results of operations, projected future taxable income, reversal of
existing deferred tax liabilities against deferred tax assets, and tax planning
strategies. Significant judgment is involved in this determination as we are
required to make assumptions about future commodity prices, projected
production, development activities, profitability of future business strategies
and forecasted economics in the oil and gas industry. Additionally, changes in
the effective tax rate resulting from changes in tax law and our level of
earnings may limit utilization of deferred tax assets and may affect the
valuation of deferred tax balances in the future. Changes in judgment regarding
future realization of deferred tax assets may result in a reversal of all or a
portion of the valuation allowance.
We believe our net deferred tax assets will ultimately be realized. During 2020,
a $14.5 million valuation allowance was established for the deferred tax asset
associated with a portion of our Oklahoma state net operating loss
carryforwards. In 2021, we reassessed the realizability of the deferred tax
asset related to Oklahoma state net operating loss carryforwards, and based on
current year activity, determined it was more likely than not that such assets
would be realized. Therefore, it was determined that the previously recorded
valuation allowance in 2020 should be released in 2021. We will continue to
evaluate both the
                                       56
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positive and negative evidence on a quarterly basis in determining the need for
a valuation allowance with respect to our deferred tax assets.
Contingent Liabilities
A provision for legal, environmental and other contingencies is charged to
expense when a loss is probable and the loss or range of loss can be reasonably
estimated. Determining when liabilities and expenses should be recorded for
these contingencies and the appropriate amounts of accruals is subject to an
estimation process that requires subjective judgment of management. In certain
cases, management's judgment is based on the advice and opinions of legal
counsel and other advisers, the interpretation of laws and regulations which can
be interpreted differently by regulators and/or courts of law, the experience of
the Company and other companies dealing with similar matters, and management's
decision on how it intends to respond to a particular matter; for example, a
decision to contest it vigorously or a decision to seek a negotiated settlement.
Actual losses can differ from estimates for various reasons, including differing
interpretations of laws and opinions and assessments on the amount of damages.
We closely monitor known and potential legal, environmental and other
contingencies and make our best estimate of when or if to record liabilities and
losses for matters based on available information.
New Accounting Pronouncement
See Part II, Item 8. Notes to Consolidated Financial Statements-Note 1.
Organization and Summary of Significant Accounting Policies-Adoption of new
accounting pronouncement for a discussion of the new income tax accounting
standard adopted on January 1, 2021, which did not have a material impact on our
financial position, results of operations, or cash flows.
Legislative and Regulatory Developments
The crude oil and natural gas industry in the United States is subject to
various types of regulation at the federal, state and local levels. In January
2021, President Biden issued executive orders that, among other things,
establish new greenhouse gas emission standards for the oil and gas sector.
Additionally, the Biden Administration is pursuing legislative changes to
eliminate or defer certain key U.S. federal income tax deductions historically
available to oil and gas exploration and production companies, as well as other
tax policy changes including a proposed increase in the U.S. corporate income
tax rate, among other things. These changes, if enacted, could have a material
adverse effect on our results of operations and cash flows. President Biden may
continue to issue additional executive orders in pursuit of his regulatory
agenda and there is the potential for the revision of existing laws and
regulations or the adoption of new legislation that could adversely affect the
oil and gas industry. See Part I, Item 1. Business-Regulation of the Crude Oil
and Natural Gas Industry for further discussion of significant laws and
regulations that have been enacted or are currently being considered by
regulatory bodies that may affect us in the areas in which we operate.
Inflation
Certain drilling and completion costs and costs of oilfield services, equipment,
and materials decreased in recent years as service providers reduced their costs
in response to reduced demand arising from historically low crude oil prices.
However, inflationary pressures returned in 2021 and are expected to continue in
2022 in conjunction with the significant improvement in commodity prices over
the past year in response to the lifting of COVID-19 restrictions, the
resumption of normal economic activity, and the resulting improvement in supply
and demand fundamentals. Additionally, recent supply chain disruptions stemming
from the COVID-19 pandemic have led to shortages of certain materials and
equipment and resulting increases in material and labor costs. If these supply
chain disruptions persist or worsen, and commodity prices continue to remain at
attractive levels that stimulate increased industry activity, we may face
shortages of service providers, equipment, and materials. Such shortages could
result in increased competition which may lead to further increases in costs.
Non-GAAP Financial Measures
Net crude oil and natural gas sales and net sales prices
Revenues and transportation expenses associated with production from our
operated properties are reported separately as discussed in Part II, Item 8.
Notes to Consolidated Financial Statements-Note 9. Revenues. For non-operated
properties, we receive a net payment from the operator for our share of sales
proceeds which is net of costs incurred by the operator, if any. Such
non-operated revenues are recognized at the net amount of proceeds received. As
a result, the separate presentation of revenues and transportation expenses from
our operated properties differs from the net presentation from non-operated
properties. This impacts the comparability of certain operating metrics, such as
per-unit sales prices, when such metrics are prepared in accordance with U.S.
GAAP using gross presentation for some revenues and net presentation for others.
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In order to provide metrics prepared in a manner consistent with how management
assesses the Company's operating results and to achieve comparability between
operated and non-operated revenues, we have presented crude oil and natural gas
sales net of transportation expenses in Management's Discussion and Analysis of
Financial Condition and Results of Operations, which we refer to as "net crude
oil and natural gas sales," a non-GAAP measure. Average sales prices calculated
using net crude oil and natural gas sales are referred to as "net sales prices,"
a non-GAAP measure, and are calculated by taking revenues less transportation
expenses divided by sales volumes, whether for crude oil or natural gas, as
applicable. Management believes presenting our revenues and sales prices net of
transportation expenses is useful because it normalizes the presentation
differences between operated and non-operated revenues and allows for a useful
comparison of net realized prices to NYMEX benchmark prices on a Company-wide
basis.
The following table presents a reconciliation of total Company crude oil and
natural gas sales (GAAP) to net crude oil and natural gas sales and related net
sales prices (non-GAAP) for 2021, 2020, and 2019.
Total Company                                       Year Ended December 31, 2021                                   Year Ended December 31, 2020                                    Year Ended December 31, 2019
In thousands                            Crude oil           Natural gas             Total              Crude oil            Natural gas             Total              Crude oil            Natural gas             Total
Crude oil and natural gas sales
(GAAP)                                $ 3,949,294          $ 1,844,447      

$5,793,741 $2,199,976 $355,458 $2,555,434 $3,929,994 $584,395 $4,514,389
Less: Freight costs

            (185,130)             (39,859)            (224,989)            (158,989)              (37,703)            (196,692)            (191,998)              (33,651)            (225,649)
Net crude oil and natural gas
sales (non-GAAP)                      $ 3,764,164          $ 1,804,588      

$5,568,752 $2,040,987 $317,755 $2,358,742 $3,737,996 $550,744 $4,288,740
Sales volumes (MBbl/MMcf/MBoe)

             58,757              370,110              120,442               58,793               306,528              109,881               72,136               311,865              124,113
Net sales price (non-GAAP)            $     64.06          $      4.88          $     46.24          $     34.71          $       1.04          $     21.47          $     51.82          $       1.77          $     34.56


The following tables present reconciliations of crude oil and natural gas sales
(GAAP) to net crude oil and natural gas sales and related net sales prices
(non-GAAP) for North Dakota Bakken and SCOOP for 2021, 2020, and 2019 as
presented in Part I, Item 1. Business-Crude Oil and Natural Gas
Operations-Production and Price History.
North Dakota Bakken                                Year Ended December 31, 2021                                    Year Ended December 31, 2020                                    Year Ended December 31, 2019
In thousands                           Crude oil            Natural gas             Total              Crude oil            Natural gas             Total              Crude oil            Natural gas             Total
Crude oil and natural gas
sales (GAAP)                         $ 2,695,738          $    549,932      

$3,245,670 $1,469,450 $24,714 $1,494,164 $2,826,136 $128,426 $2,954,562
Less: Freight costs

           (154,359)               (4,831)            (159,190)            (127,036)               (2,580)            (129,616)            (157,076)               (2,530)            (159,606)
Net crude oil and natural gas
sales (non-GAAP)                     $ 2,541,379          $    545,101      

$3,086,480 $1,342,414 $22,134 $1,364,548 $2,669,060 $125,896 $2,794,956
Sales volumes (MBbl/MMcf/MBoe)

            40,186               120,517               60,272               40,040                97,532               56,295               52,374                98,186               68,738
Net sales price (non-GAAP)           $     63.24          $       4.52          $     51.21          $     33.53          $       0.23          $     24.24          $     50.96          $       1.28          $     40.66


SCOOP                                            Year Ended December 31, 2021                                  Year Ended December 31, 2020                                 Year Ended December 31, 2019
In thousands                         Crude oil           Natural gas             Total              Crude oil           Natural gas            Total             Crude oil           Natural gas            Total
Crude oil and natural gas
sales (GAAP)                        $ 756,596          $    980,323         

$1,736,919 $486,076 $246,125 $732,201

$640,097 $277,230 $917,327
Less: Freight costs (2,854)

              (23,808)             (26,662)             (5,275)              (21,909)           (27,184)             (3,539)              (14,795)           (18,334)
Net crude oil and natural gas
sales (non-GAAP)                    $ 753,742          $    956,515          $ 1,710,257          $  480,801          $    224,216          $ 705,017          $  636,558          $    262,435          $ 898,993
Sales volumes
(MBbl/MMcf/MBoe)                       11,341               179,553               41,267              12,694               136,410             35,429              11,592               111,436             30,164

Net selling price (non-GAAP) $66.46 $5.33

 $     41.44          $    37.88          $       1.64          $   19.90          $    54.92          $       2.36          $   29.80


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PV-10

Our PV-10 value, a non-GAAP financial measure, is derived from the standardized
measure of discounted future net cash flows, which is the most directly
comparable financial measure computed using U.S. GAAP. PV-10 generally differs
from Standardized Measure because it does not include the effects of income
taxes on future net revenues. At December 31, 2021, our PV-10 totaled
approximately $20.49 billion. The standardized measure of our discounted future
net cash flows was approximately $16.64 billion at December 31, 2021,
representing a $3.86 billion difference from PV-10 due to the effect of
deducting estimated future income taxes in arriving at Standardized Measure. We
believe the presentation of PV-10 is relevant and useful to investors because it
presents the discounted future net cash flows attributable to proved reserves
held by companies without regard to the specific income tax characteristics of
such entities and is a useful measure of evaluating the relative monetary
significance of our crude oil and natural gas properties. Investors may utilize
PV-10 as a basis for comparing the relative size and value of our proved
reserves to other companies. PV-10 should not be considered as a substitute for,
or more meaningful than, the Standardized Measure as determined in accordance
with U.S. GAAP. Neither PV-10 nor Standardized Measure represents an estimate of
the fair market value of our crude oil and natural gas properties.
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