News Oil & Gas

NORTHERN OIL & GAS, INC. Management’s Discussion and Analysis of Financial Condition and Results of Operations. (form 10-Q)


Cautionary Statement Concerning Forward-Looking Statements


We are including the following discussion to inform our existing and potential
security holders generally of some of the risks and uncertainties that can
affect our company and to take advantage of the "safe harbor" protection for
forward-looking statements that applicable federal securities law affords.

From time to time, our management or persons acting on our behalf may make
forward-looking statements to inform existing and potential security holders
about our company. All statements other than statements of historical facts
included in this report regarding our financial position, business strategy,
plans and objectives of management for future operations, industry conditions,
indebtedness covenant compliance, capital expenditures, production, cash flow,
borrowing base under our revolving credit facility, our intention or ability to
pay or increase dividends on our capital stock, and impairment are
forward-looking statements. When used in this report, forward-looking statements
are generally accompanied by terms or phrases such as "estimate," "project,"
"predict," "believe," "expect," "continue," "anticipate," "target," "could,"
"plan," "intend," "seek," "goal," "will," "should," "may" or other words and
similar expressions that convey the uncertainty of future events or
outcomes. Items contemplating or making assumptions about actual or potential
future production sales, market size, collaborations, cash flows, and trends or
operating results also constitute such forward-looking statements.

Forward-looking statements involve inherent risks and uncertainties, and
important factors (many of which are beyond our company's control) that could
cause actual results to differ materially from those set forth in the
forward-looking statements, including the following:  changes in crude oil and
natural gas prices, the pace of drilling and completions activity on our current
properties and properties pending acquisition, the effects of the COVID-19
pandemic and related economic slowdown, infrastructure constraints and related
factors affecting our properties, cost inflation or supply chain disruptions,
ongoing legal disputes over and potential shutdown of the Dakota Access
Pipeline, our ability to acquire additional development opportunities, potential
or pending acquisition transactions, the projected capital efficiency savings
and other operating efficiencies and synergies resulting from our acquisition
transactions, integration and benefits of property acquisitions, or the effects
of such acquisitions on our company's cash position and levels of indebtedness,
changes in our reserves estimates or the value thereof, disruption to our
company's business due to acquisitions and other significant transactions,
general economic or industry conditions, nationally and/or in the communities in
which our company conducts business, changes in the interest rate environment,
legislation or regulatory requirements, conditions of the securities markets,
our ability to consummate any pending acquisition transactions, other risks and
uncertainties related to the closing of pending acquisition transactions, our
ability to raise or access capital, cyber-related risks, changes in accounting
principles, policies or guidelines, financial or political instability,
health-related epidemics, acts of war or terrorism, and other economic,
competitive, governmental, regulatory and technical factors affecting our
operations, products and prices.

We have based any forward-looking statements on our current expectations and
assumptions about future events. While our management considers these
expectations and assumptions to be reasonable, they are inherently subject to
significant business, economic, competitive, regulatory and other risks,
contingencies and uncertainties, most of which are difficult to predict and many
of which are beyond our control. Accordingly, results actually achieved may
differ materially from expected results described in these statements.
Forward-looking statements speak only as of the date they are made. You should
consider carefully the statements in the section entitled "Item 1A. Risk
Factors" and other sections of our Annual Report on Form 10-K for the fiscal
year ended December 31, 2021, as updated by subsequent reports we file with the
SEC (including this report), which describe factors that could cause our actual
results to differ from those set forth in the forward-looking statements. Our
Company does not undertake, and specifically disclaims, any obligation to update
any forward-looking statements to reflect events or circumstances occurring
after the date of such statements.

Overview


Our primary strategy is to invest in non-operated minority working and mineral
interests in oil and gas properties, with a core area of focus in the premier
basins within the United States. Using this strategy, we had participated in
7,957 gross (735.0 net) producing wells as of June 30, 2022. As of June 30,
2022, we had leased approximately 251,409 net acres, of which approximately 87%
were developed and all were located in the United States.

Our average daily production in the second quarter of 2022 was approximately
72,689 Boe per day, of which approximately 57% was oil. This was a 2% sequential
increase in production compared to the first quarter of 2022, primarily due to
production attributable to recent acquisitions and new wells added to
production. During the three months ended
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June 30, 2022, we added 10.1 net wells to production. This compared to 10.6 net
wells added to production in the first quarter of 2022 (excluding wells added at
closing of the Veritas Acquisition).

Our percentage of production volumes by basin for the three months ended
June 30, 2022 and 2021 were as follows:

                                                      Three Months Ended                                                                     Three Months Ended
                                                        June 30, 2022                                                                          June 30, 2021
                          Williston             Permian              Appalachian              Total              Williston             Permian  
           Appalachian              Total
Oil (Bbl)                        74  %                26  %                     -  %             100  %                 99  %                 1  %                     -  %             100  %
Natural Gas and NGLs
(Mcf)                            37  %                21  %                    42  %             100  %                 50  %                 1  %                    49  %             100  %
Total (Boe)                      58  %                24  %                    18  %             100  %                 80  %                 1  %                    19  %             100  %




Source of Our Revenues

We derive our revenues from the sale of oil, natural gas and NGLs produced from
our properties. Revenues are a function of the volume produced, the prevailing
market price at the time of sale, oil quality, Btu content and transportation
costs to market. We use derivative instruments to hedge future sales prices on a
substantial, but varying, portion of our oil and natural gas production. We
expect our derivative activities will help us achieve more predictable cash
flows and reduce our exposure to downward price fluctuations. The use of
derivative instruments has in the past, and may in the future, prevent us from
realizing the full benefit of upward price movements but also mitigates the
effects of declining price movements.

Principal Components of Our Cost Structure


•Commodity price differentials. The price differential between our well head
price for oil and the NYMEX WTI benchmark price is primarily driven by the cost
to transport oil via train, pipeline or truck to refineries. The price
differential between our well head price for natural gas and NGLs and the NYMEX
Henry Hub benchmark price is primarily driven by gathering and transportation
costs.

•Gain (loss) on commodity derivatives, net. We utilize commodity derivative
financial instruments to reduce our exposure to fluctuations in the prices of
oil and gas. Gain (loss) on commodity derivatives, net is comprised of (i) cash
gains and losses we recognize on settled commodity derivatives during the
period, and (ii) non-cash mark-to-market gains and losses we incur on commodity
derivative instruments outstanding at period end.

•Production expenses. Production expenses are daily costs incurred to bring oil
and natural gas out of the ground and to the market, together with the daily
costs incurred to maintain our producing properties. Such costs also include
field personnel compensation, salt water disposal, utilities, maintenance,
repairs and servicing expenses related to our oil and natural gas properties.

•Production taxes. Production taxes are paid on produced oil and natural gas
based on a percentage of revenues from products sold at market prices (not
hedged prices) or at fixed rates established by federal, state or local taxing
authorities. We seek to take full advantage of all credits and exemptions in our
various taxing jurisdictions. In general, the production taxes we pay correlate
to the changes in oil and natural gas revenues.

•Depreciation, depletion, amortization and accretion. Depreciation, depletion,
amortization and accretion includes the systematic expensing of the capitalized
costs incurred to acquire, explore and develop oil and natural gas properties.
As a full cost company, we capitalize all costs associated with our development
and acquisition efforts and allocate these costs to each unit of production
using the units-of-production method. Accretion expense relates to the passage
of time of our asset retirement obligations.

•General and administrative expenses. General and administrative expenses
include overhead, including payroll and benefits for our corporate staff, costs
of maintaining our headquarters, costs of managing our acquisition and
development operations, franchise taxes, audit and other professional fees and
legal compliance.

•Interest expense. We finance a portion of our working capital requirements,
capital expenditures and acquisitions with borrowings. As a result, we incur
interest expense that is affected by both fluctuations in interest rates and our
financing decisions. We capitalize a portion of the interest paid on applicable
borrowings into our unproved cost pool. We include interest expense that is not
capitalized into the full cost pool, the amortization of deferred financing
costs and
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bond premiums (including origination and amendment fees), commitment fees and
annual agency fees as interest expense.

•Income tax expense. Our provision for taxes includes both federal and state
taxes. We record our federal income taxes in accordance with accounting for
income taxes under GAAP, which results in the recognition of deferred tax assets
and liabilities for the expected future tax consequences of temporary
differences between the book carrying amounts and the tax basis of assets and
liabilities. Deferred tax assets and liabilities are measured using enacted tax
rates expected to apply to taxable income in the years in which those temporary
differences and carryforwards 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. A valuation
allowance is established to reduce deferred tax assets if it is more likely than
not that the related tax benefits will not be realized.

Selected Factors That Affect Our Operating Results

Our revenues, cash flows from operations and future growth depend substantially
upon:

•the timing and success of drilling and production activities by our operating
partners;

•the prices and the supply and demand for oil, natural gas and NGLs;

•the quantity of oil and natural gas production from the wells in which we
participate;

•changes in the fair value of the derivative instruments we use to reduce our
exposure to fluctuations in commodity prices;

•our ability to continue to identify and acquire high-quality acreage and
drilling opportunities; and

•the level of our operating expenses.


In addition to the factors that affect companies in our industry generally, the
location of substantially all of our acreage and wells in the Williston, Permian
and Appalachian Basins subjects our operating results to factors specific to
these regions. These factors include the potential adverse impact of weather on
drilling, production and transportation activities, particularly during the
winter and spring months, as well as infrastructure limitations, transportation
capacity, regulatory matters and other factors that may specifically affect one
or more of these regions.

The price at which our oil production is sold typically reflects a discount to
the NYMEX benchmark price. The price at which our natural gas production is sold
may reflect either a discount or premium to the NYMEX benchmark price. Thus, our
operating results are also affected by changes in the price differentials
between the applicable benchmark and the sales prices we receive for our
production. Our oil price differential to the NYMEX benchmark price during the
second quarter of 2022 was $2.33 per barrel, as compared to $5.46 per barrel in
the second quarter of 2021. Our net realized gas price in the second quarter of
2022 was $8.63 per Mcf, representing 115% realization relative to average Henry
Hub pricing, compared to a net realized gas price of $3.57 per Mcf in the second
quarter of 2021, which represented 122% realization relative to average Henry
Hub pricing. Fluctuations in our oil and gas price realizations are due to
several factors such as gathering and transportation costs, transportation
method, takeaway capacity relative to production levels, regional storage
capacity, seasonal refinery maintenance temporarily depressing demand, and in
the case of gas realizations, the price of NGLs.

Another significant factor affecting our operating results is drilling
costs. The cost of drilling wells can vary significantly, driven in part by
volatility in commodity prices that can substantially impact the level of
drilling activity. Generally, higher oil prices have led to increased drilling
activity, with the increased demand for drilling and completion services driving
these costs higher.  Lower oil prices have generally had the opposite effect.
In addition, individual components of the cost can vary depending on numerous
factors such as the length of the horizontal lateral, the number of fracture
stimulation stages, and the type and amount of proppant. During the first six
months of 2022, the weighted average gross authorization for expenditure (or
AFE) cost for wells we elected to participate in was $7.1 million, compared to
$6.9 million for the wells we elected to participate in during 2021.

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 continue to persist in 2022
in conjunction with the significant increase in commodity prices over the past
year, labor shortages, and other factors. Additionally, supply chain disruptions
stemming from
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the COVID-19 pandemic have led to shortages of certain materials and equipment
and resulting increases in material and labor costs. Our capital spending budget
for 2022 includes an estimate for the impact of cost inflation and, despite
inflationary pressures, we expect to continue generating significant amounts of
free cash flow at current commodity price levels.

Market Conditions


The price that we receive for the oil and natural gas we produce is largely a
function of market supply and demand. Because our oil and gas revenues are
heavily weighted toward oil, we are more significantly impacted by changes in
oil prices than by changes in the price of natural gas. World-wide supply in
terms of output, especially production from properties within the United States,
the production quota set by OPEC, and the strength of the U.S. dollar can
significantly impact oil prices. Historically, commodity prices have been
volatile and we expect the volatility to continue in the future. Factors
impacting the future oil supply balance are world-wide demand for oil, as well
as the growth in domestic oil production.

Prices for various quantities of natural gas, NGLs and oil that we produce
significantly impact our revenues and cash flows. The following table lists
average NYMEX prices for oil and natural gas for the three and six months ended
June 30, 2022 and 2021.

                                 Three Months Ended June 30,
                                      2022                   2021
Average NYMEX Prices(1)
Natural Gas (per Mcf)     $          7.50                  $  2.92
Oil (per Bbl)             $        108.59                  $ 66.19


_________

(1)Based on average NYMEX closing prices.


                                 Six Months Ended June 30,
                                     2022                 2021
Average NYMEX Prices(1)
Natural Gas (per Mcf)     $         6.07                $  3.14
Oil (per Bbl)             $       101.88                $ 62.22


_________

(1)Based on average NYMEX closing prices.


For the three months ended June 30, 2022, the average NYMEX pricing was $108.59
per barrel of oil, or 64% higher than the average NYMEX price per barrel for the
comparable period in 2021. Our realized oil price after reflecting settled
commodity derivatives was 40% higher in the second quarter of 2022 than in the
second quarter of 2021 due to higher average NYMEX price per barrel and a lower
oil price differential, partially offset by a larger loss on settled oil
derivatives in the second quarter of 2022 compared to the second quarter of
2021.

For the three months ended June 30, 2022, the average NYMEX pricing for natural
gas was $7.50 per Mcf, or 157% higher than in the comparable period in 2021. Our
realized natural gas price after reflecting settled commodity derivatives was
92% higher in the second quarter of 2022 than in the second quarter of 2021 due
to the higher average NYMEX natural gas price. However, these factors were
partially offset by a larger loss on settled natural gas derivatives and a lower
uplift from pricing on NGLs in the second quarter of 2022 compared to the second
quarter of 2021.

As of June 30, 2022, we had a total volume on open crude oil price swaps of 14.0
million barrels at a weighted average price of approximately $70.79 per barrel.
As of June 30, 2022, we had a total volume on open natural gas price swaps of
39.0 million MMbtu at a weighted average price of approximately $3.67 per MMbtu.
See Note 11 to the condensed financial statements.


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Results of Operations for the Three Months Ended June 30, 2022 and June 30, 2021

The following table sets forth selected operating data for the periods
indicated.

Three Months Ended June 30,

                                                                       2022                   2021                % Change
Net Production:
Oil (Bbl)                                                             3,801,663            3,034,442                      25  %
Natural Gas and NGLs (Mcf)                                           16,878,481           11,617,308                      45  %
Total (Boe)                                                           6,614,743            4,970,660                      33  %

Net Sales (in thousands):
Oil Sales                                                       $       403,978          $   184,269                     119  %
Natural Gas and NGL Sales                                               145,665               41,447
Gain (Loss) on Settled Commodity Derivatives                           (162,314)             (27,855)
Gain (Loss) on Unsettled Commodity Derivatives                           54,117             (173,057)

Total Revenues                                                          441,446               24,805

Average Sales Prices:
Oil (per Bbl)                                                   $        106.26          $     60.73                      75  %

Effect Loss on Settled Oil Derivatives on Average Price (per
Bbl)

                                                                     (32.53)               (8.16)
Oil Net of Settled Oil Derivatives (per Bbl)                              73.73                52.57                      40  %

Natural Gas and NGLs (per Mcf)                                             8.63                 3.57                     142  %

Effect of Loss on Settled Natural Gas Derivatives on Average
Price (per Mcf)

                                                           (2.29)               (0.27)

Natural Gas and NGLs Net of Settled Natural Gas Derivatives
(per Mcf)

                                                                  6.34                 3.30                      92  %

Realized Price on a Boe Basis Excluding Settled Commodity
Derivatives

                                                               83.09                45.41                      83  %

Effect of Loss on Settled Commodity Derivatives on Average
Price (per Boe)

                                                          (24.54)               (5.60)

Realized Price on a Boe Basis Including Settled Commodity
Derivatives

                                                               58.55                39.81                      47  %

Operating Expenses (in thousands):
Production Expenses                                             $        64,642          $    42,699                      51  %
Production Taxes                                                         43,840               18,514                     137  %
General and Administrative Expenses                                       8,064                7,604                       6  %
Depletion, Depreciation, Amortization and Accretion                      54,796               30,908                      77  %

Costs and Expenses (per Boe):
Production Expenses                                             $          9.77          $      8.59                      14  %
Production Taxes                                                           6.63                 3.72                      78  %
General and Administrative Expenses                                        1.22                 1.53                     (20) %
Depletion, Depreciation, Amortization and Accretion                        8.28                 6.22                      33  %

Net Producing Wells at Period End                                         735.0                588.6                      25  %



Oil and Natural Gas Sales

In the second quarter of 2022, our oil, natural gas and NGL sales, excluding the
effect of settled commodity derivatives, was $549.6 million compared to $225.7
million in the second quarter of 2021, driven by an 33% increase in production
and 83% increase in realized prices, excluding the effect of settled commodity
derivatives. The higher average realized price in the second quarter of 2022
compared to the same period in 2021 was driven by higher average NYMEX oil
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prices and a lower oil price differential. Oil price differential during the
second quarter of 2022 was $2.33 per barrel, as compared to $5.46 per barrel in
the second quarter of 2021. The higher average realized price in the second
quarter of 2022 as compared to the same period in 2021 was also driven by a
$5.06 per Mcf increase in realized natural gas and NGL prices, excluding the
effect of settled commodity derivatives, in the second quarter of 2022 compared
to the same period of 2021. See "Market Conditions" above.

We add production through drilling success as we place new wells into production
and through additions from acquisitions, which is offset by the natural decline
of our oil and natural gas production from existing wells. Our recent
acquisitions were a significant driver of our 33% increase in production levels
in the second quarter of 2022 compared to the same period in 2021.

Commodity Derivative Instruments


We enter into commodity derivative instruments to manage the price risk
attributable to future oil and natural gas production. Our gain (loss) on
commodity derivatives, net, was a loss of $108.2 million in the second quarter
of 2022, compared to a loss of $200.9 million in the second quarter of 2021.
Gain (loss) on commodity derivatives, net, is comprised of (i) cash gains and
losses we recognize on settled commodity derivative instruments during the
period, and (ii) unsettled gains and losses we incur on commodity derivative
instruments outstanding at period-end.

For the second quarter of 2022, we realized a loss on settled commodity
derivatives of $162.3 million, compared to a $27.9 million loss in the second
quarter of 2021. The increased loss on settled derivatives was primarily due to
a significant increase in the average NYMEX oil price in the second quarter of
2022 compared to the same period of 2021. During the second quarter of 2022, our
derivative settlements included 2.6 million barrels of oil at an average
settlement price of $60.91 per barrel. During the second quarter of 2021, our
settled commodity derivatives included 2.2 million barrels of oil at an average
settlement price of $56.38 per barrel. The average NYMEX oil price for the
second quarter of 2022 was $108.59 compared to $66.19 for the second quarter of
2021. Our average realized price (including all commodity derivative cash
settlements) in the second quarter of 2022 was $58.55 per Boe compared to $39.81
per Boe in the second quarter of 2021. The gain (loss) on settled commodity
derivatives decreased our average realized price per Boe by $24.54 in the second
quarter of 2022 and decreased our average realized price per Boe by $5.60 in the
second quarter of 2021.

Unsettled commodity derivative gains and losses was a loss of $54.1 million in
the second quarter of 2022, compared to a loss of $173.1 million in the second
quarter of 2021. Our derivatives are not designated for hedge accounting and are
accounted for using the mark-to-market accounting method whereby gains and
losses from changes in the fair value of derivative instruments are recognized
immediately into earnings. Mark-to-market accounting treatment creates
volatility in our revenues as gains and losses from unsettled derivatives are
included in total revenues and are not included in accumulated other
comprehensive income in the accompanying balance sheets. As commodity prices
increase or decrease, such changes will have an opposite effect on the
mark-to-market value of our commodity derivatives. Any gains on our unsettled
commodity derivatives are expected to be offset by lower wellhead revenues in
the future, while any losses are expected to be offset by higher future wellhead
revenues based on the value at the settlement date. At June 30, 2022, all of our
derivative contracts are recorded at their fair value, which was a net liability
of $606.0 million, a change of $328.3 million from the $277.7 million net
liability recorded as of December 31, 2021. The increased liability at June 30,
2022 as compared to December 31, 2021 was primarily due to changes in forward
commodity prices relative to prices on our open commodity derivative contracts
since December 31, 2021. Our open commodity derivative contracts are summarized
in "Item 3. Quantitative and Qualitative Disclosures about Market Risk-Commodity
Price Risk."

Production Expenses

Production expenses were $64.6 million in the second quarter of 2022, compared
to $42.7 million in the second quarter of 2021. On a per unit basis, production
expenses increased from $8.59 per Boe in the second quarter of 2021 to $9.77 per
Boe in the second quarter of 2022, due in large part to a $4.8 million firm
transport charge on our Appalachian Basin properties, and higher processing
costs due in part to elevated NGL pricing, which drives increased payments under
percentage of proceeds contracts. On an absolute dollar basis, the increase in
our production expenses in the second quarter of 2022, as compared to the second
quarter of 2021, was primarily due to a 33% increase in production volumes, a
25% increase in the total number of net producing wells and the aforementioned
firm transport charge and higher processing costs.



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Production Taxes

We pay production taxes based on realized oil and natural gas sales. Production
taxes were $43.8 million in the second quarter of 2022 compared to $18.5 million
in the second quarter of 2021. The increase is due to higher production and
higher realized prices, which significantly increased our oil and natural gas
sales in the second quarter of 2022 as compared to the second quarter of 2021.
As a percentage of oil and natural gas sales, our production taxes were 8.0% and
8.2% in the second quarter of 2022 and 2021, respectively. The fluctuation in
our average production tax rate from year to year is primarily due to changes in
our oil sales as a percentage of our total oil and gas sales as well as the mix
of our production by basin. Oil sales are taxed at a higher rate than natural
gas sales.

General and Administrative Expenses


General and administrative expenses were $8.1 million in the second quarter of
2022 compared to $7.6 million in the second quarter of 2021. The increase was
primarily due to increases of $1.7 million in compensation expense, $0.5 million
in professional fees, and $0.8 million from the timing of other expenditures,
which was partially offset by a reduction of $2.5 million in acquisition-related
costs in the second quarter of 2022 as compared to the second quarter of 2021.

Depletion, Depreciation, Amortization and Accretion


Depletion, depreciation, amortization and accretion ("DD&A") was $54.8 million
in the second quarter of 2022, compared to $30.9 million in the second quarter
of 2021. Depletion expense, the largest component of DD&A, increased by $23.7
million in the second quarter of 2022 compared to the second quarter of 2021.
The aggregate increase in depletion expense was driven by a 33% increase in
production levels and a 34% increase in the depletion rate per Boe. On a per
unit basis, depletion expense was $8.17 per Boe in the second quarter of 2022
compared to $6.11 per Boe in the second quarter of 2021. The higher depletion
rate per Boe was primarily driven by the closing of our CM Resources Acquisition
and Comstock Acquisitions in the second half of 2021, coupled with our Veritas
Acquisition in Q1 2022, which significantly increased our depletable base.
Depreciation, amortization and accretion was $0.7 million and $0.5 million in
the second quarter of 2022 and 2021, respectively. The following table
summarizes DD&A expense per Boe for the second quarter of 2022 and 2021:

                                                                             Three Months Ended June 30,
                                                           2022               2021            $ Change             % Change
Depletion                                              $     8.17          $  6.11          $    2.06                     34  %
Depreciation, Amortization and Accretion                     0.11             0.11                  -                      -  %
Total DD&A Expense                                     $     8.28          $  6.22          $    2.06                     33  %



Interest Expense

Interest expense, net of capitalized interest, was $18.4 million in the second
quarter of 2022 compared to $15.0 million in the second quarter of 2021. The
increase was primarily due to higher levels of debt in the second quarter of
2022 compared to the second quarter of 2021.

Gain (Loss) on the Extinguishment of Debt


  During the second quarter of 2022, we recorded a gain on the extinguishment of
debt of $0.2 million, based on the differences between the reacquisition costs
of retiring the applicable debt and the net carrying values thereof. As a result
of our refinancing transactions during the second quarter of 2021, we recorded a
loss on the extinguishment of debt of $0.5 million based on the differences
between the reacquisition costs of retiring the applicable debt and the net
carrying values thereof.

Income Tax

During the second quarter of 2022, we recorded income tax expense of $1.0
million
related to state income taxes. During the second quarter of 2021, no
income tax expense (benefit) was recorded. We continue to maintain a full
valuation allowance placed on our net deferred tax asset because of the
uncertainty regarding its realization.


We intend to continue maintaining a full valuation allowance on our deferred tax
assets until there is sufficient evidence to support the reversal of all or some
portion of these allowances. Release of any portion of the valuation allowance
would result in the recognition of certain deferred tax assets and a decrease to
income tax expense for the period the release is
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recorded. However, the exact timing and amount of the valuation allowance
release are subject to change on the basis of the level of profitability that we
are able to actually achieve. For further discussion of our valuation allowance,
see Note 9 to our condensed financial statements.


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Results of Operations for the Six Months Ended June 30, 2022 and June 30, 2021

The following table sets forth selected operating data for the periods
indicated.

Six Months Ended June 30,

                                                                         2022                     2021                % Change
Net Production:
Oil (Bbl)                                                            7,625,685                 5,664,620                      35  %
Natural Gas and NGLs (Mcf)                                          32,412,120                16,581,571                      95  %
Total (Boe)                                                         13,027,705                 8,428,215                      55  %

Net Sales (in thousands):
Oil Sales                                                       $      752,708               $   319,917                     135  %
Natural Gas and NGL Sales                                              253,393                    63,131
Gain (Loss) on Settled Commodity Derivatives                          (267,475)                  (35,152)
Gain (Loss) on Unsettled Commodity Derivatives                        (330,110)                 (301,695)

Total Revenues                                                         408,516                    46,202

Average Sales Prices:
Oil (per Bbl)                                                   $        98.71               $     56.48                      75  %

Effect of Gain (Loss) on Settled Oil Derivatives on Average
Price (per Bbl)

                                                         (29.31)                    (5.45)
Oil Net of Settled Oil Derivatives (per Bbl)                             69.40                     51.03                      36  %

Natural Gas and NGLs (per Mcf)                                            7.82                      3.81                     105  %

Effect of Gain (Loss) on Settled Natural Gas Derivatives on
Average Price (per Mcf)

                                                  (1.64)                    (0.26)

Natural Gas and NGLs Net of Settled Natural Gas Derivatives
(per Mcf)

                                                                 6.18                      3.55                      74  %

Realized Price on a Boe Basis Excluding Settled Commodity
Derivatives

                                                              77.23                     45.45                      70  %

Effect of Gain (Loss) on Settled Commodity Derivatives on
Average Price (per Boe)

                                                 (20.53)                    (4.17)

Realized Price on a Boe Basis Including Settled Commodity
Derivatives

                                                              56.70                     41.28                      37  %

Operating Expenses (in thousands):
Production Expenses                                             $      119,181               $    77,010                      55  %
Production Taxes                                                        78,455                    31,967                     145  %
General and Administrative Expenses                                     21,879                    14,388                      52  %
Depletion, Depreciation, Amortization and Accretion                    107,980                    62,128                      74  %

Costs and Expenses (per Boe):
Production Expenses                                             $         9.15               $      9.14                       -  %
Production Taxes                                                          6.02                      3.79                      59  %
General and Administrative Expenses                                       1.68                      1.71                      (2) %
Depletion, Depreciation, Amortization and Accretion                       8.29                      7.37                      12  %

Net Producing Wells at Period End                                        735.0                     588.6                      25  %



Oil and Natural Gas Sales


In the first six months of 2022, our oil, natural gas and NGL sales, excluding
the effect of settled commodity derivatives, was $1,006.1 million compared to
$383.0 million in the first six months of 2021, driven by a 55% increase in
production and 70% increase in realized prices, excluding the effect of settled
commodity derivatives. The higher average realized price in the first six months
of 2022 compared to the same period in 2021 was driven by higher average NYMEX
oil
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prices and a lower oil price differential. Oil price differential during the
first six months of 2022 was $3.17 per barrel, as compared to $5.74 per barrel
in the first six months of 2021. The higher average realized price in the first
six months of 2022 as compared to the same period in 2021 was also driven by a
$4.01 per Mcf increase in realized natural gas and NGL prices, excluding the
effect of settled commodity derivatives, in the first six months of 2022
compared to the same period of 2021. See "Market Conditions" above.

We add production through drilling success as we place new wells into production
and through additions from acquisitions, which is offset by the natural decline
of our oil and natural gas production from existing wells. Our recent
acquisitions were a significant driver of our 55% increase in production levels
in the first six months of 2022 compared to the same period in 2021.

Commodity Derivative Instruments


We enter into commodity derivative instruments to manage the price risk
attributable to future oil and natural gas production. Our gain (loss) on
commodity derivatives, net, was a loss of $597.6 million in the first six months
of 2022, compared to a loss of $336.8 million in the first six months of 2021.
Gain (loss) on commodity derivatives, net, is comprised of (i) cash gains and
losses we recognize on settled commodity derivative instruments during the
period, and (ii) unsettled gains and losses we incur on commodity derivative
instruments outstanding at period-end.

For the first six months of 2022, we realized a loss on settled commodity
derivatives of $267.5 million, compared to a $35.2 million loss in the first six
months of 2021. The decrease in settled derivatives was primarily due to a
significant increase in the average NYMEX oil price in the first six months of
2022 compared to the same period of 2021. During the first six months of 2022,
our derivative settlements included 5.29 million barrels of oil at an average
settlement price of $60.84 per barrel. During the first six months of 2021, our
settled commodity derivatives included 4.4 million barrels of oil at an average
settlement price of $56.02 per barrel. The average NYMEX oil price for the first
six months of 2022 was $101.88 compared to $62.22 for the first six months of
2021. Our average realized price (including all commodity derivative cash
settlements) in the first six months of 2022 was $56.70 per Boe compared to
$41.28 per Boe in the first six months of 2021. The gain (loss) on settled
commodity derivatives decreased our average realized price per Boe by $20.53 in
the first six months of 2022 and decreased our average realized price per Boe by
$4.17 in the first six months of 2021.

Unsettled commodity derivative gains and losses was a loss of $330.1 million in
the first six months of 2022, compared to a loss of $301.7 million in the first
six months of 2021. Our derivatives are not designated for hedge accounting and
are accounted for using the mark-to-market accounting method whereby gains and
losses from changes in the fair value of derivative instruments are recognized
immediately into earnings. Mark-to-market accounting treatment creates
volatility in our revenues as gains and losses from unsettled derivatives are
included in total revenues and are not included in accumulated other
comprehensive income in the accompanying balance sheets. As commodity prices
increase or decrease, such changes will have an opposite effect on the
mark-to-market value of our commodity derivatives. Any gains on our unsettled
commodity derivatives are expected to be offset by lower wellhead revenues in
the future, while any losses are expected to be offset by higher future wellhead
revenues based on the value at the settlement date. At June 30, 2022, all of our
derivative contracts are recorded at their fair value, which was a net liability
of $606.0 million, a change of $328.3 million from the $277.7 million net
liability recorded as of December 31, 2021. The increased liability at June 30,
2022 as compared to December 31, 2021 was primarily due to changes in forward
commodity prices relative to prices on our open commodity derivative contracts
since December 31, 2021. Our open commodity derivative contracts are summarized
in "Item 3. Quantitative and Qualitative Disclosures about Market Risk-Commodity
Price Risk."

Production Expenses

Production expenses were $119.2 million in the second quarter of 2022, compared
to $77.0 million in the first six months of 2021. On a per unit basis,
production expenses were essentially flat at $9.15 per Boe in the first six
months of 2022, compared to $9.14 per Boe in the first six months of 2021.
Although essentially flat on a per unit basis, increases were driven by a $5.4
million firm transport charge on our Appalachian Basin properties and higher
processing costs, which were largely offset by a 55% increase in our production
volumes, which increased the production base over which fixed costs are spread.
On an absolute dollar basis, the increase in our production expenses in the
first six months of 2022, as compared to the first six months of 2021, was
primarily due to a 55% increase in production volumes and a 25% increase in the
total number of net producing wells and the aforementioned firm transport charge
and higher processing costs.



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Production Taxes

We pay production taxes based on realized oil and natural gas sales. Production
taxes were $78.5 million in the first six months of 2022 compared to $32.0
million in the first six months of 2021. The increase is due to higher
production and higher realized prices, which significantly increased our oil and
natural gas sales in the first six months of 2022 as compared to the first six
months of 2021. As a percentage of oil and natural gas sales, our production
taxes were 7.8% and 8.3% in the first six months of 2022 and 2021, respectively.
The fluctuation in our average production tax rate from year to year is
primarily due to changes in our oil sales as a percentage of our total oil and
gas sales. Oil sales are taxed at a higher rate than natural gas sales.

General and Administrative Expenses


General and administrative expenses were $21.9 million in the first six months
of 2022 compared to $14.4 million in the first six months of 2021. The increase
was primarily due to increases of $2.9 million in compensation costs, $1.8
million in acquisition-related costs, and $1.5 million of professional fees in
the first six months of 2022 compared to the first six months of 2021.

Depletion, Depreciation, Amortization and Accretion


Depletion, depreciation, amortization and accretion ("DD&A") was $108.0 million
in the first six months of 2022, compared to $62.1 million in the first six
months of 2021. Depletion expense, the largest component of DD&A, increased by
$45.5 million in the first six months of 2022 compared to the first six months
of 2021. The aggregate increase in depletion expense was driven by a 55%
increase in production levels and a 13% increase in the depletion rate per Boe.
On a per unit basis, depletion expense was $8.19 per Boe in the first six months
of 2022 compared to $7.26 per Boe in the first six months of 2021. The higher
depletion rate per Boe was primarily driven by the closing of our CM Resources
Acquisition and Comstock Acquisitions in the second half of 2021, coupled with
our Veritas Acquisition in Q1 2022, which significantly increased our depletable
base. Depreciation, amortization and accretion was $1.3 million and $1.0 million
in the first six months of 2022 and 2021, respectively. The following table
summarizes DD&A expense per Boe for the first six months of 2022 and 2021:

                                                            Six Months Ended June 30,
                                                  2022             2021       $ Change       % Change
 Depletion                                  $    8.19            $ 7.26      $    0.93           13  %
 Depreciation, Amortization and Accretion        0.09              0.11          (0.02)         (18) %
 Total DD&A Expense                         $    8.28            $ 7.37      $    0.91           12  %



Interest Expense

Interest expense, net of capitalized interest, was $36.4 million in the first
six months of of 2022 compared to $28.5 million in the first six months of 2021.
The increase was primarily due to higher levels of debt in the first six months
of 2022 compared to the first six months of 2021.

Gain (Loss) on the Extinguishment of Debt


  During the first six months of 2022, we recorded a gain on the extinguishment
of debt of $0.2 million based on the differences between the reacquisition costs
of retiring the applicable debt and the net carrying values thereof. As a result
of our refinancing transactions during the first six months of 2021, we recorded
a loss on the extinguishment of debt of $13.1 million based on the differences
between the reacquisition costs of retiring the applicable debt and the net
carrying values thereof.

Income Tax

During the first six months of 2022, we recorded income tax expense of $1.8
million
related to state income taxes. During the first six months of 2021, no
income tax expense (benefit) was recorded. We continue to maintain a full
valuation allowance placed on our net deferred tax asset because of the
uncertainty regarding its realization.


We intend to continue maintaining a full valuation allowance on our deferred tax
assets until there is sufficient evidence to support the reversal of all or some
portion of these allowances. Release of any portion of the valuation allowance
would result in the recognition of certain deferred tax assets and a decrease to
income tax expense for the period the release is
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recorded. However, the exact timing and amount of the valuation allowance
release are subject to change on the basis of the level of profitability that we
are able to actually achieve. For further discussion of our valuation allowance,
see Note 9 to our condensed financial statements.

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Liquidity and Capital Resources

Overview


Our main sources of liquidity and capital resources as of the date of this
report have been internally generated cash flow from operations, proceeds from
equity and debt financings, credit facility borrowings, and cash settlements of
commodity derivative instruments. Our primary uses of capital have been for the
acquisition and development of our oil and natural gas properties. We
continually monitor potential capital sources for opportunities to enhance
liquidity or otherwise improve our financial position.

During the six months ended June 30, 2022, we repurchased and retired (i)
575,000 shares of our 6.500% Series A Perpetual Cumulative Convertible Preferred
Stock (the "Series A Preferred Stock") for total consideration of $81.2 million,
(ii) 447,051 shares of our common stock for total consideration of $12.8 million
and (iii) $13.4 million aggregate principal amount of our 2028 Notes for total
consideration of $13.1 million, plus accrued interest.

As of June 30, 2022, we had outstanding debt consisting of $367.0 million of
borrowings under our Revolving Credit Facility and $736.6 million aggregate
principal amount of our 2028 Notes. We had total liquidity of $484.5 million as
of June 30, 2022, consisting of $483.0 million of committed borrowing
availability under the Revolving Credit Facility and $1.5 million of cash on
hand.

One of the primary sources of variability in our cash flows from operating
activities is commodity price volatility. Oil accounted for 57% and 61% of our
total production volumes in the second quarter of 2022 and 2021, respectively.
As a result, our operating cash flows are more sensitive to fluctuations in oil
prices than they are to fluctuations in natural gas and NGL prices.  We seek to
maintain a robust hedging program to mitigate volatility in commodity prices
with respect to a portion of our expected production. For the six months ended
June 30, 2022, we hedged approximately 61% of our production. For a summary as
of June 30, 2022, of our open commodity swap contracts for future periods, see
"Quantitative and Qualitative Disclosures about Market Risk" in Part I, Item 3
below.

With our cash on hand, cash flow from operations, and borrowing capacity under
our Revolving Credit Facility, we believe that we will have sufficient cash flow
and liquidity to fund our budgeted capital expenditures and operating expenses
for at least the next twelve months. However, we may seek additional access to
capital and liquidity.  We cannot assure you, however, that any additional
capital will be available to us on favorable terms or at all.

Our recent capital commitments have been to fund acquisitions and development of
oil and natural gas properties. We expect to fund our near-term capital
requirements and working capital needs with cash flows from operations and
available borrowing capacity under our Revolving Credit Facility.  Our capital
expenditures could be curtailed if our cash flows decline from expected levels.
Because production from existing oil and natural gas wells declines over time,
reductions of capital expenditures used to drill and complete new oil and
natural gas wells would likely result in lower levels of oil and natural gas
production in the future.

Working Capital

Our working capital balance fluctuates as a result of changes in commodity
pricing and production volumes, collection of receivables, expenditures related
to our development and production operations and the impact of our outstanding
derivative instruments.

At June 30, 2022, we had a working capital deficit of $253.1 million, compared
to $112.2 million working capital deficit at December 31, 2021. Current assets
increased by $167.5 million and current liabilities increased by $308.4 million
at June 30, 2022, compared to December 31, 2021. The increase in current assets
is primarily due to a $167.3 million increase in our accounts receivable due to
higher commodity prices and higher production. The change in current liabilities
is due to a $209.3 million increase in our derivative instruments due to the
change in fair value as a result of the higher commodity price environment, and
a $97.9 million increase in our accounts payable and accrued liabilities due in
part to increased completion activity levels on our properties.

Cash Flows


Cash flows from operations are primarily affected by production volumes and
commodity prices, net of the effects of settlements of our derivative contracts,
and by changes in working capital. Any interim cash needs are funded by cash on
hand,
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cash flows from operations or borrowings under our Revolving Credit Facility.
The Company typically enters into commodity derivative transactions covering a
substantial, but varying, portion of its anticipated future oil and gas
production for the next 12 to 24 months. Our cash flows for the six months ended
June 30, 2022 and 2021 are presented below:

                                                 Six Months Ended
                                                     June 30,
(In thousands, unaudited)                      2022           2021

Net Cash Provided by Operating Activities $ 364,273 $ 168,952 Net Cash Used for Investing Activities (545,777) (213,541)
Net Cash Provided by Financing Activities 173,456 48,004
Net Change in Cash

                          $  (8,048)     $   3,415



Cash Flows from Operating Activities


Net cash provided by operating activities for the six months ended June 30, 2022
was $364.3 million, compared to $169.0 million in the same period of the prior
year. This increase was due to higher production volumes and higher realized
commodity prices (including the effect of settled derivatives), which was
partially offset by higher operating costs and interest costs, as well as
changes in working capital. Net cash provided by operating activities is
affected by working capital changes or the timing of cash receipts and
disbursements. Changes in working capital and other items (as reflected in our
statements of cash flows) in the six months ended June 30, 2022 was a deficit of
$122.9 million compared to a deficit of $33.0 million in the same period of the
prior year.

Cash Flows from Investing Activities


Cash flows used in investing activities during the six months ended June 30,
2022 and 2021 were $545.8 million and $213.5 million, respectively. The increase
in cash used in investing activities for the first six months of 2022 as
compared to the same period of 2021 was attributable to a $320.1 million
increase in our development and acquisition spending, which included the closing
of our Veritas Acquisition in the first quarter of 2022. Additionally, the
amount of capital expenditures included in accounts payable (and thus not
included in cash flows from investing activities) was $159.0 million and
$101.0 million at June 30, 2022 and 2021, respectively.

Our cash flows used in investing activities reflects actual cash spending, which
can lag several months from when the related costs were incurred. As a result,
our actual cash spending is not always reflective of current levels of
development activity. For instance, during the six months ended June 30, 2022,
our capitalized costs incurred for oil and natural gas properties (e.g.,
drilling and completion costs, acquisitions, and other capital expenditures)
amounted to $620.6 million, while the actual cash spend in this regard amounted
to $524.2 million.

Development and acquisition activities are discretionary. We monitor our capital
expenditures on a regular basis, adjusting the amount up or down, and between
projects, depending on projected commodity prices, cash flows and returns. Our
cash spend for development and acquisition activities for the six months ended
June 30, 2022 and 2021 are summarized in the following table:

                                                    Six Months Ended
                                                        June 30,
(In millions, unaudited)                           2022          2021

Drilling and Development Capital Expenditures $ 152.9 $ 72.6
Acquisition of Oil and Natural Gas Properties 369.7 130.8
Other Capital Expenditures

                            1.6          0.7
Total                                           $   524.2      $ 204.1



Cash Flows from Financing Activities


Net cash provided by financing activities was $173.5 million during the six
months ended June 30, 2022, compared to net cash used for financing activities
of $48.0 million during the six months ended June 30, 2021. For the six months
ended June 30, 2022, cash provided by financing activities was primarily related
to $312.0 million of net advances under our
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Revolving Credit Facility, which was partially offset by $81.2 million in
repurchases of preferred stock, $12.8 million in repurchases of common stock,
$17.0 million of common stock dividend payments, and $5.9 million of preferred
stock dividend payments. For the six months ended June 30, 2021, cash used for
financing activities was primarily related to $295.9 million in repurchases of
Second Lien Notes, net repayments under our Revolving Credit Facility of $269.0
million and the retirement of VEN Bakken Note for $130.0 million, which was
partially offset by the net proceeds of our 2028 Notes of $537.6 million and
equity offerings of $228.2 million.

Revolving Credit Facility


In June 2022, we entered into the Revolving Credit Facility with Wells Fargo
Bank, as administrative agent, and the lenders from time to time party thereto,
which amended and restated our existing revolving credit facility that was
entered into in November 2019. The Revolving Credit Facility is subject to a
borrowing base with maximum loan value to be assigned to the proved reserves
attributable to our oil and gas properties. As of June 30, 2022, the Revolving
Credit Facility had a borrowing base of $1.3 billion and an elected commitment
amount of $850.0 million, and we had $367.0 million in borrowings outstanding
under the facility, leaving $483.0 million in available committed borrowing
capacity. See Note 4 to our condensed financial statements for further details
regarding the Revolving Credit Facility.

Unsecured Notes due 2028

As of June 30, 2022, we had outstanding $736.6 million aggregate principal
amount of our 2028 Notes. See Note 4 to our condensed financial statements for
further details regarding the 2028 Notes.

Series A Preferred Stock


As of June 30, 2022, we had 1,643,732 outstanding shares of 6.500% Series A
Perpetual Cumulative Convertible Preferred Stock (the "Series A Preferred
Stock"), having an aggregate liquidation preference of $164.4 million (excluding
accumulated dividends). See Note 5 to our condensed financial statements for
further details regarding the Series A Preferred Stock.

Effects of Inflation and Pricing


The oil and natural gas industry is very cyclical and the demand for goods and
services of oil field companies, suppliers and others associated with the
industry put extreme pressure on the economic stability and pricing structure
within the industry. Typically, as prices for oil and natural gas increase, so
do all associated costs. Conversely, in a period of declining prices, associated
cost declines are likely to lag and may not adjust downward in
proportion. Material changes in prices also impact our current revenue stream,
estimates of future reserves, borrowing base calculations of bank loans,
impairment assessments of oil and natural gas properties, and values of
properties in purchase and sale transactions. Material changes in prices can
impact the value of oil and natural gas companies and their ability to raise
capital, borrow money and retain personnel. Higher prices for oil and natural
gas could result in increases in the costs of materials, services and personnel,
which we expect to occur in 2022 compared to 2021.

Contractual Obligations and Commitments

Please see our disclosure of contractual obligations and commitments as of
December 31, 2021, included in Part II, Item 7 of our Annual Report on Form 10-K
for the fiscal year ended December 31, 2021.

Critical Accounting Estimates


Critical accounting estimates are those estimates made in accordance with GAAP
that involve a significant level of estimation uncertainty and have had or are
reasonably likely to have a material impact on our financial condition or
results of operations. Our critical accounting estimates include impairment
testing of natural gas and crude oil production properties, asset retirement
obligations, revenue recognition, derivative instruments and hedging activity,
and income taxes. There were no material changes in our critical accounting
estimates from those reported in our Annual Report on Form 10-K for the fiscal
year ended December 31, 2021.

A description of our critical accounting policies was provided in Note 2 to our
financial statements provided in Part II, Item 8 of our Annual Report on Form
10-K for the fiscal year ended December 31, 2021.


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