FORAGE INDEPENDENCE AGREEMENT, INC. MANAGEMENT REPORT AND ANALYSIS OF FINANCIAL POSITION AND OPERATING RESULTS (Form 10-K)

You should read the following discussion and analysis of our financial condition
and results of operations together with the consolidated financial statements
and related notes that are included in "Item 8. Financial Statements and
Supplementary Data." This discussion contains forward-looking statements based
upon current expectations that involve risks and uncertainties. Our actual
results may differ materially from those anticipated in these forward-looking
statements as a result of various factors, including without limitation those
described in Cautionary Statement Regarding Forward-Looking Statements and
"Item 1A. Risk Factors" or in other parts of this Annual Report on Form 10-K.

Discussions of matters pertaining to the year ended December 31, 2019
and year-to-year comparisons between the years ended December 31, 2020 and 2019
are not included in this Form 10-K, but can be found under Part II, Item 7 of
our Annual Report on Form 10-K for the year ended December 31, 2020 that was
filed on March 1, 2021.

Management Overview

We have been incorporated into Delaware to November 4, 2011. We provide onshore contract drilling services to oil and natural gas producers targeting unconventional resource deposits in United States. We own and operate a top of the line fleet of modern and technologically advanced drilling rigs.

Our rig fleet includes 24 commercialized alternating current (“AC”) powered rigs, plus additional AC rigs that require significant capital expenditure in order to meet our optimal AC pad specifications that we do not expect to market unless market conditions improve significantly. Our first rig started drilling in May 2012.

We currently focus our operations on unconventional resource plays located in
geographic regions that we can efficiently support from our Houston, Texas and
Midland, Texas facilities in order to maximize economies of scale. Currently,
our rigs are operating in the Permian Basin, the Haynesville Shale and the Eagle
Ford Shale; however, our rigs have previously operated in the Mid-Continent and
Eaglebine regions as well.

Our business depends on the level of exploration and production activity by oil
and natural gas companies operating in the United States, and in particular, the
regions where we actively market our contract drilling services. The oil and
natural gas exploration and production industry is historically cyclical and
characterized by significant changes in the levels of exploration and
development activities. Oil and natural gas prices and market expectations of
potential changes in those prices significantly affect the levels of those
activities. Worldwide political, regulatory, economic, and military events, as
well as natural disasters have contributed to oil and natural gas price
volatility historically, and are likely to continue to do so in the future. Any
prolonged reduction in the overall level of exploration and development
activities in the United States and the regions where we market our contract
drilling services, whether resulting from changes in oil and natural gas prices
or otherwise, could materially and adversely affect our business.

Significant developments

Update on the COVID-19 pandemic and market conditions

During 2020, reduced demand for crude oil related to the COVID-19 pandemic,
combined with production increases from OPEC+ early in the year, led to a
significant reduction in oil prices and demand for drilling services in the
United States. In response to these adverse conditions and uncertainty, our
customers reduced planned capital expenditures and drilling activity throughout
2020. During the first quarter of 2020, our operating rig count reached a peak
of 22 rigs and temporarily reached a low of three rigs during the third quarter
of 2020. During the third quarter of 2020, oil and natural gas prices began to
stabilize and steadily improve, and demand for our products began to modestly
improve from their historic lows, which allowed us to reactivate additional rigs
during the back half of 2020 and throughout 2021. As market conditions improved,
dayrates and our revenue per day also began to steadily improve for our contract
drilling services, in particular during the second half of 2021. Recently, oil
prices (WTI-Cushing) reached a high of $96.13 per barrel on February 28, 2022,
and natural gas prices (Henry Hub) reached a high of $6.70 per mmcf on February
2, 2022. Although our customers have increased drilling activity in response to
these improvements, capital

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discipline and adherence to 2021 capital budgets, reduced access to capital
markets and hedges in place based on lower commodity prices, have caused such
increases to be less dramatic compared to prior industry cycles. As of
December 31, 2021, we had 16 rigs operating and 17 contracted, with our 17th rig
reactivating in January 2022.

Due to rapidly declining market conditions at the end of the first quarter of
2020, we took actions in order to reduce our cost structure including: salary or
compensation reductions, suspension of all cash-based incentive compensation,
reduction of the number of executive management and directors, reduction of
annual director compensation and reduction of non-field-based personnel
headcount. As market conditions improved in 2021, we reinstated our incentive
compensation accruals and increased field pay in response to tighter labor
markets. As of January 1, 2022, we have fully reinstitued pre-COVID compensation
levels and in many cases increased compensation above pre-COVID levels in
response to a tightening labor market.

On March 27, 2020, President Trump signed into law the "Coronavirus Aid, Relief,
and Economic Security (CARES) Act." The CARES Act, among other things, includes
provisions relating to refundable payroll tax credits, deferment of employer
side social security payments, net operating loss carryback periods, alternative
minimum tax credit refunds, modifications to the net interest deduction
limitations, increased limitations on qualified charitable contributions, and
technical corrections to tax depreciation methods for qualified improvement
property. We deferred $0.8 million of employer social security payments during
the year ended December 31, 2020. We made the first required payment of $0.4
million on January 3, 2022.

The CARES Act did not have a material impact on our income taxes. Management
will continue to monitor future developments and interpretations for any further
impacts on our financial condition, results of operations, or liquidity.

PPP loan

During the second quarter of 2020, we entered into an unsecured loan in the
aggregate principal amount of $10.0 million (the "PPP Loan") pursuant to the
Paycheck Protection Program (the "PPP"), sponsored by the Small Business
Administration (the "SBA") as guarantor of loans under the PPP. The PPP was part
of the CARES Act, and it provided loans to qualifying businesses in a maximum
amount equal to the lesser of $10.0 million and 2.5 times the average monthly
payroll expenses of the qualifying business. The proceeds of the loan could only
be used for payroll costs, rent, utilities, mortgage interests, and interest on
other pre-existing indebtedness (the "permissible purposes") during the covered
period that ended on or about October 13, 2020. Interest on the PPP loan was
equal to 1.0% per annum. All or part of the loan was forgivable based upon the
level of permissible expenses incurred during the covered period and changes to
the Company's headcount during the covered period to headcount during the period
from January 1, 2020 to February 15, 2020. In the third quarter of 2021, we
received notice from the SBA that our loan was forgiven and paid in full. The
loan is considered an extinguishment of debt and is recorded as "Gain on
extinguishment of debt" in our 2021 Statements of Operations. We have not
accrued any liability associated with the risk of an adverse SBA review.

Common Share Purchase Agreement

On November 11, 2020, we entered into a Common Stock Purchase Agreement (the
"Commitment Purchase Agreement") and a Registration Rights Agreement (the
"Registration Rights Agreement") with Tumim Stone Capital LLC ("Tumim").
Pursuant to the Commitment Purchase Agreement, the Company had the right to sell
to Tumim up to $5.0 million (the "Total Commitment") in shares of its common
stock, par value $0.01 per share (the "Shares") (subject to certain conditions
and limitations) from time to time during the term of the Commitment Purchase
Agreement. Sales of common stock pursuant to the Commitment Purchase Agreement,
and the timing of any sales, were solely at our option and we were under no
obligation to sell securities pursuant to this arrangement. Shares could be sold
by the Company pursuant to this arrangement over a period of up to 24 months,
commencing on December 1, 2020.

We determined that the right to sell additional shares represented a
freestanding put option under ASC 815 Derivatives and Hedging, but had a fair
value of zero, and therefore no additional accounting was required. Transaction
costs, of $0.5 million, incurred in connection with entering into the Purchase
Agreement were expensed as selling,

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general and administrative expense during the fourth quarter of 2020. As of
December 31, 2021, we had sold 1,144,000 shares for a total of $4.2 million in
proceeds at an average sales price of $3.71 per share. On December 14, 2021, the
agreement was terminated and no further shares were sold.

Amendments to the Term Credit Agreement

On June 4, 2020, we revised our Term Loan Credit Agreement to elect to pay
accrued and unpaid interest, solely during one three-consecutive-month period
immediately following such notice, in-kind (the "PIK Amount"). We agreed to pay
an additional amount equal to 0.75% of the aggregate principal amount of the
loans under the Term Loan Credit Agreement plus all PIK Amounts, if any, that
are added to such principal amount being repaid or prepaid on either the
maturity date or upon the occurrence of an acceleration of obligations under the
Term Loan Credit Agreement. On April 1, 2021, we elected to pay in-kind the $2.8
million interest payment due under our Term Loan, which increased our Term Loan
balance accordingly.

On September 28, 2021, we executed a Fourth Amendment (the "Fourth Amendment")
to the Term Loan Credit Agreement, dated as of October 1, 2018 (the "Term Loan
Credit Agreement"), which amended the Term Loan Credit Agreement to permit us,
at our option, subject to required prior notice, to elect to pay accrued and
unpaid interest due October 1, 2021, in-kind. The payment-in-kind was in lieu of
exercising a drawdown under the Accordion under the Term Loan Credit Agreement,
thus, the amount of the Term Loan Accordion commitment of $15 million was
reduced by the PIK Amount. On September 29, 2021, we elected to pay in-kind the
$3.1 million October 1, 2021 interest payment.

On December 30, 2021 we executed a Fifth Amendment (the "Fifth Amendment") to
the Term Loan Credit Agreement, dated as of October 1, 2018, to permit us, at
our option, subject to prior notice, to elect to pay accrued and unpaid interest
due January 1, 2022 in-kind. The payment-in-kind was in lieu of exercising a
drawdown under the Accordion under the Term Loan Credit Agreement, thus the
amount of the Term Loan Accordion commitment was further reduced by the PIK
Amount. On December 30, 2021, we elected to pay in-kind the $3.2 million January
3, 2022 interest payment. Following this payment-in-kind on January 1, 2022, the
Term Loan Accordion commitment was $8.7 million.

ATM offer

On June 5, 2020, we entered into an equity distribution agreement (the
"Agreement") with Piper Sandler & Co. (the "Agent"), through its Simmons Energy
division. Pursuant to the Agreement, we were able to offer and sell through the
Agent shares of our common stock, par value $0.01 per share, having an aggregate
offering price of up to $11.0 million. We issued and sold approximately $11.0
million of common stock in the second and third quarters of 2020.

On March 8, 2021, in conjunction with the ATM Distribution Agreement entered
into on June 5, 2020, our board of directors authorized an additional $2.2
million of common stock to be sold in transactions that are deemed to be
"at-the-market offerings." We began offering shares under this program during
the first quarter of 2021 and completed this offering process during the second
quarter of 2021, raising $2.2 million of gross proceeds and issuing an aggregate
of 585,934 shares at an average gross offering price of $3.75 per share.

On August 19, 2021, we entered into a new ATM Distribution Agreement relating to
the offer and sale of an additional $7.5 million of common stock to be sold in
transactions that are deemed to be "at-the-market offerings." During the fourth
quarter of 2021, we completed this offering process, raising $7.5 million of
gross proceeds and issuing an aggregate of 2,274,990 shares at an average gross
offering price of $3.30.

On December 16, 2021, in conjunction with the ATM Distribution Agreement entered
into on August 19, 2021, our board of directors authorized the sale of an
additional $5.9 million of common stock to be sold in transactions that are
deemed to be "at-the-market offerings." We began offering shares under this
program during the first quarter of 2022. As of March 4, 2022, we raised gross
proceeds of $3.6 million from the sale of shares in the offering.

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Reverse Stock Split

Following approval by our stockholders on February 6, 2020, our Board of
Directors approved a 1-for-20 reverse stock split of our common stock. The
reverse stock split reduced the number of shares of common stock issued and
outstanding from 77,523,973 and 76,241,045 shares, respectively, to 3,876,196
and 3,812,050 shares, respectively, and reduced the number of authorized shares
of our common stock from 200,000,000 shares to 50,000,000 shares.

Sidewinder Merge Effects and Merge Considerations Change

We completed the merger with Sidewinder Drilling LLC on October 1, 2018. At the
time of consummation of the Sidewinder Merger, Sidewinder owned various
mechanical rig assets and related equipment (the "Mechanical Rigs") located
principally in the Utica and Marcellus plays. As these assets were not
consistent with ICD's core strategy or geographic focus, ICD agreed that these
assets could be disposed of, with the Sidewinder unitholders receiving the net
proceeds. As a result of this arrangement, on the merger date, we recorded the
fair value of the Mechanical Rigs less costs to sell, as assets held for sale,
with a related liability in contingent consideration. Subsequently, these assets
were sold at auction for substantially less than the appraised fair values on
the merger date. As a result, in the second quarter of 2020, the contingent
consideration liability was reduced by the appraised fair values on the merger
date and the proceeds were recorded as merger consideration payable to an
affiliate on our consolidated balance sheets.

On June 4, 2020, we entered into a letter agreement (the "Merger Consideration
Amendment") with MSD Credit Opportunity Master Fund, L.P. to allow for the
deferral of payment of the Mechanical Rig net proceeds of $2.9 million, to the
earlier of (i) June 30, 2022 and (ii) a change of control transaction (as
defined therein) (such applicable date, the "Payment Date"), and requires us to
pay an additional amount in connection with such deferred payment equal to
interest accrued on the amount of Mechanical Rig net proceeds during the period
between May 1, 2020 and the Payment Date, which interest shall accrue at a rate
of 15% per annum, compounded quarterly, during the period beginning on May 1,
2020 and ending on December 31, 2020 and at a rate of 25% per annum, compounded
quarterly, during any period following December 31, 2020. The Mechanical Rig net
proceeds were previously payable in the second quarter of 2020. Accrued interest
as of December 31, 2021 was $1.2 million.

Impairment of assets, net

During 2021, we impaired a damaged piece of drilling equipment for $0.3 million,
net of insurance recoveries. We also sold miscellaneous drilling equipment.
Accordingly, we impaired the drilling equipment to fair market value less cost
to sell and recorded asset impairment expense of $0.5 million in our
consolidated statements of operations.

During the first quarter of 2020, as a result of the rapidly deteriorating
market conditions described in "COVID-19 Pandemic and Market Conditions Update,"
we concluded that a triggering event had occurred and, accordingly, an interim
asset impairment test was performed. As a result, we recognized impairment of
$3.3 million associated with the decline in the market value of our assets held
for sale based upon the market approach method and $13.3 million related to the
remaining assets on rigs removed from our marketed fleet, as well as certain
other component equipment and inventory; all of which was deemed to be
unsaleable and of zero value based upon the macroeconomic conditions at the time
and uncertainties surrounding COVID-19.

During the fourth quarter of 2020, due to the highly competitive market and in
an effort to minimize capital spending, management drafted and approved a plan
to upgrade our existing fleet by utilizing the primary components needed to
complete the upgrades from five of our existing rigs and these five rigs were
removed from our marketed fleet. We recorded an impairment charge of $21.9
million related to the remaining assets on these non-marketed rigs.
Additionally, we recorded a $2.4 million asset impairment based upon the market
approach method on certain capital spare parts, all of which were deemed to be
incompatible with our upgraded fleet.

Our income

We earn contract drilling revenues pursuant to drilling contracts entered into
with our customers. We perform drilling services on a "daywork" basis, under
which we charge a specified rate per day, or "dayrate." The dayrate

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associated with each of our contracts is a negotiated price determined by the
capabilities of the rig, location, depth and complexity of the wells to be
drilled, operating conditions, duration of the contract and market conditions.
The term of land drilling contracts may be for a defined number of wells or for
a fixed time period. We generally receive lump-sum payments for the mobilization
of rigs and other drilling equipment at the commencement of a new drilling
contract. Revenue and costs associated with the initial mobilization are
deferred and recognized ratably over the term of the related drilling contract
once the rig spuds. Costs incurred to relocate rigs and other equipment to an
area in which a contract has not been secured are expensed as incurred. If a
contract is terminated prior to the specified contract term, early termination
payments received from the customer are only recognized as revenues when all
contractual obligations, such as mitigation requirements, are satisfied. While
under contract, our rigs generally earn a reduced rate while the rig is moving
between wells or drilling locations, or on standby waiting for the customer.
Reimbursements for the purchase of supplies, equipment, trucking and other
services that are provided at the request of our customers are recorded as
revenue when incurred. The related costs are recorded as operating expenses when
incurred. Revenue is presented net of any sales tax charged to the customer that
we are required to remit to local or state governmental taxing authorities.

Our operating costs

Our operating costs include all expenses associated with operating and
maintaining our drilling rigs. Operating costs include all "rig level" expenses
such as labor and related payroll costs, repair and maintenance expenses,
supplies, workers' compensation and other insurance, ad valorem taxes and
equipment rental costs. Also included in our operating costs are certain costs
that are not incurred at the "rig level." These costs include expenses directly
associated with our operations management team as well as our safety and
maintenance personnel who are not directly assigned to our rigs but are
responsible for the oversight and support of our operations and safety and
maintenance programs across our fleet.

Our operating costs also include costs and expenses associated with construction
activities at our Galayda yard location to the extent that construction
activities cease or are not continuous. During 2021, our operating costs also
included approximately $1.4 million of costs associated with the reactivation of
idle rigs. Reactivation costs include costs associated with recommissioning the
rig, the hiring and training of new crews and the purchase of supplies and other
consumables required for the operation of the rigs.

How we evaluate our operations

We regularly use a number of financial and operational measures to analyze and
evaluate the performance of our business and compensate our employees, including
the following:

Safety performance. Maintaining a strong safety record is an essential

of our business strategy. We measure security by tracking total recordable

incident rate for our operations. In addition, we closely monitor and measure

? compliance with our safety policies and procedures, including “near misses”

compliance with job safety reports and analysis. We believe that our risk-based HSE approach

management system provides the control required, but the flexibility needed, to

conduct all activities in a safe, efficient and appropriate manner.

Use. Platform usage measures the total time our platforms

earn income under a contract during a given period. We measure

usage by dividing the total number of operating days for a platform by the

total number of days that the platform is available to operate in the

? calendar period. A rig is available for operation commencing on the earliest of the following dates:

the date he digs his initial well after construction or when it was

completed and is being actively marketed. “Operation Days” represents the total number

days that a platform generates revenue under a contract, from the moment the platform starts up

its initial shaft under the contract and ending with the completion of the platform

   demobilization.


   Revenue Per Day. Revenue per day measures the amount of revenue that an

mining rig earns daily for a given period. We calculate

? revenue per day by dividing the total contracted drilling revenue earned during the

applicable period by the number of business days in the period. Revenue

attributable to fees reimbursed by customers are excluded from this measure.

Operating cost per day. Operating cost per day measures operating costs

? incurred daily for a given period. We calculate the operation

   cost per day by dividing total operating costs during the


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applicable period by the number of business days in the period. Operating costs

attributable to fees reimbursed by customers are excluded from this measure.

Operational efficiency and availability. Maintain the operational efficiency of our platforms

? is an essential part of our business strategy. We measure our operation

   efficiency by tracking each drilling rig's unscheduled downtime on a
   daily, monthly, quarterly and annual basis.


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Results of Operations

The following summarizes our financial and operating data for the years ended
December 31, 2021 and 2020:

                                                         Year Ended
                                              December 31,       December 31,
(In thousands, except per share data)             2021               2020
Revenues                                     $        87,955    $        83,418
Costs and expenses
Operating costs                                       75,751             65,367
Selling, general and administrative                   15,699             

13,484

Severance expense                                          -              

1,076

Depreciation and amortization                         38,915             

43,919

Asset impairment, net                                    800             

41,007

(Gain) loss on disposition of assets, net              (245)               

723
Other expense                                            150                  -
Total cost and expenses                              131,070            165,576
Operating loss                                      (43,115)           (82,158)
Interest expense                                    (15,193)           (14,627)

Gain on extinguishment of debt                        10,128               

–

Loss before income taxes                            (48,180)           

(96,785)

Income tax expense (benefit)                          18,532              

(147)

Net loss                                     $      (66,712)    $      

(96,638)

Other financial and operating data
Number of marketed rigs (end of period) (1)               24               

24

Rig operating days (2)                                 4,651              

3,739

Average number of operating rigs (3)                    12.7              

10.2

Rig utilization (4)                                       53 %               35 %
Average revenue per operating day (5)        $        17,224    $        19,000
Average cost per operating day (6)           $        13,943    $        

13,984

Average rig margin per operating day         $         3,281    $         5,016
Oil price per Bbl (7) (end of year)          $         75.33    $         48.35
Natural gas price per Mcf (8) (end of year)  $          3.82    $          2.36

(1) Released platforms exclude inactive platforms that will not be reactivated until upgrades

or conversions are complete or market conditions improve significantly.

Platform operating days represent the number of days our platforms are generating revenue (2) under a contract during the period, including days when standby revenue is

won.

The average number of rigs in operation is calculated by dividing the total number (3) of days the rig was in operation during the period by the total number of calendar days in

the period.

(4) Platform usage is calculated as days of platform operation divided by total

number of days our drilling rigs are available during the applicable period.

Average revenue per operating day represents total contracted drilling revenue

earned during the period divided by days of platform operation during the period.

Are excluded from the calculation of the average income per day of operation the income (5) associated with the reimbursement (i) of the disbursements paid by

customers of $7.8 million and $9.0 million over the past years

December 31, 2021 and 2020, respectively, and (ii) early termination revenue

    of zero and $3.3 million during the years ended December 31, 2021 and 2020,
    respectively.


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The average cost per operating day represents the total operating costs incurred

during the period divided by the days of operation of the platform during the period. What follows

costs are excluded from the calculation of the average cost per day of operation:

(i) disbursements reimbursed by clients of $7.8 million and $9.0

million over the years ended December 31, 2021 and 2020, respectively, (6)(ii) expensed overhead due to reduced platform upgrade activities $1.6

million and $1.9 million during the years ended the years ended December 31, 2021

and 2020, respectively, (iii) platform reactivation costs, including new crew

training costs, $1.4 million and $1.6 million over the past years

December 31, 2021 and 2020, respectively, and (iv) platform dismantling costs

associated with stacking disabled platforms from $0.1 million and $0.6 million

over the past years December 31, 2021 and 2020, respectively.

(7) Spot price of WTI as published by United States Energy Information

Administration.

(8) Henry Hub spot price as reported by United States Energy Information

Administration.

Comparison of years ended December 31, 2021 and 2020

Revenue

Revenues for the year ended December 31, 2021 were $88.0 million, representing a
5.4% increase over revenues of $83.4 million for the year ended
December 31, 2020. This increase was attributable to an increase in
operating days to 4,651 days as compared to 3,739 days in 2020. The increase in
operating days was primarily attributable to the reactivation of rigs in 2021
after the drastic downturn in market conditions in 2020 as a result of the
COVID-19 pandemic and the concurrent initiation of a crude oil price war between
members of the "OPEC+" group. On a revenue per operating day basis, which
excludes the impact of early termination, our revenue per operating day
decreased to $17,224 during 2021 compared to revenue per operating day of
$19,000 during 2020. This decrease in average revenue per day resulted from the
expiration of various higher dayrate legacy term contracts prior to 2021.

Operating costs

Operating costs for the year ended December 31, 2021 were $75.8 million,
representing a 15.9% increase over operating costs for the year ended
December 31, 2020 of $65.4 million. This increase was attributable to an
increase in operating days to 4,651 days as compared to 3,739 days in 2020. On a
cost per operating day basis, our cost per day decreased to $13,943 during 2021,
compared to cost per day of $13,984 during 2020. This decrease was primarily
attributable to inefficiencies during the downturn in 2020, offset by higher
personnel costs associated with staffing for planned rig reactivations and
tighter labor markets in 2021.

Selling, general and administrative expenses

Selling, general and administrative expenses for the year ended
December 31, 2021 were $15.7 millionrepresenting an increase of 16.4% over selling, general and administrative expenses for the year ended
December 31, 2020 of $13.5 million. This increase is primarily related to higher incentive compensation accruals in 2021. We suspended our incentive compensation plan for 2020 due to the COVID-19 pandemic.

Severance pay

Severance expense of $1.1 million was recorded during 2020 in connection with
our cost reduction measures instituted in response to the COVID-19 pandemic and
deteriorating market conditions. We did not record any severance expense in
2021.

Depreciation and amortization

Depreciation and amortization for the year ended December 31, 2021 was $38.9
million, representing a 11.4% decrease compared to $43.9 million for the year
ended December 31, 2020. This decrease was primarily the result of the asset
impairments incurred in 2020 and 2021, offset by increases related to the
introduction of reactivated drilling rigs upgraded by us in 2021. We begin
depreciating our rigs on a straight-line basis when they commence drilling

operations.

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Asset Impairment, net

Asset impairment expense of $0.8 million was recorded for the year ended
December 31, 2021, as compared to $41.0 million for the year ended
December 31, 2020. For further discussion, see "Significant Developments - Asset
Impairments" in this Management's Discussion and Analysis of Financial Condition
and Results of Operations.

(Gain) Loss on disposal of assets, net

A gain on disposal of assets totaling $0.2 million and a loss of $0.7 million has been recorded for completed fiscal years December 31, 2021 and 2020, respectively. During the current and prior year period, the gain and loss relate primarily to the sale of miscellaneous drilling equipment.

Other expenses

Other expense of $0.2 million was recorded during 2021 in connection with the
termination of our Commitment Purchase Agreement. We did not record any other
expense in 2020.

Interest Expense

Interest expense was $15.2 million for the year ended December 31, 2021,
compared to $14.6 million for the year ended December 31, 2020. The increase in
the current year primarily relates to the compounding interest on the merger
consideration payable in June 2022.

Gain on extinguishment of debt

A gain on extinguishment of debt totaling $10.1 million was recorded for the
year ended December 31, 2021 related to the forgiveness of our PPP Loan. See
Note 8 "Long-term Debt" for additional information.

Income tax expense (benefit)

Income tax expense for the year ended December 31, 2021 amounted to $18.5
million compared to income tax benefit of $0.1 million for the year ended
December 31, 2020. The effective tax rate was negative 38.5% for the year ended
2021 compared to 0.2% for the year ended 2020. Tax expenses for 2021 primarily
related to non-cash charges related to the inability to utilize net operating
loss ("NOL") deferred tax assets to offset deferred tax liabilities due to an
IRC Section 382 ownership change occurring in October 2021 and the limitations
therefrom placed upon the NOLs. Taxes for 2020 primarily relate to Louisiana
state income tax and Texas margin tax. See Note 9 "Income Taxes" for additional
information.

Cash and capital resources

Our liquidity as of December 31, 2021 included cash on hand of $4.1 million,
$11.3 million of availability under our $40.0 million ABL Credit Facility, based
on a borrowing base of $17.8 million, and an $11.9 million committed accordion
under our existing term loan facility. Subsequent to December 31, 2021, we
raised an additional $3.6 million of gross proceeds through "at-the-market"
equity offerings issuing an additional 1,061,853 shares which is not included in
our liquidity or our outstanding share count as of December 31, 2021.

We expect our future capital and cash requirements to be related to operating expenses, maintenance capital expenditures, rig reactivations, working capital and general business needs.

Cash flow from operations, ignoring working capital fluctuations, was negative
during 2021. Subsequent to December 31, 2021, we elected to pay in-kind $3.2
million of interest due on January 1, 2022, which reduced our remaining Term
Loan Accordion commitment and increased our Term Loan Facility balance
accordingly. Looking forward past December 31, 2021, we currently estimate that
required non-operating cash payments for interest under our credit facilities
and finance lease payments will approximate $18.1 million for the 12 months

ending December 31,

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2022. In addition, the final merger consideration payment due pursuant to our
merger agreement executed in connection with our merger with Sidewinder Drilling
matures on June 30, 2022. Payments for capital expenditures and financing leases
and to fund operations will be in addition to these amounts.

Because our cash flows from operations have been and could continue to be
impacted by depressed market conditions caused by the COVID-19 pandemic, we may
be required to continue to draw down under our ABL Credit Facility and to draw
down funds pursuant to the DDTL Facility under our term loan facility to meet
required non-operating expenditures and if necessary to fund operations. We
currently believe that the actions we have taken to date and our existing
sources of liquidity are sufficient to fund our operations for the next
twelve months. However, due to the uncertainty regarding the duration of the
COVID-19 pandemic and its effects on the oil and gas industry and our business
and operations, there can be no assurance in this regard.

Although our Term Loan Credit Agreement does not mature until October 2023, we
also have begun the process of evaluating alternatives to refinance this Term
Loan Facility. We cannot predict at this time the form of any such refinancing;
however, such alternatives could include an extension of the term of the Term
Loan Facility, the conversion or refinancing of all or part of the debt to
equity or equity-linked instruments, and adjustments to interest rates and
covenants, the issuance of debt or equity securities to third parties, or a
combination of conversions or exchanges and issuances of debt or equity
securities to third parties. Although market conditions for our business have
been strengthening, we cannot predict whether suitable refinancing alternatives
will be available to us, or the timing of when such refinancing could occur.

You should read “Item 1A Risk Factors”, in particular “Risks Relating to Our Liquidity”, for additional information regarding risks surrounding our operations and financial liquidity.

Contractual obligations

From December 31, 2021we had contractual obligations described below.

Our obligations include "off-balance sheet arrangements" whereby the liabilities
associated with unconditional purchase obligations are not fully reflected in
our consolidated balance sheets.

(in thousands)                               2022        2023       2024      Thereafter       Total
Term Loan Facility                         $      -    $ 135,883    $   -    $          -    $ 135,883
ABL Credit Facility                               -        6,300        -               -        6,300

Interest on Term Loan Facility               12,467       12,399        -               -       24,866
Interest on ABL Credit Facility                 303          303        -               -          606
Deferred amendment fee                            -          975        -               -          975
Merger consideration payable to an
affiliate, including interest                 4,606            -        -               -        4,606
Finance leases                                4,868        1,068      200               -        6,136
Purchase obligations                          2,927            -        -               -        2,927
Total contractual obligations              $ 25,171    $ 156,928    $ 200    $          -    $ 182,299


Our long-term debt as of December 31, 2021 consisted of amounts due under our
Term Loan Facility (as defined and further described below). Interest on
long-term debt is related to our estimated future contractual interest
obligations on long-term indebtedness outstanding as of December 31, 2021 under
our Term Loan Facility. Interest payment obligations on our Term Loan Facility
were estimated based on the 9.0% interest rate that was in effect
at December 31, 2021, and the principal balance of $135.9 million at
December 31, 2021, and assuming repayment of the outstanding balance occurs
at October 1, 2023. Interest payment obligation on our ABL Credit Facility were
estimated based on the 4.75% interest rate that was in effect at December 31,
2021, and the principal balance of $6.3 million at December 31, 2021, and
assuming repayment of the outstanding balance occurs at October 1, 2023.
Included in our contractual obligations are finance leases on vehicles and
certain drilling equipment. These leases generally have a term of 36 months

and
are paid monthly.

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Our purchase obligations relate primarily to outstanding purchase orders for rig
equipment or components ordered but not received. We have made progress payments
on these orders of approximately $0.2 million that could be forfeited if we

were
to cancel these orders.

Cash Flows

                                                                   Year Ended December 31,
(in thousands)                                                      2021                 2020
Net cash (used in) provided by operating activities            $       (9,579)         $     287
Net cash used in investing activities                                 (14,378)           (8,977)
Net cash provided by financing activities                               15,818            15,763
Net (decrease) increase in cash and cash equivalents           $       

(8,139) $7,073

Net cash (Used in) Provided by operating activities

Cash used in operating activities was $9.6 million for the year ended
December 31, 2021 compared to cash provided by operating activities of $0.3
million for the year ended December 31, 2020. Factors affecting changes in
operating cash flows are similar to those that impact net earnings, with the
exception of non-cash items such as depreciation and amortization, impairments,
gains or losses on disposals of assets, stock-based compensation, deferred taxes
and amortization of deferred financing costs. Additionally, changes in working
capital items such as accounts receivable, inventory, prepaid expense, accounts
payable and accrued liabilities can significantly affect operating cash flows.
Cash flows from operating activities during 2021 were lower as a result of a
decrease in net loss of $29.9 million, adjusted for non-cash items of $57.1
million, compared to $88.5 million in 2020. Additionally, working capital
changes that increased cash flows from operating activities were de minimis in
2021 compared to working capital changes that increased cash flows from
operating activities of $8.4 million in 2020.

Net cash used In investment activities

Cash used in investing activities was $14.4 million for the year ended
December 31, 2021 compared to $9.0 million for the year ended December 31, 2020.
Our primary investing activities in 2021 related to rig upgrades and maintenance
capital expenditures. Cash payments of $16.4 million for capital expenditures
were offset by proceeds from the sale of property, plant and equipment of $2.0
million. Cash payments during 2021 included approximately $1.0 million
associated with equipment purchased in 2020. During 2020, cash payments of $14.2
million for capital expenditures were offset by proceeds from the sale of
property, plant and equipment of $5.1 million and the collection of principal on
note receivable of $0.1 million.

Net cash provided by financing activities

Cash provided by financing activities was $15.8 million for the year ended
December 31, 2021 compared to cash provided by financing activities of $15.8
million for the year ended December 31, 2020. During 2021, we received proceeds
from borrowings under our Revolving Credit Facility of $6.3 million, proceeds
from the issuance of common stock through our ATM transaction, net of issuance
costs of $9.0 million and proceeds from the issuance of common stock under our
equity line of credit purchase agreement of $4.2 million offset by restricted
stock units withheld for taxes paid of $14.0 thousand, the purchase of treasury
stock of $10.0 thousand, financing cost paid of $64 thousand, and made payments
for finance lease obligations of $3.6 million. During 2020, we made borrowings
under our Revolving Credit Facility of $11.0 million and under the PPP Loan of
$10.0 million, offset by repayments under our Revolving Credit Facility of $11.0
million, common stock issuance costs of $0.8 million, received proceeds from
issuance of common stock of $11.0 million, had restricted stock units withheld
for taxes paid of $44.0 thousand, purchased $0.1 million of treasury stock and
made payments for finance lease obligations of $4.3 million.

long-term debt

On October 1, 2018, we entered into a Term Loan Credit Agreement (the "Term Loan
Credit Agreement") for an initial term loan in an aggregate principal amount
of $130.0 million, (the "Term Loan Facility") and (b) a delayed

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draw term loan facility in an aggregate principal amount of up to $15.0
million (the "DDTL Facility", and together with the Term Loan Facility, the
"Term Facilities"). The Term Facilities have a maturity date of October 1, 2023,
at which time all outstanding principal under the Term Facilities and other
obligations become due and payable in full. The outstanding balance under this
Term Loan Credit Agreement at December 31, 2021 was $135.9 million, and
increased to $139.1 million in January 2022 as a result of the payment-in-kind
of interest due on January 1, 2022.

At our option, interest under the Term Loan Facility is determined by reference to, at our option, either (i) a “base rate” equal to the greater of (a) the effective federal funds rate plus of 0.05%, (b) the London Interbank Offered Rate (“LIBOR”) with an interest period of one month, plus 1.0%, and (c) the interest rate as publicly stated from time to time by the the wall street journal as the “prime rate” in United Statesplus an applicable margin of 6.5%, or (ii) a “LIBOR rate” equal to LIBOR with an interest period of one month, plus an applicable margin of 7.5%.

The Term Loan Credit Agreement contains financial covenants, including a
liquidity covenant of $10.0 million and a springing fixed charge coverage ratio
covenant of 1:1 that is tested when availability under the ABL Credit Facility
(defined below) and the DDTL Facility is below $5.0 million at any time that a
DDTL Facility loan is outstanding. The Term Loan Credit Agreement also contains
other customary affirmative and negative covenants, including limitations on
indebtedness, liens, fundamental changes, asset dispositions, restricted
payments, investments and transactions with affiliates. The Term Loan Credit
Agreement also provides for customary events of default, including breaches of
material covenants, defaults under the ABL Credit Facility or other material
agreements for indebtedness, and a change of control.

The obligations under the Term Loan Credit Agreement are secured by a first
priority lien on collateral (the "Term Priority Collateral") other than accounts
receivable, deposit accounts and other related collateral pledged as first
priority collateral ("Priority Collateral") under the ABL Credit Facility
(defined below) and a second priority lien on such Priority Collateral, and are
unconditionally guaranteed by all of our current and future direct and indirect
subsidiaries. MSD PCOF Partners IV, LLC (an affiliate of MSD Partners) is the
lender of our $130.0 million Term Loan Facility. MSD Partners, together with MSD
Capital, owned approximately 6.1% of the outstanding shares of our common stock
as of June 30, 2021. Their ownership percentage dropped below the 5% beneficial
ownership percentage as of September 30, 2021, and remains as such at December
31, 2021.

In June 2020, we revised our Term Loan Credit Agreement to elect to pay accrued
and unpaid interest, solely during one three-consecutive-month period
immediately following such notice, in-kind (the "PIK Amount"). We agreed to pay
an additional amount equal to 0.75% of the aggregate principal amount of the
loans under the Term Loan Credit Agreement plus all PIK Amounts, if any, that
are added to such principal amount being repaid or prepaid on either the
maturity date or upon the occurrence of an acceleration of obligations under the
Term Loan Credit Agreement. As such, the additional amount, approximately $1.0
million, was recorded as a direct deduction from the face amount of the Term
Loan Facility and as a long-term payable on our consolidated balance sheets. The
additional amount is amortized as interest expense over the term of the Term
Loan Facility. During the second quarter of 2021, we utilized this PIK option to
pay interest due during the quarter. In September 2021, we amended our Term Loan
Credit Agreement to permit us, subject to required prior notice, to elect to pay
accrued and unpaid interest due October 1, 2021, in-kind. The payment-in-kind is
in lieu of exercising a drawdown under the DDTL Facility under the Term Loan
Credit Agreement, reducing the amount of the DDTL Facility commitment of $15
million by the amount of the accrued and unpaid interest due October 1, 2021. On
October 1, 2021, we elected to pay in-kind the $3.1 million interest payment due
under our Term Loan Credit Agreement. Subsequent to December 31, 2021, we
elected to pay in- kind $3.2 million of interest due on January 1, 2022, which
will draw down our remaining $11.9 million DDTL Facility and increase our Term
Loan Facility balance accordingly.

Additionally on October 1, 2018, we entered into a $40.0 million revolving
Credit Agreement (the "ABL Credit Facility"), including availability for letters
of credit in an aggregate amount at any time outstanding not to exceed $7.5
million. Availability under the ABL Credit Facility is subject to a borrowing
base calculated based on 85% of the net amount of our eligible accounts
receivable, minus reserves. The ABL Credit Facility has a maturity date of the
earlier of October 1, 2023 or the maturity date of the Term Loan Credit
Agreement.

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At our election, interest under the ABL Credit Facility is determined by
reference at our option to either (i) a "base rate" equal to the higher of
(a) the federal funds effective rate plus 0.05%, (b) LIBOR with an interest
period of one month, plus 1.0%, and (c) the prime rate of Wells Fargo, plus in
each case, an applicable base rate margin ranging from 1.0% to 1.5% based on
quarterly availability, or (ii) a revolving loan rate equal to LIBOR for the
applicable interest period plus an applicable LIBOR margin ranging
from 2.0% to 2.5% based on quarterly availability. We also pay, on a quarterly
basis, a commitment fee of 0.375% (or 0.25% at any time when revolver usage is
greater than 50% of the maximum credit) per annum on the unused portion of the
ABL Credit Facility commitment.

The ABL Credit Facility contains a springing fixed charge coverage ratio
covenant of 1:1 that is tested when availability is less than 10% of the maximum
credit. The ABL Credit Facility also contains other customary affirmative and
negative covenants, including limitations on indebtedness, liens, fundamental
changes, asset dispositions, restricted payments, investments and transactions
with affiliates. The ABL Credit Facility also provides for customary events of
default, including breaches of material covenants, defaults under the Term Loan
Credit Agreement or other material agreements for indebtedness, and a change of
control. We are in compliance with our financial covenants as of
December 31, 2021.

The obligations under the ABL Credit Facility are secured by a first priority
lien on Priority Collateral, which includes all accounts receivable and deposit
accounts, and a second priority lien on the Term Priority Collateral, and are
unconditionally guaranteed by all of our current and future direct and indirect
subsidiaries. As of December 31, 2021, the weighted-average interest rate on our
borrowings was 8.81%. At December 31, 2021, the borrowing base under our ABL
Credit Facility was $17.8 million, and we had $11.3 million of availability
remaining of our $40.0 million commitment on that date.

In addition, on April 27, 2020, we entered into an unsecured loan in the
aggregate principal amount of $10.0 million (the "PPP Loan") pursuant to the
PPP, sponsored by the SBA as guarantor of loans under the PPP. The PPP was part
of the CARES Act, and it provided loans to qualifying businesses in a maximum
amount equal to the lesser of $10.0 million and 2.5 times the average monthly
payroll expenses of the qualifying business. The proceeds of the loan could only
be used for payroll costs, rent, utilities, mortgage interests, and interest on
other pre-existing indebtedness (the "permissible purposes") during the covered
period ending October 13, 2020. Interest on the PPP Loan was equal to 1.0% per
annum. All or part of the loan was forgivable based upon the level of
permissible expenses incurred during the covered period and changes to the
Company's headcount during the period from January 1, 2020 to February 15, 2020.
In the third quarter of 2021, we received notice from the SBA that our loan was
forgiven and paid in full. We have not accrued any liability associated with the
risk of an adverse SBA review.

In addition, our long-term debt includes finance leases. These leases generally have an initial term of 36 months and are paid monthly.

Significant Accounting Policies and Accounting Estimates

The consolidated financial statements are impacted by the accounting policies
and estimates and assumptions used by management during their preparation. These
estimates and assumptions are evaluated on an on-going basis. Estimates are
based on historical experience and on various other assumptions that we believe
to be reasonable under the circumstances, the results of which form the basis
for making judgments about the carrying values of assets and liabilities if not
readily available from other sources. Actual results may differ from these
estimates under different assumptions or conditions. The following is a
discussion of the critical accounting policies and estimates used in our
consolidated financial statements. Other significant accounting policies are
summarized in Note 2 "Summary of Significant Accounting Policies" to the
consolidated financial statements included in "Item 8. Financial Statements

and
Supplementary Data."

Revenue and Cost Recognition

We earn contract drilling revenues pursuant to drilling contracts entered into
with our customers. We perform drilling services on a "daywork" basis, under
which we charge a specified rate per day, or "dayrate." The dayrate associated
with each of our contracts is a negotiated price determined by the capabilities
of the rig, location, depth and

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complexity of the wells to be drilled, operating conditions, duration of the
contract and market conditions. The term of land drilling contracts may be for a
defined number of wells or for a fixed time period. We generally receive
lump-sum payments for the mobilization of rigs and other drilling equipment at
the commencement of a new drilling contract. Revenue and costs associated with
the initial mobilization are deferred and recognized ratably over the term of
the related drilling contract once the rig spuds. Costs incurred to relocate
rigs and other equipment to an area in which a contract has not been secured are
expensed as incurred. Our contracts provide for early termination fees in the
event our customers choose to cancel the contract prior to the specified
contract term. We record a contract liability for such fees received up front,
and recognize them ratably as contract drilling revenue over the initial term of
the related drilling contract or until such time that all performance
obligations are satisfied. While under contract, our rigs generally earn a
reduced rate while the rig is moving between wells or drilling locations, or on
standby waiting for the customer. Reimbursements for the purchase of supplies,
equipment, trucking and other services that are provided at the request of our
customers are recorded as revenue when incurred. The related costs are recorded
as operating expenses when incurred. Revenue is presented net of any sales tax
charged to the customer that we are required to remit to local or state
governmental taxing authorities.

Our operating costs include all expenses associated with operating and
maintaining our drilling rigs. Operating costs include all "rig level" expenses
such as labor and related payroll costs, repair and maintenance expenses,
supplies, workers' compensation and other insurance, ad valorem taxes and
equipment rental costs. Also included in our operating costs are certain costs
that are not incurred at the rig level. These costs include expenses directly
associated with our operations management team as well as our safety and
maintenance personnel who are not directly assigned to our rigs but are
responsible for the oversight and support of our operations and safety and
maintenance programs across our fleet.

Fixed assets

Property, plant and equipment, including renewals and betterments, are stated at
cost less accumulated depreciation. All property, plant and equipment are
depreciated using the straight-line method based on the estimated useful lives
of the assets, which range from two to 39 years. Our determination of the useful
lives of property and equipment requires us to make various assumptions when the
assets are acquired or placed into service about the expected usage, normal wear
and tear and the extent and frequency of maintenance programs. The cost of
maintenance and repairs are expensed as incurred. Major overhauls and upgrades
are capitalized and depreciated over their remaining useful life.

We review our assets for impairment whenever events or changes in circumstances
indicate that the carrying amount of an asset may not be recoverable. The
recoverability of assets that are held and used is measured by comparison of the
estimated future undiscounted cash flows associated with the asset to the
carrying amount of the asset. If the carrying value of such assets is less than
the estimated undiscounted cash flow, an impairment charge is recorded in the
amount by which the carrying amount of the assets exceeds their estimated fair
value.

Asset impairment expense of $0.8 million was recorded for 2021, as compared to
$41.0 million for 2020. For further discussion, see "Significant Developments -
Asset Impairments" in this Management's Discussion and Analysis of Financial
Condition and Results of Operations.

Income taxes

We use the asset and liability method of accounting for income taxes. Under this
method, we record deferred income taxes based upon differences between the
financial reporting basis and tax basis of assets and liabilities, and use
enacted tax rates and laws that we expect will be in effect when we realize
those assets or settle those liabilities. We review deferred tax assets for a
valuation allowance based upon management's estimates of whether it is more
likely than not that a portion of the deferred tax asset will be fully realized
in a future period.

We recognize the benefit of a tax position in the financial statements only after determining that the relevant tax authority would more likely than not maintain the position following an audit. For tax positions reaching the more likely than not threshold, the amount recognized in the consolidated financial statements is the most significant benefit that has a greater than 50% probability of being realized upon final settlement with the relevant tax authority .

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Our policy is to include interest and penalties related to the unrecognized tax
benefits within the income tax expense (benefit) line item in our consolidated
statement of operations.

Stock-Based Compensation

We accrue compensation expense over the required service period for all stock-based compensation based on the fair value of the award at the grant date. The charge is included in selling, general and administrative expenses in our Consolidated Statement of Income or capitalized as part of the rig construction business.

Other topics

Off-balance sheet arrangements

We are party to certain arrangements defined as "off-balance sheet arrangements"
that have or are reasonably likely to have a current or future effect on our
financial condition, changes in financial condition, revenues or expenses,
results of operations, liquidity, capital expenditures or capital resources that
is material to investors. These arrangements relate to non-cancelable operating
leases with terms of less than twelve months and unconditional purchase
obligations not fully reflected on our consolidated balance sheets. See
Note 13 "Commitments and Contingencies" to our consolidated financial statements
for additional information.

Recent accounting pronouncements

In June 2016, the Financial Accounting Standards Board ("FASB") issued
Accounting Standards Update ("ASU") No. 2016-13, Financial Instruments - Credit
Losses: Measurement of Credit Losses on Financial Instruments, as additional
guidance on the measurement of credit losses on financial instruments. The new
guidance requires the measurement of all expected credit losses for financial
assets held at the reporting date based on historical experience, current
conditions and reasonable supportable forecasts. In addition, the guidance
amends the accounting for credit losses on available-for-sale debt securities
and purchased financial assets with credit deterioration. The new guidance is
effective for all public companies for interim and annual periods beginning
after December 15, 2019, with early adoption permitted for interim and annual
periods beginning after December 15, 2018. In October 2019, the FASB approved a
proposal which grants smaller reporting companies additional time to implement
FASB standards on current expected credit losses (CECL) to January 2023. As a
smaller reporting company, we will defer adoption of ASU No. 2016-13 until
January 2023. We are currently evaluating the impact this guidance will have on
our consolidated financial statements.

On April 1, 2020, we adopted the new standard, ASU 2020-04, Reference Rate
Reform: Facilitation of the Effects of Reference Rate Reform on Financial
Reporting, which provides optional expedients and exceptions for applying
generally accepted accounting principles to contracts, hedging relationships,
and other transactions affected by reference rate reform (e.g. discontinuation
of LIBOR) if certain criteria are met. In January 2021, the FASB issued ASU No.
2021-01, Reference Rate Reform, to provide clarifying guidance regarding the
scope of Topic 848, effective immediately. As of December 31, 2021, we have not
yet elected any optional expedients provided in the standard. We will apply the
accounting relief as relevant contract and hedge accounting relationship
modifications are made during the reference rate reform transition period. We do
not expect the standard to have a material impact on our consolidated financial
statements.

In August 2020, the FASB issued ASU No. 2020-06, Debt-Debt with Conversion and
Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in
Entity's Own Equity (Subtopic 815-40): Accounting for Convertible Instruments
and Contracts in an Entity's Own Equity, to simplify the accounting for
convertible instruments by removing certain separation models in Subtopic
470-20, Debt-Debt with Conversion and Other Options, for convertible
instruments. The pronouncement is effective for fiscal years, and for interim
periods within those fiscal years, beginning after December 15, 2021, with early
adoption permitted. We do not expect the standard to have a material impact on
our consolidated financial statements.

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In May 2021, the FASB issued ASU No. 2021-04, Earnings Per Share (Topic 260),
Debt - Modifications and Extinguishments (Subtopic 470-50), Compensation - Stock
Compensation (Topic 718), and Derivatives and Hedging - Contracts in Entity's
Own Equity (Subtopic 815-40): Issuer's Accounting for Certain Modifications or
Exchanges of Freestanding Equity-Classified Written Call Options, which
clarifies that issuers should account for modifications and exchanges of
freestanding equity-classified written call options that remain
equity-classified after these transactions as an exchange of the original
instrument for a new instrument. The pronouncement is effective for fiscal
years, and interim periods within those fiscal years, beginning after December
15, 2021, with early adoption permitted. We adopted this guidance on January 1,
2022 and there is no impact on our consolidated financial statements.

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