What changed in this filing

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Item 1A. Risk Factors

2022-02-28 compared with 2021-03-05 · 167 added, 126 removed, 247 unchanged (54% of the section changed)

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Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of other economic factors that are beyond our control.

Although oil prices steadily rose during late 2020 and early 2021, they fell during early 2020, with West Texas Intermediate oil prices dropping from a high of $63.27 per barrel in January 2020 to a low of negative $39.68 per barrel in April 2020.

Oil prices fell beginning in early 2020 and recovered during 2021 and into early 2022.

West Texas Intermediate oil prices averaged $39.16 per barrel during 2020 and improved to an average of $77.33 per barrel during the fourth quarter of 2021.

The West Texas Intermediate price averaged $68.14 per barrel during 2021.

Over this same period, U.S.

natural gas prices have also been volatile, with the Henry Hub price ranging from a high of $3.14 per million British thermal units (“MMBtu”) in October 2020 to a low of $1.33 per MMBtu in September 2020.

As of March 3, 2021, the price of West Texas Intermediate oil was $61.28 per barrel and the Henry Hub price for natural gas was $2.82 per MMBtu.

The prolonged volatility and low levels of oil and natural gas prices and persisting supply and demand imbalances have depressed levels of exploration, development, and production activity, and if the drop in oil and natural gas prices we have experienced in 2020 continues or further declines and the supply and demand imbalances persist, there would be a material adverse effect on our business, consolidated results of operations, and consolidated financial condition.

natural gas prices have also been volatile, with the Henry Hub price ranging from a high of $23.86 per million British thermal units (“MMBtu”) in February 2021 to a low of $1.33 per MMBtu in September 2020 and averaged $2.03 and $3.89 per MMBtu during 2020 and 2021, respectively.

As of February 25, 2022, the price of West Texas Intermediate oil was $91.90 per barrel and the Henry Hub price for natural gas was $4.48 per MMBtu.

The prolonged volatility and low levels of oil and natural gas prices and supply and demand imbalances depressed levels of exploration, development, and production activity during 2020 and early 2021.

If the drop in oil and natural gas prices experienced in 2020 and early 2021 returns or further declines and the supply and demand imbalances persist, there would be a material adverse effect on our business, consolidated results of operations, and consolidated financial condition.

Should current market conditions worsen for an extended period of time, we may be required to record additional asset impairments.

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and acceleration of the development of, and demand for, alternative energy sources.

The COVID-19 pandemic has had, or may in the future have, certain negative impacts on our business, and such impacts have had, or may in the future have, an adverse effect on our business, our financial condition, results of operations, or liquidity.

The COVID-19 pandemic has had, and may in the future have, certain negative impacts on our business, and such impacts have had, and may in the future have, an adverse effect on our business, our financial condition, results of operations, or liquidity.

The COVID-19 pandemic and the resulting economic impact have had a significant negative impact on the oil and gas industry.

The deterioration in demand for oil caused by the pandemic, coupled with oil oversupply, has had, and is reasonably likely to continue to have, an adverse impact on the demand for our products and services.

The public health crisis caused by the COVID-19 pandemic, and the measures that have been taken or that may be taken in the future by governments, various regulatory agencies, our customers and our suppliers, have had, or may in the future have, certain negative impacts on our financial condition, results of operations, and liquidity, including, without limitation, the following:

• demand for our products and services declining as our customers continue to adjust their operations in response to lower oil and gas prices;

In addition to the deterioration in demand for oil in 2020 which had an adverse impact on the demand for our products and services, the public health crisis caused by the COVID-19 pandemic, and the measures that have been taken or that may be taken in the future by governments, various regulatory agencies, our customers and our suppliers, have had, and may in the future have, certain negative impacts on our financial condition, results of operations, and liquidity, including, without limitation, the following:

• actions undertaken by national, state and local governments and health officials to contain COVID-19 or treat its effects.

In response to various governmental directives, at points we have required most office-based employees, including most employees based at our headquarters in The Woodlands, Texas, to work remotely.

We may experience reductions in productivity and disruptions to our business routines while work-from-home arrangements remain in place;

We may experience reductions in productivity and disruptions to our business routines to the extent work-from-home arrangements remain in place;

• We could encounter logistical complications and increased costs adapting our disclosure controls and procedures and our internal control over financial reporting in a changing environment that includes work-from-home arrangements and furloughs.

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• restrictions on importing and exporting products;

• higher logistics costs and global shipping delays;

• impacts related to late customer payments and contractual defaults associated with customer and supplier bankruptcies;

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Also, we may be required to write off obsolete inventory, and such charges may be significant.

The resumption of our normal business operations after the disruptions caused by the COVID-19 pandemic may be delayed or constrained by its lingering effects on the oil and gas industry.

Any of the negative impacts of the COVID-19 pandemic, including those described above, alone or in combination with others, may have a significant

adverse effect on our financial condition, results of operations, or liquidity.

The full extent to which the COVID-19 pandemic will negatively affect our financial condition, results of operations, or liquidity will depend on future developments that are highly uncertain and cannot be predicted, including the scope and duration of the pandemic, the COVID-19 infection rate, the efficacy of distribution of COVID-19 vaccines, the actions taken by authorities to contain it or treat its impact and the resulting impact on the oil and gas industry.

Any of the negative impacts of the COVID-19 pandemic, including those described above, alone or in combination with others, may have a significant adverse effect on our financial condition, results of operations, or liquidity.

The full extent to which the COVID-19 pandemic will negatively affect our financial condition, results of operations, or liquidity will depend on future developments that are highly uncertain and cannot be predicted, including the scope and duration of the pandemic, the COVID-19 infection rate, the outbreak of new COVID-19 variants, the efficacy of distribution of COVID-19 vaccines, the actions taken by authorities to contain it or treat its impact and the resulting impact on the oil and gas industry.

Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist, the full extent of the impact they will have on our financial condition, results of operations, or liquidity or the pace or extent of any subsequent recovery.

Current debt and equity market conditions may continue to limit our ability to obtain additional financing, including to pursue other business opportunities or refinancing existing indebtedness upon maturity .

Conditions in the market for debt and equity securities in the energy sector have increased the difficulty of obtaining debt or equity financing to grow our business.

Due in part to the recent stock market decline, the closing price of our common stock was $0.86 as of December 31, 2020.

As of March 3, 2021 the market price for our common stock was $2.59.

At the current price for our common stock, acquisition and financing transactions that involve the use of our common equity may be significantly dilutive to our stockholders.

The issuance of new convertible debt or equity securities in the future for acquisition and financing transactions, if available, could be significantly dilutive to our stockholders.

We may have difficulty obtaining refinancing for our existing indebtedness upon maturity in the current market environment.

TETRA’s term loan matures in 2025.

We encounter, and expect to continue to encounter, intense competition in the sale of our products and services.

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Low oil prices and the supply and demand imbalance are expected to adversely affect such levels of spending in the oil and natural gas industry.

In particular, Completion Fluids & Products Division profitability in future periods will continue to be affected by the mix of its products and services, including the timing of TETRA CS Neptune completion fluid projects, which are also dependent upon the success of customer offshore exploration and drilling efforts.

Our customers are maintaining reduced capital expenditure plans for 2021 in light of current market conditions.

Such industry capital expenditure reductions have had, and are expected to continue to have, a negative effect on the demand for many of our products and services.

This has had, and may continue to have, a negative effect on our revenues and results of operations.

In addition, Completion Fluids & Products Division profitability in future periods will continue to be affected by the mix of its products and services, including the timing of TETRA CS Neptune completion fluid projects, which are also dependent upon the success of customer offshore exploration and drilling efforts.

If our customers reduce capital expenditures, such reductions may have a negative effect on the demand for many of our products and services and on our revenues and results of operations.

A large concentration of our operating activities is located in the Permian Basin region of Texas and New Mexico.

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Adverse changes in any of these other factors may have a material adverse effect on our revenues and profitability.

We are a significant shareholder of CCLP and the value of our investment in CCLP, including future distributions received from CCLP, may fluctuate substantially.

On January 29, 2021, we entered into and closed the GP Sale with Spartan to sell the general partner of CCLP along with the IDRs and approximately 23.1% of the outstanding limited partner interests in CCLP.

Following the closing of the GP Sale, we retained approximately 11.1% of the outstanding CCLP common units.

The value of our investment in CCLP may be adversely affected by negative changes in its results of operations, cash flows and financial position, which may occur as a result of the many risks attendant with operating in the compression services industry.

CCLP has substantial indebtedness and interest expense, which in turn reduces its cash available to fund capital expenditures or for distribution to CCLP’s common unitholders, including us.

CCLP’s ability to service its indebtedness will depend upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors.

If CCLP’s operating results are not sufficient to service its indebtedness, CCLP may be forced to consider taking actions such as reducing or delaying its business activities, investments and capital expenditures, delaying the increase of distributions, selling assets, restructuring or refinancing its indebtedness, or seeking additional equity capital or bankruptcy protection.

Without the ability to increase CCLP’s compression equipment fleet or otherwise grow its operations, CCLP’s ability to continue to retain customers whose compression services needs are expanding and to increase distributions to its common unitholders, including us, in the future may be limited.

We hold minority investments in both publicly-traded and privately-held companies.

Over time, the fair value of these investments may fluctuate significantly causing volatility in our financial results.

As of December 31, 2021, we hold approximately 3.8% of the outstanding CSI Compressco common units, which had a fair value of $6.2 million.

The value of our investment in CSI Compressco may be adversely affected by negative changes in its results of operations, cash flows and financial position, which may occur as a result of the many risks attendant with operating in the compression services industry.

We are party to agreements in which Standard Lithium has the right to explore, produce and extract Lithium in our Arkansas leases as well as additional potential resources in the Mojave region of California.

The company receives cash and stock of Standard Lithium under the terms of the arrangements.

If we elect to hold Standard Lithium stock received under these agreements, our operating results could be significantly affected by fluctuations in the market value of our stock holding.

As of December 2021, we also hold a $5.0 million investment in a convertible note issued by CarbonFree.

This note will be subject to fair value measurement adjustments which will affect our financial results and there can be no assurance that it will ultimately be repaid or converted into equity of CarbonFree.

Changes in the economic environment have resulted, and could further result, in significant impairments of certain of our long-lived assets.

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The impact of reduced expected future cash flow could require the write-down of all or a portion of the carrying value for these assets, which would result in additional impairments, resulting in decreased earnings.

During 2020, we recorded an impairment charge of $0.6 million primarily related to a right of use asset for the lease of our Canada office within our Water & Flowback Services Division as we ceased use of the office during the year.

During the three-year period ending December 31, 2021, we recorded a total of $93.2 million of impairments and other charges for long-lived assets other than goodwill.

During the fourth quarter of 2019, we recorded an impairment of $91.6 million in our Completion Fluids & Products Division related to our El Dorado, Arkansas calcium chloride production plant facility assets as a result of a reduction in the cost of raw materials for certain of our other chemical production plants and reduced demand for calcium chloride from the El Dorado plant due to general market conditions in the oil and gas industry.

During the fourth quarter of 2019, we also recorded an impairment of $0.3 million related to certain equipment assets in our Water & Flowback Services Division.

During the third quarter of 2018, as a result of decreased expected future cash flows from a specific customer contract, we recorded a long-lived asset impairment of $2.9 million of an identified intangible asset within the Water & Flowback Services Division.

Most significantly, during the fourth quarter of 2019, we recorded an impairment of $91.6 million in our Completion Fluids & Products Division related to our El Dorado, Arkansas calcium chloride production plant facility assets as a result of a reduction in the cost of raw materials for certain of our other chemical production plants and reduced demand for calcium chloride from the El Dorado plant due to general market conditions in the oil and gas industry.

Depressed commodity prices and/or adverse changes in the economic environment could result in a greater decrease in the demand for many of our products and services, which could impact the expected utilization rates of certain of our long-lived assets, including plant facilities, operating locations, and operating equipment.

As part of our internal annual business outlook for each of our reporting units that we performed during the fourth quarter of 2019, we considered changes in the global economic environment that negatively impacted our stock price and market capitalization.

As part of the first step of goodwill impairment testing for our Water Management reporting unit (part of our Water & Flowback Services Division) as of December 31, 2019, the only reporting unit with goodwill, we determined that the fair value of the Water Management reporting unit was less than its carrying value, and the remaining balance of $25.9 million of goodwill was impaired.

its carrying value, and the remaining balance of $25.9 million of goodwill was impaired.

Additional internal annual business outlook analyses for each of our reporting units that we performed during the fourth quarters of 2020 and 2021 did not indicate additional impairments.

We are dependent on third-party suppliers for specific products and equipment necessary to provide certain of our products and services.

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In our manufacture of brominated CBF products, we use elemental bromine, hydrobromic acid, and other raw materials that are purchased from third parties.

Although we have long-term supply agreements with Lanxess, if we were unable to acquire these raw materials at reasonable

prices for a prolonged period, our Completion Fluids & Products Division business could be materially and adversely affected.

The fabrication of our production testing, well monitoring, sand separation, and water management equipment requires the purchase of various components, some of which we obtain from a single source or a limited group of suppliers.

Our reliance on these suppliers exposes us to the risk of price increases, inferior component quality, or an inability to obtain an adequate supply of required components in a timely manner.

The profitability or future growth of our Water & Flowback Services Division may be adversely affected due to our dependence on these key suppliers.

There are several raw materials for which there are only a limited number of suppliers or a single supplier.

For example, we are currently required to purchase all of our requirements of elemental bromine, up to a certain specified maximum, from Lanxess under a long-term supply agreement.

To mitigate potential supply constraints, we enter into supply agreements with particular suppliers, including Lanxess.

We also evaluate alternative sources of supply to avoid reliance on limited or sole-source suppliers when possible.

Although we have long-term supply agreements with Lanxess, there is no assurance that we will have an adequate supply of elemental bromine or the other raw materials required for all of our CBFs opportunities, or that such raw materials will be available at reasonable prices.

Economic sanctions and other regulations imposed by the United States and other international countries as a result of the conflict involving Russia and Ukraine may disrupt supplies or affect the prices of certain raw materials.

Should the conflict in Ukraine or other international locations further escalate, it is difficult to anticipate the extent to which current or future sanctions could increase our costs, disrupt our supplies, reduce our sales or otherwise affect our operations.

If we are unable to acquire these raw materials at reasonable prices, or at all, for a prolonged period, our Completion Fluids & Products Division business could be materially and adversely affected.

Operating and Technological Risks

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We are subject to a number of risks associated with the GP Sale, and these risks could adversely impact our operations, financial condition and business.

On January 29, 2021, we closed the sale of CCLP’s general partner and approximately 23.1% of the outstanding limited partner interests in CCLP to Spartan.

On January 29, 2021, we closed the sale of CSI Compressco’s general partner and approximately 23.1% of the outstanding limited partner interests in CSI Compressco to Spartan.

We are subject to a number of risks associated with this transaction, including risks associated with:

• any required payments of indemnification obligations under the Purchase Agreement for retained liabilities and breaches of representations, warranties or covenants;

• our failure to realize the full purchase price anticipated under the Purchase Agreement, including the ability of CCLP to generate adjusted EBITDA on or prior to December 31, 2022 sufficient to result in payment of the contingent consideration.

• our failure to realize the full purchase price anticipated under the Purchase Agreement, including the ability of CSI Compressco to generate adjusted EBITDA on or prior to December 31, 2022 sufficient to result in payment of the contingent consideration.

As a result of these risks, we may be unable to realize the anticipated benefits of the transaction, including the total amount of consideration we expect to realize.

Our failure to realize the anticipated benefits of the transaction

would adversely impact our operations, financial condition and business and could limit our ability to pursue additional strategic transactions.

Our failure to realize the anticipated benefits of the transaction would adversely impact our operations, financial condition and business and could limit our ability to pursue additional strategic transactions.

We may not be able to economically extract lithium or bromine from the leased acreage in our Arkansas brine leases.

Our Arkansas brine leases currently only contain exploration targets of lithium and bromine, and we may never discover proven mineral reserves on these properties.

While we continue to evaluate the next steps regarding the potential development of our brine leases, we have only very recently started to conduct exploration work on the leases, and we are not currently able to determine the economic viability of the extraction of the lithium and bromine from the leased acreage.

In addition, the extraction of lithium and bromine from these brine leases will likely require a significant amount of time and capital, which we are not able to estimate at this time and which may not be available to us on acceptable terms or at all.

There can be no assurance that any future exploration efforts on these properties will be successful.

As a result of these uncertainties, no assurance can be given that any future exploration programs will result in the discovery of commercial mineral resources or reserves.

Failure to effectively and timely execute our any of our low carbon energy initiatives could have an adverse effect on business and financial condition.

Our future success may depend on our ability to effectively execute on our low carbon energy initiatives.

This strategy depends on our ability to effectively develop new technologies, expand application of our global infrastructure and chemistry expertise and on the economic viability of the extraction of lithium and bromine from the leased acreage.

The exploration, development and extraction of brine and lithium from our Arkansas brine leases will likely require significant time and capital, and there is no guarantee of a return from these operations.

Our low carbon energy initiatives may also depend in part on successful development of partnerships with other companies, such as our partnership and investment in CarbonFree, and such partners’ execution of their own respective projects and business strategies.

If we, or the projects or partners we invest in, fail to execute our low carbon energy initiatives as planned, or if execution of such initiatives requires more time and capital than expected, demand for our technologies, services and mineral assets and consequently, our business, results of operations and financial condition could be adversely affected.

Weather-Related Risks

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A portion of our operations is susceptible to adverse weather conditions in the Gulf of Mexico, including hurricanes and other extreme weather conditions.

Our 2021 results reflect an estimated unfavorable impact of $3.1 million due to the severe weather conditions during February that shut down fracking activity in several of our key markets and negatively impacted the supply chain for our industrial chemicals operations.

Even if we do not experience direct damage from storms, we may experience disruptions in our operations, because we are unable to operate or our customers or suppliers may curtail their activities due to damage to their wells, platforms, pipelines, and facilities.

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Our long-term debt agreements contain covenants and other provisions that restrict our ability to take certain actions and may limit our ability to operate or grow our business in the future.

As of December 31, 2020, our total long-term debt outstanding of $199.9 million, excluding debt of CCLP included in liabilities of discontinued operations, consisted of the carrying amount outstanding under our credit agreement (the “Term Credit Agreement”) and our Asset-Based Credit Agreement (the “ABL Credit Agreement”), both of which we entered into in September 2018.

Following the closing of the GP Sale on January 29, 2021, our consolidated balance sheet will no longer include the amounts of CCLP.

We were required to use all net cash proceeds from the sale to repay borrowings under our Term Credit Agreement.

liens, (iii) engaging in mergers and other fundamental changes, (iv) making investments, (v) entering into, or amending, transactions with affiliates, (vi) paying dividends and making other restricted payments, (vii) prepaying other indebtedness, and (viii) selling assets.

As of December 31, 2021, our total long-term debt outstanding of $151.9 million consisted of the carrying amount outstanding under our credit agreement (the “Term Credit Agreement”) and our Asset-Based Credit Agreement (the “ABL Credit Agreement”), both of which we entered into in September 2018.

Following the closing of the GP Sale on January 29, 2021, we were required to use all net cash proceeds from the sale to repay borrowings under our Term Credit Agreement.

The ABL Credit Agreement and Term Credit Agreement each contain certain affirmative and negative covenants, including covenants that restrict the ability of TETRA and certain of its subsidiaries to take certain actions including, among other things and subject to certain significant exceptions, (i) incurring debt, (ii) granting liens, (iii) engaging in mergers and other fundamental changes, (iv) making investments, (v) entering into, or amending, transactions with affiliates, (vi) paying dividends and making other restricted payments, (vii) prepaying other indebtedness, and (viii) selling assets.

The ABL Credit Agreement also contains a provision that may require a fixed charge coverage ratio (as defined in the ABL Credit Agreement) of not less than 1.00 to 1.00 in the event that certain conditions associated with outstanding borrowings and cash availability occur.

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Our Term Credit Agreement requires us to annually prepay up to 50% of Excess Cash Flow (as defined in the Term Credit Agreement) from the most recent full fiscal year.

If our Leverage Ratio (as defined in the Term Credit Agreement) at year-end is less than 2.00 to 1.00 , the prepayment requirement is decreased to 25%.

If our Leverage Ratio (as defined in the Term Credit Agreement) at year-end is less than 2.00 to

1.00 , the prepayment requirement is decreased to 25%.

If our Leverage Ratio at year-end is less than 1.50 to 1.00, then no prepayment is required.

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To the extent that a buyer of these properties fails to perform the decommissioning work required, a previous owner, including Maritech, may be required to perform operations to satisfy the decommissioning liabilities.

As a result of the third-party indemnity agreements and corporate guaranties we have previously provided to the U.S.

Department of the Interior and to other private third-parties as the former parent company of Maritech, we may be responsible for satisfying these decommissioning obligations if they are not satisfied by the current owners and operators of the properties or by Maritech.

As a result of the third-party indemnity agreements and corporate guaranties we have previously provided, we may be responsible for satisfying these obligations if they are not satisfied by the current owners and operators of the properties or by Maritech.

Significant decommissioning liabilities that were assumed by the buyers of the Maritech properties in these previous sales remain unperformed.

If oil and natural gas pricing levels continue to be depressed or further deteriorate, one or more of these buyers may be unable to perform the decommissioning work required on a property previously owned by Maritech.

If these buyers, or any successor owners of the Maritech properties, are unable to satisfy and extinguish their decommissioning liabilities due to bankruptcy or other liquidity issues, the U.S.

Department of the Interior may seek to impose those decommissioning obligations on Maritech and on us due to our third party indemnity agreements, and contractual commitments and guaranties issued from time to time by us to the U.S.

Department of the Interior and various third parties.

Department of the Interior may seek to impose those obligations on Maritech and on us.

The amount of cash necessary to satisfy these obligations could be significant and could adversely affect our business, results of operations, financial condition, and cash flows.

In March 2018, pursuant to a series of transactions, Maritech sold the remaining offshore leases held by Maritech to Orinoco Natural Resources, LLC (“Orinoco”) and, immediately thereafter, we sold all equity interest in Maritech to Orinoco.

The assignments for six of the offshore leases conveyed to Orinoco have not been approved by the U.S.

Department of the Interior and Maritech remains an owner of record for these leases.

Maritech also remains a recognized operator of a portion of four other offshore properties.

The assignments for all of the offshore leases conveyed to Orinoco have now been approved by the U.S.

Department of the Interior and Orinoco (or its successors in interest) own these leases.

Maritech also remains a recognized owner of one additional lease and remains an operator of a portion of four other offshore leases, two of which have either been relinquished or expired.

Maritech was also a lessee on six leases when they expired and which have unsatisfied decommissioning liabilities.

Under the Maritech Asset Purchase Agreement, Orinoco assumed all of Maritech’s decommissioning liabilities related to the leases conveyed to Orinoco (the “Orinoco Lease Liabilities”) and, under the Maritech Membership Interest Purchase Agreement, Orinoco assumed all other liabilities of Maritech, including the Legacy Liabilities, subject to limited exceptions unrelated to the decommissioning liabilities.

Pursuant to a Bonding Agreement executed in connection with such purchase agreements, Orinoco provided non-revocable bonds in the aggregate amount of approximately $46.8 million to secure the performance of certain of Maritech’s decommissioning obligations related to the Orinoco Lease Liabilities and certain of Maritech’s remaining current decommissioning obligations (not including the Legacy Liabilities).

Orinoco was required to replace the initial bonds delivered at closing with other non-revocable performance bonds in two stages.

The first set of replacement bonds were required to be delivered within 90 days following closing and the second set of replacement bonds were required to be delivered within 180 days following closing.

The replacement bonds had to meet certain additional requirements and were required to be in the aggregate sum of $47.0 million.

In the event Orinoco did not provide the first or second set of replacement bonds, Orinoco was required to make cash escrow payments.

Among the other requirements of the final replacement bonds was that

they must provide coverage for all of the asset retirement obligations of Maritech instead of only relating to specific properties.

The payment obligations of Orinoco under the Bonding Agreement are guaranteed by Thomas M.

Clarke and Ana M.

Clarke pursuant to a separate guaranty agreement (the “Clarke Bonding Guaranty Agreement”).

Orinoco has not delivered such replacement bonds and neither it nor the Clarkes has made any of the escrow payments required pursuant to the terms of the Bonding Agreement.

We filed a lawsuit against Orinoco and the Clarkes to enforce the terms of the Bonding Agreement and the Clarke Bonding Guaranty Agreement.

A summary judgment was initially granted in favor of Orinoco and the Clarkes, which dismissed our claims against Orinoco under the Bonding Agreement and against the Clarkes under the Clarke Bonding Guaranty Agreement.

We filed an appeal and also asked the trial court to grant a new trial on the summary judgment to modify the judgment because we believe this judgment should not have been granted.

On November 5, 2019, the trial court signed an order granting our motion for new trial and vacating the prior order granting summary judgment for Orinoco and the Clarkes.

The parties are awaiting direction from the court on a new scheduling order and/or trial setting.

The non-revocable performance bonds delivered at the closing remain in effect.

If in the future we become liable for decommissioning liabilities associated with any property covered by either an initial bond or stage 1 permanent bond, the Bonding Agreement provides that if we call any of the initial bonds or the stage 1 permanent bonds to satisfy such liability and the amount of the bond payment is not sufficient to pay for such liability, Orinoco will pay us for the additional amount required.

Our guarantees may still cover these liabilities.

Orinoco was required to replace the Initial Bonds delivered at closing with other non-revocable performance bonds but has not done so.

See Note 11 - “Commitments and Contingencies” in the Notes to Consolidated Financial Statements for further discussion of status of bond replacement.

If in the future we become liable for decommissioning liabilities associated with any property covered by either an Initial Bond or Replacement Bonds, the Bonding Agreement provides that if we call any of the Initial Bonds or the Interim Replacement Bonds to satisfy such liability and the amount of the bond payment is not sufficient to pay for such liability, Orinoco will pay us for the additional amount required.

To the extent Orinoco is unable to cover any such deficiency or we become liable for a significant portion of the Legacy Liabilities, our financial condition and results of operations may be negatively affected.

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Recent and additional anticipated changes to the supplemental bonding and financial assurance program managed by the U.S.

Department of the Interior could require all oil and gas owners and operators with infrastructure in the Gulf of Mexico to provide additional supplemental bonds or other acceptable financial assurance for decommissioning liabilities.

Department of the Interior could require all oil and gas owners and operators with infrastructure in the Gulf of Mexico to provide additional supplemental bonds or other acceptable financial

assurance for decommissioning liabilities.

These changes have the potential to adversely impact the financial condition of lease owners and operators in the Gulf of Mexico and increase the number of such owners and operators seeking bankruptcy protection, given current oil and gas prices.

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Department of the Interior under the Trump Administration ultimately rescinded the 2016 NTL in 2020, the Biden Administration could seek to reconsider the changes made by the U.S.

Department of the Interior under the Trump Administration and, should the Biden Administration re-issue and fully implement guidance or rules analogous to, or more rigorous than, the 2016 NTL, such developments could increase operating costs for lease owners and operators in the Gulf of Mexico and reduce the availability of surety bonds due to the increased demands for such bonds in a low-price commodity environment.

As a result, there is significant uncertainty surrounding financial assurance obligations for Gulf of Mexico lease owners and operators and for us through the third-party indemnity agreements we have provided for Maritech liabilities to the U.S.

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Department of the Interior also recently increased its estimates for decommissioning liabilities in the Gulf of Mexico, causing the potential need for additional supplemental bonding and/or other financial assurances to be dramatically increased.

When coupled with the volatile and currently low prices of oil and gas, it is difficult to predict the impact of the rule and regulatory changes already promulgated and as may be forthcoming by the U.S.

When coupled with the volatile prices of oil and gas, it is difficult to predict the impact of the rule and regulatory changes already promulgated and as may be forthcoming by the U.S.

Department of the Interior relating to financial assurance for decommissioning liabilities.

Any revisions to the U.S.

us due to the fact that we are only a former parent company of Maritech and are only a guarantor as opposed to an actual lease owner or operator.

Department of the Interior’s supplemental bonding process could result in demands for the posting of increased financial assurances by owners and operators in the Gulf of Mexico, including Maritech, Orinoco and the other entities to whom Maritech divested its Gulf of Mexico assets, but such demands cannot be directly placed on us due to the fact that we are only a former parent company of Maritech and are only a guarantor as opposed to an actual lease owner or operator.

This may force lease owners and operators of leases and other infrastructure in the Gulf of Mexico to obtain surety bonds or other forms of financial assurance, the costs of which could be significant.

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Many of our customers, particularly those associated with our onshore operations, are small- to medium-sized oil and gas operators that may be more susceptible to declines in oil and gas commodity prices or generally increased operating expenses than larger companies.

Our ability to collect from our customers is impacted by the current volatile oil and natural gas price environment and we may face increased credit risks if the current reduced price of oil continues for an extended period of time.

Our ability to collect from our customers could be impacted by volatility in the oil and natural gas price environment and we may face increased credit risks if the price of oil were to fall and remain low for an extended period of time.

As discussed in the preceding risk factors, we face the risk of having to satisfy decommissioning liabilities on properties presently or formerly owned by Maritech.

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We are exposed to interest rate risks with regard to our credit facility debt and future refinancing thereof.

As of December 31, 2020, we had no outstanding balance under our ABL Credit Agreement and $213.5 million outstanding under our Term Credit Agreement.

Following repayment from GP Sale proceeds, the balance outstanding under our Term Credit Agreement is $201.7 million.

As of December 31, 2021, we had $1.6 million outstanding balance under our ABL Credit Agreement and $163.1 million outstanding under our Term Credit Agreement.

These credit facilities consist of floating rate loans that bear interest at an agreed upon percentage rate spread above London Interbank Offered Rate (“LIBOR”) or an alternate base rate.

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We currently are not a party to an interest rate swap contract or other derivative instrument designed to hedge our exposure to interest rate fluctuation risk.

Our ABL Credit Agreement is scheduled to mature on September 10, 2023.

Our ABL Credit Agreement is scheduled to mature on May 31, 2025.

Our Term Loan Agreement is scheduled to mature on September 10, 2025.

There can be no assurance that financial market conditions or borrowing terms at the times these existing debt agreements are renegotiated will be as favorable as the current

terms and interest rates.

There can be no assurance that financial market conditions or borrowing terms at the times these existing debt agreements are renegotiated will be as favorable as the current terms and interest rates.

We may be unable to obtain financing in the future for working capital, capital expenditures, acquisitions, debt service requirements, or other purposes.

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For example, the EPA has asserted federal regulatory authority under the Safe Drinking Water Act Underground Injection Control program over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance for such activities and issued a final regulation under the Clean Water Act prohibiting discharges to publicly owned treatment works of wastewater from onshore unconventional oil and gas facilities.

Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability;

surface spills during the management of fracturing fluids, chemicals or produced water;

injection of fracturing fluids into wells with inadequate mechanical integrity;

injection of fracturing fluids directly into groundwater resources;

discharge of inadequately treated fracturing wastewater to surface waters;

and disposal or storage of fracturing wastewater in unlined pits.

Certain environmental and other groups have suggested that additional federal, state, and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process.

Several states have adopted regulations that require operators to disclose the chemical constituents in hydraulic fracturing fluids.

Several states have adopted regulations that require operators to disclose

the chemical constituents in hydraulic fracturing fluids.

We cannot predict whether any federal, state or local laws or regulations will be enacted regarding hydraulic fracturing, and, if so, what actions any such laws or regulations would require or prohibit.

If additional levels of regulation or permitting requirements were imposed on oil and gas operators through the adoption of new laws and regulations, the domestic demand for certain of our products and services could be decreased or subject to delays.

Other jurisdictions where our products and services are used may impose similar or more stringent restrictions.

If additional levels of regulation or permitting requirements were imposed on oil and gas operators through the adoption of new laws and regulations, the demand for certain of our products and services could be decreased or subject to delays.

We operate in the U.S.

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Other governmental or regulatory actions could further reduce our revenues and increase our operating costs, including the cost to insure offshore operations, resulting in reduced cash flows and profitability.

Our onshore and offshore operations expose us to risks such as the potential for harmful substances escaping into the environment and causing damages or injuries, which could be substantial.

Our onshore and offshore operations, including operations related to energy storage and carbon capture, utilization and storage, expose us to risks such as the potential for harmful substances escaping into the environment and causing damages or injuries, which could be substantial.

We maintain limited environmental liability insurance covering named locations and environmental risks associated with contract services for oil and gas operations.

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Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties, or international agreements that impose additional restrictions on the industry may adversely affect our financial results.

Regulators are becoming more focused on air emissions from oil and gas operations, including volatile organic compounds, hazardous air pollutants, and greenhouse gases (“GHGs”).

Regulators are becoming more focused on-air emissions from oil and gas operations, including volatile organic compounds, hazardous air pollutants, and GHGs.

In particular, the focus on GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our financial results if such laws, regulations, treaties, or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally.

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In addition to increasing our risk of environmental liability, the rigorous enforcement of environmental laws and regulations has accelerated demand for our products and services in some of the markets we serve.

Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas our customers produce, while the physical effects of climate change could disrupt production and cause us to incur costs in preparing for or responding to those effects.

The EPA has adopted various regulations to restrict emissions of GHGs under existing provisions of the CAA.

Such EPA rules regulate GHG emissions under the CAA and require a reduction in emissions of GHGs from motor vehicles and from certain large stationary sources.

For example, the EPA published final rules in June 2016 that require the reduction of volatile organic compounds and methane emissions from certain hydraulically fractured natural gas wells and further require that most wells use so-called “green” completions.

These regulations also established new requirements regarding emissions from production-related wet seal and reciprocating compressors, pneumatic controllers and storage vessels.

While the EPA under the Trump Administration finalized rules to rescind or modify certain of these requirements in September 2020, including rescission of the methane-specific requirements applicable to sources in the production and processing segments of the oil and gas industry, various states and industry and environmental groups are separately challenging the EPA’s 2016 standards and its September 2020 final rule.

Moreover, notwithstanding the current court challenges, the EPA under the Biden Administration is expected to reconsider the September 2020 final rule, which could result in more stringent methane emission rulemaking.

In addition, the EPA also requires the annual reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, as well as from certain oil and gas production facilities.

In addition, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global GHG emissions (the “Paris Agreement”).

The Paris Agreement entered into force in November 2016 after more than 170 nations ratified or otherwise indicated their intent to be bound by the Paris Agreement.

Although the United States withdrew from the Paris Agreement in November 2020, President Biden issued an executive order recommitting the United States to the Paris Agreement in January 2021.

President Biden has also issued executive orders that commit to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and an increased emphasis on climate-related risk across government agencies and economic sectors.

The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our facilities and operations could require us to incur costs.

Congress (“Congress”) has considered and almost one-half of the states have adopted legislation that seeks to control or reduce emissions of GHGs from a wide range of sources.

Any such legislation could adversely affect demand for the oil and natural gas our customers produce and, in turn, demand for our products and services.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events;

if any such effects were to occur, they could have an adverse effect on our operations and cause us to incur costs in preparing for or responding to those effects.

For more information on the environmental laws and regulations to which we are subject, see our disclosures titled “Health, Safety, and Environmental Affairs Regulation” set forth in Item 1 of this Annual Report.

Our operations, and those of our suppliers and customers, are subject to a series of risks arising from climate change.

The threat of climate change continues to attract considerable attention in the United States and in foreign countries.

As a result, our operations as well as the operations of our oil and natural gas exploration and production customers and our suppliers are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.

In the United States, no comprehensive climate change legislation has been implemented at the federal level.

However, President Biden has highlighted addressing climate change as a priority of his administration and has issued several executive orders addressing climate change.

Moreover, following the U.S.

Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, implementing GHG emissions limits on vehicles manufactured for operation in the United States.

The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years.

In September 2020, the Trump Administration revised prior regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations.

However, subsequently, the U.S.

Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions, effectively reinstating the prior standards.

Additionally, in November 2021, EPA issued a proposed rule that, if finalized, would establish OOOO(b) new source and OOOO(c) first-time existing source standards of performance for methane and volatile organic compound emissions for oil and gas facilities.

Operators of affected facilities will have to comply with

specific standards of performance to include leak detection using optical gas imaging and subsequent repair requirement, and reduction of emissions by 95% through capture and control systems.

EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November 2021 proposed rule and anticipates the issuance of a final rule by the end of the year.

We cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements.

However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a significant possibility.

Separately, various states and groups of states have adopted or are considering adopting legislation, regulation or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions.

At the international level, the United Nations-sponsored "Paris Agreement" requires member states to submit non-binding, individually determined reduction goals known as Nationally Determined Contributions (“NDCs”) every five years after 2020.

Following President Biden’s executive order in January 2021, the United States rejoined the Paris Agreement and, in April 2021, established a goal of reducing economy wide net GHG emissions 50-52% below 2005 levels by 2030.

Additionally, at the 26th Conference of the Parties (“COP26”) in Glasgow in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge;

an initiative committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all feasible reductions” in the energy sector.

The full impact of these actions is uncertain at this time, and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects upon us and our customers’ operations.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including action taken by President Biden with respect to his climate change related pledges.

On January 27, 2021, President Biden issued an executive order that called for substantial action on climate change, including, among other things, the increased use of zero-emission vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across government agencies and economic sectors.

The Biden Administration has also called for restrictions on leasing on federal land.

For more information, see our risk factor titled “Regulatory initiatives related to hydraulic fracturing in the countries where we and our customers operate could result in operating restrictions or delays in the completion of oil and gas wells that may reduce demand for our services.” Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emission limitations for oil and gas facilities.

Litigation risks are also increasing as a number of parties have sought to bring suit against oil and natural gas companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

There are also increasing financial risks for companies in the fossil fuel sector as shareholders currently invested in such companies may elect in the future to shift some or all of their investments into other sectors.

Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies.

For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals.

The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050.

There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector.

In late 2020, the Federal Reserve announced that it had joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector.

Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities.

Although we cannot predict the effects of these actions, such limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities, which could reduce demand for our products and services.

Additionally, the Securities and Exchange Commission announced its intention to promulgate rules requiring climate disclosures.

Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate the GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce demand for our products and services.

Additionally, political, litigation and financial risks may result in our oil and natural gas operators restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce the demand for our products and services.

One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact us, our customers’, and our suppliers’ operations.

Such physical risks may result in damage to our customers’ facilities or otherwise adversely impact their operations, such as if they become subject to water use curtailments in response to drought, or demand for their products, such as to the extent warmer winters reduce the demand for energy for heating purposes, which may ultimately reduce demand for the products and services we provide.

Such physical risks may also impact our suppliers, which may adversely affect our ability to provide our products and services.

Increased attention to ESG matters and conservation measures may adversely impact our or our customers’ business.

Increasing attention to, and societal expectations on companies to address, climate change and other environmental and social impacts, investor and societal expectations regarding voluntary ESG disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our customers’ products, reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets.

Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us or our customers.

To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.

For more information, see our risk factor titled “Our operations, and those of our suppliers and customers, are subject to a series of risks arising from climate change.”

Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, certain statements in those voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith.

Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters.

Additionally, we may announce various targets or product and service offerings in an attempt to improve our ESG profile.

However, we cannot guarantee that we will be able to meet any such targets or that such targets or offerings will have the intended results on our ESG profile, including but not limited to as a result of unforeseen costs, consequences, or technical difficulties associated with such targets or offerings.

Also, despite any voluntary actions, we may receive pressure from certain investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals or policies, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters.

Such ratings are used by some investors to inform their investment and voting decisions.

Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital.

Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.

Such ESG matters may also impact our customers, which may result in reduced demand for certain of our products and services.

We also cannot guarantee that any new product or service offerings we develop in light of ESG matters, including but not limited to the energy transition, will be suitable for our customers’ business operations.

To the extent alternative technologies are preferred, whether as a result of regulatory impacts or changes in industry practice, it may adversely impact our business or results of operation.

Our operations in foreign countries exposes us to complex regulations and may present us with new obstacles to growth.

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Hydraulic fracturing typically is regulated by state oil and gas commissions or similar state agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process in the U.S.

For example, the EPA (i) asserted regulatory authority pursuant to the federal Safe Drinking Water Act Underground Injection Control program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities, (ii) published final rules under the federal CAA in 2012 and published additional final regulations in June 2016 governing methane and volatile organic compound performance standards, including standards for the capture of air emissions released by the oil and natural gas hydraulic fracturing industry (however, rules were finalized in September 2020 modifying or rescinding some of these requirements), (iii) in June 2016 published an effluent limitations final rule prohibiting the discharge of waste water from shale natural-gas extraction operations to a treatment plant, and (iv) in 2014 published an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing.

For example, the EPA has issued rulemakings under several laws governing hydraulic fracturing activities and disposal of wastes associated with the process.

In 2016, the U.S.

Bureau of Land Management (“BLM”) published a final rule that established new or more stringent standards for performing hydraulic fracturing on federal and Indian lands.

Bureau of Land Management (“BLM”) also published a final rule that established new or more stringent standards for performing hydraulic fracturing on federal and Indian lands.

BLM under the Trump Administration issued a final rule in late 2018 rescinding the 2016 action;

however, a California federal court vacated the 2018 final rule in July 2020, and a Wyoming federal court subsequently vacated the 2016 final rule in October 2020.

Accordingly, the 2016 final rule is no longer in effect, but the Wyoming decision is expected to be appealed.

Accordingly, the 2016 final rule is no longer in effect, but the Wyoming decision has been appealed.

Moreover, the Biden Administration is expected to pursue regulatory initiatives that restrict hydraulic fracturing activities on federal lands as well as other actions to more stringently regulate certain aspects of oil and gas development such as air emissions and water discharges.

On January 20, 2021, the Acting Secretary of the U.S.

Department of the Interior issued an order, effective immediately, that suspends new oil and gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days.

In addition, President Biden issued an executive order on January 27, 2021, that suspends new leasing activities for oil and gas exploration and production on non-Indian federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities on such lands and waters.

However, these orders do not apply to operations under existing leases and permits.

The Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process.

President Biden issued an executive order on

January 27, 2021, that suspends new leasing activities, but not operations under existing leases, for oil and gas exploration and production on non-Indian federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities on such lands and waters.

Although the federal court for the Western District of Louisiana issued a preliminary injunction against the leasing pause, in response to the executive order, the Department of Interior issued a report recommending various changes to the federal leasing program, though many such changes would require Congressional action.

As a result, we cannot predict the final scope of regulations or restrictions that may apply to oil and gas operations on federal lands and waters.

However, any regulations that ban or effectively ban such operations may adversely impact demand for our products and services.

The United States Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process.

At the state level, some states, including Texas, Oklahoma and New Mexico, have adopted, and other states are considering adopting legal requirements that could impose new or more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities.

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We also invest in security technology, perform penetration tests from time to time, and design our business processes to attempt to mitigate the risk of such breaches.

However, there can be no assurance that security breaches will not occur.

However, there can be no assurance that

security breaches will not occur.

Moreover, the development and maintenance of these measures requires continuous monitoring as technologies change and efforts to overcome security measures evolve.

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However, a successful breach or attack could have a material negative impact on our operations or business reputation and subject us to consequences such as litigation and direct costs associated with incident response.

Changes to applicable tax laws and regulations or exposure to additional income tax liabilities could affect our business and future profitability.

We are subject to various complex and evolving United States federal, state, and local and non-U.S.

Our business and future profitability could be affected by numerous factors, including the availability of tax credits, exemptions, refunds and other benefits to reduce our tax liabilities, changes in the relative amount of our earnings subject to tax in the various jurisdictions in which we operate or have subsidiaries, the potential expansion of our business into or otherwise becoming subject to tax in additional jurisdictions, changes to our existing business structure and operations, the extent of our intercompany transactions, and the extent to which taxing authorities in the relevant jurisdictions respect those intercompany transactions.

Further, United States federal, state, and local and non-U.S.

tax laws, policies, statutes, rules, regulations, or ordinances could be interpreted, changed, modified, or applied adversely to us, in each case, possibly with retroactive effect, and may have an adverse effect on our business and future profitability.

For example, several tax proposals have been set forth that would, if enacted, make significant changes to United States tax laws.

Such proposals include an increase in the U.S.

income tax rate applicable to corporations (such as us) from 21%, the imposition of a minimum tax on book income for certain corporations, and the imposition of an excise tax on certain corporate stock repurchases that would be borne by the corporation repurchasing such stock.

The United States Congress may consider, and could include, some or all of these proposals in connection with tax reform that may be undertaken.

It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect.

The passage of any legislation as a result of these proposals and other similar changes in United States federal income tax laws could adversely affect our business and future profitability.

Unresolved Staff Comments.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1A. Risk Factors