Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss, reported as a component of stockholders’stockholders' equity, decreased from $70.3 million at December 31, 2016primarily relates to $56.8 million at September 30, 2017, due to changesfluctuations in currency exchange rates. Accumulated other comprehensive loss is primarily related to fluctuations in the currency exchange rates compared toagainst the U.S. dollar which areas used to translate certain of the international operations of our reportablethe Company's operating segments. Accumulated other comprehensive loss decreased from $66.0 million at December 31, 2021 to $65.2 million at March 31, 2022. For the ninethree months ended September 30, 2017March 31, 2022 and 2016,2021, currency translation adjustments recognized as a component of other comprehensive income (loss)loss due to exchange rate movements were primarily attributable to the United Kingdom and Brazil. As of September 30, 2017,
During the three months ended March 31, 2022, the exchange ratesrate for the British pound and the Brazilian realweakened by 3% compared to the U.S. dollar and the Brazilian real strengthened by 8% and 3%, respectively,17% compared to the exchange rates at December 31, 2016,U.S. dollar, contributing to other comprehensive income of $13.5 million reported for$0.9 million. During the ninethree months ended September 30, 2017. During the first nine months of 2016,March 31, 2021, the exchange ratesrate for the British pound weakenedstrengthened by 12%1% compared to the U.S. dollar while the Brazilian real strengthenedweakened by 22%8% compared to the U.S. dollar, during the same period, contributing to other comprehensive loss of $12.5$1.5 million.
| |
5. | For the three months ended March 31, 2022, the Company's income tax expense was $3.4 million on a pre-tax loss of $6.0 million. Income tax expense in the first quarter of 2022 included the impact of valuation allowances recorded against U.S. tax assets as well as certain non-deductible expenses and discrete tax items. This compares to an income tax benefit of $2.3 million on a pre-tax loss of $18.1 million, which included certain non-deductible expenses and discrete tax items, for the three months ended March 31, 2021.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 8. Net Loss Per Share |
The table below provides a reconciliation of the numerators and denominators of basic and diluted net loss per share for the three and nine months ended September 30, 2017March 31, 2022 and 20162021 (in thousands, except per share amounts):
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| Numerators: | | | | | | | |
| Net loss from continuing operations | $ | (15,031 | ) | | $ | (10,818 | ) | | $ | (46,955 | ) | | $ | (35,759 | ) |
| Less: Income attributable to unvested restricted stock awards | — |
| | — |
| | — |
| | — |
|
Numerator for basic net loss per share from continuing operations | (15,031 | ) | | (10,818 | ) | | (46,955 | ) | | (35,759 | ) |
| Net loss from discontinued operations, net of tax | — |
| | — |
| | — |
| | (4 | ) |
Numerator for basic net loss per share attributable to Oil States | (15,031 | ) | | (10,818 | ) | | (46,955 | ) | | (35,763 | ) |
| Effect of dilutive securities: | | | | | | | |
| Unvested restricted stock awards | — |
| | — |
| | — |
| | — |
|
Numerator for diluted net loss per share attributable to Oil States | $ | (15,031 | ) | | $ | (10,818 | ) | | $ | (46,955 | ) | | $ | (35,763 | ) |
| | | | | | | | |
| Denominators: | | | | | | | |
| Weighted average number of common shares outstanding | 51,089 |
| | 51,354 |
| | 51,310 |
| | 51,287 |
|
| Less: Weighted average number of unvested restricted stock awards outstanding | (1,111 | ) | | (1,132 | ) | | (1,120 | ) | | (1,129 | ) |
Denominator for basic net loss per share attributable to Oil States | 49,978 |
| | 50,222 |
| | 50,190 |
| | 50,158 |
|
| Effect of dilutive securities: | | | | | | | |
| Unvested restricted stock awards | — |
| | — |
| | — |
| | — |
|
| Assumed exercise of stock options | — |
| | — |
| | — |
| | — |
|
| | — |
| | — |
| | — |
| | — |
|
Denominator for diluted net loss per share attributable to Oil States | 49,978 |
| | 50,222 |
| | 50,190 |
| | 50,158 |
|
| | | | | | | | |
Basic net loss per share attributable to Oil States from: | | | | | | | |
| Continuing operations | $ | (0.30 | ) | | $ | (0.22 | ) | | $ | (0.94 | ) | | $ | (0.71 | ) |
| Discontinued operations | — |
| | — |
| | — |
| | — |
|
| Net loss | $ | (0.30 | ) | | $ | (0.22 | ) | | $ | (0.94 | ) | | $ | (0.71 | ) |
| | | | | | | | |
Diluted net loss per share attributable to Oil States from: | | | | | | | |
| Continuing operations | $ | (0.30 | ) | | $ | (0.22 | ) | | $ | (0.94 | ) | | $ | (0.71 | ) |
| Discontinued operations | — |
| | — |
| | — |
| | — |
|
| Net loss | $ | (0.30 | ) | | $ | (0.22 | ) | | $ | (0.94 | ) | | $ | (0.71 | ) |
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
(Continued)
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended
March 31, |
| | | | | 2022 | | 2021 | | |
| Numerators: | | | | | | | | | |
| Net loss | | | | | $ | (9,424) | | | $ | (15,810) | | | |
| Less: Income attributable to unvested restricted stock awards | | | | | — | | | — | | | |
| Numerator for basic net loss per share | | | | | (9,424) | | | (15,810) | | | |
| Effect of dilutive securities: | | | | | | | | | |
| Unvested restricted stock awards | | | | | — | | | — | | | |
| Numerator for diluted net loss per share | | | | | $ | (9,424) | | | $ | (15,810) | | | |
| | | | | | | | | |
| Denominators: | | | | | | | | | |
| Weighted average number of common shares outstanding | | | | | 61,627 | | | 61,169 | | | |
| Less: Weighted average number of unvested restricted stock awards outstanding | | | | | (1,129) | | | (1,071) | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Denominator for basic and diluted net loss per share | | | | | 60,498 | | | 60,098 | | | |
| | | | | | | | | |
| Net loss per share: | | | | | | | | | |
| Basic | | | | | $ | (0.16) | | | $ | (0.26) | | | |
| Diluted | | | | | (0.16) | | | (0.26) | | | |
The calculation of diluted net loss per share for the three and nine months ended September 30, 2017March 31, 2022 and 2021 excluded 701298 thousand shares and 712500 thousand shares, respectively, issuable pursuant to outstanding stock options, and restricted stock awards, due to their antidilutive effect. The calculationAdditionally, shares issuable upon conversion of diluted net loss per share forboth the three2023 Notes and nine months ended September 30, 2016the 2026 Notes were excluded 745 thousand shares and 755 thousand shares, respectively, issuable pursuantdue to, outstanding stock options and restricted stock awards, due toamong other factors, their antidilutive effect.
| |
6. | Business Acquisitions and Goodwill |
In January 2017, our Offshore/Manufactured Products segment acquired the intellectual property and assets of complementary product lines to our global crane manufacturing and service operations. The acquisition included adding active heave compensation technology and knuckle-boom crane designs to our existing portfolio.
In April 2017, our Offshore/Manufactured Products segment acquired assets and intellectual property that are complementary to our riser testing, inspection and repair service offerings. This complimentary technology allows the segment to provide automated inspection techniques either on board an offshore vessel or on the quayside, without the requirements to transport to a facility to remove the buoyancy materials.
Using cash on hand, consideration paid in connection with these transactions totaled $12.9 million, which was allocated to the net assets acquired, including intangibles and goodwill. While no material adjustments are anticipated, the Company’s allocations of purchase price are preliminary and subject to change primarily based on the final determination of the fair values of intangible assets acquired.
Changes in the carrying amount of goodwill for the nine month period ended September 30, 2017 were as follows (in thousands):
|
| | | | | | | | | | | | | | | | | | | |
| | Well Site Services | | | | |
| | Completion
Services | | Drilling
Services | | Subtotal | | Offshore /
Manufactured
Products | | Total |
| Balance as of December 31, 2016 | | | | | | | | | |
| Goodwill | $ | 199,278 |
| | $ | 22,767 |
| | $ | 222,045 |
| | $ | 158,619 |
| | $ | 380,664 |
|
| Accumulated impairment losses | (94,528 | ) | | (22,767 | ) | | (117,295 | ) | | — |
| | (117,295 | ) |
| | 104,750 |
| | — |
| | 104,750 |
| | 158,619 |
| | 263,369 |
|
| Goodwill acquired | — |
| | — |
| | — |
| | 4,698 |
| | 4,698 |
|
| Foreign currency translation | 353 |
| | — |
| | 353 |
| | 497 |
| | 850 |
|
| Balance as of September 30, 2017 | $ | 105,103 |
| | $ | — |
| | $ | 105,103 |
| | $ | 163,814 |
| | $ | 268,917 |
|
| | | | | | | | | | |
| Balance as of September 30, 2017 | | | | | | | | | |
| Goodwill | $ | 199,631 |
| | $ | 22,767 |
| | $ | 222,398 |
| | $ | 163,814 |
| | $ | 386,212 |
|
| Accumulated impairment losses | (94,528 | ) | | (22,767 | ) | | (117,295 | ) | | — |
| | (117,295 | ) |
| | $ | 105,103 |
| | $ | — |
| | $ | 105,103 |
| | $ | 163,814 |
| | $ | 268,917 |
|
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
(Continued)
As of September 30, 2017 and December 31, 2016, long-term debt consisted of the following (in thousands):
|
| | | | | | | |
| | September 30,
2017 | | December 31,
2016 |
Revolving credit facility(1) | $ | 14,260 |
| | $ | 40,230 |
|
| Capital lease obligations and other debt | 5,293 |
| | 5,696 |
|
| Total debt | 19,553 |
| | 45,926 |
|
| Less: Current portion | (492 | ) | | (538 | ) |
| Total long-term debt and capitalized leases | $ | 19,061 |
| | $ | 45,388 |
|
| |
(1) | Amounts presented are net of $1.4 million and $2.0 million, respectively, of unamortized debt issuance costs. |
RevolvingCredit Facility
The Company has a $600 million senior secured revolving credit facility (the “Revolving Credit Facility”) with an option to increase the maximum borrowings to $750 million subject to additional lender commitments prior to its maturity on May 28, 2019. As of September 30, 2017, we had $15.6 million outstanding under the Credit Agreement (as defined below) and an additional $21.6 million of outstanding letters of credit, leaving $146.5 million available to be drawn under the Revolving Credit Facility. As of September 30, 2017, amounts available to be drawn under the Revolving Credit Facility plus cash and cash equivalents totaled $212.4 million. The total amount available to be drawn was less than the lender commitments as of September 30, 2017, due to the maximum leverage ratio covenant in the Credit Agreement which serves to limit borrowings. We expect our availability to continue to be limited by the maximum leverage ratio covenant during the remainder of 2017 and into 2018 based upon our forecast of our trailing twelve-month EBITDA (as defined in the Credit Agreement and further discussed below).
The Revolving Credit Facility is governed by a Credit Agreement dated as of May 28, 2014, as amended, (the “Credit Agreement”) by and among the Company, the Lenders party thereto, Wells Fargo Bank, N.A., as administrative agent, the Swing Line Lender and an Issuing Bank, and Royal Bank of Canada, as Syndication agent, and Compass Bank, as Documentation agent. Amounts outstanding under the Revolving Credit Facility bear interest at LIBOR plus a margin of 1.50% to 2.50%, or at a base rate plus a margin of 0.50% to 1.50%, in each case based on a ratio of the Company’s total leverage to EBITDA. During the first nine months of 2017, our applicable margin over LIBOR was 1.50%. We must also pay a quarterly commitment fee, based on our leverage ratio, on the unused commitments under the Credit Agreement. The unused commitment fee was 0.375% during the first nine months of 2017. The Credit Agreement contains customary financial covenants and restrictions. Specifically, we must maintain an interest coverage ratio, defined as the ratio of consolidated EBITDA to consolidated interest expense, of at least 3.0 to 1.0 and a maximum leverage ratio, defined as the ratio of total debt to consolidated EBITDA, of no greater than 3.25 to 1.0. Each of the factors considered in the calculations of these ratios are defined in the Credit Agreement. EBITDA and consolidated interest, as defined, exclude goodwill impairments, losses on extinguishment of debt, debt discount amortization, and other non-cash charges. As of September 30, 2017, we were in compliance with our debt covenants.
Borrowings under the Credit Agreement are secured by a pledge of substantially all of our assets and the assets of our domestic subsidiaries. Our obligations under the Credit Agreement are guaranteed by our significant domestic subsidiaries. The Revolving Credit Facility also contains negative covenants that limit the Company's ability to borrow additional funds, encumber assets, pay dividends, sell assets and enter into other significant transactions.
Under the Credit Agreement, the occurrence of specified change of control events involving our Company would constitute an event of default that would permit the banks to, among other things, accelerate the maturity of the facility and cause it to become immediately due and payable in full.
| |
8. | Fair Value Measurements |
The Company’s financial instruments consist of cash and cash equivalents, investments, receivables, payables, bank debt and foreign currency forward contracts. The Company believes that the carrying values of these instruments on the accompanying consolidated balance sheets approximate their fair values.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
(Continued)
| |
9. | Changes in Common Stock Outstanding |
|
| | |
Shares of common stock outstanding – December 31, 2016 | 51,374,361 |
|
Restricted stock awards, net of forfeitures | 425,386 |
|
Shares withheld for taxes on vesting of restricted stock awards and transferred to treasury | (148,536 | ) |
Purchase of treasury stock | (561,765 | ) |
Shares of common stock outstanding – September 30, 2017 | 51,089,446 |
|
On July 29, 2015, the Company’s Board of Directors approved a new share repurchase program providing for the repurchase of up to $150.0 million of the Company’s common stock, which, following extension, was scheduled to expire on July 29, 2017. On July 26, 2017, our Board of Directors extended the share repurchase program for one year to July 29, 2018. During the first nine months of 2017, the Company repurchased 562 thousand shares of common stock under the program at a total cost of $16.3 million. The amount remaining under our share repurchase authorization as of September 30, 2017 was $120.5 million. Subject to applicable securities laws, such purchases will be at such times and in such amounts as the Company deems appropriate.
| |
10. | Stock-based9. Long-Term Incentive Compensation |
The following table presents a summary of activity for stock options, service-based restricted stock awards and performance-based stock unit awards for the ninethree months ended September 30, 2017.March 31, 2022 (in thousands):
|
| | | | | | | | | | | |
| | Stock Options | | Service-based
Restricted Stock | | Performance-based
Stock Units |
| Outstanding at December 31, 2016 | 715,095 |
| | 1,140,489 |
| | 157,925 |
|
| Granted | — |
| | 475,432 |
| | 74,758 |
|
| Restricted stock awards vested | — |
| | (466,304 | ) | | — |
|
| Forfeited | (21,818 | ) | | (50,046 | ) | | — |
|
| Outstanding at September 30, 2017 | 693,277 |
| | 1,099,571 |
| | 232,683 |
|
| Weighted average grant date fair value (2017 awards) | $ | — |
| | $ | 39.50 |
| | $ | 62.66 |
|
| | | | | | | | | | | | | | | | | |
| Stock Options | | Service-based Restricted Stock | | Performance-based Stock Units |
| Outstanding – December 31, 2021 | 388 | | | 993 | | | 358 | |
| Granted | — | | | 686 | | | 233 | |
| Vested | — | | | (403) | | | — | |
| Forfeited | (122) | | | (12) | | | — | |
| Outstanding – March 31, 2022 | 266 | | | 1,264 | | | 591 | |
| Weighted average grant date fair value (2022 awards) | $ | — | | | $ | 6.53 | | | $ | 6.53 | |
The restricted stock program consists of a combination of service-based restricted stock and performance-based stock units. The service-basedService-based restricted stock awards generally vest on a straight-line basis over theira term which isof three years. Performance-based stock awards generally three to four years. Thevest at the end of a three-year period, with the number of performance-based restricted shares ultimately issued under the program is dependent upon our achievement of a predefined specific performance measures generally measuredobjectives. The performance objective for performance-based awards granted in 2022 and 2021 is the Company's cumulative EBITDA over a three-year period. The performance objective for outstanding awards granted in 2020 is the Company's EBITDA growth rate over a three-year period.
In the event the predefined targets are exceeded for any performance-based award, additional shares up to a maximum of 200% of the target award may be granted. Conversely, if actual performance falls below the predefined target, the number of shares vested is reduced. If the actual performance falls below the threshold performance level, no restricted shares will vest.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
During the first quarters of 2022 and 2021, the Company issued conditional long-term cash incentive awards ("Cash Awards") of $1.5 million and $1.5 million, respectively, with the ultimate dollar amount to be awarded ranging from zero to a maximum of $3.1 million for both the 2022 and 2021 Cash Awards. The performance measure for the 2017 and 2016 awardsthese Cash Awards is relative total stockholder return compared to oura peer group of companies whilemeasured over a three-year period. The ultimate dollar amount to be awarded for the 2022 and 2021 Cash Awards is limited to their targeted award value ($1.5 million) if the Company's total stockholder return is negative over the performance measure specified forperiod. The obligations, if any, related to the 2015 awards was average after-tax return on invested capital. Currently, it is unlikely thatCash Awards are classified as liabilities and recognized over the 2015 performance measure threshold will be met which would result in a performance award forfeiture of approximately 80 thousand units in the fourth quarter of 2017.
vesting period.
Stock-based compensation pre-tax expense recognized induring the three-month periodsthree months ended September 30, 2017March 31, 2022 and 20162021 totaled $6.1$1.8 million and $5.4 million, respectively. Stock-based compensation pre-tax expense recognized in the nine month periods ended September 30, 2017 and 2016 totaled $17.1 million and $15.9$2.8 million, respectively. As of September 30, 2017,March 31, 2022, there was $33.7$11.0 million of pre-tax compensation costs related to service-based and performance-based stock awards, and unvested stock options, which will be recognized in future periods as vesting conditions are satisfied.
10. Segments and Related Information
The Company operates through 3 operating segments: Offshore/Manufactured Products, Well Site Services and Downhole Technologies. Financial information by operating segment for the three months ended March 31, 2022 and 2021 is summarized in the following tables (in thousands).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Revenues | | Depreciation and amortization | | Operating income (loss) | | Capital expenditures | | Total assets |
| Three Months Ended March 31, 2022 | | | | | | | | | |
| Offshore/Manufactured Products | $ | 84,112 | | | $ | 5,330 | | | $ | 10,196 | | | $ | 902 | | | $ | 559,877 | |
| Well Site Services | 48,172 | | | 7,932 | | | (3,395) | | | 1,548 | | | 197,077 | |
| Downhole Technologies | 31,760 | | | 4,384 | | | (1,505) | | | 317 | | | 265,958 | |
| Corporate | — | | | 171 | | | (9,632) | | | 91 | | | 55,053 | |
| Total | $ | 164,044 | | | $ | 17,817 | | | $ | (4,336) | | | $ | 2,858 | | | $ | 1,077,965 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Revenues | | Depreciation and amortization | | Operating income (loss) | | Capital expenditures | | Total assets |
| Three Months Ended March 31, 2021 | | | | | | | | | |
| Offshore/Manufactured Products | $ | 60,609 | | | $ | 5,469 | | | $ | 1,071 | | | $ | 463 | | | $ | 534,819 | |
Well Site Services(1) | 39,550 | | | 11,468 | | | (9,853) | | | 3,330 | | | 229,968 | |
| Downhole Technologies | 25,430 | | | 4,389 | | | (1,615) | | | 83 | | | 280,320 | |
| Corporate | — | | | 194 | | | (9,365) | | | 244 | | | 79,312 | |
| Total | $ | 125,589 | | | $ | 21,520 | | | $ | (19,762) | | | $ | 4,120 | | | $ | 1,124,419 | |
________________
(1)Operating loss included a non-cash fixed asset impairment charge of $0.7 million.
See Note 2, "Asset Impairments and Other Restructuring Items," and Note 3, "Details of Selected Balance Sheet Accounts," for further discussion of these and other charges and benefits recognized in first three months of 2021.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
(Continued)
The income tax provision for interim periods is based on estimates of the effective tax rate for the entire fiscal year. The Company’s income tax provisionfollowing tables provide supplemental disaggregated revenue from contracts with customers by operating segment for the three and nine months ended September 30, 2017 was an income tax benefitMarch 31, 2022 and 2021 (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Offshore/Manufactured Products | | Well Site Services | | Downhole Technologies | | Total |
| 2022 | | 2021 | | 2022 | | 2021 | | 2022 | | 2021 | | 2022 | | 2021 |
| Three Months Ended March 31 | | | | | | | | | | | | | | | |
| Major revenue categories - | | | | | | | | | | | | | | | |
| Project-driven products | $ | 33,844 | | | $ | 21,374 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 33,844 | | | $ | 21,374 | |
| Short-cycle: | | | | | | | | | | | | | | | |
| Completion products and services | 13,580 | | | 8,114 | | | 45,166 | | | 38,799 | | | 31,760 | | | 25,430 | | | 90,506 | | | 72,343 | |
| Drilling services | — | | | — | | | 3,006 | | | 751 | | | — | | | — | | | 3,006 | | | 751 | |
| Other products | 7,044 | | | 4,136 | | | — | | | — | | | — | | | — | | | 7,044 | | | 4,136 | |
| Total short-cycle | 20,624 | | | 12,250 | | | 48,172 | | | 39,550 | | | 31,760 | | | 25,430 | | | 100,556 | | | 77,230 | |
| Other products and services | 29,644 | | | 26,985 | | | — | | | — | | | — | | | — | | | 29,644 | | | 26,985 | |
| $ | 84,112 | | | $ | 60,609 | | | $ | 48,172 | | | $ | 39,550 | | | $ | 31,760 | | | $ | 25,430 | | | $ | 164,044 | | | $ | 125,589 | |
Revenues from products and services transferred to customers over time accounted for approximately 62% and 62% of $4.0 million, or 21.1% of pre-tax losses, and $15.7 million, or 25.1% of pre-tax losses, respectively. This compares to an income tax benefit of $6.0 million, or 35.8% of pre-tax losses, and $20.5 million, or 36.4% of pre-tax losses, respectively,consolidated revenues for the three and nine months ended September 30, 2016.March 31, 2022 and 2021, respectively. The lower effective tax rate benefitbalance of revenues for the respective periods relates to products and services transferred to customers at a point in time. As of March 31, 2022, the firstCompany had $152.0 million of remaining backlog related to contracts with an original expected duration of greater than one year. Approximately 35% of this remaining backlog is expected to be recognized as revenue over the remaining nine months of 2017 was primarily attributable2022, with an additional 35% recognized in 2023 and the balance thereafter.
11. Commitments and Contingencies
During 2021 and the first quarter of 2022, the distribution of COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded. However, the effects of the COVID-19 pandemic and related economic, business and market disruptions continue and the macro outlook remains uncertain. The most direct impacts that the Company continues to a shiftexperience are decreased pricing for its products and services due to the timing and rate of activity increases, market pressures driving increased capital discipline by its customers, supply chain disruptions, labor market constraints and inflation in wages, materials, parts, equipment and other costs. While the prices of and demand for crude oil have recovered from the lows seen in the mix between domestic pre-tax losses and foreign pre-tax income compared to the prior-year period, additional valuation allowances provided against net operating losses in certain domestic and foreign jurisdictions, and incremental tax expense related to our decision to carryback certain U.S. net operating losses discussed below.
During the third quarter of 2017, the Company decided to carryback 2016 and 2017 U.S. net operating losses to prior years. The Company plans to file carryback claims against prior year U.S. federal income tax returns and has recorded related income taxes receivable totaling $16.6 million. Such amounts have been classified within prepaid expenses and other current assets as of September 30, 2017. The effectinitial stages of the carryback willpandemic, further outbreaks or the emergence of new strains of the COVID-19 virus could result in the lossreimposition of certain previously claimed tax deductions. As a result, the Company recorded a discrete tax charge of $1.0 million in the third quarter of 2017, thereby reducing the effective tax rate benefit.
The Company records a valuation allowance in each reporting period when management believes that it is more likely than not that any deferred tax asset will not be realized. This assessment requires analysis of available positive and negative evidence, including losses incurred in recent years, reversals of temporary differences, forecasts of future income, assessment of future business assumptions and tax planning strategies. During 2016 and the first nine months of 2017, we recorded valuation allowances with respect to net operating loss carryforwards of certain of our domestic and foreign operations. Future increasesinternational regulations directing individuals to stay at home, limiting travel, requiring facility closures and imposing quarantines. Widespread implementation of these or similar restrictions could result in our valuation allowances are possible if our estimates and assumptions (particularly as they relate to our forecasts) are revised such that they reduce estimates of future taxable income duringcommodity price volatility, reduced demand for the carryforward period.
| |
12. | Segments and Related Information |
The Company operates through two reportable segments: Well Site Services and Offshore/Manufactured Products. The Company’s reportable segments represent strategic business units that offer differentCompany's products and services. They are managed separately because each business requires different technologies and marketing strategies. Acquisitions have been direct extensions to our business segments. Separate business lines within the Well Site Services segment have been disclosed to provide additional information for that segment.
Our Well Site Services segment provides a broad range of equipment and services that are used to drill for, establish and maintain the flow of oil and natural gas from a well throughout its life cycle. In this segment, our operations primarily include completion-focused equipment and services, as well as land drilling services. Our Completion Services operations provide solutions to our customers using our completion tools and highly-trained personnel throughout our service offerings which include: wireline support, frac stacks, isolations tools, extended reach tools, ball launchers, well testing operations, thru tubing activity and sand control. Drilling Services provides land drilling services for shallow to medium depth wellsdelays in West Texas and the Rocky Mountain regionor inability of the United States.
Our Offshore/Manufactured Products segment designs, manufacturesCompany to fulfill its contractual obligations to customers, logistic constraints, increases in the Company's costs and markets capital equipment utilizedworkforce and raw material shortages. The Company continues to monitor the effect of the COVID-19 pandemic on floating production systems, subsea pipeline infrastructure,its employees, customers, critical suppliers and offshore drilling rigs and vessels,other stakeholders. The ultimate duration of the COVID-19 pandemic, along with short-cycleresulting governmental restrictions and other products. Driven principally by longer-term customer investmentsrelated impacts on the prices of and demand for offshorecrude oil, the global economy and natural gas projects, “project-driven product” revenues include: flexible bearings, advanced connector systems, high-pressure riser systems, deepwater mooring systems, cranes, subsea pipeline products and blow-out preventer stack integration. “Short-cycle products” manufactured by the segment include: valves, elastomers and other specialty products generally used in the land-based drilling and completion markets. “Other products,” manufactured and offered by the segment, include a variety of products for use in industrial, military and other applications outside the oil and gas industry. The segment also offers a broad line of complementary, value-added services including: specialty welding, fabrication, cladding and machining services, offshore installation services, and inspection and repair services.
Financial information by business segment for the three and nine months ended September 30, 2017 and 2016 is summarized as follows (in thousands).
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
(Continued)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Revenues | | Depreciation and
amortization | | Operating (loss) income | | Equity in
losses of
unconsolidated
affiliates | | Capital
expenditures | | Total assets |
| Three months ended September 30, 2017 | | | | | | | | | | | |
| Well Site Services – | | | | | | | | | | | |
| Completion Services | $ | 61,015 |
| | $ | 15,679 |
| | $ | (9,933 | ) | | $ | — |
| | $ | 2,447 |
| | $ | 427,207 |
|
| Drilling Services | 16,162 |
| | 4,454 |
| | (3,235 | ) | | — |
| | 1,693 |
| | 74,991 |
|
| Total Well Site Services | 77,177 |
| | 20,133 |
| | (13,168 | ) | | — |
| | 4,140 |
| | 502,198 |
|
| Offshore/Manufactured Products | 86,871 |
| | 6,404 |
| | 7,334 |
| | (33 | ) | | 2,846 |
| | 782,651 |
|
| Corporate | — |
| | 251 |
| | (12,349 | ) | | — |
| | 54 |
| | 44,506 |
|
| Total | $ | 164,048 |
| | $ | 26,788 |
| | $ | (18,183 | ) | | $ | (33 | ) | | $ | 7,040 |
| | $ | 1,329,355 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Revenues | | Depreciation and
amortization | | Operating (loss) income | | Equity in
losses of
unconsolidated
affiliates | | Capital
expenditures | | Total assets |
| Three months ended September 30, 2016 | | | | | | | | | | | |
| Well Site Services – | | | | | | | | | | | |
| Completion Services | $ | 38,975 |
| | $ | 17,230 |
| | $ | (20,450 | ) | | $ | — |
| | $ | 2,365 |
| | $ | 475,139 |
|
| Drilling Services | 7,375 |
| | 5,629 |
| | (5,641 | ) | | — |
| | 249 |
| | 82,683 |
|
| Total Well Site Services | 46,350 |
| | 22,859 |
| | (26,091 | ) | | — |
| | 2,614 |
| | 557,822 |
|
| Offshore/Manufactured Products | 132,656 |
| | 6,712 |
| | 22,867 |
| | (77 | ) | | 2,502 |
| | 851,819 |
|
| Corporate | — |
| | 277 |
| | (12,402 | ) | | — |
| | 379 |
| | 25,486 |
|
| Total | $ | 179,006 |
| | $ | 29,848 |
| | $ | (15,626 | ) | | $ | (77 | ) | | $ | 5,495 |
| | $ | 1,435,127 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Revenues | | Depreciation and
amortization | | Operating (loss) income | | Equity in
losses of
unconsolidated
affiliates | | Capital
expenditures | | Total assets |
| Nine months ended September 30, 2017 | | | | | | | | | | | |
| Well Site Services – | | | | | | | | | | | |
| Completion Services | $ | 167,577 |
| | $ | 48,400 |
| | $ | (38,960 | ) | | $ | — |
| | $ | 8,560 |
| | $ | 427,207 |
|
| Drilling Services | 39,120 |
| | 14,283 |
| | (11,239 | ) | | — |
| | 2,800 |
| | 74,991 |
|
| Total Well Site Services | 206,697 |
| | 62,683 |
| | (50,199 | ) | | — |
| | 11,360 |
| | 502,198 |
|
| Offshore/Manufactured Products | 280,220 |
| | 19,091 |
| | 27,460 |
| | (62 | ) | | 8,775 |
| | 782,651 |
|
| Corporate | — |
| | 778 |
| | (37,274 | ) | | — |
| | 196 |
| | 44,506 |
|
| Total | $ | 486,917 |
| | $ | 82,552 |
| | $ | (60,013 | ) | | $ | (62 | ) | | $ | 20,331 |
| | $ | 1,329,355 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Revenues | | Depreciation and
amortization | | Operating (loss) income | | Equity in
losses of
unconsolidated
affiliates | | Capital
expenditures | | Total assets |
| Nine months ended September 30, 2016 | | | | | | | | | | | |
| Well Site Services – | | | | | | | | | | | |
| Completion Services | $ | 116,748 |
| | $ | 52,789 |
| | $ | (66,251 | ) | | $ | — |
| | $ | 9,032 |
| | $ | 475,139 |
|
| Drilling Services | 14,016 |
| | 18,053 |
| | (19,697 | ) | | — |
| | 748 |
| | 82,683 |
|
| Total Well Site Services | 130,764 |
| | 70,842 |
| | (85,948 | ) | | — |
| | 9,780 |
| | 557,822 |
|
| Offshore/Manufactured Products | 393,746 |
| | 17,977 |
| | 67,854 |
| | (196 | ) | | 13,476 |
| | 851,819 |
|
| Corporate | — |
| | 847 |
| | (34,798 | ) | | — |
| | 637 |
| | 25,486 |
|
| Total | $ | 524,510 |
| | $ | 89,666 |
| | $ | (52,892 | ) | | $ | (196 | ) | | $ | 23,893 |
| | $ | 1,435,127 |
|
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
(Continued)
capital markets remains uncertain.
The Company has one customer whose revenue individually represented 16% and 15% of the Company’s consolidated product and service revenue for the three and nine months ended September 30, 2017, respectively, and whose receivables individually represented 12% of the Company’s consolidated total accounts receivable as of September 30, 2017.
The following table provides supplemental revenue information for the Offshore/Manufactured Products segment for the three and nine months ended September 30, 2017 and 2016 (in thousands):
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| Project-driven products | $ | 22,698 |
| | $ | 76,541 |
| | $ | 89,615 |
| | $ | 234,440 |
|
| Short-cycle products | 37,781 |
| | 23,766 |
| | 110,872 |
| | 63,033 |
|
| Other products and services | 26,392 |
| | 32,349 |
| | 79,733 |
| | 96,273 |
|
| | $ | 86,871 |
| | $ | 132,656 |
| | $ | 280,220 |
| | $ | 393,746 |
|
| |
13. | Commitments and Contingencies |
In the ordinary course of conducting our business, we become involved in litigation and other claims from private party actions, as well as judicial and administrative proceedings involving governmental authorities at the federal, state and local levels. Over recent years, a number of lawsuits were filed in Federal Court, against the Company and or one of its subsidiaries, by current and former employees alleging violations of the Fair Labor Standards Act (“FLSA”). The plaintiffs seek damages and penalties for the Company’s alleged failure to: properly classify its field service employees as “non-exempt” under the FLSA; and pay them on an hourly basis (including overtime). The plaintiffs are seeking recovery on their own behalf as well as on behalf of a class of similarly situated employees. Settlement of the class action against the Company was approved, and a judgment was entered November 19, 2015. The Company has settled the vast majority of these claims and is evaluating potential settlements for the remaining individual plaintiffs’ claims which are not expected to be significant.
We are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning ourits commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of ourthe Company's products or operations. Some of these claims relate to matters occurring prior to ourthe acquisition of businesses, and some relate to businesses we havethe Company has sold. In certain cases, we arethe Company is entitled to indemnification from the sellers of businesses and, in other cases, we havethe Company has indemnified the buyers of businesses from us.businesses. Although wethe Company can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on us, we believethe Company, management believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by indemnity or insurance, will not have a material adverse effect on ourthe Company's consolidated financial position, results of operations or liquidity.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Following the GEODynamics Acquisition in January 2018, the Company determined that certain steel products historically imported by GEODynamics from China for use in its manufacturing process were potentially subject to anti-dumping and countervailing duties. Following an internal review, the Company voluntarily disclosed this matter to U.S. Customs and Border Protection ("CBP") and, in December 2020, reached an agreement with CBP to settle this matter for $7.3 million. The Company believes that the Seller is required to indemnify and hold the Company harmless against the amount of this and other settlements and related costs of $7.5 million, and the Company has provided notice to and asserted indemnification claims against the Seller. Additionally, the Company believes that its agreements with the Seller allow it to set-off such amounts against payments due under the $25.0 million promissory note and that, because the Company has asserted indemnification claims, the maturity date of such note is extended until the resolution of such claims. Accordingly, the Company reduced the carrying amount of such note in its consolidated balance sheet to $17.5 million as of March 31, 2022, which is the Company's current best estimate of what is owed after set-off for such indemnification matters, but without considering the outcome of the counterclaim described below.
In August 2020, the Seller filed a breach of contract suit against the Company and one of its wholly-owned subsidiaries in federal court alleging that payments due under the promissory note are required to be, but have not been, repaid in accordance with the terms of the note. Additionally, the Seller alleged that it was entitled to approximately $19.0 million in U.S. federal income tax carryback claims received by the Company under the provisions of the CARES Act. On February 15, 2021, following the federal magistrate's report and recommendation that the federal district court dismiss the Seller's lawsuit for lack of federal jurisdiction, the Seller dismissed the federal lawsuit without prejudice and refiled its lawsuit in state court. On September 20, 2021, the state court denied the Seller's motion for partial summary judgement. In December 2021, the Company filed a counterclaim against the Seller alleging material misrepresentations and breaches of warranties by the Seller with respect to GEODynamics' liability for anti-dumping and countervailing duties. The Company denies the validity of the breach of contract claims asserted by the Seller and is vigorously defending against this lawsuit.
12. Subsequent Events
On April 14, 2022, the Offshore/Manufactured Products segment acquired E-Flow Control Holdings Limited ("E-Flow"), a global provider of fully integrated handling, control, monitoring and instrumentation solutions. E-Flow, founded in 1988, provides a broad range of engineering, design, manufacturing, installation and commissioning services to its customers in the energy industry. The purchase price of $8.6 million, which is subject to customary post-closing adjustments, was funded with cash on-hand.
Cautionary Statement Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q and other statements we make contain certain “forward-looking statements”"forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”"Securities Act") and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”"Exchange Act"). Actual results could differ materially from those projected in the forward-looking statements as a result of a number of important factors.factors, including incorrect or changed assumptions. For a discussion of known material factors that could affect our results, please refer to “Part"Part I, Item 1. Business,” “Part" "Part I, Item 1A. Risk Factors,” “Part" "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations”Operations" and “Part"Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk”Risk" included in our 20162021 Annual Report on Form 10-K filed with the Securities and Exchange Commission (the "SEC") on February 17, 2017 as well as “Part II, Item 1A, Rick Factors” included in this Quarterly Report on Form 10-Q.
22, 2022.
You can typically identify “forward-looking statements”"forward-looking statements" by the use of forward-looking words such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast,” “proposed,” “should,” “seek,”"may," "will," "could," "project," "believe," "anticipate," "expect," "estimate," "potential," "plan," "forecast," "proposed," "should," "seek," and other similar words. Such statements may relate to our future financial position, budgets, capital expenditures, projected costs, plans and objectives of management for future operations and possible future strategic transactions. Where any such forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution thatActual results frequently differ from assumed facts or bases almost always vary from actual results. Theand such differences between assumed facts or bases and actual results can be material, depending upon the circumstances.
In anyWhile we believe we are providing forward-looking statement where we express an expectation or belief as to future results, such expectation or belief isstatements expressed in good faith and believed to haveon a reasonable basis. However,basis, there can be no assurance that the statement of expectation or beliefactual results will result or be achieved or accomplished.not differ from such forward-looking statements. The following are important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, our Company:us:
•the ongoing impact of the Coronavirus Disease 2019 ("COVID-19") pandemic;
•the ability and willingness of the Organization of Petroleum Exporting Countries ("OPEC") and other producing nations to set and maintain oil production levels and pricing;
•the level of supply of and demand for oil and natural gas;gas, which has been impacted by the ongoing war between Russia and Ukraine that began in February 2022;
•fluctuations in the current and future prices of oil and natural gas;
the cyclical nature of the oil and gas industry;
•the level of exploration, drilling and completion activity;
•the cyclical nature of the oil and natural gas industry;
•the level of offshore oil and natural gas developmental activities;
•the financial health of our customers;
•the impact of environmental matters, including executive actions and regulatory or legislative efforts to adopt environmental or climate change regulations that may result in increased operating costs or reduced oil and natural gas production or demand globally;
•proposed new rules by the SEC relating to the disclosure of a range of climate-related information and risks;
•political, economic and litigation efforts to restrict or eliminate certain oil and natural gas exploration, development and production activities due to concerns over the threat of climate change;
•the availability of and access to attractive oil and natural gas field prospects, which may be affected by governmental actions or actions of other parties which may restrict drilling;restricting drilling and completion activities;
the level of offshore oil and natural gas developmental activities;
•general global economic conditions;
the ability of the Organization of Petroleum Exporting Countries to set and maintain production levels and pricing;
•global weather conditions and natural disasters;
•changes in tax laws and regulations;
•supply chain disruptions;
•the impact of environmental matters, including future environmental regulations;tariffs and duties on imported materials and exported finished goods;
•our ability to findtimely obtain and maintain critical permits for operating facilities;
•our ability to attract and retain skilled personnel;
•negative outcome of litigation, threatened litigation or government proceeding;proceedings;
•our ability to develop new competitive technologies and products;
•inflation, including our ability to increase prices to our customers as our costs increase;
•fluctuations in currency exchange rates;
•physical, digital, cyber, internal and external security breaches and other incidents affecting information security and data privacy;
•our ability to access and the availability and cost of capital;capital in the bank and capital markets;
•our ability to protect and enforce our intellectual property rights;
•our ability to complete the integration of acquired businesses and achieve the expected accretion in earnings; and
•the other factors identified in “Part"Part I, Item 1A. Risk Factors”Factors" in our 20162021 Annual Report on Form 10-K.
Should one or more of these risks or uncertainties materialize or should the assumptions on which our forward-looking statements are based prove incorrect or change, actual results may differ materially from those expected, estimated or projected. In addition, the factors identified above may not necessarily be all of the important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by us, or on our behalf. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no responsibility to publicly release the result of any revision of our forward-looking statements after the date they are made.
In addition, in certain places in this Quarterly Report on Form 10-Q, we refer to information and reports published by third parties that purport to describe trends or developments in the energy industry. The Company doesWe do so for the convenience of our stockholders and in an effort to provide information available in the market that will assist the Company’sour investors to have ain better understanding of the market environment in which the Company operates.we operate. However, the Companywe specifically disclaimsdisclaim any responsibility for the accuracy and completeness of such information and undertakesundertake no obligation to update such information.
ITEM 2.Management’sManagement's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read together with our condensed consolidated financial statements and the notes to those statements included elsewhere in this Quarterly Report on Form 10-Q and our consolidated financial statements and notes to those statements included in our 20162021 Annual Report on Form 10-K.
During the first quarter of 2017, we modified the name of our “Offshore Products” segment10-K in order to the “Offshore/Manufactured Products” segment given the higher proportional weighting of our shorter-cycle manufactured products (much ofunderstand factors, such as charges and credits, financing transactions and changes in tax regulations, which is driven by land-based activity)may impact comparability from period to the total revenues generated by the segment. The Company has also provided supplemental disclosure below, and in Note 12, “Segments and Related Information,” with respect to product and service revenues generated by the Offshore/Manufactured Products segment, including project-driven products, short-cycle products, and other products and services. There have been no operational, reporting or other material changes related to the Offshore/Manufactured Products segment.
Macroeconomic Environment
period.
We provide a broad range of manufactured products and services to customers in the oilenergy, industrial and gas industrymilitary sectors through our Offshore/Manufactured Products, and Well Site Services businessand Downhole Technologies segments. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas industry, particularly our customers’customers' willingness to invest capital in the exploration for and development of crude oil and natural gas reserves. Our customers’customers' capital spending programs are generally based on their cash flows and their outlook for near-term and long-term commodity prices, making demand for our products and services sensitive to expectations regarding future crude oil and natural gas prices, as well as economic growth, commodity demand and estimates of resource production. As a result,production and regulatory pressures related to environmental, social and governance ("ESG") considerations.
Recent Developments
The spot price of Brent crude oil price averaged $101 per barrel during the first quarter of 2022, an increase of 27% from the fourth quarter 2021 average and the highest quarterly average level observed since the second quarter of 2014. The higher commodity price environment was driven by crude oil supply reductions resulting from the Russian invasion of Ukraine on February 24, 2022, increased demand for our productsas the global effects of the COVID-19 pandemic have moderated and services is largely sensitiveslower crude oil production growth due to future expectations with respect toreduced investments by operators globally.
Brent and West Texas Intermediate ("WTI") crude oil and natural gas prices.pricing trends were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Average Price(1) for quarter ended | | Average Price(1) for year ended December 31 |
| Year | | March 31 | | June 30 | | September 30 | | December 31 | |
| Brent Crude (per bbl) | | | | | | | | |
| 2022 | | $ | 100.87 | | | $ | — | | | $ | — | | | $ | — | | | $ | 100.87 | |
| 2021 | | 61.04 | | | 68.98 | | | 73.51 | | | 79.61 | | | 70.86 | |
| WTI Crude (per bbl) | | | | | | | | |
| 2022 | | $ | 95.18 | | | $ | — | | | $ | — | | | $ | — | | | $ | 95.18 | |
| 2021 | | 58.09 | | | 66.19 | | | 70.58 | | | 77.33 | | | 68.14 | |
| Henry Hub Natural Gas (per MMBtu) | | | | | | |
| 2022 | | $ | 4.67 | | | $ | — | | | $ | — | | | $ | — | | | $ | 4.67 | |
| 2021 | | 3.50 | | | 2.95 | | | 4.35 | | | 4.75 | | | 3.90 | |
Our consolidated results of operations reflect current industry trends________________
(1)Source: U.S. Energy Information Administration (spot prices).
On April 22, 2022, Brent crude oil, WTI crude oil and customer spending activities which are focused on growthnatural gas spot prices closed at $105.15 per barrel, $102.86 per barrel and $6.59 per MMBtu, respectively. Additionally, as presented in more detail below, the U.S. shale play regions with weaker U.S. Gulfdrilling rig count reported on April 22, 2022 was 695 rigs, 10% above the first quarter 2021 average.
In January of Mexico and international activity. In addition, investments in deepwater markets globally have slowed since2022, we completed the startpreviously announced exit of the recent industry downturn in 2014.
A severe industry downturn started in the second halfcertain non-performing service offerings within our Well Site Services segment. These service offerings generated revenues of 2014 and continued into 2017, driven by global economic uncertainties and high levels of global oil production. As shown in the table that follows, significant downward crude oil price volatility began in late 2014 with Intercontinental Exchange Brent (“Brent”) crude oil declining from an average of $102 per barrel in the third quarter of 2014 to an average of $34 per barrel$4.4 million in the first quarter of 2016 (a level last seen2021.
During the first quarter of 2022, we recorded bad debt expense of $0.8 million related to receivables from Russia-based customers of the Offshore/Manufactured Products segment. As of March 31, 2022, we had no remaining material balance sheet exposure related to Russia.
On April 14, 2022, our Offshore/Manufactured Products segment acquired E-Flow Control Holdings Limited ("E-Flow"), a global provider of fully integrated handling, control, monitoring and instrumentation solutions. E-Flow, founded in 2004).1988, provides a broad range of engineering, design, manufacturing, installation and commissioning services to its customers in the energy industry. The sustained material decrease inpurchase price of $8.6 million, which is subject to customary post-closing adjustments, was funded with cash on-hand.
Overview
Current and expected future pricing for WTI crude oil, prices relative to 2014 is primarily attributable to high levels of global crude oil inventories resulting from significant production growth in the U.S. shale plays, the strengthening of the U.S. dollar relative to other currencies, and increased production by the Organization of Petroleum Exporting Countries (“OPEC”). OPEC demonstrated, throughout 2015 and through November of 2016 an unwillingness to modify production levels, as it had done in previous years, in an effort to protect its market share. These production increases were partially offset by growth in global crude oil demand. The combination of these factors caused a global supply and demand imbalance for crude oil which, along with concernsexpectations regarding the potential effects on energy demand stemming from the diminished growth outlook in China and other emerging markets, and supply increases relatedregulatory environment, are factors that will continue to the lifting of sanctions against Iran, resulted in materially lower crude oil prices. Non-OPEC production, particularly in the United States, beganinfluence our customers' willingness to decline in 2015 due to substantially reduced investment in drilling and completion activity triggered by lower crude oil prices leading to some recovery in crude oil prices in late 2016 and early 2017 relative to the crude oil price lows experienced in early 2016. On November 30, 2016, OPEC agreed to production cuts which should, over time, if the cuts are adhered to, result in further reductions in global crude oil inventories and a more favorable commodity price environment. In May 2017, OPEC agreed to extend these production cuts to March 2018. Brent crude oil prices averaged $52 per barrel in the third quarter of 2017, which is 14% above the third quarter 2016 average of $46 per barrel and up 5% from the average in the second quarter of 2017. Similarly, the average price
of West Texas Intermediate (“WTI”) was $48 per barrel in the third quarter of 2017, up 7% from the third quarter 2016 average of $45 per barrel but unchanged on a sequential quarter basis. The year-over-year improvement in oil prices was driven by the belief that OPEC and Russia, its key ally in the effort to stabilize the global crude oil market, would be successful in cutting their production. However, improvements in crude oil prices rapidly translated into increased drilling activityinvest in U.S. shale play developments in areas such as the Permian Basin, which is leading to higher domestic production. This increased shale driven activity has pressured crude oil prices again with the average WTI price per barrel over the secondthey allocate capital and third quarters of 2017 declining 7% from the first quarter 2017 average. Further, WTI crude oil is currently trading at an approximate $6 per barrel discount to Brent crude oil, as shown below. Spending in these regions, which began to improve in the second half of 2016 in response to higher crude oil prices, has positively influenced the overall drillingstrive for financial discipline and completion activity in these regionsspending levels that are within their capital budgets and therefore, the activity of our Well Site Services segment as well ascash flows. Expectations for short-cycle products within our Offshore/Manufactured Products segment in 2017. Expectations with respect to the longer-term price for Brent crude oil will continue to influence our customers’customers' spending related to global offshore drilling and development and, thus, a significant portion of the activity of our Offshore/Manufactured Products segment.
Given the historical volatilityCrude oil prices and levels of demand for crude oil prices, there remains a degree of risk that prices couldare likely to remain at their current levels or deteriorate furtherhighly volatile due to relatively high levelsnumerous factors, including geopolitical conflicts (such as the direction and outcome of Russia's invasion of Ukraine), unrest and tensions; sanctions; global inventories, increasinguncertainties related to the COVID-19 pandemic; domestic or international crude oil production, slowing growth ratesproduction; changes in various global regions,governmental rules and regulations; the willingness of operators to invest capital in the exploration for and development of resources; use of alternatives,alternative fuels; improved vehicle fuel efficiency; a more sustained movement to electric vehicles and/orvehicles; and the potential for ongoing supply/demand imbalances. Conversely, if the global supply of crude oil were to decrease due to a prolonged reduction in capitalCapital investment by our customers or if government instability inrecently reached a major oil-producing nation develops, and energy demand were15-year low due to continuenegative developments with respect to increase in the United States, India and China, a sustained recovery in WTI and Brent crude oil prices could occur. In any event, crude oil price improvements will depend upon a rebalancingmany of global supply and demand, with a corresponding reduction in global inventories, the timing of which is difficult to predict. If commodity prices do not improve, or decline further, demand for our products and services could continue to be weak or could decline further.these factors.
Natural gas prices improved slightly over the past year from an average of $2.88 per mmBtu in the third quarter of 2016 to an average of $2.95 per mmBtu during the third quarter of 2017. Customer spending in the natural gas shale plays has been limited due to associatedtechnological advancements that have led to significant amounts of natural gas being produced from prolific basins in the Northeastern United States and from associated gas produced from the drilling and completion of unconventional oil wells in North America. If natural gas production growth surpasses demand growth in the United States, and/or if the supply of natural gas wereStates.
U.S. drilling, completion and production activity and, in turn, our financial results, are sensitive to increase, whether from conventional or unconventional production or associated natural gas production from oil wells,near-term fluctuations in commodity prices, for natural gas could remain depressed for an extended period of time and could result in fewer rigs drilling for natural gas.
Recentparticularly WTI crude oil Brent crude and natural gas pricing trends are as follows:
|
| | | | | | | | | | | | | | | | |
| | | Average Price(1) for quarter ended |
| Year | | March 31 | | June 30 | | September 30 | | December 31 |
| WTI Crude (per bbl) | | | | | | |
| 2017 | | $ | 51.62 |
| | $ | 48.14 |
| | $ | 48.18 |
| | |
| 2016 | | $ | 33.35 |
| | $ | 45.46 |
| | $ | 44.85 |
| | $ | 49.14 |
|
| 2015 | | $ | 48.49 |
| | $ | 57.85 |
| | $ | 46.49 |
| | $ | 41.94 |
|
| 2014 | | $ | 98.68 |
| | $ | 103.35 |
| | $ | 97.87 |
| | $ | 73.21 |
|
| Brent Crude (per bbl) | | | | | | |
| 2017 | | $ | 53.59 |
| | $ | 49.59 |
| | $ | 52.10 |
| | |
| 2016 | | $ | 33.84 |
| | $ | 45.57 |
| | $ | 45.80 |
| | $ | 49.11 |
|
| 2015 | | $ | 53.98 |
| | $ | 61.65 |
| | $ | 50.44 |
| | $ | 43.56 |
|
| 2014 | | $ | 108.14 |
| | $ | 109.69 |
| | $ | 101.90 |
| | $ | 76.43 |
|
| Henry Hub Natural Gas (per mmBtu) | | | | |
| 2017 | | $ | 3.02 |
| | $ | 3.08 |
| | $ | 2.95 |
| | |
| 2016 | | $ | 1.99 |
| | $ | 2.15 |
| | $ | 2.88 |
| | $ | 3.04 |
|
| 2015 | | $ | 2.90 |
| | $ | 2.75 |
| | $ | 2.76 |
| | $ | 2.12 |
|
| 2014 | | $ | 5.18 |
| | $ | 4.61 |
| | $ | 3.96 |
| | $ | 3.78 |
|
| |
(1) | Source: U.S. Energy Information Administration (“EIA”). As of October 23, 2017, WTI crude oil, Brent crude oil and natural gas traded at approximately $51.91 per barrel, $57.69 per barrel and $2.95 per mmBtu, respectively. |
Overview
Demand for the products and services of our Offshore/Manufactured Products segment is driven by the longer-term outlook for commodity prices, and changes in drilling and completion activity, both offshore and onshore. Demand for the equipment and services of our Well Site Services segment responds to shorter-term movements in crude oil and natural gas prices and, specifically, changes in North American drilling and completion activity given the spot contractshort-term, call-out nature of our operations coupled with shorter cycles between drilling a well and bringing it on production. Other factors that can affect our business and financial results include, but are not limited to, the general global economic environment, competitive pricing pressures and regulatory changes in the United States and international markets.
U.S. operations.
Our Offshore/Manufactured Products segment provides technology-driven, highly-engineered products and services for offshore oil and natural gas production systems and facilities globally, as well as certain products and services to the offshore and land-based drilling and completion markets. Approximately 60%This segment also produces a variety of Offshore/Manufactured Products salesproducts for use in 2016 were driven by our customers’ capital spending for offshore production systemsindustrial, military and subsea pipeline infrastructure, repairs and, to a lesser extent, upgrades of existing offshore drilling rigs and construction of new offshore drilling rigs and vessels (referred to herein as “project-driven product revenue”). As a result, thisother applications outside the traditional energy industry. This segment has historically beenis particularly influenced by global spending on deepwater drilling and production, spending, which areis primarily driven largely by our customers’customers' longer-term commodity demand forecasts and outlook for crude oil and natural gas prices. Approximately 40% of Offshore/Manufactured Products segment sales in the first quarter of 2022 were driven by our customers' capital spending for products used in exploratory and developmental drilling, greenfield offshore production infrastructure, and subsea pipeline tie-in and repair system applications, along with upgraded equipment for existing offshore drilling rigs and other vessels (referred to herein as "project-driven products"). Deepwater oil and gas development projects typically involve significant capital investments and multi-year development plans. As a result, suchSuch projects are generally undertaken by larger exploration, field development and production companies (primarily international oil companies (“IOCs”) and state-run national oil companies (“NOCs”))companies) using relatively conservative crude oil and natural gas pricing assumptions. WeGiven the long lead times associated with field development, we believe some of these deepwater projects, once approved for development, are therefore,generally less susceptible to short-term fluctuations in the price of crude oil and natural gas given longer lead times associated with field development. However, the decline in crude oil prices that began in 2014 and continued into 2017, coupled with the relatively uncertain outlook around shorter-term and possibly longer-term pricing improvements have caused exploration and production companies to reevaluate their future capital expenditures in regards to these deepwater projects since they are expensive to drill and complete, have long lead times to first production and may be considered uneconomical relative to the risk involved. However, a few development projects have been sanctioned in the first nine months of 2017 due to re-engineering of the projects and lower development costs, which led to an improvement in final investment decisions (“FIDs”) on these projects from the previous two years. Our bookings have declined, leading to substantially reduced backlog in 2017 relative to recent years. As a result, this segment’s project-driven revenue declined 62% from the first nine months of 2016 and accounted for only 32% of the segment’s total revenue in the first nine months of 2017. Shorter-cycle manufactured products sold primarily to the land-based completions market are impactedgas.
Backlog reported by near-term fluctuations in commodity prices. For the nine months ended September 30, 2017, sales of these shorter-cycle products (such as valves and elastomer products) for this segment increased 76% over the level reported in the same period last year due to the significant increase in U.S. land-based drilling and completion activity.
Our Offshore/Manufactured Products segment revenues and operating income declined at a slower pace during 2015 and 2016 than our Well Site Services segment given the high levels of backlog that existed at the beginning of 2014. Bidding and quoting activity, along with orders from customers, for our Offshore/Manufactured Products segment continued after 2014, albeit at a much slower pace. Reflectingincreased to $265 million as of March 31, 2022 from $226 million as of March 31, 2021. Bookings totaled $93 million in the impactfirst quarter of customer (both IOCs and NOCs) delays and deferrals in approving major, capital intensive projects in light of the prolonged low commodity price environment, backlog in our Offshore/Manufactured Products segment decreased from $599 million at June 30, 2014 to $199 million at December 31, 2016. With2022, yielding a book-to-bill ratio of 1.0x for the first nine months of 2017, our backlog totaled $198 million at September 30, 2017.1.1x. The following table sets forth backlog for our Offshore/Manufactured Products segment as of the dates indicated (in millions).
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Backlog as of |
| Year | | March 31 | | June 30 | | September 30 | | December 31 |
| 2022 | | $ | 265 | | | $ | — | | | $ | — | | | $ | — | |
| 2021 | | 226 | | | 214 | | | 249 | | | 260 | |
| 2020 | | 267 | | | 235 | | | 227 | | | 219 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Backlog as of |
| Year | | March 31 | | June 30 | | September 30 | | December 31 | | Year Average(1) |
| 2017 | | $ | 204 |
| | $ | 202 |
| | $ | 198 |
| | |
| | $ | 202 |
|
| 2016 | | $ | 306 |
| | $ | 268 |
| | $ | 203 |
| | $ | 199 |
| | $ | 269 |
|
| 2015 | | $ | 474 |
| | $ | 409 |
| | $ | 394 |
| | $ | 340 |
| | $ | 435 |
|
| 2014 | | $ | 578 |
| | $ | 599 |
| | $ | 543 |
| | $ | 490 |
| | $ | 564 |
|
| |
(1) | Average is computed based on month end backlog amounts for the respective nine-month and twelve-month periods. |
In ourOur Well Site Services segment we predominantly provideprovides completion services and, to a much lesser extent, land drilling services. Our Completionservices, in the United States (including the Gulf of Mexico) and the rest of the world. U.S. drilling and completion activity and, in turn, our Well Site Services business providesresults, are sensitive to near-term fluctuations in commodity prices, particularly WTI crude oil prices, given the short-term, call-out nature of its operations. We primarily supply equipment and service personnel utilized in the completion of and initial production offrom new and recompleted wells. Activity for the Completion Services business iswells in our U.S. operations, which are dependent primarily upon the level and complexity of drilling, completion and workover activity in the United States, including the Gulfour areas of Mexico,operations. Well intensity and to a lesser extent, Canada and the rest of the world. Well complexity hashave increased with the continuing transition to multi-well pads, and the drilling of longer lateral wells and increased downhole pressures, along with the increased number of frac stages completed in horizontal wells. Demand
Our Downhole Technologies segment provides oil and gas perforation systems, downhole tools and services in support of completion, intervention, wireline and well abandonment operations. This segment designs, manufactures and markets its consumable engineered products to oilfield service as well as exploration and production companies. Product and service offerings for our Drilling Services operations is driven by land drilling activitythis segment include innovations in our primary drilling marketsperforation technology through patented and proprietary systems combined with advanced modeling and analysis tools. This expertise has led to the optimization of perforation hole size, depth, and quality of tunnels, which are key factors for maximizing the Permian Basin in West Texas, where we primarily drill oileffectiveness of hydraulic fracturing. Additional offerings include proprietary frac plug and toe valve products, which are focused on zonal isolation for hydraulic fracturing of horizontal wells, and a broad range of consumable products, such as setting tools and bridge plugs, that are used in completion, intervention and decommissioning applications. Demand drivers for the U.S. Rocky Mountain area, where we drill both liquids-richDownhole Technologies segment include continued trends toward longer lateral lengths, increased frac stages and natural gas wells.
more perforation clusters to target increased unconventional well productivity, which requires ongoing technological and product developments.
Demand for our Completion Servicescompletion-related products and Drilling Services businessesservices within each of our segments is highly correlated to changes in the drilling rig count in North America, as well as changes in the total number of wells drilled in the United States, total footage anddrilled, the number of drilled wells that are completed.completed and changes in the drilling rig count. The following table sets forth a summary of the average North AmericanU.S. and international drilling rig count, as measured by Baker Hughes (a GE company),Company, as of and for the periods indicated.
|
| | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| U.S. Land – Oil | 742 | | 375 | | 671 | | 370 |
| U.S. Land – Natural gas and other | 182 | | 87 | | 167 | | 90 |
| U.S. Offshore | 22 | | 18 | | 23 | | 23 |
| Total United States | 946 | | 480 | | 861 | | 483 |
| Canada | 208 | | 121 | | 207 | | 112 |
| Total North America | 1,154 | | 601 | | 1,068 | | 595 |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Average for the |
| As of April 22, 2022 | | | | Three Months Ended March 31, |
| | | | | | 2022 | | 2021 |
| United States Rig Count: | | | | | | | | | |
| Land – Oil | 537 | | | | | | 493 | | 286 |
| Land – Natural gas and other | 145 | | | | | | 123 | | 91 |
| Offshore | 13 | | | | | | 17 | | 16 |
| 695 | | | | | | 633 | | 393 |
| International Rig Count: | | | | | | | | | |
| Land | | | | | | | 828 | | 667 |
| Offshore | | | | | | | 193 | | 169 |
| | | | | | | 1,021 | | 836 |
| | | | | | | 1,654 | | 1,229 |
The average North American rig count for the nine months ended September 30, 2017 increased 473 rigs, or 79%, compared to the nine months ended September 30, 2016, in response to the increase in crude oil prices discussed above.
Over recent years, ourU.S. energy industry experienced a shift in customer spending from natural gas exploration and development tois primarily focused on crude oil and liquids-rich exploration and development activities in the North AmericanU.S. shale plays utilizing horizontal drilling and completion techniques. The U.S. natural gas-related working rig count declined from approximately 810 rigs at the beginning of 2012 to 81 rigs in August of 2016, a more than 29 year low. According to rig count data published by Baker Hughes (a GE company), the U.S. oil rig count peaked in October 2014 at 1,609 rigs but has declined materially since late 2014 due to much lower crude oil prices, totaling 750 rigs as of September 30, 2017 (with the U.S. oil rig count having troughed at 316 rigs in May 2016, which was the lowest oil rig count during this current cyclical downturn). As of September 30, 2017,March 31, 2022, oil-directed drilling accounted for 80%79% of the total U.S. rig count – with the balance largely natural gas related. The totalDue to the unprecedented decline in crude oil prices in March and April of 2020, drilling and completion activity in the United States collapsed – with the active drilling rig count declining from 790 rigs as of February 29, 2020 to a trough of 244 rigs as of August 14, 2020. From this trough, the U.S. rig count has increased 536to 670 rigs as of March 31, 2022. As can be derived from the table above, the average U.S. rig count for the first three months of 2022 increased by 240 rigs, or 133%61%, since troughing in Maycompared to the average for the first three months of 2016, largely due to improved crude oil prices, decreased service costs2021.
We use a variety of domestically produced and improved technologies appliedimported raw materials and component products, including steel, in the shale play regions of the United States.
Exacerbating the steep declines in drilling activity experienced in 2015 and 2016, manymanufacture of our explorationproducts. The United States has imposed tariffs on a variety of imported products, including steel and production customers deferred well completions. These deferred completions are referred to in the industry as drilled but uncompleted wells (or “DUCs”). Given our Well Site Services segment’s exposurealuminum. In response to the levelU.S. tariffs on steel and aluminum, the European Union and several other countries, including Canada and China, have threatened and/or imposed retaliatory tariffs. The effect of completion activity, anthese tariffs and the application and interpretation of existing trade agreements and customs, anti-dumping and countervailing duty regulations continue to evolve, and we continue to monitor these matters. If we encounter difficulty in procuring these raw materials and component products, or if the prices we have to pay for these products increase in the number of DUCs will have a short-term negative impactand we are unable to pass corresponding cost increases on to our customers, our financial position, cash flows and results of operations relativecould be adversely affected. Furthermore, uncertainty with respect to the rig count trends but over the longer-term should have a positive impact on the segment’s results as the wells are completed.
Reduced demand for our products and services, coupled with a reductionpotential costs in the prices we chargedrilling and completion of oil and gas wells could cause our customers for our services has adversely affected our results of operations, cash flows and financial position since the second half of 2014. If the current pricing environment for crude oil and natural gas does not improve,to delay or declines further, our customers may be required to further reduce their capital expenditures, causing additional declines in the demand for, and prices of, our products and services,cancel planned projects which, if this occurred, would adversely affect our results of operations,financial position, cash flows and results of operations. See Note 11, "Commitments and Contingencies."
Other factors that can affect our business and financial position. Our customers have experienced a significant declineresults include but are not limited to: the general global economic environment; competitive pricing pressures; public health crises; natural disasters; labor market constraints; supply chain disruptions; inflation in their revenueswages, materials, parts, equipment and cash flows due toother costs; climate-related and other regulatory changes; geopolitical tensions; and changes in tax laws in the commodity price declines, with many experiencing a significant reduction in liquidity. Several explorationUnited States and production companies declared bankruptcy during 2015 and 2016, or had to exchange equity for the forgiveness of debt, and others were forced to sell assets in an effort to preserve liquidity. However, over the past twelve months, access to capital and debt markets have improved for certain of these customers.
international markets. We continue to monitor the global economy, the prices of and demand for crude oil and natural gas, and the resultant impact on the capital spending plans and operations of our customers in order to plan and manage our business.
Human Capital
For more information on our health and safety, diversity and other workforce policies, please see "Part I, Item 1. Business – Human Capital" in our Annual Report on Form 10-K for the year ended December 31, 2021.
Selected Financial Data
This selected financial data should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and related Notes included in "Part I, Item 1. Financial Statements" of this Quarterly Report on Form 10-Q and "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and our Consolidated Financial Statements and related notes included in "Part II, Item 8. Financial Statements and Supplementary Data" of our Annual Report on Form 10-K for the year ended December 31, 2021 in order to understand factors, such as charges and credits, financing transactions and changes in tax regulations, which may impact the comparability of the selected financial data.
Unaudited Consolidated Results of Operations
The following summarizes our consolidated results of operations for the three months ended March 31, 2022 and 2021 (in thousands, except per share amounts):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Three Months Ended March 31, | | |
| | | | | | | 2022 | | 2021 | | Variance |
| Revenues: | | | | | | | | | | | |
| Products | | | | | | | $ | 85,761 | | | $ | 61,445 | | | $ | 24,316 | |
| Services | | | | | | | 78,283 | | | 64,144 | | | 14,139 | |
| | | | | | | 164,044 | | | 125,589 | | | 38,455 | |
| Costs and expenses: | | | | | | | | | | | |
| Product costs | | | | | | | 64,801 | | | 49,463 | | | 15,338 | |
| Service costs | | | | | | | 61,803 | | | 52,847 | | | 8,956 | |
| Cost of revenues (exclusive of depreciation and amortization expense presented below) | | | | | | | 126,604 | | | 102,310 | | | 24,294 | |
| Selling, general and administrative expenses | | | | | | | 23,833 | | | 21,225 | | | 2,608 | |
| Depreciation and amortization expense | | | | | | | 17,817 | | | 21,520 | | | (3,703) | |
| Impairments of goodwill | | | | | | | — | | | — | | | — | |
| | | | | | | | | | | |
Impairments of fixed assets(1) | | | | | | | — | | | 650 | | | (650) | |
| Other operating (income) expense, net | | | | | | | 126 | | | (354) | | | 480 | |
| | | | | | | 168,380 | | | 145,351 | | | 23,029 | |
| Operating loss | | | | | | | (4,336) | | | (19,762) | | | 15,426 | |
| | | | | | | | | | | |
| Interest expense, net | | | | | | | (2,672) | | | (2,325) | | | (347) | |
Other income, net(2) | | | | | | | 1,025 | | | 3,960 | | | (2,935) | |
| Loss before income taxes | | | | | | | (5,983) | | | (18,127) | | | 12,144 | |
| Income tax benefit | | | | | | | (3,441) | | | 2,317 | | | (5,758) | |
| Net loss | | | | | | | $ | (9,424) | | | $ | (15,810) | | | $ | 6,386 | |
| | | | | | | | | | | |
| Net loss per share: |
| Basic | | | | | | | $ | (0.16) | | | $ | (0.26) | | | |
| Diluted | | | | | | | (0.16) | | | (0.26) | | | |
| | | | | | | | | | | |
| Weighted average number of common shares outstanding: |
| Basic | | | | | | | 60,498 | | 60,098 | | |
| Diluted | | | | | | | 60,498 | | 60,098 | | |
________________
(1)During the first quarter of 2021, we recognized non-cash impairment charges of $0.7 million to reduce the carrying value of certain fixed assets to their estimated realizable value.
(2)During the first quarter of 2021, we recognized non-cash gains of $3.6 million in connection with our purchases of $125.0 million principal amount of our 2023 Notes.
See Note 2, "Asset Impairments and Other Restructuring Items," Note 3, "Details of Selected Balance Sheet Accounts" and Note 4, "Long-term Debt," to the Unaudited Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q for further discussion of these and other charges and benefits recognized in the first three months of 2021.
Unaudited Segment Results of Operations
We manage and measure our business performance in twothree distinct operating segments: Offshore/Manufactured Products, Well Site Services and Offshore/Manufactured Products. SelectedDownhole Technologies. Supplemental financial information by businessoperating segment for the three and nine months ended September 30, 2017March 31, 2022 and 20162021 is summarized below (dollars in(in thousands):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Three Months Ended March 31, | | |
| | | | | | | 2022 | | 2021 | | Variance |
| Revenues | | | | | | | | | | | |
| Offshore/Manufactured Products | | | | | | | | | | | |
| Project-driven products | | | | | | | $ | 33,844 | | | $ | 21,374 | | | $ | 12,470 | |
| Short-cycle products | | | | | | | 20,624 | | | 12,250 | | | 8,374 | |
| Other products and services | | | | | | | 29,644 | | | 26,985 | | | 2,659 | |
| Total Offshore/Manufactured Products | | | | | | | 84,112 | | | 60,609 | | | 23,503 | |
| Well Site Services | | | | | | | 48,172 | | | 39,550 | | | 8,622 | |
| Downhole Technologies | | | | | | | 31,760 | | | 25,430 | | | 6,330 | |
| Total | | | | | | | $ | 164,044 | | | $ | 125,589 | | | $ | 38,455 | |
| | | | | | | | | | | |
| Operating income (loss) | | | | | | | | | | | |
| Offshore/Manufactured Products | | | | | | | $ | 10,196 | | | $ | 1,071 | | | $ | 9,125 | |
Well Site Services(1) | | | | | | | (3,395) | | | (9,853) | | | 6,458 | |
| Downhole Technologies | | | | | | | (1,505) | | | (1,615) | | | 110 | |
| Corporate | | | | | | | (9,632) | | | (9,365) | | | (267) | |
| Total | | | | | | | $ | (4,336) | | | $ | (19,762) | | | $ | 15,426 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | | | | Variance | | | | | | Variance |
| | 2017 | | 2016 | | $ | | % | | 2017 | | 2016 | | $ | | % |
| Revenues | | | | | | | | | | | | | | | |
| Well Site Services - | | | | | | | | | | | | | | | |
| Completion Services | $ | 61,015 |
| | $ | 38,975 |
| | $ | 22,040 |
| | 57 | % | | $ | 167,577 |
| | $ | 116,748 |
| | $ | 50,829 |
| | 44 | % |
| Drilling Services | 16,162 |
| | 7,375 |
| | 8,787 |
| | 119 | % | | 39,120 |
| | 14,016 |
| | 25,104 |
| | 179 | % |
| Total Well Site Services | 77,177 |
| | 46,350 |
| | 30,827 |
| | 67 | % | | 206,697 |
| | 130,764 |
| | 75,933 |
| | 58 | % |
| Offshore/Manufactured Products - | | | | | | | | | | | | | | | |
| Project-driven products | 22,698 |
| | 76,541 |
| | (53,843 | ) | | (70 | )% | | 89,615 |
| | 234,440 |
| | (144,825 | ) | | (62 | )% |
| Short-cycle products | 37,781 |
| | 23,766 |
| | 14,015 |
| | 59 | % | | 110,872 |
| | 63,033 |
| | 47,839 |
| | 76 | % |
| Other products and services | 26,392 |
| | 32,349 |
| | (5,957 | ) | | (18 | )% | | 79,733 |
| | 96,273 |
| | (16,540 | ) | | (17 | )% |
| Total Offshore/Manufactured Products | 86,871 |
| | 132,656 |
| | (45,785 | ) | | (35 | )% | | 280,220 |
| | 393,746 |
| | (113,526 | ) | | (29 | )% |
| Total | $ | 164,048 |
| | $ | 179,006 |
| | $ | (14,958 | ) | | (8 | )% | | $ | 486,917 |
| | $ | 524,510 |
| | $ | (37,593 | ) | | (7 | )% |
| | | | | | | | | | | | | | | | |
| Product and service costs | | | | | | | | | | | | | | | |
| Well Site Services - | | | | | | | | | | | | | | | |
| Completion Services | $ | 51,584 |
| | $ | 36,871 |
| | $ | 14,713 |
| | 40 | % | | $ | 146,833 |
| | $ | 111,701 |
| | $ | 35,132 |
| | 31 | % |
| Drilling Services | 14,521 |
| | 6,992 |
| | 7,529 |
| | 108 | % | | 34,755 |
| | 14,368 |
| | 20,387 |
| | 142 | % |
| Total Well Site Services | 66,105 |
| | 43,863 |
| | 22,242 |
| | 51 | % | | 181,588 |
| | 126,069 |
| | 55,519 |
| | 44 | % |
| Offshore/Manufactured Products | 63,084 |
| | 91,903 |
| | (28,819 | ) | | (31 | )% | | 198,361 |
| | 274,912 |
| | (76,551 | ) | | (28 | )% |
| Total | $ | 129,189 |
| | $ | 135,766 |
| | $ | (6,577 | ) | | (5 | )% | | $ | 379,949 |
| | $ | 400,981 |
| | $ | (21,032 | ) | | (5 | )% |
| | | | | | | | | | | | | | | | |
Gross profit (loss)(1) | | | | | | | | | | | | | | | |
| Well Site Services - | | | | | | | | | | | | | | | |
| Completion Services | $ | 9,432 |
| | $ | 2,104 |
| | $ | 7,328 |
| | 348 | % | | $ | 20,744 |
| | $ | 5,047 |
| | $ | 15,697 |
| | 311 | % |
| Drilling Services | 1,640 |
| | 383 |
| | 1,257 |
| | 328 | % | | 4,365 |
| | (352 | ) | | 4,717 |
| | n.m. |
|
| Total Well Site Services | 11,072 |
| | 2,487 |
| | 8,585 |
| | 345 | % | | 25,109 |
| | 4,695 |
| | 20,414 |
| | 435 | % |
| Offshore/Manufactured Products | 23,787 |
| | 40,754 |
| | (16,967 | ) | | (42 | )% | | 81,859 |
| | 118,835 |
| | (36,976 | ) | | (31 | )% |
| Total | $ | 34,859 |
| | $ | 43,241 |
| | $ | (8,382 | ) | | (19 | )% | | $ | 106,968 |
| | $ | 123,530 |
| | $ | (16,562 | ) | | (13 | )% |
(1)Operating loss in the first quarter of 2021 included non-cash fixed asset impairment charges of $0.7 million.
See Note 2, "Asset Impairments and Other Restructuring Items," and Note 3, "Details of Selected Balance Sheet Accounts," to the Unaudited Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q for further discussion of these and other charges and benefits recognized in the first three months of 2021.
|
| | | | | | | | | | | | | | | | | | | |
Gross profit (loss) as a percentage of revenues(1) | | | | | | | | | | | | |
| Well Site Services - | | | | | | | | | | | | | | | |
| Completion Services | 15 | % | | 5 | % | | | | | | 12 | % | | 4 | % | | | | |
| Drilling Services | 10 | % | | 5 | % | | | | | | 11 | % | | (3 | )% | | | | |
| Total Well Site Services | 14 | % | | 5 | % | | | | | | 12 | % | | 4 | % | | | | |
| Offshore/Manufactured Products | 27 | % | | 31 | % | | | | | | 29 | % | | 30 | % | | | | |
| Total | 21 | % | | 24 | % | | | | | | 22 | % | | 24 | % | | | | |
| |
(1) | Gross profit (loss) is computed by deducting product and service costs from revenues, and excludes depreciation expense. Gross profit (loss) as a percentage of revenues is also referred to herein as gross margin. |
Three Months Ended September 30, 2017March 31, 2022 Compared to Three Months Ended September 30, 2016
March 31, 2021
We reported a net loss for the three months ended September 30, 2017March 31, 2022 of $15.0$9.4 million, or $0.30$0.16 per diluted share, which included $0.4 million ($0.3 million after-tax, or $0.01 per diluted share) of severance and other downsizing charges and $1.0 million ($0.02 per diluted share) of additional tax expense related to the decision to carryback net operating losses incurred in 2016 against taxable income reported in 2014. Excluding these third quarter 2017 charges, the net loss would have been $13.7 million, or $0.27 per diluted share. These results compare to a net loss for the three months ended September 30, 2016March 31, 2021 of $10.8$15.8 million, or $0.22$0.26 per diluted share, which included $2.0non-cash gains of $3.6 million ($1.32.9 million after-tax, or $0.03$0.05 per dilutedshare) associated with debt extinguishment offset by $3.4 million ($2.7 million after-tax, or $0.04 per share) of severance and other downsizing charges. Excluding these third quarter 2016 charges, the net loss from continuing operations would have been $9.5 million, or $0.19 per diluted share.restructuring costs.
The Company’s third quarter 2017 consolidatedOur reported results of operations were adversely affected by Hurricane Harvey which caused widespread damagereflect the negative impact of the global response to the COVID-19 pandemic, ongoing uncertainties related to future crude oil demand and logistical challengessupply and, to a lesser extent, supply chain disruptions. Customer-driven activity has continued to improve since the low levels of 2020, but uncertainty remains around the willingness of operators (our customers) to invest in HoustonU.S. land-based drilling, completion and production activities given regulatory pressures around ESG considerations.
During the surrounding region wherefirst quarter of 2021, we operate five manufacturing facilities and employ about 500 individuals. The Company was impacted by lowerrecognized an aggregate $4.8 million reduction of payroll tax expense (within cost of revenues and under-absorptionselling, general and administrative expense) as part of manufacturing facility costs primarilythe Coronavirus Aid, Relief, and Economic Security Act (the "CARES Act") employee retention credit program.
Revenues. Consolidated total revenues in its Offshore/Manufactured Products segment but also suffered some field-level downtime due to employee dislocations resultingthe first quarter of 2022 increased $38.5 million, or 31%, from the storm. Onefirst quarter of 2021.
Consolidated product revenues in the Company's Houston facilities experienced significant floodingfirst quarter of 2022 increased $24.3 million, or 40%, from the first quarter of 2021, driven primarily by increased U.S. land-based customer activity and is not yet operational but was fully insured. Project workhigher demand for project-related fixed platform equipment. Consolidated service revenues in that facility has been shiftedthe first quarter of 2022 increased $14.1 million, or 22%, from the first quarter of 2021 due primarily to other manufacturing locations to meet customer delivery requirements.
Our consolidated results of operations also reflect current industry trends andhigher customer spending activities which are focused on growth in the U.S. shale play regions with weaker U.S.and the Gulf of Mexico, and international activity. In addition, investments in deepwater markets globally have slowed since the start of the recent industry downturn in 2014.
Revenues. Consolidated revenues in the third quarter of 2017 decreased $15.0 million, or 8%, from the third quarter of 2016 due to declines in our Offshore/Manufactured Products segment, which were partially offset by improvementsthe exit of certain non-performing service offerings in January 2022. As can be derived from the following table, 61% of our consolidated revenues in both the first quarter of 2022 and 2021 were derived from sales of our short-cycle product and service offerings.
The following table provides supplemental disaggregated revenue from contracts with customers by operating segment for the three months ended March 31, 2022 and 2021 (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Offshore/ Manufactured Products | | Well Site Services | | Downhole Technologies | | Total |
| Three Months Ended March 31 | 2022 | | 2021 | | 2022 | | 2021 | | 2022 | | 2021 | | 2022 | | 2021 |
| Major revenue categories - | | | | | | | | | | | | | | | |
| Project-driven products | $ | 33,844 | | | $ | 21,374 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 33,844 | | | $ | 21,374 | |
| Short-cycle: | | | | | | | | | | | | | | | |
| Completion products and services | 13,580 | | | 8,114 | | | 45,166 | | | 38,799 | | | 31,760 | | | 25,430 | | | 90,506 | | | 72,343 | |
| Drilling services | — | | | — | | | 3,006 | | | 751 | | | — | | | — | | | 3,006 | | | 751 | |
| Other products | 7,044 | | | 4,136 | | | — | | | — | | | — | | | — | | | 7,044 | | | 4,136 | |
| Total short-cycle | 20,624 | | | 12,250 | | | 48,172 | | | 39,550 | | | 31,760 | | | 25,430 | | | 100,556 | | | 77,230 | |
| Other products and services | 29,644 | | | 26,985 | | | — | | | — | | | — | | | — | | | 29,644 | | | 26,985 | |
| $ | 84,112 | | | $ | 60,609 | | | $ | 48,172 | | | $ | 39,550 | | | $ | 31,760 | | | $ | 25,430 | | | $ | 164,044 | | | $ | 125,589 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Percentage of total revenue by type - | | | | | | | | | | | | | | | |
| Products | 71 | % | | 65 | % | | — | % | | — | % | | 82 | % | | 86 | % | | 52 | % | | 49 | % |
| Services | 29 | % | | 35 | % | | 100 | % | | 100 | % | | 18 | % | | 14 | % | | 48 | % | | 51 | % |
Cost of Revenues (exclusive of Depreciation and Amortization Expense). Our consolidated total cost of revenues (exclusive of depreciation and amortization expense) increased $24.3 million, or 24%, in the first quarter of 2022 compared to the first quarter of 2021.
Consolidated product costs in the first quarter of 2022 increased $15.3 million, or 31%, compared to the first quarter of 2021. Consolidated service costs in the first quarter of 2022 increased $9.0 million, or 17%, compared to the first quarter of 2021.
Selling, General and Administrative Expense. Selling, general and administrative expense increased $2.6 million, or 12%, in the first quarter of 2022 from the first quarter of 2021 due primarily to higher professional service, bad debt and trade show expenses.
Depreciation and Amortization Expense. Depreciation and amortization expense decreased $3.7 million, or 17%, in the first quarter of 2022 compared to the prior-year period, driven primarily by reduced capital investments made in our Well Site Services segment in recent years. Note 10, "Segments and Related Information," to our Consolidated Financial Statements presents depreciation and amortization expense by segment. In
Impairments of Fixed Assets. During the thirdfirst quarter of 2017, over 55% of consolidated revenues were driven by U.S. shale play activity.
Our Well Site Services segment revenues increased $30.8 million, or 67%, in the third quarter of 2017 from the prior-year quarter due to growth of both Completion Services and Drilling Services revenues. Our Completion Services revenues increased $22.0 million, or 57%, in the third quarter of 2017 compared to the third quarter of 2016, with the impact of a higher commodity price environment and lower overall service costs driving increased U.S. land-based activity, partially offset by the timing of customer activity in certain international markets. The number of Completion Services job tickets in the third quarter of 2017 increased 31% over the prior-year period and revenue per Completion Services job increased 20% year-over-year as a result of increased completions activity and a more favorable job mix. Our Drilling Services revenues increased $8.8 million, or 119%, to $16.2 million in the third quarter of 2017 from the third quarter of 2016 primarily as a result of increased utilization of our land drilling rigs from an average of 15% during the third quarter of 2016 to an average of 34% in the third quarter of 2017 coupled with increased dayrates.
Our Offshore/Manufactured Products segment revenues decreased $45.8 million, or 35%, in the third quarter of 2017 compared to the third quarter of 2016 primarily as a result of a decline in demand for deepwater project-driven products (including subsea pipeline infrastructure, offshore production and drilling products), lower levels of service activities and a backlog position that has trended lower since mid-2014. These deepwater project-driven revenue declines were partially offset by increases in sales of our short-cycle products, which increased 59% year-over-year. Shorter-cycle products, such as elastomers and valves, have benefited from increased land-based drilling and completion activity in the United States. Bidding and quoting activity, along with orders from customers, for our Offshore/Manufactured Products segment continued, albeit at a much slower pace. Reflecting the impact of customer delays and deferrals in approving major, capital intensive projects in light of the prolonged low commodity price environment, backlog in our Offshore/Manufactured Products segment decreased from $340 million at December 31, 2015 to $199 million at December 31, 2016. With a book to bill ratio of 1.0x in the first nine months of 2017, our backlog remained relatively flat at $198 million as of September 30, 2017.
Cost of Sales and Services. Our consolidated cost of sales and services decreased $6.6 million, or 5%, in the third quarter of 2017 compared to the third quarter of 2016 as a result of decreased cost of sales and services at our Offshore/Manufactured Products segment of $28.8 million, or 31%, which was partially offset by a $22.2 million, or 51%, increase in cost of services at our Well Site Services segment. Consolidated gross profit as a percentage of revenues decreased from 24% in the third quarter of 2016 to 21% in the third quarter of 2017, with gross margin expansion within2021, our Well Site Services segment offset byrecorded non-cash impairment charges of $0.7 million to reduce the impactcarrying value of a significant reduction in salescertain of project-driven products in our Offshore/Manufactured Products segment.the segment's fixed assets to their estimated realizable value.
Our Well Site Services segment cost of services increased $22.2 million, or 51%, in the third quarter of 2017 compared to the third quarter of 2016 as a result of a $14.7 million, or 40%, increase in Completion Services cost of services and a $7.5 million, or 108%, increase in costs in our Drilling Services business. These increases in cost of services, which are strongly correlated to the revenue increases in these businesses, reflect the increase in land-based activity in the United States. Costs increases included higher personnel costs from increased employee overtime and costs associated with headcount additions made during the current year. Our Well Site Services segment gross profit as a percentage of revenues improved from 5% in the third quarter of 2016 to 14% in the third quarter of 2017. Our Completion Services gross profit as a percentage of revenues increased from 5% in the third quarter of 2016 to 15% in the third quarter of 2017 primarily due to the significant increase in revenue levels. Our Drilling Services gross profit as a percentage of revenues improved from 5% in the third quarter of 2016 to 10% in the third quarter of 2017, primarily due to increased rig utilization and cost absorption.
Our Offshore/Manufactured Products segment cost of sales decreased $28.8 million, or 31%, in the third quarter of 2017 compared to the third quarter of 2016 reflecting the decrease in project-driven activity. Gross profit as a percentage of revenues decreased from 31% in the third quarter of 2016 to 27% in the third quarter of 2017 driven primarily by the reported 70% decline in sales of project-driven products.
Selling, General and Administrative Expenses. Selling, general and administrative expenses decreased $3.5 million, or 12%, in the third quarter of 2017 from the prior-year quarter reflecting the impact of 2016 cost reduction measures, lower incentive compensation accruals and reduced employee severance-related charges in the third quarter of 2017.
Depreciation and Amortization. Depreciation and amortization expense decreased $3.1 million, or 10%, in the third quarter of 2017 compared to the third quarter of 2016 primarily due to certain assets becoming fully depreciated and overall lower levels of capital expenditures.
Other Operating (Income) Expense, Net. Other operating income declined from $1.4 million in the third quarter of 2016 to $0.6 million in the third quarter of 2017, primarily due to the impact of lower foreign currency exchange gains recognized in the current-year period.
Operating Loss.Loss. Our consolidated operating loss increased from $15.6was $4.3 million in the thirdfirst quarter of 20162022. This compares to $18.2a consolidated operating loss of $19.8 million recognized in the first quarter of 2021, which included the $0.7 million of non-cash fixed asset impairment charges and $3.4 million in severance and restructuring costs. Excluding these charges, our consolidated operating loss decreased $11.4 million or 72%.
Interest Expense, Net. Net interest expense was $2.7 million in the thirdfirst quarter of 2017 primarily as a result of a decrease in operating income from our Offshore/Manufactured Products segment of $15.5 million due2022, which compares to a continued decline in offshore-related activity, offset by a decrease in operating loss of $12.9 million from our Well Site Services segment. Corporate expenses were $12.3$2.3 million in the thirdfirst quarter of 2017, flat with the prior-year period.
Interest Expense and Interest Income. Net interest expense decreased $0.2 million, or 14%, in the third quarter of 2017 compared to the third quarter of 2016 primarily due to a reduction in amounts outstanding under the Revolving Credit Facility (defined below) partially offset by higher unused commitment fees paid to our lenders.2021. Interest expense as a percentage of total debt outstanding increased from 5.6%was approximately 6% in the thirdfirst quarter of 2016 to 14.0%2022 and 4% in the thirdfirst quarter of 2017 due to an increased proportion2021.
Other Income, Net. Net other income for the first quarter of interest expense associated2021 included non-cash gains of $3.6 million in connection with unused commitment fees, lower average borrowings outstanding underour purchases of $125.0 million principal amount of our 1.5% convertible senior notes (the "2023 Notes") for $120.0 million in cash.
Income Tax. For the Revolving Credit Facility and non-cash amortizationfirst quarter of debt issuance costs.
Income TaxBenefit. The2022, our income tax provision for interim periods is basedwas $3.4 million on estimatesa pre-tax loss of $6.0 million. Income tax expense in the effectivefirst quarter of 2022 included the impact of valuation allowances recorded against U.S. tax rate for the entire fiscal year. The Company’s incomeassets as well as certain non-deductible expenses and discrete tax provision for the three months ended September 30, 2017 was an income tax benefit of $4.0 million, or 21% of pre-tax losses, compareditems. This compares to an income tax benefit of $6.0$2.3 million or 36%on a pre-tax loss of pre-tax losses$18.1 million for the three months ended September 30, 2016. The lower effective tax rate benefit in the thirdfirst quarter of 2017 was primarily attributable to a shift in2021, which included certain non-deductible expenses and discrete tax items.
Other ComprehensiveIncome (Loss). Reported comprehensive loss is the mix between domestic pre-tax lossessum of reported net loss and foreign pre-taxother comprehensive income compared to the prior-year period, additional valuation allowances provided against net operating losses in certain domestic and foreign jurisdictions and incremental tax expense related to the decision to carryback 2016 net operating losses.
Other ComprehensiveIncome(Loss)(loss). Other comprehensive income was $4.9$0.9 million in the thirdfirst quarter of 20172022 compared to a loss of $5.2$1.5 million in the thirdfirst quarter of 20162021 due to fluctuations in foreign currency exchange rates compared to the U.S. dollar for certain of the international operations of our reportableoperating segments. For the three months ended September 30, 2017first quarters of 2022 and 2016, currency translation adjustments recognized as a component of other comprehensive income (loss) were primarily attributable to the United Kingdom and Brazil. During the third quarter of 2017, the exchange rates for the British pound and the Brazilian real strengthened compared to the U.S. dollar. This compares to the third quarter of 2016, when the exchange rates for the British pound weakened compared to the U.S. dollar, while the Brazilian real strengthened compared to the U.S. dollar. The British pound was impacted by the United Kingdom’s vote to exit the European Union in late June 2016.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
We reported a net loss for the nine months ended September 30, 2017 of $47.0 million, or $0.94 per diluted share, which included $2.0 million ($1.5 million after-tax, or $0.03 per diluted share) of severance and other downsizing charges and $1.0 million ($0.02 per diluted share) of additional tax expense related to the decision to carryback net operating losses incurred in 2016 against taxable income reported in 2014. Excluding these charges in the first nine months of 2017, the net loss would have been $44.5 million, or $0.89 per diluted share. These results compare to a net loss of $35.8 million, or $0.71 per diluted share for the nine months ended September 30, 2016, which included $4.6 million ($3.0 million after-tax, or $0.06 per diluted share) of severance and other downsizing charges. Excluding these charges in the first nine months of 2016, the net loss would have been $32.8 million, or $0.65 per diluted share.
During the third quarter of 2017, the Company’s consolidated results of operations were adversely affected by Hurricane Harvey which caused widespread damage and logistical challenges in Houston and the surrounding region where we operate five manufacturing facilities and employ about 500 individuals. The Company was impacted by lower revenues and under-absorption of manufacturing facility costs primarily in its Offshore/Manufactured Products segment but also suffered some field-level downtime due to employee dislocations resulting from the storm. One of the Company's Houston facilities experienced significant flooding and is not yet operational but was fully insured. Project work in that facility has been shifted to other manufacturing locations to meet customer delivery requirements.
Our consolidated results of operations also reflect current industry trends and customer spending activities which are focused on growth in the U.S. shale play regions with weaker U.S. Gulf of Mexico and international activity. In addition, investments in deepwater markets globally have slowed since the start of the recent industry downturn in 2014.
Revenues. Consolidated revenues in the first nine months of 2017 decreased $37.6 million, or 7%, from the first nine months of 2016 due to declines in our Offshore/Manufactured Products segment, partially offset by improvements in our Well Site Services segment. In the first nine months of 2017, over 50% of consolidated revenues were driven by U.S. shale play activity.
Our Well Site Services segment revenues increased $75.9 million, or 58%, in the first nine months of 2017 compared to the prior-year period due to growth of both Completion Services and Drilling Services revenues. Our Completion Services revenues increased $50.8 million, or 44%, in the first nine months of 2017 compared to the first nine months of 2016, with the impact of a higher commodity price environment and lower service costs driving increased U.S. land-based activity, partially offset by the timing of customer activity in certain international markets. The number of Completion Services job tickets in the first nine months of 2017 increased 23% over the prior-year period and revenue per Completion Services job increased 17% year-over-year as a result of increased completions activity, a more favorable job mix and improved pricing. Our Drilling Services revenues increased $25.1 million, or 179%, to $39.1 million in the first nine months of 2017 from the first nine months of 2016 due to higher utilization of our land drilling rigs, which increased from an average of 10% during the first nine months of 2016 to an average of 28% in the first nine months of 2017.
Our Offshore/Manufactured Products segment revenues decreased $113.5 million, or 29%, in the first nine months of 2017 compared to the first nine months of 2016 primarily as a result of a decline in demand for deepwater project-driven products (primarily subsea pipeline infrastructure, offshore production and drilling products), lower levels of service activities and a backlog position that has trended lower since mid-2014. These deepwater project-driven revenue declines were partially offset by a 76% increase in sales of our short-cycle products. Shorter-cycle products, such as elastomers and valves, have benefited from increased land-based drilling and completion activity in the United States. Bidding and quoting activity, along with orders from customers, for our Offshore/Manufactured Products segment continued, albeit at a much slower pace. Reflecting the impact of customer delays and deferrals in approving major, capital intensive projects in light of the prolonged low commodity price environment, backlog in our Offshore/Manufactured Products segment decreased from $340 million at December 31, 2015 to $199 million at December 31, 2016. With a book-to-bill ratio of 1.0x in the first nine months of 2017, our backlog remained relatively flat at $198 million as of September 30, 2017.
Cost of Sales and Services. Our consolidated cost of sales and services decreased $21.0 million, or 5%, in the first nine months of 2017 compared to the first nine months of 2016 as a result of decreased cost of sales and services at our Offshore/Manufactured Products segment of $76.6 million, or 28%, which was partially offset by a $55.5 million, or 44%, increase in cost of services at our Well Site Services segment. Consolidated gross profit as a percentage of revenues decreased from 24% in the first nine months of 2016 to 22% in the first nine months of 2017 with gross margin expansion within our Well Site Services segment offset by the impact of a significant reduction in sales of project-driven products in our Offshore/Manufactured Products segment.
Our Well Site Services segment cost of services increased $55.5 million, or 44%, in the first nine months of 2017 compared to the first nine months of 2016 as a result of a $35.1 million, or 31%, increase in Completion Services cost of services and a $20.4 million, or 142%, increase in service costs in our Drilling Services business. These increases in cost of services, which are strongly correlated to the revenue increases in these businesses, reflect the increase in land-based activity in the United States. Costs increases included higher personnel costs from increased employee overtime and costs associated with headcount additions made during the nine months of 2017. Our Well Site Services segment gross profit as a percentage of revenues increased from 4% in the first nine months of 2016 to 12% in the first nine months of 2017. Our Completion Services gross profit as a percentage of revenues increased from 4% in the first nine months of 2016 to 12% in the first nine months of 2017 primarily due to the increase in revenues. Our Drilling Services gross profit as a percentage of revenues improved from (3)% in the first nine months of 2016 to 11% in the first nine months of 2017 primarily due to increased rig utilization and cost absorption.
Our Offshore/Manufactured Products segment cost of sales decreased $76.6 million, or 28%, in the first nine months of 2017 compared to the first nine months of 2016 reflecting the decrease in project-driven revenues. Gross profit as a percentage of revenues decreased from 30% in the first nine months of 2016 to 29% in the first nine months of 2017, due primarily to the reported 62% decline in sales of project-driven products, which was partially offset by a 76% increase in sales of short-cycle products.
Selling, General and Administrative Expenses. Selling, general and administrative expenses decreased $6.8 million, or 7%, in the first nine months of 2017 from the prior-year period primarily due to the impact of 2016 cost reduction initiatives and lower employee severance-related charges in the first nine months of 2017, partially offset by higher incentive compensation accruals.
Depreciation and Amortization. Depreciation and amortization expense decreased $7.1 million, or 8%, in the first nine months of 2017 compared to the first nine months of 2016 primarily due to certain assets becoming fully depreciated coupled with overall lower levels of capital expenditures.
Other Operating (Income) Expense, Net. Other operating (income) expense, net moved from other operating income of $4.1 million in the first nine months of 2016 to other operating expense of $0.4 million in the first nine months of 2017, reflecting primarily the impact of foreign currency exchange gains or losses recognized in the respective periods.
Operating Loss. Our consolidated operating loss increased from $52.9 million in the first nine months of 2016 to $60.0 million in the first nine months of 2017 primarily as a result of a decrease in operating income from our Offshore/Manufactured Products segment of $40.4 million due to a continued decline in offshore-related activity, partially offset by a decreased operating loss of $35.7 million from our Well Site Services segment. Corporate expenses were $37.3 million in the first nine months of 2017, an increase of $2.5 million from the prior-year period due primarily to higher incentive compensation accruals and increased stock-based compensation expense.
Interest Expense and Interest Income. Net interest expense decreased $0.7 million, or 18%, in the first nine months of 2017 compared to the first nine months of 2016 primarily due to a reduction in amounts outstanding under the Revolving Credit Facility partially offset by higher unused commitment fees paid to our lenders. Interest expense as a percentage of total debt outstanding increased from 5.6% in the first nine months of 2016 to 14.5% in the first nine months of 2017 due to an increased proportion of interest expense associated with unused commitment fees, lower average borrowings outstanding under the Revolving Credit Facility and non-cash amortization of debt issuance costs.
Income TaxBenefit. The income tax provision for interim periods is based on estimates of the effective tax rate for the entire fiscal year. The Company’s income tax provision for the nine months ended September 30, 2017 was an income tax benefit of $15.7 million, or 25% of pre-tax losses, compared to an income tax benefit of $20.5 million, or 36% of pre-tax losses for the nine months ended September 30, 2016. The lower effective tax rate benefit in the first nine months of 2017 was primarily attributable to a shift in the mix between domestic pre-tax losses and foreign pre-tax income compared to the prior-year period, additional valuation allowances provided against net operating losses in certain domestic and foreign jurisdictions, and incremental tax expense related to the decision to carryback 2016 U.S. net operating losses against 2014 taxable income.
Other ComprehensiveIncome(Loss). Other comprehensive income was $13.5 million in the first nine months of 2017 compared to a loss of $12.5 million in the first nine months of 2016 due to fluctuations in foreign currency exchange rates compared to the U.S. dollar for certain of the international operations of our reportable segments. For the nine months ended September 30, 2017 and 2016,2021, recurring currency translation adjustments recognized as a component of other comprehensive income (loss) were primarily attributable to the United Kingdom and Brazil. During the first nine monthsquarter of 2017,2022, the exchange rates for the British pound and the Brazilian real strengthened compared to the U.S. dollar. This compares to the first nine months of 2016, when exchange ratesrate for the British pound weakened compared to the U.S. dollar, while the Brazilian real strengthened compared to the U.S. dollar. TheDuring the first quarter of 2021, the exchange rate for the British pound was impactedstrengthened compared to the U.S. dollar while the exchange rate for the Brazilian real weakened compared to the U.S. dollar.
Segment Operating Results
Offshore/Manufactured Products
Revenues. Our Offshore/Manufactured Products segment revenues increased $23.5 million, or 39%, in the first quarter of 2022 compared to the first quarter of 2021 due primarily to increased demand for short-cycle products and fixed platform equipment.
Operating Income (Loss). Our Offshore/Manufactured Products segment reported operating income of $10.2 million in the first quarter of 2022. The segment reported an operating loss of $1.1 million in the first quarter of 2021, which included severance and restructuring costs of $0.3 million.
Backlog. Backlog in our Offshore/Manufactured Products segment totaled $265 million as of March 31, 2022 compared to $260 million as of December 31, 2021. Bookings during the first quarter of 2022 totaled $93 million, yielding a book-to-bill ratio of 1.1x.
Well Site Services
Revenues. Our Well Site Services segment revenues increased $8.6 million, or 22%, in the first quarter of 2022 compared to the same prior-year period, driven by increased U.S. customer activity levels partially offset by the exit of U.S. thru-tubing service offerings in January 2022.
Operating Loss. Our Well Site Services segment reported an operating loss of $3.4 million in the first quarter of 2022. The segment reported an operating loss of $9.9 million in the first quarter of 2021, which included non-cash fixed asset impairment charges of $0.7 million. The operating loss decrease of $6.5 million, or 66%, compared to the same prior-year period was primarily driven by the impact of the reported revenue growth and a $3.7 million decrease in depreciation and amortization expense.
Downhole Technologies
Revenues. Our Downhole Technologies segment revenues increased $6.3 million, or 25%, in the first quarter of 2022 from the same prior-year period due primarily to increased customer demand for perforating and completion products in the United Kingdom’s voteStates.
Operating Loss. Our Downhole Technologies segment reported an operating loss of $1.5 million in the first quarter of 2022. The segment reported an operating loss of $1.6 million in the first quarter of 2021.
Corporate
Operating Loss. Corporate expenses of $9.6 million in the first quarter of 2022 were comparable to exit the European Union in late June 2016.first quarter of 2021.
Liquidity, Capital Resources and Other Matters
Our primary liquidity needs are to fund operating and capital expenditures, which, in the past, have included expanding and upgrading our Offshore/Manufactured Products manufacturing facilities and equipment, replacing and increasing Completion Services assets, funding new product development and general working capital needs. In addition, capital has been used to repay debt, fund our share repurchase program, and fund strategic business acquisitions.acquisitions, repay debt and fund share repurchases. Our primary sources of funds have beenare cash flow from operations, proceeds from borrowings under the Revolving Credit Facility,our credit facilities and, less frequently, capital markets transactions.
The crude oil and natural gas industry is highly cyclical which may result in declines in the demand for, and prices of, our products and services or the inability or failure of our customers to meet their obligations to us. These adverse market conditions could require us to incur asset impairment charges, deferred tax valuation allowances and/or write down the value of our goodwill, and may otherwise adversely impact our results of operations and our cash flows and financial position.
Operating Activities
Despite generally weak market conditions, cashCash flows totaling $76.3used in operations totaled $10.7 million were provided by continuingduring the three months ended March 31, 2022, compared to $8.4 million used in operations during the first nine monthsquarter of 2017 compared to $107.8 million provided by continuing operations during the same period of 2016. 2021.
During the first nine monthsquarter of 2017, $25.52022, $21.3 million was provided fromused to fund net working capital reductions with decreasesincreases, primarily due to increases in inventories and accounts receivable and inventories partially offsetdriven by the impact of a $17.3 million increase in income taxes receivable.higher activity levels. During the first nine monthsquarter of 2016, $64.62021, $12.1 million was provided fromused to fund net working capital reductionsincreases, primarily due to decreasesincreases in accounts receivable and inventories.
Investing Activities
Cash used in investing activities during the first nine monthsquarter of 2017 was $32.72022 totaled $2.1 million, compared to $24.4$2.4 million used in investing activities during the first nine months of 2016. 2021.
Capital expenditures totaled $20.3$2.9 million and $23.9$4.1 million during the first nine monthsquarter of 20172022 and 2016,2021, respectively. DuringThese investments were partially offset by proceeds from the first nine monthssale of 2017, we also invested $12.9 million within our Offshore/Manufactured Products segment to acquire complementary intellectual property and assets to expand our global crane manufacturingequipment of $0.9 million and service operations as well as our riser testing, inspection and repair service offerings.
After considering the $20.3$1.9 million invested during the first ninethree months of 2017, we2022 and 2021, respectively.
We expect to spend between $30approximately $25 million and $35 million in total capital expenditures during 2017, which compares to $30 million spent in 2016.2022. Whether planned expenditures will actually be spentmade in 20172022 depends on industry conditions, project approvals and schedules, vendor delivery timing, free cash flow generation and careful monitoring of our levels of liquidity. We plan to fund these capital expenditures with available cash, internally generated funds and, if necessary, borrowings under the Revolving Credit Facility. The foregoing capital expenditure forecast does not include any funds for strategic acquisitions, which the Company could pursue depending on the economic environment in our industry and the availability of transactions at prices deemed to be attractive to the Company.
At September 30, 2017, substantially all of our cash was held by our international subsidiaries. Our intent is to utilize at least a portion of these cash balances for future investment outside of the United States. Approximately $37 million of cash held by our international subsidiaries can be repatriated by us without triggering any incremental tax consequences.
ABL Facility discussed below.
Financing Activities
During the ninethree months ended September 30, 2017,March 31, 2022, net cash of $48.6$1.2 million was used in financing activities, primarily as a result of repayment of $26.6 million of borrowings under the Revolving Credit Facility and repurchases of our common stock totaling $16.3 million in the second quarter of 2017.activities. This compares to $63.7$6.6 million of cash used in financing activities during the ninethree months ended September 30, 2016, primarilyMarch 31, 2021, including our purchases of $125.0 million principal amount of our 2023 Notes for cash totaling $120.0 million and $12.0 million of net repayments under our ABL Facility. Partially offsetting these uses in the first quarter of 2021 was our issuance of $135.0 million principal amount of our 4.75% convertible senior notes (the "2026 Notes") yielding net cash proceeds of $130.3 million.
As of March 31, 2022, we had cash and cash equivalents totaling $39.2 million, which compared to $52.9 million as a result of repayingDecember 31, 2021.
As of March 31, 2022, we had no borrowings outstanding under our ABL Facility, $26.0 million principal amount of our 2023 Notes outstanding, $135.0 million principal amount of our 2026 Notes outstanding and other debt underof $21.5 million. Our reported interest expense, which included amortization of deferred financing costs of $0.5 million during the Revolving Credit Facility.
first quarter of 2022, was above our contractual cash interest expense. For the first quarter of 2022, our contractual cash interest expense was $2.2 million, or approximately 5% of the average principal balance of debt outstanding.
We believe that cash on hand,on-hand, cash flow from operations and borrowing capacity available borrowings under the Revolving Creditour ABL Facility will be sufficient to meet our liquidity needs in the coming twelve months. If our plans or assumptions change, or are inaccurate, or if we make further acquisitions, we may need to raise additional capital. Acquisitions have been, and our management believes acquisitions will continue to be, a key element of our business strategy. The timing, size or success of any acquisition effort and the associated potential capital commitments are unpredictable and uncertain. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Our ability to obtain capital for additional projects to implement our growth strategy over the longer term will depend upon our future operating performance, financial condition and, more broadly, on the availability of equity and debt financing. Capital availability will be affected by prevailing conditions in our industry, the global economy, the global financial markets, stakeholder scrutiny of ESG matters and other factors, many of which are beyond our control. In this regard, the effect of the COVID-19 pandemic resulted in a significant disruption of global financial markets. For companies like ours that support the energy industry, this disruption negatively impacted the value of our common stock and may reduce our ability to access capital in the bank and capital markets or result in such capital being available on less favorable terms, which could in the future negatively affect our liquidity.
On March 21, 2022, the SEC proposed new rules relating to the disclosure of a range of climate-related information and risks. We are currently assessing these rules, but at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from these rules. To the extent these rules are finalized as proposed, we or our customers could incur increased costs related to the assessment and disclosure of climate-related risks. We may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. In addition, such additional debt serviceenhanced climate disclosure requirements could be based on higher interest ratesaccelerate the trend of certain stakeholders and shorter maturitieslenders in restricting or seeking more stringent conditions with respect to their investments in our customers in the energy industry and could impose a significant burdencompanies like ours that support the energy industry. For more information on our resultsrisks related to climate change, see the risk factor in "Part I, Item 1A. Risk Factors" included in our Annual Report on Form 10-K for the year ended December 31, 2021 titled, "Our and our customers' operations are subject to a series of operations and financial condition, and any issuancerisks arising out of additional equity securitiesthe threat of climate change that could result in significant dilution to stockholders.
Share Repurchase Program. On July 29, 2015,increased operating costs, limit the Company’s Board of Directors approved a new share repurchase program providingareas in which oil and natural gas production may occur, and reduce demand for the repurchase of up to $150.0products and services we provide."
ABL Facility. On February 10, 2021, we entered into a senior secured credit facility with certain lenders, which provides for a $125.0 million of the Company’s common stock, which, following extension, was scheduled to expire on July 29, 2017. On July 26, 2017, our Board of Directors extended the share repurchase program for one year to July 29, 2018. During the first nine months of 2017, the Company repurchased 562 thousand shares of common stock under the program at a total cost of $16.3 million. The amount remaining under our share repurchase authorization as of September 30, 2017 was $120.5 million. Subject to applicable securities laws, such purchases will be at such times and in such amounts as the Company deems appropriate.
Credit Facility. The Company has a $600 million senior securedasset-based revolving credit facility (the “Revolving Credit Facility”"ABL Facility") with an option to increase the maximum borrowings to $750 millionunder which credit availability is subject to additional lender commitmentsa borrowing base calculation. On March 16, 2021, we entered into an amendment to the ABL Facility that permitted us to incur the indebtedness represented by the 2026 Notes.
The ABL Facility is governed by a credit agreement, as amended, with Wells Fargo Bank, National Association, as administrative agent and the lenders and other financial institutions from time to time party thereto (the "ABL Agreement"). The ABL Agreement matures on February 10, 2025 with a springing maturity 91 days prior to itsthe maturity of any outstanding indebtedness with a principal amount in excess of $17.5 million (excluding the unsecured promissory note to the seller of GEODynamics, Inc. discussed below).
See Note 4, "Long-term Debt," to the Unaudited Condensed Consolidated Financial Statements included in this Quarterly Report on May 28, 2019.Form 10-Q for further information regarding the ABL Agreement. As of September 30, 2017,March 31, 2022, we had $15.6 million in borrowings outstanding under the Credit Agreement (as defined below) and an additional $21.6$19.6 million of outstanding letters of credit, leaving $146.5 million available to be drawnbut no borrowings outstanding under the Revolving Credit Facility. As of September 30, 2017, amounts available to be drawn under the Revolving Credit Facility plus cash and cash equivalents totaled $212.4 million.ABL Agreement. The total amount available to be drawn was less than the lender commitments as of September 30, 2017, dueMarch 31, 2022 was $51.0 million, calculated based on the current borrowing base less outstanding letters of credit.
2026 Notes. On March 16, 2021, we issued $135.0 million aggregate principal amount of the 2026 Notes pursuant to the maximum leverage ratio covenant in the Credit Agreement which serves to limit borrowings. We expect our availability to continue to be limited by the maximum leverage ratio covenant during the remainder of 2017 and into 2018 based upon our forecast of our trailing twelve-month EBITDA (as defined in the Credit Agreement and further discussed below).
The Revolving Credit Facility is governed by a Credit Agreementan indenture, dated as of May 28, 2014, as amended,March 16, 2021 (the “Credit Agreement”"2026 Indenture") by and among, between the Company the Lenders party thereto,and Wells Fargo Bank, N.A.,National Association, as administrative agent,trustee. Computershare Trust Company, National Association, assumed the Swing Line Lender and an Issuing Bank; Royal Bankrole of Canada,trustee as Syndication agent; and Compass Bank, as Documentation agent. Amounts outstanding underof March 1, 2022. Net proceeds from the Revolving Credit Facility bear interest at LIBOR plus a margin of 1.50% to 2.50%, or at a base rate plus a margin of 0.50% to 1.50%, in each case based on a ratio2026 Notes offering, after deducting issuance costs, totaled $130.6 million. We used $120.0 million of the Company’s total leveragecash proceeds to EBITDA. Duringpurchase $125.0 million principal amount of the first nine months of 2017, our applicable margin over LIBOR was 1.50%. We must also pay a quarterly commitment fee, based on our leverage ratio, onoutstanding 2023 Notes, with the unused commitments under the Credit Agreement. The unused commitment fee was 0.375% during the first nine months of 2017. Interest expense as a percentage of total debt outstanding increased from 5.6% in the first nine months of 2016balance added to 14.5% in the first nine months of 2017. The increase in the weighted average interest rate was attributable to an increased proportion of interest expense associated with unused commitment fees, lower average borrowings outstanding under the Revolving Credit Facility and non-cash amortization of debt issuance costs.
cash on-hand.
The Credit Agreement2026 Indenture contains customary financial covenants and restrictions. Specifically, we must maintain an interest coverage ratio, defined ascertain events of default, including certain defaults by the ratio of consolidated EBITDACompany with respect to consolidated interest expense,other indebtedness of at least 3.0$40.0 million.
See Note 4, "Long-term Debt," to 1.0 and a maximum leverage ratio, defined as the ratioUnaudited Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q for further information regarding the 2026 Notes. As of total debt to consolidated EBITDA, of no greater than 3.25 to 1.0. EachMarch 31, 2022, none of the factors consideredconditions allowing holders of the 2026 Notes to convert, or requiring us to repurchase the 2026 Notes, had been met.
2023 Notes. On January 30, 2018, we issued $200.0 million aggregate principal amount of the 2023 Notes pursuant to an indenture, dated as of January 30, 2018 (the "2023 Indenture"), between the Company and Wells Fargo Bank, National Association, as trustee. Computershare Trust Company, National Association, assumed the role of trustee as of March 1, 2022. Since September 2019, we have purchased a cumulative $174.0 million principal amount of the 2023 Notes for $152.8 million in cash, with $26.0 million principal amount outstanding as of March 31, 2022.
The 2023 Indenture contains certain events of default, including certain defaults by the calculationsCompany with respect to other indebtedness of these ratios are definedat least $40.0 million.
See Note 4, "Long-term Debt," to the Unaudited Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q for further information regarding the Credit Agreement. EBITDA and consolidated interest, as defined, exclude goodwill impairments, losses on extinguishment of debt, debt discount amortization, and other non-cash charges.2023 Notes. As of September 30, 2017,March 31, 2022, none of the conditions allowing holders of the 2023 Notes to convert, or requiring us to repurchase the 2023 Notes, had been met.
Promissory Note. In connection with the 2018 acquisition of GEODynamics, Inc., (such company, "GEODynamics" and such acquisition, the "GEODynamics Acquisition"), we wereissued a $25.0 million promissory note that was scheduled to mature on July 12, 2019. Payments due under the promissory note are subject to set-off, in compliance withfull or in part, against certain indemnification claims related to matters occurring prior to our debt covenantsacquisition of GEODynamics. We have provided notice to and expect to continueasserted indemnification claims against the seller of GEODynamics (the "Seller"), and the Seller has filed a breach of contract suit against us and one of our wholly-owned subsidiaries alleging that payments due under the promissory note are required to be, but have not been, repaid in compliance duringaccordance with the remainderterms of 2017. Borrowings under the Credit Agreement are secured by a pledgesuch note. We have incurred settlement costs and expenses of substantially all of our assets$7.5 million related to such indemnification claims and the assets of our domestic subsidiaries. Our obligations under the Credit Agreement are guaranteed by our significant domestic subsidiaries.
Under the Credit Agreement, the occurrence of specified change of control events involving our Company would constitute an event of defaultbelieve that would permit the banks to, among other things, accelerate the maturity date of such note is extended until the facilityresolution of such indemnity claims and cause itthat we are permitted to become immediately dueset-off the principal amount owed by the amount of such costs and payableexpenses. Accordingly, we have reduced the carrying amount of such note in full.
our consolidated balance sheet to $17.5 million as of March 31, 2022, which is our current best estimate of what is owed after set-off for indemnification matters. See Note 11, "Commitments and Contingencies," to the Unaudited Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q for additional discussion.
Our total debt represented 1.6%21% and 20% of our combined total debt and stockholders’stockholders' equity at September 30, 2017 compared to 3.7% atas of March 31, 2022 and December 31, 2016.2021, respectively.
Contingencies and Other Obligations. We are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our product or operations. Some of these claims relate to matters occurring prior to the acquisition of businesses, and some relate to businesses we have sold. In certain cases, we are entitled to indemnification from the sellers of the businesses and, in other cases, we have indemnified the buyers of businesses. In addition, the Seller in the GEODynamics Acquisition filed a breach of contract suit against us in federal court in August 2020, in which the Seller alleged, among other contractual breaches, that it was entitled to approximately $19 million in U.S. federal income tax carryback claims we received under the provisions of the CARES Act legislation. On February 15, 2021, the Seller dismissed the federal lawsuit without prejudice and refiled its lawsuit in state court. On September 20, 2021, a motion by the Seller for partial summary judgement was denied by the state court. Although we can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by indemnity or insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity. See Note 11, "Commitments and Contingencies," to the Unaudited Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q for additional discussion.
Off-Balance Sheet Arrangements. As of March 31, 2022, we had no off-balance sheet arrangements. Critical Accounting Policies
For a discussion of the critical accounting policies and estimates that we use in the preparation of our condensed consolidated financial statements, see “Item"Part II Item 7. Management’sManagement's Discussion and Analysis of Financial Condition and Results of Operations”Operations" in our 20162021 Annual Report on Form 10-K. These estimates require significant judgments, assumptions and estimates. We have discussed the development, selection, and disclosure of these critical accounting policies and estimates with the audit committee of our Board of Directors. There have been no material changes to the judgments, assumptions and estimates upon which our critical accounting estimates are based. For a discussion of recent
Recent Accounting Pronouncements
From time to time, new accounting pronouncements see Note 2, “Recentare issued by the Financial Accounting Pronouncements.”Standards Board, which are adopted by us as of the specified effective date. Management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on our consolidated financial statements upon adoption.
Off-Balance Sheet Arrangements
As of September 30, 2017, we had no off-balance sheet arrangements as defined in Item 303(a)(4)(ii) of Regulation S-K.
ITEMItem 3.Quantitative and Qualitative Disclosures about Market Risk
Market risk refers to the potential losses arising from changes in interest rates, foreign currency fluctuations and exchange rates, equity prices, and commodity prices, including the correlation among these factors and their volatility.
Our principal market risks are our exposure to changes in interest rates and foreign currency exchange rates. We enter into derivative instruments only to the extent considered necessary to meet risk management objectives and do not use derivative contracts for speculative purposes.
Interest Rate Risk
Risk.We have a revolving credit facility that is subject to the risk of higher interest charges associated with increases in interest rates. As of September 30, 2017,March 31, 2022, we had no floating-rate obligations totaling $15.6 million drawnoutstanding under the Revolving Creditour ABL Facility. TheseUse of floating-rate obligations would expose us to the risk of increased interest expense in the event of increases in short-term interest rates. If the floating interest rates increased by 1% from September 30, 2017 levels, our consolidated interest expense would increase by a total of approximately $0.2 million annually.
Foreign Currency Exchange Rate Risk
Risk.Our operations are conducted in various countries around the world and we receive revenue from these operations in a number of different currencies. As such, our earnings are subject to movements in foreign currency exchange rates when transactions are denominated in (i) currencies other than the U.S. dollar, which is our functional currency, or (ii) the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of foreign currency exchange rate risks in areas outside of the United States (primarily in our Offshore/Manufactured Products segment), we generally pay a portion of our expenses in local currencies and a substantial portion of our contracts provide for collections from customers in U.S. dollars. During the ninethree months ended September 30, 2017,March 31, 2022, our reported foreign currency exchange losses were $0.6$0.4 million and are included in “Other"Other operating (income) expense, net”net" in the Consolidated Statementsconsolidated statements of Operations. In order to reduce our exposure to fluctuations in foreign currency exchange rates, we may enter into foreign currency exchange agreements with financial institutions. As of September 30, 2017 and December 31, 2016, we had outstanding foreign currency forward purchase contracts with notional amounts of $2.4 million related to expected cash flows denominated in Euros.operations.
Our accumulatedAccumulated other comprehensive loss, reported as a component of stockholders’stockholders' equity, decreased from $70.3 million at December 31, 2016primarily relates to $56.8 million at September 30, 2017, due to changesfluctuations in currency exchange rates. Accumulated other comprehensive loss is primarily related to fluctuations in the currency exchange rates compared toagainst the U.S. dollar which areas used to translate certain of the international operations of our reportableoperating segments. ForOur accumulated other comprehensive loss decreased $0.9 million from $66.0 million as of December 31, 2021 to $65.2 million as of March 31, 2022, due to changes in currency exchange rates. During the ninethree months ended September 30, 2017, currency translation adjustments recognized as a component of other comprehensive income were primarily attributable to the United Kingdom and Brazil. As of September 30, 2017,March 31, 2022, the exchange ratesrate for the British pound and the Brazilian realweakened by 3% compared to the U.S. dollar while the Brazilian real strengthened by 8% and 3%, respectively,17% compared to the exchange rates at December 31, 2016, contributing to other comprehensive income of $13.5 million reported for the nine months ended September 30, 2017.U.S. dollar.
ITEM 4.Controls and Procedures
(i) Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this Quarterly Report on Form 10-Q, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) of the Exchange Act. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission.SEC. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2017March 31, 2022 at the reasonable assurance level.
(ii) Changes in Internal ControlOverFinancial Reporting
During the nine months ended September 30, 2017, there wereThere have been no changes in ourthe Company's internal control over financial reporting (as that term is defined in Rules 13a-15(f) and 15d-15(f) ofunder the Exchange Act), which have that occurred during the three months ended March 31, 2022, that has materially affected, our internal control over financial reporting, or areis reasonably likely to materially affect, our internal control over financial reporting.
PART II --– OTHER INFORMATION
ITEM 1.Legal Proceedings
The information with respect to this Item 1 is set forth under Note 13, “Commitments11, "Commitments and Contingencies.”"
ITEM 1A.Risk Factors
“"Part I, Item 1A. Risk Factors”Factors" of our 20162021 Annual Report on Form 10-K includes a detailed discussion of our risk factors. The risks described in this Quarterly Report on Form 10-Q and our 2016 Form 10-Ksuch report are not the only risks we face. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, also may materially adversely affect our business, financial conditionconditions or future results. There have been no material changes to our risk factors as set forth in our 20162021 Annual Report on Form 10-K.
ITEM 2.Unregistered Sales of Equity Securities and Use of Proceeds
(a) None.
(b) None.
(c)
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Total Number of Shares Purchased(1) | | Average Price Paid per Share(1) | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs |
| January 1 through January 31, 2022 | | — | | | $ | — | | | — | | | $ | — | |
| February 1 through February 28, 2022 | | 160,834 | | | 6.15 | | | — | | | — | |
| March 1 through March 31, 2022 | | — | | | — | | | — | | | — | |
| Total | | 160,834 | | | $ | 6.15 | | | — | | | |
________________
(1)All shares purchased during the three-month period ended March 31, 2022 were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants. These shares were not part of a publicly announced program to purchase common stock.
|
| | | | | | | | | | | | | | |
| Period | | Total Number of Shares Purchased(1) | | Average Price Paid per Share(1) | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs(2) |
| July 1 through July 31, 2017 | | 57 |
| | $ | 26.55 |
| | — |
| | $ | 120,544,560 |
|
| August 1 through August 31, 2017 | | 4,354 |
| | 21.52 |
| | — |
| | 120,544,560 |
|
| September 1 through September 30, 2017 | | 420 |
| | 24.45 |
| | — |
| | 120,544,560 |
|
| Total | | 4,831 |
| | $ | 21.83 |
| | — |
| | |
|
| |
(1) | All of the 4,831 shares purchased during the three-month period ended September 30, 2017 were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants. These shares were not part of a publicly announced program to purchase common stock. |
| |
(2) | On July 29, 2015, the Company’s Board of Directors approved a new share repurchase program providing for the repurchase of up to $150 million of the Company’s common stock, which, following extension, was scheduled to expire on July 29, 2017. On July 26, 2017, our Board of Directors extended the share repurchase program for one year to July 29, 2018. |
ITEM 3.Defaults Upon Senior Securities
None.
ITEM4.Mine Safety Disclosures.
Disclosures
Not applicable.
ITEM 5.Other Information
None.
ITEM 6.Exhibits
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| Exhibit No. | | Description |
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| 101.INS* | — | XBRL Instance Document |
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| 101.SCH* | — | XBRL Taxonomy Extension Schema Document |
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| 101.CAL* | — | XBRL Taxonomy Extension Calculation Linkbase Document |
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| 101.DEF* | — | XBRL Taxonomy Extension Definition Linkbase Document |
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| 101.LAB* | — | XBRL Taxonomy Extension Label Linkbase Document |
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| 101.PRE* | — | XBRL Taxonomy Extension Presentation Linkbase Document |
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| 104 | — | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
The exhibits required to be filed by Item 6. are set forth in the Exhibit Index accompanying this Quarterly Report on Form 10‑Q.---------
* Filed herewith.
** Furnished herewith.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
OIL STATES INTERNATIONAL, INC.
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| | | | OIL STATES INTERNATIONAL, INC. | |
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| Date: | October 27, 2017April 29, 2022 | | ByBy: | /s/ LLOYD A. HAJDIK | |
| | | | Lloyd A. Hajdik | |
| | | | Executive Vice President, Chief Financial Officer and | |
| | | | Treasurer (Duly Authorized Officer and Principal Financial Officer) | |
Exhibit Index
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Exhibit No. | | Description |
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101.INS* | — | XBRL Instance Document |
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101.SCH* | — | XBRL Taxonomy Extension Schema Document |
| | |
101.CAL* | — | XBRL Taxonomy Extension Calculation Linkbase Document |
| | |
101.DEF* | — | XBRL Taxonomy Extension Definition Linkbase Document. |
| | |
101.LAB* | — | XBRL Taxonomy Extension Label Linkbase Document |
| | |
101.PRE* | — | XBRL Taxonomy Extension Presentation Linkbase Document |
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* Filed herewith.
** Furnished herewith.