The pressure pumping services segment provides hydraulic fracturing. The well services segment provides coil tubing, flowback and equipment rental services. The sand segment sells, distributes and produces sand for use in hydraulic fracturing. The contract land and directional drilling services segment provides vertical, horizontal and directional drilling services. The other energy services segment provides housing, kitchen and dining, and recreational service facilities for oilfield workers that are located in remote areas away from readily available lodging as well as energy infrastructure services. The pressure pumping and well service segments primarily services in the Utica Shale of Eastern Ohio, Marcellus Shale in Pennsylvania, Eagle Ford and Permian basin in Texas and the SCOOP/STACK in the mid-continent region. The natural sand proppant segment primarily services the Utica Shale and Montney Shale in British Columbia and Alberta, Canada. The contract land and directional drilling services segment primarily services the Permian Basin in West Texas. The other energy services segment provides service in Canada, Texas and New Mexico.
Subsequent to September 30, 2017, the Company entered into railcar lease agreements with aggregate commitments of $2.2 million.
Subsequent to September 30, 2017, the Company ordered additional capital equipment with aggregate commitments of $3.4 million.
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Subsequent to September 30, 2017, the Company entered into an agreement to purchase sand from an unrelated third party seller with aggregate commitments of $2.2 million.
On October 19, 2017, Cobra entered into a contract to aid in the restoration of utility infrastructure on the island of Puerto Rico. The contract provides for payments of up to $200.0 million, including an initial payment of $15.0 million at the time of signing. As of November 7, 2017, the Company had entered into $32.7 million of commitments related to this contract and made prepayments and deposits of $12.6 million with respect to these commitments.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read in conjunction with the unaudited condensed consolidated financial statements and related notes thereto presented in this quarterly reportQuarterly Report and the consolidated financial statements and related notes thereto included in our Annual Report on Form 10-K. This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in Item 1A. “Risk Factors” in our Form 10-K for the year ended December 31, 2016,2022, filed with the Securities and Exchange Commission, or the SEC, on February 24, 2017.2023 and the section entitled “Forward-Looking Statements” appearing elsewhere in this Quarterly Report.
Overview
We are an integrated, growth-oriented energy serviceservices company serving companies engaged infocused on providing products and services to enable the exploration and development of North American onshore unconventional oil and natural gas reservesreserve as well as the construction and energy infrastructure.repair of the electric grid for private utilities, public investor-owned utilities and co-operative utilities through our infrastructure services businesses. Our primary business objective is to grow our operations and create value for stockholders through organic growth opportunities and accretive acquisitions. Our suite of services includes pressure pumpingwell completion services, wellinfrastructure services, natural sand proppant services, contract land and directional drilling services and other energy services. Our pressure pumpingwell completion services division provides hydraulic fracturing, sand hauling and water transfer services. Our wellinfrastructure services division provides pressure controlengineering, design, construction, upgrade, maintenance and repair services cementing, flowback services and equipment rentals.to the electrical infrastructure industry. Our natural sand proppant services division mines, processes and sells distributes and producesnatural sand proppant used for hydraulic fracturing. Our contract land and directional drilling services division currently provides drilling rigs and crews for operators as well as rental equipment, such as mud motors and operational tools, for both vertical and horizontal drilling. Our other energyIn addition to these service divisions, we also provide aviation services, division has historically provided housing, kitchenequipment rentals, crude oil hauling services, remote accommodations and dining, and recreational service facilities for oilfield workers located in remote areas away from readily available lodging and now also includes energy infrastructure services.equipment manufacturing. We believe that the services we offer play a critical role in increasing the ultimate recovery and present value of production streams from unconventional resources.resources as well as in maintaining and improving electrical infrastructure. Our complementary suite of completion and production and drilling related services provides us with the opportunity to cross-sell our services and expand our customer base and geographic positioning.
On November 24, 2014, Mammoth Energy Holdings LLC, or Mammoth Holdings, Gulfport Energy Corporation, or Gulfport, The growth of our industrial businesses is ongoing. We offer infrastructure engineering services focused on the transmission and Rhino Exploration LLC, or Rhino, contributeddistribution industry and also have equipment manufacturing operations and offer fiber optic services. Our equipment manufacturing operations provide us with the ability to Mammoth Energy Partners LP, orrepair much of our existing equipment in-house, as well as the Partnership, their respective interestsoption to manufacture certain new equipment we may need in the following entities: Bison Drillingfuture. Our fiber optic services include the installation of both aerial and Field Services, LLC, or Bison Drilling; Bison Trucking LLC, or Bison Trucking; White Wing Tubular Services LLC, or White Wing; Barracuda Logistics LLC, or Barracuda; Panther Drilling Systems LLC, or Panther Drilling; Redback Energy Services LLC, or Redback Energy Services; Redback Coil Tubing LLC, or Redback Coil Tubing; Muskie Proppant LLC, or Muskie Proppant; Stingray Pressure Pumping LLC, or Pressure Pumping; Stingray Logistics LLC, or Logistics;buried fiber. We are continuing to explore other opportunities to expand our industrial business lines.
Although demand across our three largest segments improved during 2022 and Great White Sand Tiger Lodging Ltd., or Lodging. Upon completion of these contributions, Mammoth Holdings, Gulfport and Rhino beneficially owned a 68.7%, 30.5% and 0.8% equity interest, respectively,remained strong during the three months ended March 31, 2023, we continue to address the external challenges in the Partnership.
On October 12, 2016, prior to and in connection with the IPO, the Partnership converted to a Delaware limited liability company named Mammoth Energy Partners LLC, or Mammoth LLC, and Mammoth Holdings, Gulfport and Rhino contributed their respective membership interests in Mammoth LLC to us in exchange for shares of our common stock, and Mammoth LLC became our wholly-owned subsidiary.
On October 19, 2016,today’s economic environment as we closed our IPO of 7,750,000 shares of common stock, of which 7,500,000 shares were sold by us and the remaining 250,000 shares were sold by certain selling stockholders, at a price to the public of $15.00 per share. Our common stock is traded on the Nasdaq Global Select Market under the symbol “TUSK.” Unless the context otherwise requires, references in this report to “we,” “our,” “us,” or like terms, when used in a historical context for periods prior to October 12, 2016 refer to the Partnership and its subsidiaries. References in this report to “we,” “our,” “us,” or like terms, when used in the present tense or for periods commencing on or after October 12, 2016 refer to Mammoth Energy Services, Inc., or Mammoth Inc., and its subsidiaries. Mammoth Inc. was formed in June 2016, and did not conduct any material business operations prior to the completion of the IPO and the contribution described above completed on October 12, 2016 immediately prior to the IPO. Prior to the IPO, Mammoth Inc. was a wholly-owned subsidiary of the Partnership.
On June 5, 2017, we acquired Sturgeon Acquisitions LLC, or Sturgeon, and Sturgeon's wholly owned subsidiaries Taylor Frac, LLC, Taylor Real Estate Investments, LLC and South River Road, LLC. Prior to the acquisition, we and Sturgeon were under common control and, in accordance with generally accepted accounting principles in the United States, or GAAP, we have accounted for this acquisition in a manner similar to the pooling of interest method of accounting. Therefore, our historical financial information for all periods included in this Quarterly Report on Form 10-Q has been recast to combine Sturgeon's financial resultsremain disciplined with our financial results as if the acquisition had been effective since Sturgeon commenced operations.spending and are focused on continuing to improve our operational efficiencies and cost structure and on enhancing value for our stockholders.
Overview of Our Industries
Third Quarter 2017 Highlights
Oil and Natural Gas Industry
Expansion of Services
During the third quarter of 2017, we expanded our pressure pumping, sand and last-mile trucking services into the SCOOP/STACK. The startup of our fifth pressure pumping fleet occurred in August 2017 with the startup of our sixth fleet occurring in October 2017, both of which were in the Mid-Continent.
5-Star Acquisition
On July 1, 2017, we completed our acquisition of 5 Star Electric, LLC, or 5 Star, from unrelated third party sellers. We funded the the acquisition of 5 Star with cash on hand and borrowings under our credit facility. The acquisition of 5 Star expanded the energy infrastructure component of our other energy services segment.
Industry Overview
The oil and natural gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including the domestic and international supply and demand for oil and natural gas, current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by exploration and production companies to their drilling, completion and related services and products budget.budgets. The oil and natural gas industry is also impacted by general domestic and international economic conditions, political instability in oil producing countries, government regulations (both in the United States and elsewhere), levels of customer demand, the availability of pipeline capacity, storage capacity, shortages of equipment and materials and other conditions and factors that are beyond our control.
Demand for most of our oil and natural gas products and services depends substantially on the level of expenditures by companies in the oil and natural gas industry. The significant declinelevels of capital expenditures of our customers are predominantly driven by the prices of oil and natural gas. In March and April 2020, concurrent with the COVID-19 pandemic and quarantine orders in the U.S. and worldwide, oil prices dropped sharply to below zero dollars per barrel for the first time in history due to factors including significantly reduced demand and a shortage of storage facilities. In 2021, U.S. oil production stabilized as
commodity prices increased and demand for crude oil rebounded. We saw improvements in the oilfield services industry and in both pricing and utilization of our well completion and drilling services during 2022. During the first quarter of 2023, pricing for crude oil and natural gas prices that begandeclined from levels seen in the third quarter of 2014 continued into February 2016, when the closing price of oil reached a 12-year low of $26.19 per barrel on February 11, 2016. The low commodity price environment caused a reduction in the drilling,2022, which may slow down completion and other production activities of most offor our customers and, their spending on our products and services.
The reduction inas a result, reduce demand during the first part of 2016, and the resulting oversupply of many of the services and products we provide, substantially reduced the prices we could charge our customers for our productswell completion services. Further, the ongoing war and services, and had a negativerelated humanitarian crisis in Ukraine could continue to have an adverse impact on the utilizationglobal energy markets and volatility of commodity prices.
In response to market conditions, we have temporarily shut down our cementing and acidizing operations and flowback operations beginning in July 2019, our contract drilling operations beginning in December 2019, our rig hauling operations beginning in April 2020, our coil tubing, pressure control and full service transportation operations beginning in July 2020 and our crude oil hauling operations beginning in July 2021. We continue to monitor the market to determine if and when we can recommence these services.
We are currently operating three of our services. This overall trend with respectsix pressure pumping fleets. Subject to market conditions, supply chain constraints and liquidity requirements, we have plans to upgrade one spread to Tier 4 dual fuel as well as upgrade two fleets to Tier 2 dual fuel, giving us a total of four dual fuel fleets by year-end 2023. Continuing supply chain disruptions have resulted in backlogs of equipment and replacement parts for our customers’ activities and spending reversed in late 2016 as oil prices startedour competitors’ pressure pumping fleets, which we expect to rebound from the 12-year low recorded on February 11, 2016 of $26.21 per barrel, reaching a high of $54.06 per barrel on December 28, 2016. Duringpersist through at least the first nine monthshalf of 2017,2023. Any of these factors may result in the delay of our plans to activate, convert or upgrade our existing pressure pumping fleets in the second half of 2023, which may adversely impact our business, financial condition and cash flow.
Natural Sand Proppant Industry
In our natural sand proppant services business, we experienced a significant decline in demand for our sand proppant in the second half of 2019 and throughout 2020 as a result of completion activity falling due to lower oil traded between a low of $42.53 per barrel recorded on June 21, 2017demand and a high of $54.45 per barrel on February 23, 2017, withpricing, increased capital discipline by our customers, budget exhaustion and the COVID-19 pandemic. Activity rebounded modestly in 2021 and continued to increase throughout 2022 as we saw an average of $49.40 per barrel. This increase in commodity prices from 2016 levels has spurred a significant increase in the land rig count with 918 rigs operating on September 29, 2017, up approximately 45%volume of sand sold. Supply constraints from labor shortages have negatively affected West Texas in-basin mine operations and increased demand for Northern White frac sand for the 635 rigs operating at year-end 2016. Asregion in 2022. Demand from oil and gas companies in Western Canada and the rig count increased, we experienced anMarcellus Shale was also strong in 2022. The increase in activity and pricing, mainly in our completion and production, natural sand proppant and contract land and directional drilling businesses. If near term commodity prices remain at current levels or recover further, we expect to continue to experience2022 resulted in an increase in demand and pricing for our services and products. Despitesand, which continued throughout the anticipated declines in remote accommodation services revenue, our other energy services revenue increased during the thirdfirst quarter of 20172023. However, as discussed above, pricing for crude oil and natural gas declined from levels seen in 2022, which may impact completion activities for our energycustomers and demand for our sand proppant services.
As a result of adverse market conditions, production at our Muskie sand facility in Pierce County, Wisconsin has been temporarily idled since September 2018. Our contracted capacity has provided a baseline of business, which has kept our Taylor and Piranha plants operating and our costs competitive.
Energy Infrastructure Industry
Our infrastructure services began to contribute to our financial results. Within this segment, subsequentbusiness provides engineering, design, construction, upgrade, maintenance and repair services to the endelectrical infrastructure industry. We offer a broad range of services on electric transmission and distribution, or T&D, networks and substation facilities, which include engineering, design, construction, upgrade, maintenance and repair of high voltage transmission lines, substations and lower voltage overhead and underground distribution systems. Our commercial services include the installation, maintenance and repair of commercial wiring. We also provide storm repair and restoration services in response to storms and other disasters. We provide infrastructure services primarily in the northeast, southwest, midwest and western portions of the thirdUnited States. We currently have agreements in place with private utilities, public IOUs and Co-Ops.
During 2022, operational improvements combined with increased crew count drove enhanced results in our infrastructure services division. Although our average crew count declined slightly from approximately 93 crews throughout the fourth quarter of 2017,2022 to approximately 88 crews throughout the first quarter of 2023, operational efficiencies drove improved results. Funding for projects in the infrastructure space remains strong with added opportunities expected from the Infrastructure Investment and Jobs Act, which was signed into law on November 15, 2021. We anticipate the federal spending to begin fueling additional projects in this sector beginning in late 2023. We continue to focus on operational execution and pursue opportunities within this sector as we strategically structure our service offerings for growth, intending to increase our infrastructure services activity and expand both our geographic footprint and depth of projects, especially in fiber maintenance and installation projects.
We work for multiple utilities primarily across the northeastern, southwestern, midwestern and western portions of the United States. We believe that we are well-positioned to compete for new projects due to the experience of our infrastructure management team, combined with our vertically integrated service offerings. We are seeking to leverage this experience and our service offerings to grow our customer base and increase our revenues in the continental United States over the coming years.
Our infrastructure services business has been adversely impacted by the outstanding amounts owed to us by the Puerto Rico Electric Power Authority, or PREPA, for services performed by our subsidiary, Cobra Acquisitions LLC, or Cobra, signed a contract to aid in the restoration of the electric utility infrastructure in Puerto Rico to restore PREPA’s electrical grid damaged by Hurricane Maria. As of March 31, 2023, PREPA owed us approximately $227.0 million for services performed excluding approximately $163.2 million of interest charged on these delinquent balances. See Note 2. Basis of Presentation and Significant Accounting Policies—Accounts Receivable of our unaudited condensed consolidated financial statements. PREPA is currently subject to bankruptcy proceedings, which were filed in July 2017 and are currently pending in the U.S. District Court for the District of Puerto Rico. As a result, PREPA’s ability to meet its payment obligations under the contracts is largely dependent upon funding from the Federal Emergency Management Agency, or FEMA, or other sources. On September 30, 2019, we filed a motion with the U.S. District Court for the District of Puerto Rico seeking recovery of the amounts owed to us by PREPA, which motion was stayed by the Court. On March 25, 2020, we filed an urgent motion to modify the stay order and allow our recovery of approximately $62 million in claims related to a tax gross-up provision contained in the first contract. This emergency motion was denied on June 3, 2020 and the Court extended the stay of our motion. On December 9, 2020, the Court again extended the stay of our motion and directed PREPA to file a status report by June 7, 2021. On April 6, 2021, we filed a motion to lift the stay order. Following this filing, PREPA initiated discussion with Cobra, which resulted in PREPA and Cobra filing a joint motion to adjourn all deadlines relative to the April 6, 2021 motion until the June 16, 2021 omnibus hearing as a result of PREPA’s understanding that providesFEMA would be releasing a report in the near future relating to the first contract. The joint motion was granted by the Court on April 14, 2021. On May 26, 2021, FEMA issued a Determination Memorandum related to the first contract between Cobra and PREPA in which, among other things, FEMA raised two contract compliance issues and, as a result, concluded that approximately $47 million in costs were not authorized costs under the contract. On June 14, 2021, the Court issued an order adjourning Cobra’s motion to lift the stay order to a hearing on August 4, 2021 and directing Cobra and PREPA to meet and confer in good faith concerning, among other things, (i) the May 26, 2021 Determination Memorandum issued by FEMA and (ii) whether and when a second determination memorandum is expected. The parties were further directed to file an additional status report, which was filed on July 20, 2021. On July 23, 2021, with our aid, PREPA filed an appeal of the entire $47 million that FEMA de-obligated in the May 26, 2021 Determination Memorandum. FEMA approved the appeal in part and denied the appeal in part. FEMA found that staffing costs of $24.4 million are eligible for funding. On August 4, 2021, the Court denied Cobra’s April 6, 2021 motion to lift the stay order, extended the stay of our motion seeking recovery of amounts owed to Cobra and directed the parties to file an additional joint status report, which was filed on January 22, 2022. On January 26, 2022, the Court extended the stay and directed the parties to file a further status report by July 25, 2022. On June 7, 2022, Cobra filed a motion to lift the stay order. On June 29, 2022 the Court denied Cobra’s motion and extended the stay to January 2023. On November 21, 2022, FEMA issued a Determination Memorandum related to the 100% federal funded portion of the second contract between Cobra and PREPA in which FEMA concluded that approximately $5.6 million in costs were not authorized costs under the contract. On December 21, 2022, FEMA issued a Determination Memorandum related to the 90% federal cost share portion of the second contract between Cobra and PREPA in which FEMA concluded that approximately $68.1 million in costs were not authorized costs under the contract. PREPA filed a first-level administrative appeal of the November 21, 2022 Determination Memorandum and has indicated that they will review the December 21, 2022 Determination Memorandums and, to the extent they feel plausible, file a first-level administrative appeal of the unauthorized amounts. On January 7, 2023, Cobra and PREPA filed a joint status report with the Court, in which PREPA requested that the Court continue the stay through July 31, 2023 and Cobra requested that the stay be lifted. On January 18, 2023, the Court entered an order extending the stay and directing the parties to file a further status report addressing (i) the status of any administrative appeals in connection with the November and December determination memorandums regarding the second contract, (ii) the status of the criminal proceedings against the former Cobra president and the FEMA official that concluded in December 2022, and (iii) a summary of the outstanding and unpaid amounts arising from the first and second contracts and whether PREPA disputes Cobra’s entitlement to these amounts with the Court by July 31, 2023.
On January 20, 2023, Cobra submitted a certified claim for approximately $379 million to FEMA pursuant to the federal Contract Disputes Act. On February 1, 2023, FEMA notified Cobra that it had reviewed the claim and determined that no contract, expressed or implied, exists between FEMA and Cobra. On March 27, 2023, Cobra was notified that FEMA had approved $233 million in Cobra invoices related to the December 21, 2022 Determination Memorandum. The 90% federal cost share of this approved amount was $210 million, which was obligated and made available for draw down on March 27, 2023. Of this $210 million, approximately $99 million has been represented by both PREPA and FEMA as intended to pay Cobra for outstanding invoices and the remaining $111 million is a reimbursement to PREPA for payments already made on Cobra invoices. On March 29, 2023, Cobra filed a notice of upappeal with the Civilian Board of Contract Appeals related to $200 million. Underthe certified
claim submitted in January 2023. On April 25, 2023, FEMA filed a motion to dismiss Cobra’s appeal alleging lack of jurisdiction.
We believe all amounts charged to PREPA were in accordance with the terms of the contracts. Further, we believe these receivables are collectible. However, in the event PREPA (i) does not have or does not obtain the funds necessary to satisfy its obligations to Cobra under the contracts, (ii) obtains the necessary funds but refuses to pay the amounts owed to us or (iii) otherwise does not pay amounts owed to us for services performed, the receivable may not be collected and our financial condition, results of operations and cash flows would be materially and adversely affected. In addition, government contracts are subject to various uncertainties, restrictions and regulations, including oversight audits and compliance reviews by government agencies and representatives. In this contract, we intend to mobilize more than 500 peopleregard, on September 10, 2019, the U.S. District Court for the District of Puerto Rico unsealed an indictment that charged the former president of Cobra with conspiracy, wire fraud, false statements and disaster fraud. Two other individuals were also charged in the indictment. The indictment focused on the interactions between a former FEMA official and the necessary equipmentformer President of Cobra. Neither we nor any of our subsidiaries were charged in the indictment. On May 18, 2022, the former FEMA official and the former president of Cobra each pled guilty to Puerto Rico.one-count information charging gratuities related to a project that Cobra never bid upon and was never awarded or received any monies for. On December 13, 2022, the Court sentenced the former Cobra president to custody of the Bureau of Prisons for six months and one day, a term of supervised release of six months and a fine of $25,000. The Court sentenced the FEMA official to custody of the Bureau of Prisons for six months and one day, a term of supervised release of six months and a fine of $15,000. The Court also dismissed the indictment against the two defendants. We do not expect any additional activity in the criminal proceeding. Given the uncertainty inherent in the criminal litigation, however, it is not possible at this time to determine the potential impacts that the sentencings could have on us. PREPA has stated in Court filings that it may contend the alleged criminal activity affects Cobra’s entitlement to payment under its contracts with PREPA. It is unclear what PREPA's position will be going forward. See Note 18. Commitments and Contingencies to our unaudited condensed consolidated financial statements included elsewhere in this report for additional information regarding these investigations and proceedings. Further, as noted above, our contracts with PREPA have concluded and we have not obtained, and there can be no assurance that we will be able to obtain, one or more contracts with other customers to replace the level of services that we provided to PREPA.
First Quarter 2023 Financial Overview
•Total revenue for the first quarter of 2023 increased by $54.0 million, or 87%, to $116.3 million from $62.3 million for the first quarter of 2022. The increase in total revenue is primarily due to an increase in well completions, driven primarily by increased utilization and pricing for our services.
•Net income for the first quarter of 2023 was $8.4 million, or $0.17 per diluted share, as compared to net loss of $14.8 million, or $0.32 loss per diluted share, for the first quarter of 2022.
•Net cash flow provided by operating activities for the first quarter of 2023 was $3.2 million, as compared to net cash flow used in operating activities of $2.4 million for the first quarter of 2022.
•Adjusted EBITDA (as defined and reconciled below) for the first quarter of 2023 increased by $21.4 million, or 230%, to $30.7 million from $9.3 million for the first quarter of 2022. See “Non-GAAP Financial Measures” below for a reconciliation of net income to Adjusted EBITDA.
Results of Operations
Three Months Ended September 30, 2017March 31, 2023 Compared to Three Months Ended September 30, 2016March 31, 2022 | | | | | | | | | | | |
| Three Months Ended |
| March 31, 2023 | | March 31, 2022 |
| (in thousands) |
Revenue: | | | |
Well completion services | $ | 67,300 | | | $ | 23,874 | |
Infrastructure services | 28,280 | | | 23,009 | |
Natural sand proppant services | 12,467 | | | 9,179 | |
Drilling services | 1,825 | | | 2,855 | |
Other services | 7,032 | | | 4,732 | |
Eliminations | (584) | | | (1,351) | |
Total revenue | 116,320 | | | 62,298 | |
| | | |
Cost of revenue: | | | |
Well completion services (exclusive of depreciation and amortization of $4,813 and $6,437, respectively, for the three months ended March 31, 2023 and 2022) | 52,515 | | | 22,870 | |
Infrastructure services (exclusive of depreciation and amortization of $3,372 and $4,306, respectively, for the three months ended March 31, 2023 and 2022) | 22,487 | | | 18,903 | |
Natural sand proppant services (exclusive of depreciation, depletion and accretion of $1,186 and $1,792, respectively, for the three months ended March 31, 2023 and 2022) | 7,860 | | | 7,788 | |
Drilling services (exclusive of depreciation and amortization of $1,367 and $1,680, respectively, for the three months ended March 31, 2023 and 2022) | 2,031 | | | 2,532 | |
Other services (exclusive of depreciation and amortization of $2,210 and $2,933, respectively, for the three months ended March 31, 2023 and 2022) | 4,684 | | | 3,664 | |
Eliminations | (584) | | | (1,277) | |
Total cost of revenue | 88,993 | | | 54,480 | |
Selling, general and administrative expenses | 8,383 | | | 8,668 | |
Depreciation, depletion, amortization and accretion | 12,956 | | | 17,167 | |
Gains on disposal of assets, net | (361) | | | (196) | |
| | | |
| | | |
Operating income (loss) | 6,349 | | | (17,821) | |
Interest expense, net | (3,289) | | | (2,349) | |
Other income, net | 8,624 | | | 9,041 | |
Income (loss) before income taxes | 11,684 | | | (11,129) | |
Provision for income taxes | 3,333 | | | 3,688 | |
Net income (loss) | $ | 8,351 | | | $ | (14,817) | |
|
| | | | | | | |
| Three Months Ended |
| September 30, 2017 | | September 30, 2016 |
Revenue: | | | |
Pressure pumping services | $ | 75,704,868 |
| | $ | 35,531,481 |
|
Well services | 16,161,569 |
| | 2,274,728 |
|
Natural sand proppant services | 29,331,525 |
| | 8,232,467 |
|
Contract land and directional drilling services | 13,643,943 |
| | 8,695,475 |
|
Other energy services | 14,462,995 |
| | 8,604,395 |
|
Total revenue | 149,304,900 |
| | 63,338,546 |
|
| | | |
Cost of revenue: | | | |
Pressure pumping services | 52,960,761 |
| | 20,782,936 |
|
Well services | 13,852,628 |
| | 3,068,159 |
|
Natural sand proppant services | 25,177,849 |
| | 6,429,040 |
|
Contract land and directional drilling services | 11,597,757 |
| | 9,042,242 |
|
Other energy services | 10,943,699 |
| | 3,544,410 |
|
Total cost of revenue | 114,532,694 |
| | 42,866,787 |
|
Selling, general and administrative expenses | 8,022,661 |
| | 3,194,607 |
|
Depreciation and amortization | 27,223,733 |
| | 17,921,471 |
|
Operating loss | (474,188 | ) | | (644,319 | ) |
Interest expense, net | (1,420,067 | ) | | (1,024,514 | ) |
Other expense, net | (319,252 | ) | | (253,832 | ) |
Loss before income taxes | (2,213,507 | ) | | (1,922,665 | ) |
(Benefit) provision for income taxes | (1,412,680 | ) | | 1,055,961 |
|
Net loss | $ | (800,827 | ) | | $ | (2,978,626 | ) |
Revenue. Revenue for the three months ended September 30, 2017March 31, 2023 increased $86.0$54.0 million, or 136%87%, to $149.3$116.3 million from $63.3$62.3 million for the three months ended September 30, 2016.March 31, 2022. The increase in total revenue is primarily attributable to an increase in well completions revenue during the three months ended March 31, 2023 primarily due to increased utilization and pricing. Revenue derived from related parties was $0.2 million for the three months ended March 31, 2023 and $0.3 million for the three months ended March 31, 2022. Revenue by operating division was as follows:
Pressure Pumping Well Completion Services. Pressure pumpingWell completion services division revenueincreased $40.2$43.4 million, or 113%182%, to $75.7$67.3 million for the three months ended September 30, 2017March 31, 2023 from $35.5$23.9 million for the three months ended September 30, 2016.March 31, 2022. The increase in our well completion services revenue was primarily driven by ana 189% increase in fleet utilizationthe number of stages completed from two active fleets, averaging 36% utilization,699 for the three months ended September 30, 2016March 31, 2022 to 82%, on2,018 for the three months ended March 31,
2023 as well as an increase in both pricing for our services and sand and chemical materials revenue. An average of 3.6 of our fleets were active for the three months ended March 31, 2023 as compared to an average of five active1.6 fleets for the three months ended September 30, 2017. Our fourth and fifth fleets began working in June and August 2017, respectively. Additionally, the number of stages completed increased to 1,617 for the three months ended September 30, 2017 from 511 for the three months ended September 30, 2016.March 31, 2022.
Well Services. Well Infrastructure Services. Infrastructure services division revenue increased $13.9$5.3 million, or 604%23%, to $16.2$28.3 million for the three months ended September 30, 2017March 31, 2023 from $2.3$23.0 million for the three months ended September 30, 2016. Cementing and energyMarch 31, 2022 primarily due to operational execution, an increase in crew count, improved pricing for our services accounted for $9.1 million of the increase as a result of our Stingray Cementing and Stingray Energy acquisitions. Our coil tubing services accounted for $4.1 million of our operating division increase, as a result of increased utilization and an increase in average day rates from approximately $16,800storm restoration activity. Average crew count was 88 crews for the three months ended September 30, 2016March 31, 2023, as compared to approximately $30,20085 crews for the three months ended September 30, 2017. Our flowback services accounted for $0.7 million of our operating division increase, as a result of an increase in utilization.March 31, 2022.
Natural Sand Proppant Services. Natural sand proppant services division revenue increased $21.1$3.3 million, or 257%36%, to $29.3$12.5 million for the three months ended September 30, 2017,March 31, 2023, from $8.2$9.2 million for the three months ended September 30, 2016. TheMarch 31, 2022 primarily due to an 45% increase was primarily attributablein the average price per ton of sand sold from $21.44 per ton during the three months ended March 31, 2022 to an$31.02 per ton during the three months ended March 31, 2023, and a 19% increase in tons of sand sold from 188,018328,591 tons for the three months ended September 30, 2016March 31, 2022 to 438,800391,439 tons for the three months ended September 30, 2017. InMarch 31, 2023.
addition, the price per ton of sand sold increased from $44 to $67, from the three months ended September 30, 2016 to the three months ended September 30, 2017.
Contract Land and Directional Drilling Services. Contract land and directional drillingServices. Drilling services division revenue increased $4.9decreased $1.1 million, or 56%38%, from $8.7to $1.8 million for the three months ended September 30, 2016March 31, 2023 as compared to $13.6$2.9 million for the three months ended September 30, 2017.March 31, 2022. The increase wasdecrease is primarily attributabledue to a decline utilization for our landdirectional drilling services, which accounted for $2.0 million, or 41%, of the operating division increase as a result of an increase in average day ratesbusiness from approximately $12,200 to approximately $14,80048% for the three months ended September 30, 2016 and 2017, respectively. The average rig count remained consistent at an average of five rigs for each respective period. Our directional drilling services accounted for $1.5 million, orMarch 31, 2022 to 30%, of the operating division increase as a result of utilization increasing from 25% for the three months ended September 30, 2016 to 32% for the three months ended September 30, 2017. Our rig movingMarch 31, 2023.
Other Services. Other services accounted for $1.4revenue, consisting of revenue derived from our aviation, equipment rental, remote accommodation and equipment manufacturing businesses, increased approximately $2.3 million, or 29%, of the operating division increase. The increase in our rig moving services was driven by the increase in drilling activity.
Other Energy Services. Other energy services division revenue, which has historically included only remote accommodation services but now also includes energy infrastructure services, increased $5.9 million, or 69%49%, to $14.5$7.0 million for the three months ended September 30, 2017March 31, 2023, from $8.6$4.7 million for the three months ended September 30, 2016. The increase was a resultMarch 31, 2022. Inter-segment revenue, consisting primarily of revenue derived from our energy infrastructure services of $13.5 million. The increase from energy infrastructure serviceswell completion segment, was partially offset by a decrease in total rooms nights rented from 65,455 to 5,569$0.4 million and $0.3 million for the three months ended September 30, 2016March 31, 2023 and 2017, respectively, partially offset by2022, respectively.
Revenue from our accommodations business increased $1.9 million primarily due to an increase in revenue per room night, in Canadian dollars, from $172 forrooms rented during the three months ended September 30, 2016March 31, 2023 compared to $187 for the three months ended September 30, 2017.March 31, 2022. Additionally, an average of 287 pieces of equipment were rented to customers during the three months ended March 31, 2023, anincrease of 29% from an average of 222 pieces of equipment rented to customers during the three months ended March 31, 2022, resulting in an increase to revenue of $0.3 million.
Cost of Revenue (exclusive of depreciation, depletion, amortization and accretion expense). Cost of revenue, exclusive of depreciation, depletion, amortization and accretion expense, increased $71.6$34.5 million from $42.9$54.5 million, or 68%87% of total revenue, for the three months ended September 30, 2016March 31, 2022 to $114.5$89.0 million, or 77%of total revenue, for the three months ended September 30, 2017.March 31, 2023. The increase is primarily due to an increase in activity in our well completions divisions. Cost of revenue by operating division was as follows:
Pressure PumpingWell Completion Services. Pressure pumpingWell completion services division cost of revenue, exclusive of depreciation and amortization expense, increased $32.2$29.6 million, or 155%130%, to $53.0$52.5 million for the three months ended September 30, 2017March 31, 2023 from $20.8$22.9 million for the three months ended September 30, 2016. The increase wasMarch 31, 2022, primarily due to thean increase in active fleets, which resulted in increases in proppant costs, repairsutilization and maintenance expense and labor-related costs. The labor-related costs were primarily as a result of staffing our third, fourth and fifth pressure pumping fleets during 2017. As a percentage of revenue, our pressure pumping services divisionthe cost of revenue was 70% and 58% for the three months ended September 30, 2017 and September 30, 2016, respectively.
Well Services. Well services division cost of revenue increased $10.8 million, or 348%, from $3.1 million for the three months ended September 30, 2016 to $13.9 million for the three months ended September 30, 2017. The increase was primarily due to increases in labor-related costs and the acquisition of Stingray Cementing and Stingray Energy.consumables. As a percentage of revenue, our well completion services division cost of revenue, was 86%exclusive of depreciation and 135%amortization expense of $4.8 million and $6.4 million for the three months ended September 30, 2017March 31, 2023 and September 30, 2016,2022, respectively, was 78% and 96% for the three months ended March 31, 2023 and 2022, respectively. The decrease in cost of revenue as a percentage of revenue wasis primarily due to thean increase in utilization as well as improved pricing.
Infrastructure Services. Infrastructure services division cost of revenue, exclusive of depreciation and average day ratesamortization expense, increased $3.6 million, or 19%, to $22.5 million for the three months ended March 31, 2023 from $18.9 million for the three months ended March 31, 2022, primarily due to an increase in activity. As a percentage of revenue, cost of revenue, exclusive of depreciation and amortization expense of $3.4 million and $4.3 million for the three months ended March 31, 2023 and 2022, respectively, was 80% and 82% for the three months ended March 31, 2023 and 2022, respectively. The decline as a percentage of revenue is primarily due to improved pricing, an increase in storm restoration activity as well as a decline in labor related costs as a result of improved efficiency of our coil tubing division.crews.
Natural Sand Proppant Services. Natural sand proppant services division cost of revenue, exclusive of depreciation, depletion and accretion expense, increased $18.8$0.1 million, or 294%, from $6.4to $7.9 million for the three months ended September 30, 2016 to $25.2
March 31, 2023 from $7.8 million for the three months ended September 30, 2017, primarily due to an increase in tons of sand sold.March 31, 2022. As a percentage of revenue, cost of revenue, was 86%exclusive of depreciation, depletion and 78%accretion expense of $1.2 million and $1.8 million for the three months ended September 30, 2017March 31, 2023 and September 30, 2016,2022, respectively, was 63% and 85% for the three months ended March 31, 2023 and 2022, respectively. The increase wasdecrease as a percentage of revenue is primarily due to increasesan 45% increase in salesprice per ton of sand sold.
Drilling Services. Drilling services division cost of revenue, exclusive of depreciation and amortization expense, decreased $0.5 million, or 20%, to $2.0 million for the pressure pumping division which are eliminated in consolidation.
Contract Land and Directional Drilling Services. Contract land and directionalthree months ended March 31, 2023 from $2.5 million for the three months ended March 31, 2022. As a percentage of revenue, our drilling services division cost of revenue, increased $2.6exclusive of depreciation and amortization expense of $1.4 million or 29%, from $9.0and $1.7 million for the three months ended September 30, 2016March 31, 2023 and 2022, respectively, was 111% and 86% for the three months ended March 31, 2023 and 2022, respectively. The increase is primarily due to $11.6a decline in utilization.
Other Services. Other services division cost of revenue, exclusive of depreciation and amortization expense, increased $1.0 million, or 27%, to $4.7 million for the three months ended September 30, 2017, primarily due to an increase in labor-related costs, repairs and maintenance and increased utilization. As a percentage of revenue, our contract land and directional drilling services division cost of revenue was 85% and 104% for the three months ended September 30, 2017 and September 30, 2016, respectively. The decrease was primarily due to higher day rates and utilization.
Other Energy Services. Other energy services division cost of revenue increased $7.4 million, or 211%,March 31, 2023 from $3.5$3.7 million for the three months ended September 30, 2016March 31, 2022 primarily due to $10.9 million for the three months ended
September 30, 2017.increased activity. As a percentage of revenue, cost of revenue, was 76%exclusive of depreciation and 41%amortization expense of $2.2 million and $2.9 million for the three months ended September 30, 2017March 31, 2023 and 2016,2022, respectively, was 67% and 77% for the three months ended March 31, 2023 and 2022, respectively. The decrease is primarily due to an increase attributable to costs from our energy infrastructure services was partially offset by decreases in costs attributable to our remote accommodation services.utilization.
Selling, General and Administrative Expenses. Selling, general and administrative, or SG&A, expenses represent the costs associated with managing and supporting our operations. TheseThe table below presents a breakdown of SG&A expenses increased $4.8for the periods indicated (in thousands): | | | | | | | | | | | |
| Three Months Ended |
| March 31, 2023 | | March 31, 2022 |
Cash expenses: | | | |
Compensation and benefits | $ | 4,277 | | | $ | 2,983 | |
Professional services | 1,929 | | | 3,637 | |
Other(a) | 1,911 | | | 1,906 | |
Total cash SG&A expense | 8,117 | | | 8,526 | |
Non-cash expenses: | | | |
Bad debt provision | (381) | | | (99) | |
| | | |
Stock based compensation | 647 | | | 241 | |
Total non-cash SG&A expense | 266 | | | 142 | |
Total SG&A expense | $ | 8,383 | | | $ | 8,668 | |
a. Includes travel-related costs, IT expenses, rent, utilities and other general and administrative-related costs.
Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion decreased $4.2 million, or 150%24%, to $8.0$13.0 million for the three months ended September 30, 2017,March 31, 2023 from $3.2$17.2 million for the three months ended September 30, 2016.March 31, 2022. The increase in expenses wasdecrease is primarily attributable to a $1.5decline in property and equipment depreciation expense as a result of existing assets being fully depreciated.
Gains on Disposal of Assets, Net. Gains on the disposal of assets were $0.4 million increase in compensation, of which $1.0 million was related to equity based compensation, a $3.4 million increase in professional fees and services, of which $0.3 million was related to acquisition-related costs, and a $0.1 million reduction in bad debt expense for the three months ended September 30, 2017, compared to the three months ended September 30, 2016.
Depreciation and Amortization. Depreciation and amortization increased $9.3 million, or 52%, to $27.2$0.2 million for the three months ended September 30, 2017 from $17.9March 31, 2023 and 2022, respectively.
Operating Income (Loss). We reported operating income of $6.3 million for the three months ended September 30, 2016. The increase was primarily attributable to placing in service of $162.6 million of capital additions during 2017 partially offset by $26.2 million and $14.9 million of assets that fully depreciated during 2016 and 2017, respectively.
Interest Expense, Net. Interest expense increased $0.4 million, or 40%, to $1.4 million during the three months ended September 30, 2017, from $1.0 million during the three months ended September 30, 2016. The increase in interest expense was attributable to an increase in average borrowings during the three months ended September 30, 2017.
Other Expense, Net. Non-operating expense resulted in expense of $0.3 million for both the three months ended September 30, 2016 and 2017. Both periods were primarily comprised of loss recognition on assets disposed of during the period.
Income Taxes. Prior to our initial public offering in October 2016, we were treated as a pass-through entity for federal income tax and most state income tax purposes. For the three months ended September 30, 2017, we recognized income tax benefit of $1.4 millionMarch 31, 2023 compared to an income tax expenseoperating loss of $1.1$17.8 million for the three months ended September 30, 2016. The provision for the three months ended September 30, 2016 was primarily attributable to our subsidiary, Lodging, which provides our remote accommodation services.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 |
Revenue: | | | |
Pressure pumping services | $ | 166,081,904 |
| | $ | 91,854,152 |
|
Well services | 27,645,671 |
| | 7,203,225 |
|
Natural sand proppant services | 68,244,156 |
| | 22,440,254 |
|
Contract land and directional drilling services | 36,866,670 |
| | 20,327,904 |
|
Other energy services | 23,694,579 |
| | 23,258,504 |
|
Total revenue | 322,532,980 |
| | 165,084,039 |
|
| | | |
Cost of revenue: | | | |
Pressure pumping services | 117,494,570 |
| | 60,866,617 |
|
Well services | 24,288,693 |
| | 10,030,214 |
|
Natural sand proppant services | 57,759,173 |
| | 22,861,407 |
|
Contract land and directional drilling services | 34,584,336 |
| | 22,010,295 |
|
Other energy services | 16,243,862 |
| | 9,993,073 |
|
Total cost of revenue | 250,370,634 |
| | 125,761,606 |
|
Selling, general and administrative expenses | 22,459,165 |
| | 12,014,619 |
|
Depreciation and amortization | 64,354,383 |
| | 54,483,158 |
|
Impairment of long-lived assets | — |
| | 1,870,885 |
|
Operating loss | (14,651,202 | ) | | (29,046,229 | ) |
Interest expense, net | (2,928,859 | ) | | (3,332,901 | ) |
Bargain purchase gain, net of tax | 4,011,512 |
| | — |
|
Other (expense) income, net | (705,894 | ) | | 371,894 |
|
Loss before income taxes | (14,274,443 | ) | | (32,007,236 | ) |
(Benefit) provision for income taxes | (7,322,822 | ) | | 2,739,696 |
|
Net loss | $ | (6,951,621 | ) | | $ | (34,746,932 | ) |
Revenue. Revenue for the nine months ended September 30, 2017 increased $157.4 million, or 95%, to $322.5 million from $165.1 million for the nine months ended September 30, 2016. Revenue by operating division was as follows:
Pressure Pumping Services. Pressure pumping services division revenue increased $74.2 million, or 81%, to $166.1 million for the nine months ended September 30, 2017 from $91.9 million for the nine months ended September 30, 2016. The increase was primarily driven by an increase in fleet utilization of 45%, on an average of two active fleets, for the nine months ended September 30, 2016 to 84%, on an average of 3.3 active fleets, for the nine months ended September 30, 2017. Additionally, the number of stages completed increased to 3,764 for the nine months ended September 30, 2017 from 1,678 for the nine months ended September 30, 2016.
Well Services. Well services division revenue increased $20.4 million, or 283%, to $27.6 million for the nine months ended September 30, 2017 from $7.2 million for the nine months ended September 30, 2016. The cementing and energy services divisions accounted for $11.7 million of the increase as a result of our Stingray Cementing and Stingray Energy acquisitions. Our coil tubing services accounted for $7.9 million of our operating division increase, as a result of increased utilization and an increase in average day rates from approximately $17,933 for the nine months ended September 30, 2016 to approximately $26,933 for the nine months ended September 30, 2017. Our flowback services accounted for $0.8 million of our operating division increase, as a result of increased utilization.
Natural Sand Proppant Services. Natural sand proppant services division revenue increased $45.8 million, or 204%, to $68.2 million for the nine months ended September 30, 2017, from $22.4 million for the nine months ended September 30, 2016. The increase was primarily attributable to an increase in tons sold from approximately
447,908 for the nine months ended September 30, 2016 to approximately 1,035,506 in the nine months ended September 30, 2017, in addition to an increase in price per ton of of sand sold from $50 to $66, for the nine months ended September 30, 2016 and 2017, respectively.
Contract Land and Directional Drilling Services. Contract land and directional drilling services division revenue increased $16.6 million, or 82%, from $20.3 million for the nine months ended September 30, 2016 to $36.9 million for the nine months ended September 30, 2017. The increase was primarily attributable to our land drilling services, which accounted for $9.0 million, or 55%, of the operating division increase.March 31, 2022. The increase in our land drilling services was driven by a increase in average active rigs from four for the nine months ended September 30, 2016 to five for the nine months ended September 30, 2017 as well as a increase in average day rates from approximately $12,667 to approximately $14,433 during those same periods. Our directional drilling services accounted for $4.0 million, or 24%, of the operating division increase as a result of utilization declining from 18% for the nine months ended September 30, 2016 to 28% for the nine months ended September 30, 2017. Our rig moving services accounted for $3.7 million, or 22%, of the operating division increase primarily driven by the increase in drilling activity. Our drill pipe inspection services accounted for a decline of $0.2 million, or (1)%, of the operating division.
Other Energy Services. Other energy services division revenue increased $0.4 million, or 2%, to $23.7 million for the nine months ended September 30, 2017 from $23.3 million for the nine months ended September 30, 2016. The increase in attributable to $15.2 million of revenue from our energy infrastructure services during the nine months ended September 30, 2017. We did not not provide infrastructure services during the same period in 2016. The increase from our infrastructure services was offset by a decrease in our remote accommodation services due to a decrease in total room nights rented from 174,684 for the nine months ended September 30, 2016 to 55,007 for the nine months ended September 30, 2017 partially offset by an increase in revenue per room night, in Canadian dollars, from $176 for the nine months ended September 30, 2016 to $202 for the nine months ended September 30, 2017. The decrease in revenue from our remote accommodation services was partially offset by approximately $0.9 million of business interruption insurance proceeds we collected and recognized for the nine months ended September 30, 2017.
Cost of revenue. Cost of revenue increased $124.6 million from $125.8 million, or 76% of total revenue, for the nine months ended September 30, 2016 to $250.4 million, or 78%of total revenue, for the nine months ended September 30, 2017. Cost of revenue by operating division was as follows:
Pressure Pumping Services. Pressure pumping services division cost of revenue increased $56.6 million, or 93%, to $117.5 million for the nine months ended September 30, 2017 from $60.9 million for the nine months ended September 30, 2016. The increase was primarily due to our additional fleets, which resulted in increases in proppant costs, repairs and maintenance expense and labor-related costs. The labor-related costs increased primarily as a result of staffing our third, fourth and fifth pressure pumping fleets which came online during 2017. As a percentage of revenue, our pressure pumping services division cost of revenue was 71% and 66% for the nine months ended September 30, 2017 and 2016, respectively.
Well Services. Well services division cost of revenue increased $14.3 million, or 143%, from $10.0 million for the nine months ended September 30, 2016 to $24.3 million for the nine months ended September 30, 2017. The increase wasincome is primarily due to an increase in labor-related costs. As a percentage of revenue,activity and pricing for our well services division cost of revenue was 88% and 139% for the nine months ended September 30, 2017 and September 30, 2016, respectively. The decrease in cost of revenue as a percentage of revenue was primarily due to increases in utilization as well as pricing in our coil tubing services.completions division.
Natural Sand Proppant Services. Natural sand proppant services division cost of revenue Interest Expense, Net. Interest expense, net increased $34.9$1.0 million, or 152%43%, from $22.9to $3.3 million for the ninethree months ended September 30, 2016 to $57.8March 31, 2023 from $2.3 million for the ninethree months ended September 30, 2017,March 31, 2022. The increase is primarily due to an increase in tons sold. As a percentage of revenue, cost of revenue was 85% and 102% for the nine months ended September 30, 2017 and 2016, respectively. The decrease in cost of revenue as a percentage of revenue was primarily dueinterest rate under our revolving credit facility.
Other Income, Net. Other income decreased $0.4 million to an increase in price per ton sold.
Contract Land and Directional Drilling Services. Contract land and directional drilling services division cost of revenue increased $12.6 million, or 57%, from $22.0$8.6 million for the ninethree months ended September 30, 2016March 31, 2023 compared to $34.6$9.0 million for the ninethree months ended September 30, 2017, primarily due to an increase in labor-related costs, repairs and maintenance and increased utilization. As a percentageMarch 31, 2022.
Income Taxes. We recorded income tax expense of revenue, our contract land and directional drilling services division cost$3.3 million on pre-tax income of revenue was 94% and 108% for the nine months ended September 30, 2017 and 2016, respectively. The decrease was primarily due to higher day rates and utilization.
Other Energy Services. Other energy services division cost of revenue increased $6.2 million, or 62%, from $10.0 million the nine months ended September 30, 2016 to $16.2$11.7 million for the ninethree months ended September 30, 2017, primarily dueMarch 31, 2023 compared to costs associated with our energy infrastructure services$3.7 million on pre-tax losses of $11.8$11.1 million which were offset by decreases in costs associated with our remote accommodation services. As a percentage of revenue, cost of revenue was 69% and 43% for the ninethree months ended September 30, 2017March 31, 2022. Our effective tax rates were 29% and 2016,33% for the three months ended March 31, 2023 and 2022, respectively. The increase waseffective tax rates for the three months ended March 31, 2023 and 2022 differed from the statutory rate of 21% primarily due to the decrease in total room nights rented from 174,684 formix of earnings between the nine months ended September 30, 2016 to 55,007 for the nine months ended September 30, 2017.
Selling, GeneralUnited States and Administrative expenses. Selling, general and administrative expenses represent the costs associated with managing and supporting our operations. These expenses increased $10.5 million, or 88%, to $22.5 million for the nine months ended September 30, 2017, from $12.0 million for the nine months ended September 30, 2016. The increase in expenses was primarily attributable to a $6.5 million increase in compensation and benefits, of which $2.5 million was related to equity based compensation, and a $5.0 million increase in professional fees, of which $2.6 million was related to acquisition-related costs, partially offset by a decrease in bad debt expense of $1.1 million.
Depreciation and Amortization. Depreciation and amortization increased $9.9 million, or 18%, to $64.4 million for the nine months ended September 30, 2017 from $54.5 million for the nine months ended September 30, 2016. The increase was primarily attributable to placing in service of $162.6 million of capital additions during 2017, partially offset by $26.2 million and $14.9 million of assets that fully depreciated during 2016 and 2017, respectively.
Impairment of Long-lived Assets. The nine months ended September 30, 2016 included impairment charges of $1.9 million attributable to various fixed assetsPuerto Rico as well as changes in the amount of $0.4 million, $0.1 million and $1.4 million for the contract land and directional drilling services, pressure pumping and well service segments, respectively.valuation allowance.
Interest Expense, Net. Interest expense decreased $0.4 million, or 12%, to $2.9 million during the nine months ended September 30, 2017, from $3.3 million during the nine months ended September 30, 2016. The decrease in interest expense was attributable to a decrease in average borrowings during the nine months ended September 30, 2017.
Bargain Purchase Gain. Bargain purchase resulted in a gain of $4.0 million for the nine months ended September 30, 2017 on the purchase of Chieftain (see Note 3 of Part I of this Report).
Other (Expense) Income, Net. Non-operating (charges) income resulted in expense of $0.7 million for the nine months ended September 30, 2017, compared to other income, net of $0.4 million for the nine months ended September 30, 2016. Both periods were primarily comprised of income/loss recognition on assets disposed during the period.
Income Taxes. Prior to our initial public offering in October 2016, we were treated as a pass-through entity for federal income tax and most state income tax purposes. For the nine months ended September 30, 2017, we recognized income tax benefit of $7.3 million compared to an income tax expense of $2.7 million for the nine months ended September 30, 2016. The provision for the nine months ended September 30, 2016 was primarily attributable to our subsidiary, Lodging, which provides our remote accommodation services.
Non-GAAP Financial Measures
Adjusted EBITDA
Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income (loss) before depreciation, depletion, amortization and accretion, and amortization, impairmentgains on disposal of long-lived assets, acquisition related costs, equitystock based compensation, interest expense, net, other (income) expense,income (expense), net (which is comprised of the (gain) or lossinterest on disposal of long-lived assets), bargain purchase gaintrade accounts receivable and certain legal expenses) and provision (benefit) for income taxes.taxes, further adjusted to add back interest on trade accounts receivable. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industryindustries depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss)loss or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measuremeasures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.
The following tables also provide a reconciliation of Adjusted EBITDA to the GAAP financial measure of net income or (loss) for each of our operating segments for the specified periods.periods (in thousands).
Consolidated | | | | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, | | | | |
Reconciliation of Adjusted EBITDA to net income (loss): | 2023 | | 2022 | | | | | | |
Net income (loss) | $ | 8,351 | | | $ | (14,817) | | | | | | | |
Depreciation, depletion, amortization and accretion expense | 12,956 | | | 17,167 | | | | | | | |
Gains on disposal of assets, net | (361) | | | (196) | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Stock based compensation | 647 | | | 241 | | | | | | | |
Interest expense, net | 3,289 | | | 2,349 | | | | | | | |
Other income, net | (8,624) | | | (9,041) | | | | | | | |
Provision for income taxes | 3,333 | | | 3,688 | | | | | | | |
Interest on trade accounts receivable | 11,112 | | | 9,862 | | | | | | | |
Adjusted EBITDA | $ | 30,703 | | | $ | 9,253 | | | | | | | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, |
Reconciliation of Adjusted EBITDA to net income (loss): | 2017 | | 2016 | | 2017 | | 2016 |
Net loss | $ | (800,827 | ) | | $ | (2,978,626 | ) | | $ | (6,951,621 | ) | | $ | (34,746,932 | ) |
Depreciation, depletion, accretion and amortization expense | 27,223,733 |
| | 17,921,471 |
| | 64,354,383 |
| | 54,483,158 |
|
Impairment of long-lived assets | — |
| | — |
| | — |
| | 1,870,885 |
|
Acquisition related costs | 264,091 |
| | — |
| | 2,454,840 |
| | — |
|
Equity based compensation | 1,028,317 |
| | (18,683 | ) | | 2,648,210 |
| | (18,683 | ) |
Bargain purchase gain | — |
| | — |
| | (4,011,512 | ) | | — |
|
Interest expense | 1,420,067 |
| | 1,024,514 |
| | 2,928,859 |
| | 3,332,901 |
|
Other expense (income), net | 319,252 |
| | 253,832 |
| | 705,894 |
| | (371,894 | ) |
(Benefit) provision for income taxes | (1,412,680 | ) | | 1,055,961 |
| | (7,322,822 | ) | | 2,739,696 |
|
Adjusted EBITDA | $ | 28,041,953 |
| | $ | 17,258,469 |
| | $ | 54,806,231 |
| | $ | 27,289,131 |
|
Pressure PumpingWell Completion Services
| | | | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, | | | | |
Reconciliation of Adjusted EBITDA to net income (loss): | 2023 | | 2022 | | | | | | |
Net income (loss) | $ | 6,547 | | | $ | (7,801) | | | | | | | |
Depreciation and amortization expense | 4,817 | | | 6,444 | | | | | | | |
Gains on disposal of assets, net | — | | | (49) | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Stock based compensation | 291 | | | 87 | | | | | | | |
Interest expense | 929 | | | 371 | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Adjusted EBITDA | $ | 12,584 | | | $ | (948) | | | | | | | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended | Nine Months Ended |
| September 30, | | September 30, |
Reconciliation of Adjusted EBITDA to net income (loss): | 2017 | | 2016 | | 2017 | | 2016 |
Net income (loss) | $ | 6,482,013 |
| | $ | 4,646,485 |
| | $ | 8,922,945 |
| | $ | (624,730 | ) |
Depreciation and amortization expense | 13,038,962 |
| | 9,050,605 |
| | 31,823,408 |
| | 27,964,092 |
|
Impairment of long-lived assets | — |
| | — |
| | — |
| | 138,587 |
|
Acquisition related costs | 500 |
| | — |
| | 500 |
| | — |
|
Equity based compensation | 428,398 |
| | — |
| | 1,202,687 |
| | — |
|
Interest expense | 591,724 |
| | 134,017 |
| | 1,023,519 |
| | 502,781 |
|
Other expense, net | 120,261 |
| | 1,262 |
| | 126,650 |
| | 25,087 |
|
Adjusted EBITDA | $ | 20,661,858 |
| | $ | 13,832,369 |
| | $ | 43,099,709 |
| | $ | 28,005,817 |
|
Infrastructure Services | | | | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, | | | | |
Reconciliation of Adjusted EBITDA to net income: | 2023 | | 2022 | | | | | | |
Net income | $ | 2,452 | | | $ | 125 | | | | | | | |
Depreciation and amortization expense | 3,374 | | | 4,314 | | | | | | | |
Gains on disposal of assets | (127) | | | (5) | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Stock based compensation | 230 | | | 98 | | | | | | | |
Interest expense | 1,845 | | | 1,542 | | | | | | | |
Other income, net | (8,808) | | | (9,582) | | | | | | | |
Provision for income taxes | 2,847 | | | 3,067 | | | | | | | |
Interest on trade accounts receivable | 11,112 | | | 9,862 | | | | | | | |
Adjusted EBITDA | $ | 12,925 | | | $ | 9,421 | | | | | | | |
Other Well Services
|
| | | | | | | | | | | | | | | |
| Three Months Ended | Nine Months Ended |
| September 30, | | September 30, |
Reconciliation of Adjusted EBITDA to net income (loss): | 2017 | | 2016 | | 2017 | | 2016 |
Net (loss) income | $ | (2,148,146 | ) | | $ | (2,563,056 | ) | | $ | 384,107 |
| | $ | (9,137,921 | ) |
Depreciation and amortization expense | 4,511,622 |
| | 1,233,702 |
| | 7,939,784 |
| | 3,903,924 |
|
Impairment of long-lived assets | — |
| | — |
| | — |
| | 1,384,751 |
|
Acquisition related costs | 65,394 |
| | — |
| | 235,526 |
| | — |
|
Equity based compensation | 127,930 |
| | (18,683 | ) | | 265,380 |
| | (18,683 | ) |
Interest expense, net | 94,357 |
| | 29,489 |
| | (14,019 | ) | | 178,584 |
|
Other expense (income), net | 38,186 |
| | 1,159 |
| | 36,195 |
| | (671,986 | ) |
(Benefit) provision for income taxes | (1,278,456 | ) | | 5,929 |
| | (7,778,970 | ) | | 2,835 |
|
Adjusted EBITDA | $ | 1,410,887 |
| | $ | (1,311,460 | ) | | $ | 1,068,003 |
| | $ | (4,358,496 | ) |
Natural Sand Proppant Services | | | | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, | | | | |
Reconciliation of Adjusted EBITDA to net income (loss): | 2023 | | 2022 | | | | | | |
Net income (loss) | $ | 2,779 | | | $ | (1,315) | | | | | | | |
Depreciation, depletion, amortization and accretion expense | 1,187 | | | 1,795 | | | | | | | |
Gains on disposal of assets | (16) | | | (75) | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Stock based compensation | 77 | | | 34 | | | | | | | |
Interest expense | 156 | | | 162 | | | | | | | |
Other income, net | (2) | | | (4) | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Adjusted EBITDA | $ | 4,181 | | | $ | 597 | | | | | | | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended | Nine Months Ended |
| September 30, | | September 30, |
Reconciliation of Adjusted EBITDA to net income (loss): | 2017 | | 2016 | | 2017 | | 2016 |
Net (loss) income | $ | (929,837 | ) | | $ | (518,666 | ) | | $ | 723,370 |
| | $ | (8,086,996 | ) |
Depreciation, depletion, accretion and amortization expense | 3,034,342 |
| | 1,784,689 |
| | 6,603,001 |
| | 4,734,540 |
|
Acquisition related costs | 166,654 |
| | — |
| | 2,120,733 |
| | — |
|
Equity based compensation | 271,762 |
| | — |
| | 524,223 |
| | — |
|
Bargain purchase gain | — |
| | — |
| | (4,011,512 | ) | | — |
|
Interest expense | 86,857 |
| | 108,744 |
| | 572,096 |
| | 319,855 |
|
Other expense, net | 97,744 |
| | 9,439 |
| | 251,520 |
| | 82,422 |
|
Provision for income taxes | 23,824 |
| | 3,716 |
| | 32,326 |
| | 3,716 |
|
Adjusted EBITDA | $ | 2,751,346 |
| | $ | 1,387,922 |
| | $ | 6,815,757 |
| | $ | (2,946,463 | ) |
Contract Land and Directional Drilling Services
| | | | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, | | | | |
Reconciliation of Adjusted EBITDA to net loss: | 2023 | | 2022 | | | | | | |
Net loss | $ | (2,046) | | | $ | (1,753) | | | | | | | |
Depreciation expense | 1,367 | | | 1,680 | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Stock based compensation | 11 | | | 5 | | | | | | | |
Interest expense | 160 | | | 104 | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Adjusted EBITDA | $ | (508) | | | $ | 36 | | | | | | | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended | Nine Months Ended |
| September 30, | | September 30, |
Reconciliation of Adjusted EBITDA to net income (loss): | 2017 | | 2016 | | 2017 | | 2016 |
Net loss | $ | (4,972,767 | ) | | $ | (7,386,386 | ) | | $ | (18,289,001 | ) | | $ | (24,079,359 | ) |
Depreciation and amortization expense | 5,035,990 |
| | 5,297,694 |
| | 14,978,300 |
| | 16,243,626 |
|
Impairment of long-lived assets | — |
| | — |
| | — |
| | 347,547 |
|
Acquisition related costs | (16,328 | ) | | — |
| | 8,187 |
| | — |
|
Equity based compensation | 137,637 |
| | — |
| | 429,901 |
| | — |
|
Interest expense | 570,364 |
| | 718,706 |
| | 1,227,422 |
| | 2,272,913 |
|
Other expense, net | 38,324 |
| | 237,211 |
| | 262,560 |
| | 179,639 |
|
Adjusted EBITDA | $ | 793,220 |
| | $ | (1,132,775 | ) | | $ | (1,382,631 | ) | | $ | (5,035,634 | ) |
Other Services(a) | | | | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, | | | | |
Reconciliation of Adjusted EBITDA to net loss: | 2023 | | 2022 | | | | | | |
Net loss | $ | (1,381) | | | $ | (3,999) | | | | | | | |
Depreciation, amortization and accretion expense | 2,211 | | | 2,934 | | | | | | | |
Gains on disposal of assets, net | (218) | | | (67) | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Stock based compensation | 38 | | | 17 | | | | | | | |
Interest expense, net | 199 | | | 170 | | | | | | | |
Other expense, net | 186 | | | 545 | | | | | | | |
Provision for income taxes | 486 | | | 621 | | | | | | | |
| | | | | | | | | |
Adjusted EBITDA | $ | 1,521 | | | $ | 221 | | | | | | | |
a. Includes results for our aviation, equipment rentals, remote accommodations and equipment manufacturing and corporate related activities. Our corporate related activities do not generate revenue.
Other Energy Services
|
| | | | | | | | | | | | | | | |
| Three Months Ended | Nine Months Ended |
| September 30, | | September 30, |
Reconciliation of Adjusted EBITDA to net income (loss): | 2017 | | 2016 | | 2017 | | 2016 |
Net income | $ | 767,910 |
| | $ | 2,842,997 |
| | $ | 1,306,958 |
| | $ | 7,182,074 |
|
Depreciation and amortization expense | 1,602,817 |
| | 554,781 |
| | 3,009,890 |
| | 1,636,976 |
|
Impairment of long-lived assets | — |
| | — |
| | — |
| | — |
|
Acquisition related costs | 47,871 |
| | — |
| | 89,894 |
| | — |
|
Equity based compensation | 62,590 |
| | — |
| | 226,019 |
| | — |
|
Interest expense | 76,765 |
| | 33,558 |
| | 119,841 |
| | 58,768 |
|
Other expense, net | 24,737 |
| | 4,761 |
| | 28,969 |
| | 12,944 |
|
(Benefit) provision for income taxes | (158,048 | ) | | 1,046,316 |
| | 423,822 |
| | 2,733,145 |
|
Adjusted EBITDA | $ | 2,424,642 |
| | $ | 4,482,413 |
| | $ | 5,205,393 |
| | $ | 11,623,907 |
|
Liquidity and Capital Resources
We require capital to fund ongoing operations including maintenance expenditures on our existing fleet andof equipment, organic growth initiatives, investments and acquisitions. Since November 2014, ouracquisitions, and the litigation settlement obligations described in Note 18 “Commitments and Contingencies” of the Notes to the Unaudited Condensed Consolidated Financial Statements and under “Capital Requirements and Sources of Liquidity” below. Our primary sources of liquidity have been cash on hand, borrowings under our revolving credit facility and cash flows from operations. Our primary useuses of capital hashave been for investing in property and equipment used to provide our services and to acquire complimentarycomplementary businesses.
Liquidity
The following table summarizes our liquidity as of the dates indicated (in thousands): | | | | | | | | | | | |
| March 31, | | December 31, |
| 2023 | | 2022 |
Cash and cash equivalents | $ | 11,727 | | | $ | 17,282 | |
Revolving credit facility availability | 118,399 | | | 119,756 | |
Less current and long-term debt | (84,614) | | | (83,520) | |
Less available borrowing capacity reserve | (10,000) | | | (10,000) | |
Less letter of credit facilities (insurance programs) | (2,800) | | | (2,800) | |
Less letter of credit facilities (environmental remediation) | (3,569) | | | (3,694) | |
Net working capital (less cash and current portion of long-term debt)(a) | 343,459 | | | 325,719 | |
Total | $ | 372,602 | | | $ | 362,743 | |
a.Net working capital (less cash and current portion of long-term debt) is a non-GAAP measure and, as of March 31, 2023, is calculated by subtracting total current liabilities of $237.7 million and cash and cash equivalents of $11.7 million from total current assets of $508.3 million,
further adjusted to add current portion of long-term debt of $84.6 million. As of September 30, 2017,December 31, 2022, net working capital (less cash and current portion of long-term debt) is calculated by subtracting total current liabilities of $237.2 million and cash and cash equivalents of $17.3 million from total current assets of $496.7 million, further adjusted to add current portion of long-term debt of $83.5 million. Amounts include receivables due from PREPA of $390.2 million at March 31, 2023 and $379.0 million at December 31, 2022 and corresponding liabilities of $50.5 million at March 31, 2023 and $47.6 million at December 31, 2022.
As of April 26, 2023, we had an aggregatecash on hand of $94.0$9.5 million inand outstanding borrowings outstanding under our revolving credit facility of $76.0 million, leaving an aggregate of $69.8$26.0 million of available borrowing capacity under this facility, which is netafter giving effect to $6.4 million of outstanding letters of credit and the requirement to maintain a $10.0 million reserve out of $5.5 million.the available borrowing capacity.
The following table summarizesContinued prolonged volatility in the capital, financial and/or credit markets due to the COVID-19 pandemic, inflationary pressures or otherwise and volatility in commodity prices and/or adverse macroeconomic conditions may further limit our liquidity foraccess to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all. In addition, if we are unable to comply with the periods indicated:
|
| | | | | | | |
| September 30, | | December 31, |
| 2017 | | 2016 |
Cash and cash equivalents | $ | 14,278,328 |
| | $ | 29,238,618 |
|
Revolving credit facilities availability | 169,233,484 |
| | 164,354,373 |
|
Less long-term debt | (94,000,000 | ) | | — |
|
Less letter of credit facilities (rail car commitments) | (454,560 | ) | | (454,560 | ) |
Less letter of credit facilities (insurance programs) | (1,636,000 | ) | | (1,636,000 | ) |
Less letter of credit facilities (environmental remediation) | (3,363,627 | ) | | (1,375,342 | ) |
Net working capital (less cash) | 33,519,145 |
| | 30,453,429 |
|
Total | $ | 117,576,770 |
| | $ | 220,580,518 |
|
At November 7, 2017, we had an aggregate of $110.2 million in borrowings outstandingfinancial covenants under our amended revolving credit facility, leavingor obtain a waiver of forecasted or actual non-compliance with any such financial covenants from our lenders, and an aggregateevent of $53.2 milliondefault occurs and remains uncured, our lenders would not be required to lend any additional amounts to us, could elect to increase our interest rate by 200 basis points, could elect to declare all outstanding borrowings, together with accrued and unpaid interest and fees, to be due and payable, may have the ability to require us to apply all of our available borrowing capacity under thiscash to repay our outstanding borrowings and may foreclose on substantially all of our assets. Further, we may not be able to extend, repay or refinance our existing revolving credit facility, which is net of letters of credit of $5.5 million.currently scheduled to mature on October 19, 2023, at or prior to maturity on the terms acceptable to us or at all.
Liquidity and Cash Flows
The following table sets forth our cash flows at the dates indicated:indicated (in thousands): | | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, | | |
| 2023 | | 2022 | | | | |
Net cash provided by (used in) operating activities | $ | 3,240 | | | $ | (2,381) | | | | | |
Net cash used in investing activities | (5,706) | | | (144) | | | | | |
Net cash (used in) provided by financing activities | (3,083) | | | 736 | | | | | |
Effect of foreign exchange rate on cash | (6) | | | 8 | | | | | |
Net change in cash | $ | (5,555) | | | $ | (1,781) | | | | | |
|
| | | | | | | | | | | | | |
| Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, |
| 2017 | 2016 | | 2017 | 2016 |
Net cash provided by operating activities | $ | 16,631,835 |
| $ | 14,101,540 |
| | $ | 40,636,834 |
| $ | 23,140,617 |
|
Net cash used in investing activities | (38,134,271 | ) | (1,699,652 | ) | | (140,827,687 | ) | (708,342 | ) |
Net cash provided by (used in) financing activities | 27,222,791 |
| (10,300,000 | ) | | 85,148,937 |
| (23,000,000 | ) |
Effect of foreign exchange rate on cash | 8,683 |
| 128,280 |
| | 81,626 |
| 186,967 |
|
Net change in cash | $ | 5,729,038 |
| $ | 2,230,168 |
| | $ | (14,960,290 | ) | $ | (380,758 | ) |
Operating Activities
Net cash provided by operating activities was $40.6$3.2 million for the ninethree months ended September 30, 2017,March 31, 2023, compared to $23.1cash used in operating activities of $2.4 million for the ninethree months ended September 30, 2016.March 31, 2022. The increase in operating cash flows was primarily attributable to thean increase in revenue.utilization and pricing for our well completions division.
Net cash provided by operating activities was $16.6 million for the three months ended September 30, 2017, compared to $14.1 million for the three months ended September 30, 2016. The increase in operating cash flows was primarily attributable to timing of receivable collections with related parties.
Investing Activities
Net cash used in investing activities was $140.8 million for the nine months ended September 30, 2017, compared to $0.7 million for the nine months ended September 30, 2016. Net cash used in investing activities was $38.1$5.7 million for the three months ended September 30, 2017,March 31, 2023, compared to $1.7$0.1 million for the three months ended September 30, 2016. With the exception of the businesses acquired, substantially all cashMarch 31, 2022. Cash used in investing activities was used to purchaseis primarily comprised of purchases of property and equipment that is utilized to provide our services.and proceeds from the disposal of property and equipment.
The following table summarizes our capital expenditures by operating division for the periods indicated:indicated (in thousands): | | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, | | |
| 2023 | | 2022 | | | | |
Well completion services(a) | $ | 5,772 | | | $ | 801 | | | | | |
Infrastructure services(b) | 203 | | | 398 | | | | | |
| | | | | | | |
Drilling services(c) | — | | | 2 | | | | | |
Other(d) | — | | | 60 | | | | | |
Eliminations | 61 | | | (79) | | | | | |
Total capital expenditures | $ | 6,036 | | | $ | 1,182 | | | | | |
a. Capital expenditures primarily for upgrades to our pressure pumping fleet to reduce greenhouse gas emissions and maintenance for the three months ended March 31, 2023 and 2022. |
| | | | | | | | | | | | | | | |
| Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
Pressure pumping services (a) | $ | 19,580,804 |
| | $ | 335,312 |
| | $ | 72,982,713 |
| | $ | 1,262,854 |
|
Well services (b) | 777,399 |
| | 156,783 |
| | 1,121,873 |
| | 404,612 |
|
Natural sand proppant production (c) | 4,927,935 |
| | 359,656 |
| | 7,897,818 |
| | 522,267 |
|
Contract and directional drilling services (d) | 2,356,885 |
| | 1,069,381 |
| | 8,257,702 |
| | 1,492,476 |
|
Other energy services (e) | 8,054,748 |
| | 12,706 |
| | 12,013,384 |
| | 425,838 |
|
Net change in cash | $ | 35,697,771 |
| | $ | 1,933,838 |
| | $ | 102,273,490 |
| | $ | 4,108,047 |
|
b. Capital expenditures primarily for tooling and other equipment for the three months ended March 31, 2023 and 2022. | |
(a). | Capital expenditures primarily for pressure pumping equipment for the three and nine months ended September 30, 2017 and 2016. |
| |
(b). | Capital expenditures primarily for equipment upgrades for the three and nine months ended September 30, 2017 and 2016. |
| |
(c). | Capital expenditures included a conveyor and plant additions for the three and nine months ended September 30, 2017 and 2016. |
| |
(d). | Capital expenditures primarily for upgrades to our rig fleet for the three and nine months ended September 30, 2017 and 2016. |
| |
(e). | Capital expenditures primarily for an intersection upgrade for the nine months ended September 30, 2016. Capital expenditures for the nine months ended September 30, 2017 represent property and equipment for energy infrastructure services. |
c. Capital expenditures primarily for maintenance for the three months ended March 31, 2022.
d. Capital expenditures primarily for equipment for our rental business for the three months ended March 31, 2022.
Financing Activities
Net cash used in financing activities was $3.1 million for the three months ended March 31, 2023, compared to net cash provided by financing activities of $0.7 million for the three months ended March 31, 2022. Net cash used in financing activities for the three months ended March 31, 2023 was primarily attributable to principal payment on financing leases and equipment financing notes of $2.0 million, principal payments on sale leaseback arrangements of $1.2 million and share repurchases used to satisfy tax withholding obligations of $0.9 million in connection with the vesting and settlement of certain executive restricted stock unit awards. These were partially offset by net borrowings under our revolving credit facility of $1.1 million during the three months ended March 31, 2023. Net cash provided by financing activities was $85.1 million for the nine months ended September 30, 2017, compared to cash used in financing activities of $23.0 million for the nine months ended September 30, 2016. Net cash provided by financing activities was $27.2 million for the three months ended September 30, 2017, comparedMarch 31, 2022 was primarily attributable to cash used in financing activities of $10.3 million for the three months ended September 30, 2016. For the nine months ended September 30, 2017, cash provided by financing activities were used to fund the Chieftain, 5 Star and Higher Power Electrical, LLC acquisitions and to purchase property and equipment. For the nine months ended September 30, 2016, substantially all cash used in financing activities was used to pay down net borrowings under our revolving credit facility.facility of $2.2 million, partially offset by principal payments on financing leases and equipment financing notes totaling $1.5 million.
Effect of Foreign Exchange Rate on Cash
The effect of foreign exchange rate on cash was $0.1 million and $0.2 milliona nominal amount for the nine months ended September 30, 2017 and 2016, respectively. The effecteach of foreign rate on cash was $8.7 thousand for the three months ended September 30, 2017, compared to $0.1 million for the three months ended September 30, 2016.March 31, 2023 and 2022. The year-over-year effectchange was driven primarily by a favorable (unfavorable) shift in the weakness (strength) of the Canadian dollar relative to the U.S. dollar for the cash held in Canadian accounts.
Working Capital
Our working capital totaled $47.8$270.6 million and $59.7$259.5 million at September 30, 2017March 31, 2023 and December 31, 2016, respectively.2022, respectively, including receivables due from PREPA of $390.2 million at March 31, 2023 and $379.0 million at December 31, 2022 and corresponding liabilities of $50.5 million at March 31, 2023 and $47.6 million at December 31, 2022. Our cash balances totaled $14.3were $11.7 million and $29.2$17.3 million at September 30, 2017March 31, 2023 and December 31, 2016,2022, respectively.
Our Revolving Credit Facility
On November 25, 2014,October 19, 2018, we and certain of our direct and indirect subsidiaries, as borrowers, entered into a $170.0 millionan amended and restated revolving credit and security agreementfacility, as subsequently amended, with PNC Capital Markets LLC, as lead arranger,the lenders party thereto and PNC Bank, National Association, as a lender and as administrative agent for the administrative and collateral agent, and the lenders from time-to-time party thereto. Our revolving credit facility, as amended in connection with the IPO, matures on November 25, 2019. Borrowings under our revolving credit facility are secured by our and our subsidiaries’ assets. The maximum
availability for futurelenders. At March 31, 2023, we had outstanding borrowings under our revolving credit facility isof $84.6 million and $17.4 million of available borrowing capacity under this facility, after giving effect to $6.4 million of outstanding letters of credit and the requirement to maintain a $10.0 million reserve out of the available borrowing capacity.
On February 28, 2022, we entered into a fourth amendment to the revolving credit facility (the “Fourth Amendment”) to, in relevant part, (i) amend our financial covenants as outlined below, (ii) provide for a conditional increase of the applicable interest margin, (iii) permit certain sale-leaseback transactions, and (iv) provide for a reduction in the maximum revolving advance amount in an amount equal to 50% of the PREPA claims proceeds, subject to a borrowing base calculation prepared monthly.
Effective as of July 12, 2017, our revolving credit facility was amended, providing us with greater flexibility for permitted acquisitions and permitted indebtedness, increasing the maximum amount creditedfloor equal to the borrowing base for sand inventorysum of eligible billed and for in-transit inventory and increasing certain default thresholds from $5 million to $15 million.unbilled accounts receivables.
Interest is payable monthly at a base rate set by the lead institution’s commercial lending group plus an applicable margin. Additionally, at our request, outstanding balances are permitted to be converted to LIBOR rate plus applicable margin tranches at set increments of $500,000.
The LIBOR rate option allows us to select interest periods from one, two, three or six months. The applicable margin for either the base rate or the LIBOR rate option can vary from 1.5% to 3.0%, based upon a calculation of the excess availability of the line as a percentage of the maximum credit limit.
At September 30, 2017, $94.0 million of the total outstanding balance of $94.0 million under the facility was in a one month LIBOR rate option tranche with an interest rate of 3.99%. As of September 30, 2017, we had availability of $69.8 millionfinancial covenants under our revolving credit facility which is net of letters of credit of $5.5 million.were amended as follows:
Our revolving credit facility contains various customary affirmative
•the leverage ratio was eliminated;
•the fixed charge coverage ratio was reduced to 0.85 to 1.0 for the six months ended June 30, 2022 and restrictive covenants. Amongincreases to 1.1 to 1.0 for the covenants are two financial covenants, including periods thereafter;
•a minimum adjusted EBITDA covenant of $4.7 million, excluding interest coverage ratio (3.0on the accounts receivable from PREPA, for the five months ending May 31, 2022 was added; and
•the minimum excess availability covenant was reduced to 1.0), and a maximum leverage ratio (4.0$7.5 million through March 31, 2022, after which the minimum excess availability covenant increased to 1.0), and minimum availability ($10.0 million). As of September 30, 2017 and December 31, 2016, we$10.0 million.
We were in compliance with these covenants.the applicable financial covenants under our amended revolving credit facility in effect as of March 31, 2023. For additional information regarding our revolving credit facility, see Note 9. Debt to our unaudited condensed consolidated financial statements included elsewhere in this report.
As of April 26, 2023, our outstanding borrowings under our amended revolving credit facility were $76.0 million, leaving an aggregate of $26.0 million of available borrowing capacity, after giving effect to $6.4 million of outstanding letters of credit and the requirement to maintain a $10.0 million reserve out of the available borrowing capacity. If we fail to comply with the financial covenants contemplated by our amended revolving credit facility, or obtain a waiver of forecasted or actual non-compliance with any such financial covenants from our lenders, and an event of default occurs and remains uncured, it will have a material adverse effect on our business, financial condition, liquidity and results of operations. In addition, our revolving credit facility is currently scheduled to mature on October 19, 2023. Although we continue to explore various strategic alternatives to extend, refinance, or repay our revolving credit facility on or before the scheduled maturity date, which may include proceeds from any equity or debt transactions, there is no guarantee that such extension, refinancing or repayment will be secured. Additionally, any such extended or new credit facility could have terms that are less favorable to us than the terms of our existing revolving credit facility, which may significantly increase our cost of capital and may have a material adverse effect on our liquidity and financial condition. For additional information regarding our amended revolving credit facility and financial covenants thereunder, see Note 9. Debt to our unaudited condensed consolidated financial statements included elsewhere in this report.
Sale Leaseback Transactions
On December 30, 2020, we entered into an agreement with First National Capital, LLC, or FNC, whereby we agreed to sell certain assets from our infrastructure segment to FNC for aggregate proceeds of $5.0 million. Concurrent with the sale of assets, we entered into a 36 month lease agreement whereby we lease back the assets at a monthly rental rate of $0.1 million. On June 1, 2021, we entered into another agreement with FNC whereby we sold additional assets from our infrastructure segment to FNC for aggregate proceeds of $9.5 million and entered into a 42-month lease agreement whereby we lease back the assets at a monthly rental rate of $0.2 million. On June 1, 2022, we entered into another agreement with FNC whereby we sold additional assets from our infrastructure segment to FNC for aggregate proceeds of $4.6 million and entered into a 42-month lease agreement whereby we lease back the assets at a monthly rental rate of $0.1 million. Under the agreements, we have the option to purchase the assets at the end of the lease term. We recorded a liability for the proceeds received and will continue to depreciate the assets. We imputed an interest rate so that the carrying amount of the financial liabilities will be the expected repurchase price at the end of the initial lease terms.
Equipment Financing Note
In December 2022, we entered into a 42 month financing arrangement with FNC for the purchase of seven new pressure pumping units for an aggregate value of $9.7 million. Under this arrangement, we have agreed to make monthly principal and interest payments totaling $0.3 million over the term of the agreement. This note is secured by the seven pressure pumping units and bears interest at an imputed rate of approximately 15.0%.
Capital Requirements and Sources of Liquidity
With commodity prices beginning As we pursue our business and financial strategy, we regularly consider which capital resources are available to increase in the second half of 2016meet our future financial obligations and then stabilizing within their current range, we have seen an increase in customer demand, particularly in our pressure pumping and natural sand proppant services divisions. Our capital budget for 2017 increased substantially from our 2016 capital budget of approximately $11.3 million. Our expected 2017 full-year capital budget currently includes expenditures of $64.0 million in our pressure pumping services division for the acquisition of 132,500 horsepower of new high pressure hydraulic pumps and related equipment, $8.0 million in our pressure pumping service division for tractors, pneumatic trailers to enhance our last mile solutions, $25.0 million in our sand segment for plant capacity expansion projects, and $33.0 million for rig upgrades and additional equipment for our well services, contract and direction drilling services and other energy services divisions. During the first nine months ended September 30, 2017, we spent approximately $102.3 million on such capital expenditures, including $35.7 million during the third quarter of 2017, and an additional $42.0 million to complete business acquisitions. Due to the anticipated 120-day duration of the initial work to be performed under the contract signed by Cobra to aid in the restoration of the electric utility infrastructure in Puerto Rico, we intend to lease a majority of the equipment required to fulfill the contract. As a result, we do not anticipate a material increase in our announced $143.0 million capital expenditure budget for 2017.
liquidity requirement. We believe that our cash on hand, operating cash flow and available borrowings under our revolving credit facility will be sufficient to fundmeet our short-term and long-term funding requirements, including funding our current operations, for at least the next twelve months. However,planned capital expenditures, debt service obligations and known contingencies.
Our liquidity and future cash flows, however, are subject to a number of variables, including receipt of payments from our customers, including PREPA, and our ability to extend, refinance or repay our revolving credit facility at or prior to its scheduled maturity date of October 19, 2023. As of March 31, 2023, PREPA owed Cobra approximately $390.2 million for services performed, including $163.2 million of interest charges. Throughout 2021, we released significant additionaldata that we obtained through Freedom of Information Act requests that affirm the work performed by Cobra in Puerto Rico. We believe these documents in conjunction with the current Administration’s focus on the recovery of Puerto Rico and our enhanced lobbying efforts will aid in collecting the outstanding amounts owed to us by PREPA. However, in the event PREPA (i) does not have or does not obtain the funds necessary to satisfy its obligations to Cobra under the contracts, (ii) obtains the necessary funds but refuses to pay the amounts owed to Cobra or (iii) otherwise does not pay amounts owed to Cobra for services performed, the receivable may not be collectible, which may adversely impact our liquidity.
We have revised our 2023 capital expenditure estimate down to approximately $24.0 million from the previously planned 2023 capital budget of $64 million primarily due to lower commodity prices, softer demand for oilfield services and volatility in market conditions. During the first quarter of 2023, pricing for crude oil and natural gas declined from levels seen in 2022, which may slow down completion activities for our customers and, as a result, reduce demand for our oilfield services. Capital expenditures will ultimately be dependent upon industry conditions and our financial results.These capital expenditures could be requiredinclude $21 million for our well completions segment, $1 million for our infrastructure segment, $1 million for our natural sand proppant segment, and $1 million for our other businesses. During the three months ended March 31, 2023, our capital expenditures totaled $6.0 million.
Also, as noted above in this report, in response to conductmarket conditions we have (i) temporarily shut down certain of our oilfield service offerings, including coil tubing, pressure control, flowback, crude oil hauling, cementing, acidizing and land drilling services, (ii) idled certain facilities, including our sand processing plant in Pierce County, Wisconsin and (iii) reduced our workforce across all of our operations. There can be no assurance thatWe continue to monitor market conditions to determine if and when we will recommence these services and operations and other capital resourcesincrease our workforce. Any such recommencement and expansion will provide cashfurther increase our liquidity requirements in sufficient amounts to maintain planned or future levelsadvance of capital expenditures. Further,revenue generation.
In addition, while we continue to pursue our previously announced acquisition strategy to enhance our portfolio of products and services, market positioning and/or geographic presence. We regularly evaluate acquisition opportunities, and the number of opportunities coming to our attention has increased substantially since the IPO. However, we do not have a specific acquisition budget for 2017 since2023. We intend to continue to evaluate acquisition opportunities, including those in the timing and size of acquisitions cannot be accurately forecasted.renewable energy sector as well as transactions involving entities controlled by Wexford. Our acquisitions may be undertaken with cash, our common stock or a combination of cash, common stock and/or other consideration. In the event we make one or more additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital.
If we seek additional capital for thatany of the above or other reasons, we may do so through borrowings under oura revolving credit facility, joint venture partnerships, sale-leaseback transactions, asset sales, offerings of debt or equity securities or other means. WeAlthough we expect that our sources of capital will be adequate to fund our short-term and long-term liquidity requirements, we cannot assure you that this additional capital will be available on acceptable terms or at all. If we are unable to obtain funds we need, we may not be ableour ability to conduct operations, make capital expenditures, satisfy debt services obligations, pay litigation settlement obligations, fund contingencies and/or complete acquisitions that may be favorable to us or finance the capital expenditures necessary to conduct our operations.
Off-Balance Sheet Arrangements
Lease Obligations
We lease real estate, rail cars and other equipment under long-term operating leases with varying terms and expiration dates through 2025.
Minimum Purchase Commitments
Wewill be impaired, which would have entered into agreements with sand suppliers that contain minimum purchase obligations. Our failure to purchase the minimum tonnage specified would require us to pay shortfall fees. However, the minimum quantities set forth in the agreements are not in excess of our current expected future requirements.
Capital Spend Commitments
We have entered into agreements with suppliers to acquire capital equipment. These commitments are included in our 2017 capital budget discussed under the heading "Capital Requirements and Sources of Liquidity."
Aggregate future minimum lease payments under these agreements in effect at September 30, 2017 are as follows:
|
| | | | | | | | | | | | |
Year ended December 31: | | Operating Leases | | Capital Spend Commitments | | Minimum Purchase Commitments |
Remainder of 2017 | | $ | 3,377,429 |
| | $ | 26,847,278 |
| | $ | 3,556,655 |
|
2018 | | 13,047,020 |
| | — |
| | 10,866,000 |
|
2019 | | 10,533,906 |
| | — |
| | 10,866,000 |
|
2020 | | 8,085,194 |
| | — |
| | — |
|
2021 | | 5,744,808 |
| | — |
| | — |
|
Thereafter | | 6,189,124 |
| | — |
| | — |
|
| | $ | 46,977,481 |
| | $ | 26,847,278 |
| | $ | 25,288,655 |
|
Other Commitments
Subsequent to September 30, 2017, we entered into railcar lease agreements with aggregate commitments of $2.2 million.
Subsequent to September 30, 2017, we entered into a lease agreement for capital equipment with aggregate commitments of $3.4 million.
Subsequent to September 30, 2017, we entered into an agreement to purchase sand from an unrelated third party seller with aggregate commitments of $2.2 million.
On October 19, 2017, Cobra entered into a contract to aid in the restoration of utility infrastructure on the island of Puerto Rico. The contract provides for payments of up to $200.0 million, including an initial payment of $15.0 million at the time of signing. As of November 7, 2017, Cobra had entered into $32.7 million of commitments related to this contract and made prepayments and deposits of $12.6 million with respect to these commitments.
New Accounting Pronouncements
In July 2015, the FASB issued ASU No. 2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory,” which changes inventory measured using any method other than last-in, first-out (LIFO) or the retail inventory method (for example, inventory measured using first-in, first-out (FIFO) or average cost) at the lower of cost and net realizable value. ASU 2015-11 is effective for annual and interim reporting periods beginning after December 15, 2016, with early adoption permitted. On January 1, 2017, we adopted the ASU and it did not impact our condensed consolidated financial statements.
In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers.” ASU 2014-09 supersedes existing revenue recognition requirements in GAAP and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. Additionally, it requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. The ASU was effective for annual and interim reporting periods beginning after December 15, 2016, using either a full or a modified retrospective application approach; however, in July 2015 the FASB decided to defer the effective date by one year (until 2018) by issuing ASU No. 2015-14, "Revenue From Contracts with Customers: Deferral of the Effective Date." We expect to adopt this new revenue guidance in the first quarter of 2018. Our review has indicated that the pressure pumping services and natural sand proppant segments contain contracts which could lead to changes in the timing of revenue recognition. Although we have not completed our review, we have made initial assessments of the impact on revenue and expenses. Based on these assessments, we currently do not expect a material impact to theadverse effect on our business, financial condition, results of operations financial position and cash flowsas a result of this guidance. We expect to complete our review of all remaining customer contracts and will make a final assessment in the fourth quarter of 2017. Our services are primarily short-term in nature, and we do not expect that the new revenue recognition standard will have a material impact on our financial statements upon adoption. We will adopt the new standard utilizing the modified retrospective method that will result in a cumulative effect adjustment as of January 1, 2018.flows.
In February 2016, the FASB issued ASU No, 2016-2 “Leases” amending the current accounting for leases. Under the new provisions, all lessees will report a right-of-use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less. All other leases will fall into one of two categories: (i) a financing lease or (ii) an operating lease. Lessor accounting remains substantially unchanged with the exception that no leases entered into after the effective date will be classified as leveraged leases. For sale leaseback transactions, a sale will only be recognized if the criteria in the new revenue recognition standard are met. ASU 2016-2 is effective for fiscal years beginning after December 15, 2018, and interim periods within that fiscal year. Early adoption is permitted. Since a portion of our revenue may be subject to this new leasing guidance, we are evaluating the possibility of adopting this updated leasing guidance at the same time we adopt the new revenue standard discussed above, utilizing the retrospective method of adoption. This new leasing guidance will also impact us in situations where we are the lessee, and in certain circumstances we will have a right-of-use asset and lease liability on our consolidated financial statements. We are currently evaluating the effect the new guidance will have on our consolidated financial statements and results of operations.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The demand, pricing and terms for oilour products and gas services provided by us are largely dependent upon the level of activity for the U.S. oil and natural gas industry, energy infrastructure industry and natural sand proppant industry. Industry conditions are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and natural gas;gas services, energy infrastructure services and natural sand proppant; demand for repair and construction of transmission lines, substations and distribution networks in the energy infrastructure industry and the level of expenditures of utility companies; the level of prices of, and expectations about future prices offor, oil and natural gas;gas and natural sand proppant, as well as energy infrastructure services; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves; availablereserves and frac sand reserves meeting industry specifications and consisting of the mesh size in demand; access to pipeline, transloading and other transportation facilities and their capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of oil and natural gas producers and other users of our services to raise equity capital and debt financing; and merger and divestiture activity amongin industries in which we operate.
In March and April 2020, concurrent with the COVID-19 pandemic and quarantine orders in the U.S. and worldwide, oil prices dropped sharply to below zero dollars per barrel for the first time in history due to factors including significantly reduced demand and a shortage of storage facilities. In 2021, U.S. oil production stabilized as commodity prices increased and demand for crude oil rebounded, many exploration and production companies set their operating budgets based on the prevailing prices for oil and natural gas producers.at the time. Despite improvement in the U.S. and global economic activity, easing of the COVID-19 pandemic and related restrictions, rising energy use and improved commodity prices, the budgets for the publicly traded exploration and production companies remained relatively flat throughout 2021, with any excess cash flows used for debt repayment and shareholder returns, rather than to increase production. We saw improvements in the oilfield services industry and in both pricing and utilization of our well completion and drilling services throughout 2022. During the first quarter of 2023, pricing for crude oil and natural gas declined from levels seen in 2022, which may slow down completion activities for our customers and, as a result, reduce demand for our well completion services. Further, the ongoing war and related humanitarian crisis in Ukraine could continue to have an adverse effect on the global supply chain and volatility of commodity prices.
The levelAlthough the levels of activity in the U.S. oil and natural gas exploration and production, industry is volatile. Expected trends in oilenergy infrastructure and natural gas production activities may notsand proppant industries improved throughout 2022, they have historically been and continue and demandto be volatile. We are unable to predict the ultimate impact of the COVID-19 pandemic, the volatility in commodity prices, any changes in the near-term or long-term outlook for our services may not reflect the level of activity in the industry. Any prolonged substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and therefore affect demand for our services. A material decline in oil and natural gas pricesindustries or U.S. activity levels could have a material adverse effectoverall macroeconomic conditions on our business, financial condition, results of operations, cash flows and cash flows. Recently, demand for our services has been strong and we are continuing our past practice of committing our equipment on a short-term or day-to-day basis.stock price.
Interest Rate Risk
We had a cash and cash equivalents balance of $14.3$11.7 million at September 30, 2017.March 31, 2023. We do not enter into investments for trading or speculative purposes. We do not believe that we have any material exposure
Interest under our credit facility is payable at a base rate, which can fluctuate based on multiple facts, including rates set by the U.S. Federal Reserve (which increased its benchmark interest rate by an aggregate of 4.75 percentage points throughout 2022 and 2023, and may continue to changes in the fair value of these investments as a result of changes in interest rates. Declines inincrease interest rates however, will reduce future income.
in an effort to counter the persistent inflation), the supply and demand for credit and general economic conditions, plus an applicable margin. The applicable margin is currently set at 4.0%, which can be reduced to 3.5% under certain circumstances specified in our credit facility. At September 30, 2017,March 31, 2023, we had $94.0outstanding borrowings under our revolving credit facility of $84.6 million outstanding under this facility with a weighted average interest rate of 3.99%11.5%. A 1% increase or decrease in the interest rate at that time would have increasedincrease or decreaseddecrease our interest expense by approximately $0.9$0.8 million per year. We do not currently hedge our interest rate exposure.
Foreign Currency Risk
Our remote accommodation business, which is included in our other energy services segment,division, generates revenue and incurs expenses that are denominated in the Canadian dollar. These transactions could be materially affected by currency fluctuations. Changes in currency exchange rates could adversely affect our consolidated results of operations or financial position. We also maintain cash balances denominated in the Canadian dollar. At September 30, 2017,March 31, 2023, we had $3.0$2.4 million of cash, in Canadian dollars, in Canadian accounts. A 10% increase in the strength of the Canadian dollar versus the U.S. dollar would have resulted in an increase in pre-tax income of approximately $0.2$0.1 million as of September 30, 2017.March 31, 2023. Conversely, a corresponding decrease in
the strength of the Canadian dollar would have resulted in a comparable decrease in pre-tax income. We have not hedged our exposure to changes in foreign currency exchange rates and, as a result, could incur unanticipated translation gains and losses.
Customer Credit Risk
We are also subject to credit risk due to concentration of our receivables from several significant customers. We generally do not require our customers to post collateral. The inability, delay or failure of our customers to meet their obligations to us due to customer liquidity issues or their insolvency or liquidation may adversely affect our business, financial condition, results of operations and cash flows. This risk may be further enhanced by the COVID-19 pandemic, the volatility in commodity prices, the reduction in demand for our services and challenging macroeconomic conditions.
Specifically, we had receivables due from PREPA totaling $390.2 million, including $163.2 million of interest charges, as of March 31, 2023. PREPA is currently subject to bankruptcy proceedings pending in the U.S. District Court for the District of Puerto Rico. As a result, PREPA’s ability to meet its payment obligations under the contracts is largely dependent upon funding from the FEMA or other sources. See Note 2. Basis of Presentation and Significant Accounting Policies—Accounts Receivable and —Concentrations of Credit Risk and Significant Customers and Note 18. Commitments and Contingencies—Litigation of our unaudited condensed consolidated financial statements.
Seasonality
We provide infrastructure services in the northeastern, southwestern, midwestern and western portions of the United States. We provide well completion and productiondrilling services primarily in the Utica, Permian Basin, Eagle Ford, Marcellus, SCOOP, STACK, Granite Wash, Cana Woodford and Cleveland sand resource plays located in the continental U.S. We also provide remote accommodation services in the oil sands in Alberta, Canada. We serve these markets through our facilities and service centers that are strategically located to serve resource playsour customers in Ohio, Texas, Oklahoma, Wisconsin, Minnesota,Kentucky, Colorado, California, Indiana and Alberta, Canada. For the nine months ended September 30, 2017 and 2016, we generated approximately 81% and 85%, respectively,A portion of our revenue from our operationsrevenues are generated in Ohio, Wisconsin, Minnesota, Pennsylvania, West Virginia and Canada where weather conditions may be severe. As a result, our operations may be limited or disrupted, particularly during winter and spring months, in these geographic regions, which would have a material adverse effect on our financial condition and results of operations. Our operations in Oklahoma and Texas are generally not affected by seasonal weather conditions.
Inflation
Although the impact of inflation has been insignificant on our operations in prior years, inflation in the U.S. has been at some of the highest levels in over 40 years, creating inflationary pressure on the cost of services, equipment and other goods in our industries and other sectors and contributing to labor and materials shortages across the supply-chain. Throughout 2022 and early 2023, the Federal Reserve increased its benchmark interest rates by an aggregate of 4.75 percentage points, and may continue increasing benchmark interest rates in the future. If the efforts to control inflation are not successful and inflationary pressures persist, our business, results of operations and financial condition may be adversely affected.
Item 4. Controls and Procedures
Evaluation of Disclosure Control and Procedures
Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and d15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.
As of September 30, 2017,March 31, 2023, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief
Executive Officer and Chief Financial Officer have concluded that as of September 30, 2017,March 31, 2023, our disclosure controls and procedures are effective.
Changes in Internal Control Over Financial Reporting
There was no change in our internal control over financial reporting (as defined in Rules 13a-15(d) and 15d-15(d) under the Exchange Act) that occurred during the quarter ended September 30, 2017March 31, 2023 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
We are routinely involved in state and local tax audits. During 2015, the State of Ohio assessed taxes on the purchase of equipment we believe is exempt under state law. We have appealed the assessment and a hearing was scheduled for November 30, 2016. In November 2016, the State of Ohio deferred the hearing until April 2017. While we are not able to predict the outcome of the appeal, this matter is not expected to have a material adverse effect on our financial position or results of operations.
Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including breaches of contractual obligations, workers’ compensation claims, and employment related disputes.disputes, arbitrations, class actions and other litigation. We are also involved, from time to time, in reviews, investigations, subpoenas and other proceedings (both formal and informal) by governmental agencies regarding our business (collectively, “regulatory matters”), which regulatory matters, if determined adversely to us, could subject us to significant fines, penalties, obligations to change our business practices or other requirements resulting in increased expenses, diminished income and damage to our reputation. In the opinion of our management, none of the pending litigation, disputes or claims against us if decided adversely, willis expected to have a material adverse effect on our financial condition, cash flows or results of operations.operations, except as disclosed in Note 18 “Commitments and Contingencies,” of the Notes to Unaudited Condensed Consolidated Financial Statements.
See Part I, Item 1. Note 13 of this Report.
Item 1A. Risk Factors
Security holdersAs of the date of this filing, our Company and potential investors in our securities should carefully consideroperations continue to be subject to the risk factors set forth below andpreviously disclosed in Item 1A. Risk Factors in our Annual Report on Form 10-K (Commission File No. 001-37917) filed with the SEC on February 24, 2017, together with the information set forth in our subsequent Quarterly Reports on Form 10-Q, current reports on Form 8-K and other materials we file with the SEC.
Other than set forth below, there have been no material changes to the Risk Factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016 or our subsequent quarterly reports on Form 10-Q.
One of our energy services subsidiaries recently entered into2023. For a contract with the Puerto Rico Electric Power Authority, or PREPA, which provides for payments to us of up to $200.0 million. PREPA is currently subject to pending bankruptcy proceeding. In the event that PREPA does not have or does not obtain the funds necessary to satisfy its payment obligations to our subsidiary under the contract or terminates the contract prior to the enddiscussion of the contract term,recent trends and uncertainties impacting our financial condition, resultsbusiness, see also “Management’s Discussion and Analysis of operationsFinancial Condition and cash flows could be materiallyResults of Operations—Recent Developments—Overview of Our Services and adversely affected.Industry Conditions”
On October 19, 2017, our energy services subsidiary Cobra Acquisitions LLC, or Cobra, and PREPA entered into an energy master services agreement for repairs to PREPA's electrical grid as a result of Hurricane Maria. The one-year contract provides for payments of up to $200.0 million, including an initial payment of $15.0 million. As of November 7, 2017, Cobra had entered into $32.7 million of commitments related to this contract and made prepayments and deposits of $12.6 million with respect to these commitments. PREPA is currently subject to bankruptcy proceedings pending in the U.S. District Court for the District of Puerto Rico. As a result, PREPA's ability to meet its payment obligations under the contract will be largely dependent upon funding from the Federal Emergency Management Agency, or FEMA, or other sources. PREPA's contracting practices in connection with restoration and repair of PREPA's electrical grid in Puerto Rico, and the terms of certain of those contracts, have been subject to critical comment and are the subject of review and hearings by U.S. federal and Puerto Rican governmental entities. Recently, a contract for restoration and repair services entered into by PREPA with an unrelated third party was terminated by PREPA. In the event that PREPA does not have or does not obtain the funds necessary to satisfy its obligations to Cobra under the contract or terminates the contract prior to the end of the contract term, our financial condition, results of operations and cash flows could be materially and adversely affected.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
On June 5, 2017, we issued an aggregateUnregistered Sales of 7.0 millionEquity Securities
None.
Issuer Repurchases of Equity Securities
Our common stock repurchase activity for the three months ended March 31, 2023 was as follows:
| | | | | | | | | | | | | | | | | | | | |
Period | | Total number of shares repurchased(a) | | Average price paid per share | | Total number of shares purchased as part of publicly announced plans or programs |
January | | — | | | $ | — | | | — | |
February | | — | | | $ | — | | | — | |
March | | 165,595 | | | $ | 5.55 | | | — | |
Total | | 165,595 | | | $ | 5.55 | | | — | |
a.Represents 165,595 shares of our common stock repurchased from the Company’s executive officers in order to the contributors under the Contribution Agreements as consideration for all outstanding membership interests in Sturgeon, Stingray Energy and Stingray Cementing acquired. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations —— Second Quarter 2017 Highlights.” These shares of our common stock were issued in reliancesatisfy tax withholding requirements upon the exemption from the registration requirementsvesting and settlement of the Securities Act provided by Section 4(2)certain of the Securities Act as sales by an issuer not involving any public offeringtheir restricted stock unit awards. Such shares are cancelled and retired immediately upon repurchase.
Item 4. Mine Safety Disclosures
Our operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures, operating equipment and other matters. Our failure to comply with such standards, or changes in such standards or the interpretation or enforcement thereof, could have a material adverse effect on our business and financial condition or otherwise impose significant restrictions on our ability to conduct mineral extraction and processing operations. Following passage of The Mine Improvement and New Emergency Response Act of 2006, MSHA significantly increased the numbers of citations and orders charged against mining operations. The dollar penalties assessed for citations issued has also increased in recent years. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this Report.
Item 5. Other Information
Not applicable.
MAMMOTH ENERGY SERVICES, INC.
Item 6. Exhibits
The following exhibits are filed as a part of this report: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Incorporated By Reference | | | |
Exhibit Number | | Exhibit Description | | Form | | Commission File No. | | Filing Date | | Exhibit No. | | Filed Herewith | Furnished Herewith |
| | | | 8-K | | 001-37917 | | 11/15/2016 | | 3.1 | | | |
| | | | 8-K | | 001-37917 | | 11/15/2016 | | 3.2 | | | |
| | | | 8-K | | 001-37917 | | 6/9/2020 | | 3.1 | | | |
| | | | S-1/A | | 333-213504 | | 10/3/2016 | | 4.1 | | | |
| | | | 8-K | | 001-37917 | | 11/15/2016 | | 4.1 | | | |
| | | | | | | | | | | | X | |
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101.INS | | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | | | | | | | | | | X | |
101.SCH | | XBRL Taxonomy Extension Schema Document. | | | | | | | | | | X | |
101.CAL | | XBRL Taxonomy Extension Calculation Linkbase Document. | | | | | | | | | | X | |
101.DEF | | XBRL Taxonomy Extension Definition Linkbase Document. | | | | | | | | | | X | |
101.LAB | | XBRL Taxonomy Extension Labels Linkbase Document. | | | | | | | | | | X | |
101.PRE | | XBRL Taxonomy Extension Presentation Linkbase Document. | | | | | | | | | | X | |
104 | | Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | | | | | | | | | | X | |
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| | | | Incorporated By Reference | | | |
Exhibit Number | | Exhibit Description | | Form | | Commission File No. | | Filing Date | | Exhibit No. | | Filed Herewith | Furnished Herewith |
2.1# | | Amended and Restated Contribution Agreement by and among MEH Sub LLC, Gulfport Energy Corporation, Rhino Exploration LLC, Mammoth Energy Partners LLC and Mammoth Energy Services, Inc. dated as of May 12, 2017 | | DEF 14C | | 001-37917 | | 5/15/2017 | | A-1 | | | |
2.2# | | Amended and Restated Contribution Agreement by and among MEH Sub LLC, Gulfport Energy Corporation, Mammoth Energy Partners LLC and Mammoth Energy Services, Inc. dated as of May 12, 2017 | | DEF 14C | | 001-37917 | | 5/15/2017 | | A-2 | | | |
2.3# | | Amended and Restated Contribution Agreement by and among MEH Sub LLC, Gulfport Energy Corporation, Mammoth Energy Partners LLC and Mammoth Energy Services, Inc. dated as of May 12, 2017 | | DEF 14C | | 001-37917 | | 5/15/2017 | | A-3 | | | |
3.1 | | Amended and Restated Certificate of Incorporation of the Company | | 8-K | | 001-37917 | | 11/15/2016 | | 3.1 | | | |
3.2 | | Amended and Restated Bylaws of the Company | | 8-K | | 001-37917 | | 11/15/2016 | | 3.2 | | | |
4.1 | | Specimen Certificate for shares of common stock, par value $0.01 per share, of the Company | | S-1/A | | 333-213504 | | 10/3/2016 | | 4.1 | | | |
4.2 | | Registration Rights Agreement, dated October 12, 2016, by and between the Company and Mammoth Energy Holdings, LLC | | 8-K | | 001-37917 | | 11/15/2016 | | 4.1 | | | |
4.3 | | Investor Rights Agreement, dated October 12, 2016, by and between the Company and Gulfport Energy Corporation | | 8-K | | 001-37917 | | 11/15/2016 | | 4.2 | | | |
4.4 | | Registration Rights Agreement, dated October 12, 2016, by and between the Company and Rhino Exploration LLC | | 8-K | | 001-37917 | | 11/15/2016 | | 4.3 | | | |
10.1 | | Second Amendment to Revolving Credit and Security Agreement, dated as of July 12, 2017 among Mammoth Energy Services, Inc. and its subsidiaries. | | | | | | | | | | X | |
| | Emergency Master Service Agreement for PREPA’s Electrical Grid Repairs-Hurricane Maria, executed on October 19, 2017, by the Puerto Rico Electric Power Authority (PREPA) and Cobra Acquisitions LLC. | | | | | | | | | | X | |
| | Amendment No. 1 to Emergency Master Service Agreement for PREPA’s Electrical Grid Repairs-Hurricane Maria, executed on November 1, 2017, by the Puerto Rico Electric Power Authority (PREPA) and Cobra Acquisitions LLC. | | | | | | | | | | X | |
| | Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934. | | | | | | | | | | X | |
| | Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934. | | | | | | | | | | X | |
| | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | | | | | | | | | | X | |
| | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | | | | | | | | | | X | |
| | Mine Safety Disclosure Exhibit | | | | | | | | | | X | |
101.1 | | Interactive data files pursuant to Rule 405 of Regulation S-T. | | | | | | | | | | | |
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# | The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission. |
MAMMOTH ENERGY SERVICES, INC.
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.
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| | | | | MAMMOTH ENERGY SERVICES, INC. |
Date: | April 28, 2023 | | By: | | /s/ Arty Straehla |
| | | | | Arty Straehla |
| | | | | Chief Executive Officer |
| | | | | |
Date: | April 28, 2023 | | By: | | MAMMOTH ENERGY SERVICES, INC. |
Date: | November 13, 2017 | | By: | | /s/ Arty Straehla |
| | | | | Arty Straehla |
| | | | | Chief Executive Officer |
| | | | | |
Date: | November 13, 2017 | | By: | | /s/ Mark Layton |
| | | | | Mark Layton |
| | | | | Chief Financial Officer |
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