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Select Energy Services, Inc. Consolidated Financial Statements December 31, 2016 and 2015
As filed with the Securities and Exchange Commission on March 2, 2017
Registration No. 333-
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
Select Energy Services, Inc.
(Exact name of registrant as specified in its charter)
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Delaware
(State or other jurisdiction of incorporation or organization) |
1389
(Primary Standard Industrial Classification Code Number) |
81-4561945
(IRS Employer Identification No.) |
1820 North I-35, P.O. Box 1715
Gainesville, Texas 76241
(940) 668-0259
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)
John D. Schmitz
1820 North I-35, P.O. Box 1715
Gainesville, Texas 76241
(940) 668-0259
(Name, address, including zip code, and telephone number, including area code, of agent for service)
| Copies to: | ||
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David P. Oelman Alan Beck Vinson & Elkins L.L.P. 1001 Fannin, Suite 2500 Houston, Texas 77002 (713) 758-2222 |
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Hillary H. Holmes Baker Botts L.L.P. One Shell Plaza 910 Louisiana Street Houston, Texas 77002 (713) 229-1234 |
Approximate date of commencement of proposed sale of the securities to the public:
As soon as practicable after the effective date of this Registration Statement.
If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box: o
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
| Large accelerated filer o | Accelerated filer o |
Non-accelerated filer
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(Do not check if a smaller reporting company) |
Smaller reporting company o |
CALCULATION OF REGISTRATION FEE
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Title of Each Class of Securities
to be Registered |
Proposed Maximum
Aggregate Offering Price(1)(2) |
Amount of
Registration Fee(3) |
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Class A common stock, par value $0.01 per share |
$100,000,000 | $11,590 | ||
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- (1)
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Includes
shares issuable upon exercise of the underwriters' option to purchase additional shares of Class A common stock.
- (2)
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Estimated
solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.
- (3)
- Calculated pursuant to Rule 457(o) under the Securities Act.
The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state or jurisdiction where the offer or sale is not permitted.
PRELIMINARY PROSPECTUS
(Subject to completion, dated , 2017)
Shares
Select Energy Services, Inc.
CLASS A COMMON STOCK
This is the initial public offering of the Class A common stock of Select Energy Services, Inc., a Delaware corporation. We are offering shares of our Class A common stock and the selling shareholders are selling shares of Class A common stock. We will not receive any proceeds from the sale of shares by the selling shareholders. No public market currently exists for our Class A common stock. We are an "emerging growth company" as that term is used in the Jumpstart Our Business Startups Act of 2012, and as such, we have elected to take advantage of certain reduced public company reporting requirements for this prospectus and future filings. Please see "Risk Factors" and "Summary—Emerging Growth Company Status."
We intend to apply to list our Class A common stock on the New York Stock Exchange under the symbol "WTTR."
We anticipate that the initial public offering price of our Class A common stock will be between $ and $ per share.
Investing in our Class A common stock involves risks. Please see "Risk Factors" beginning on page 22 of this prospectus.
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Per share
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Total
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Price to public |
$ | $ | ||
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Underwriting discounts and commissions(1) |
$ | $ | ||
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Proceeds to Select Energy Services, Inc. (before expenses) |
$ | $ | ||
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- (1)
- We refer you to "Underwriting" beginning on page 147 of this prospectus for additional information regarding underwriting compensation.
We have granted the underwriters an option for a period of 30 days to purchase up to additional shares of Class A common stock on the same terms and conditions set forth above if the underwriters sell more than shares of Class A common stock in this offering.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed on the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
The underwriters expect to deliver the shares on or about , 2017.
| Credit Suisse | FBR | Wells Fargo Securities |
| BofA Merrill Lynch | Citigroup | J.P. Morgan |
| Deutsche Bank Securities | RBC Capital Markets | |
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Simmons & Company International, Energy Specialists of Piper Jaffray |
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Tudor, Pickering, Holt & Co. |
Prospectus dated , 2017.
You should rely only on the information contained in this prospectus or in any free writing prospectus prepared by us or on behalf of us or to which we have referred you. Neither we, the selling shareholders nor underwriters have authorized any other person to provide you with information different from that contained in this prospectus and any free writing prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. Neither we, the selling shareholders nor the underwriters are making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of our Class A common stock. Our business, financial condition, results of operations and prospects may have changed since that date.
This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read "Risk Factors" and "Forward-Looking Statements."
We use market data and industry forecasts throughout this prospectus, and in particular in the sections entitled "Summary," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business." Market data used in this prospectus has been obtained from publicly available information and publications as well as our good faith estimates. The industry data sourced from The Freedonia Group is from its "Industry Study #3352: Oilfield Chemicals" report published in November of 2015. The industry data sourced from Spears & Associates is generally from its "Drilling and Production Outlook" report published in September of 2016 as well as its "Hydraulic Fracturing Market Report" published in the third quarter of 2016 and other supporting materials. We
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believe that these third-party sources are reliable. We believe that the information contained therein has been obtained from sources believed to be reliable. However, we have not independently verified the data obtained from these sources. Forecasts and other forward-looking information obtained from these sources are subject to the same qualifications and uncertainties that apply to the other forward-looking statements that are described in this prospectus. In addition, while we are not aware of any misstatements regarding the market or industry data presented herein, such statements involve risks and uncertainties and are subject to change based on various factors, including those discussed under the heading "Risk Factors."
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This summary highlights selected information contained elsewhere in this prospectus, but it does not contain all of the information that you may consider important in making your investment decision. Before deciding to invest in our Class A common stock, you should carefully read the entire prospectus, including in particular, "Risk Factors," "Forward-Looking Statements" "Management's Discussion and Analysis of Financial Condition and Results of Operation" and the consolidated financial statements and related notes included elsewhere in this prospectus. The following summary is qualified in its entirety by the more detailed information and financial statements and notes thereto included elsewhere in this prospectus.
The information presented in this prospectus assumes an initial public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus). In this prospectus, unless the context otherwise requires, references to the "Company," "we," "our," "us" or similar terms refer (1) prior to the consummation of the transactions described under "Organizational Structure" to Select Energy Services, LLC, or Select LLC, and SES Holdings, LLC, or SES Holdings, and their consolidated subsidiaries, and (2) after the transactions described under "Organizational Structure," to Select Energy Services, Inc., or Select Inc., and its consolidated subsidiaries.
Except as otherwise indicated, all information contained in this prospectus assumes that the underwriters do not exercise their option to purchase additional shares of Class A common stock and excludes Class A common stock reserved for issuance under our equity incentive plan.
We are a leading provider of total water solutions to the U.S. unconventional oil and gas industry. Within the major shale plays in the United States, we believe we are a market leader in sourcing and transfer of water (both by permanent pipeline and temporary pipe) prior to its use in drilling and completion activities associated with hydraulic fracturing or "fracking," which we collectively refer to as "pre-frac water services." In most of our areas of operations, we provide complementary water-related services that support oil and gas well completion and production activities including containment, monitoring, treatment, flowback, hauling and disposal. Our services are necessary to establish and maintain production of oil and gas over the productive life of a horizontal well. Water and related services are increasingly important as oil and gas exploration and production ("E&P") companies have increased the complexity and completion intensity of horizontal wells (including the use of longer horizontal wellbore laterals, tighter spacing of frac stages in the laterals and increased water and proppant use per foot of lateral) in order to improve production and recovery of hydrocarbons. Historically, we have generated a substantial majority of our revenues through providing total water solutions to our customers. We provide our services to major integrated and large E&P companies, who typically represent the largest producers in each of our areas of operations.
Water is essential to the development and completion of unconventional oil and gas wells, where producers rely on fracking to stimulate the production of oil and gas from dense subsurface rock formations. Prior to the fracking process, we source, transfer, provide containment of and treat the water used by our customers in the well completion process. The fracking process involves the injection of significant amounts of water and proppants (typically sand) under high pressure, through a cased and cemented wellbore into targeted subsurface formations thousands of feet underground to fracture the surrounding rock. The fractures created allow hydrocarbons to flow into the wellbore for extraction. After the water is pumped into the well, it returns to the surface over time. Ten to fifty percent of the water returns as flowback during the first several weeks following the well completion process, and a large percentage of the remainder, as well as pre-existing water in the formation, returns to the surface as produced water over the life of the well. After the fracking process is completed, we provide a variety of services related to flowback and produced water and fluids that complement oil and gas completion and production activities.
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The diagram below illustrates the services we provide during the completion cycle of a horizontal well:
As the development of unconventional reservoirs has evolved, the water service needs of E&P companies have grown and diversified. Increasing completion intensity and the shift to multi-well pad drilling have significantly increased the demand for water and resulted in more complex logistical challenges in sourcing, transferring, containing and disposing of the water needed to drill and complete wells as well as to maintain production. Seeking to maximize the efficiency of their completion techniques, E&P companies have found that substantially increasing the amount of water and proppant injected into the formation can dramatically increase production. Management estimates that the completion of a horizontal well in 2009 required an average of approximately 75,000 barrels of water or approximately 575 tank truck loads, while a current horizontal well completion can require in excess of 500,000 barrels per well or approximately 3,850 tank truck loads. These volumes are amplified in multi-well pad completions which can require in excess of 5 million barrels of water per pad, or the equivalent of 38,500 tank truck loads. Significant mechanical, logistical, environmental and safety issues related to the transfer of such large volumes via tank truck have resulted in E&P companies shifting their operational focus away from traditional tank truck operators and small, local water service providers, to larger, regional and national players, like us, who have the expertise and scale to provide high quality, reliable and comprehensive water solution services.
We believe our broad geographic footprint, comprehensive suite of water services, inventory of water sources and permanent and temporary pipeline infrastructure position us to be a leading provider of water solutions in all of the shale plays that we serve. We have well-established field operations in what we believe to be core areas of all major shale plays in the United States, including the Permian Basin, SCOOP/STACK, Bakken, Eagle Ford, Marcellus, Utica, Haynesville, Rockies (DJ Basin, Niobrara Shale and Powder River Basin) and other Mid-Continent basins (Woodford, Barnett, Fayetteville, Granite Wash and Mississippian). Our broad footprint enables us to service the majority of current domestic unconventional drilling and completions activity. We estimate that over 80% of all currently active U.S. onshore horizontal rigs are operating in our primary service areas and anticipate that the vast majority of rigs that will be deployed in the near- to medium-term will be situated in these areas. In particular, we have established a strong position in the Permian Basin, which is presently our largest operating region, and where we expect producers to invest significant capital as commodity prices continue to recover from recent lows.
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We seek to be a "one-stop" provider of total water solutions for our customers in most of our areas of operations. We have the capability to provide all of the water services our customers require in their drilling and completion activities (predominantly for fracking), including the sourcing, transferring, containing and monitoring of water. We also offer various complementary water-related services that support oil and gas completion and production activities, including well testing, flowback, fluid hauling, pipeline gathering, treatment, recycling and disposal of water. For 2016, 76% of our water solutions segment revenue was generated from pre-frac and well testing activities with the remaining 24% from flowback and produced water services. Due to the increasing amount of water and fluid involved in completing a productive horizontal well by current industry standards, production of oil and gas in unconventional basins would not be commercially viable without the kind of extensive and complex water solutions and logistics-related services that we provide.
Our inventory of water sources is a key competitive advantage and enables us to offer our customers reliable access to the volume of water essential for fracking operations. Water sources are often difficult to locate, permit and reliably access, particularly in the quantities required for multi-well pad development programs. Navigating applicable regulations is especially difficult as the rules governing the sourcing of fresh water vary by state, county and municipality and each water resource may be overseen by federal and state agencies, regional water basin commissions, local water planning agencies and individual landowners. Additionally, upon the occurrence of certain events, the applicable governmental agency generally has the authority to terminate certain of our existing permits. We have spent the past five or more years obtaining strategic water sources and have secured permits or long-term access rights to approximately 1.5 billion barrels of water annually from currently in excess of 350 sources, a number which varies over time, including large scale sources such as the Brazos, Missouri, Ohio, Poudre, Rio Grande, Sabine, San Antonio, South Platte and Washita Rivers. In the Bakken, for example, we believe we have established a market leading position by securing three governmental permits which enable us to withdraw up to 100 million barrels of water annually from the Missouri River and Lake Sakakawea in North Dakota. Freshwater access cannot be easily replicated on Lake Sakakawea today as there are multiple environmental and regulatory conditions that must be met before an industrial water intake location can be built. New permits will also not be granted within 25 miles of an intake location associated with an existing permit. We have three of the five existing permits off Lake Sakakawea. In addition to surface water rights, groundwater resources are a key component of our extensive water portfolio. These sources have been secured or developed within our water solutions group and are designed with dedicated storage and transfer logistics to offer a complete water management service.
The first step in procuring a water source is identifying an area of interest based on anticipated drilling and completion activity as a result of lease activity, applications for permits and industry sources. We initiate the water sourcing process with a focus on gathering as much information as possible. Initially, we search public water records and use spatial data such as static and interactive maps managed and generated by our geographic information system team. This information provides a comprehensive overview of the area of interest, including information regarding active drilling rigs, permits, currently contracted water sources, potential surface water sources, river and stream use permits and existing and potential water well locations. We also research groundwater and surface water availability, landowner information, regulatory requirements of the state, county and district, and access logistics. After a specific water source is identified, we perform an assessment of the particular prospective source, including confirming availability, regulatory status, and any limitations on potential water rights. We use our AquaView® technology to quantify volumes and flow rates to verify current and potential water availability and volumes. After confirming the relevant ownership information, we begin negotiations with the applicable landowner or holder of the water rights. After finalizing the agreements and access rights, our team will obtain additional regulatory approvals, permits and right-of-ways as needed based on the regulatory authorities involved and individual circumstances.
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Going forward, we believe that our expertise and relationships in water sourcing will provide us with a competitive advantage in identifying and securing additional sources of water.
As a complement to our water sourcing rights, we have also made significant investments in strategic pipelines that provide reliable and cost effective water transfer. Our most significant pipeline assets are located in the Bakken and allow us to take advantage of our water permits in that area. Our Bakken pipelines consist of two active underground pipeline systems, the Charlson and the Iverson systems, in McKenzie County, North Dakota that can currently deliver up to 62 million barrels of fresh water per year. We are in the process of developing a third underground pipeline to support Williams County and western Mountrail County in North Dakota that would increase our capacity to take advantage of our maximum permitted right to 100 million barrels of fresh water per year. We have signed long-term contracts supported by Areas of Mutual Interest ("AMIs") with major Bakken producers that we believe will utilize a significant portion of our current pipeline capacity. We have also made investments outside of the Bakken, including our pipeline serving the SCOOP area of Oklahoma and our pipeline serving the Haynesville. In addition to our permanent water delivery systems, we have invested over $100 million in temporary piping systems, including approximately 525 miles of lay-flat hose, a temporary piping solution, and other related assets. These investments enable us to provide our customers with temporary water transfer systems that have substantially lower risk of leaks or spills compared to many alternative temporary piping options. We believe our expansive inventory of lay-flat hose, in combination with our customers' preference for this temporary water transfer method, positions us to be a market leader for this class of water transfer services. Going forward, we intend to make additional investments in water transfer infrastructure and believe we are well positioned to capture attractive opportunities due to our market position, customer relationships and industry experience and expertise.
Other Services
In addition to our comprehensive water solutions, we also offer our customers services through our accommodations and equipment rentals segment as well as our wellsite completion and construction services segment. Our accommodations and rentals segment provides workforce accommodations and surface rental equipment supporting oil and gas drilling, completion and production operations. Our wellsite completion and construction services segment includes crane and logistics services, wellsite and pipeline construction and various field services. We provide our accommodation and rentals and wellsite completion and construction services to a wide range of customers in most of the major shale plays or basins in the United States.
Industry Trends and Market Recovery
While demand for our services has declined from its highs in late 2014 as a result of the downturn in commodity prices and the corresponding decline in oil and gas drilling and completion activity, we believe that demand for our services will increase over the near-to-medium term as producers resume drilling and completion activities, including completion of their drilled but uncompleted wells, which we refer to as "DUCs." According to Baker Hughes' North American Rotary Rig Count, as of the week ended February 24, 2017, the number of active drilling rigs across our areas of operations has remained constant or increased in 36 of the last 40 weeks and has increased by approximately 104% since recent lows in late May 2016. If commodity prices continue to stabilize or rise, we expect to continue to see an increase in oil and gas drilling and completion activities leading to increased demand for our services.
We believe we will benefit from the emerging recovery of domestic drilling and completion activity as a result of our presence in what we believe to be the core of key domestic shale basins and the consistent industry trends of (i) increases in horizontal drilling, (ii) greater rig efficiency, characterized by multi-well pad development programs that enable our customers to drill more wells with each active
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rig and (iii) higher horizontal well completion intensity characterized by the use of longer horizontal wellbore laterals, tighter spacing of frac stages in the laterals and increased water and proppant use per foot of lateral. We also anticipate that the initial increases in drilling and completion activity will occur within our service footprint as capital spending will first be concentrated in the acreage that offers the most attractive economics to our upstream customers. These industry trends toward completion intensity and increased rig efficiency will directly benefit companies, like us, that provide consumable completion services, such as water or proppant. Given the increased production, recoveries and expected returns that E&P companies have reported due to greater rig efficiency and increasing completion intensity, we project a continuation of these trends. Therefore, we believe that growth in demand for water-related services will significantly outpace the growth in rig count throughout the industry recovery.
We also expect to see an increase in demand for our services as oil and gas producers complete their inventory of DUCs. While oil and gas producers typically have some inventory of DUCs, the backlog has grown significantly during the past two years as oil and gas producers have deliberately delayed completing drilled wells in anticipation of higher commodity prices that would generate higher returns on invested capital. According to the Drilling Productivity Report released on February 13, 2017 by the U.S. Energy Information Administration, or the EIA, as of January 2017, there were over 5,300 DUCs in the major U.S. shale plays (excluding the MidContinent) and 498 active drilling rigs in those areas, representing approximately 11 DUCs per active drilling rig in those areas. This represents a significant increase from approximately three DUCs per active drilling rig in those areas as of January 2014 according to EIA data. As commodity prices increase to levels that meet the targeted returns of E&P companies, we expect E&P companies will complete their DUC inventory. We expect the completion of this DUC inventory will increase the demand for water and our water-related completion services above the rate of growth in rigs in the near-to-medium term.
As a result of the prolonged decline in oil and gas completion and production activity and the relative oversupply of the services we offer in the market, the prices that we charge for our water and water-related services have declined. We estimate that across all service lines and regions, prices are down 30% to 35% from late 2014. For the reasons discussed above, we expect oil and gas drilling, completion and production activity, and the related demand for our services, to increase in the near-to-medium term. As this demand increases, we expect that supply constraints and the returns that our customers are able to achieve on their upstream investments should allow us to increase the prices that we charge for our services.
Our services are offered through three operating segments: water solutions (79.8% of fiscal year 2016 revenue), accommodations and rentals (9.0% of fiscal year 2016 revenue) and wellsite completion and construction services (11.2% of fiscal year 2016 revenue).
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- Water Solutions. Our water solutions segment, operating primarily under our subsidiary Select Energy Services, LLC, is a leading provider of total water solutions to customers that include major integrated oil companies and independent oil and gas producers. These services include: the sourcing of water; the transfer of the water to the wellsite through permanent pipeline infrastructure and temporary pipe; the containment of fluids off- and on-location; measuring and monitoring of water; the filtering and treatment of fluids, well testing and handling of flowback and produced formation water; and the transportation and recycling or disposal of drilling, completion and production fluids. We possess an extensive asset base, which we believe is the largest in the water solutions industry, including approximately 1.5 billion barrels of annual source water, 600 water transfer pumps, 1,360 miles of permanent and temporary pipeline distribution systems, 120 well testing spreads and 220 owned and leased tractors, approximately 287,000 barrels per day in permitted disposal capacity, 1,300 frac tanks, and 34 above ground
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Accommodations and Rentals.
Our accommodations and rentals segment,
operating under our subsidiary Peak Oilfield Services, LLC ("Peak"), provides workforce accommodations and surface rental equipment supporting drilling, completion and production operations to
the U.S. onshore oil and gas industry. The services provided include fully furnished office and living quarters, fresh water supply and waste water removal, portable power generation and light plants,
internet, phone, intercom, surveillance and monitoring services and other long-term rental supporting field personnel.
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- Wellsite Completion and Construction Services. Our wellsite completion and construction services segment, operating under our subsidiary Affirm Oilfield Services, LLC ("Affirm"), provides oil and gas operators with a variety of services, including crane and logistics services, wellsite and pipeline construction and field services. These services are performed to establish, maintain and improve production throughout the productive life of an oil or gas well, or to otherwise facilitate other services performed on a well.
high capacity storage tanks. We own or have contractual access rights to 111 miles of permanent pipelines. We also have investments in or strategic relationships with treatment technology companies providing bubble flotation, chemical precipitation, chemical disinfection and distillation, through in-house equipment, strategic licensing, investments and relationships. Our water solutions segment includes our engineered water solutions group, which consists of professionals with significant technical and project development experience.
We also incur certain administrative costs and expenses that we have not allocated to our operating segments. These costs include compensation for corporate executives and officers, corporate office and administrative salaries, management fees paid to certain affiliates, professional fees for accounting, tax and legal services, interest expense and state and federal income tax expense.
We believe that the following competitive strengths will allow us to successfully execute our business strategies.
Leading Market Position Offering Critical Water Solutions. As a result of our inventory of water sources, our asset base and our water delivery systems and infrastructure, we believe we are a market leader in providing pre-frac water services to the U.S. unconventional oil and gas industry. In most of our areas of operations, we also provide complementary water-related services that support oil and gas completion and production activities. Our principal competitors are typically smaller, private companies operating in fewer shale basins and in only one or two water services-related product lines. By comparison, in most of our areas of operations, we offer our customers comprehensive, integrated water solutions, from initial sourcing of water to disposal of flowback or produced water. Further, our scale allows us to cost-effectively increase our service offering to match increases in drilling and completions activity by our customers. We have an engineered water solutions team with significant experience in field planning, logistics management, regulatory compliance, technical design, petroleum and chemical engineering, geographical information systems, water resources and environmental science. This team is capable of designing, developing and operating projects across the productive life of a field and provides us with a unique competitive advantage in meeting customer requirements for complex and customized water solutions. We believe our ability to engineer and deliver end-to-end water solutions differentiates us from our competitors and enables us to be a value-added partner to E&P companies.
National Footprint Focused in the Core of Each Major Shale Play. Our operations are concentrated in what we believe to be the core areas of the major shale plays in the United States, including the Permian Basin, SCOOP/STACK, Bakken, Eagle Ford, Marcellus, Utica, Haynesville, Rockies (DJ Basin, Niobrara Shale and Powder River Basin) and other Mid-Continent basins (Woodford, Barnett,
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Fayetteville, Granite Wash and Mississippian). In each of our core geographic regions, we have a high quality customer base, including major integrated and large E&P companies, who represent the largest producers in those areas of operations. Our geographic breadth and diversification have allowed us to accumulate significant knowledge regarding the water solutions required in both oil and gas formations with varying geological characteristics and allows us to translate, apply and adapt water solutions developed in one region to other regions. In addition, we have the ability to shift assets among geographic regions as activity levels fluctuate due to market or regulatory forces. Finally, our national footprint allows us to satisfy the needs of major integrated and large independent E&P companies that demand multi-basin service capabilities.
Unique Inventory of Strategic Water Sources. To support our pre-frac water capabilities, we have secured water sources that differentiate us from our competitors and drive water transfer and other related service revenues. Identifying and securing these water sources is not easily replicated given the significant know-how and relationships with local, state and federal government agencies as well as private landowners that we have developed over the last five or more years. Specifically, through a portfolio of contracts with and permits from regulatory bodies, corporations and individual landowners, we have secured rights to approximately 1.5 billion barrels of water annually from currently in excess of 350 sources, a number which varies over time, including permits on 9 major rivers in U.S. shale basins. Most of our water sources in the Bakken and Haynesville are secured on an exclusive basis. Our deep knowledge of each basin and long-term customer relationships allow us to develop water sources that are logistically correct, providing a reliable, scalable water delivery system that is in close proximity to current and future drilling and completion activity. For example, in the Bakken we have three governmental permits that enable us to withdraw up to 100 million barrels of water annually from the Missouri River and Lake Sakakawea in North Dakota. Freshwater access cannot be easily replicated on Lake Sakakawea today as there are multiple environmental and regulatory conditions that must be met before an industrial water intake location can be built. New permits will also not be granted within 25 miles of an intake location associated with an existing permit. We have three of the five existing permits off Lake Sakakawea. Our water resources have historically attracted and will continue to attract customers seeking abundant water supply to plan long-term field developments. Further, we have successfully marketed other water-related services to our water sourcing customers in the past and we expect we will continue to do so in the future.
Significant Investment in Water Delivery Systems and Infrastructure. We have made significant investments in infrastructure to efficiently deliver water from the source to the well site. Our fixed, underground pipeline systems provide a cost-effective, reliable source of freshwater transfer and offer us the ability to scale our operations as market activity fluctuates. Our most significant pipelines today service what we believe to be core acreage in the Bakken. Our Bakken pipeline systems consist of two underground, independent pipeline systems in McKenzie County, North Dakota totaling approximately 90 miles of pipeline, including 38 miles that we own and an additional 52 miles that we have contractual rights to access. We use our Bakken pipeline systems to supply fresh water to support drilling, completion and production activities. We believe our Bakken water rights and the proximity of our infrastructure to the most economic acreage in the Bakken represent significant competitive advantages with respect to supplying and transferring water required for well completions that should generate high margins as the basin recovers. Since the second pipeline was put into service in eastern McKenzie County in the second quarter of 2015, we have successfully won all of our bids for frac water transfer jobs within seven miles of this pipeline. In addition to our fixed pipeline assets, we believe that we are the largest domestic provider of lay-flat hose, with approximately 525 miles available, which provides our customers with flexible temporary water transfer solutions. We believe that our investment in water transfer infrastructure differentiates us from our competition and will enable us to acquire new customers and drive revenue growth as drilling and completions activity increases.
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Technology. We are committed to technology and product innovation. As such, we believe we are the industry leader in developing and applying technological solutions to provide value, precision and convenience to our clients. We developed AquaView®, a suite of proprietary monitoring and automation devices and related services that remotely and accurately measure and monitor water assets in real time. We also developed AquaLogic™, which consists of proprietary methods to remotely and automatically control and manage water transfer operations. These service offerings allow for more efficient, safer performance at an affordable cost for our customers, and we believe this is a competitive advantage in capturing and retaining business. We will continue to invest in technology in order to maintain our position as one of the leading water solutions providers, manage our costs of goods sold and improve gross margins.
Experienced Management Team with Significant Equity Ownership. Our management team has an extensive track record in the oilfield services industry with an average of over 20 years of oilfield services experience. Our Chief Executive Officer, John Schmitz, has a decades-long history of founding and building successful oilfield service companies. The majority of our management team has worked together since SES Holdings' formation in July 2008. Further, our management team has significant equity ownership which aligns their incentives with the other equity owners of the business. Following this offering, management will own an approximate % indirect economic interest in us. In addition, following this offering, funds controlled by Crestview Partners II GP, L.P. ("Crestview GP") and managed by Crestview Advisors, L.L.C. ("Crestview Partners"), a private equity firm focused on long-term, proprietary investments that manages over $7 billion of aggregate commitments, will own an approximate % economic interest in us. We believe we have benefited from Crestview Partners' investment in our business and expect to continue to benefit from their ongoing involvement in the business following this offering.
Financial Strength and Flexibility. Following the closing of this offering, we expect to have a strong credit profile and approximately $ million in total liquidity, including cash on hand and availability under our credit facility. We expect our total liquidity will be reduced by the cash consideration used to complete the Permian Acquisition, also described in "—Recent Developments" below. Our low leverage and sufficient available liquidity will enable us to fund our business and selectively pursue accretive acquisitions and organic growth opportunities as they arise.
Strong Focus on Operational Safety and Environmental Stewardship. We maintain a culture that prioritizes safety, the environment and our relationship with the communities in which we operate. We place a strong emphasis on the safe execution of our operations, including safety training for our employees and the development of a variety of safety programs designed to make us a market leader in safety standards. In addition, we work closely with federal, state and local governments and community organizations to help ensure that our operations comply with legal requirements and community standards. We believe that our customers will select their service providers based in part on the quality of their safety and compliance records, and therefore, we will continue to make significant investments to be a market leader in this area.
Our primary objective is to provide superior returns to our stockholders as a leading provider of total water solutions to E&P companies operating in the major shale plays in the United States. We believe we will be able to achieve this objective by executing on the following strategies.
Capitalize on the Recovery in Activity in Unconventional Resource Plays. Water is essential, and increasingly important, to the development and completion of oil and gas wells in the major shale plays that we serve in the United States. Due to our strategic positioning in what we believe to be core acreage in the shale plays, we believe we are well situated to benefit from the anticipated increase in drilling and completion activity as commodity prices rise from their recent lows. Furthermore, we
8
believe the industry trends discussed above will drive growth in demand for total water solutions that will significantly outpace the growth in rig count. Horizontal drilling techniques in the regions we serve have continued to evolve, and operators have dramatically increased the amount of water and proppant used during the completion of horizontal wells. As market dynamics improve further, we expect to benefit from our market leading position and footprint and gain market share in the basins where we currently operate and expand our operations into emerging resource plays as they develop.
Build out or Acquire Water Infrastructure. Our fixed pipeline assets are a key competitive advantage and allow us to deliver water efficiently and cost effectively. We are pursuing and evaluating several near-term opportunities to make additional investments in water infrastructure. On February 24, 2017, we executed definitive agreements to purchase a company with extensive freshwater pipeline and water rights to service producers in the Permian Basin, which is expected to close in March 2017, subject to the satisfaction of customary closing conditions. We are also currently developing a third system to provide water to Williams County and western Mountrail County in North Dakota to augment our already strong position with our two pipelines servicing McKenzie County. We have entered into, and depending on market conditions may continue to enter into, long-term contracts to support our Bakken development efforts. We have identified additional expansion opportunities for our other two existing pipeline systems in the SCOOP area of Oklahoma and the Haynesville area. Beyond these prospects, we plan to invest opportunistically in organic growth to gain market share in our current areas of operations and selectively pursue acquisitions that will allow us to strengthen our footprint and market our total water solutions to our customers.
Strengthen and Expand Our Customer Relationships Through Pre-Frac Water Services. We will continue to focus on being a market leader in pre-frac water services, expanding our market position to be a high value-add service provider, and offering our customers end-to-end water and related services associated with oil and gas drilling, completion and production activities. Looking forward, our broad service offering and focused expertise should allow us to expand our relationships with existing customers and attract new customers as demand for water and water solutions increases. Furthermore, we believe we can expand certain customer relationships that are currently limited to a single basin and become a preferred provider in multiple basins. In addition, for customers seeking to outsource field planning and logistical services, our engineered water solutions group designs, develops, operates and manages water solutions across the life cycle of a development plan.
Expand and Utilize Our Water Sources. One of our key differentiators is our portfolio of water rights, which serves as a reliable, scalable and cost effective source of water for our customers. We will also seek to identify and secure additional water sources to meet the ongoing and future water needs of our customers. Our dedicated access to high volume water sources that can support long-term development plans should allow us to attract new customers and strengthen our existing customer relationships. In the future, we plan to utilize the relationships and expertise we have developed in the process of obtaining our current portfolio of water rights to further expand our water sources.
Continue to Invest in Technology and Personnel. Satisfying the water-related service needs of an operator drilling or producing from a shale well is a highly complex and ever-changing process that requires significant technical expertise in diverse areas such as geology, engineering, environmental science and regulatory affairs. We have made significant investments in software, hardware and proprietary systems that have enabled us to develop technology and become one of the leading firms in the water solutions industry. In addition, we have built a strong team of experienced professionals holding advanced degrees to develop and execute new technologies as well as provide the technical knowledge to be a value-added partner to our customers. We plan to continue to invest in our personnel through personal, professional and job-specific training and to invest selectively in technologies that we believe will enhance the breadth and quality of our service offerings.
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Maintain Financial Strength and Flexibility. We will seek to maintain a conservative balance sheet, which allows us to better react to changes in commodity prices and related demand for our services, as well as overall market conditions. As of the closing of this offering, we expect to have $ million outstanding and $ million available under our credit facility, which is scheduled to mature in 2020. We believe this borrowing capacity, along with our cash flow from operations and the proceeds from this offering, will provide us with sufficient liquidity to execute the business strategies discussed above.
Permian Acquisition. On February 24, 2017, we executed definitive agreements to acquire a company in the Permian Basin (the "Permian Acquisition") with significant proprietary fresh water sources and water transport infrastructure, including pipeline infrastructure, storage facilities and pumps. The target company currently provides water-related services to E&P companies in the Permian Basin. We estimate that the total consideration payable by us for this acquisition will be approximately $56.5 million (assuming the target company has a minimum of $6 million in working capital as of the closing), with $51 million to be paid in cash and $5.5 million to be paid in equity. We expect to fund the cash portion of the consideration for the Permian Acquisition with borrowings under our credit facility, which we expect to repay with a portion of the net proceeds of this offering. If consummated, we believe that this acquisition will significantly improve our position in the Permian Basin. The closing of the Permian Acquisition is subject to customary closing conditions and we can provide no assurance as to whether or when the transaction will be consummated.
144A Offering. On December 20, 2016, we completed a private placement to qualified institutional buyers, accredited investors and certain foreign investors of 16,100,000 shares of our Class A-1 common stock, par value $0.01 per share, for gross proceeds of $322,000,000 (net proceeds of $297.2 million), pursuant to which FBR Capital Markets & Co. ("FBR") acted as initial purchaser and placement agent (the "144A Offering"). The shares of Class A-1 common stock will automatically convert to Class A common stock upon the effectiveness of a registration statement filed to permit resales of shares purchased in the 144A Offering, which we expect to occur in connection with this offering. For more information on the 144A Offering, please read "Description of our Capital Stock—Class A-1 Common Stock."
An investment in our Class A common stock involves a number of risks. You should carefully consider, in addition to the other information contained in this prospectus (including "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and related notes), the risks described in "Risk Factors" before investing in our Class A common stock. These risks could adversely affect our business, financial condition and results of operations, and cause the trading price of our Class A common stock to decline. You could lose part or all of your investment. In reviewing this prospectus, you should bear in mind that past results are no guarantee of future performance. You should read the section titled "Forward-Looking Statements" for a discussion of what types of statements are forward-looking statements, as well as the significance of such statements in the context of this prospectus.
These "Risk Factors" include, but are not limited to:
- •
-
Our business depends on domestic capital spending by the oil and gas industry, and reductions in capital spending could have a material adverse
effect on our liquidity, results of operations and financial condition;
- •
- If oil prices or gas prices fail to increase or decline further, the demand for our services could be adversely affected;
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- •
-
We are subject to environmental and occupational health and safety laws and regulations that may expose us to significant liabilities for
penalties, damages or costs of remediation or compliance;
- •
-
Federal, state and local legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or
delays in the drilling and completion of oil and gas wells that may reduce demand for our services and could have a material adverse effect on our liquidity, consolidated results of operations and
consolidated financial condition;
- •
-
There is currently no public market for our Class A common stock, a trading market for our Class A common stock may never develop
following this offering and our Class A common stock price may be volatile and could decline substantially following this offering;
- •
-
We are a holding company; our sole material asset after completion of this offering will be our equity interest in SES Holdings and,
accordingly, we will be dependent upon distributions and payments from SES Holdings to pay taxes, make payments under the Tax Receivable Agreements (as defined below) and cover our corporate and other
overhead expenses; and
- •
- SES Legacy Holdings, LLC ("Legacy Owner Holdco") and the Legacy Owners (as defined below) have interests that conflict with holders of shares of our Class A common stock.
The Company was incorporated as a Delaware corporation on November 21, 2016. The Company is a holding company whose sole material asset consists of a membership interest in SES Holdings. SES Holdings was formed as a Delaware limited liability company in July 2008 and owns all of the equity interests of the primary operating subsidiaries through which we operate our business. The Company is the sole managing member of SES Holdings, is responsible for all operational, management and administrative decisions relating to SES Holdings' business and consolidates the financial results of SES Holdings and its subsidiaries.
In December 2016, in connection with the 144A Offering we completed certain reorganization transactions including:
- •
-
Legacy Owner Holdco acquired by merger all of the outstanding membership interests in SES Holdings from the existing owners of such membership
interests, whom we refer to as the "Legacy Owners," in exchange for membership interests in Legacy Owner Holdco;
- •
-
the membership interests of SES Holdings were converted into a single class of common units, which we refer to as "SES Holdings LLC
Units";
- •
-
the Company acquired, directly or indirectly, SES Holdings LLC Units that were directly and indirectly owned by certain affiliates of
the Legacy Owners, whom we refer to as the "Contributing Legacy Owners," in exchange for 3,802,972 shares of Class A common stock;
- •
-
the Company issued 16,100,000 shares of Class A-1 common stock, which will be automatically converted to shares of Class A common
stock upon the effectiveness of a registration statement filed to permit resales of shares purchased in the 144A Offering;
- •
-
the Company issued 38,462,541 shares of its Class B common stock and contributed these shares and all of the net proceeds of the
144A Offering to SES Holdings in exchange for a number of SES Holdings LLC Units equal to the number of shares of Class A-1 common stock issued to the purchasers in the
144A Offering; and
- •
- SES Holdings distributed to Legacy Owner Holdco all of the Class B common stock it received from the Company, with Legacy Owner Holdco receiving one share of Class B common stock for each SES Holdings LLC Unit that Legacy Owner Holdco owns.
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Each share of Class B common stock has no economic rights but entitles its holder to one vote on matters to be voted on by our stockholders. Holders of Class A common stock and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation. We do not intend to list our Class B common stock on any stock exchange. All of our Class B common stock is held by Legacy Owner Holdco; accordingly, the board of managers of Legacy Owner Holdco exercise voting control over all Class B common stock.
Subject to certain limitations, Legacy Owner Holdco (and its permitted transferees, including certain members of Legacy Owner Holdco under the SES Holdings LLC Agreement) has the right, which we refer to as the "Exchange Right," to cause SES Holdings to acquire all or a portion of its SES Holdings LLC Units (along with a corresponding number of shares of our Class B common stock) for, at SES Holdings' election, (i) shares of our Class A common stock at an exchange ratio of one share of Class A common stock for each SES Holdings LLC Unit exchanged, subject to conversion rate adjustments for stock splits, stock dividends, reclassification and other similar transactions or (ii) cash in an amount equal to the Cash Election Value of such Class A common stock. Alternatively, upon the exercise of any Exchange Right, the Company (instead of SES Holdings) will have the right, which we refer to as our "Call Right," to acquire the tendered SES Holdings LLC Units from the exchanging unitholder for, at its election, (i) the number of shares of Class A common stock the exchanging unitholder would have received under the Exchange Right or (ii) cash in an amount equal to the Cash Election Value of such Class A common stock. The board of managers of Legacy Owner Holdco, which consists of our CEO, John Schmitz, and two representatives of funds controlled by Crestview GP, must unanimously approve any exchange of ownership interests in Legacy Owner Holdco for SES Holdings LLC Units except, following listing of our Class A common stock on a national securities exchange, for exchanges by affiliates of John Schmitz and Crestview GP (which may be made at the election of such affiliates). If such exchange is approved, such members of Legacy Owner Holdco will have the same "Exchange Right" as Legacy Owner Holdco, subject to the terms and conditions described above. In connection with any exchange of SES Holdings LLC Units pursuant to an Exchange Right or our Call Right, the corresponding number of shares of Class B common stock will be cancelled. The Exchange Rights will be subject to restrictions intended to ensure that SES Holdings will continue to be treated as a partnership for U.S. federal income tax purposes. Please read "Certain Relationships and Related Party Transactions—SES Holdings LLC Agreement."
In connection with the 144A Offering, we entered into two tax receivable agreements, which we refer to as the "Tax Receivable Agreements," with Legacy Owner Holdco, Crestview GP and certain affiliates of the Legacy Owners, including the Contributing Legacy Owners, whom we collectively refer to as the "TRA Holders."
The first of the Tax Receivable Agreements, which we entered into with Legacy Owner Holdco and Crestview GP, generally provides for the payment by us to such TRA Holders of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax that we actually realize (computed using simplifying assumptions to address the impact of state and local taxes) or are deemed to realize in certain circumstances in periods after the 144A Offering as a result of, as applicable to each such TRA Holder, (i) certain increases in tax basis that occur as a result of our acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder's SES Holdings LLC Units in connection with the 144A Offering or pursuant to the exercise of the Exchange Right or our Call Right and (ii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under such Tax Receivable Agreement.
The second of the Tax Receivable Agreements, which we entered into with an affiliate of the Contributing Legacy Owners, generally provides for the payment by us to such TRA Holders of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax that we actually realize (computed using simplifying assumptions to address the impact of state and local taxes) or are
12
deemed to realize in certain circumstances in periods after the 144A Offering as a result of, as applicable to each such TRA Holder, (i) any net operating losses available to us as a result of certain reorganization transactions entered into in connection with the 144A Offering and (ii) imputed interest deemed to be paid by us as a result of any payments we make under such Tax Receivable Agreement.
Under both Tax Receivable Agreements, we will retain the benefit of the remaining 15% of these cash savings. Certain of the TRA Holders' rights under the Tax Receivable Agreements are transferable in connection with a permitted transfer of SES Holdings LLC Units or if the TRA Holder no longer holds SES Holdings LLC Units. For additional information regarding the Tax Receivable Agreements, see "Risk Factors—Risks Relating to the Offering and our Class A Common Stock," "Risk Factors—Risks Related to Our Internal Reorganization and Resulting Structure" and "Certain Relationships and Related Party Transactions—Tax Receivable Agreements."
13
The diagram below depicts our simplified organizational structure immediately following this offering assuming that the underwriters do not exercise their option to purchase additional shares of Class A common stock:
Our Relationship with Crestview Partners
Following this offering, funds controlled by Crestview GP will indirectly own (i) shares of our Class A common stock, which will represent approximately % of the economic interests in us and % of our voting power (approximately % and %, respectively, if the underwriters exercise in full their option to purchase additional shares of our Class A common stock) and (ii) indirectly through Legacy Owner Holdco, SES Holdings LLC Units and shares of our Class B common stock, which will represent approximately % of the economic interests in SES Holdings and % of
14
our voting power (approximately % and %, respectively, if the underwriters exercise in full their option to purchase additional shares of our Class A common stock). For more information on our reorganization and the ownership of our common stock by our principal and selling shareholders, see "Organizational Structure" and "Principal and Selling Shareholders."
Founded in 2004, Crestview Partners is a value-oriented private equity firm focused on the middle market. The firm is based in New York and manages funds with over $7 billion of aggregate capital commitments. The firm is led by a group of partners who have complementary experience and distinguished backgrounds in private equity, finance, operations and management. Crestview Partners' senior investment professionals primarily focus on sourcing and managing investments in each of the specialty areas of the firm: media, energy, financial services and industrials.
Emerging Growth Company Status
We are an "emerging growth company" within the meaning of the federal securities laws. For as long as we are an emerging growth company, we will not be required to comply with certain requirements that are applicable to other public companies that are not "emerging growth companies" including, but not limited to, the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, the reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and the exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended, or the "Securities Act," for complying with new or revised accounting standards.
We intend to take advantage of all of the reduced reporting requirements and exemptions, including the longer phase-in periods for the adoption of new or revised financial accounting standards under Section 107 of the JOBS Act until we are no longer an emerging growth company. Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act. We will cease to be an "emerging growth company" upon the earliest of: (i) the last day of the fiscal year in which we have $1.0 billion or more in annual revenues; (ii) the date on which we become a "large accelerated filer" (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30); (iii) the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or (iv) the last day of the fiscal year following the fifth anniversary of our initial public offering.
For a description of the qualifications and other requirements applicable to emerging growth companies and certain elections that we have made due to our status as an emerging growth company, see "Risk Factors—Risks Related to the Offering and our Class A Common Stock—Since we expect to be an "emerging growth company," we will not be required to comply with certain disclosure requirements that are applicable to other public companies and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our Class A common stock less attractive to investors."
Our principal executive offices are located at 1820 North I-35, P.O. Box 1715, Gainesville, Texas 76241, and our telephone number at that address is (940) 668-0259. Our website address is www.selectenergyservices.com. Information contained on our website does not constitute part of this prospectus.
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|
Class A common stock offered by us |
shares ( shares if the underwriters' option to purchase additional shares is exercised in full). | |
|
Class A common stock offered by selling shareholders |
shares. | |
|
Class A common stock to be outstanding immediately after completion of this offering |
shares ( shares if the underwriters' option to purchase additional shares is exercised in full). | |
|
|
The 16,100,000 shares of our Class A-1 Common Stock issued in the 144A Offering will automatically convert to Class A common stock upon the effectiveness of a registration statement filed to permit resales of such shares, which we expect to occur in connection with this offering. Following such conversion, we will have shares outstanding ( shares if the underwriters' option to purchase additional shares is exercised in full). | |
|
|
If all outstanding SES Holdings LLC Units held by Legacy Owner Holdco were exchanged (along with a corresponding number of shares of our Class B common stock) for newly-issued shares of Class A common stock on a one-for-one basis, shares of Class A common stock would be outstanding (regardless of whether the underwriters' option to purchase additional shares is exercised). | |
|
Class A common stock owned by the selling shareholders after this offering |
shares. | |
|
Option to purchase additional shares |
We have granted the underwriters a 30-day option to purchase up to an aggregate of additional shares of our Class A common stock. | |
|
Class B common stock to be outstanding after this offering |
38,462,541 shares or one share for each SES Holdings LLC Unit held by Legacy Owner Holdco immediately following this offering. Shares of our Class B common stock have voting rights but no economic rights. In connection with any exchange of SES Holdings LLC Units pursuant to an Exchange Right or our Call Right, the corresponding number of shares of Class B common stock will be cancelled. | |
|
Voting power of Class A common stock |
% (or 100% if all outstanding SES Holdings LLC Units held by Legacy Owner Holdco are exchanged (along with a corresponding number of shares of our Class B common stock) for newly issued shares of Class A common stock on a one for one basis). | |
|
Voting power of Class B common stock |
% (or 0% if all outstanding SES Holdings LLC Units held by Legacy Owner Holdco are exchanged (along with a corresponding number of shares of our Class B common stock) for newly issued shares of Class A common stock on a one for one basis). |
16
|
Use of proceeds |
We expect to receive approximately $ million of net proceeds from the sale of the Class A common stock offered by us, based upon the assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and estimated offering expenses payable by us (or approximately $ million if the underwriters' option to purchase additional shares is exercised in full). Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $ million (assuming no exercise of the underwriters' option to purchase additional shares). | |
|
|
We intend to contribute all of the net proceeds we receive from this offering to SES Holdings in exchange for SES Holdings LLC Units. SES Holdings intends to use the net proceeds in the following manner: (i) up to $51 million will be used to repay borrowings incurred under our credit facility to fund the cash portion of the purchase price of the Permian Acquisition; (ii) $10.7 million will be used for the cash settlement of outstanding phantom units at SES Holdings; (iii) approximately $5 million will be used for growth capital expenditures in the Bakken, including the expansion of the Bakken Pipeline systems; and (iv) the balance will be used for general corporate purposes, including other organic and acquisition growth opportunities. | |
|
|
If the underwriters exercise their option to purchase additional shares of our Class A common stock, we will contribute those proceeds we receive to SES Holdings in exchange for additional SES Holdings LLC Units and SES Holdings will use those proceeds for general corporate purposes. | |
|
|
We will not receive any of the proceeds from the sale of shares of our Class A common stock by the selling shareholders. | |
|
Voting rights |
Each share of our Class A common stock entitles its holder to one vote on all matters to be voted on by stockholders generally. | |
|
|
Each share of our Class B common stock entitles its holder to one vote on all matters to be voted on by stockholders generally. | |
|
|
Holders of our Class A common stock and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our amended and restated certificate of incorporation. See "Description of Capital Stock." | |
|
Dividend policy |
We do not anticipate paying any cash dividends on our Class A common stock. See "Dividend Policy." |
17
|
Exchange rights of holders of SES Holdings LLC Units |
Subject to certain limitations, Legacy Owner Holdco (and its permitted transferees under the SES Holdings LLC Agreement) has the right to cause SES Holdings to acquire all or a portion of its SES Holdings LLC Units (along with a corresponding number of shares of our Class B common stock) for, at SES Holdings' election, (i) shares of our Class A common stock at an exchange ratio of one share of Class A common stock for each SES Holdings LLC Unit exchanged, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) cash in an amount equal to the Cash Election Value of such Class A common stock. Alternatively, upon the exercise of any Exchange Right, the Company (instead of SES Holdings) will have the right to acquire the tendered SES Holdings LLC Units from the exchanging unitholder for, at its election, (i) the number of shares of Class A common stock the exchanging unitholder would have received under the Exchange Right or (ii) cash in an amount equal to the Cash Election Value of such Class A common stock. The board of managers of Legacy Owner Holdco, which consists of our Chief Executive Officer, John Schmitz and two representatives of funds controlled by Crestview GP, must unanimously approve any exchange of ownership interests in Legacy Owner Holdco for SES Holdings LLC Units except, following listing of our Class A common stock on a national securities change, for exchanges by affiliates of John Schmitz or Crestview GP (which may be made at the election of such affiliates). If such exchange is approved, such members of Legacy Owner Holdco will have the same Exchange Right as Legacy Owner Holdco, subject to the terms and conditions described above. In connection with any exchange of SES Holdings LLC Units pursuant to an Exchange Right or our Call Right, the corresponding number of shares of Class B common stock will be cancelled. Please read "Certain Relationships and Related Party Transactions—SES Holdings LLC Agreement." | |
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Risk factors |
You should carefully read and consider the information set forth under "Risk Factors" and all other information set forth in this prospectus before deciding to invest in our Class A common stock. | |
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Listing and trading symbol |
We intend to apply to list our Class A common stock on the New York Stock Exchange ("NYSE") under the symbol "WTTR." |
The information above does not include shares of Class A common stock reserved for issuance pursuant to our equity incentive plan.
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Summary Consolidated Financial Data
The following table presents our summary historical financial data for the periods and as of the dates indicated. The statement of operations data for the years ended December 31, 2016 and 2015 and the balance sheet data as of December 31, 2016 and 2015 are derived from our audited consolidated financial statements and the notes thereto included in the F-pages of this prospectus.
Historical results are not necessarily indicative of the results we expect in future periods. The data presented below should be read in conjunction with, and are qualified in their entirety by reference to, "Capitalization" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and the notes thereto included elsewhere in this prospectus.
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20
|
|
Year Ended December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2016 | 2015 | |||||
|
|
(in thousands)
|
||||||
|
Balance Sheet Data (at period end): |
|||||||
|
Cash and cash equivalents |
$ | 40,041 | $ | 16,305 | |||
|
Total assets |
405,066 | 650,248 | |||||
|
Long-term liabilities |
23,974 | 256,923 | |||||
|
Other Financial Data: |
|||||||
|
EBITDA(1) |
$ | (201,237 | ) | $ | 39,853 | ||
|
Adjusted EBITDA(1) |
16,944 | 65,539 | |||||
- (1)
-
We
define EBITDA as net income, plus taxes, interest expense, and depreciation and amortization. We define Adjusted EBITDA as EBITDA plus/(minus) loss/(income) from
discontinued operations, plus any impairment charges or asset write-offs pursuant to GAAP, plus/(minus) non-cash losses/(gains) on the sale of assets or subsidiaries, non-recurring compensation
expense, non-cash compensation expense, and nonrecurring or unusual expenses or charges, including severance expenses, transaction costs, or facilities related exit and disposal related expenditures.
Our board of directors, management and investors use EBITDA and Adjusted EBITDA to assess our financial performance because it allows them to compare our operating performance on a consistent basis
across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization) and non-recurring items outside the
control of our management team. We present EBITDA and Adjusted EBITDA because we believe they provide useful information regarding the factors and trends affecting our business in addition to measures
calculated under GAAP.
EBITDA and Adjusted EBITDA each have limitations as an analytical tool and should not be considered as alternatives to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. Other companies in our industry may calculate EBITDA or Adjusted EBITDA differently, limiting its usefulness as a comparative measure.
The following table shows the reconciliation of historical EBITDA and Adjusted EBITDA to the most directly comparable GAAP measure, net income (loss).
|
|
Year Ended December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2016 | 2015 | |||||
|
|
(in thousands)
|
||||||
|
Net income (loss) |
$ | (313,948 | ) | $ | (81,872 | ) | |
|
Interest expense |
16,128 | 13,689 | |||||
|
Tax (benefit) expense |
(524 | ) | 324 | ||||
|
Depreciation and amortization |
97,107 | 107,712 | |||||
| | | | | | | | |
|
EBITDA |
(201,237 | ) | 39,853 | ||||
|
Net income from discontinued operations |
— | (21 | ) | ||||
|
Impairment |
198,692 | 21,366 | |||||
|
Lease abandonment costs |
19,423 | — | |||||
|
Non-recurring severance expense |
886 | 3,200 | |||||
|
Non-recurring deal costs (reimbursement) |
(236 | ) | 2,790 | ||||
|
Non-cash incentive gain |
(487 | ) | (889 | ) | |||
|
Non-cash gain on sale of subsidiaries and other assets |
(97 | ) | (760 | ) | |||
| | | | | | | | |
|
Adjusted EBITDA |
$ | 16,944 | $ | 65,539 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
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Investing in our Class A common stock involves a high degree of risk. You should carefully consider the risks described below together with the other information set forth in this prospectus before making an investment decision. Our business, financial condition, cash flows or results of operations could be adversely affected by the occurrence of any of the risks discussed below. Additionally, the trading price of our Class A common stock could decline due to the occurrence of any of these risks, and you may lose all or part of your investment. The risks discussed below are not the only risks we face. We may experience additional risks and uncertainties not currently known to us or as a result of developments occurring in the future. Conditions that we currently deem to be immaterial may also adversely affect our business, financial condition, cash flows and results of operations.
Risks Related to Our Business
Our business depends on domestic capital spending by the oil and gas industry, and reductions in capital spending could have a material adverse effect on our liquidity, results of operations and financial condition.
Our business is directly affected by our customers' capital spending to explore for, develop and produce oil and gas in the United States. The significant decline in oil and gas prices that began in the fourth quarter of 2014 has caused a reduction in the exploration, development and production activities of most of our customers and their spending on our services. These cuts in spending have curtailed drilling programs as well as discretionary spending on well services, which has resulted in a reduction in the demand for our services as compared to activity levels in mid-2014, as well as the rates we can charge and the utilization of our assets. In addition, certain of our customers could become unable to pay their vendors and service providers, including us, as a result of the decline in commodity prices. Reduced discovery rates of new oil and gas reserves in our market areas as a result of decreased capital spending may also have a negative long-term impact on our business, even in an environment of stronger oil and gas prices, to the extent the reduced number of wells for us to service more than offsets increasing completion activity and intensity. Any of these conditions or events could adversely affect our operating results. If a recovery does not materialize and our customers fail to increase their capital spending, it could have a material adverse effect on our liquidity, results of operations and financial condition.
Industry conditions are influenced by numerous factors over which we have no control, including:
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the domestic and foreign economic conditions and supply of and demand for oil and gas;
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the level of prices, and expectations about future prices, of oil and gas;
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the level of global oil and gas exploration and production;
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governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and
gas reserves;
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political and economic conditions in oil and gas producing countries;
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actions by the members of Organization of Petroleum Exporting Countries with respect to oil production levels and announcements of potential
changes in such levels, including failure to meet agreed reduction to output announced on November 30, 2016;
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global weather conditions and natural disasters;
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worldwide political, military and economic conditions;
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the cost of producing and delivering oil and gas;
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- the discovery rates of new oil and gas reserves;
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activities by non-governmental organizations to restrict the exploration, development and production of oil and gas so as to minimize emissions
of carbon dioxide, a greenhouse gas;
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the ability of oil and gas producers to access capital;
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technical advances affecting energy consumption; and
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- the potential acceleration of development of alternative fuels.
If oil prices or gas prices fail to increase or decline further, the demand for our services could be adversely affected.
The demand for our services is primarily determined by current and anticipated oil and gas prices and the related levels of capital spending and drilling activity in the areas in which we have operations. Volatility or weakness in oil prices or gas prices (or the perception that oil prices or gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production spending on existing wells. This, in turn, could lead to lower demand for our services and may cause lower rates and lower utilization of our assets. If oil prices decline or gas prices continue to remain low or decline further, or if the recent increase in drilling activity reverses, the demand for our services and our results of operations could be materially and adversely affected.
Prices for oil and gas historically have been extremely volatile and are expected to continue to be volatile. During the past six years, the posted West Texas Intermediate ("WTI") price for oil has ranged from a twelve-year low of $26.19 per Bbl in February 2016 to a high of $113.39 per Bbl in April 2011. The Henry Hub spot market price of gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $7.51 per MMBtu in January 2010. During 2016, WTI prices ranged from $26.19 to $54.01 per Bbl and the Henry Hub spot market price of gas ranged from $1.49 to $3.80 per MMBtu. Oil prices have begun to recover and reached a closing price of $53.99 per barrel on February 24, 2017, while the Henry Hub spot market price of gas was $2.63 per MMBtu on the same date. If the prices of oil and gas reverse their recent increases or decline, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected.
We have developed certain key infrastructure assets in the Bakken area of North Dakota, making us vulnerable to risks associated with conducting business in this region.
We have secured three governmental permits that enable us to withdraw water from the Missouri River and Lake Sakakawea in North Dakota and have developed and expect to develop in the future significant water infrastructure related to these permits.
Because of the key nature of these permits and water infrastructure within the Bakken, the success and profitability of our business may be disproportionately exposed to factors impacting this region. These factors include, among others: (i) the prices of, and associated costs to produce, crude oil and gas from wells in the Bakken and other regional supply and demand factors (including the generally higher cost nature of production in the Bakken compared to other major shale plays and the pricing differentials that exist in the Bakken because of transportation constraints); (ii) the amount of exploration, development and production activities of our Bakken customers and their spending on our services; (iii) our ability to keep and maintain our governmental water permits; (iv) the cost of operations and the prices we can charge our customers in this region; and (v) the availability of equipment, supplies, and labor. Although we currently have secured key permits for water in this region, if we were to lose our water rights for any reason, including termination by the government upon the occurrence of certain events, or our competitors were able to secure equivalent rights, our business could be materially harmed. In addition, our operations in the Bakken field may be adversely affected by severe weather events such as floods, blizzards, ice storms and tornadoes. For the years ended December 31, 2016 and 2015, our Bakken operations represented 9.6% and 5.5%, respectively,
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of our revenues. The concentration of our water permits and significant infrastructure assets in North Dakota also increases our exposure to changes in local laws and regulations, including those designed to protect wildlife, and unexpected events that may occur in this region such as seismic events, industrial accidents or labor difficulties. Any of the risks described above could have an adverse effect on our financial condition, results of operations and cash flows.
Restrictions on the ability to procure water or changes in water sourcing requirements could decrease the demand for our water-related services.
Our business includes water transfer for use in our customers' oil and gas exploration and production activities. Our access to the water we supply may be limited due to reasons such as prolonged drought or our inability to acquire or maintain water sourcing permits or other rights. In addition, some state and local governmental authorities have begun to monitor or restrict the use of water subject to their jurisdiction for hydraulic fracturing to ensure adequate local water supply. For instance, some states requires E&P companies to report certain information regarding the water they use for hydraulic fracturing and to monitor the quality of groundwater surrounding some wells stimulated by hydraulic fracturing. Any such decrease in the availability of water, or demand for water services, could adversely affect our business and results of operations.
We have operated at a loss in the past, and there is no assurance of our profitability in the future.
Historically, we have experienced periods of low demand for our services and have incurred operating losses. In the future, we may not be able to reduce our costs, increase our revenues or reduce our debt service obligations sufficient to achieve or maintain profitability and generate positive operating income. Under such circumstances, we may incur further operating losses and experience negative operating cash flow.
Fuel conservation measures could reduce demand for oil and natural gas which would in turn reduce the demand for our services.
Fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, prospects, results of operations and cash flows. Additionally, the increased competitiveness of alternative energy sources (such as wind, solar geothermal, tidal, fuel cells and biofuels) could reduce demand for hydrocarbons and therefore for our services, which would lead to a reduction in our revenues.
The growth of our business through acquisitions may expose us to various risks, including those relating to difficulties in identifying suitable, accretive acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements.
As a component of our business strategy, we intend to pursue selected, accretive acquisitions of complementary assets, businesses and technologies. Acquisitions involve numerous risks, including:
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unanticipated costs and assumption of liabilities and exposure to unforeseen liabilities of the acquired business, including but not limited to
environmental liabilities;
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difficulties in integrating the operations and assets of the acquired business and the acquired personnel;
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- limitations on our ability to properly assess and maintain an effective internal control environment over an acquired business;
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potential losses of key employees and customers of the acquired business;
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risks of entering markets in which we have limited prior experience; and
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- increases in our expenses and working capital requirements.
The process of integrating an acquired business may involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a significant amount time and resources. Our failure to incorporate the acquired business and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. Furthermore, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.
In addition, we may not have sufficient capital resources to complete any additional acquisitions. We may incur substantial indebtedness to finance future acquisitions and also may issue equity, debt or convertible securities in connection with such acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition and the issuance of additional equity or convertible securities could be dilutive to our existing stockholders. Furthermore, we may not be able to obtain additional financing on satisfactory terms. Even if we have access to the necessary capital, we may be unable to continue to identify suitable acquisition opportunities, negotiate acceptable terms or successfully acquire identified targets.
We may be unable to close the Permian Acquisition, or any other potential acquisition, on the terms described or at all.
There is no assurance that we will be able to close the Permian Acquisition, or any other potential acquisition. We could determine through a market analysis, a review of historical and projected financial statements of a particular company or other due diligence that the target company does not meet our investment standards. We also may be unable to come to an agreement. Additionally, there is no assurance that we will successfully close an acquisition once a purchase agreement has been signed, or that we will realize the expected benefits from any potential acquisition.
Our credit facility subjects us to various financial and other restrictive covenants. These restrictions may limit our operational or financial flexibility and could subject us to potential defaults under our credit facility.
Our credit facility subjects us to significant financial and other restrictive covenants, including restrictions on our ability to consolidate or merge with other companies, conduct asset sales, incur additional indebtedness, grant liens, issue guarantees, make investments, loans or advances, pay dividends, enter into certain transactions with affiliates and make capital expenditures in excess of specified thresholds.
Our credit facility contains certain financial covenants, including (i) the maintenance of an Interest Coverage Ratio (as such term is defined in the credit facility) of not less than (a) 1.10 to 1.0 for the quarter ending on December 31, 2016, (b) 1.25 to 1.0 for the quarter ending on March 31, 2017, (c) 1.50 to 1.0 for the quarter ending on June 30, 2017, (d) 2.50 to 1.0 for the quarter ending on September 30, 2017 and (e) 3.00 to 1.0 for each fiscal quarter ending on or after December 31, 2017 and (ii) the maintenance of a Leverage Ratio (as such term is defined in the credit facility) of not greater than (a) 4.00 to 1.0 for the quarter ending on September 30, 2017, (b) 3.50 to 1.0 for the quarter ending on December 31, 2017, (c) 3.25 to 1.0 for the quarters ending on March 31, 2018, June 30, 2018 and September 30, 2018, (d) 3.00 to 1.0 for the quarter ending December 31, 2018 and (e) 2.75 to 1.0 for each fiscal quarter ending on or after March 31, 2019. Our ability to comply with these financial condition tests can be affected by events beyond our control and we may not be able to do so. Our scheduled maturity date is February 28, 2020. In addition, our credit facility contains an
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anti-cash hoarding provision that restricts us from making any borrowing, if after giving effect to such borrowing, we would have in excess of $20 million in cash and cash equivalents at the end of the week such borrowing is made. These restrictions may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our credit facilities impose on us. For additional information regarding our credit facility, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility."
If we are unable to remain in compliance with the covenants of our credit facility, then amounts outstanding thereunder may be accelerated and become due immediately. Any such acceleration could have a material adverse effect on our financial condition and results of operations.
We may incur additional indebtedness or issue additional equity securities to execute our long-term growth strategy, which may reduce our profitability or result in significant dilution to our stockholders.
Constructing and maintaining water infrastructure used in the oil and gas industry requires significant capital. We may require additional capital in the future to develop and construct water sourcing, transfer and other related infrastructure to execute our growth strategy. For the year ended December 31, 2016 and 2015, we incurred approximately $36.3 million and $48.7 million, respectively, in capital expenditures. Historically, we have financed these investments through cash flows from operations, external borrowings and capital contributions from the Legacy Owners and Contributing Legacy Owners. These sources of capital may not be available to us in the future. In addition, our credit facility currently restricts our spending on capital expenditures (other than those funded by net proceeds from equity issuances) to $35 million for the fiscal year ending December 31, 2017 and for each year thereafter to the greater of (i) $35 million or (ii) 50% of our EBITDA for the prior twelve months and removes this restriction if the Leverage Ratio is less than 3.00 to 1.0. The maximum commitment under the credit facility is $100 million at the end of the preceding fiscal quarter. If we are unable to fund capital expenditures for any reason, we may not be able to capture available growth opportunities and any such failure could have a material adverse effect on our results of operations and financial condition. If we incur additional indebtedness or issue additional equity securities, our profitability may be reduced and our stockholders may experience significant dilution.
We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition, results of operations and cash available for distribution.
We operate with most of our customers under master service agreements, or MSAs. We endeavor to allocate potential liabilities and risks between the parties in the MSAs. Generally, under our MSAs, including those relating to our services, we assume responsibility for, including control and removal of, pollution or contamination which originates above surface and originates from our equipment or services. Our customer assumes responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling fluids. We may have liability in such cases if we are negligent or commit willful acts. Generally, our customers also agree to indemnify us against claims arising from their employees' personal injury or death to the extent that, in the case of our operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers generally agree to indemnify us for loss or destruction of customer-owned property or equipment and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. Losses due to
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catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into an MSA with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition, results of operation and cash available for distribution.
We are subject to environmental and occupational health and safety laws and regulations that may expose us to significant liabilities for penalties, damages or costs of remediation or compliance.
Our operations and the operations of our customers are subject to federal, regional, state and local laws and regulations relating to protection of natural resources and the environment, health and safety aspects of our operations and waste management, including the transportation and disposal of waste and other materials. These laws and regulations may impose numerous obligations on our operations and the operations of our customers, including the acquisition of permits to take freshwater from surface and underground sources, construct pipelines or containment facilities, drill wells or conduct other regulated activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from our facilities or from customer locations where we are providing services, the imposition of substantial liabilities for pollution resulting from our operations, and the application of specific health and safety criteria addressing worker protection. Any failure on our part or the part of our customers to comply with these laws and regulations could result in restrictions on operations, assessment of administrative, civil and criminal penalties, revocation of permits and issuance of corrective action orders requiring the performance of investigatory, remedial or curative activities.
Our business activities present risks of incurring significant environmental costs and liabilities, including costs and liabilities resulting from our handling of oilfield and other wastes, because of air emissions and wastewater discharges related to our operations, and due to historical oilfield industry operations and waste disposal practices. Our businesses include the operation of oilfield waste disposal injection wells that pose risks of environmental liability, including leakage from the wells to surface or subsurface soils, surface water or groundwater. In addition, private parties, including the owners of properties upon which we perform services and facilities where our wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. Some environmental laws and regulations may impose strict liability, which means that in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Remedial costs and other damages arising as a result of environmental laws and costs associated with changes in environmental laws and regulations could be substantial and could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
Laws and regulations protecting the environment generally have become more stringent in recent years and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. Changes in existing laws or regulations, or the adoption of new laws or regulations, could delay or curtail exploratory or developmental drilling for oil and gas and could limit well servicing opportunities. We may not be able to recover some or any of our costs of compliance with these laws and regulations from insurance.
Unsatisfactory safety performance may negatively affect our customer relationships and, to the extent we fail to retain existing customers or attract new customers, adversely impact our revenues.
Our ability to retain existing customers and attract new business is dependent on many factors, including our ability to demonstrate that we can reliably and safely operate our business and stay
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current on constantly changing rules, regulations, training and laws. Existing and potential customers consider the safety record of their service providers to be of high importance in their decision to engage third-party servicers. If one or more accidents were to occur at one of our operating sites, the affected customer may seek to terminate or cancel its use of our facilities or services and may be less likely to continue to use our services, which could cause us to lose substantial revenues. Further, our ability to attract new customers may be impaired if they elect not to purchase our third-party services because they view our safety record as unacceptable. In addition, it is possible that we will experience numerous or particularly severe accidents in the future, causing our safety record to deteriorate. This may be more likely as we continue to grow, if we experience high employee turnover or labor shortage, or add inexperienced personnel.
Federal, state and local legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the drilling and completion of oil and gas wells that may reduce demand for our services and could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from dense subsurface rock formations. The process involves the injection of water, sand and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is currently generally exempt from regulation under the U.S. Safe Drinking Water Act's (the "SDWA") Underground Injection Control ("UIC") program and is typically regulated by state oil and gas commissions or similar agencies.
However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in February 2014, the U.S. Environmental Protection Agency (the "EPA") asserted regulatory authority pursuant to the SDWA's UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. The EPA also issued final Clean Air Act ("CAA") regulations in 2012 and in June 2016 governing performance standards, including standards for the capture of emissions of methane and volatile organic compounds ("VOCs") released during hydraulic fracturing. Additionally, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants and, in May 2014, issued a prepublication of its Advance Notice of Proposed Rulemaking regarding the Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the Bureau of Land Management ("BLM") published a final rule in March 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands but, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked congressional authority to promulgate the rule. That decision is currently being appealed by the federal government. From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In the event that new federal restrictions on the hydraulic-fracturing process are adopted in areas where we or our customers conduct business, we or our customers may incur additional costs or permitting requirements to comply with such federal requirements that may be significant in nature and, in the case of our customers, could experience added delays or curtailment in the pursuit of exploration, development, or production activities, which would in turn reduce the demand for our services.
Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations, including states where we or our customers operate. For example, Texas, Oklahoma, California, Ohio, Pennsylvania and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States could also elect
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to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular, as certain local governments in California have done. Other states, such as Texas, Oklahoma and Ohio have taken steps to limit the authority of local governments to regulate oil and gas development.
In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that "water cycle" activities associated with hydraulic fracturing may impact drinking water resources "under some circumstances," noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs for our customers in the production of oil and gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and an associated decrease in demand for our services and increased compliance costs and time, which could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.
Climate change legislation or regulations restricting or regulating emissions of greenhouse gases could result in increased operating costs and reduced demand for our field services.
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration ("PSD") construction and Title V operating permit reviews for certain large stationary sources that emit certain principal, or "criteria," pollutants. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet "best available control technology" standards. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from oil and gas production, processing, transmission and storage facilities in the United States.
Congress has from time to time considered legislation to reduce emissions of GHGs but there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions through the completion of GHG emissions inventories and by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. The EPA has also developed strategies for the reduction of methane emissions, including emissions from the oil and gas industry. For example, in June 2016, the EPA published final rules establishing new emissions standards for methane and additional standards for VOCs from certain new, modified and reconstructed equipment and processes in the oil and gas source category, including production, processing, transmission and storage activities and is formally seeking additional information from E&P operators as necessary to eventually expand these final rules to include existing equipment and processes. Furthermore, the EPA passed a new rule, known as the Clean Power Plan, to
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limit GHGs from power plants. While the U.S. Supreme Court issued a stay in February 2016, preventing implementation during the pendency of legal challenges to the rule in court, should the stay be lifted and legal challenges prove unsuccessful, then it could reduce demand for the oil and gas our customers produce, which could reduce the demand for our services, depending on the methods used to implement the rule. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that proposed an agreement, requiring member countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This agreement was signed by the United States in April 2016 and entered into force in November 2016. The United States is one of over 120 nations having ratified or otherwise consented to the agreement; however this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions.
Although it is not possible at this time to predict how new laws or regulations in the United States or any legal requirements imposed following the United States' agreeing to the Paris Agreement that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or other legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our or our customers' equipment and operations could require us or our customers to incur costs to reduce emissions of GHGs associated with operations as well as delays or restrictions in the ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and gas our customers produce, which could reduce demand for our services.
Finally, it should be noted that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our operations.
Legislation or regulatory initiatives intended to address seismic activity associated with oilfield disposal wells could restrict our ability to dispose of produced water gathered from our customers and, accordingly, could have a material adverse effect on our business.
We dispose of wastewater gathered from oil and gas producing customers that results from their drilling and production operations pursuant to permits issued to us by government authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent permitting or operating constraints or new monitoring and reporting requirements owing to, among other things, concerns of the public or governmental authorities regarding such disposal activities.
One such concern relates to recent seismic events near underground disposal wells used for the disposal by injection of produced water resulting from oil and gas activities. When caused by human activity, such events are called induced seismicity. Developing research suggests that the link between seismic activity and wastewater disposal may vary by region, and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico and Arkansas. The United States Geological Survey also noted the potential for induced seismicity in Ohio and Alabama. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for wastewater disposal wells in 2014 that imposed
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certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. The Texas Railroad Commission adopted similar rules in 2014. In addition, ongoing lawsuits allege that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells. Increased regulation and attention given to induced seismicity could lead to greater opposition to oil and gas activities utilizing injection wells for waste disposal. The adoption and implementation of any new laws, regulations or directives that restrict our ability to dispose of wastewater gathered from our customers by limiting, volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.
The Endangered Species Act and Migratory Bird Treaty Act govern both our and our oil and gas producing customers' operations and additional restrictions may be imposed in the future, which constraints could have an adverse impact on our ability to expand some of our existing operations or limit our customers' ability to develop new oil and gas wells.
The Endangered Species Act (the "ESA") restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the "MBTA"). To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where we or our oil and gas producing customers' operate, both our and our customers' abilities to conduct or expand operations and construct facilities could be limited or be forced to incur material additional costs. Moreover, our customer's drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons. Some of our operations and the operations of our customers are located in areas that are designated as habitats for protected species.
In addition, as a result of a settlement approved by the U.S. District Court for the District of Columbia in 2011, the U.S. Fish & Wildlife Service (the "FWS") is required to make a determination on the listing of numerous other species as endangered or threatened under the ESA by the end of the FWS' 2017 fiscal year. The designation of previously unidentified endangered or threatened species could indirectly cause us to incur additional costs, cause our or our oil and gas producing customers' operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. The FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands.
We face significant competition that may cause us to lose market share and could negatively affect our ability to expand our operations, and we may be unable to compete effectively with larger companies.
The water solutions business is highly competitive. Some of our competitors have a similarly broad geographic scope, as well as greater financial and other resources than we do, while others focus on specific basins only and may have local competitive cost efficiencies as a result. Additionally, there may be new companies that enter the water solutions business or our existing and potential customers may develop their own water solutions businesses. Our ability to maintain current revenue and cash flows, and our ability to expand our operations, could be adversely affected by the activities of our competitors and our customers. If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to effectively compete. All of these competitive pressures could have a material adverse effect on our business, results of operations and financial condition.
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The oil and gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Many of our larger competitors provide a broader base of services on a regional, national or worldwide basis. These companies may have a greater ability to continue oilfield service activities during periods of low commodity prices, to contract for equipment, to secure trained personnel, to secure contracts and permits and to absorb the burden of present and future federal, state, local and other laws and regulations. Any inability to compete effectively with larger companies could have a material adverse impact on our financial condition and results of operations.
Our success depends on key members of our management, the loss of any of whom could disrupt our business operations.
We depend to a large extent on the services of some of our executive officers. The loss of the services of one or more of our key executives could increase our exposure to the other risks described in this "Risk Factors" section. We do not maintain key man insurance on any of our personnel other than John Schmitz, our Chairman and Chief Executive Officer.
Our industry has experienced a high rate of employee turnover. Any difficulty we experience replacing or adding personnel could have a material adverse effect on our liquidity, results of operations and financial condition.
We are dependent upon the available labor pool of skilled employees and may not be able to find enough skilled labor to meet our needs, which could have a negative effect on our growth. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. Our services require skilled workers who can perform physically demanding work. As a result of our industry volatility, including the recent and pronounced decline in drilling activity, as well as the demanding nature of the work, many workers have left the oilfield services section to pursue employment in different fields. If we are unable to retain or meet growing demand for skilled technical personnel, our operating results and our ability to execute our growth strategies may be adversely affected.
Delays or restrictions in obtaining permits by us for our operations or by our customers for their operations could impair our business.
In most states, our operations and the operations of our oil and gas producing customers require permits from one or more governmental agencies in order to perform drilling and completion activities, secure water rights, construct impoundments tanks and operate pipelines or trucking services. Such permits are typically issued by state agencies, but federal and local governmental permits may also be required. The requirements for such permits vary depending on the location where such drilling and completion, and pipeline and gathering, activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, the conditions that may be imposed in connection with the granting of the permit and whether the permit may be terminated. In addition, some of our customers' drilling and completion activities may take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities. Under certain circumstances, federal agencies may cancel proposed leases for federal lands and refuse to grant or delay required approvals. Therefore, our customers' operations in certain areas of the United States may be interrupted or suspended for varying lengths of time, causing a loss of revenue to us and adversely affecting our results of operations in support of those customers.
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In the future we may face increased obligations relating to the closing of our wastewater disposal facilities and may be required to provide an increased level of financial assurance to guarantee that the appropriate closure activities will occur for a wastewater disposal facility.
Obtaining a permit to own or operate wastewater disposal facilities generally requires us to establish performance bonds, letters of credit or other forms of financial assurance to address remediation and closure obligations. As we acquire additional wastewater disposal facilities or expand our existing wastewater disposal facilities, these obligations will increase. Additionally, in the future, regulatory agencies may require us to increase the amount of our closure bonds at existing wastewater disposal facilities. Moreover, actual costs could exceed our current expectations, as a result of, among other things, federal, state or local government regulatory action, increased costs charged by service providers that assist in closing wastewater disposal facilities and additional environmental remediation requirements. Increased regulatory requirements regarding our existing or future wastewater disposal facilities, including the requirement to pay increased closure and post-closure costs or to establish increased financial assurance for such activities could substantially increase our operating costs and cause our available cash that we have to distribute to our unitholders to decline.
Constraints in the supply of equipment used in providing services to our customers and replacement parts for such could affect our ability to execute our growth strategies.
Equipment used in providing services to our customers is normally readily available. Market conditions could trigger constraints in the supply chain of certain equipment or replacement parts for such equipment, which could have a material adverse effect on our business. The majority of our risk associated with supply chain constraints occurs in those situations where we have a relationship with a single supplier for a particular resource.
Technology advancements in well service technologies, including those involving recycling of saltwater or the replacement of water in fracturing fluid, could have a material adverse effect on our business, financial condition and results of operations.
The oilfield services industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. The saltwater disposal industry is subject to the introduction of new waste treatment and disposal techniques and services using new technologies including those involving recycling of saltwater, some of which may be subject to patent protection. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. For example, some oil and gas producers are focusing on developing and utilizing non-water fracturing techniques, including those utilizing propane, carbon dioxide or nitrogen instead of water. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or products at all, on a timely basis or at an acceptable cost. New technology could also make it easier for our customers to vertically integrate their operations or reduce the amount of waste produced in oil and gas drilling and production activities, thereby reducing or eliminating the need for third-party disposal. Limits on our ability to effectively use or implement new technologies may have a material adverse effect on our business, financial condition and results of operations.
We may be adversely affected by uncertainty in the global financial markets and the continuing worldwide economic downturn.
Our future results may be impacted by the continuing uncertainty caused by the worldwide economic downturn, continued volatility or deterioration in the debt and equity capital markets,
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inflation, deflation or other adverse economic conditions that may negatively affect us or parties with whom we do business resulting in a reduction in our customers' spending and their non-payment or inability to perform obligations owed to us, such as the failure of customers to honor their commitments or the failure of major suppliers to complete orders. Additionally, credit market conditions may change slowing our collection efforts as customers may experience increased difficulty in obtaining requisite financing, potentially leading to lost revenue and higher than normal accounts receivable. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense to us.
The current global economic environment may adversely impact our ability to issue debt. A continuation of the economic uncertainty may cause institutional investors to respond to their borrowers by increasing interest rates, enacting tighter lending standards or refusing to refinance existing debt upon its maturity or on terms similar to the expiring debt. However, due to the above listed factors, we cannot be certain that additional funding will be available if needed and, to the extent required, on acceptable terms.
Our operations are subject to inherent risks, some of which are beyond our control. These risks may be self-insured, or may not be fully covered under our insurance policies.
Our operations are subject to hazards inherent in the oil and gas industry, such as, but not limited to, accidents, blowouts, explosions, craterings, fires, oil spills and releases of drilling, completion or fracturing fluids or wastewater into the environment. These conditions can cause:
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disruption in operations;
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substantial repair or remediate costs;
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personal injury or loss of human life;
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significant damage to or destruction of property, and equipment;
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environmental pollution, including groundwater contamination;
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impairment or suspension of operations; and
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- substantial revenue loss.
The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition. Any interruption in our services due to pipeline breakdowns or necessary maintenance or repairs could reduce sales revenues and earnings. In addition, claims for loss of oil and gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in our being named as a defendant in lawsuits asserting large claims.
We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against or the failure of an insurer to meet its insurance obligations could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive.
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The deterioration of the financial condition of our customers could adversely affect our business.
During times when the gas or crude oil markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers' spending for our services. In addition, in the course of our business we hold accounts receivable from our customers. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense or loss of expected revenues to us.
We may be required to take write-downs of the carrying values of our long-lived assets.
We evaluate our long-lived assets, such as property and equipment, for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Recoverability is measured by a comparison of their carrying amount to the estimated undiscounted cash flows to be generated by those assets. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, economics and other factors, we may be required to write down the carrying value of our long-lived and other intangible assets. We recorded an impairment of $60.03 million on our long-lived assets for the year ended December 31, 2016.
Seasonal weather conditions and natural disasters could severely disrupt normal operations and harm our business.
Our Water Solutions operations are located primarily in the southern, mid-western and eastern United States. These areas are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. Additionally, extended drought conditions in our operating regions could impact our ability to source sufficient water for our customers or increase the cost for such water. As a result, a natural disaster or inclement weather conditions could severely disrupt the normal operation of our business and adversely impact our financial condition and results of operations.
We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
The oil and gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and to process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks.
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A terrorist attack or armed conflict could harm our business.
The occurrence or threat of terrorist attacks in the United States or other countries, anti-terrorist efforts and other armed conflicts involving the United States or other countries, including continued hostilities in the Middle East, may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers' operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
We engage in transactions with related parties and such transactions present possible conflicts of interest that could have an adverse effect on us.
We have entered into a significant number of transactions with related parties. The details of certain of these transactions are set forth in the section "Certain Relationships and Related Party Transactions." Related party transactions create the possibility of conflicts of interest with regard to our management. Such a conflict could cause an individual in our management to seek to advance his or her economic interests above ours. Further, the appearance of conflicts of interest created by related party transactions could impair the confidence of our investors. Our board of directors regularly reviews these transactions. Notwithstanding this, it is possible that a conflict of interest could have a material adverse effect on our liquidity, results of operations and financial condition.
The adoption of more stringent trucking legislation or regulations may increase our costs and could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.
In connection with the services we provide, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation (the "U.S. DOT"), and by analogous state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible legislative and regulatory changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations and changes in the regulations that govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.
Interstate motor carrier operations are subject to safety requirements developed and implemented by the U.S. DOT. Intrastate motor carrier operations often are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state laws and regulations.
From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes, including taxes on motor fuels, which may increase our costs or adversely affect the recruitment of drivers. Management cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted. We may be required to increase operating expenses or capital expenditures in order to comply with any new laws, regulations or other restrictions.
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Disruptions in the transportation services of trucking companies transporting wastewater could have a material adverse effect on our results.
We use trucks to transport some produced water to our wastewater disposal facilities. In recent years, certain states, such as North Dakota and Texas, and state counties have increased enforcement of weight limits on trucks used to transport raw materials on their public roads. It is possible that the states, counties and cities in which we operate our business may modify their laws to further reduce truck weight limits or impose curfews or other restrictions on the use of roadways. Such legislation and enforcement efforts could result in delays in, and increased costs to, transport produced water to our wastewater disposal facilities, which may either increase our operating costs or reduce the amount of produced water transported to our facilities. Such developments could decrease our operating margins or amounts of produced water disposed at our wastewater disposal facilities and thereby have a material adverse effect on our results of operations and financial condition.
A significant increase in fuel prices may adversely affect our transportation costs, which could have a material adverse effect on our results of operations and financial condition.
Fuel is one of our significant operating expenses, and a significant increase in fuel prices could result in increased transportation costs. The price and supply of fuel is unpredictable and fluctuates based on events such as geopolitical developments, supply and demand for oil and gas, actions by oil and gas producers, war and unrest in oil producing countries and regions, regional production patterns and weather concerns. A significant increase in fuel prices could increase the price of, and therefore reduce demand for, our services, which could affect our results of operations and financial condition.
Risks Relating to the Offering and our Class A Common Stock
The initial public offering price of our Class A common stock may not be indicative of the market price of our Class A common stock after this offering. In addition, an active, liquid and orderly trading market for our Class A common stock may not develop or be maintained, and our stock price may be volatile.
Prior to this offering, our Class A common stock was not traded on any market. An active, liquid and orderly trading market for our Class A common stock may not develop or be maintained after this offering. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors' purchase and sale orders. The market price of our Class A common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our Class A common stock, you could lose a substantial part or all of your investment in our Class A common stock. The initial public offering price will be negotiated between us, the selling shareholders and representatives of the underwriters, based on numerous factors which we discuss in "Underwriting," and may not be indicative of the market price of our Class A common stock after this offering. Consequently, you may not be able to sell shares of our Class A common stock at prices equal to or greater than the price paid by you in this offering.
The following factors could affect our stock price:
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quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;
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the public reaction to our press releases, our other public announcements and our filings with the SEC;
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strategic actions by our competitors;
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changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;
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- speculation in the press or investment community;
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the failure of research analysts to cover our Class A common stock;
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sales of our Class A common stock by us, the selling shareholders or other shareholders, or the perception that such sales may occur;
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changes in accounting principles, policies, guidance, interpretations or standards;
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additions or departures of key management personnel;
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actions by our shareholders;
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general market conditions, including fluctuations in commodity prices;
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domestic and international economic, legal and regulatory factors unrelated to our performance; and
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- the realization of any risks describes under this "Risk Factors" section.
The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Class A common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company's securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management's attention and resources and harm our business, operating results and financial condition.
We do not expect to pay any dividends to the holders of the Class A common stock offered hereby in the foreseeable future and the availability and timing of future dividends, if any, is uncertain.
We expect to use any free cash flow from future operations to support the growth of our business, including the repayment of our debt, and do not expect to declare or pay any dividends on our Class A common stock in the foreseeable future. Our credit facility places certain restrictions on the ability of us and our subsidiaries to pay dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your Class A common stock at a price greater than you paid for it. There is no guarantee that the price of our Class A common stock that will prevail in the market will ever exceed the price that you pay in this offering. We may amend our credit facility or enter into new debt arrangements that also prohibit or restrict our ability to pay dividends on our Class A common stock.
Subject to such restrictions, our board of directors will determine the amount and timing of stockholder dividends, if any, that we may pay in future periods. In making this determination, our directors will consider all relevant factors, including the amount of cash available for dividends, capital expenditures, covenants, prohibitions or limitations with respect to dividends, applicable law, general operational requirements and other variables. We cannot predict the amount or timing of any future dividends you may receive, and if we do commence the payment of dividends, we may be unable to pay, maintain or increase dividends over time. Therefore, you may not be able to realize any return on your investment in our Class A common stock for an extended period of time, if at all.
Investors in this offering will experience immediate and substantial dilution of $ per share.
Based on an assumed initial public offering price of $ per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of our Class A common stock in this offering will experience an immediate and substantial dilution of $ per share in the as adjusted net tangible book value per share of Class A common stock from the initial public offering price, and our as adjusted net tangible book value as of December 31, 2016 after giving effect to this offering would be
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$ per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. See "Dilution."
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential shareholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A common stock.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. We are not currently required to comply with the SEC's rules implementing Section 404 of the Sarbanes Oxley Act and therefore are not required to make a formal assessment of the effectiveness of our internal controls over financial reporting for that purpose. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Sections 302 and 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A common stock.
Since we expect to be a "controlled company" for purposes of the corporate governance requirements of the NYSE, our stockholders will not have, and may never have, the protections that these corporate governance requirements are intended to provide.
Since we expect to be a "controlled company" for purposes of the corporate governance requirements of the NYSE, we are not required to comply with the provisions requiring that a majority of our directors be independent, the compensation of our executives be determined by independent directors or nominees for election to our board of directors be selected by independent directors. If we choose to take advantage of any or all of these exemptions, our stockholders may not have the protections that these rules are intended to provide.
Since we expect to be an "emerging growth company," we will not be required to comply with certain disclosure requirements that are applicable to other public companies and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our Class A common stock less attractive to investors.
We expect to be an "emerging growth company," as defined in the JOBS Act and we may take advantage of certain exemptions from various reporting requirements that are applicable to public companies, including, but not limited to, longer phase-in periods for the adoption of new or revised financial accounting standards, not being required to comply with the auditor attestation requirements of Section 404 of Sarbanes-Oxley, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. We intend to take advantage of all of the reduced reporting requirements and exemptions, including the longer phase-in periods for the adoption of new or revised financial accounting standards under Section 107 of the JOBS Act, until we are no longer an emerging growth company. Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. If we were to
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subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act.
We cannot predict if investors will find our Class A common stock less attractive because we will rely on these exemptions. If some investors find our Class A common stock less attractive as a result, there may be a less active trading market for our Class A common stock and our Class A common stock price may be more volatile. Under the JOBS Act, "emerging growth companies" can delay adopting new or revised accounting standards until such time as those standards apply to private companies.
We will incur increased costs as a result of becoming a public company.
As a privately held company, we were not responsible for the corporate governance and financial reporting practices and policies required of a public company. Following the completion of this offering, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of Sarbanes-Oxley, related regulations of the SEC and the requirements of the NYSE, with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:
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institute a more comprehensive compliance function;
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comply with rules promulgated by the NYSE;
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prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
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establish new internal policies, such as those relating to disclosure controls and procedures and insider trading; and
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- involve and retain to a greater degree outside counsel and accountants in the above activities.
In addition, we expect that being a public company subject to these rules and regulations will require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers.
Certain of our directors and senior management have limited experience managing public companies, which could adversely affect our financial position.
Certain members of our senior management and certain of our directors have not previously managed a publicly traded operating company and may be unsuccessful in doing so. The demands of managing a publicly traded company are significant, and some members of our senior management or board of directors may not be able to meet these increased demands. Failure to effectively manage our business could adversely affect our overall financial position.
Future sales of our equity securities, or the perception that such sales may occur, may depress our share price, and any additional capital raised through the sale of equity or convertible securities may dilute your ownership in us.
Subject to certain limitations and exceptions, Legacy Owner Holdco and its permitted transferees may exchange their SES Holdings LLC Units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock (on a one-for-one basis, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions) and then sell those shares of Class A common stock. In addition, the 16,100,000 shares of
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our Class A-1 Common Stock issued in the 144A Offering will automatically convert to Class A common stock upon the effectiveness of a registration statement filed to permit resales of such shares. The investors in our 144A Offering are entitled to sell such shares 60 days following the closing of this offering. Additionally, we may in the future issue our previously authorized and unissued securities. We are authorized to issue 250 million shares of Class A common stock, 40 million shares of Class A-1 common stock, 150 million shares of Class B common stock and 50 million shares of preferred stock with such designations, preferences and rights as determined by our board of directors. The potential issuance of such additional shares of equity securities will result in the dilution of the ownership interests of the holders of our Class A common stock and may create downward pressure on the trading price, if any, of our Class A common stock. The registration rights of our Legacy Owners and the investors in the 144A Offering and the sales of substantial amounts of our Class A common stock following the effectiveness of the shelf registration statements for the benefit of our Legacy Owners or investors in the 144A Offering, or the perception that these sales may occur, could cause the market price of our Class A common stock to decline and impair our ability to raise capital. We also may grant additional registration rights in connection with any future issuance of our capital stock.
The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our Class A common stock.
Our stockholders, directors and executive officers have entered into lock-up agreements with respect to their equity securities of the Company. As restrictions on resale end, the market price of our stock could decline if the holders of restricted shares sell them or are perceived by the market as intending to sell them. , at any time and without notice, may release all or any portion of the equity securities subject to the foregoing lock-up agreements entered into in connection with this offering. Investors in the 144A Offering have entered into lock-up agreements which expire 60 days from the closing of this offering. FBR, at any time and without notice, may release all or any portion of the equity securities subject to the foregoing lock-up agreements entered into in connection with the 144A Offering. If the restrictions under the lock-up agreements are waived, our Class A common stock will be available for sale into the market, which could reduce the market value for our Class A common stock. The lockup agreements entered into in connection with the 144A Offering contain an exception permitting us to issue shares of Class A common stock in connection with acquisitions in an amount up to 19.9 percent of the outstanding voting power at the time of such issuance, provided that the recipient executes a similar lockup agreement. The issuance of such shares of Class A common stock would ultimately be dilutive to the holders of shares of Class A common stock acquired in this offering.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A common stock or if our operating results do not meet their expectations, the share price for our Class A common stock could decline.
The trading market for our Class A common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our Company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause the price or trading volume of our Class A common stock to decline. Moreover, if one or more of the analysts who cover our company downgrades our Class A common stock or if our operating results do not meet their expectations, the share price of our Class A common stock could decline.
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Provisions in our certificate of incorporation and bylaws and Delaware law may discourage a takeover attempt even if a takeover might be beneficial to our stockholders.
Provisions contained in our certificate of incorporation and bylaws, in each case as amended and restated as of the date on which this offering is completed, could make it more difficult for a third party to acquire us after we have become a publicly traded company. Provisions of our certificate of incorporation and bylaws impose various procedural and other requirements, which could make it more difficult for stockholders to effect certain corporate actions. For example, our certificate of incorporation authorizes our board of directors to determine the rights, preferences, privileges and restrictions of unissued series of preferred stock without any vote or action by our stockholders. Thus, our board of directors can authorize and issue shares of preferred stock with voting or conversion rights that could adversely affect the voting or other rights of holders of our capital stock. These rights may have the effect of delaying or deterring a change of control of our company. Additionally, our bylaws establish limitations on the removal of directors and on the ability of our stockholders to call special meetings and include advance notice requirements for nominations for election to our board of directors and for proposing matters that can be acted upon at stockholder meetings.
In addition, after we cease to be a controlled company, a classified board of directors will be established, so that only approximately one-third of our directors will be elected each year. See "Description of Capital Stock—Anti-Takeover Effects of Provisions of Our Certificate of Incorporation, Our Bylaws and Delaware Law." These provisions could limit the price that certain investors might be willing to pay in the future for shares of our Class A common stock.
In addition, certain change of control events have the effect of accelerating the payment due under our Tax Receivable Agreements, which could be substantial and accordingly serve as a disincentive to a potential acquirer of our company. See "Risks Related to Our Internal Reorganization and Resulting Structure—In certain cases, payments under the Tax Receivable Agreements may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreements."
Legacy Owner Holdco controls a significant percentage of our voting power.
Legacy Owner Holdco beneficially owns 100% of our Class B common stock, and upon completion of this offering, the Class B common stock will represent approximately % of our outstanding voting capital stock. See "Organizational Structure" and "Summary—Organization." In addition, certain of our directors are currently employed by Crestview Partners, our private equity sponsor and the manager of funds that hold the largest equity interest in Legacy Owner Holdco. Other funds controlled by Crestview GP also owns all of our currently outstanding shares of our Class A common stock, representing an additional % of our outstanding voting capital. Collectively, these holders control approximately % of our voting shares after completion of this offering. Holders of Class A common stock and Class B common stock generally will vote together as a single class on all matters presented to our stockholders for their vote or approval. Consequently, Legacy Owner Holdco will have control over all matters that require approval by our stockholders, including the election and removal of directors, changes to our organizational documents and approval of acquisition offers and other significant corporate transactions. This concentration of ownership will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial. So long as Legacy Owner Holdco continues to own a significant amount of our outstanding voting capital stock, even if such amount is less than 50%, it will continue to be able to strongly influence all matters requiring stockholder approval, regardless of whether or not other stockholders believe that a transaction is in their own best interests.
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Our amended and restated certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities, which could adversely affect our business or prospects.
Our amended and restated certificate of incorporation provides that, to the fullest extent permitted by applicable law, we renounce any interest or expectancy in any business opportunity that involves any aspect of the energy business or industry and that may be from time to time presented to any member of Legacy Owner Holdco, Crestview Partners or any affiliates of Crestview GP, B-29 Investments, LP, Sunray Capital, LP and Proactive Investments, LP (the "Legacy Group") or any director or officer of the corporation who is also an employee, partner, member, manager, officer or director of any member of the Legacy Group, including our Chief Executive Officer, John Schmitz, and our President, Cody Ortowski, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so. Mr. Schmitz controls both B-29 Investments LP and Sunray Capital, LP and is a direct and indirect beneficiary of these provisions in our Articles of Incorporation. Our amended and restated certificate of incorporation further provides that no such person or party shall be liable to us by reason of the fact that such person pursues any such business opportunity, or fails to offer any such business opportunity to us.
As a result, any member of the Legacy Group or any director or officer of the corporation who is also an employee, partner, member, manager, officer or director of any member of the Legacy Group may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, by renouncing our interest and expectancy in any business opportunity that may be from time to time presented to any member of the Legacy Group or any director or officer of the corporation who is also an employee, partner, member, manager, officer or director of any member of the Legacy Group, our business or prospects could be adversely affected if attractive business opportunities are procured by such parties for their own benefit rather than for ours. See "Certain Relationships and Related Party Transactions."
A significant reduction by Crestview of its ownership interests in us could adversely affect us.
We believe that Crestview's ownership interests in us provides it with an economic incentive to assist us to be successful. Upon the expiration or earlier waiver of the lock-up restrictions on transfers or sales of our securities following the completion of this offering, Crestview will not be subject to any obligation to maintain its ownership interest in us and may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If Crestview sells all or a substantial portion of its ownership interest in us, it may have less incentive to assist in our success and its affiliate(s) that are expected to serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations.
We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A common stock.
Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our shareholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto
43
specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A common stock.
Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders' ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the "DGCL"), our amended and restated certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder's ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
Risks Related to Our Organizational Structure
We are a holding company. Our sole material asset will be our equity interest in SES Holdings, and accordingly, we will be dependent upon distributions and payments from SES Holdings to pay taxes, make payments under the Tax Receivable Agreements and cover our corporate and other overhead expenses.
We are a holding company and have no material assets other than our equity interest in SES Holdings. Please see "Organizational Structure." We will have no independent means of generating revenue. To the extent SES Holdings has available cash, we intend to cause SES Holdings to make (i) generally pro rata distributions to its unitholders, including us, in an amount at least sufficient to allow us to pay our taxes and to make payments under the Tax Receivable Agreements we entered into with the TRA Holders and any subsequent tax receivable agreements that we may enter into in connection with future acquisitions and (ii) non-pro rata payments to us to reimburse us for our corporate and other overhead expenses. We will be limited, however, in our ability to cause SES Holdings and its subsidiaries to make these and other distributions or payments to us due to certain limitations, including the restrictions under our credit facility and the cash requirements and financial condition of SES Holdings. To the extent that we need funds and SES Holdings or its subsidiaries are restricted from making such distributions or payments under applicable law or regulations or under the terms of their financing arrangements or are otherwise unable to provide such funds, our liquidity and financial condition could be adversely affected.
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We will be required to make payments under the Tax Receivable Agreements for certain tax benefits we may claim, and the amounts of such payments could be significant.
In connection with the 144A Offering, we entered into two Tax Receivable Agreements which generally provide for the payment by us to the TRA Holders of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax that we actually realize (computed using simplifying assumptions to address the impact of state and local taxes) or are deemed to realize in certain circumstances as a result of certain tax basis increases, net operating losses available to us as a result of certain reorganization transactions entered into in connection with the 144A Offering, and certain tax benefits attributable to imputed interest. We will retain the benefit of the remaining 15% of these cash savings.
The term of each Tax Receivable Agreement commenced upon the completion of the 144A Offering and will continue until all tax benefits that are subject to such Tax Receivable Agreement have been utilized or expired, unless we exercise our right to terminate the Tax Receivable Agreements (or the Tax Receivable Agreements are terminated due to other circumstances, including our breach of a material obligation thereunder or certain mergers or other changes of control) and we make the termination payment specified in the Tax Receivable Agreements. In addition, payments we make under the Tax Receivable Agreements will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return. In the event that the Tax Receivable Agreements are not terminated and we have sufficient taxable income to utilize all of the tax benefits subject to the Tax Receivable Agreements, the payments due under the Tax Receivable Agreement entered into with Legacy Owner Holdco and Crestview GP are expected to commence in late 2017 and to continue for 20 years after the date of the last exchange of SES Holdings LLC Units, and the payments due under the Tax Receivable Agreement entered into with an affiliate of the Contributing Legacy Owners are expected to commence in late 2017 and to continue for five taxable years following the 144A Offering.
The payment obligations under the Tax Receivable Agreements are our obligations and not obligations of SES Holdings, and we expect that the payments we will be required to make under the Tax Receivable Agreements will be substantial. Estimating the amount and timing of payments that may become due under the Tax Receivable Agreements is by its nature imprecise. For purposes of the Tax Receivable Agreements, cash savings in tax generally will be calculated by comparing our actual tax liability (using the actual applicable U.S. federal income tax rate and an assumed combined state and local income and franchise tax rate) to the amount we would have been required to pay had we not been able to utilize any of the tax benefits subject to the Tax Receivable Agreements. The amounts payable, as well as the timing of any payments, under the Tax Receivable Agreements are dependent upon future events and significant assumptions, including the timing of the exchanges of SES Holdings LLC Units, the market price of our Class A common stock at the time of each exchange (since such market price will determine the amount of tax basis increases resulting from the exchange), the extent to which such exchanges are taxable transactions, the amount of the exchanging unitholder's tax basis in its SES Holdings LLC Units at the time of the relevant exchange, the depreciation and amortization periods that apply to the increase in tax basis, the amount of net operating losses available to us as a result of reorganization transactions entered into in connection with the 144A Offering, the amount and timing of taxable income we generate in the future, the U.S. federal income tax rate then applicable, and the portion of our payments under the Tax Receivable Agreements that constitute imputed interest or give rise to depreciable or amortizable tax basis.
Certain of the TRA Holders' rights under the Tax Receivable Agreements are transferable in connection with a permitted transfer of SES Holdings LLC Units or if the TRA Holder no longer holds SES Holdings LLC Units. The payments under the Tax Receivable Agreements will not be conditioned upon the continued ownership interest in either SES Holdings or us of any holder of rights under the Tax Receivable Agreements. Please read "Certain Relationships and Related Party Transactions—Tax Receivable Agreements."
45
In certain cases, payments under the Tax Receivable Agreements may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreements.
If we elect to terminate the Tax Receivable Agreements early or they are terminated early due to our failure to honor a material obligation thereunder or due to certain mergers, asset sales, other forms of business combinations or other changes of control, our obligations under the Tax Receivable Agreements would accelerate and we would be required to make an immediate payment equal to the present value of the anticipated future payments to be made by us under the Tax Receivable Agreements (determined by applying a discount rate of the lesser of 6.50% per annum, compounded annually, or one-year LIBOR plus 100 basis points); and such payment is expected to be substantial. The calculation of anticipated future payments will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreements, including (i) the assumption that we have sufficient taxable income to fully utilize the tax benefits covered by the Tax Receivable Agreements, (ii) the assumption that any SES Holdings LLC Units (other than those held by us) outstanding on the termination date are exchanged on the termination date and (iii) certain loss or credit carryovers will be utilized in the taxable year that includes the termination date. Any early termination payment may be made significantly in advance of the actual realization, if any, of the future tax benefits to which the termination payment relates.
As a result of either an early termination or a change of control, we could be required to make payments under the Tax Receivable Agreements that exceed our actual cash tax savings under the Tax Receivable Agreements. In these situations, our obligations under the Tax Receivable Agreements could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales or other forms of business combinations or changes of control. For example, if the Tax Receivable Agreements were terminated immediately after this offering, the estimated termination payments would, in the aggregate, be approximately $ million (calculated using a discount rate equal to the lesser of 6.50% per annum, compounded annually, or one-year LIBOR plus 100 basis points, applied against an undiscounted liability of $ million). The foregoing number is merely an estimate and the actual payment could differ materially. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreements.
Payments under the Tax Receivable Agreements will be based on the tax reporting positions that we will determine. The TRA Holders will not reimburse us for any payments previously made under the Tax Receivable Agreements if any tax benefits that have given rise to payments under the Tax Receivable Agreements are subsequently disallowed, except that excess payments made to the TRA Holders will be netted against payments that would otherwise be made to the TRA Holders, if any, after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.
Please read "Certain Relationships and Related Party Transactions—Tax Receivable Agreements."
If SES Holdings were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, we and SES Holdings might be subject to potentially significant tax inefficiencies, and we would not be able to recover payments previously made by us under the Tax Receivable Agreements even if the corresponding tax benefits were subsequently determined to have been unavailable due to such status.
We intend to operate such that SES Holdings does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A "publicly traded partnership" is a partnership, the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, exchanges of SES Holdings LLC Units pursuant to an Exchange Right (or our Call Right) or other transfers of SES
46
Holdings LLC Units could cause SES Holdings to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that exchanges or other transfers of SES Holdings LLC Units qualify for one or more such safe harbors. For example, we intend to limit the number of unitholders of SES Holdings and Legacy Owner Holdco, and the SES Holdings LLC Agreement, provides for limitations on the ability of unitholders of SES Holdings to transfer their SES Holdings LLC Units and will provide us, as managing member of SES Holdings, with the right to impose restrictions (in addition to those already in place) on the ability of unitholders of SES Holdings to exchange their SES Holdings LLC Units pursuant to an Exchange Right to the extent we believe it is necessary to ensure that SES Holdings will continue to be treated as a partnership for U.S. federal income tax purposes.
If SES Holdings were to become a publicly traded partnership, significant tax inefficiencies might result for us and for SES Holdings. In addition, we may not be able to realize tax benefits covered under the Tax Receivable Agreements, and we would not be able to recover any payments previously made by us under the Tax Receivable Agreements, even if the corresponding tax benefits (including any claimed increase in the tax basis of SES Holdings' assets) were subsequently determined to have been unavailable.
The sale or exchange of 50% or more of the capital and profits interests of SES Holdings during any twelve-month period will result in the termination of the SES Holdings partnership for U.S. federal income tax purposes, which could result in significant deferral of depreciation deductions allowable in computing our taxable income.
SES Holdings will be considered to have terminated its partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in its capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Among other consequences, the termination of SES Holdings for U.S. federal income tax purposes could result in a significant deferral of depreciation deductions allowable in computing SES Holdings' taxable income, including the taxable income of SES Holdings that is allocable to us. The termination of SES Holdings would not affect its classification as a partnership for U.S. federal income tax purposes, but it would result in its being treated as a new partnership for U.S. federal income tax purposes following the termination.
Legacy Owner Holdco and the Legacy Owners have interests that conflict with holders of shares of our Class A common stock.
Immediately following this offering, Legacy Owner Holdco will own approximately % of the outstanding SES Holdings LLC Units. Because it holds a portion of its ownership interest in our business in the form of direct ownership interests in SES Holdings rather than through us, Legacy Owner Holdco may have conflicting interests with holders of shares of Class A common stock. For example, Legacy Owner Holdco may have different tax positions from us, and decisions we make in the course of running our business, such as with respect to mergers, asset sales, other forms of business combinations or other changes in control, may affect the timing and amount of payments that are received by the TRA Holders under the Tax Receivable Agreements. See "Certain Relationships and Related Party Transactions—Tax Receivable Agreements" and "Summary—Our Relationship with Crestview Partners."
The fact that Legacy Owner Holdco will have voting control over all matters that require the approval of our stockholders amplifies the potential risks to our company and our other stockholders relating to the conflicts of interest described above.
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The information in this prospectus includes "forward-looking statements." All statements, other than statements of historical fact, included in this prospectus regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words "could," "believe," "anticipate," "intend," "estimate," "expect," "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading "Risk Factors" included in this prospectus. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:
- •
-
the level of capital spending by domestic oil and gas companies;
- •
-
trends and volatility in oil and gas prices;
- •
-
demand for our services;
- •
-
regional impacts to our business, including our key infrastructure assets within the Bakken;
- •
-
our level of indebtedness and our ability to comply with covenants contained in our credit facility or future debt instruments;
- •
-
our access to capital to fund expansions, acquisitions and our working capital needs and our ability to obtain debt or equity financing on
satisfactory terms;
- •
-
our safety performance;
- •
-
the impact of current and future laws, rulings and governmental regulations, including those related to hydraulic fracturing, accessing water,
disposing of wastewater and various environmental matters;
- •
-
our ability to retain key management and employees;
- •
-
the impacts of competition on our operations;
- •
-
our ability to hire and retain skilled labor;
- •
-
delays or restrictions in obtaining permits by us or our competitors;
- •
-
constraints in supply or availability of equipment used in our business;
- •
-
the impacts of advancements in drilling and well service technologies;
- •
-
changes in global economic conditions, generally, and in the markets we serve;
- •
-
accidents, weather, seasonality or other events affecting our business; and
- •
- the other risks identified in this prospectus including, without limitation, those under the headings "Risk Factors," "Business," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Certain Relationships and Related Party Transactions."
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These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors also could have material adverse effects on our future results. Our future results will depend upon various other risks and uncertainties, including those described elsewhere in this prospectus under the heading, "Risk Factors." Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. All forward-looking statements attributable to us are qualified in their entirety by this cautionary statement.
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We estimate that our net proceeds from this offering, assuming an initial public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus) and after deducting the underwriters' discount and estimated offering expenses payable by us will be approximately $ million, assuming the over-allotment option is not exercised. We intend to contribute all of the net proceeds received by us to SES Holdings in exchange for SES Holdings LLC Units. SES Holdings intends to use the net proceeds in the following manner: (i) up to $51 million will be used to repay borrowings incurred under our credit facility to fund the cash portion of the purchase price of the Permian Acquisition; (ii) $10.7 million will be used for the cash settlement of outstanding phantom units at SES Holdings; (iii) approximately $5 million will be used for growth capital expenditures in the Bakken, including the expansion of the Bakken Pipeline systems; and (iv) the balance will be used for general corporate purposes, including other organic and acquisition growth opportunities.
The underwriters have an option to purchase up to an additional shares of our Class A common stock at the offering price less the underwriting discount, as applicable, within 30 days after the date of this prospectus to cover over-allotments, if any. Exercise of this option in full would result in additional net proceeds to us of approximately $ million.
A $1.00 increase or decrease in the assumed initial public offering price of $ per share would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses, received by us to increase or decrease, respectively, by approximately $ million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus remains the same. If the proceeds increase due to a higher initial public offering price or due to the issuance of additional shares, we would contribute the additional net proceeds received by us to SES Holdings in exchange for SES Holdings LLC Units. SES Holdings intends to use the additional net proceeds for general corporate purposes. If the proceeds decrease due to a lower initial public offering price or a decrease in the number of shares issued, then we would decrease the amount of net proceeds contributed to SES Holdings and SES Holdings would reduce by a corresponding amount the net proceeds directed to general corporate purposes. Any reduction in net proceeds may cause us to need to borrow additional funds under our credit facilities to fund our operations, which would increase our interest expense and decrease our net income.
We will not receive any of the proceeds from the sale of shares of our Class A common stock by the selling shareholders. We will pay all expenses related to this offering, other than underwriting discounts and commissions related to the shares sold by the selling shareholders.
Affiliates of certain of the underwriters are lenders under our credit facility and, accordingly, such affiliates may receive a portion of the net proceeds from this offering. See "Underwriting."
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We do not anticipate declaring or paying any cash dividends to holders of our Class A common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations and financial condition, capital requirements, business prospects, statutory and contractual restrictions on our ability to pay dividends, including restrictions contained in our credit agreement and other factors our board of directors may deem relevant.
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The following table shows our cash and cash equivalents and capitalization as of December 31, 2016:
- •
-
on an actual basis; and
- •
- on an as adjusted basis to give effect to (i) this offering at an assumed initial offering price of $ per share (which is the midpoint of the range set forth on the cover of this prospectus) and (ii) the application of the net proceeds, after deducting the estimated underwriters' discount and estimated offering expenses payable by us, as set forth in "Use of Proceeds." You should refer to "Use of Proceeds," "Selected Consolidated Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the financial statements contained in the F-pages to this prospectus in evaluating the material presented below.
|
|
December 31, 2016 | ||||||
|---|---|---|---|---|---|---|---|
|
|
Actual | As Adjusted | |||||
|
|
(In thousands)
|
||||||
|
Cash and cash equivalents |
$ | 40,041 | $ | ||||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
|
Long-term debt, including current maturities: |
|||||||
|
Credit Facility(1) |
— | — | |||||
| | | | | | | | |
|
Total long-term debt |
— | — | |||||
| | | | | | | | |
|
Equity: |
|||||||
|
Class A-1 common stock, $0.01 par value; 40,000,000 shares authorized, 16,100,000 shares issued and outstanding (actual) and no shares issued and outstanding (as adjusted) |
161 | — | |||||
|
Class A common stock, $0.01 par value; 250,000,000 shares authorized, 3,802,972 shares issued and outstanding (actual) and shares issued and outstanding (as adjusted) |
38 | ||||||
|
Class B common stock, $0.01 par value; 150,000,000 shares authorized and 38,462,541 shares issued and outstanding (actual and as adjusted) |
385 | 385 | |||||
|
Preferred Stock, $0.01 par value; 50,000,000 authorized and no shares issued and outstanding (actual and as adjusted) |
— | — | |||||
|
Additional paid-in capital |
113,175 | ||||||
|
Accumulated deficit |
(1,043 | ) | |||||
| | | | | | | | |
|
Total stockholders' equity |
112,716 | ||||||
| | | | | | | | |
|
Noncontrolling interests |
221,992 | ||||||
| | | | | | | | |
|
Total equity |
334,708 | ||||||
| | | | | | | | |
|
Total capitalization |
$ | 334,708 | $ | ||||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
- (1)
- As of December 31, 2016, we had no drawn borrowings and $16.3 million of letters of credit outstanding under the credit facility. As of February 28, 2017, we had no drawn borrowings and $16.2 million of letters of credit outstanding under the credit facility.
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Purchasers of the Class A common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the Class A common stock for accounting purposes. Our net tangible book value as of December 31, 2016 was approximately $ million, or $ per share of Class A common stock. Net tangible book value per share is determined by dividing our tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of Class A common stock that will be outstanding immediately prior to the closing of this offering. After giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses), our adjusted net tangible book value as of December 31, 2016 would have been approximately $ million, or $ per share. This represents an immediate increase in the net tangible book value of $ per share to our existing shareholders and an immediate dilution (i.e., the difference between the offering price and the adjusted net tangible book value after this offering) to new investors purchasing shares in this offering of $ per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering (assuming that 100% of our Class B common stock has been exchanged for Class A common stock):
|
Initial public offering price per share |
$ | ||||||
|
Net tangible book value per share as of December 31, 2016 |
$ | ||||||
|
Increase per share attributable to new investors in this offering |
|||||||
| | | | | | | | |
|
As adjusted net tangible book value per share after giving effect to this offering |
|||||||
| | | | | | | | |
|
Dilution in net tangible book value per share to new investors in this offering(1) |
$ | ||||||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
- (1)
- If the initial public offering price were to increase or decrease by $1.00 per share, then dilution in net tangible book value per share to new investors in this offering would equal $ or $ , respectively.
The following table summarizes, on an adjusted basis as of December 31, 2016, the total number of shares of Class A common stock owned by existing shareholders (assuming that 100% of our Class B common stock has been exchanged for Class A common stock) and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing shareholders and to be paid by new investors in this offering at $ , calculated before deduction of estimated underwriting discounts and commissions.
|
|
|
|
Total Consideration |
|
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
Shares Acquired |
|
||||||||||||||
|
|
Amount
(in thousands) |
|
Average
Price Per Share |
|||||||||||||
|
|
Number | Percent | Percent | |||||||||||||
|
Existing shareholders |
% | $ | % | $ | ||||||||||||
|
New investors in this offering |
||||||||||||||||
|
Total |
% | $ | % | $ | ||||||||||||
The data in the table excludes shares of Class A common stock initially reserved for issuance under our equity incentive plan.
If the underwriters' option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to , or approximately % of the total number of shares of Class A common stock.
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SELECTED CONSOLIDATED FINANCIAL DATA
The following table presents our selected historical financial data for the periods and as of the dates indicated. The statement of operations data for the years ended December 31, 2016 and 2015 and the balance sheet data as of December 31, 2016 and 2015 are derived from our audited consolidated financial statements and the notes thereto included in the F-pages of this prospectus.
Historical results are not necessarily indicative of the results we expect in future periods. The data presented below should be read in conjunction with, and are qualified in their entirety by reference to, "Capitalization" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and the notes thereto included elsewhere in this prospectus.
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- (1)
- For definitions and reconciliations of historical EBITDA and Adjusted EBITDA, see "Summary—Summary Consolidated Financial Data."
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with "Selected Consolidated Financial Data" and our audited and unaudited financial statements and related notes appearing elsewhere in this prospectus. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this prospectus under "Forward-Looking Statements" and "Risk Factors." We assume no obligation to update any of these forward-looking statements.
The financial data discussed below for the year ended December 31, 2014 was derived from our unaudited historical consolidated financial statements, that were prepared by our management in accordance with GAAP and that are not included in the prospectus. Neither our independent registered public accounting firm, nor any other independent registered public accounting firm, have compiled, examined or performed any procedures with respect to such financial data in accordance with SEC requirements, and such metrics are not intended to be indicative of future performance.
Overview
We are a leading provider of total water solutions to the U.S. unconventional oil and gas industry. Within the major shale plays in the United States, we believe we are a market leader in sourcing and transfer of water (both by permanent pipeline and temporary pipe) prior to its use in drilling and completion activities associated with hydraulic fracturing or "fracking," which we collectively refer to as "pre-frac water services." In most of our areas of operations, we provide complementary water-related services that support oil and gas well completion and production activities including containment, monitoring, treatment, flowback, hauling and disposal. Our services are necessary to establish and maintain production of oil and gas over the productive life of a horizontal well. Water and related services are increasingly important as E&P companies have increased the complexity and completion intensity of horizontal wells (including the use of longer horizontal wellbore laterals, tighter spacing of frac stages in the laterals and increased water and proppant use per foot of lateral) in order to improve production and recovery of hydrocarbons. Historically, we have generated a substantial majority of our revenues through providing total water solutions to our customers. We provide our services to major integrated and large E&P companies, who typically represent the largest producers in each of our areas of operations.
Our Segments
Our services are offered through three operating segments: water solutions, accommodations and rentals, and wellsite completion and construction services.
- •
- Water Solutions. Our water solutions segment, operating primarily under our subsidiary Select LLC, is a leading provider of total water solutions to customers that include major integrated oil companies and independent oil and gas producers. These services include: the sourcing of water; the transfer of the water to the wellsite through permanent pipeline infrastructure and temporary pipe; the containment of fluids off- and on-location; measuring and monitoring of water; the filtering and treatment of fluids, well testing and handling of flowback and produced formation water; and the transportation and recycling or disposal of drilling, completion and production fluids. We possess an extensive asset base, which we believe is the largest in the water solutions industry, including approximately 1.5 billion barrels of annual source water, 600 water transfer pumps, 1,360 miles of permanent and temporary pipeline distribution systems, 120 well testing spreads and 220 owned and leased tractors, approximately 287,000 barrels per day in permitted disposal capacity, 1,300 frac tanks, and 34 above ground high capacity storage tanks. We own or have contractual access rights to 111 miles of permanent
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- •
-
Accommodations and Rentals.
Our accommodations and rentals segment,
operating under our subsidiary Peak, provides workforce accommodations and surface rental equipment supporting drilling, completion and production operations to the U.S. onshore oil and gas industry.
The services provided include fully furnished office and living quarters, fresh water supply and waste water removal, portable power generation and light plants, internet, phone, intercom,
surveillance and monitoring services and other long-term rental supporting field personnel.
- •
- Wellsite Completion and Construction Services. Our wellsite completion and construction services segment, operating under our subsidiary Affirm, provides oil and gas operators with a variety of services, including crane and logistics services, wellsite and pipeline construction and field services. These services are performed to establish, maintain and improve production throughout the productive life of an oil or gas well, or to otherwise facilitate other services performed on a well.
pipelines. We also have investments in or strategic relationships with treatment technology companies providing bubble flotation, chemical precipitation, chemical disinfection and distillation, through in-house equipment, strategic licensing, investments and relationships. Our water solutions segment includes our engineered water solutions group, which consists of professionals with significant technical and project development experience.
Recent Trends and Outlook
The oil and gas industry has historically 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 gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by E&P companies to their drilling, completion, production and related services budget. The oil and 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 and other conditions and factors that are beyond our control.
Demand for most of our services is driven most directly by the level of expenditures by E&P companies and, thus, is dependent upon commodity prices. Oil prices declined from the third quarter of 2014 into February 2016, reaching a 12-year low of $26.19 per barrel for WTI crude oil on February 11, 2016. The low commodity price environment caused a reduction in the drilling, completion and other activities of our customers and their spending on our services. As a result, our overall activity levels were down significantly. Further, the relative oversupply of many of the services we provide in combination with the cost cutting actions undertaken by our customers in response to falling revenues have substantially reduced the prices we can charge our customers for our services. This overall trend with respect to our customers' activities and spending negatively impacted our financial results from 2014 to 2015 and the pressure continued into 2016. Oil prices have begun to recover and reached a closing price of $53.99 per barrel on February 24, 2017. Oil and gas producers have responded to the improvement in oil prices by increasing drilling and completion activity levels, with the number of active drilling rigs in the U.S. (as reported by Baker Hughes) increasing 87% from a low of 404 rigs as of the week ended May 27, 2016 to 754 rigs for the week ended February 24, 2017. As commodity prices have begun to recover beginning in late 2016, we have experienced a recent increase in activity which has positively impacted our revenues and other financial results. If near term commodity prices stabilize at current levels and recover further, we expect to experience further increase in demand for our services. As the activity level of our customers increase, we also expect that the relatively oversupply of our services will decrease and will result in upward pressure on pricing.
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In terms of the impact of the emerging recovery in drilling and completion activity, we stand to benefit as a result of our presence in what we believe to be the core of key domestic shale basins and the consistent industry trends of (i) increases in horizontal drilling, (ii) greater rig efficiency, characterized by multi-well pad development programs that enable our customers to drill more wells with each active rig and (iii) higher horizontal well completion intensity characterized by the use of longer horizontal wellbore laterals, tighter spacing of frac stages in the laterals and increased water and proppant use per foot of lateral. We anticipate that the initial increases in drilling and completion activity will occur within our service footprint as capital spending will initially be concentrated in the acreage that offers the most attractive economics to our upstream customers. The industry trends toward greater completion intensity and increased rig efficiency will directly benefit companies, like us, that provide consumable completion services, such as water or proppant, and we believe that growth in demand for water-related services will significantly outpace the growth in rig count as the industry recovers.
While oil and gas producers typically have an inventory of DUCs, the backlog has grown above typical levels during the past two years as oil and gas producers have deliberately delayed completing drilled wells in anticipation of higher commodity prices. According to the Drilling Productivity Report released on February 13, 2017 by the EIA, as of January 2017, there were over 5,300 DUCs in the major U.S. shale plays (excluding the MidContinent) and 498 active drilling rigs in those areas, representing approximately 11 DUCs per active drilling rig in those areas. This represents a significant increase from approximately three DUCs per active drilling rig in those areas as of January 2014 according to EIA data. As commodity prices increase to levels that meet the targeted returns of E&P companies, we expect E&P companies will complete their DUC inventory. We expect the completion of this DUC inventory will increase the demand for water and our water-related completion services in the near-to-medium term.
How We Generate Revenue
We currently generate a significant majority of our revenue through our water solutions segment, specifically through the sourcing and transfer of water used in drilling and completion activities associated with hydraulic fracturing. We generate our revenue through a variety of contract structures, including master service agreements and AMI contracts with fixed pricing terms but no guaranteed throughput amounts. While we have some fixed price arrangements, most of our water and water-related services are priced based on prevailing market conditions, giving due consideration to the specific requirements of the customer.
We also generate revenue through our accommodations and rentals and wellsite completion and construction services segments which provide workforce accommodations, related rentals and a variety of wellsite completion and construction services, including wellsite construction, pipeline construction, oilfield trucking, field services and well services. We invoice the majority of our clients for these services on a per job basis or pursuant to short-term contracts as the customer's needs arise.
Costs of Conducting Our Business
The principal expenses involved in conducting our business are labor costs, equipment costs (including depreciation, repair and maintenance and leasing costs), fuel costs and water sourcing costs. Our fixed costs are relatively low and a large portion of the costs we incur in our business are only incurred when we provide water and water-related services to our customers.
Labor costs associated with our employees represent the most significant costs of our business. We incurred labor costs of $140.3 million and $235.8 million for the years ended December 31, 2016 and 2015, respectively. The majority of our labor costs are variable and are incurred only while we are providing water and water-related services. We also incur costs to employ personnel to sell and
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supervise our services and perform maintenance on our assets which are not directly tied to our level of business activity. We also incur selling, general and administrative costs for compensation of our administrative personnel at our field sites and in our corporate headquarters.
We incur significant equipment costs in connection with the operation of our business, including depreciation, repair and maintenance and leasing costs. We incurred equipment costs of $111.8 million and $145.1 million for the years ended December 31, 2016 and 2015, respectively. Our depreciation costs are expected to decline over the next few years as a result of recent impairments as well as the decline in our capital expenditures over the last three years, which will be partially offset by any future capital expenditures on depreciable assets.
Fuel costs associated with water transportation is a significant operating cost. We incurred fuel costs of $17.3 million and $31.2 million for the years ended December 31, 2016 and 2015, respectively. Fuel prices impact our transportation costs, which affect the pricing and demand of our services, and have an impact on our results of operations.
We incur water sourcing costs in connection with obtaining strategic and reliable water sources to provide repeatable water volumes to our customers. We incurred water sourcing costs of $21.9 million and $27.6 million for the years ended December 31, 2016 and 2015, respectively.
Public Company Costs
Upon closing of this offering, we expect to incur direct, incremental general and administrative expenses as a result of being a publicly traded company, including, but not limited to, costs associated with annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs, and independent director compensation. These direct, incremental general and administrative expenditures are not reflected in the historical consolidated and combined financial statements. We also expect to incur incremental, non-recurring costs related to our transition to a publicly traded corporation. These incremental expenses exclude the costs of this offering, any initial public offering and the costs associated with the initial implementation of our Sarbanes-Oxley Section 404 internal control reviews and testing. Costs incurred by us for corporate and other overhead expenses will be reimbursed by SES Holdings, pursuant to the SES Holdings LLC Agreement.
How We Evaluate Our Operations
We use a variety of operational and financial metrics to assess our performance. Among other measures, management considers each of the following:
- •
-
Revenue;
- •
-
Gross Profit;
- •
-
EBITDA; and
- •
- Adjusted EBITDA.
Revenue
We analyze our revenue by comparing actual monthly revenue to our internal projections to assess our performance. We also assess incremental changes in revenue compared to incremental changes in direct operating costs, and selling, general and administrative expenses across our operating segments to identify potential areas for improvement, as well as to determine whether segments are meeting management's expectations.
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Gross Profit
We analyze our gross profit, which we define as revenues less direct operating expenses (including depreciation expense) to measure our financial performance. We believe gross profit is a meaningful metric because it provides insight on profitability and true operating performance based on the historical cost basis of our assets. We also compare gross profit to prior periods and across locations to identify underperforming locations.
EBITDA and Adjusted EBITDA
We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income, plus taxes, interest expense, and depreciation and amortization. We define Adjusted EBITDA as EBITDA plus/(minus) loss/(income) from discontinued operations, plus any impairment charges or asset write-offs pursuant to GAAP, plus/(minus) non-cash losses/(gains) on sale of assets or subsidiaries, non-cash compensation expense, non-recurring compensation expense and nonrecurring or unusual expenses or charges, including severance expenses, transaction costs, or facilities related exit and disposal related expenditures. See "—Comparison of Non-GAAP Financial Measures" for more information and a reconciliation of EBITDA and Adjusted EBITDA to net income (loss), the most directly comparable financial measure calculated and presented in accordance with GAAP.
Results of Operations
Year Ended December 31, 2016, Compared to Year Ended December 31, 2015
|
|
Year ended December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2016 | 2015 | |||||
|
|
(In thousands)
|
||||||
|
Revenue |
|||||||
|
Water solutions |
$ | 241,455 | $ | 427,496 | |||
|
Accommodations and rentals |
27,151 | 52,948 | |||||
|
Wellsite completion and construction services |
33,793 | 55,133 | |||||
| | | | | | | | |
|
Total revenue |
302,399 | 535,577 | |||||
|
Costs of revenue |
|||||||
|
Water solutions |
200,399 | 332,411 | |||||
|
Accommodations and rentals |
22,019 | 37,957 | |||||
|
Wellsite completion and construction services |
29,089 | 48,356 | |||||
|
Depreciation and amortization |
95,020 | 104,608 | |||||
| | | | | | | | |
|
Total costs of revenue |
346,527 | 523,332 | |||||
| | | | | | | | |
|
Gross profit (loss) |
(44,128 | ) | 12,245 | ||||
|
Operating expenses |
|||||||
|
Selling, general and administrative |
34,643 | 56,548 | |||||
|
Depreciation and amortization |
2,087 | 3,104 | |||||
|
Impairment of goodwill and other intangible assets |
138,666 | 21,366 | |||||
|
Impairment of property and equipment |
60,026 | — | |||||
|
Lease abandonment costs |
19,423 | — | |||||
| | | | | | | | |
|
Total operating expenses |
254,845 | 81,018 | |||||
| | | | | | | | |
|
Loss from operations |
(298,973 | ) | (68,773 | ) | |||
|
Other income (expense) |
|||||||
|
Interest expense, net |
(16,128 | ) | (13,689 | ) | |||
|
Other income, net |
629 | 893 | |||||
| | | | | | | | |
|
Loss before taxes |
(314,472 | ) | (81,569 | ) | |||
|
Tax benefit (expense) |
|||||||
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|
|
Year ended December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2016 | 2015 | |||||
|
|
(In thousands)
|
||||||
| 524 | (324 | ) | |||||
| | | | | | | | |
|
Net loss from continuing operations |
(313,948 | ) | (81,893 | ) | |||
|
Net income from discontinued operations, net of tax |
— | 21 | |||||
| | | | | | | | |
|
Net loss |
(313,948 | ) | (81,872 | ) | |||
|
Net loss attributable to Predecessor |
306,481 | 80,891 | |||||
|
Net loss attributable to noncontrolling interests |
6,424 | 981 | |||||
| | | | | | | | |
|
Net loss attributable to Select Energy Services, Inc. |
$ | (1,043 | ) | $ | — | ||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Revenue
Our revenue decreased $233.2 million, or 43.5%, to $302.4 million for the year ended December 31, 2016 compared to $535.6 million for the year ended December 31, 2015. The decrease was primarily attributable to a decrease in our water solutions segment revenues of $186.0 million. For the year ended December 31, 2016, our water solutions, accommodations and rentals, and wellsite completion and construction services segments constituted 79.8%, 9.0% and 11.2% of our total revenue, respectively, compared to 79.8%, 9.9%, and 10.3%, respectively, for the year ended December 31, 2015. The revenue decrease by operating segment was as follows:
Water Solutions. Revenue decreased $186.0 million, or 43.5%, to $241.5 million for the year ended December 31, 2016 compared to $427.5 million for the year ended December 31, 2015. The decrease was primarily attributable to a decline in completion activities and a decrease in average annual rig count of 48% during 2016 compared to 2015 due to a low commodity price environment. Of the total decrease in revenue, approximately $84.6 million, or 19.8% was attributable to our top five customers from 2015 as rig counts for these customers decreased in excess of 52% over the period, leading to a decline in demand for water-related services. The abandonment of eight yards resulted in a reduction in revenues of $32.5 million from the prior period and the consolidation of certain facilities with significant reductions in activity resulted in a decline in revenues of $46.1 million.
Accommodations and Rentals. Revenue decreased $25.7 million, or 48.7%, to $27.2 million for the year ended December 31, 2016 compared to $52.9 million for the year ended December 31, 2015. The revenue decrease was primarily attributable to decreases in demand for equipment rentals due to a decline in average annual rig count of 48%, as well as a decrease in our wellsite trailer rental day rate. During 2016, rates for wellsite trailer rental service, which include rentals of trailers, generators, light plants, and sewer services decreased approximately 37% compared to 2015. Due to activity declines, we also closed certain facilities, which further contributed to a decrease in revenue of $3.5 million during 2016.
Wellsite Completion and Construction Services. Revenue decreased $21.3 million, or 38.7%, to $33.8 million for the year ended December 31, 2016 compared to $55.1 million for the year ended December 31, 2015. The decrease was primarily attributable to decreases in the wellsite and pipeline construction and field services revenue streams of $8.4 million and $8.2 million, respectively, as drilling and production activity declined due to a low commodity price environment and decreasing rig counts. Additionally, within our crane and logistics services revenue stream, the heavy haul equipment rental service was closed during 2016, causing a decrease of $4.2 million in revenues.
For the years ended December 31, 2015 and 2014, our revenues were $535.6 million and $903.8 million, respectively.
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Cost of Revenue
Cost of revenue decreased $176.8 million, or 33.8%, to $346.5 million for the year ended December 31, 2016 compared to $523.3 million for the year ended December 31, 2015. The decrease was largely attributable to lower salaries and wages due to a reduction in employee headcount as a result of the decline in demand for our services resulting from the overall reduction in drilling, completion and production activities, particularly in our water solutions segment. The cost of revenue decrease by operating segment was as follows:
Water Solutions. Cost of revenue decreased $132.0 million, or 39.7%, to $200.4 million for the year ended December 31, 2016 compared to $332.4 million for the year ended December 31, 2015. The decrease was primarily attributable to a decrease in salaries and wages of $54.8 million as a result of a reduction in headcount of approximately 19% during the year ended December 31, 2016 as compared to the prior year. The decrease was also attributable to a decrease in equipment rental and maintenance expense of $14.8 million, materials and supplies expense of $13.4 million, contract labor expense of $12.1 million, bulk and retail fuel expense of $9.2 million, and freshwater expense of $5.6 million. The reduction in fuel and maintenance related expenses were largely attributable to a reduction of 33% in the average number of trucks and tractors in our fleet.
Accommodations and Rentals. Cost of revenue decreased $16.0 million, or 42.0%, to $22.0 million for the year ended December 31, 2016 compared to $38.0 million for the year ended December 31, 2015. The decrease was primarily attributable to a decrease in salaries and wages of $6.7 million resulting from a reduction in headcount of approximately 23% during the year ended December 31, 2016 as compared to the prior year. The remainder of the decrease was attributable to decreases in variable costs, including equipment rentals expense of $2.9 million, bulk and retail fuel expense of $1.9 million, and insurance expense of $1.2 million.
Wellsite Completion and Construction Services. Cost of revenue decreased $19.3 million, or 39.8%, to $29.1 million for the year ended December 31, 2016 compared to $48.4 million for the year ended December 31, 2015. The decrease was primarily attributable to a decrease in salaries and wages of $8.3 million due to a reduction in headcount of approximately 18% during the year ended December 31, 2016 as compared to the prior year period. The remainder of the decrease was attributable to decreases in variable costs, including contract labor expense of $2.5 million, bulk and retail fuel expense of $2.0 million, insurance expense of $1.8 million, equipment rental and maintenance expense of $1.7 million, and materials expense of $1.7 million.
Depreciation and Amortization. Depreciation and amortization expense decreased $9.6 million, or 9.2%, to $95.0 million for the year ended December 31, 2016 compared to $104.6 million for the year ended December 31, 2015. The decrease was primarily attributable to assets becoming fully depreciated or being subject to impairment during 2016.
Gross Profit
Gross profit decreased $56.3 million to a loss of $44.1 million for the year ended December 31, 2016 compared to profit of $12.2 million for the year ended December 31, 2015 as a result of factors described above.
Selling, General and Administrative Expenses
The decrease in selling, general, and administrative expenses of $21.9 million, or 38.7%, to $34.6 million for the year ended December 31, 2016 compared to $56.5 million for the year ended December 31, 2015 was primarily due to a decrease in salaries and wages due to a reduction in average headcount of 38% during the year ended December 31, 2016 as compared to the prior year period. The decrease was also attributable to partial or complete closings of certain regional offices during 2016.
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Impairment
Due to significant reductions in oil and gas prices and rig counts, we recognized an impairment loss of $20.1 million related to goodwill and $1.3 million related to intangible assets in our water solutions segment in the consolidated statement of operations for the year ended December 31, 2015. Additionally, due to further declines in industry activity and in oil and gas prices during early 2016, we determined there were additional triggering events requiring an assessment of the recoverability of goodwill. This assessment resulted in an impairment loss of $137.5 million related to goodwill and $60.0 million related to long-lived assets in our water solutions segment, $1.0 million related to goodwill and $0.1 million related to other intangible assets in our accommodations and rentals segment was recognized in the consolidated statements of operations for the year ended December 31, 2016. Refer to "—Critical Accounting Policies and Estimates" for additional detail and discussion.
Lease Abandonment Costs
Due to depressed industry conditions and a resulting reduction in the need for facilities, during the year ended December 31, 2016, we recorded $19.4 million of lease abandonment costs related to certain facilities that were no longer in use. No lease abandonment costs were incurred during the year ended December 31, 2015.
Interest Expense
The increase in interest expense of $2.4 million, or 17.8% during the year ended December 31, 2016 compared to the year ended December 31, 2015 was due to an increase in interest rates as a result of the amendment to our credit facility in October 2015 as a result of the factors described above.
Net Loss
Net loss increased by $232.0 million to $313.9 million for the year ended December 31, 2016 compared to $81.9 million for the year ended December 31, 2015.
Comparison of Non-GAAP Financial Measures
We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income, plus taxes, interest expense, and depreciation and amortization. We define Adjusted EBITDA as EBITDA plus/(minus) loss/(income) from discontinued operations, plus any impairment charges or asset write-offs pursuant to GAAP, plus/(minus) non-cash losses/(gains) on the sale of assets or subsidiaries, non-recurring compensation expense, non-cash compensation expense, and non-recurring or unusual expenses or charges, including severance expenses, transaction costs, or facilities-related exit and disposal-related expenditures.
Our board of directors, management and investors use EBITDA and Adjusted EBITDA to assess our financial performance because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization) and items outside the control of our management team. We present EBITDA and Adjusted EBITDA because we believe they provide useful information regarding the factors and trends affecting our business in addition to measures calculated under GAAP.
Note Regarding Non-GAAP Financial Measures
EBITDA and Adjusted EBITDA are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information
63
to investors in assessing our financial performance and results of operations. Net income is the GAAP measure most directly comparable to EBITDA and Adjusted EBITDA. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool due to exclusion of some but not all items that affect the most directly comparable GAAP financial measures. You should not consider EBITDA or Adjusted EBITDA in isolation or as substitutes for an analysis of our results as reported under GAAP. Because EBITDA and Adjusted EBITDA may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For further discussion, please see "Summary—Summary Consolidated Financial Data."
The following table presents a reconciliation of EBITDA and Adjusted EBITDA to our net income (loss), which is the most directly comparable GAAP measure for the periods presented:
Year Ended December 31, 2016, Compared to Year Ended December 31, 2015
|
|
Year ended December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2016 | 2015 | |||||
|
|
(In thousands)
|
||||||
|
Net loss |
$ | (313,948 | ) | $ | (81,872 | ) | |
|
Interest expense |
16,128 | 13,689 | |||||
|
Tax (benefit) expense |
(524 | ) | 324 | ||||
|
Depreciation and amortization |
97,107 | 107,712 | |||||
| | | | | | | | |
|
EBITDA |
(201,237 | ) | 39,853 | ||||
|
Net income from discontinued operations |
— | (21 | ) | ||||
|
Impairment |
198,692 | 21,366 | |||||
|
Lease abandonment costs |
19,423 | — | |||||
|
Non-recurring severance expense |
886 | 3,200 | |||||
|
Non-recurring deal costs |
(236 | ) | 2,790 | ||||
|
Non-cash incentive gain |
(487 | ) | (889 | ) | |||
|
Non-cash loss on sale of subsidiaries and other assets |
(97 | ) | (760 | ) | |||
| | | | | | | | |
|
Adjusted EBITDA |
$ | 16,944 | $ | 65,539 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
EBITDA and Adjusted EBITDA
EBITDA was $(201.2) million for the year ended December 31, 2016 compared to $39.9 million for the year ended December 31, 2015. Adjusted EBITDA was $16.9 million for the year ended December 31, 2016 compared to $65.5 million for the year ended December 31, 2015. The decrease in EBITDA resulted from decreases in revenue and gross profit, as well as impairment charges recorded during the year ended December 31, 2016 as discussed above. The decrease in Adjusted EBITDA resulted from decreases in revenue and gross profit, as discussed above.
For the years ended December 31, 2015 and 2014, our Adjusted EBITDA was $65.5 million and $159.7 million, respectively. For the year ended December 31, 2014, our Adjusted EBITDA of $159.7 million represents net income of $2.1 million, plus depreciation and amortization of $128.0 million, interest expense of $16.9 million, net loss from discontinued operations of $8.3 million, and taxes and non-cash items of $4.4 million.
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Liquidity and Capital Resources
Overview
Our primary sources of liquidity to date have been capital contributions from our members and from investors under the 144A Offering, borrowings under our credit facility and cash flows from operations. Our primary uses of capital have been capital expenditures to support organic growth. We strive to maintain financial flexibility and proactively monitor potential capital sources, including equity and debt financing, to meet our investment and target liquidity requirements and to permit us to manage the cyclicality associated with our business.
As described in "Use of Proceeds," we intend to use the net proceeds from this offering to purchase SES Holdings LLC Units. SES Holdings intends to use the net proceeds from the sale of SES Holdings LLC Units to repay borrowings incurred under our credit facility to fund the cash portion of the purchase price of the Permian Acquisition, for the cash settlement of outstanding phantom units at SES Holdings, for growth capital expenditures in the Bakken including the expansion of the Bakken Pipeline systems, with the balance available for general corporate purposes, including other organic and acquisition growth opportunities. Following this offering, we intend to finance most of our capital expenditures, contractual obligations and working capital needs with cash generated from operations and borrowings from our credit facility. For a discussion of the credit facility, see "—Credit Facility" below. We believe that our operating cash flow and available borrowings under our credit facility will be sufficient to fund our operations for at least the next twelve months.
On December 20, 2016, we completed the 144A Offering for net proceeds of $297.2 million. We contributed all of these net proceeds to SES Holdings in exchange for SES Holdings LLC Units. SES Holdings used the net proceeds to repay a portion of its outstanding indebtedness and for general corporate purposes.
At December 31, 2016, cash and cash equivalents totaled $40.0 million. In addition to cash and cash equivalents, we had approximately $83.7 million of available borrowing capacity under our credit facility as of December 31, 2016.
Cash Flows
The following table summarizes our cash flows for the periods indicated:
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Year ended December 31, | ||||||
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2016 | 2015 | |||||
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(in thousands)
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Cash flows provided by operating activities |
$ | 5,131 | $ | 151,999 | |||
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Cash flows used in investing activities |
(26,955 | ) | (38,703 | ) | |||
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Cash flows provided by (used in) financing activities |
45,560 | (107,348 | ) | ||||
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Subtotal |
23,736 | 5,948 | |||||
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Effect of exchange rate changes on cash |
— | 75 | |||||
| | | | | | | | |
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Increase in cash |
$ | 23,736 | $ | 6,023 | |||
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| | | | | | | | |
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Analysis of Cash Flow Changes Between the Years Ended December 31, 2016 and 2015
Operating Activities. Net cash provided by operating activities was $5.1 million for the year ended December 31, 2016, compared to $152.0 million for the year ended December 31, 2015. The $146.9 million decrease in cash from operating activities was primarily attributable to an increase in net loss adjusted for non-cash intangible and fixed asset impairment charges and decreases in accounts
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receivable and accounts payable and accrued liabilities during the period. These changes are primarily the result of the low commodity prices and decreased demand for our services.
Investing Activities. Net cash used in investing activities was $27.0 million for the year ended December 31, 2016, compared to $38.7 million for the year ended December 31, 2015. The $11.7 million decrease in net cash used in investing activities was primarily due to increased cash proceeds from the sale of property and equipment during the year ended December 31, 2015. Overall cash outflow for purchases of property and equipment also decreased during the year ended December 31, 2016. During the year ended December 31, 2016, we incurred capital expenditures of approximately $16.2 million to terminate equipment leases and purchase vehicles formerly subject to such leases.
Financing Activities. Net cash from financing activities was $45.6 million for the year ended December 31, 2016, compared to cash used in financing activities of $107.4 million for the year ended December 31, 2015. The $152.9 million change in cash from financing activities was primarily due to net proceeds from the 144A Offering completed on December 20, 2016 of approximately $297.2 million and Predecessor member contributions of approximately $23.5 million, offset by an increase in net repayments on long term debt of approximately $168.5 million during the year ended December 31, 2016.
Credit Facility
On May 3, 2011, we entered into an Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent, and various lenders, which was amended most recently on December 20, 2016. As of December 20, 2016, the total commitment under our credit facility was $100.0 million in the form of a revolver. As of February 28, 2017, we had no drawn borrowings under this bank facility. However, our available borrowings are reduced by letters of credit of $16.2 million. The revolver also has a sublimit of $20.0 million for letters of credit and a sublimit of $5.0 million for swing-line loans.
Our credit facility contains certain financial covenants, including (i) the maintenance of an Interest Coverage Ratio (as such term is defined in the credit facility) of not less than (a) 1.10 to 1.0 for the quarter ending on December 31, 2016, (b) 1.25 to 1.0 for the quarter ending on March 31, 2017, (c) 1.50 to 1.0 for the quarter ending on June 30, 2017, (d) 2.50 to 1.0 for the quarter ending on September 30, 2017 and (e) 3.00 to 1.0 for each fiscal quarter ending on or after December 31, 2017 and (ii) the maintenance of a Leverage Ratio of not greater than (a) 4.00 to 1.0 for the quarter ending on September 30, 2017, (b) 3.50 to 1.0 for the quarter ending on December 31, 2017, (c) 3.25 to 1.0 for the quarters ending on March 31, 2018, June 30, 2018 and September 30, 2018, (d) 3.00 to 1.0 for the quarter ending December 31, 2018 and (e) 2.75 to 1.0 for each fiscal quarter ending on or after March 31, 2019.
Our scheduled maturity date is February 28, 2020 and the per annum interest rate on our loans is LIBOR plus an applicable margin that ranges between 3.00% and 4.50%, based on our Leverage Ratio. Our capacity to make capital expenditures is $35 million for the fiscal year ending December 31, 2017 and for each year thereafter is the greater of (i) $35 million or (ii) 50% of our EBITDA for the prior twelve months; but this restriction is not applicable for any quarter if our Leverage Ratio as of the end of the preceding fiscal quarter was less than 3.00 to 1.0. Our Leverage Ratio was less than 3.00 to 1.0 as of December 31, 2016. In addition, our credit facility contains an anti-cash hoarding provision that restricts us from making any borrowing, if after giving effect to such borrowing, we would have in excess of $20 million in cash and cash equivalents at the end of the week such borrowing is made.
As of December 31, 2016, we were in compliance with all restrictive covenants under our credit facility.
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Contractual Obligations
The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2016.
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Payments Due by Period | |||||||||||||||
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Contractual Obligations
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Year 1 | Years 2 - 3 | Years 4 - 5 |
More than
5 Years |
Total | |||||||||||
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(in thousands)
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Credit Facility(1) |
$ | — | $ | — | $ | — | $ | — | $ | — | ||||||
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Estimated letters of credit fees and commitment fees(1) |
928 | 1,856 | 149 | — | 2,933 | |||||||||||
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Operating lease obligations |
13,407 | 19,273 | 14,414 | 37,661 | 84,755 | |||||||||||
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Total |
$ | 14,335 | $ | 21,129 | $ | 14,563 | $ | 37,661 | $ | 87,688 | ||||||
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- (1)
- For a description of our credit facility, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility."
Tax Receivable Agreements
With respect to obligations under each of our Tax Receivable Agreements (except in cases where we elect to terminate the Tax Receivable Agreements early, the Tax Receivable Agreements are terminated early due to certain mergers or other changes of control or we have available cash but fail to make payments when due), generally we may elect to defer payments due under the Tax Receivable Agreements if we do not have available cash to satisfy our payment obligations under the Tax Receivable Agreements or if our contractual obligations limit our ability to make these payments. Any such deferred payments under the Tax Receivable Agreements generally will accrue interest. We intend to account for any amounts payable under the Tax Receivable Agreements in accordance with ASC Topic 450, Contingent Consideration. For further discussion regarding such an acceleration and its potential impact, please read "Risk Factors—Risks Related to Our Internal Reorganization and Resulting Structure—In certain cases, payments under the Tax Receivable Agreements may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreements." For additional information regarding the Tax Receivable Agreement, see "Certain Relationships and Related Party Transactions—Tax Receivable Agreements."
Quantitative and Qualitative Disclosure about Market Risk
The demand, pricing and terms for oilfield services provided by us are largely dependent upon the level of activity for the U.S. oil and gas 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 gas; the level of prices, and expectations about future prices of oil and gas; the cost of exploring for, developing, producing and delivering oil and gas; the expected rates of declining current production; the discovery rates of new oil and gas reserves; available pipeline and other transportation 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 gas producers to raise equity capital and debt financing; and merger and divestiture activity among oil and gas producers.
The level of activity in the U.S. oil and gas industry is volatile. Expected trends in oil and gas production activities may not continue and demand for our services may not reflect the level of activity in the industry. Any prolonged substantial reduction in oil and gas prices would likely affect oil and gas production levels and therefore affect demand for our services. A material decline in oil and gas prices
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or U.S. activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Interest Rate Risk
At December 31, 2016, we had no debt outstanding under our credit agreement. Interest is calculated under the terms of our credit agreement based on our selection, from time to time, of one of the index rates available to us plus an applicable margin that varies based on certain factors. Assuming no change in the amount outstanding, there would be no impact on interest expense as a result of a 1% increase or decrease in the assumed weighted average interest rate. We do not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of assumptions, judgments and estimates that affect the reported amounts of assets liabilities, revenue, expenses, and related disclosures as well as disclosures about any contingent assets and liabilities. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimations and how they can impact our financial statements. The following accounting policies involve critical accounting estimates because they are dependent on our judgement and assumptions about matters that are inherently uncertain.
We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the current facts and circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions about future events and their effects are subject to uncertainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained, and as the business environment in which we operate changes. We believe the current assumptions, judgments and estimates used to determine amounts reflected in our consolidated financial statements are appropriate, however, actual results may differ under different conditions. This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in this report.
Emerging Growth Company Status: Under the JOBS Act, we expect that we will meet the definition of an "emerging growth company," which would allow us to have an extended transition period for complying with new or revised accounting standards pursuant to Section 107(b) of the JOBS Act. We intend to take advantage of all of the reduced reporting requirements and exemptions, including the longer phase-in periods for the adoption of new or revised financial accounting standards under Section 107 of the JOBS Act until we are no longer an emerging growth company. Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act.
Goodwill and other intangible assets : The purchase price of acquired businesses is allocated to its identifiable assets and liabilities based upon estimated fair values as of the acquisition date. Goodwill and other intangible assets are initially recorded at their fair values. Goodwill represents the excess of the purchase price of acquisitions over the fair value of the net assets acquired in a business combination. Our goodwill at December 31, 2016 and 2015, totaled $12.2 million and $150.8 million.
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Goodwill and other intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. Intangible assets with finite useful lives are amortized either on a straight-line basis over the asset's estimated useful life or on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized.
Impairment of goodwill, long-lived and other intangible assets : Long-lived assets, such as property and equipment and finite-lived intangible assets, are evaluated for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Recoverability is measured by a comparison of their carrying amount to the estimated undiscounted cash flows to be generated by those assets. If the undiscounted cash flows are less than the carrying amount, we record impairment losses for the excess of their carrying value over the estimated fair value. Fair value is determined, in part, by the estimated cash flows to be generated by those assets. Our cash flow estimates are based upon, among other things, historical results adjusted to reflect our best estimate of future market rates, utilization levels, and operating performance. Development of future cash flows also requires management to make assumptions and to apply judgment, including timing of future expected cash flows, using the appropriate discount rates, and determining salvage values. The estimate of fair value represents our best estimates of these factors based on current industry trends and reference to market transactions, and is subject to variability. Assets are generally grouped at the lowest level of identifiable cash flows. We operate within the oilfield service industry, and the cyclical nature of the oil and gas industry that we serve and our estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows, can have a significant impact on the estimated fair value of these assets and, in periods of prolonged down cycles, may result in impairment charges. Changes to our key assumptions related to future performance, market conditions and other economic factors could adversely affect our impairment valuation.
Due to certain economic factors surrounding a decrease in oil prices and rig count that ultimately led to a decline in the oilfield services industry, during the year ended December 31, 2015, an impairment loss of $1.3 million related to other intangible assets was recognized in the consolidated statements of operations. The impairment related to certain customer relationships within our water solutions segment. Due to further declines in oil prices and the overall industry during 2016, we recognized an impairment loss of $60.0 million related to long-lived assets in our water solutions segment and $0.1 million related to other intangible assets in our accommodations and rental segment during the year ended December 31, 2016.
We conduct our annual goodwill impairment tests in the fourth quarter of each year, or more frequently if indicators of impairment exist. Our annual impairment tests utilize an income approach, which provides an estimated fair value based on discounted cash flow projections using weighted average cost of capital calculations based on capital structures of publicly traded peer companies to determine the fair value of our reporting units. Our reporting units are based on our organizational and reporting structure. When performing the annual impairment test, we have the option of performing a qualitative or quantitative assessment to determine if an impairment has occurred. If a qualitative assessment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then we would be required to perform a quantitative impairment test for goodwill. Goodwill is tested for impairment using a two-step approach. In the first step, the fair value of each reporting unit is determined and compared to the reporting unit's carrying value, including goodwill. If the fair value of a reporting unit is less than its carrying value, the second step of the goodwill impairment test is performed to measure the amount of impairment, if any. In the second step, the fair value of the reporting unit is allocated to the assets and liabilities of the reporting unit as if it had been acquired in a business combination and the purchase price was equivalent to the fair value of the reporting unit. The excess of the fair value of the reporting unit over the amounts assigned to its assets and liabilities is referred to as the implied fair value of goodwill. If the implied fair value
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of goodwill at the reporting unit level is less than its carrying value, an impairment loss is recorded to the extent that the implied fair value of goodwill at the reporting unit is less than its carrying value. Application of the goodwill impairment test requires judgment, including the identification of reporting units, allocation of assets (including goodwill) and liabilities to reporting units, and determining the fair value. The determination of reporting unit fair value relies upon certain estimates and assumptions that are complex and are affected by numerous factors, including the general economic environment and levels of exploration and production activity of oil and gas companies, our financial performance and trends, and our strategies and business plans, among others. Unanticipated changes, including immaterial revisions, to these assumptions could result in a provision for impairment in a future period. Given the nature of these evaluations and their application to specific assets and time frames, it is not possible to reasonably quantify the impact of changes in these assumptions.
Although we believe the historical assumptions and estimates we have made are reasonable and appropriate, different assumptions and estimates could materially impact our reported financial results. Due to certain economic factors surrounding industry declines, we recognized a goodwill impairment loss of $20.1 million related to our water solutions segment in the consolidated statements of operations during the year ended December 31, 2015. Due to further declines in oilfield services activity during 2016, for the year ended December 31, 2016, we recognized a goodwill impairment loss of $137.5 million related to our water solutions segment and $1.0 million related to our accommodations and rentals segment in the consolidated statements of operations.
Revenue recognition : We recognize revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured. Services are typically priced on a throughput, day-rate, hourly rate, or per-job basis depending on the type of services provided. Our services are generally governed by a service agreement or other persuasive evidence of an arrangement that includes fixed or determinable fees and do not generally include right of return provisions or other significant post-delivery obligations. Collectability is reasonably assured based on the establishment of appropriate credit qualification prior to services being rendered. Revenue generated by each of our segments are outlined as follows:
Water Solutions —Our Water Solutions segment provides water-related services to customers, including the sourcing and transfer of water, the containment of fluids, the measuring and monitoring of water, the filtering and treatment of fluids, well testing and handling, transportation, and the recycling or disposal of fluids. Revenue from water solutions is primarily based on a per-barrel price or other throughput metric as specified in the contract. We recognize revenue when services are performed. When an agreement specifies multiple services to a customer, revenue is allocated to the services performed based on the relative selling price of the services.
Accommodations and Rentals —Our Accommodations and Rentals segment provides workforce accommodations and surface rental equipment. Accommodation services include trailer housing and mobile home units for field personnel. Equipment rentals are related to the accommodations and include generators, sewer and water tanks, and communication systems. Revenue from accommodations and equipment rental is typically recognized on a day-rate basis.
Wellsite Completion and Construction Services —Our Wellsite Completion and Construction Services segment provides crane and logistics services, wellsite and pipeline construction, and field services. Revenue for heavy-equipment rental is typically recognized on a day-rate basis. Construction or field personnel revenue is based on hourly rates or on a per-job basis as services are performed.
Self-insurance : We self-insure, through deductibles and retentions, up to certain levels for losses related to general liability, workers' compensation and employer's liability, and vehicle liability. Prior to
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June 1, 2016, we were self-insured for group medical claims; however, as of June 1, 2016, we are fully-insured for group medical. Management regularly reviews its estimates of reported and unreported claims and provides for losses through reserves.
We use actuarial estimates to record our liability for future periods. If the number of claims or the costs associated with those claims were to increase significantly over our estimates, additional charges to earnings could be necessary to cover required payments. As of December 31, 2016, we estimate the range of exposure to be from $11.4 million to $12.9 million. We have recorded liabilities at December 31, 2016 of $12.3 million which represents management's best estimate of probable loss.
Equity-based compensation : We have historically accounted for equity-based awards by measuring the awards at the grant date and recognizing the grant date fair value as an expense over the service period, which is usually the vesting period. Since we are not publicly traded, we do not have a listed price with which to calculate fair value. We have historically and consistently calculated fair value using a market approach, taking into consideration peer group analysis of publicly traded companies.
Equity options have been granted with an exercise price equal to or greater than the fair market value of its underlying equity instrument as of the date of grant. We have historically valued our equity on a quarterly basis using a market approach that includes a comparison to publicly traded peer companies using earnings multiples based on their market values and a discount for lack of marketability. We have utilized the Black-Scholes model to determine fair value, which incorporates assumptions to value stock-based awards. The risk-free interest rate has been based on the U.S. Treasury yield curve in effect for the expected term of the option at the time of grant. There has been no market for our equity. Therefore, we have considered the historic volatility of publicly traded peer companies when determining the volatility factor. The expected life of the options has been based on a formula considering the vesting period and term of the options awarded. During the year ended December 31, 2016, we granted 204,245 equity options, on an adjusted basis, with a grant date fair value of $0.4 million. No equity options were granted during the year ended December 31, 2015.
Our phantom awards are cash-settled awards contingent upon meeting certain equity returns and a liquidation event. As a result of the cash-settlement feature of these awards, we consider these awards to be liability awards, which are measured at fair value at each reporting date and the pro rata vested portion of the award is recognized as a liability to the extent that the performance condition is deemed probable. No compensation expense has been recognized to date due to the non-occurrence of the performance condition, which is not yet considered probable. Upon completion of our initial public offering, we will be required to settle the then-outstanding phantom awards for cash for a maximum amount of $7.53 per phantom award, assuming our offering of Class A shares prices at a per-share price exceeding $16.00. As of December 31, 2016, we had 1,427,583 phantom awards outstanding, which would require a maximum cash payment of $10.7 million.
Recent Accounting Pronouncements
Under the JOBS Act, we expect that we will meet the definition of an "emerging growth company," which would allow us to have an extended transition period for complying with new or revised accounting standards pursuant to Section 107(b) of the JOBS Act. We intend to take advantage of all of the reduced reporting requirements and exemptions, including the longer phase-in periods for the adoption of new or revised financial accounting standards under Section 107 of the JOBS Act until we are no longer an emerging growth company. Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act.
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In May 2014, the Financial Accounting Standards Board (the "FASB") issued an accounting standards update on a comprehensive new revenue recognition standard that will supersede Accounting Standards Codification ("ASC") 605, Revenue Recognition. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The standard allows for either "full retrospective" adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up as of the earliest period presented, or "modified retrospective" adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. In August 2015, the FASB decided to defer the original effective date by one year to be effective for annual reporting periods beginning after December 15, 2018, and interim reporting periods within annual reporting periods beginning after December 15, 2019 for nonpublic entities. We are still evaluating the impact that the new accounting guidance will have on our consolidated financial statements and related disclosures and have not yet determined the method by which we will adopt the standard.
In August 2014, the FASB issued an accounting standard that requires management to assess a company's ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Before this new standard, there was minimal guidance in GAAP specific to going concern. Under the new standard, disclosures are required when conditions give rise to substantial doubt about a company's ability to continue as a going concern within one year from the financial statement issuance date. The new standard applies to all companies and is effective for the annual period ending after December 15, 2016, and all annual and interim periods thereafter. Management does not have substantial doubt about the Company's ability to continue as a going concern within one year after the date of these financial statements; therefore, no additional disclosure on this topic is required. Adoption of the new guidance during the year ended December 31, 2016 did not have a material impact on our consolidated financial statements and related disclosures.
In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015 and interim periods within fiscal years beginning after December 15, 2016, for nonpublic entities. Early adoption is permitted for financial statements that have not been previously issued. We adopted this guidance in 2016 and retrospectively reclassified $2.9 million of debt issuance costs that were previously presented as other long term assets to a direct deduction from the carrying value of short-term and long-term debt within the consolidated balance sheets as of December 31, 2015.
In November 2015, the FASB issued an accounting standards update which amends existing guidance on income taxes to require the classification of all deferred tax assets and liabilities as noncurrent on the balance sheet. The pronouncement is effective for annual reporting periods beginning after December 15, 2017, and interim periods within annual periods beginning after December 15, 2018 for nonpublic entities, and may be applied either prospectively or retrospectively. We plan to adopt this guidance during the year ended December 31, 2017 and do not expect the adoption to have a material impact on our consolidated financial statements and related disclosures.
In February 2016, the FASB issued an accounting standards update for leases. The ASU introduces a lessee model that brings most leases on the balance sheet. The new standard also aligns many of the underlying principles of the new lessor model with those in the current accounting guidance as well as the FASB's new revenue recognition standard. However, the ASU eliminates the use of bright-line tests
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in determining lease classification as required in the current guidance. The ASU also requires additional qualitative disclosures along with specific quantitative disclosures to better enable users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The pronouncement is effective for annual reporting periods beginning after December 15, 2019, including interim periods within fiscal years beginning after December 15, 2020, for nonpublic entities using a modified retrospective approach. Early adoption is permitted. We are still evaluating the impact that the new accounting guidance will have on our consolidated financial statements and related disclosures and have not yet determined the method by which we will adopt the standard.
In March 2016, the FASB issued an accounting standards update that provides a new requirement to record all of the tax effects related to share-based payments at settlement (or expiration) through the income statement. This pronouncement is effective for annual reporting periods beginning after December 15, 2017, and interim periods within fiscal years beginning after December 15, 2018, for nonpublic entities. We are still evaluating the impact that the new accounting guidance will have on our consolidated financial statements and related disclosures.
In August 2016, the FASB issued an accounting standards update addressing the classification and presentation of eight specific cash flow issues that currently result in diverse practices. The amendments provide guidance in the presentation and classification of certain cash receipts and cash payments in the statement of cash flows including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. This pronouncement is effective for annual reporting periods beginning after December 15, 2018, and interim periods within fiscal years beginning after December 15, 2019, for nonpublic entities. The amendments in this ASU should be applied using a retrospective approach. We are still evaluating the impact that the new accounting guidance will have on our consolidated financial statements and related disclosures.
In January 2017, the FASB issued an accounting standards update clarifying the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This pronouncement is effective for annual reporting periods beginning after December 15, 2018, and interim periods within fiscal years beginning after December 15, 2019, for nonpublic entities. We are still evaluating the impact that the new accounting guidance will have on our consolidated financial statements and related disclosures.
Internal Controls and Procedures
We are not currently required to comply with the SEC's rules implementing Section 404 of Sarbanes Oxley, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC's rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting under Section 404 until our second annual report after becoming a public company.
Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting, and will not be required to do so for as long as we are an "emerging growth company" pursuant to the provisions of the JOBS Act. See "Summary—Emerging Growth Company Status."
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Off Balance Sheet Arrangements
At December 31, 2016, we had no material off balance sheet arrangements, except for operating leases. As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such financing arrangements.
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Overview
We are a leading provider of total water solutions to the U.S. unconventional oil and gas industry. Within the major shale plays in the United States, we believe we are a market leader in sourcing and transfer of water (both by permanent pipeline and temporary pipe) prior to its use in drilling and completion activities associated with hydraulic fracturing or "fracking," which we collectively refer to as "pre-frac water services." In most of our areas of operations, we provide complementary water-related services that support oil and gas well completion and production activities including containment, monitoring, treatment, flowback, hauling and disposal. Our services are necessary to establish and maintain production of oil and gas over the productive life of a horizontal well. Water and related services are increasingly important as E&P companies have increased the complexity and completion intensity of horizontal wells (including the use of longer horizontal wellbore laterals, tighter spacing of frac stages in the laterals and increased water and proppant use per foot of lateral) in order to improve production and recovery of hydrocarbons. Historically, we have generated a substantial majority of our revenues through providing total water solutions to our customers. We provide our services to major integrated and large E&P companies, who typically represent the largest producers in each of our areas of operations.
Water is essential to the development and completion of unconventional oil and gas wells, where producers rely on fracking to stimulate the production of oil and gas from dense subsurface rock formations. Prior to the fracking process, we source, transfer, provide containment of and treat the water used by our customers in the well completion process. The fracking process involves the injection of significant amounts of water and proppants (typically sand) under high pressure, through a cased and cemented wellbore into targeted subsurface formations thousands of feet underground to fracture the surrounding rock. The fractures created allow hydrocarbons to flow into the wellbore for extraction. After the water is pumped into the well, it returns to the surface over time. Ten to fifty percent of the water returns as flowback during the first several weeks following the well completion process, and a large percentage of the remainder, as well as pre-existing water in the formation, returns to the surface as produced water over the life of the well. After the fracking process is completed, we provide a variety of services related to flowback and produced water and fluids that complement oil and gas completion and production activities.
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The diagram below illustrates the services we provide during the completion cycle of a horizontal well:
As the development of unconventional reservoirs has evolved, the water service needs of E&P companies have grown and diversified. Increasing completion intensity and the shift to multi-well pad drilling have significantly increased the demand for water and resulted in more complex logistical challenges in sourcing, transferring, containing and disposing of the water needed to drill and complete wells as well as to maintain production. Seeking to maximize the efficiency of their completion techniques, E&P companies have found that substantially increasing the amount of water and proppant injected into the formation can dramatically increase production. Management estimates that the completion of a horizontal well in 2009 required an average of approximately 75,000 barrels of water or approximately 575 tank truck loads, while a current horizontal well completion can require in excess of 500,000 barrels per well or approximately 3,850 tank truck loads. These volumes are amplified in multi-well pad completions which can require in excess of 5 million barrels of water per pad, or the equivalent of 38,500 tank truck loads. Significant mechanical, logistical, environmental and safety issues related to the transfer of such large volumes via tank truck have resulted in E&P companies shifting their operational focus away from traditional tank truck operators and small, local water service providers, to larger, regional and national players, like us, who have the expertise and scale to provide high quality, reliable and comprehensive water solution services.
We believe our broad geographic footprint, comprehensive suite of water services, inventory of water sources and permanent and temporary pipeline infrastructure position us to be a leading provider of water solutions in all of the shale plays that we serve. We have well-established field operations in what we believe to be core areas of all major shale plays in the United States, including the Permian Basin, SCOOP/STACK, Bakken, Eagle Ford, Marcellus, Utica, Haynesville, Rockies (DJ Basin, Niobrara Shale and Powder River Basin) and other Mid-Continent basins (Woodford, Barnett, Fayetteville, Granite Wash and Mississippian). Our broad footprint enables us to service the majority of current domestic unconventional drilling and completions activity. We estimate that over 80% of all currently active U.S. onshore horizontal rigs are operating in our primary service areas and anticipate that the vast majority of rigs that will be deployed in the near- to medium-term will be situated in these areas. In particular, we have established a strong position in the Permian Basin, which is presently our largest operating region, and where we expect producers to invest significant capital as commodity prices continue to recover from recent lows.
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We seek to be a "one-stop" provider of total water solutions for our customers in most of our areas of operations. We have the capability to provide all of the water services our customers require in their drilling and completion activities (predominantly for fracking), including the sourcing, transferring, containing and monitoring of water. We also offer various complementary water-related services that support oil and gas completion and production activities, including well testing, flowback, fluid hauling, pipeline gathering, treatment, recycling and disposal of water. For 2016, 76% of our water solutions segment revenue was generated from pre-frac and well testing activities with the remaining 24% from flowback and produced water services. Due to the increasing amount of water and fluid involved in completing a productive horizontal well by current industry standards, production of oil and gas in unconventional basins would not be commercially viable without the kind of extensive and complex water solutions and logistics-related services that we provide.
Our inventory of water sources is a key competitive advantage and enables us to offer our customers reliable access to the volume of water essential for fracking operations. Water sources are often difficult to locate, permit and reliably access, particularly in the quantities required for multi-well pad development programs. Navigating applicable regulations is especially difficult as the rules governing the sourcing of fresh water vary by state, county and municipality and each water resource may be overseen by federal and state agencies, regional water basin commissions, local water planning agencies and individual landowners. Additionally, upon the occurrence of certain events, the applicable governmental agency generally has the authority to terminate certain of our existing permits. We have spent the past five or more years obtaining strategic water sources and have secured permits or long-term access rights to approximately 1.5 billion barrels of water annually from currently in excess of 350 sources, a number which varies over time, including large scale sources such as the Brazos, Missouri, Ohio, Poudre, Rio Grande, Sabine, San Antonio, South Platte and Washita Rivers. In the Bakken, for example, we believe we have established a market leading position by securing three governmental permits which enable us to withdraw up to 100 million barrels of water annually from the Missouri River and Lake Sakakawea in North Dakota. Freshwater access cannot be easily replicated on Lake Sakakawea today as there are multiple environmental and regulatory conditions that must be met before an industrial water intake location can be built. New permits will also not be granted within 25 miles of an intake location associated with an existing permit. We have three of the five existing permits off Lake Sakakawea. In addition to surface water rights, groundwater resources are a key component of our extensive water portfolio. These sources have been secured or developed within our water solutions group and are designed with dedicated storage and transfer logistics to offer a complete water management service.
The first step in procuring a water source is identifying an area of interest based on anticipated drilling and completion activity as a result of lease activity, applications for permits and industry sources. We initiate the water sourcing process with a focus on gathering as much information as possible. Initially, we search public water records and use spatial data such as static and interactive maps managed and generated by our geographic information system team. This information provides a comprehensive overview of the area of interest, including information regarding active drilling rigs, permits, currently contracted water sources, potential surface water sources, river and stream use permits and existing and potential water well locations. We also research groundwater and surface water availability, landowner information, regulatory requirements of the state, county and district, and access logistics. After a specific water source is identified, we perform an assessment of the particular prospective source, including confirming availability, regulatory status, and any limitations on potential water rights. We use our AquaView® technology to quantify volumes and flow rates to verify current and potential water availability and volumes. After confirming the relevant ownership information, we begin negotiations with the applicable landowner or holder of the water rights. After finalizing the agreements and access rights, our team will obtain additional regulatory approvals, permits and right-of-ways as needed based on the regulatory authorities involved and individual circumstances.
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Going forward, we believe that our expertise and relationships in water sourcing will provide us with a competitive advantage in identifying and securing additional sources of water.
As a complement to our water sourcing rights, we have also made significant investments in strategic pipelines that provide reliable and cost effective water transfer. Our most significant pipeline assets are located in the Bakken and allow us to take advantage of our water permits in that area. Our Bakken pipelines consist of two active underground pipeline systems, the Charlson and the Iverson systems, in McKenzie County, North Dakota that can currently deliver up to 62 million barrels of fresh water per year. We are in the process of developing a third underground pipeline to support Williams County and western Mountrail County in North Dakota that would increase our capacity to take advantage of our maximum permitted right to 100 million barrels of fresh water per year. We have signed long-term contracts supported by AMIs with major Bakken producers that we believe will utilize a significant portion of our current pipeline capacity, including two long-term, fixed price contracts. We have also made investments outside of the Bakken, including our pipeline serving the SCOOP area of Oklahoma, the "Pecan Hill Pipeline," and our pipeline serving the Haynesville, the "IP Pipeline." In addition to our permanent water delivery systems, we have invested over $100 million in temporary piping systems, including approximately 525 miles of lay-flat hose, a temporary piping solution, and other related assets. These investments enable us to provide our customers with temporary water transfer systems that have substantially lower risk of leaks or spills compared to many alternative temporary piping options. We believe our expansive inventory of lay-flat hose, in combination with our customers' preference for this temporary water transfer method, positions us to be a market leader for this class of water transfer services. Going forward, we intend to make additional investments in water transfer infrastructure and believe we are well positioned to capture attractive opportunities due to our market position, customer relationships and industry experience and expertise.
In addition to our comprehensive water solutions, we also offer our customers services through our accommodations and equipment rentals segment as well as our wellsite completion and construction services segment. Our accommodations and rentals segment provides workforce accommodations and surface rental equipment supporting oil and gas drilling, completion and production operations. Our wellsite completion and construction services segment includes crane and logistics services, wellsite and pipeline construction and various field services. We provide our accommodation and rentals and wellsite completion and construction services to a wide range of customers in most of the major shale plays or basins in the United States.
Market Trends and Outlook
The oil and gas industry has historically 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 gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated by E&P companies and allocated to their drilling, completion, production and related services budget. The oil and 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 and other conditions and factors that are beyond our control.
Demand for most of our services depends substantially on the level of expenditures by E&P companies. The significant decline in oil prices that began 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 for WTI crude oil on February 11, 2016. These prices resulted in a significant reduction in drilling, completion and other production activities of most of our customers as well as their expenditures for our services.
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The reduction in demand, as well as the oversupply of many of the services we provide, has substantially reduced the prices we can charge our customers for our services, and has had a negative impact on the utilization of our services and assets. This overall trend with respect to our customers' activities and spending has continued in 2016. However, since hitting historically low oil prices in February 2016, oil prices have begun to recover and reached a closing price of $53.99 per barrel for WTI crude oil on February 24, 2017. Oil and gas producers have responded to the improvement in oil prices by increasing drilling activity levels, with the number of active drilling rigs in the U.S. as reported by Baker Hughes increasing 87% from a low of 404 rigs as of the week ended May 27, 2016 to 754 rigs for the week ended February 24, 2017. If near term commodity prices stabilize at current levels or recover further, we expect to experience increasing demand for our services, particularly for our pre-frac water services.
We also believe we will benefit from the emerging recovery of domestic drilling and completion activity as a result of our presence in what we believe to be the core of key domestic shale basins and trends toward increased horizontal well completion intensity and rig efficiency. Additionally, we anticipate that the initial increases in drilling and completion activity will occur within our service footprint as capital spending will initially be concentrated in the acreage that offers the most attractive economics to our upstream customers. Oil and gas producers completing their inventory of drilled but uncompleted wells, or DUCs should further increase the demand for our services in those geographic areas. For additional information regarding these completion intensity trends and the current inventory of DUCs, please read "—Our Industry—Industry Trends Impacting our Business.
Our Competitive Strengths
We believe that the following competitive strengths will allow us to successfully execute our business strategies.
Leading Market Position Offering Critical Water Solutions. As a result of our inventory of water sources, our asset base and our water delivery systems and infrastructure, we believe we are a market leader in providing pre-frac water services to the U.S. unconventional oil and gas industry. In most of our areas of operations, we also provide complementary water-related services that support oil and gas completion and production activities. Our principal competitors are typically smaller, private companies operating in fewer shale basins and in only one or two water services-related product lines. By comparison, in most of our areas of operations, we offer our customers comprehensive, integrated water solutions, from initial sourcing of water to disposal of flowback or produced water. Further, our scale allows us to cost-effectively increase our service offering to match increases in drilling and completions activity by our customers. We have an engineered water solutions team with significant experience in field planning, logistics management, regulatory compliance, technical design, petroleum and chemical engineering, geographical information systems, water resources and environmental science. This team is capable of designing, developing and operating projects across the productive life of a field and provides us with a unique competitive advantage in meeting customer requirements for complex and customized water solutions. We believe our ability to engineer and deliver end-to-end water solutions differentiates us from our competitors and enables us to be a value-added partner to E&P companies.
National Footprint Focused in the Core of Each Major Shale Play. Our operations are concentrated in what we believe to be the core areas of the major shale plays in the United States, including the Permian Basin, SCOOP/STACK, Bakken, Eagle Ford, Marcellus, Utica, Haynesville, Rockies (DJ Basin, Niobrara Shale and Powder River Basin) and other Mid-Continent basins (Woodford, Barnett, Fayetteville, Granite Wash and Mississippian). In each of our core geographic regions, we have a high quality customer base, including major integrated and large E&P companies, who represent the largest producers in those areas of operations. Our geographic breadth and diversification have allowed us to accumulate significant knowledge regarding the water solutions required in both oil and gas formations
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with varying geological characteristics and allows us to translate, apply and adapt water solutions developed in one region to other regions. In addition, we have the ability to shift assets among geographic regions as activity levels fluctuate due to market or regulatory forces. Finally, our national footprint allows us to satisfy the needs of major integrated and large independent E&P companies that demand multi-basin service capabilities.
Unique Inventory of Strategic Water Sources. To support our pre-frac water capabilities, we have secured water sources that differentiate us from our competitors and drive water transfer and other related service revenues. Identifying and securing these water sources is not easily replicated given the significant know-how and relationships with local, state and federal government agencies as well as private landowners that we have developed over the last five or more years. Specifically, through a portfolio of contracts with and permits from regulatory bodies, corporations and individual landowners, we have secured rights to approximately 1.5 billion barrels of water annually from currently in excess of 350 sources, a number which varies over time, including permits on 9 major rivers in U.S. shale basins. Most of our water sources in the Bakken and Haynesville are secured on an exclusive basis. Our deep knowledge of each basin and long-term customer relationships allow us to develop water sources that are logistically correct, providing a reliable, scalable water delivery system that is in close proximity to current and future drilling and completion activity. For example, in the Bakken we have three governmental permits that enable us to withdraw up to 100 million barrels of water annually from the Missouri River and Lake Sakakawea in North Dakota. Freshwater access cannot be easily replicated on Lake Sakakawea today as there are multiple environmental and regulatory conditions that must be met before an industrial water intake location can be built. New permits will also not be granted within 25 miles of an intake location associated with an existing permit. We have three of the five existing permits off Lake Sakakawea. Our water resources have historically attracted and will continue to attract customers seeking abundant water supply to plan long-term field developments. Further, we have successfully marketed other water-related services to our water sourcing customers in the past and we expect we will continue to do so in the future.
Significant Investment in Water Delivery Systems and Infrastructure. We have made significant investments in infrastructure to efficiently deliver water from the source to the well site. Our fixed, underground pipeline systems provide a cost-effective, reliable source of freshwater transfer and offer us the ability to scale our operations as market activity fluctuates. Our most significant pipelines today service what we believe to be core acreage in the Bakken. Our Bakken pipeline systems consist of two underground, independent pipeline systems in McKenzie County, North Dakota totaling approximately 90 miles of pipeline, including 38 miles that we own and an additional 52 miles that we have contractual rights to access. We use our Bakken pipeline systems to supply fresh water to support drilling, completion and production activities. We believe our Bakken water rights and the proximity of our infrastructure to the most economic acreage in the Bakken represent significant competitive advantages with respect to supplying and transferring water required for well completions that should generate high margins as the basin recovers. Since the second pipeline was put into service in eastern McKenzie County in the second quarter of 2015, we have successfully won all of our bids for frac water transfer jobs within seven miles of this pipeline. In addition to our fixed pipeline assets, we believe that we are the largest domestic provider of lay-flat hose, with approximately 525 miles available, which provides our customers with flexible temporary water transfer solutions. We believe that our investment in water transfer infrastructure differentiates us from our competition and will enable us to acquire new customers and drive revenue growth as drilling and completions activity increases.
Technology. We are committed to technology and product innovation. As such, we believe we are the industry leader in developing and applying technological solutions to provide value, precision and convenience to our clients. We developed AquaView®, a suite of proprietary monitoring and automation devices and related services that remotely and accurately measure and monitor water assets in real time. We also developed AquaLogic™, which consists of proprietary methods to remotely and
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automatically control and manage water transfer operations. These service offerings allow for more efficient, safer performance at an affordable cost for our customers, and we believe this is a competitive advantage in capturing and retaining business. We will continue to invest in technology in order to maintain our position as one of the leading water solutions providers, manage our costs of goods sold and improve gross margins.
Experienced Management Team with Significant Equity Ownership. Our management team has an extensive track record in the oilfield services industry with an average of over 20 years of oilfield services experience. Our Chief Executive Officer, John Schmitz, has a decades-long history of founding and building successful oilfield service companies. The majority of our management team has worked together since SES Holdings' formation in July 2008. Further, our management team has significant equity ownership which aligns their incentives with the other equity owners of the business. Following this offering, management will own an approximate % economic interest in us. In addition, following this offering, funds controlled by Crestview GP and managed by Crestview Partners will own an approximate % economic interest in us. We believe we have benefited from Crestview Partners' investment in our business and expect to continue to benefit from their ongoing involvement in the business following this offering.
Financial Strength and Flexibility. Following the closing of this offering, we expect to have a strong credit profile and approximately $ million in total liquidity, including cash on hand and availability under our credit facility. We expect our total liquidity will be reduced by the cash consideration used to complete the Permian Acquisition, also described in "Summary—Recent Developments." Our low leverage and sufficient available liquidity, will enable us to fund our business and selectively pursue accretive acquisitions and organic growth opportunities as they arise.
Strong Focus on Operational Safety and Environmental Stewardship. We maintain a culture that prioritizes safety, the environment and our relationship with the communities in which we operate. We place a strong emphasis on the safe execution of our operations, including safety training for our employees and the development of a variety of safety programs designed to make us a market leader in safety standards. In addition, we work closely with federal, state and local governments and community organizations to help ensure that our operations comply with legal requirements and community standards. We believe that our customers will select their service providers based in part on the quality of their safety and compliance records, and therefore, we will continue to make significant investments to be a market leader in this area.
Our Business Strategies
Our primary objective is to provide superior returns to our stockholders as a leading provider of total water solutions to E&P companies operating in the major shale plays in the United States. We believe we will be able to achieve this objective by executing on the following strategies.
Capitalize on the Recovery in Activity in Unconventional Resource Plays. Water is essential, and increasingly important, to the development and completion of oil and gas wells in the major shale plays that we serve in the United States. Due to our strategic positioning in what we believe to be core acreage in the shale plays, we believe we are well situated to benefit from the anticipated increase in drilling and completion activity as commodity prices rise from their recent lows. Furthermore, we believe the industry trends discussed below will drive growth in demand for total water solutions that will significantly outpace the growth in rig count. Horizontal drilling techniques in the regions we serve have continued to evolve, and operators have dramatically increased the amount of water and proppant used during the completion of horizontal wells. As market dynamics improve further, we expect to benefit from our market leading position and footprint and gain market share in the basins where we currently operate and expand our operations into emerging resource plays as they develop.
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Build out or Acquire Water Infrastructure. Our fixed pipeline assets are a key competitive advantage and allow us to deliver water efficiently and cost effectively. We are pursuing and evaluating several near-term opportunities to make additional investments in water infrastructure. On February 24, 2017, we executed definitive agreements to purchase a company with extensive freshwater pipeline and water rights to service producers in the Permian Basin, which is expected to close in March 2017, subject to the satisfaction of custormary closing conditions. We are also currently developing a third system to provide water to Williams County and western Mountrail County in North Dakota to augment our already strong position with our two pipelines servicing McKenzie County. We have entered into, and depending on market conditions may continue to enter into, long-term contracts to support our Bakken development efforts. We have identified additional expansion opportunities for our other two existing pipeline systems, in the SCOOP area of Oklahoma and the Haynesville area. Beyond these prospects, we plan to invest opportunistically in organic growth to gain market share in our current areas of operations and selectively pursue acquisitions that will allow us to strengthen our footprint and market our total water solutions to our customers.
Strengthen and Expand Our Customer Relationships Through Pre-Frac Water Services. We will continue to focus on being a market leader in pre-frac water services, expanding our market position to be a high value-add service provider, and offering our customers end-to-end water and related services associated with oil and gas drilling, completion and production activities. Looking forward, our broad service offering and focused expertise should allow us to expand our relationships with existing customers and attract new customers as demand for water and water solutions increases. Furthermore, we believe we can expand certain customer relationships that are currently limited to a single basin and become a preferred provider in multiple basins. In addition, for customers seeking to outsource field planning and logistical services, our engineered water solutions group designs, develops, operates and manages water solutions across the life cycle of a development plan.
Expand and Utilize Our Water Sources. One of our key differentiators is our portfolio of water rights, which serves as a reliable, scalable and cost effective source of water for our customers. We will also seek to identify and secure additional water sources to meet the ongoing and future water needs of our customers. Our dedicated access to high volume water sources that can support long-term development plans should allow us to attract new customers and strengthen our existing customer relationships. In the future, we plan to utilize the relationships and expertise we have developed in the process of obtaining our current portfolio of water rights to further expand our water sources.
Continue to Invest in Technology and Personnel. Satisfying the water-related service needs of an operator drilling or producing from a shale well is a highly complex and ever-changing process that requires significant technical expertise in diverse areas such as geology, engineering, environmental science and regulatory affairs. We have made significant investments in software, hardware and proprietary systems that have enabled us to develop technology and become one of the leading firms in the water solutions industry. In addition, we have built a strong team of experienced professionals holding advanced degrees to develop and execute new technologies as well as provide the technical knowledge to be a value-added partner to our customers. We plan to continue to invest in our personnel through personal, professional and job-specific training and to invest selectively in technologies that we believe will enhance the breadth and quality of our service offerings.
Maintain Financial Strength and Flexibility. We will seek to maintain a conservative balance sheet, which allows us to better react to changes in commodity prices and related demand for our services, as well as overall market conditions. As of the closing of this offering, we expect to have $ million outstanding and $ million available under our credit facility, which is scheduled to mature in 2020. We believe this borrowing capacity, along with our cash flow from operations and the proceeds from this offering, will provide us with sufficient liquidity to execute the business strategies discussed above.
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Our Industry
Unconventional Resources and Hydraulic Fracturing
Over the past decade, the innovative application of horizontal drilling and hydraulic fracturing catalyzed a revolution in the United States oil and gas industry. Vast reservoirs of crude oil and gas locked in tight rock formations, or unconventional resources, were previously uneconomic to develop, but now represent an important ongoing source of oil and gas supply. In spite of the cyclical nature of the oil and gas industry, development of U.S. unconventional resources is expected to continue to experience growth within the industry. The U.S. Energy Information Administration, or the EIA, reports that U.S. gas production from shale gas and tight oil plays grew at a 21% compound annual growth rate ("CAGR") from 2005 to 2015 while U.S. tight oil production grew at a 28% CAGR over the same timeframe. The charts below from the EIA's 2016 Annual Energy Outlook depict both the historical growth and projected future growth of U.S. unconventional resources.
Crude Oil Production (MMbbls/d)
Gas Production (tcf)
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The Role of Water in Unconventional Development, Completion and Production
Water is essential to the development and completion of unconventional oil and gas wells, where producers rely on hydraulic fracturing to stimulate the production of oil and gas from dense subsurface rock formations. Prior to the fracking process, water is sourced, transferred, contained and treated in connection with the well completion process. Although water is used during drilling, the vast majority of water is utilized for the completion cycle—or hydraulic fracturing—of a horizontal well. The fracking process involves the injection of significant amounts of water and proppants (typically sand) under high pressure, through a cased and cemented wellbore into targeted subsurface formations thousands of feet underground to fracture the surrounding rock. The resulting fractures allow hydrocarbons to flow into the wellbore for extraction.
After the water is pumped into the well, it returns to the surface over time. Ten to fifty percent of the water returns as flowback during the first several weeks following the well completion process, and a large percentage of the remainder, as well as pre-existing water in the formation, returns to the surface as produced water over the life of the well. Various waste byproducts are also generated during drilling and completion of, and production from crude oil and gas wells. An array of federal and state rules and regulations mandate that these byproducts be disposed of in an environmentally safe manner. Although E&P companies may complete the water-related tasks themselves, many choose to outsource these services to one or more third party service providers specializing in such tasks.
A significant component of post-frac water handling involves the disposal of flowback and produced water waste fluids (commonly referred to in the industry as "saltwater"), which includes brinish fluids returned to the surface during a well's completion and production phases. E&P companies and producers are required to timely dispose of these fluids during the lifespan of their producing oil and gas wells and with the drilling and completion of new oil and gas wells.
The most common method of saltwater disposal is to transport the flowback and produced water to facilities that treat and dispose of the wastewater. Key considerations operators consider include the ratio of water to hydrocarbon, or the water cut, the water decline curve, the expected lifespan of the salt water disposal facility based on the waste streams being disposed and the presence of competing service providers.
Capital Spending by E&P Companies and DUC Inventory
Demand for water and water-related services depends on the level of expenditures by companies in the oil and gas industry, which are in turn dependent on oil and gas prices, as well as advances in horizontal drilling and hydraulic fracturing techniques. Oil prices experienced a significant decline beginning in the third quarter of 2014 and continuing until February 2016, when the closing price of oil reached a 12-year low of $26.19 per barrel for WTI crude oil on February 11, 2016. Since the February low, oil prices have begun to recover and reached a closing price of $53.99 per barrel for WTI crude oil on February 24, 2017. Oil and gas producers have responded to the improvement in oil prices by increasing drilling activity levels, with the number of active drilling rigs in the U.S., as reported by Baker Hughes, increasing 87% from a low of 404 rigs for the week ended May 27, 2016 to 754 rigs for the week ended February 24, 2017. Industry analysts expect the recovery to continue, with Spears & Associates estimating a 40% year-over-year growth in U.S. onshore rig count for 2017 and an annual growth rate in U.S. onshore rig count of 24% from 2016 through 2020.
Prior to the industry downturn, the volume of fluid used in hydraulic fracturing experienced significant growth, with the Freedonia Group estimating that growth in fluid volume averaged over 40% annually between 2004 and 2014. In their 2015 Oilfield Chemicals Study, the Freedonia Group reported that the rapid growth resulted from an increasing number of wells fractured each year and significant growth in the size of individual fracturing treatments employed. During the recent downturn however, according to Spears & Associates, total annual water demand for 2015 fell to 3,851 million barrels,
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which was down approximately 29.0% from 2014 levels and is projected to decline an additional 34.8% in 2016 due to the downturn in drilling and completion activity driven by low commodity prices since late 2014. With the projected increase in activity as well as continued advancements in completion techniques, Spears & Associates is projecting increased water demand for 2018 of 157.4% as compared to expected 2016 levels, which greatly exceeds Spears' estimated horizontal rig count growth of 61.4% over the same period.
Total U.S. Water Demand (MMbbls)
In the near term, we expect demand for water and water-related services to outpace rig count growth as oil and gas producers complete wells that have been drilled but not yet completed, which we refer to as drilled uncompleted wells or "DUCs." While oil and gas producers often have an inventory of DUCs, the backlog has grown significantly during the past two years as oil and gas producers have deliberately delayed completing drilled wells in anticipation of higher commodity prices. According to the Drilling Productivity Report released on February 13, 2017 by the U.S. Energy Information Administration, or the EIA, as of January 2017, there are over 5,300 DUCs in the major U.S. shale plays (excluding the MidContinent) and 498 active drilling rigs in those areas, representing approximately 11 DUCs per active drilling rig in those areas. The number of DUCs per active drilling rig has increased significantly during the market downturn—for comparison, the average number of DUCs per active drilling rig in January 2014 was approximately three per rig. Further, the EIA estimate of current DUCs represents 68% of the total horizontal wells drilled during 2016, according to Spears & Associates. As oil and gas prices have recovered in recent months, producers have begun to complete these wells, increasing the demand for water and water-related services. Assuming oil and gas prices stabilize or increase from current levels, we expect the continuing completion efforts with this DUC inventory to increase the demand for water and water-related completion services in the near-to-medium term.
Industry Trends Impacting Our Business
We expect demand for water-related services to increase at a faster rate than rig count as a result of consistent industry trends toward (i) increases in horizontal drilling, (ii) greater rig efficiency, characterized by multi-well pad development programs that enable E&P companies to drill more wells with each active rig and (iii) higher horizontal well completion intensity characterized by the use of longer horizontal wellbore laterals, tighter spacing of frac stages in the laterals and increased water and proppant use per foot of lateral. The techniques being utilized by E&P companies have continued to
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evolve as producers work to improve per-well production and recoveries and are driving significant growth in the per-well demand for water and also the aggregate demand for water. These trends are discussed in greater detail below.
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- Increases in Horizontal Drilling. Over the past several years producers have utilized specialized drilling rigs to drill horizontally through shale formations in order to expose a greater portion of the wellbore to the hydrocarbon bearing shale formation, which correspondingly increases production from the well. According to the Baker Hughes rig count, the percentage of active rigs drilling horizontal wells has increased from 42% of total domestic rigs in 2009 to 68% in 2014, and recently, the percentage of rigs drilling horizontal wells increased further to 80% of active domestic rigs. Horizontal wells require greater volumes of water and proppant than vertical wells and we expect horizontal drilling to continue to be the primary focus of oil and gas producers as they increase the active rig count.
% of Active Rig Count by Drilling Orientation
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- Increasing Rig Efficiency: Techniques being used by E&P producers, including multi-well pad development programs, have led to improved rig efficiencies and increased horizontal wells drilled per rig. According to Spears & Associates, from 2011 to 2015, wells per rig per year in the U.S. increased by 55.4% from 12.1 in 2011 to 18.8 in 2015, with rigs expected to maintain these efficiency gains through 2020. Coupled with longer laterals and increased water intensity, this trend indicates that demand for water and proppant relating to well drilling and completion can be expected to outpace standalone rig growth.
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Horizontal Wells per Rig per Year
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- Longer Horizontal Laterals. As horizontal drilling has increased, rig operators have improved their ability to drill significantly longer horizontal sections—or "laterals"—in each well. These longer horizontal laterals effectively provide producers with a greater length of productive wellbore relative to the non-productive vertical portion of the wellbore, which is fixed. According to Spears & Associates, lateral lengths have increased significantly across the major U.S. onshore basins since 2013 and similar growth is expected to continue. Additionally, current leading edge horizontal wells are 10,000 feet or longer and we expect the growth in lateral length to continue. Because water use and the number of frac stages per well are directly tied to the length of the horizontal lateral, longer laterals have led to a significant increase in demand for water and proppant, as well as related fluid handling services.
Average Horizontal Lateral Length Across Key Basins (ft.)
- •
- More Proppant. Finally, operators are also increasing the quantity of proppant used in their hydraulic fracturing designs—both in aggregate amount used per well and on a per-foot basis. According to research from Spears and Associates, the amount of proppant per horizontal
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completion across the U.S. has increased 32% over the last three years from approximately 2,718 tons in 2013 to 3,601 tons in 2016 with anticipated continued increases as producers continue to report superior production results with greater proppant loading. Chesapeake Energy Corporation recently reported completing a well in the Haynesville Shale with 25,000 tons of proppant. Higher quantities of proppant drive higher volumes of water because a greater volume of water is needed to effectively transport the proppant down the wellbore and into the formation.
Tons of Proppant per Horizontal Well
- •
- More Water Per Well: Increasing volumes of water per well has emerged as a critical component of the techniques employed by oil and gas producers to increase recoveries from shale development wells and improve the economics of shale development operations. According to Spears & Associates, the average volume of water injected per horizontal well across the U.S. is projected to increase 144.6% by 2018, from 209,000 barrels in 2013 to 510,000 barrels in 2018. Although Spears does not forecast water demand beyond 2018, we expect the water intensity of well completions to continue to grow with increased lateral lengths and greater quantities of proppant per well.
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Water Usage per Horizontal Well (MBbls)
Supply Dynamics
Large quantities of water are essential for unconventional resource development. The primary sources of water utilized for oil and gas operations are surface water (rivers, lakes, ponds), potable and non-potable groundwater, and recycled water from flowback or produced water. Depending on where the development is taking place, any or all of these sources may be available. Several factors can influence water sourcing choices, including volumes available from each source, interests and needs of other water users, and costs associated with obtaining, treating, and transporting the water to the wellsite. Further, each geographic area has different challenges relating to geology, such as the amount of minerals and impurities in the water, which must also be taken into consideration. In the future, regulatory requirements could result in operators actively seeking water management strategies and technologies to reduce freshwater use in fracking and lower the costs associated with securing water. However, the treatment, reuse or recycling of produced water can pose challenges, as such opportunities can be limited by water quality and the potentially high cost of treating water.
Once identified, water sources are often difficult to permit and reliably access, particularly in the quantities required for multi-well pad development programs. Navigating applicable regulations is particularly difficult as the rules governing the sourcing of fresh water vary by state, county and municipality and each water resource may be overseen by federal and state agencies, regional water basin commissions, local water planning agencies and individual landowners. Access to water may be limited due to reasons such as prolonged drought or an inability to acquire or maintain water sourcing permits or other rights. In addition, some state and local governmental authorities have begun to monitor or restrict the use of water subject to their jurisdiction for hydraulic fracturing to ensure adequate local water supply.
Oil and gas operators have several options to transfer water from the source to the well site. The three main methods of water transport include trucks, temporary pipes (including lay-flat hose), or permanent pipelines. Historically, E&P companies have relied primarily on trucks to transfer water to and from well sites, and trucking may still be preferred for conventional vertical wells, delineation wells, and areas where pipeline permitting and land acquisition is restricted. However, trucking water is typically the most expensive transfer method, and companies are increasingly using temporary and permanent piping both for economic and other considerations, such as reducing the number of trucks on the road, reducing associated vehicle emissions, and trucking capacity constraints. Temporary pipes, such as lay-flat hose, can also be used for flexible short-term needs for those wells for which the water
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source and the well pad site are reasonably close. Above-ground temporary pipes allow for high rate, short- to mid-distance water transportation (in excess of 20 miles) as they can be installed quickly and relocated to adapt to changing operations schedules. For operations that are expected to remain in a general area for several years or for areas with a significant amount of activity, permanent pipeline systems may be developed. While the initial capital cost is higher, permanent pipelines can be strategic and prove to be the most cost-effective option to service the water needs for large, long-term development areas.
As water demand has continued to increase, operators and service companies have been faced with significant mechanical, logistical, environmental and safety issues related to the transfer of such large volumes. As a result of these trends, producers have increasingly moved away from traditional tank truck operators and small, local water service providers who compete on the basis of local relationships and price to larger, regional and national players who have the expertise and scale to provide high quality, reliable and comprehensive water solution services. The chart below illustrates the evolution of water sourcing in the oil and gas industry.
|
|
Pre 2008 Conventional
Vertical |
2008 - 2010
Early Horizontal |
Current Leading
Edge Horizontal |
Future Multi-Well Pad
Development |
||||
|---|---|---|---|---|---|---|---|---|
|
Frac Water per Well |
~15,000 bbls | ~75,000 bbls | ~500,000 bbls | Up to 5,000,000 bbls on a multi-well pad | ||||
|
Equivalent Tank Truck Loads(1) |
~115 | ~575 | ~3,850 | ~38,500 | ||||
|
Lateral Length (Feet) |
~1,500 | ~3,500 | ~6,000 | ~8,000 | ||||
|
Logistical Challenges |
Minor |
|
Complex | |||||
|
E&P Approach |
Minimal Attention |
|
Mission Critical | |||||
- Note:
-
Water
per well based on current management estimates of well completion intensity.
- (1)
- Assumes truck capacity of 130 barrels.
Description of Business Segments
Water Solutions
Service Lines
Our water solutions segment, operating primarily under our subsidiary, Select Energy Services, is a leading provider of total water solutions to customers that include major integrated oil companies and independent oil and gas producers. These services include: the sourcing of water; the transfer of the water to the wellsite through permanent pipeline infrastructure and temporary pipe; the containment of fluids off- and on-location; measuring and monitoring of water; the filtering and treatment of fluids, well testing and handling of flowback and produced formation water; and the transfer and recycling or disposal of drilling, completion and production fluids.
Our water solutions operating segment is divided into the following service lines:
- •
- Water sourcing. Our water sourcing service line helps E&P companies source water used for drilling and completion operations from our surface, ground and industrial water sources. Specifically, through a portfolio of contracts with and permits from regulatory bodies, corporations and individual landowners, we have secured rights to approximately 1.5 billion barrels of water annually from currently in excess of 350 sources, a number which varies over time, including large scale sources such as the Brazos, Missouri, Ohio, Poudre, Rio Grande, Sabine, San Antonio, South Platte and Washita Rivers. In the Bakken, we have three governmental permits that enable us to withdraw up to 100 million barrels of water annually from the Missouri River and Lake Sakakawea in North Dakota. Freshwater access cannot be
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- •
-
Water transfer.
Our water transfer service line provides high-volume,
high-rate water transfer services through permanent pipeline systems and temporary pipe systems. This service is utilized to transfer water from a source to a containment location on or off the
wellsite, from the containment directly to the well to support completion operations, and, in certain circumstances, directly from the source to the well. As of December 31, 2016, our assets
included more than 110 miles of operational underground pipeline, over 525 miles of lay-flat hose, approximately 700 miles of other temporary pipe (excluding lay-flat hose) and more than 600 high-rate
water transfer pumps. Our permanent pipeline systems are located in the Bakken, the SCOOP and the Haynesville, as described in more detail below.
- •
-
Bakken:
We have invested $30 million in the Charlson Pipeline
and the Iverson Pipeline in the Bakken located in McKenzie County, North Dakota, and we are developing a third pipeline system that will serve Williams County and western Mountrail County. The
Charlson pipeline system is located on the eastern side of McKenzie County, North Dakota, and consists of 32 miles of operational pipeline. The Iverson pipeline system is located in eastern McKenzie
County, North Dakota, and consists of 58 miles of operational pipeline. Of the approximately 90 miles of underground pipeline systems, we own 38 miles and have contractual rights to access the
remaining 52 miles. The development of the third permit is expected to take place in 2017 and will allow us to utilize 100 million barrels of fresh water per year across the three systems.
- •
-
SCOOP:
Through our interest in a joint venture with Access Midstream
(subsequently merged with Williams Partners), we own a nine-mile, underground fresh water delivery pipeline in Grady County, Oklahoma in what we believe to be the core of the SCOOP, with an additional
23 miles of sour gas pipeline that can be subsequently converted to deliver fresh water. The source for this pipeline system originates from the Washita River, a reliable water source in an otherwise
dry and drought-prone region of Oklahoma. We are currently permitted by the Oklahoma Water Resources Board to withdraw 10.8 million barrels of water per year from the river, in excess of the
pipeline's current physical throughput capacity of 9.2 million barrels per year.
- •
- Haynesville: We own an approximate 12-mile underground fresh water delivery pipeline in De Soto Parish, Louisiana, which transports effluent from a pump station at International Paper's Mansfield Plant Outfall No. 1 to five delivery points within the Holly Field for use in fracking operations. The IP Pipeline is located in what we believe is the core acreage of the Haynesville shale.
easily replicated on Lake Sakakawea today as there are multiple environmental and regulatory conditions that must be met before an industrial water intake location can be built. New permits will also not be granted within 25 miles of an intake location associated with an existing permit. We have three of the five existing permits off Lake Sakakawea. In addition to primary frac water sourcing, we also source brine water and other completion fluids.
Our lay-flat hose provides a flexible water transfer solution and can be customized to fit a specific project. After the completion of a project, lay-flat hose can be quickly and cost-effectively removed and redeployed for a new project, including projects in different geographic regions. Lay-flat hose has a significantly lower risk of spills than most other types of temporary jointed-pipe as a result of the strength and durability of the hose as well as the secure nature of any coupling joints used to connect multiple sections of hose. We believe the average length of lay-flat hose used in a project is approximately 5 miles, but the length can vary from as little as a few hundred feet to as much as 75 miles for a comprehensive water management program. Our lay-flat hose consists of 8 inch, 10 inch and 12 inch diameter segments. Depending on the requirements of a project, lay-flat hose may run from a water source directly to a
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- •
-
Water recycling and treatment.
Our water recycling and treatment service
line works with oil and gas producers to filter or treat water utilized in or produced by the drilling, completion and production processes to allow for safe and effective reuse or disposal. We offer
our customers treatment and filtration solutions ranging from large mesh filter pods to the application of advanced technologies, such as bubble floatation, chemical precipitation, chemical
disinfection and distillation, through in-house equipment, strategic licensing, investments and relationships.
- •
-
Well testing and flowback.
Our well testing and flowback service line
provides highly trained personnel and state-of-the-art equipment to perform a multitude of services relating to the completion and production of oil, gas, condensate and water, including frac support,
frac plug drill-out, flowback, well testing and lease operating. These services are critical to the completion and production phase of a well, as it provides the customer with initial well
productivity data which ultimately impacts a reservoir's capacity to produce hydrocarbons, such as oil, gas and condensate. Our traditional well testing and hydraulic equipment can service a multitude
of operational scenarios, such as high and low temperature, high and low pressure, high hydrogen sulfide concentration and high volume. Currently, we own approximately 120 equipment spreads to support
this broad range of services.
- •
-
Fluid hauling.
Our fluid hauling service line transports and stores water
and various drilling, completion and production fluids utilizing our fleet of vacuum trucks, winch trucks, hydrovac trucks, and related assets, such as frac tanks. As of December 31, 2016, we
owned and leased approximately 180 tractors.
- •
- Fluid disposal. As of December 31, 2016, we owned and operated 18 salt water disposal ("SWD") wells with a daily maximum permitted disposal volume of 287,400 bpd with the following geographic breakdown: Permian (110,000 bpd), Eagle Ford (95,000 bpd), Haynesville (46,000 bpd), MidContinent (25,000 bpd), Rockies (10,000 bpd) and Marcellus (1,400 bpd). Our SWD wells are located in the Eagle Ford (6), Permian, (4), Haynesville (3), MidContinent (2), Rockies (1) and Marcellus (2) regions.
containment area or well site or from containment area to containment area. Our customers generally prefer lay-flat hose to alternative temporary piping options due to the cost-effectiveness, customizability and reduced risk of spills.
Geographic Areas of Operation
We offer our water solutions services in most of the major unconventional shale plays in the continental U.S., as illustrated by a " ü " in the chart below.
|
|
Geographic Region | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Services Provided
|
Permian | MidCon | Bakken | Eagle Ford | Marcellus / Utica | Haynesville | Rockies | ||||||||
|
Water Sourcing |
ü | ü | ü | ü | ü | ü | ü | ||||||||
|
Water Transfer |
ü | ü | ü | ü | ü | ü | ü | ||||||||
|
Water Monitoring |
ü | ü | ü | ü | ü | ü | ü | ||||||||
|
Water Treating |
ü | ü | — | ü | ü | ü | ü | ||||||||
|
Containment |
ü | ü | ü | ü | ü | ü | ü | ||||||||
|
Well Testing |
ü | ü | — | ü | * | ü | ü | ||||||||
|
Fluid Hauling |
ü | ü | — | ü | * | ü | ü | ||||||||
|
Frac Tanks |
ü | ü | — | ü | * | ü | ü | ||||||||
|
SWD Wells |
ü | ü | — | ü | ü | ü | ü | ||||||||
- *
- In these regions, we have retained facilities but are not currently conducting operations.
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Customers
Our water solutions customers primarily include major integrated and independent U.S. and international oil and gas producers.
Competition
Many large domestic and international oilfield services companies offer some water-oriented and environmental services, though these are generally ancillary to their core businesses. As a result, the water solutions industry is highly fragmented and our main competitors are typically smaller or mid-sized and often private service providers that focus on water solutions and logistical services across a narrow geographic range.
Accommodations and Rentals
Service Lines
Our accommodations and rentals segment, operating under our subsidiary, Peak, provides workforce accommodations and surface rental equipment supporting drilling, completion and production operations to support onshore oil and gas activity. The services provided include fully furnished office and living quarters, fresh water supply and waste water removal, portable power generation and light plants, internet, phone, intercom, surveillance and monitoring services and other long-term rental supporting field personnel.
- •
-
Accommodations.
Our accommodations service line provides fully furnished
office and living quarters for field personnel, as well as fresh water supply to and waste water removal from such quarters and satellite communications, intercoms and video surveillance.
- •
- Rentals. Our rentals service line provides support rental equipment, including forklifts, manlifts, generators, fresh and waste water tanks, wellsite light plants, combination units that provide power generation and lighting, mobile safety showers, guard shacks, trash trailers, RVs, sound wall barriers, containment barriers, cooling trailers and heating units.
Geographic Areas of Operation
We provide accommodations and rental services in most of the major unconventional shale plays in the continental U.S.A " ü " indicates that we offer the service line in the indicated geographic region. We currently do not offer any of our accommodation and rental services in the Bakken.
|
|
Geographic Region | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Service Provided
|
Permian | MidCon | Bakken | Eagle Ford | Marcellus/ Utica | Haynesville | Rockies | ||||||||
|
Accommodations |
ü | ü | — | ü | ü | ü | — | ||||||||
|
Rentals |
ü | ü | — | ü | ü | ü | ü | ||||||||
Customers
Our accommodations and rentals customers include major integrated and independent U.S. and international oil and gas producers.
Competition
Historically, the market for wellsite living quarters, office space, portable power, wellsite lighting, and communications equipment has been serviced by a relatively fragmented competitor base ranging from small local companies and privately-owned regional service companies to large private and public companies operating across diverse geographies.
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Wellsite Completion and Construction Services
Service Lines
Our wellsite completion and construction services segment operating under our subsidiary, Affirm supports our water solutions segment and provides oil and gas operators with a variety of services, including crane and logistics services, wellsite and pipeline construction and field services. These services are performed to establish, maintain and improve production throughout the productive life of an oil or gas well, or to otherwise facilitate other services performed on a well.
- •
-
Crane and Logistics Services.
Our crane and logistics services line
provides crane services to support completion activity, aggregate hauling for site preparation, pipe storage and forklift services.
- •
-
Construction Services.
Our construction services line provides wellsite and
pipeline construction and maintenance services for both E&P companies and midstream companies.
- •
- Field services. Our field services service line provides the personnel and related equipment required to perform well hookups, facility construction, lease maintenance and general roustabout services.
Geographic Areas of Operation
We offer wellsite completion and construction services in most of the major unconventional shale plays in the continental U.S.A " ü " indicates that we offer the service line in the indicated geographic region. We currently do not offer any of our wellsite construction services in the Bakken.
|
|
Geographic Region | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Service Provided
|
Permian | MidCon | Bakken | Eagle Ford | Marcellus/ Utica | Haynesville | Rockies | ||||||||
|
Crane and logistics services |
ü | ü | — | ü | ü | ü | ü | ||||||||
|
Construction services |
ü | — | — | ü | — | — | — | ||||||||
|
Field services |
ü | ü | — | ü | ü | ü | ü | ||||||||
Customers
Our wellsite completion and construction services include major integrated U.S. and international oil companies, and gas producers as well as midstream and other oilfield services companies.
Competition
Our main competitors are typically smaller or mid-sized and often private service providers that focus on construction and field services across a narrow geographic range.
Significant Customer
For the year ended December 31, 2015, one of our customers accounted for approximately 10.6% of our total consolidated revenues. No customer accounted for more than 10% of our total consolidated revenues for the year ended December 31, 2016.
Sales and Marketing
Our sales activities are directed through a network of sales representatives and business development personnel, which provides us coverage at both the corporate and field level of our customers. Sales representatives work closely with local operations managers to target potential opportunities through strategic focus and planning. Customers are identified as targets based on their drilling and completion activity, geographic location, and economic viability. Direction of the sales team
94
is conducted through multiple weekly meetings and daily reporting. Our sales strategy is also supported by a proprietary database that we have developed based upon current rig and permit activity and the location of our strategic water sources.
Our marketing activities are performed by an internal marketing group with input from a steering committee. Our strategy is based on building a national brand though multiple media outlets including our website, blog and social media accounts, radio, print and billboard advertisements, and various industry-specific conferences, publications and lectures.
Engineered Water Solutions
Our Engineered Water Solutions group is comprised of professionals with significant technical and project development experience. The team consists of professionals with advanced degrees and experience in areas as diverse as geology, geography, petroleum and chemical engineering, computer science, environmental science, geographic information systems and regulatory affairs. This group has been designed to help customers develop and execute water solutions for wide-scale development projects, with our professionals integrating themselves into our customers' operations teams at the outset of the planning process.
Environmental and Occupational Safety and Health Matters
Our water-related and wellsite completion and construction operations in support of oil and gas exploration, development and production activities pursued by our customers are subject to stringent and comprehensive federal, state and local laws and regulations governing occupational safety and health, the discharge of materials into the environment and environmental protection. Numerous governmental entities, including the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things (i) require the acquisition of permits to take freshwater from surface water and groundwater, construct pipelines or containment facilities, drill wells and other regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into non-producing formations; (iii) limit or prohibit our operations on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing operations; (v) impose specific safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from our operations. Any failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting or performance of projects; and the issuance of orders enjoining performance of some or all of our operations in a particular area.
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, completion or water management activities, or waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Our customers may also incur increased costs or delays or restrictions in permitting or operating activities as a result of more stringent environmental laws and regulations, which may result in a curtailment of exploration, development or production activities that would reduce the demand for our services.
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The following is a summary of the more significant existing environmental and occupational safety and health laws, as amended from time to time, to which our business is subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
Hazardous substances and wastes. The Resource Conservation and Recovery Act ("RCRA"), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA, and instead are regulated under RCRA's less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency's failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our and our oil and gas producing customers' costs to manage and dispose of generated wastes, which could have a material adverse effect on our and our customers' results of operations and financial position. In the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes.
Wastes containing naturally occurring radioactive materials ("NORM") may also be generated in connection with our operations. Certain processes used to produce oil and gas may enhance the radioactivity of NORM, which may be present in oilfield wastes. NORM is subject primarily to individual state radiation control regulations. In addition, NORM handling and management activities are governed by regulations promulgated by the Occupational Safety and Health Administration ("OSHA"). These state and OSHA regulations impose certain requirements concerning worker protection, the treatment, storage and disposal of NORM waste, the management of waste piles, containers and tanks containing NORM, as well as restrictions on the uses of land with NORM contamination.
The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the Superfund law, and comparable state laws impose liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the current and past owner or operator of the site where the hazardous substance release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, neighboring landowners and other third-parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released
96
into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.
We currently own, lease, or operate numerous properties that have been used for activities supporting oil and gas exploration, development and production for a number of years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where we conduct services for our customers or where such substances have been taken for treatment or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial operations to prevent future contamination, the costs of which could be material.
Water discharges and use. The Federal Water Pollution Control Act, also known as the Clean Water Act ("CWA"), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.
The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. The EPA has issued final rules outlining its position on the federal jurisdictional reach over waters of the United States, but this rule has been stayed nationwide by the U.S. Sixth Circuit Court of Appeals as that appellate court and numerous district courts ponder lawsuits opposing implementation of the rule. In January 2017, the United States Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. Litigation surrounding this rule is ongoing. On February 28, 2017, President Trump issued an executive order directing the EPA and the U.S. Army Corps of Engineers to review and, consistent with applicable law, initiate rulemaking to rescind or revise the rule. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
The Oil Pollution Act of 1990 ("OPA") amends the CWA and sets minimum standards for prevention, containment and cleanup of oil spills. The OPA applies to vessels, offshore facilities, and onshore facilities, including E&P facilities that may affect waters of the United States. Under OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of oil into waters of the United States.
Underground injection wells and induced seismicity. Our underground injection operations are regulated pursuant to the UIC program established under the federal SDWA and analogous state and local laws and regulations. The UIC program includes requirements for permitting, testing, monitoring,
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record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require a permit from the applicable regulatory agencies to operate underground injection wells. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties claiming damages for alternative water supplies, property and personal injuries. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced waters and other substances, which could affect our business.
Furthermore, in response to recent seismic events near underground disposal wells used for the disposal by injection of produced water resulting from oil and gas activities, federal and some state agencies are investigating whether such wells have caused increased seismic activity, and some states have restricted, suspended or shut down the use of such disposal wells. In response to these concerns, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for wastewater disposal wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. The Texas Railroad Commission adopted similar rules in 2014. The adoption and implementation of any new laws, regulations or directives that restrict our ability to dispose of wastewater gathered from our customers by limiting, volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition, and results of operations.
Hydraulic fracturing activities. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from dense subsurface rock formations. The process involves the injection of water, sand and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is currently generally exempt from regulation under the UIC program established under the SDWA and is typically regulated by state oil and gas commissions or similar agencies.
However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in February 2014, the EPA asserted regulatory authority pursuant to the SDWA's UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. The EPA also issued final CAA regulations in 2012 and in June 2016 governing performance standards, including standards for the capture of emissions of methane and VOCs released during hydraulic fracturing. Additionally, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants and, in May 2014, published an Advance Notice of Proposed Rulemaking regarding the Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the BLM published a final rule in March 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands but, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked congressional authority to promulgate the rule. That decision is currently being appealed by the federal government. From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In the event that new federal restrictions on the hydraulic-fracturing process are adopted in areas where we or our customers conduct business, we or our customers may incur additional costs or permitting requirements to comply with such federal
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requirements that may be significant in nature and, in the case of our customers, could experience added delays or curtailment in the pursuit of exploration, development, or production activities, which would in turn reduce the demand for our services.
Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations, including states where we or our customers operate. For example, Texas, Oklahoma, California, Ohio, Pennsylvania, and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal, and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular, as certain local governments in California have done. Other states, such as Texas, Oklahoma, and Ohio have taken steps to limit the authority of local governments to regulate oil and gas development.
In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that "water cycle" activities associated with hydraulic fracturing may impact drinking water resources "under some circumstances," noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. The EPA's study report did not find a direct link between the action of hydraulically fracturing the well itself and contamination of groundwater resources. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs for our customers in the production of oil and gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and an associated decrease in demand for our services, increased compliance costs and time, which could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.
Air Emissions. The CAA and comparable state laws restrict the emission of air pollutants from many sources through air emissions standards, construction and operating permit programs and the imposition of other compliance standards. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay our projects as well as our customers' development of oil and gas projects. Over the next several years, we or our customers may incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard for ground-level ozone from the current standard of 75 parts per million to 70 parts per million under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. In a second example, the EPA promulgated rules in 2012 under the CAA that subject oil and gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards and a separate set of requirements to address certain hazardous air
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pollutants frequently associated with oil and gas production and processing activities pursuant to the National Standards for Emission of Hazardous Air Pollutants program. Compliance with one or more of these and other air pollution control and permitting requirements has the potential to delay the development of oil and gas projects and increase our costs of development and production, which costs could be significant.
Climate Change. In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that emit certain principal, or "criteria," pollutants. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet "best available control technology" standards. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from oil and gas production, processing, transmission and storage facilities in the United States.
Congress has from time to time considered legislation to reduce emissions of GHGs but there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions through the completion of GHG emissions inventories and by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. The EPA has also developed strategies for the reduction of methane emissions, including emissions from the oil and gas industry. For example, in June 2016, the EPA published final rules establishing new emissions standards for methane and additional standards for VOCs from certain new, modified and reconstructed equipment and processes in the oil and gas source category, including production, processing, transmission and storage activities and is formally seeking additional information from E&P operators as necessary to eventually expand these final rules to include existing equipment and processes. Furthermore, the EPA passed a new rule, known as the Clean Power Plan, to limit greenhouse gases from power plants. While the U.S. Supreme Court issued a stay in February 2016, preventing implementation during the pendency of legal challenges to the rule in court, should the stay be lifted and legal challenges prove unsuccessful, then it could reduce demand for the oil and gas our customers produce, which could reduce the demand for our services, depending on the methods used to implement the rule. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that proposed an agreement, requiring member countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This agreement was signed by the United States in April 2016 and entered into force in November 2016. The United States is one of over 120 nations having ratified or otherwise consented to the agreement; however this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions.
Although it is not possible at this time to predict how new laws or regulations in the United States or any legal requirements imposed following the United States' agreeing to the Paris Agreement that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or other legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our or our customers' equipment and operations could require us or our customers to incur costs to reduce emissions of GHGs associated with operations as well as delays or restrictions in the ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and gas our customers produce, which could reduce demand for our services. Finally, it should be noted that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have
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significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.
Endangered Species. The ESA restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the MBTA. To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where we or our oil and gas producing customers operate, our and our customers' abilities to conduct or expand operations and construct facilities could be limited or be forced to incur material additional costs. Moreover, our customer's drilling activities may be delayed, restricted, or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons. Some of our operations and the operations of our customers are located in areas that are designated as habitats for protected species. In addition, as a result of a settlement approved by the U.S. District Court for the District of Columbia in 2011, the FWS is required to make a determination on the listing of numerous other species as endangered or threatened under the ESA by the end of the FWS' 2017 fiscal year. The designation of previously unidentified endangered or threatened species could indirectly cause us to incur additional costs, cause our or our oil and gas producing customers' operations to become subject to operating restrictions or bans and limit future development activity in affected areas. The FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state, and private lands.
OSHA and other legal requirements. We are subject to the requirements of the OSHA and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements.
In addition, as part of the services we provide, we operate as a motor carrier and therefore are subject to regulation by the U.S. DOT and various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, regulatory safety, and hazardous materials labeling, placarding and marking. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes on motor fuels, among other things, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
Seasonality
Our results of operations have historically reflected seasonal tendencies, typically in the fourth quarter, relating to holiday seasons, inclement winter weather and the conclusion of our customers' annual drilling and completions capital expenditure budgets during which we typically experience declines in our operating results. In a stable commodity price and operations environment, October has historically been our most active month, with notable declines in November and December for the reasons described above.
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Intellectual Property
We own a number of trademarks and Internet domains in North America, which we use in connection with our businesses.
Risk Management and Insurance
Our operations are subject to hazards inherent in the oil and gas industry, including accidents, blowouts, explosions, craterings, fires, oil spills and hazardous materials spills. These conditions can cause:
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personal injury or loss of life;
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damage to, or destruction of property, the environment and wildlife; and
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- the suspension of our or our customers' operations.
In addition, claims for loss of oil and gas production and damage to formations can occur in the well services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in us being named as a defendant in lawsuits asserting large claims.
Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage and personal injury.
Despite our efforts to maintain high safety standards, from time to time, we have suffered accidents, and there is a risk that we will experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability, and our relationship with customers, employees and regulatory agencies. In particular, in recent years many of our large customers have placed an increased emphasis on the safety records of their service providers. Any significant increase in the frequency or severity of these incidents, or the general level of compensatory payments, could adversely affect the cost of, or our ability to obtain, workers' compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.
We maintain insurance coverage of types and amounts that we believe to be customary in the industry including workers' compensation, employer's liability, sudden & accidental pollution, umbrella, comprehensive commercial general liability, business automobile and property and equipment physical damage insurance. Our insurance coverage may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable or on terms as favorable as our current arrangements.
We enter into Master Service Agreements ("MSAs") with each of our customers. Our MSAs delineate our and our customer's respective indemnification obligations with respect to the services we provide. Generally, under our MSAs, including those relating to our water solutions, accommodations and rentals and wellsite completion and construction services, we assume responsibility for pollution or contamination originating above the surface from our equipment or handling of the equipment of others. However, our customers assume responsibility for all other pollution or contamination that may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling fluids. The assumed responsibilities include the control, removal and clean-up of any pollution or contamination. In such cases, we may be exposed to additional liability if we are grossly negligent or commit willful acts causing the pollution or contamination. Generally, our customers also agree to indemnify us against claims arising from the personal injury or death of the customers' employees or those of the customers' other contractors, in the case of our hydraulic fracturing operations, to the extent that such employees are injured by such operations, unless the loss is a result of our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees or employees of any of
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our subcontractors, unless resulting from the gross negligence or willful misconduct of our customer. The same principals apply to mutual indemnification for loss or destruction of customer-owned property or equipment, except such indemnification is not limited in an instance of gross negligence or willful misconduct. Losses arising from catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we may be unsuccessful in enforcing contractual terms, incur an unforeseen liability that is not addressed by the scope of the contractual provisions or be required to enter into an MSA with terms that vary from our standard allocations of risk, as described above. Consequently, we may incur substantial losses that could materially and adversely affect our financial condition and results of operations.
Legal Proceedings
We are not currently a party to any legal proceedings that, if determined adversely against us, individually or in the aggregate, would have a material adverse effect on our financial position, results of operations or cash flows. We are, however, named defendants in certain lawsuits, investigations and claims arising in the ordinary course of conducting our business, including certain environmental claims and employee-related matters, and we expect that we will be named defendants in similar lawsuits, investigations and claims in the future. While the outcome of these lawsuits, investigations and claims cannot be predicted with certainty, we do not expect these matters to have a material adverse impact on our business, results of operations, cash flows or financial condition. We have not assumed any liabilities arising out of these existing lawsuits, investigations and claims.
Employees
As of December 31, 2016, we had approximately 1,700 employees and no unionized labor. We believe we have good relations with our employees.
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Board of Directors and Executive Officers
Set forth below are the name, age, position and description of the business experience of our executive officers and directors.
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Name
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Age | Position | |||
|---|---|---|---|---|---|
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John Schmitz |
56 | Chairman and Chief Executive Officer | |||
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Eric Mattson |
65 | Executive Vice President, Finance | |||
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Cody Ortowski |
40 | President | |||
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Gary Gillette |
56 | Chief Financial Officer and Senior Vice President | |||
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Robert Delaney |
59 | Director | |||
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Adam Klein |
38 | Director | |||
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Douglas J. Wall |
64 | Director | |||
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Richard A. Burnett |
43 | Director | |||
John Schmitz—Chairman and Chief Executive Officer. Mr. Schmitz has served as our Chief Executive Officer and Chairman since November 2016 and served as the Chief Executive Officer and Chairman of SES Holdings since we were originally founded as Peak Oilfield Services, LLC and began operations in 2007. After Mr. Schmitz founded Peak, he led the transformation of our assets and operations through a series of strategic acquisitions designed to enhance the company's total water solutions offerings. Prior to founding Select and its predecessors, Mr. Schmitz served as the North Texas Division Manager for Complete Production Services, Inc. ("Complete" (formerly NYSE: CPX) before its sale to Superior Energy Services, Inc. (NYSE: SPN) in February 2012). Mr. Schmitz's involvement with Complete originated when his initial oilfield services holding company, BSI Holdings, Inc., was recapitalized by SCF Partners in 2003 and was rebranded underneath the Complete Energy Services, Inc. umbrella. Mr. Schmitz founded Brammer Supply, Inc., the predecessor to BSI Holdings, Inc., in 1983 and spent the 20 years thereafter growing the company, both organically and through acquisitions, into an integrated wellsite service provider with over 16 locations in North and East Texas, Oklahoma and Louisiana. Mr. Schmitz was also responsible for the founding and subsequent recapitalization of Allied Production Solutions, LP, a production surface tank equipment manufacturer, which ultimately merged into Forum Energy Technologies, Inc. in August 2010.
Mr. Schmitz is the founder and President of: (i) B-29 Family Holdings, LLC, the family office representing the business interests of John and Steve Schmitz, (ii) B-29 Investments, LP, the private equity arm of Mr. Schmitz's family office, and (iii) Sunray Capital, LP, a subsidiary of B-29 Investments, LP that contains privately-held interests in various oil and gas investments. Through Mr. Schmitz's oversight of these investment holding companies, he has been instrumental in the successful closing of numerous upstream and midstream transactions including the sales of property packages across the Barnett, Eagle Ford, and Fayetteville basins to EOG Resources, Chesapeake Energy, and XTO Energy, respectively, and the sale of Cimmaron Gathering, LP, a natural gas pipeline company, to Copano Energy, LLC (formerly NASDAQ: CPNO). Mr. Schmitz has served on the Board of Forum Energy Technologies (NYSE: FET) since September 2010 and serves on the board of multiple private oil and gas companies.
As our founder, Mr. Schmitz is a main driving force behind our success to date. Mr. Schmitz has successfully grown our company through his vision, leadership skills and business judgment, and for this reason we believe Mr. Schmitz is a valuable asset to our board and is the appropriate person to serve as Chairman.
Eric Mattson—Executive Vice President, Finance. Mr. Mattson has served as our Executive Vice President, Finance since we were incorporated in November 2016. Prior to that, he served as Executive
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Vice President, Finance of SES Holdings since January 2016 and Executive Vice President and Chief Financial Officer from November 2008 through January 2016. Mr. Mattson was an early investor in Select prior to joining our management team.
From 1999 to 2007, Mr. Mattson served as the Senior Vice President & Chief Financial Officer of two technology companies, NetRail, Inc., a Tier One IP provider and VeriCenter, Inc., an IT managed services provider. Both companies were venture capital backed start-up companies and were successfully sold to Cogent Communications Group, Inc. and SunGard, Inc., respectively. From 1993 through 1999, Mr. Mattson served as Senior Vice President & Chief Financial Officer of Baker Hughes, Inc., an oil service company. Mr. Mattson joined Baker International, Inc. in 1980, and served in a number of capacities, including Treasurer prior to the merger of Baker International, Inc. and Hughes Tool Company in 1987, at which time he became Vice President and Treasurer of Baker Hughes, Inc., a position he held until 1993. Mr. Mattson received a B.S. in Economics and an M.B.A. from The Pennsylvania State University.
Cody Ortowski—President. Mr. Ortowski has served as our President since we were incorporated in November 2016 and as President of SES Holdings since September 2014. He joined SES Holdings' predecessor in 2007, serving as the Vice President of Operations and was promoted to Executive Vice President and Chief Operating Officer in 2011. He joined our company in connection with our acquisition of Impact Energy Services, LLC ("Impact"), a water transfer company he cofounded in 2004. Prior to founding Impact, Mr. Ortowski worked for 14 years for Pumpco Energy Services, Inc. ("Pumpco"), a stimulation and cementing company headquartered in Gainesville, Texas, where he served as Vice President of Stimulation Services. While serving as Vice President of Stimulation Services, Mr. Ortowski was instrumental in growing Pumpco's operations throughout the Barnett Shale of North Texas and expanding into other U.S. markets. Mr. Ortowski received a B.B.A. in Financial Management from Abilene Christian University.
Gary Gillette—Chief Financial Officer and Senior Vice President. Mr. Gillette has served as our Chief Financial Officer and Senior Vice President since we were incorporated in November 2016. Prior to that, he served in the same capacity for SES Holdings since January 2016 and as Chief Financial Officer of Select LLC since June 2015. Prior to joining our company, Mr. Gillette spent eight years with Allied Oil and Gas Services, LLC, as the Chief Financial Officer where he was critical in helping the company quadruple in size—from a single shale play to one spanning seven North American regions. Mr. Gillette began his career with Ernst &Young where he served a number of energy-related and manufacturing clients for nine years, before going on to serve in Finance and Operations roles with Thomson Tax & Accounting (a unit of Thomson-Reuters).
Mr. Gillette is a Certified Public Accountant and Chartered Global Management Accountant, and received a B.S. in Business Administration from Concord University and an M.B.A. from New York Institute of Technology.
Robert Delaney—Director. Mr. Delaney became a member of our board of directors in November 2016 and has served on the board of directors of SES Holdings since May 2010. Mr. Delaney is a partner at Crestview Partners and serves as the head of its energy strategy. Prior to joining Crestview Partners in 2007, Mr. Delaney was a partner at Goldman Sachs & Co., where he served in a variety of leadership positions including head of the corporate private equity business in Asia, head of the Leveraged Finance Group and co-head of the Structured Finance Group, which provided project financing for the energy, power and infrastructure sectors. Mr. Delaney received an M.B.A. from Harvard Business School. He received an M.S. in accounting from NYU Stern School of Business, and an A.B. from Hamilton College.
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Mr. Delaney's extensive transactional and investment banking experience, his experience as a private equity investor and his experience with our business enable Mr. Delaney to provide valuable insight regarding complex financial and strategic issues in our industry.
Adam Klein—Director. Mr. Klein became a member of our board of directors in November 2016 and has served on the board of directors of SES Holdings since May 2010. Mr. Klein is a partner focused on energy investments at Crestview Partners and has been involved with monitoring Crestview Partners' investment in our company. Prior to joining Crestview Partners in 2007, Mr. Klein worked as an investment professional at Centennial Ventures, Inc., where he invested in early- to mid-stage companies across multiple industries. Before joining Centennial Ventures, Mr. Klein worked in the Mergers & Acquisitions group at Compass Partners from 2001 to 2003, advising corporations and private equity firms on a wide range of transactions. Previously, Mr. Klein worked in the Media & Telecom group at Donaldson, Lufkin & Jenrette and then Credit Suisse from 2000 through 2001. Mr. Klein received an M.B.A. from Harvard Business School and an A.B. in Economics from Harvard College. Mr. Klein served on the board of directors of FBR & Co. from February 2010 to June 2014.
Mr. Klein's private equity investment and company oversight experience, significant familiarity with our industry, and background with respect to acquisitions, debt financings and equity financings make him well- qualified to serve on our board of directors.
Douglas J. Wall—Director. Mr. Wall rejoined our board of directors in November 2016, having previously served on the board of SES Holdings, our subsidiary from January 2012 through December 2014. Mr. Wall formerly served as President and Chief Executive Officer of Patterson-UTI Energy, Inc. from October 2007 through September 2012, after joining the company as Chief Operating Officer in April 2007. He joined Patterson-UTI Energy, Inc. after a sixteen-year career with Baker Hughes, Inc., most recently as Group President, Completions & Production. In that role he was responsible for the operations of Baker Oil Tools, Inc. Baker Petrolite Corporation, and Centrilift, Inc., as well as the company's production optimization efforts. From 2003 to 2005, Mr. Wall was President of Baker Oil Tools, Inc., and from 1997 to 2003, he was President of Hughes Christensen Company. From 1991 to 1997, he was President and Chief Executive Officer of Western Rock Bit Company Ltd., then Hughes Tool Company's distributor in Canada. Prior to joining Baker Hughes, Inc. and its predecessors, Mr. Wall held a variety of senior executive positions with oilfield service companies in Canada. He began his career in the drilling industry in 1978 with ATCO Drilling (previously Thomson Drilling) and later spent 10 years with Adeco Drilling & Engineering Company Ltd., an affiliate of Parker Drilling Company.
Since May 2014, Mr. Wall has served on the board of directors of Fugro N.V., a Dutch-based company involved in the geotechnical, survey, subsea and seismic business. Additionally, in August 2016, Mr. Wall joined the board of directors of Seventy Seven Energy Inc., an Oklahoma-based oilfield services company that provides drilling, pressure pumping, oilfield rental tools and other services to U.S. onshore E&P companies. Mr. Wall received a B.A. in Economics from the University of Calgary and an M.B.A. in Finance and Marketing from the University of Alberta.
We believe Mr. Wall's extensive experience as a public energy company executive and his service on multiple public company boards bring valuable experience and insight to our board.
Richard A. Burnett—Director . Mr. Burnett joined our board of directors in November 2016 and will serve as the chairman of our audit committee. Mr. Burnett is currently the Chief Financial Officer of Double Eagle Energy Holdings II, a U.S. onshore E&P partnership with Apollo Natural Resource Partners. Prior to joining Double Eagle Energy Holdings II in August 2016, Mr. Burnett spent three years at EXCO Resources, Inc., a publicly-traded U.S. onshore E&P company, serving as Vice President, Chief Financial Officer and Chief Accounting Officer.
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From 2002 to November 2013, Mr. Burnett was at KPMG LLP, an international accounting firm, serving as a Partner beginning 2007. Starting in June 2012, Mr. Burnett served as the Partner in charge of the Energy Audit Practice within the Dallas/Ft. Worth Business Unit. Prior to joining KPMG LLP in 2002, Mr. Burnett spent time at Arthur Andersen LLP and Marine Drilling Companies, Inc. Mr. Burnett is a Certified Public Accountant in the State of Texas. Mr. Burnett received a B.B.A. in Accounting from Texas Tech University.
Mr. Burnett brings extensive business and financial expertise to our board from his two decades of financial management, accounting and public company expertise in the oil and gas and accounting industries. For these reasons we believe he is an ideal candidate to serve on our board and serve as our Audit Committee Chairman.
Board of Directors
The number of members of our board of directors will be determined from time-to-time by resolution of the board of directors. Currently, our board of directors consists of five persons.
Upon completion of this offering, we will become subject to Sarbanes-Oxley and, if our Class A common stock becomes listed on a stock exchange, we will become subject to the rules of such stock exchange. Generally, these rules require that a specified number or percentage of directors serving on the board and certain co