Item 1. BUSINESS
General
Dawson Geophysical Company, a Texas corporation (the “Company”), is a leading provider of North American onshore seismic data acquisition services with operations throughout the continental United States (“U.S.”) and Canada. We acquire and process 2-D, 3-D and multi-component seismic data for our clients, ranging from major oil and gas companies to independent oil and gas operators as well as providers of multi-client data libraries. Our principal business office is located at 508 West Wall, Suite 800, Midland, Texas 79701 (Telephone: 432-684-3000), and our internet address is www.dawson3d.com. We make available free of charge on our website our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K as soon as reasonably practicable after filing or furnishing such information with the Securities and Exchange Commission (“SEC”).
On February 11, 2015, the Company, which was formerly known as TGC Industries, Inc. (“Legacy TGC”), consummated a strategic business combination with Dawson Operating Company, which was formerly known as Dawson Geophysical Company (“Legacy Dawson”), pursuant to which a wholly-owned subsidiary of Legacy TGC merged with and into Legacy Dawson, with Legacy Dawson continuing after the merger as the surviving entity and a wholly-owned subsidiary of Legacy TGC (the “Merger”). In connection with the Merger, Legacy Dawson changed its name to “Dawson Operating Company” and Legacy TGC changed its name to “Dawson Geophysical Company.” Legacy TGC was formed in 1980. Legacy Dawson was formed in 1952.
Except as otherwise specifically noted herein, references herein to the “Company,” “we,” “us” or “our” refer to post-combination Dawson Geophysical Company and its consolidated subsidiaries, including Legacy Dawson.
We provide our seismic data acquisition services primarily to onshore oil and natural gas exploration and development companies for use in the onshore drilling and production of oil and natural gas in the continental U.S. and Canada as well as providers of multi-client data libraries. The main factors influencing demand for seismic data acquisition services in our industry are the level of drilling activity by oil and natural gas companies and the sizes of such companies’ exploration and development budgets, which, in turn, depend largely on current and anticipated future crude oil and natural gas prices and depletion rates of the companies’ oil and natural gas reserves.
As of December 31, 2017, we operated nine seismic crews, consisting of six crews in the U.S. and three crews in Canada, and one seismic data processing center. We began the fourth quarter operating seven crews in the U.S. and two in Canada, and ended the quarter operating six crews in the U.S. and three crews in Canada. We are currently operating seven crews in the U.S. and anticipate operating up to seven crews in the U.S. into the third quarter of 2018. We anticipate operating four crews in Canada through the end of the winter season, which concludes at the end of the first quarter 2018. While demand for our services improved throughout 2017, we continue to experience a challenging market environment due to fluctuations in domestic oil and natural gas exploration activities and commodity prices. Our seismic crews supply seismic data primarily to companies engaged in the exploration and development of oil and natural gas on land and in land-to-water transition areas. Seismic acquisition services of our wholly-owned subsidiary, Eagle Canada Seismic Services, ULC (“Eagle Canada”), are also used by the potash mining industry in Canada, and Eagle Canada has particular expertise through its heliportable capabilities. Our clients rely on seismic data to identify areas where subsurface conditions are favorable for the accumulation of existing hydrocarbons, to optimize the development and production of hydrocarbon reservoirs, to better delineate existing oil and natural gas fields, and to augment reservoir management techniques. In addition, seismic data are sometimes utilized in unconventional reservoirs to identify geo-hazards (such as subsurface faults) for drilling purposes, aid in geo-steering of a horizontal well bore and rock property identification for high grading of well locations and hydraulic fracturing. The majority of our current activity is in areas of unconventional reservoirs.
We acquire geophysical data using the latest in 3-D seismic survey techniques. We introduce acoustic energy into the ground by using vibration equipment or dynamite detonation, depending on the surface terrain, area of operation, and subsurface requirements. The reflected energy, or echoes, are received through geophones, converted into a digital signal at a multi-channel recording unit, and then transmitted to a central recording vehicle. Subsurface requirements dictate the number of channels necessary to perform our services. We generally use tens of thousands of recording channels in our seismic surveys. Additional recording channels enhance the resolution of the seismic survey through increased imaging analysis and provide improved operational efficiencies for our clients. With our state-of-the-art seismic equipment,
including computer technology and multiple channels, we acquire, on a cost effective basis, immense volumes of seismic data that, when processed and interpreted, produce precise images of the earth’s subsurface. Our clients then use our seismic data to generate 3-D geologic models that help reduce drilling risks, finding and development costs, and improve recovery rates from existing fields.
In addition to conventional 2-D and 3-D seismic surveys, we provide what the industry refers to as multi-component seismic data surveys. Multi-component surveys involve the recording of alternative seismic waves known as shear waves. Shear waves can be recorded as wave conversion of conventional energy sources (3-C converted waves) or from horizontal vibrator energy source units (shear wave vibrators). Multi-component data are utilized in further analysis of subsurface rock type, fabric and reservoir characterization. We own equipment required for onshore multi-component surveys. The majority of the projects in Canada require multi-component recording equipment. We have operated one to two multi-component equipped crews in the U.S. routinely over the past few years. The use of multi-component seismic data could increase in North America over the next few years if industry conditions improve and potentially require capital expenditures for additional equipment.
In recent years, we have begun providing surface-recorded microseismic services utilizing equipment we own. Microseismic monitoring is used by clients who use hydraulic fracturing to extract hydrocarbon deposits to monitor their hydraulic fracturing operations.
We market and supplement our services in the continental U.S. from our headquarters in Midland, Texas and from additional offices in three other cities in Texas (Denison, Houston and Plano) as well as two additional states, Oklahoma (Oklahoma City) and Colorado (Denver). In addition, we market and supplement our services in Canada from our facilities in Calgary, Alberta.
The Industry
Technological advances in seismic equipment and computing allow the seismic industry to acquire and process, on a cost-effective basis, immense volumes of seismic data which produce precise images of the earth’s subsurface. The latest accepted method of seismic data acquisition, processing, and the subsequent interpretation of the processed data is the 3-D seismic method. Geophysicists use computer workstations to interpret 3-D data volumes, identify subsurface anomalies, and generate a geologic model of subsurface features. In contrast with the 3-D method, the 2-D method involves the collection of seismic data in a linear fashion, thus generating a single plane of subsurface seismic data.
3-D seismic data are used in the exploration and development of new reserves and enable oil and natural gas companies to better delineate existing fields and to augment their reservoir management techniques. Benefits of incorporating high resolution 3-D seismic surveys into exploration and development programs include reducing drilling risk, decreasing oil and natural gas finding costs, and increasing the efficiencies of reservoir location, delineation, and management. In order to meet the requirements necessary to fully realize the benefits of 3-D seismic data, there is an increasing demand for improved data quality with greater subsurface resolution.
Currently, the North American seismic data acquisition industry is made up of a number of companies divided into two groups. The first group is made up of publicly-traded companies which includes us and SAExploration Holdings, Inc. (“SAE”). The second group is made up of Echo Seismic Ltd. (“ECHO”), Geokinetics, Inc. (“Geokinetics”), Breckenridge Geophysical Inc. (“Breckenridge”), and Paragon Geophysical Services, Inc. (“Paragon”), along with smaller companies which generally run one or two seismic crews and often specialize in specific regions or types of operations.
Equipment and Crews
In recent years, we have experienced continued increases in recording channel capacity on a per crew or project basis. This increase in channel count demand is driven by client needs and is necessary in order to produce higher resolution images, increase crew efficiencies and undertake larger scale projects. Due to the increase in demand for higher channel counts, we have continued our investments in additional channels. In response to project-based channel requirements, we routinely deploy a variable number of channels on a variable number of crews in an effort to maximize asset utilization and meet client needs. While the number of recording systems we own may exceed the number utilized in the field at any given time, we maintain the excess equipment to provide additional operational flexibility and to allow us to quickly deploy additional recording channels and energy source units as needed to respond to client demand and desire for
improved data quality with greater subsurface images. We believe we will realize the benefit of increased channel counts and flexibility of deployment through increased crew efficiencies, higher revenues and margins with improved conditions.
In recent years, we have purchased or leased a significant number of cable-less recording channels. We have utilized this equipment primarily as stand-alone recording systems, but, on occasion, we have utilized it in conjunction with our cable-based systems. As a result of the introduction of cable-less recording systems, we have realized increased crew efficiencies and increased revenue on projects using this equipment. We believe we will experience continued demand for cable-less recording systems in the future. While we have replaced cable-based recording equipment with cable-less equipment on certain crews, the cable-based recording equipment continues to be deployed on existing crews.
As of December 31, 2017, we owned equipment for 21 land-based seismic data acquisition crews, 190 vibrator energy source units, approximately 375,000 recording channels and 21 central recording systems. Of the 21 recording systems we owned at December 31, 2017, 12 were Geospace Technologies GSR and GSX cable-less recording systems, seven were ARAM ARIES cable-based recording systems, one was a Wireless Seismic RT System 2 system, and one was a cable-less INOVA Hawk system. Each crew consists of approximately 40 to 100 technicians with associated vehicles, geophones, a seismic recording system, energy sources, cables, and a variety of other equipment. Each ARAM crew has one central recording vehicle which captures seismic data. The GSR, GSX and INOVA Hawk crews utilize a recorder to manage the data acquisition while the individual system captures and holds the data until they are placed in the Data Transfer Module. The data is then transferred to various data storage media, which are delivered to a data processing center selected by the client.
Equipment Acquisition and Capital Expenditures
We monitor and evaluate advances in geophysical technology and commit capital funds to purchase the equipment we deem most effective to maintain our competitive position. Purchasing and updating seismic equipment and technology involves a commitment to capital spending. We also tie our capital expenditures closely to demand for our services. Beginning in 2014, we adopted a maintenance capital expenditures program due to the belief that our equipment base was sufficient to meet current demand. In response to an opportunity during the third quarter of 2017, we increased our 2017 capital budget to $16 million to acquire 19,000 units of multi-component seismic data acquisition equipment including 57,000 additional cable-less recording channels to serve our clients in the U.S. and Canada. We will continue to adopt a maintenance capital expenditure program for 2018.
Clients
Our services are marketed by supervisory and executive personnel who contact clients to determine geophysical needs and respond to client inquiries regarding the availability of crews or processing schedules. These contacts are based principally upon professional relationships developed over a number of years.
Our clients range from major oil and gas companies to small independent oil and gas operators and also providers of multi-client data libraries. The services we provide to our clients vary according to the size and needs of each client. During the twelve months ended December 31, 2017, sales to two clients represented approximately 27% of our revenue. The remaining balance of our revenue derived from varied clients and none represented 10% or more of our revenues. We anticipate that sales to these clients will represent a smaller percentage of our overall revenues during 2018.
We do not acquire seismic data for our own account or for future sale, maintain multi-client seismic data libraries, or participate in oil and gas ventures. The results of seismic surveys conducted for a client belong to that client. It is also our policy that none of our officers, directors or employees actively participate in oil and natural gas ventures. All of our clients’ information is maintained in the strictest confidence.
Domestic and Foreign Operations
We derive our revenue from domestic and foreign sources. Total revenues for the twelve months ended December 31, 2017 were approximately $157,148,000, of which $135,058,000 were earned in the U.S. and $22,090,000 were earned in Canada. Total revenue for the twelve months ended December 31, 2016 were approximately $133,330,000, of which $122,522,000 were earned in the U.S. and $10,808,000 were earned in Canada.
Long lived assets as of December 31, 2017 were approximately $307,844,000, with $282,420,000 owned in the U.S. and $25,424,000 owned in Canada. Long lived assets as of December 31, 2016 were approximately $324,950,000, with $308,418,000 owned in the U.S. and $16,532,000 owned in Canada.
Contracts
Our contracts are obtained either through competitive bidding or as a result of client negotiations. Our services are conducted under general service agreements for seismic data acquisition services which define certain obligations for us and for our clients. A supplemental agreement setting forth the terms of a specific project, which may be canceled by either party on short notice, is entered into for every project. We currently operate under supplemental agreements that are either “turnkey” agreements providing for a fixed fee to be paid to us for each unit of data acquired or “term” agreements providing for a fixed hourly, daily, or monthly fee during the term of the project or projects.
Currently, as in recent years, most of our projects are operated under turnkey agreements. Turnkey agreements generally provide us more profit potential, but involve more risks because of the potential of crew downtime or operational delays. We attempt to negotiate on a project-by-project basis some level of weather downtime protection within the turnkey agreements. Under the term agreements, we forego an increased profit potential in exchange for a more consistent revenue stream with improved protection from crew downtime or operational delays.
Competition
The acquisition of seismic data for the oil and natural gas industry is a highly competitive business. Contracts for such services generally are awarded on the basis of price quotations, crew experience, and the availability of crews to perform in a timely manner, although factors other than price, such as crew safety, performance history, and technological and operational expertise, are often determinative. Our competition includes publicly traded competitors, such as SAE. Our other major competitors include Echo, Geokinetics, Breckenridge, and Paragon. In addition to these previously named companies, we also compete for projects from time to time with smaller seismic companies which operate in local markets with only one or two crews. Further, the barriers to entry in the seismic industry are not prohibitive, and it would not be difficult for seismic companies outside of the U.S. to enter the domestic market and compete with us.
Employees
As of December 31, 2017, we employed 851 full-time employees, of which 92 consisted of management, sales, and administrative personnel with the remainder being crew and crew support personnel. Our employees are not represented by a labor union. We believe we have good relations with our employees.
See “Item 2. Properties” for a description of our material properties utilized in our business.
Item 1A.
Item 1A. RISK FACTORS
An investment in our common stock is subject to a number of risks, including those discussed below. You should carefully consider these discussions of risk and the other information included in this Form 10-K. These risk factors could affect our actual results and should be considered carefully when evaluating us. Although the risks described below are the risks that we believe are material, they are not the only risks relating to our business, our industry and our common stock. Additional risks and uncertainties, including those that are not yet identified or that we currently believe are immaterial, may also adversely affect our business, financial condition or results of operations. If any of the events described below occur, our business, financial condition or results of operations could be materially adversely affected.
We derive substantially all of our revenues from companies in the oil and natural gas exploration and development industry, as well as providers of multi-client data libraries which serve common clients in the industry. The oil and natural gas industry is a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and natural gas prices.
Demand for our services depends upon the level of expenditures by oil and natural gas companies for exploration, production, development and field management activities, which depend primarily on oil and natural gas prices. Significant fluctuations in domestic oil and natural gas exploration activities and commodity prices have affected, and will continue to affect, demand for our services and our results of operations. We could be adversely impacted if the level of such
exploration activities and the prices for oil and natural gas were to significantly decline in the future. In addition to the market prices of oil and natural gas, the willingness of our clients to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous factors over which our management has no control, including general economic conditions and the availability of credit. Any prolonged reduction in the overall level of exploration and development activities, whether resulting from changes in oil and natural gas prices or otherwise, could adversely impact us in many ways by negatively affecting:
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our revenues, cash flows, and profitability;
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our ability to maintain or increase our borrowing capacity;
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our ability to obtain additional capital to finance our business and the cost of that capital; and
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our ability to attract and retain skilled personnel whom we would need in the event of an upturn in the demand for our services.
Worldwide political, economic, and military events have contributed to oil and natural gas price volatility and are likely to continue to do so in the future. Depending on the market prices of oil and natural gas, oil and natural gas exploration and development companies may cancel or curtail their capital expenditure and drilling programs, thereby reducing demand for our services, or may become unable to pay, or have to delay payment of, amounts owed to us for our services. Oil and natural gas prices have been highly volatile historically and, we believe, will continue to be so in the future. Many factors beyond our control affect oil and natural gas prices, including:
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the cost of exploring for, producing, and delivering oil and natural gas;
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the discovery rate of new oil and natural gas reserves;
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the rate of decline of existing and new oil and natural gas reserves;
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available pipeline and other oil and natural gas transportation capacity;
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the ability of oil and natural gas companies to raise capital and debt financing;
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actions by OPEC (the Organization of Petroleum Exporting Countries);
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political instability in the Middle East and other major oil and natural gas producing regions;
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economic conditions in the U.S. and elsewhere;
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domestic and foreign tax policy;
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domestic and foreign energy policy including increased emphasis on alternative sources of energy;
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weather conditions in the U.S., Canada and elsewhere;
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the pace adopted by foreign governments for the exploration, development, and production of their national reserves;
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the price of foreign imports of oil and natural gas; and
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the overall supply and demand for oil and natural gas.
We, and our clients, may be adversely affected by an economic downturn.
An economic downturn could have a material adverse effect on our financial results and proposed plan of operations and could lead to further significant fluctuations in the demand for and pricing of oil and gas. Reduced demand
and pricing pressures could adversely affect the financial condition and results of operations of our clients and their ability to purchase our services. We are not able to predict the timing, extent, and duration of the economic cycles in the markets in which we operate. The oil and natural gas industry is emerging from a severe downturn and prices for oil and natural gas have recently stabilized after the decline that began in the fourth quarter of 2014. If the downturn that we appear to be emerging from continues for an extended period of time, or if it becomes more extreme, it may have material adverse effects on our planned operations, level of capital expenditures and financial condition.
A limited number of clients operating in a single industry account for a significant portion of our revenues, and the loss of one of these clients could adversely affect our results of operations.
We derive a significant amount of our revenues from a relatively small number of oil and gas exploration and development companies and providers of multi-client data libraries. During the twelve months ended December 31, 2017, our two largest clients accounted for approximately 27% of our revenues. If these clients, or any of our other significant clients, were to terminate their contracts or fail to contract for our services in the future because they are acquired, alter their exploration or development strategy, experience financial difficulties or for any other reason, our results of operations could be adversely affected.
Our clients could delay, reduce or cancel their service contracts with us on short notice, which may lead to lower than expected demand and revenues.
Our order book reflects client commitments at levels we believe are sufficient to maintain operations on our existing crews for the indicated periods. However, our clients can delay, reduce or cancel their service contracts with us on short notice. If the oil and natural gas industry incurs a downturn, it may result in an increase in delays, reductions or cancellations by our clients. In addition, the timing of the origination and completion of projects and when projects are awarded and contracted for is also uncertain. As a result, our order book as of any particular date may not be indicative of actual demand and revenues for any succeeding period.
Our revenues, operating results and cash flows can be expected to fluctuate from period to period.
Our revenues, operating results and cash flows may fluctuate from period to period. These fluctuations are attributable to the level of new business in a particular period, the timing of the initiation, progress or cancellation of significant projects, higher revenues and expenses on our dynamite contracts, and costs we incur to train new crews we may add in the future to meet increased client demand. Fluctuations in our operating results may also be affected by other factors that are outside of our control such as permit delays, weather delays and crew productivity. Oil and natural gas prices, while showing improvement over the past year, have continued to be volatile and have resulted in significant demand fluctuations for our services. There can be no assurance of future oil and gas price levels or stability. Our operations in Canada are also seasonal as a result of the thawing season and we have historically experienced limited Canadian activity during the second and third quarters of each year. The demand for our services will be adversely affected by a significant reduction in oil and natural gas prices and by climate change legislation or material changes to U.S. energy policy. Because our business has high fixed costs, the negative effect of one or more of these factors could trigger wide variations in our operating revenues, cash flows, EBITDA, margin, and profitability from quarter-to-quarter, rendering quarter-to-quarter comparisons unreliable as an indicator of performance. Due to the factors discussed above, you should not expect sequential growth in our quarterly revenues and profitability.
We extend credit to our clients without requiring collateral, and a default by a client could have a material adverse effect on our operating revenues.
We perform ongoing credit evaluations of our clients’ financial conditions and, generally, require no collateral from our clients. It is possible that one or more of our clients will become financially distressed, especially in light of the recent downturn in the oil and natural gas industry and fluctuations in commodity prices, which could cause them to default on their obligations to us and could reduce the client’s future need for seismic services provided by us. Our concentration of clients may also increase our overall exposure to these credit risks. A default in payment from one of our large clients could have a material adverse effect on our operating results for the period involved.
We incur losses.
We incurred net losses of $31,266,000 and $39,792,000 for the twelve months ended December 31, 2017 and 2016, respectively.
Our ability to be profitable in the future will depend on many factors beyond our control, but primarily on the level of demand for land-based seismic data acquisition services by oil and natural gas exploration and development companies. Even if we do achieve profitability, we may not be able to sustain or increase profitability on a quarterly or annual basis.
We have indebtedness from time to time under credit facilities with a commercial bank, and certain of our core assets and our accounts receivable are pledged as collateral for these obligations. Our ability to borrow may be limited if our accounts receivable decrease or the value of certain of our core assets is materially impaired.
From time to time, we have indebtedness under credit facilities with a commercial bank, and certain of our core assets as well as our accounts receivable are pledged as collateral for these borrowings. If we are unable to repay all secured borrowings when due, whether at maturity or if declared due and payable following a default, our lenders have the right to proceed against the assets pledged to secure the indebtedness and may sell these assets in order to repay those borrowings, which could materially harm our business, financial condition and results of operations. Our ability to borrow funds under our revolving line of credit is tied to the value of pledged assets as well as the amount of our eligible accounts receivable. If our pledged assets become materially impaired or our accounts receivable decrease materially for any reason, including delays, reductions or cancellations by clients or decreased demand for our services, our ability to borrow to fund operations or other obligations may be limited.
Our financial results could be adversely affected by asset impairments.
We periodically review our portfolio of equipment and our intangible assets for impairment. In connection with the Merger, we recorded intangibles associated with the combination of Legacy TGC and Legacy Dawson that are an asset on our consolidated balance sheet. Future events, including our financial performance, sustained decreases in oil and natural gas prices, reduced demand for our services, our market valuation or the market valuation of comparable companies, loss of a significant client’s business, or strategic decisions, could cause us to conclude that impairment indicators exist and ultimately that the asset values associated with our equipment or our intangibles were to be impaired. If we were to impair our equipment or intangibles, these noncash asset impairments could negatively affect our financial results in a material manner in the period in which they are recorded, and the larger the amount of any impairment that may be taken, the greater the impact such impairment may have on our financial results.
Our profitability is determined, in part, by the utilization level and productivity of our crews and is affected by numerous external factors that are beyond our control.
Our revenue is determined, in part, by the contract price we receive for our services, the level of utilization of our data acquisition crews and the productivity of these crews. Crew utilization and productivity is partly a function of external factors, such as client cancellation or delay of projects, operating delays from inclement weather, obtaining land access rights and other factors, over which we have no control. If our crews encounter operational difficulties or delays on any data acquisition survey, our results of operations may vary, and in some cases, may be adversely affected.
In recent years, most of our projects have been performed on a turnkey basis for which we were paid a fixed price for a defined scope of work or unit of data acquired. The revenue, cost and gross profit realized under our turnkey contracts can vary from our estimates because of changes in job conditions, variations in labor and equipment productivity or because of the performance of our subcontractors. Turnkey contracts may also cause us to bear substantially all of the risks of business interruption caused by external factors over which we may have no control, such as weather, obtaining land access rights, crew downtime or operational delays. These variations, delays and risks inherent in turnkey contracts may result in reducing our profitability.
We face intense competition in our business that could result in downward pricing pressure and the loss of market share.
The seismic data acquisition services industry is a highly competitive business in the continental U.S. and Canada. Our competitors include companies with financial resources that are greater than our own as well as companies of comparable and smaller size. Additionally, the seismic data acquisition business is extremely price competitive and has a history of periods in which seismic contractors bid jobs below cost and, therefore, adversely affected industry pricing. Many contracts are awarded on a bid basis, which may further increase competition based primarily on price. Further, the barriers to entry in the seismic industry are not prohibitive, and it would not be difficult for seismic companies outside of the U.S. to enter the domestic market and compete with us.
Inclement weather may adversely affect our ability to complete projects and could, therefore, adversely affect our results of operations.
Our seismic data acquisition operations could be adversely affected by inclement weather conditions. Delays associated with weather conditions could adversely affect our results of operations. For example, weather delays could affect our operations on a particular project or an entire region and could lengthen the time to complete data acquisition projects. In addition, even if we negotiate weather protection provisions in our contracts, we may not be fully compensated by our clients for delays caused by inclement weather.
Our operations are subject to delays related to obtaining land access rights of way from third parties which could affect our results of operations.
Our seismic data acquisition operations could be adversely affected by our inability to obtain timely right of way usage from both public and private land and/or mineral owners. We cannot begin surveys on property without obtaining permits from governmental entities as well as the permission of the private landowners who own the land being surveyed. In recent years, it has become more difficult, costly and time-consuming to obtain access rights of way as drilling activities have expanded into more populated areas. Additionally, while landowners generally are cooperative in granting access rights, some have become more resistant to seismic and drilling activities occurring on their property. In addition, governmental entities do not always grant permits within the time periods expected. Delays associated with obtaining such rights of way could negatively affect our results of operations.
Capital requirements for our operations are large. If we are unable to finance these requirements, we may not be able to maintain our competitive advantage.
Seismic data acquisition and data processing technologies historically have progressed steadily, and we expect this trend to continue. In order to remain competitive, we must continue to invest additional capital to maintain, upgrade and expand our seismic data acquisition capabilities. Our working capital requirements remain high, primarily due to the expansion of our infrastructure in response to client demand for cable-less recording systems and more recording channels, which has increased as the industry strives for improved data quality with greater subsurface resolution images. Our sources of working capital are limited. We have historically funded our working capital requirements primarily with cash generated from operations, cash reserves and, from time to time, borrowings from commercial banks. In recent years, we have funded some of our capital expenditures through equipment term loans and capital leases. In the past, we have also funded our capital expenditures and other financing needs through public equity offerings. If we were to expand our operations at a rate exceeding operating cash flow, if current demand or pricing of geophysical services were to decrease substantially, or if technical advances or competitive pressures required us to acquire new equipment faster than our cash flow could sustain, additional financing could be required. If we were not able to obtain such financing or renew our existing revolving line of credit when needed, our failure could have a negative impact on our ability to pursue expansion and maintain our competitive advantage.
Technological change in our business creates risks of technological obsolescence and requirements for future capital expenditures. If we are unable to keep up with these technological advances, we may not be able to compete effectively.
Seismic data acquisition technologies historically have steadily improved and progressed, and we expect this progression to continue. We are in a capital intensive industry, and in order to remain competitive, we must continue to invest additional capital to maintain, upgrade and expand our seismic data acquisition capabilities. However, we may have limitations on our ability to obtain the financing necessary to enable us to purchase state-of-the-art equipment, and certain
of our competitors may be able to purchase newer equipment when we may not be able to do so, thus affecting our ability to compete.
We rely on a limited number of key suppliers for specific seismic services and equipment.
We depend on a limited number of third parties to supply us with specific seismic services and equipment. From time to time, increased demand for seismic data acquisition services has decreased the available supply of new seismic equipment, resulting in extended delivery dates on orders of new equipment. Any delay in obtaining equipment could delay our deployment of additional crews and restrict the productivity of existing crews, adversely affecting our business and results of operations. In addition, any adverse change in the terms of our suppliers’ arrangements could affect our results of operations.
Some of our suppliers may also be our competitors. If competitive pressures were to become such that our suppliers would no longer sell to us, we would not be able to easily replace the technology with equipment that communicates effectively with our existing technology, thereby impairing our ability to conduct our business.
We are dependent on our management team and key employees, and inability to retain our current team or attract new employees could harm our business.
Our continued success depends upon attracting and retaining highly skilled professionals and other technical personnel. A number of our employees are highly skilled scientists and highly trained technicians. The loss, whether by death, departure or illness, of our senior executives or other key employees or our failure to continue to attract and retain skilled and technically knowledgeable personnel could adversely affect our ability to compete in the seismic services industry. We may experience significant competition for such personnel, particularly during periods of increased demand for seismic services. A limited number of our employees are under employment contracts, and we have no key man insurance.
We are subject to Canadian foreign currency exchange rate risk.
We conduct business in Canada which subjects us to foreign currency exchange rate risk. Currently, we do not hold or issue foreign currency forward contracts, option contracts or other derivative financial instruments to mitigate the currency exchange rate risk. Our results of operations and our cash flows could be impacted by changes in foreign currency exchange rates.
Our common stock has experienced, and may continue to experience, price volatility and low trading volume.
Our stock price is subject to significant volatility. Overall market conditions, including a decline in oil and natural gas prices and other risks and uncertainties described in this “Risk Factors” section and in our other filings with the SEC, could cause the market price of our common stock to fall. Our high and low sales prices of our common stock for the twelve months ended December 31, 2017 were $8.55 and $3.70, respectively. Further, the high and low sales prices of our common stock for the twelve months ended December 31, 2016 were $9.00 and $2.90, respectively.
Our common stock is listed on The NASDAQ Stock Market LLC (“NASDAQ”) under the symbol “DWSN.” However, daily trading volumes for our common stock are, and may continue to be, relatively small compared to many other publicly traded securities. For example, during 2017 our daily trading volume was as low as 11,200 shares. It may be difficult for you to sell your shares in the public market at any given time at prevailing prices, and the price of our common stock may, therefore, be volatile.
Our common stock has traded below $5.00 per share in the past year, and when it trades below $5.00 per share it may be considered a low-priced stock and may be subject to regulations that limit or restrict the potential market for the stock.
Although currently our common stock is trading above $5.00 per share, our common stock may be considered a low-priced stock pursuant to rules promulgated under the Exchange Act, if it trades below a price of $5.00 per share. Under these rules, broker-dealers participating in transactions in low-priced securities must first deliver a risk disclosure document which describes the risks associated with such stock, the broker-dealer’s duties, the client’s rights and remedies, and certain market and other information, and make a suitability determination approving the client for low-priced stock
transactions based on the client’s financial situation, investment experience and objectives. Broker-dealers must also disclose these restrictions in writing and provide monthly account statements to the client, and obtain specific written consent of the client. With these restrictions, the likely effect of designation as a low-price stock would be to decrease the willingness of broker-dealers to make a market for our common stock, to decrease the liquidity of the stock, and to increase the transaction costs of sales and purchases of such stocks compared to other securities. As of July 6, 2017, our common stock was quoted at a closing sales price of $3.75 per share and we cannot guarantee that our common stock will trade at a price greater than $5.00 per share.
We do not expect to pay cash dividends on our common stock for the foreseeable future, and, therefore, only appreciation of the price of our common stock may provide a return to shareholders.
While there are currently no restrictions prohibiting us from paying dividends to our shareholders, our board of directors, after consideration of economic and market conditions affecting the energy industry in general, and the oilfield services business in particular, determined that we would not pay a dividend in respect of our common stock for the foreseeable future. Payment of any dividends in the future will be at the discretion of our board and will depend on our financial condition, results of operations, capital and legal requirements, and other factors deemed relevant by the board.
Certain provisions of our amended and restated certificate of formation may make it difficult for a third party to acquire us in the future or may adversely impact your ability to obtain a premium in connection with a future change of control transaction.
Our amended and restated certificate of formation contains provisions that require the approval of holders of 80% of our issued and outstanding shares before we may merge or consolidate with or into another corporation or entity or sell all, or substantially all, of our assets to another corporation or entity. Additionally, if we increase the size of our board from the current eight directors to nine directors, we could, by resolution of the board of directors, stagger the directors’ terms, and our directors could not be removed without approval of holders of 80% of our issued and outstanding shares. These provisions could discourage or impede a tender offer, proxy contest or other similar transaction involving control of us.
In addition, our board of directors has the right to issue preferred stock upon such terms and conditions as it deems to be in our best interest. The terms of such preferred stock may adversely impact the dividend and liquidation rights of our common shareholders without the approval of our common shareholders.
We may be subject to liability claims that are not covered by our insurance.
Our business is subject to the general risks inherent in land-based seismic data acquisition activities. Our activities are often conducted in remote areas under dangerous conditions, including the detonation of dynamite. These operations are subject to risk of injury to personnel and damage to equipment. Our crews are mobile, and equipment and personnel are subject to vehicular accidents. These risks could cause us to experience equipment losses, injuries to our personnel, and interruptions in our business.
In addition, we could be subject to personal injury or real property damage claims in the normal operation of our business. Such claims may not be covered under the indemnification provisions contained in our general service agreements to the extent that the damage is due to our negligence or intentional misconduct.
Our general service agreements require us to have specific amounts of insurance. However, we do not carry insurance against certain risks that could cause losses, including business interruption resulting from equipment maintenance or weather delays. Further, there can be no assurance, however, that any insurance obtained by us will be adequate to cover all losses or liabilities or that this insurance will continue to be available or available on terms which are acceptable to us. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a materially adverse effect on us.
We may be held liable for the actions of our subcontractors.
We often work as the general contractor on seismic data acquisition surveys and, consequently, engage a number of subcontractors to perform services and provide products. While we obtain contractual indemnification and insurance covering the acts of these subcontractors and require the subcontractors to obtain insurance for our benefit, we could be
held liable for the actions of these subcontractors. In addition, subcontractors may cause injury to our personnel or damage to our property that is not fully covered by insurance.
The high fixed costs of our operations could result in operating losses.
Companies within our industry are typically subject to high fixed costs which consist primarily of depreciation (a non-cash item) and maintenance expenses associated with seismic data acquisition and equipment and crew costs. In addition, ongoing maintenance capital expenditures, as well as new equipment investment, can be significant. As a result, any extended periods of significant downtime or low productivity caused by reduced demand, weather interruptions, equipment failures, permit delays, or other causes could result in operating losses.
We operate under hazardous conditions that subject us to risk of damage to property or personnel injuries and may interrupt our business.
Our business is subject to the general risks inherent in land-based seismic data acquisition activities. Our activities are often conducted in remote areas under extreme weather and other dangerous conditions, including the use of dynamite as an energy source. These operations are subject to risk of injury to our personnel and third parties and damage to our equipment and improvements in the areas in which we operate. In addition, our crews often operate in areas where the risk of wildfires is present and may be increased by our activities. Since our crews are mobile, equipment and personnel are subject to vehicular accidents. We use diesel fuel which is classified by the U.S. Department of Transportation as a hazardous material. These risks could cause us to experience equipment losses, injuries to our personnel and interruptions in our business. Delays due to operational disruptions such as equipment losses, personnel injuries and business interruptions could adversely affect our profitability and results of operations.
Loss of our information and computer systems could adversely affect our business.
We are heavily dependent on our information systems and computer-based programs, including our seismic information, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, or if we were subject to cyberspace breaches or attacks, possible consequences include our loss of communication links, loss of seismic data and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.
Our business could be negatively impacted by security threats, including cyber-security threats and other disruptions.
We face various security threats, including cyber-security threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the safety of our employees, threats to the security of our facilities and infrastructure, and threats from terrorist acts. Cyber-security attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows.
Our business is subject to government regulation that may adversely affect our future operations.
Our operations are subject to a variety of federal, state, provincial and local laws and regulations, including laws and regulations relating to the protection of the environment and archeological sites and those that may result from climate change legislation. Canadian operations have been historically cyclical due to governmental restrictions on seismic acquisition during certain periods. As a result, there is a risk that there will be a significant amount of unused equipment during those periods. We are required to expend financial and managerial resources to comply with such laws and related permit requirements in our operations, and we anticipate that we will continue to be required to do so in the future. Although such expenditures historically have not been material to us, the fact that such laws or regulations change frequently makes it impossible for us to predict the cost or impact of such laws and regulations on our future operations. The adoption of laws and regulations that have the effect of reducing or curtailing exploration and development activities by energy companies could also adversely affect our operations by reducing the demand for our services.
Current and future legislation or regulation relating to climate change or hydraulic fracturing could negatively affect the exploration and production of oil and gas and adversely affect demand for our services.
In response to concerns suggesting that emissions of certain gases, commonly referred to as “greenhouse gases” (“GHG”) (including carbon dioxide and methane), may be contributing to global climate change, legislative and regulatory measures to address the concerns are in various phases of discussion or implementation at the national and state levels. At least one-half of the states, either individually or through multi-state regional initiatives, have already taken legal measures intended to reduce GHG emissions, primarily through the planned development of GHG emission inventories and/or GHG cap and trade programs. Although various climate change legislative measures have been under consideration by the U.S. Congress, it is not possible at this time to predict whether or when Congress may act on climate change legislation. The U.S. Environmental Protection Agency (the “EPA”) has promulgated a series of rulemakings and taken other actions that the EPA states will result in the regulation of GHG as “air pollutants” under the existing federal Clean Air Act. Furthermore, in 2010, EPA regulations became effective that require monitoring and reporting of GHG emissions on an annual basis, including extensive GHG monitoring and reporting requirements. While this rule does not control GHG emission levels from any facilities, it will cause covered facilities to incur monitoring and reporting costs. Moreover, lawsuits have been filed seeking to require individual companies to reduce GHG emissions from their operations. These and other lawsuits relating to GHG emissions may result in decisions by state and federal courts and agencies that could impact our operations.
This increasing governmental focus on alleged global warming may result in new environmental laws or regulations that may negatively affect us, our suppliers and our clients. This could cause us to incur additional direct costs in complying with any new environmental regulations, as well as increased indirect costs resulting from our clients, suppliers or both incurring additional compliance costs that get passed on to us. Moreover, passage of climate change legislation or other federal or state legislative or regulatory initiatives that regulate or restrict emissions of GHG may curtail production and demand for fossil fuels such as oil and gas in areas where our clients operate and, thus, adversely affect future demand for our services. Reductions in our revenues or increases in our expenses as a result of climate control initiatives could have adverse effects on our business, financial position, results of operations and cash flows.
Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. At the federal level, a bill was introduced in Congress in March 2011 entitled the “Fracturing Responsibility and Awareness of Chemicals Act,” or the “FRAC Act,” that would amend the federal Safe Drinking Water Act, or the “SDWA,” to repeal an exemption from regulation for hydraulic fracturing. The FRAC Act was re-introduced in Congress in June 2013, however, Congress has not taken any significant action on such legislation. If the FRAC Act or similar legislation were enacted, the definition of “underground injection” in the SDWA would be amended to encompass hydraulic fracturing activities. Such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In early 2010, the EPA indicated in a website posting that it intended to regulate hydraulic fracturing under the SDWA and require permitting for any well where hydraulic fracturing was conducted with the use of diesel as an additive. While industry groups have challenged the EPA’s website posting as improper rulemaking, the Agency’s position, if upheld, could require additional permitting. In addition, in March 2010, the EPA commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, and a committee of the U.S. House of Representatives has commenced its own investigation into hydraulic fracturing practices. The EPA issued a final report in December 2016, concluding that hydraulic fracturing activities have the potential to impact drinking water resources, particularly when involving water withdrawals, spills, fracturing into wells with inadequate mechanical integrity, fracturing directly into such resources, underground migration of liquids and gases, and inadequate treatment, disposal, storage and discharge of wastewater. The final report also listed the data gaps and uncertainties that limited the EPA’s ability to fully assess the potential impacts of hydraulic fracturing on drinking water resources.
These legislative and regulatory initiatives imposing additional reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult or costly to complete natural gas wells. Shale gas cannot be
economically produced without extensive fracturing. In the event such legislation is enacted, demand for our seismic acquisition services may be adversely affected.
We are subject to the requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to maintain compliance with Section 404, or if the costs related to maintaining compliance are significant, our profitability, stock price, results of operations and financial condition could be materially adversely affected.
If we are unable to maintain adequate internal controls in accordance with Section 404, as such standards are amended, supplemented, or modified from time to time, we may not be able to ensure that we have effective internal controls over financial reporting on an ongoing basis in accordance with Section 404. Failure to achieve and maintain effective internal controls could have a material adverse effect on our stock price. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of clients, reduce our ability to obtain financing, and/or require additional expenditures to comply with these requirements, each of which could negatively impact our business, profitability and financial condition.
Item 1B.
Item 1B. UNRESOLVED STAFF COMMENTS
None.
Item 2.
Item 2. PROPERTIES
Our headquarters are located in a 34,570 square foot leased property in Midland, Texas. We have two properties in Midland that we own, including a 61,402 square foot property we use as a field office, equipment and fabrication facility, and maintenance and repair shop, along with a 6,600 square foot property that we use as an inventory field office and storage facility.
We also have additional offices in three other cities in Texas: Denison, Houston and Plano. Our Denison warehouse facility consists of one 5,000 square foot building, two 10,000 square foot adjacent buildings and an outdoor storage area of approximately 60,500 square feet. Our Houston sales office is in a 10,041 square foot facility. Our office in Plano, Texas consists of 7,797 square feet of office space.
We lease a 3,443 square foot facility in Denver, Colorado as a sales office. We also lease a 7,480 square foot facility in Oklahoma City, Oklahoma as a sales office.
We lease 15,020 square feet of office, warehouse and shop space located in Calgary, Alberta.
We believe that our existing facilities are being appropriately utilized in line with past experience and are well maintained, suitable for their intended use and adequate to meet our current and future operating requirements.
Item 3.
Item 3. LEGAL PROCEEDINGS
From time to time, we are a party to various legal proceedings arising in the ordinary course of business. Although we cannot predict the outcomes of any such legal proceedings, our management believes that the resolution of pending legal actions will not have a material adverse effect on our financial condition, results of operations or liquidity.
For a discussion of certain contingencies affecting the Company, please refer to Note 16, “Commitments and Contingencies,” to the Consolidated Financial Statements incorporated by reference herein.
Item 4.
Item 4. MINE SAFETY DISCLOSURES
Not applicable.
Part II
Item 5.
Item 5. MARKET FOR OUR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our common stock trades on the NASDAQ under the symbol “DWSN.” The table below represents the high and low sales prices per share for the periods shown.
As of March 5, 2018, the market price for our common stock was $6.25 per share, and we had 109 common stockholders of record, as reported by our transfer agent.
We did not pay any dividends to shareholders in 2017 or 2016. While there are currently no restrictions prohibiting us from paying dividends to our shareholders, our board of directors, after consideration of economic and market conditions affecting the energy industry in general, and the oilfield services business in particular, determined that we would not pay a dividend in respect of our common stock for the foreseeable future. Payment of any dividends in the future will be at the discretion of our board and will depend on our financial condition, results of operations, capital and legal requirements, and other factors deemed relevant by the board.
The following table summarizes certain information regarding securities authorized for issuance under our equity compensation plans as of December 31, 2017. See information and definitions regarding material features of the plans in Note 8, “Stock-Based Compensation,” to the Consolidated Financial Statements incorporated by reference herein.
Equity Compensation Plan Information
(1)
Number of securities to be issued upon the exercise of outstanding options, warrants and rights include 133,760 options that have vested but have not yet been exercised and 171,700 restricted stock unit awards that have not yet vested.
(2)
Excludes unvested restricted stock unit awards, for which there is no exercise price.
(3)
Restricted stock unit awards have no exercise price.
PERFORMANCE GRAPH
The following graph matches Dawson Geophysical Company’s cumulative five year total shareholder return on common stock with the cumulative total returns of the S&P 500 index and the PHLX Oil Service Sector index. The graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends) from December 31, 2012 to December 31, 2017.
The stock prices used in the computation of the graph below reflect those of Legacy TGC from December 31, 2012 to December 31, 2014 multiplied by three to account for the 1-for-3 reverse stock split undertaken by Legacy TGC in connection with the Merger. The stock price at December 31, 2015, 2016, and 2017 reflects that of the combined Company following the Merger, as reported on NASDAQ under the symbol “DWSN”.
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Dawson Geophysical Company, the S&P 500 Index
and the PHLX Oil Service Sector Index
*$100 invested on December 31, 2012 in stock or index, including reinvestment of dividends.
Year ended December 31.
The stock price performance included in this graph is not necessarily indicative of future stock price performance.
Item 6.
Item 6. SELECTED FINANCIAL DATA
The following selected financial data should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the Company’s consolidated financial statements and related notes included in Item 8, “Financial Statements and Supplementary Data.”
(1)
Net loss for the year ended December 31, 2015, the three months ended December 31, 2014 and the year ended September 30, 2014 include transaction costs associated with the Merger of $3,314,000, $1,492,000 and $950,000, respectively.
(2)
Earnings per share for the three months ended December 31, 2014 and for the years ended September 30, 2014, and 2013 have been adjusted for the effect of the Merger by dividing the previously reported earnings per share by the Merger conversion factor of 1.76.
(3)
Calculated based on dividends declared in period regardless of period paid.
(4)
Dividends per share for the three months ended December 31, 2014 and for the year ended September 30, 2014 have been adjusted for the effect of the Merger by dividing the previously reported dividends per share by the Merger conversion factor of 1.76.
(5)
Weighted average shares for the three months ended December 31, 2014 and for the years ended September 30, 2014 and 2013 have been adjusted for the effect of the Merger by multiplying the previously reported weighted average shares by the Merger conversion factor of 1.76.
Item 7.
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our financial statements and related notes thereto included elsewhere in this Form 10-K. Portions of this document that are not statements of historical or current fact are forward-looking statements that involve risk and uncertainties, such as statements of our plans, business strategy, objectives, expectations and intentions. This discussion contains forward-looking statements that involve risks and uncertainties. Please see “Business,” “Disclosure Regarding Forward-Looking Statements” and “Risk Factors” elsewhere in this Form 10-K.
On February 11, 2015, Legacy TGC completed the Merger with Legacy Dawson pursuant to which a wholly-owned subsidiary of Legacy TGC merged with and into Legacy Dawson, with Legacy Dawson continuing after the Merger as the surviving entity and a wholly-owned subsidiary of Legacy TGC. The common stock of the merged company is listed on NASDAQ under the symbol “DWSN.” Under the Merger agreement, at the effective time of the Merger, each issued and outstanding share of Legacy Dawson’s common stock, par value $0.33 1/3 per share, including shares underlying Legacy Dawson’s outstanding equity awards, were converted into the right to receive 1.760 shares of common stock of Legacy TGC, par value $0.01 per share (the “Legacy TGC Common Stock”), after giving effect to a 1-for-3 reverse stock split of Legacy TGC Common Stock which occurred immediately prior to the Merger.
The Merger is accounted for as a reverse acquisition under which Legacy Dawson is considered the accounting acquirer of Legacy TGC. As such, the financial statements of Legacy Dawson are treated as the historical financial statements of the merged company. Except as otherwise specifically provided, this discussion and analysis relates to the business and operations of Legacy Dawson and its consolidated subsidiaries for the periods prior to the closing of the Merger and on a consolidated basis with Legacy TGC and its subsidiaries after the closing of the Merger.
You should read this discussion in conjunction with the financial statements and notes thereto included elsewhere in this Form 10-K. Unless the context requires otherwise, all references in this Item 7 to the “Company,” “we,” “us” or “our” refer to (i) Legacy Dawson and its consolidated subsidiaries, for periods through February 10, 2015 and (ii) the merged company for periods on or after February 11, 2015.
Overview
We are a leading provider of North American onshore seismic data acquisition services with operations throughout the continental U.S. and Canada. Substantially all of our revenues are derived from the seismic data acquisition services we provide to our clients, mainly oil and natural gas companies of all sizes. Our clients consist of major oil and gas companies, independent oil and gas operators, and providers of multi-client data libraries. Demand for our services depends upon the level of spending by these companies for exploration, production, development and field management activities, which depends, in a large part, on oil and natural gas prices. Significant fluctuations in domestic oil and natural gas exploration activities and commodity prices, as we have recently experienced, have affected, and will continue to affect, demand for our services and our results of operations, and such fluctuations continue to be the single most important factor affecting our business and results of operations.
During the fourth quarter of 2017, as anticipated, we experienced a temporary decline in crew utilization primarily due to project readiness issues. We began the fourth quarter operating seven crews in the U.S. and two in Canada, and ended the quarter operating six crews in the U.S. and three in Canada. The fourth quarter in the U.S. historically has been challenging due to shorter work days and the holiday season. We are currently operating seven crews in the U.S. and anticipate operating up to seven crews into the third quarter of 2018. We anticipate completing two microseismic projects in the U.S. during the first half of 2018, and operating four crews in Canada through the end of the winter season which concludes at the end of the first quarter of 2018.
While we continue to experience lower than historical demand, we encountered a moderate increase in demand for our services for the year 2017 when compared to 2016. This resulted in improved productivity and crew utilization, primarily during the second half of the year. The recent rise in oil prices, combined with forecasted oil price increases through 2018, has resulted in increased demand for our services and has brought about a return to positive EBITDA. At the same time, the oil and gas industry’s renewed focus on profitability as well as production growth has further driven an increase in requests for proposals, as more exploration and production operators seek to lower drilling and completion
costs as well as maximize production through the integrated use of seismic data into their development plans. While still well off the demand levels experienced in 2015, the recent increase in bid activity is encouraging.
The majority of our crews are currently working in oil producing basins, however, we anticipate increased seismic data acquisition activity in basins outside of the Permian and Delaware basins as commodity prices improve and those basins become more economic. While our revenues are mainly affected by the level of client demand for our services, our revenues are also affected by the pricing for our services that we negotiate with our clients and the productivity and utilization level of our data acquisition crews. Factors impacting productivity and utilization levels include client demand, commodity prices, whether we enter into turnkey or dayrate contracts with our clients, the number and size of crews, the number of recording channels per crew, crew downtime related to inclement weather, delays in acquiring land access permits, agricultural or hunting activity, holiday schedules, short winter days, crew repositioning and equipment failure. To the extent we experience these factors, our operating results may be affected from quarter to quarter. Consequently, our efforts to negotiate more favorable contract terms in our supplemental service agreements, mitigate permit access delays and improve overall crew productivity may contribute to growth in our revenues.
In response to the lower than historical demand for our services, we have continued our cost reduction measures. Our efforts include the sale of our dynamite energy source drilling operation during March 2017. This operation, acquired as part of our February 2015 Merger with TGC Industries, was sold to a long-term service provider and resulted in a gain of approximately $1.45 million. We also decreased costs through operational restructuring and a reduction in the levels of our in-house supplemental services. We continue an evaluation of all in-house service levels in order to reduce our costs. Due to the additional crews in the field during the fourth quarter, our employee count increased to 851 as of December 31, 2017.
Most of our client contracts are turnkey contracts. The percentage of revenues derived from turnkey contracts represented approximately three-quarters of our revenues in 2017 and 2016. While turnkey contracts allow us to capitalize on improved crew productivity, we also bear more risks related to weather and crew downtime. We expect the percentage of turnkey contracts to remain high as we continue our operations in the mid-continent, western and southwestern regions of the U.S. in which turnkey contracts are more common.
Over time, we have experienced continued increases in recording channel capacity on a per-crew or project basis and high utilization of cable-less and multicomponent equipment. This increase in channel count demand is driven by client needs and is necessary in order to produce higher resolution images, increase crew efficiencies and undertake larger scale projects. In response to project-based channel requirements, we routinely deploy a variable number of channels on a variable number of crews in an effort to maximize asset utilization and meet client needs.
Reimbursable third-party charges related to our use of helicopter support services, permit support services, specialized survey technologies and dynamite energy sources in areas with limited access are other important factors affecting our results. Revenues associated with third-party charges as a percentage of revenues were generally below our historical range during 2017. We expect that as we continue our operations in the more open terrain of the mid-continent, western and southwestern regions of the U.S., the level of these third-party charges will continue to be generally below our historical range of 25% to 35% of revenue.
While the markets for oil and natural gas have been very volatile and are likely to continue to be so in the future, and we can make no assurances as to future levels of domestic exploration or commodity prices, we believe opportunities exist for us to enhance our market position by responding to our clients’ continuing desire for higher resolution subsurface images. If economic conditions continue to weaken such that our clients continue to reduce their capital expenditures or if the sustained drop in oil and natural gas prices worsens, it could continue to result in diminished demand for our seismic services, could cause downward pressure on the prices we charge and would affect our results of operations.
Items Affecting Comparability of Our Financial Results
As discussed above, the Merger was accounted for as a reverse acquisition under which Legacy Dawson was considered the accounting acquirer of Legacy TGC. As such, the historical financial statements of Legacy Dawson are treated as the historical financial statements of the combined company. Due to the foregoing, our financial results for the three months ended December 31, 2014 and the years ended September 30, 2014 and 2013 are not directly comparable to our financial results for the years ended December 31, 2017, 2016 and 2015. This is a result of the combination of the
assets and liabilities and results of operations of two previously separate companies. The financial results for the year ended December 31, 2015 presented in this Form 10-K reflect the operations of Legacy Dawson for the period January 1 through February 10, 2015 and the operations of the combined company for the period February 11 through December 31, 2015.
Results of Operations
Year Ended December 31, 2017 versus Year Ended December 31, 2016
Operating Revenues. Operating revenues for the year ended December 31, 2017 were $157,148,000 as compared to $133,330,000 for the same period of 2016. The increase was primarily due to an increase in utilization rates in 2017 as demand for our services showed moderate improvement over 2016. We also had an increase in reimbursable revenue due to the increased number of acquisition projects. We experienced revenue increases in both the U.S. and Canadian markets in 2017. Although we saw increases in our revenue, we did experience a number of project readiness issues and client-directed delays throughout 2017. Severe weather conditions in several areas of operations during the first and second quarters of 2017 led to short term project delays with our crew count dropping to as low as two in April of 2017.
Operating Expenses. Operating expenses for the year ended December 31, 2017 increased to $139,164,000 as compared to $121,661,000 for the same period of 2016. The increase in operating expenses and reimbursed third-party charges was primarily a result of an increase in utilization rates as discussed in operating revenues above and higher reimbursable expenses corresponding to the increased number of acquisition projects.
General and administrative expenses. General and administrative expenses were 10.3% of revenues in the year ended December 31, 2017 compared to 12.6% of revenues in the same period of 2016. General and administrative expenses decreased to $16,189,000 during the year ended December 31, 2017 from $16,822,000 during the same period of 2016. The primary factor for the decrease in general and administrative expenses was on-going cost reduction efforts to reduce administrative costs to support our operations.
Depreciation expense. Depreciation for the year ended December 31, 2017 totaled $39,235,000 compared to $44,283,000 for the same period of 2016. The decrease in depreciation expense is a result of limiting capital expenditures to necessary maintenance capital requirements in recent years. Our depreciation expense is expected to remain flat during 2018 primarily due to limited capital expenditures to maintain our existing asset base.
Our total operating costs for the year ended December 31, 2017 were $194,588,000, representing a 6.5% increase from the corresponding period of 2016. This change was primarily due to the factors described above.
Income Taxes. Income tax benefit was $5,314,000 for the year ended December 31, 2017 as compared to $6,449,000 for the same period of 2016. The effective tax benefit rates for the years ended December 31, 2017 and 2016 were approximately 14.5% and 13.9%, respectively. Our effective tax rates increased as compared to the corresponding period from the prior year primarily due to the filing and processing of federal and state tax returns and the associated refunds received. Our effective tax rates differ from the statutory federal rate of 35% for certain items such as state and local taxes, valuation allowances, non-deductible expenses and discrete items.
Year Ended December 31, 2016 versus Year Ended December 31, 2015
Operating Revenues. Operating revenues for the year ended December 31, 2016 were $133,330,000 as compared to $234,685,000 for the same period of 2015. The decrease was primarily due to the significant reduction in utilization rates in 2016 as demand for our services decreased as a result of decreased and uncertain commodity prices and reduced client expenditures. Severe weather conditions in several areas of operations during the first and second quarters also led to short term project delays. Client directed delays affected utilization of two to three crews during the third and fourth quarters. Reimbursed third-party charges decreased consistently with the overall drop in revenues during the year ended December 31, 2016.
Operating Expenses. Operating expenses for the year ended December 31, 2016 decreased to $121,661,000 as compared to $205,566,000 for the same period of 2015. The decrease in operating expenses and reimbursed third-party charges was primarily a result of the significant reduction in utilization rates discussed in operating revenues above.
General and administrative expenses. General and administrative expenses were 12.6% of revenues in the year ended December 31, 2016 compared to 9.7% of revenues in the same period of 2015. General and administrative expenses decreased to $16,822,000 during the year ended December 31, 2016 from $22,729,000 during the same period of 2015. The primary factors for the decrease in general and administrative expense were transaction costs of approximately $3,314,000 related to the Merger in 2015 and reduced administrative costs to support our operations.
Depreciation expense. Depreciation for the year ended December 31, 2016 totaled $44,283,000 compared to $47,072,000 for the same period of 2015. The decrease in depreciation expense is a result of limiting capital expenditures to necessary maintenance capital requirements in recent years.
Our total operating costs for the year ended December 31, 2016 were $182,766,000, representing a 33.6% decrease from the corresponding period of 2015. This change was primarily due to the factors described above.
Income Taxes. Income tax benefit was $6,449,000 for the year ended December 31, 2016 as compared to $13,755,000 for the same period of 2015. The effective tax benefit rates for the years ended December 31, 2016 and 2015 were approximately 13.9% and 34.4%, respectively. Our effective tax rates decreased as compared to the corresponding period from the prior year primarily due to the recording of a valuation allowance during the year against our federal net operating loss deferred tax asset and an increase in our valuation allowance against our state net operating loss deferred tax assets. Our effective tax rates differ from the statutory federal rate of 35% for certain items such as state and local taxes, valuation allowances, non-deductible expenses and discrete items.
Use of EBITDA (Non-GAAP measure)
We define EBITDA as net income (loss) plus interest expense, interest income, income taxes, and depreciation and amortization expense. Our management uses EBITDA as a supplemental financial measure to assess:
·
the financial performance of our assets without regard to financing methods, capital structures, taxes or historical cost basis;
·
our liquidity and operating performance over time in relation to other companies that own similar assets and that we believe calculate EBITDA in a similar manner; and
·
the ability of our assets to generate cash sufficient for us to pay potential interest costs.
We also understand that such data are used by investors to assess our performance. However, the term EBITDA is not defined under generally accepted accounting principles (“GAAP”), and EBITDA is not a measure of operating income, operating performance or liquidity presented in accordance with GAAP. When assessing our operating performance or liquidity, investors and others should not consider this data in isolation or as a substitute for net income (loss), cash flow from operating activities or other cash flow data calculated in accordance with GAAP. In addition, our EBITDA may not be comparable to EBITDA or similarly titled measures utilized by other companies since such other companies may not calculate EBITDA in the same manner as us. Further, the results presented by EBITDA cannot be achieved without incurring the costs that the measure excludes: interest, taxes, and depreciation and amortization.
The reconciliation of our EBITDA to our net loss and net cash (used in) provided by operating activities, which are the most directly comparable GAAP financial measures, are provided in the following tables (in thousands):
Liquidity and Capital Resources
Introduction. Our principal sources of cash are amounts earned from the seismic data acquisition services we provide to our clients. Our principal uses of cash are the amounts used to provide these services, including expenses related to our operations and acquiring new equipment. Accordingly, our cash position depends (as do our revenues) on the level of demand for our services. Historically, cash generated from our operations along with cash reserves and borrowings from commercial banks have been sufficient to fund our working capital requirements and, to some extent, our capital expenditures.
Cash Flows. The following table shows our sources and uses of cash (in thousands) for the years ended December 31, 2017, 2016 and 2015:
Year Ended December 31, 2017 versus Year Ended December 31, 2016
Net cash used in operating activities was $6,703,000 for the year ended December 31, 2017 compared to cash provided by operating activities of $8,742,000 for the same period in 2016. Cash reductions were primarily due to an increase in our operating level of accounts receivable as of December 31, 2017.
Net cash provided by investing activities was $16,788,000 for the year ended December 31, 2017 and includes $23,667,000 of cash reserves that were not reinvested offset by cash capital expenditures of $8,675,000. The increase in cash provided by investing activities were aided by $1,325,000 of proceeds from disposal of assets and $375,000 of proceeds on flood insurance claims. Net cash used in investing activities was $22,729,000 for the year ended December 31, 2016 and included $19,250,000 of cash reserves that were invested and cash capital expenditures of $8,251,000. These increases in cash used in investing activities were offset by $1,922,000 of proceeds from disposal of assets and $2,850,000 of proceeds on flood insurance claims.
Net cash used in financing activities was $3,420,000 for the year ended December 31, 2017 and includes principal payments of $2,186,000 on our notes, payments of $1,076,000 under our capital leases, and outflows of $158,000 associated with taxes related to stock vesting. Net cash used in financing activities was $8,483,000 for the year ended December 31, 2016 and included principal payments of $7,554,000 on our notes, payments of $780,000 under our capital leases, and outflows of $149,000 associated with taxes related to stock vesting.
Year Ended December 31, 2016 versus Year Ended December 31, 2015
Net cash provided by operating activities was $8,742,000 and $20,612,000 for the years ended December 31, 2016 and 2015, respectively. This decrease primarily reflects our decline in revenues during the year ended December 31, 2016. Cash received from reductions in our overall operating level of accounts receivable to $16,031,000 as of December 31, 2016 from $35,700,000 as of December 31, 2015 provided $19,669,000 of operating cash flows for the year ended December 31, 2016.
Net cash used in investing activities was $22,729,000 for the year ended December 31, 2016 and included $19,250,000 of cash reserves that were invested and cash capital expenditures of $8,251,000. These increases in cash used in investing activities were offset by $1,922,000 of proceeds from disposal of assets and $2,850,000 of proceeds on flood insurance claims. Net cash provided by investing activities was $15,787,000 for the year ended December 31, 2015 and included cash of $12,382,000 acquired in the Merger, $7,750,000 of short term investment maturities that were not reinvested, $1,501,000 of proceeds from disposal of assets and $1,000,000 of proceeds on flood insurance claims. These increases in cash provided by investing activities were offset by cash capital expenditures of $6,846,000.
Net cash used in financing activities was $8,483,000 for the year ended December 31, 2016 and included principal payments of $7,554,000 on our notes, payments of $780,000 under our capital leases, and outflows of $149,000 associated with taxes related to stock vesting. Net cash used in financing activities was $13,606,000 for the year ended December 31, 2015 and included principal payments of $16,348,000 on our notes, payments of $1,535,000 under our capital leases, and outflows of $867,000 associated with taxes related to stock vesting offset by proceeds of $5,144,000 from our Credit Agreement (as defined below).
Capital Expenditures. During 2017, we made capital expenditures of $16,310,000. Our Board of Directors approved an increase to our 2017 capital budget during the third quarter, raising it from $10,000,000 to $16,000,000. This was due to an opportunity to acquire seismic data acquisition equipment during that quarter. The Board of Directors approved an initial 2018 budget of $10,000,000 for capital expenditures, which is limited primarily to necessary maintenance capital requirements and incremental recording channel replacement or increase. In recent years, we have funded some of our capital expenditures through capital leases, cash reserves, and equipment term loans. In the past, we have also funded our capital expenditures and other financing needs through public equity offerings.
We continually strive to supply our clients with technologically advanced 3-D data acquisition recording services and data processing capabilities. We maintain equipment in and out of service in anticipation of increased future demand for our services.
Capital Resources. Historically, we have primarily relied on cash generated from operations, cash reserves and borrowings from commercial banks to fund our working capital requirements and, to some extent, our capital expenditures. Recently, we have funded some of our capital expenditures through capital leases and equipment term loans. From time to time in the past, we have also funded our capital expenditures and other financing needs through public equity offerings.
Indebtedness. On June 30, 2015, we entered into an amendment to our Credit Agreement with our lender Sovereign Bank, (as amended from time to time, the “Credit Agreement”) for the purpose of renewing, extending and increasing our line of credit under such agreement. The Credit Agreement was renewed on June 30, 2017. In a merger effective September 11, 2017, Sovereign Bank merged with and into Veritex Bank.
Credit Agreement. Our Credit Agreement with Veritex Bank (formerly Sovereign Bank) includes term loan and revolving loan features, and also allows for the issuance of letters of credit and other promissory notes. We can borrow up to a maximum of $20.0 million pursuant to the Credit Agreement, subject to the terms and limitations discussed below.
The Credit Agreement provides for a revolving loan feature (the “Line of Credit”) that permits us to borrow, repay and re-borrow, from time to time until June 30, 2018, up to the lesser of (i) $20.0 million or (ii) a sum equal to (a) 80% of our eligible accounts receivable (less the outstanding principal balance of term loans and letters of credit under the Credit Agreement) and (b) the lesser of (i) 50% of the value of certain of our core equipment or (ii) $12,500,000. We have not utilized the Line of Credit since its inception. Because our ability to borrow funds under the Line of Credit is tied to the amount of our eligible accounts receivable and value of certain of our core equipment, if our accounts receivable decrease materially for any reason, including delays, reductions or cancellations by clients, or decreased demand for our services, or the value of our pledged core equipment decreases materially, our borrowing ability to fund operations or other obligations may be reduced.
The Credit Agreement also provides for a term loan feature. We have no outstanding notes payable under the term loan feature of the Credit Agreement, and any notes outstanding under this feature would count toward the maximum amounts we may borrow under the Credit Agreement.
We paid off our remaining equipment note payable during the third quarter of 2017. We do not currently have any notes payable under our Credit Agreement.
Our obligations under the Line of Credit are secured by a security interest in our accounts receivable and certain of our core equipment, and the term loans are also secured by certain of our core equipment. Interest on amounts outstanding under the Credit Agreement accrues at the lesser of 4.5% or the prime rate (as quoted in the Wall Street Journal), subject to an interest rate floor of 2.5%. The Credit Agreement contains customary covenants for credit facilities of this type, including limitations on disposition of assets, mergers and other fundamental changes. We are also obligated to meet certain financial covenants, including (i) a ratio of (x) total liabilities minus subordinated debt to (y) tangible net worth plus subordinated debt not to exceed 1.00:1.00, (ii) a ratio of current assets to current liabilities of at least 1.50:1.00 and (iii) required tangible net worth of not less than $125,000,000. We were in compliance with all covenants under the Credit Agreement, including specified ratios, as of December 31, 2017.
Veritex Bank has issued three letters of credit as of December 31, 2017. The first letter of credit is in the amount of $1,767,000 to support payment of our insurance obligations. The principal amount of this letter of credit is collateralized by certain of our core equipment. The second letter of credit is in the amount of $583,000 to support our workers’ compensation insurance and is secured by a certificate of deposit. The third letter of credit is unsecured and in the amount of $75,000, to support certain of our performance obligations. None of the letters of credit count as funds borrowed under our Line of Credit.
Other Indebtedness. We paid in full, during November 2017, one note payable to a finance company for various insurance premiums.
In addition, we lease certain seismic recording equipment and vehicles under leases classified as capital leases. Our Consolidated Balance Sheets as of December 31, 2017 include capital lease obligations of $7,865,000.
Contractual Obligations. We believe that our capital resources, including our short-term investments, cash flow from operations, and funds available under our Line of Credit, will be adequate to meet our current operational needs. We believe that we will be able to finance our 2018 capital expenditures through cash flow from operations, borrowings from commercial lenders, and the funds available under our Line of Credit. However, our ability to satisfy working capital requirements, meet debt repayment obligations, and fund future capital requirements will depend principally upon our future operating performance, which is subject to the risks inherent in our business, and will also depend on the extent to which the current economic climate adversely affects the ability of our customers, and/or potential customers, to promptly pay amounts owing to us under their service contracts with us.
The following table summarizes payments due in specific periods related to our contractual obligations with initial terms exceeding one year as of December 31, 2017 (in thousands):
Off-Balance Sheet Arrangements
As of December 31, 2017, we had no off-balance sheet arrangements under current GAAP. However, we do have operating leases discussed above in the “Liquidity and Capital Resources: Contractual Obligations” section and below in the “Recently Issued Accounting Pronouncements” section.
Critical Accounting Policies
The preparation of our financial statements in conformity with GAAP requires that certain assumptions and estimates be made that affect the reported amounts of assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reporting periods. Because of the use of assumptions and estimates inherent in the reporting process, actual results could differ from those estimates.
Allowance for Doubtful Accounts. We prepare our allowance for doubtful accounts receivable based on our review of past-due accounts, our past experience of historical write-offs and our current client base. While the collectability
of outstanding client invoices is continually assessed, the inherent volatility of the energy industry’s business cycle can cause swift and unpredictable changes in the financial stability of our clients.
Impairment of Long-Lived Assets. We review long-lived assets for impairment when triggering events occur suggesting deterioration in the assets’ recoverability or fair value. Recognition of an impairment charge is required if future expected undiscounted net cash flows are insufficient to recover the carrying value of the assets, and the fair value of the assets is below the carrying value of the assets. Our forecast of future cash flows used to perform impairment analysis includes estimates of future revenues and expenses based on our anticipated future results while considering anticipated future oil and gas prices, which is fundamental in assessing demand for our services. If the carrying amounts of the assets exceed the estimated expected undiscounted future cash flows, we measure the amount of possible impairment by comparing the carrying amount of the asset to its fair value. No impairment charges were recognized for the years ended December 31, 2017, 2016 and 2015.
Leases. We lease certain vehicles and seismic recording equipment under lease agreements. We evaluate each lease to determine its appropriate classification as an operating or capital lease for financial reporting purposes. Any lease that does not meet the criteria for a capital lease is accounted for as an operating lease. The assets and liabilities under capital leases are recorded at the lower of the present value of the minimum lease payments or the fair market value of the related assets. Assets under capital leases are amortized using the straight-line method over the initial lease term. Amortization of assets under capital leases is included in depreciation expense.
Revenue Recognition. Our services are provided under cancelable service contracts. These contracts are either “turnkey” or “term” agreements. Under both types of agreements, we recognize revenues when revenue is realizable and services are performed. Services are defined as the commencement of data acquisition or processing operations. Revenues are considered realizable when earned according to the terms of the service contracts. Under turnkey agreements, revenue is recognized on a per-unit-of-data-acquired rate, as services are performed. Under term agreements, revenue is recognized on a per-unit-of-time-worked rate, as services are performed. In the case of a cancelled service contract, we recognize revenue and bill our client for services performed up to the date of cancellation.
We also receive reimbursements for certain out-of-pocket expenses under the terms of our service contracts. We record amounts billed to clients in revenue at the gross amount including out-of-pocket expenses that are reimbursed by the client.
In some instances, we bill clients in advance of the services performed. In those cases, we recognize the liability as deferred revenue. As services are performed, those deferred revenue amounts are recognized as revenue.
In some instances, the contract contains certain permitting, surveying and drilling costs that are incorporated into the per-unit-of-data-acquired rate. In these circumstances, these set-up costs that occur prior to initiating revenue recognition are capitalized and amortized as data is acquired.
Income Taxes. We account for our income taxes with the recognition of amounts of taxes payable or refundable for the current year and by using an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been recognized in our financial statements or tax returns. We determine deferred taxes by identifying the types and amounts of existing temporary differences, measuring the total deferred tax asset or liability using the applicable tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates of deferred tax assets and liabilities is recognized in income in the year of an enacted rate change. The deferred tax asset is reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Our methodology for recording income taxes requires judgment regarding assumptions and the use of estimates, including determining our annual effective tax rate and the valuation of deferred tax assets, which can create a variance between actual results and estimates and could have a material impact on our provision or benefit for income taxes. Due to our recent operating losses and valuation allowances, we may recognize reduced or no tax benefits on future losses on the Consolidated Statements of Operations and Comprehensive Loss. Our effective tax rates differ from the statutory federal rate of 35% for certain items such as state and local taxes, valuation allowances, non-deductible expenses and discrete items.
Recently Issued Accounting Pronouncements
In February 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act passed by the U.S. federal government in December 2017. This ASU is effective for the annual period beginning after December 15, 2018, and for annual and interim periods thereafter. We do not believe this ASU will have a material impact on our condensed consolidated financial statements.
In May 2017, the FASB issued ASU No. 2017-09, Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting, which provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. This ASU is effective for the annual period beginning after December 15, 2017, and for annual and interim periods thereafter. We do not believe this ASU will have a material impact on our condensed consolidated financial statements.
In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which is intended to simplify accounting for share-based payments awarded to employees, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This ASU was effective for the annual period beginning after December 15, 2016, and for annual and interim periods thereafter. We adopted ASU 2016-09 in the first quarter of 2017 and elected to account for forfeitures as they occur, rather than estimate expected forfeitures. As a result of adopting this standard, we applied the modified retrospective approach and recorded a cumulative-effect adjustment within the Consolidated Statements of Stockholders’ Equity that had no material impact on our condensed consolidated financial statements.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases. In January 2017, the FASB issued ASU No. 2017-03, Accounting Changes and Error Corrections (Topic 250) and Investments - Equity Method and Joint Ventures (Topic 323), which stated additional qualitative disclosures should be considered to assess the significance of the impact upon adoption. This ASU is effective for the annual period beginning after December 15, 2018, and for annual and interim periods thereafter. Early adoption is permitted. In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current lease guidance in Topic 840. We are currently evaluating the new guidance and practical expedient to determine the impact they will have on our condensed consolidated financial statements and believe that the most significant change will be to our Condensed Consolidated Balance Sheets as our asset and liability balances will increase for operating leases that are currently off-balance sheet.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. Entities have the option of using either a full retrospective or modified approach to adopt ASU No. 2014-09. Subsequent amendments to the initial guidance have been issued in March 2016, April 2016, May 2016, December 2016, January 2017, and September 2017 within ASU No. 2016-08, ASU No. 2016-10, ASU No. 2016-12, ASU No. 2016-20, ASU No. 2017-03, and ASU No. 2017-13 regarding principal-versus-agent, performance obligations and licensing, assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. These updates do not change the core principle of the guidance under ASU No. 2014-09, but rather provide implementation guidance. This new standard must be adopted by us in our calendar year beginning January 1, 2018. We have completed our assessment of the new standard and are adopting the standard using the full retrospective method.
For further information regarding the impact of this ASU on our consolidated financial statements see Note 17, “Recently Issued Accounting Pronouncements” to the Consolidated Financial Statements.
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to certain market risks arising from the use of financial instruments in the ordinary course of business. These risks arise primarily as a result of potential changes to operating concentration of credit risk and changes in interest rates. We have not entered into any hedge arrangements, commodity swap agreements, commodity futures, options or other derivative financial instruments. We also conduct business in Canada, which subjects our results of operations and cash flows to foreign currency exchange rate risk.
Concentration of Credit Risk. Our principal market risks include fluctuations in commodity prices, which affect demand for and pricing of our services, and the risk related to the concentration of our clients in the oil and natural gas industry. Since all of our clients are involved in the oil and natural gas industry, there may be a positive or negative effect on our exposure to credit risk because our clients may be similarly affected by changes in economic and industry conditions. As an example, changes to existing regulations or the adoption of new regulations may unfavorably impact us, our suppliers or our clients. In the normal course of business, we provide credit terms to our clients. Accordingly, we perform ongoing credit evaluations of our clients and maintain allowances for possible losses. Our historical experience supports our allowance for doubtful accounts of $250,000 at December 31, 2017. This does not necessarily indicate that it would be adequate to cover a payment default by one large or several smaller clients.
We generally provide services to certain key clients that account for a significant percentage of our accounts receivable at any given time. Our key clients vary over time. We extend credit to various companies in the oil and natural gas industry, including our key clients, for the acquisition of seismic data, which results in a concentration of credit risk. This concentration of credit risk may be affected by changes in the economic or other conditions of our key clients and may accordingly impact our overall credit risk. If any of these significant clients were to terminate their contracts or fail to contract for our services in the future because they are acquired, alter their exploration or development strategy, or for any other reason, our results of operations could be affected. Because of the nature of our contracts and clients’ projects, our largest clients can change from year to year, and the largest clients in any year may not be indicative of the largest clients in any subsequent year. During the twelve months ended December 31, 2017, our two largest clients accounted for approximately 27% of revenue. The remaining balance of our revenue derived from varied clients and none represented more than 10% of revenue.
Interest Rate Risk. From time to time, we are exposed to the impact of interest rate changes on the outstanding indebtedness under our Credit Agreement.
We generally have cash in the bank which exceeds federally insured limits. Historically, we have not experienced any losses in such accounts; however, volatility in financial markets may impact our credit risk on cash and short-term investments. At December 31, 2017, cash and cash equivalents totaled $22,013,000.
For further information, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Item 1A. Risk Factors.”
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item appears on pages through hereof and are incorporated herein by reference.
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
Item 9A.
Item 9A. CONTROLS AND PROCEDURES
Management’s Evaluation of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive, financial and accounting officers, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this report. Based
upon that evaluation, our President and Chief Executive Officer, and our Executive Vice President, Chief Financial Officer, Secretary, and Treasurer concluded that, as of December 31, 2017, our disclosure controls and procedures were effective, in all material respects, with regard to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, for information required to be disclosed by us in the reports that we file or submit under the Exchange Act. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our President and Chief Executive Officer, and our Executive Vice President, Chief Financial Officer, Secretary, and Treasurer, as appropriate, to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of management, including our President and Chief Executive Officer, and Executive Vice President, Chief Financial Officer, Secretary, and Treasurer, we evaluated the effectiveness of our internal controls over financial reporting as of December 31, 2017 using the criteria set forth in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on this evaluation, we have concluded that, as of December 31, 2017, our internal control over financial reporting was effective. Our internal control over financial reporting as of December 31, 2017 has been audited by RSM US LLP, the independent registered public accounting firm who also audited our financial statements. Their attestation report appears on page.
Changes in Internal Control over Financial Reporting
In the fourth quarter of 2017, we added and/or modified certain internal controls and processes in preparation of adopting the new revenue recognition standard in January 2018 under the full retrospective approach. There have not been any additional changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) of the Exchange Act) during the quarter ended December 31, 2017 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
Item 9B.
Item 9B. OTHER INFORMATION
None.
Part III
Item 10.
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by Item 10 of Form 10-K is hereby incorporated by reference from the earlier filed of: (i) an amendment to this annual report on Form 10-K or (ii) the Company’s definitive proxy statement which will be filed pursuant to Regulation 14A within 120 days after the Company’s year-end for the year covered by this report.
Item 11.
Item 11. EXECUTIVE COMPENSATION
The information required by Item 11 of Form 10-K is hereby incorporated by reference from the earlier filed of: (i) an amendment to this annual report on Form 10-K or (ii) the Company’s definitive proxy statement which will be filed pursuant to Regulation 14A within 120 days after the Company’s year-end for the year covered by this report.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required with respect to our equity compensation plans is set forth in Item 5 of this Form 10-K. Other information required by Item 12 of Form 10-K is hereby incorporated by reference from the earlier filed of: (i) an amendment to this annual report on Form 10-K or (ii) the Company’s definitive proxy statement which will be filed pursuant to Regulation 14A within 120 days after the Company’s year-end for the year covered by this report.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The information required by Item 13 of Form 10-K is hereby incorporated by reference from the earlier filed of: (i) an amendment to this annual report on Form 10-K or (ii) the Company’s definitive proxy statement which will be filed pursuant to Regulation 14A within 120 days after the Company’s year-end for the year covered by this report.
Item 14.
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by Item 14 of Form 10-K is hereby incorporated by reference from the earlier filed of: (i) an amendment to this annual report on Form 10-K or (ii) the Company’s definitive proxy statement, which will be filed pursuant to Regulation 14A within 120 days after the Company’s year-end for the year covered by this report.
Part IV
Item 15.
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)The following documents are filed as part of this report:
(1)Financial Statements.
The following consolidated financial statements of the Company appear on pages through and are incorporated by reference into Part II, Item 8:
Reports of Independent Registered Public Accounting Firms 		
Consolidated Balance Sheets 		
Consolidated Statements of Operations and Comprehensive Loss 		
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to the Consolidated Financial Statements 		
(2)Financial Statement Schedules.
All schedules are omitted because they are either not applicable or the required information is shown in the financial statements or notes thereto.
(3)Exhibits.
The information required by this item 15(a)(3) is set forth in the Index to Exhibits accompanying this Annual Report on Form 10-K and is hereby incorporated by reference.
INDEX TO EXHIBITS
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Midland, and the State of Texas, on the 9th day of March, 2018.
Pursuant to the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ Stephen C. Jumper
Stephen C. Jumper
President, Chief Executive Officer and Chairman of the Board of Directors
(principal executive officer)
03-09-18
/s/ Wayne A. Whitener
Wayne A. Whitener
Vice Chairman of the Board of Directors
03-09-18
/s/ William J. Barrett
William J. Barrett
Director
03-09-18
/s/ Craig W. Cooper
Craig W. Cooper
Director
03-09-18
/s/ Gary M. Hoover
Gary M. Hoover
Director
03-09-18
/s/ Allen T. McInnes
Allen T. McInnes
Director
03-09-18
/s/ Ted R. North
Ted R. North
Director
03-09-18
/s/ Mark A. Vander Ploeg
Mark A. Vander Ploeg
Director
03-09-18
/s/ James K. Brata
James K. Brata
Executive Vice President, Chief Financial Officer, Secretary, and Treasurer
(principal financial and accounting officer)
03-09-18
			 		
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
Dawson Geophysical Company
Opinion on the Internal Control Over Financial Reporting
We have audited Dawson Geophysical Company's (the Company) internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets as of December 31, 2017 and 2016, the related consolidated statements of operations and comprehensive loss, stockholders' equity and cash flows for each of the years then ended of the Company and our report dated March 9, 2017 expressed an unqualified opinion.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ RSM US LLP
Houston, Texas
March 9, 2018
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
Dawson Geophysical Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Dawson Geophysical Company and its subsidiaries (the Company) as of December 31, 2017 and 2016, the related consolidated statements of operations and comprehensive loss, stockholders' equity and cash flows for each of the years then ended, and the related notes to the consolidated financial statements.
In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013, and our report dated March 9, 2018 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ RSM US LLP
We have served as the Company's auditor since 2016.
Houston, Texas
March 9, 2018
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Dawson Geophysical Company
We have audited the accompanying consolidated statements of operations and comprehensive loss, stockholders' equity and cash flows for the year ended December 31, 2015. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows of Dawson Geophysical Company for the year ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Dallas, Texas
March 15, 2016
DAWSON GEOPHYSICAL COMPANY
CONSOLIDATED BALANCE SHEETS
(amounts in thousands, except share data)
See accompanying notes to the consolidated financial statements.
DAWSON GEOPHYSICAL COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS
(amounts in thousands, except share and per share data)
See accompanying notes to the consolidated financial statements.
			 		
DAWSON GEOPHYSICAL COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(amounts in thousands, except share data)
See accompanying notes to the consolidated financial statements.
DAWSON GEOPHYSICAL COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in thousands)
See accompanying notes to the consolidated financial statements.
			 		
DAWSON GEOPHYSICAL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On February 11, 2015, the Company, which was formerly known as TGC Industries, Inc. (“Legacy TGC”), consummated a strategic business combination (the “Merger”) with Dawson Operating Company LLC, which was formerly known as Dawson Geophysical Company (“Legacy Dawson”). Unless the context requires otherwise, all references in the Notes to Consolidated Financial Statements of this Form 10-K to the “Company,” “we,” “us” or “our” refer to (i) Legacy Dawson and its consolidated subsidiaries, for periods through February 10, 2015 and (ii) the merged company for periods on or after February 11, 2015.
1. Summary of Significant Accounting Policies
Organization and Nature of Operations
The Company is a leading provider of onshore seismic data acquisition and processing services. Founded in 1952, the Company acquires and processes 2-D, 3-D and multi-component seismic data for its clients, ranging from major oil and gas companies to independent oil and gas operators as well as providers of multi-client data libraries. The Company operates in the lower 48 states of the U.S. and in Canada.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Dawson Operating LLC, Eagle Canada, Inc., Dawson Seismic Services Holdings, Inc., Eagle Canada Seismic Services ULC and Exploration Surveys, Inc. All significant intercompany balances and transactions have been eliminated in consolidation.
Cash Equivalents
For purposes of the financial statements, the Company considers demand deposits, certificates of deposit, overnight investments, money market funds and all highly liquid debt instruments purchased with an initial maturity of three months or less to be cash equivalents.
Allowance for Doubtful Accounts
Management determines the need for any allowance for doubtful accounts receivable based on its review of past-due accounts, its past experience of historical write-offs and its current client base. While the collectability of outstanding client invoices is continually assessed, the inherent volatility of the energy industry’s business cycle can cause swift and unpredictable changes in the financial stability of the Company’s clients.
Property and Equipment
Property and equipment is capitalized at historical cost or the fair value of assets acquired in a business combination and is depreciated over the useful life of the asset. Management’s estimation of this useful life is based on circumstances that exist in the seismic industry and information available at the time of the purchase of the asset. As circumstances change and new information becomes available, these estimates could change.
Depreciation is computed using the straight-line method. When assets are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the balance sheet, and any resulting gain or loss is reflected in the results of operations for the period.
Impairment of Long-Lived Assets
Long-lived assets are reviewed for impairment when triggering events occur suggesting deterioration in the assets’ recoverability or fair value. Recognition of an impairment charge is required if future expected undiscounted net cash flows are insufficient to recover the carrying value of the assets, and the fair value of the assets is below the carrying value of the assets. Management’s forecast of future cash flows used to perform impairment analysis includes estimates
of future revenues and expenses based on the Company’s anticipated future results, while considering anticipated future oil and natural gas prices which is fundamental in assessing demand for the Company’s services. If the carrying amounts of the assets exceed the estimated expected undiscounted future cash flows, the Company measures the amount of possible impairment by comparing the carrying amount of the assets to the fair value. No impairment charges were recognized for the years ended December 31, 2017, 2016 and 2015.
Leases
The Company leases certain seismic recording equipment and vehicles under lease agreements. The Company evaluates each lease to determine its appropriate classification as an operating or capital lease for financial reporting purposes. Any lease that does not meet the criteria for a capital lease is accounted for as an operating lease. The assets and liabilities under capital leases are recorded at the lower of the present value of the minimum lease payments or the fair market value of the related assets. Assets under capital leases are amortized using the straight-line method over the initial lease term. Amortization of assets under capital leases is included in depreciation expense.
Intangibles
The Company has intangible assets consisting primarily of trademarks/tradenames (which are not amortized) resulting from a business combination. The Company tests for impairment on an annual basis during the fourth quarter, and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount. No impairment charges were recognized for the years ended December 31, 2017, 2016 and 2015.
Revenue Recognition
Services are provided under cancelable service contracts. These contracts are either “turnkey” or “term” agreements. Under both types of agreements, the Company recognizes revenues when revenue is realizable and services have been performed. Services are defined as the commencement of data acquisition or processing operations. Revenues are considered realizable when earned according to the terms of the service contracts. Under turnkey agreements, revenue is recognized on a per-unit-of-data-acquired rate as services are performed. Under term agreements, revenue is recognized on a per-unit-of-time-worked rate as services are performed. In the case of a cancelled service contract, revenue is recognized and the client is billed for services performed up to the date of cancellation.
The Company receives reimbursements for certain out-of-pocket expenses under the terms of the service contracts. Amounts billed to clients are recorded in revenue at the gross amount, including out-of-pocket expenses that are reimbursed by the client.
In some instances, clients are billed in advance of services performed. In those cases, the Company recognizes the liability as deferred revenue. As services are performed, those deferred revenue amounts are recognized as revenue.
In some instances, the contract contains certain permitting, surveying and drilling costs that are incorporated into the per-unit-of-data-acquired rate. In these circumstances, these set-up costs that occur prior to initiating revenue recognition are capitalized and amortized as data is acquired.
Stock-Based Compensation
The Company measures all stock-based compensation awards, which include stock options, restricted stock, restricted stock units and common stock awards, using the fair value method and recognizes compensation expense, net of actual forfeitures, as operating or general and administrative expense, as appropriate, in the Consolidated Statements of Operations and Comprehensive Loss on a straight-line basis over the vesting period of the related awards.
Foreign Currency Translation
The U.S. Dollar is the reporting currency for all periods presented. The functional currency of the Company’s foreign subsidiaries is generally the local currency. Any transactions denominated in a currency other than the functional currency are remeasured with the resulting unrealized gain or loss recognized in the Consolidated Statements of Operations and Comprehensive Loss as other income (expense). All assets and liabilities in the functional currency are then translated
into U.S. Dollars at the exchange rate on the balance sheet date. Income and expenses are translated using the exchange rate applicable to each transaction. Equity transactions are translated using historical exchange rates. Adjustments resulting from translation are recorded as a separate component of accumulated other comprehensive income (loss) in the Consolidated Balance Sheets. Realized foreign currency transaction gains (losses) are included in the Consolidated Statements of Operations and Comprehensive Loss as other income (expense).
Income Taxes
The Company accounts for income taxes by recognizing amounts of taxes payable or refundable for the current year, and by using an asset and liability approach in recognizing the amount of deferred tax assets and liabilities for the future tax consequences of events that have been recognized in the Company’s financial statements or tax returns. Management determines deferred taxes by identifying the types and amounts of existing temporary differences, measuring the total deferred tax asset or liability using the applicable tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates of deferred tax assets and liabilities is recognized in income in the year of an enacted rate change. The deferred tax asset is reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax asset will not be realized. Management’s methodology for recording income taxes requires judgment regarding assumptions and the use of estimates, including determining the annual effective tax rate and the valuation of deferred tax assets, which can create variances between actual results and estimates and could have a material impact on the Company’s provision or benefit for income taxes. Due to recent operating losses and valuation allowances, the Company may recognize reduced or no tax benefits on future losses on the Consolidated Statements of Operations and Comprehensive Loss. The Company’s effective tax rates differ from the statutory federal rate of 35% for certain items such as state and local taxes, valuation allowances, non-deductible expenses and discrete items.
Use of Estimates in the Preparation of Financial Statements
Preparation of the accompanying financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Because of the use of assumptions and estimates inherent in the reporting process, actual results could differ from those estimates.
Reclassifications
Certain reclassifications have been made to the years ended December 31, 2016 and 2015 consolidated financial statements to conform to the 2017 presentation. This includes reclassifications on the Consolidated Statements of Cash Flows for the adoption in 2016 of ASU No 2016-05.
2.Short-Term Investments
The Company had short-term investments at December 31, 2017 and 2016 consisting of certificates of deposit with original maturities greater than three months but less than a year. Certificates of deposits with any given banking institution did not exceed the FDIC insurance limit at December 31, 2017 or 2016.
3. Fair Value of Financial Instruments
At December 31, 2017 and 2016, the Company’s financial instruments included cash and cash equivalents, short-term investments in certificates of deposit, accounts receivable, other current assets, accounts payable, other current liabilities and notes payable. At December 31, 2017, the Company’s financial instruments also included notes receivable. Due to the short-term maturities of cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities, the carrying amounts approximate fair value at the respective balance sheet dates. The carrying value of the notes receivable and notes payable approximate their fair value based on a comparison with the prevailing market interest rates. Due to the short-term maturities of the Company’s investments in certificates of deposit, the carrying amounts approximate fair value at the respective balance sheet dates. The fair values of the Company’s notes receivable, notes payable and investments in certificates of deposit are level 2 measurements in the fair value hierarchy.
4. Merger
On February 11, 2015, the Company completed the Merger. Immediately prior to the effective time of the Merger, Legacy TGC effected a reverse stock split with respect to its common stock, par value $0.01 per share, on a one-for-three ratio (the “Reverse Stock Split”) to reduce the total number of shares of Legacy TGC Common Stock outstanding. After giving effect to the Reverse Stock Split, at the effective time of the Merger, without any action on the part of any shareholder, each issued and outstanding share of Legacy Dawson’s common stock, par value $0.33-1/3 per share (the “Legacy Dawson Common Stock”), including shares underlying Legacy Dawson’s outstanding equity awards (but excluding any shares of Legacy Dawson Common Stock owned by Legacy TGC, Merger Sub or Legacy Dawson or any wholly-owned subsidiary of Legacy Dawson), were converted into the right to receive 1.760 shares of Legacy TGC Common Stock (the “Exchange Ratio”).
The Merger was accounted for as a reverse acquisition under the acquisition method of accounting in accordance with ASC No. 805, “Business Combinations.” The Company accounted for the transaction by using Legacy Dawson’s historical information and accounting policies and adding the assets and liabilities of Legacy TGC at their respective fair values. Consequently, Legacy Dawson’s assets and liabilities retained their carrying values and Legacy TGC’s assets acquired and liabilities assumed by Legacy Dawson as the accounting acquirer in the Merger were recorded at their fair values measured as of February 11, 2015, the effective date of the Merger.
5. Property and Equipment
Property and equipment (in thousands), together with the related estimated useful lives at December 31, 2017 and 2016, were as follows:
6. Supplemental Consolidated Balance Sheet Information
Other current liabilities (in thousands) consist of the following at December 31, 2017 and 2016:
7. Debt
On June 30, 2015, the Company entered into an amendment to its Credit Agreement with its lender, Sovereign Bank for the purpose of renewing, extending and increasing the Company’s line of credit under such agreement. The Credit Agreement was renewed on June 30, 2017. In a merger effective September 11, 2017, Sovereign Bank merged with and into Veritex Bank.
Credit Agreement
The Credit Agreement provides for a revolving loan feature, or Line of Credit, that permits the Company to borrow, repay and re-borrow, from time to time until June 30, 2018, up to the lesser of (i) $20.0 million or (ii) a sum equal
to (a) 80% of the Company’s eligible accounts receivable (less the outstanding principal balance of term loans and letters of credit under the Credit Agreement) and (b) the lesser of (i) 50% of the value of certain of the Company’s core equipment or (ii) $12,500,000. The Company has not utilized the Line of Credit since its inception. Because the Company’s ability to borrow funds under the Line of Credit is tied to the amount of the Company’s eligible accounts receivable and value of certain of its core equipment, if the Company’s accounts receivable decrease materially for any reason, including delays, reductions or cancellations by clients, or decreased demand for the Company’s services, or the value of the Company’s pledged core equipment decreases materially, the Company’s borrowing ability to fund operations or other obligations may be reduced.
The Credit Agreement also provides for a term loan feature. The Company has no outstanding notes payable under the term loan feature of the Credit Agreement, and any notes outstanding under this feature would count toward the maximum amounts the Company may borrow under the Credit Agreement.
The Company paid off the remaining equipment note payable during the third quarter of 2017. The Company does not currently have any notes payable under the Credit Agreement.
The Company’s obligations under the Line of Credit are secured by a security interest in the Company’s accounts receivable and certain of the Company’s core equipment, and the term loans are also secured by certain of the Company’s core equipment. Interest on amounts outstanding under the Credit Agreement accrues at the lesser of 4.5% or the prime rate (as quoted in the Wall Street Journal), subject to an interest rate floor of 2.5%. The Credit Agreement contains customary covenants for credit facilities of this type, including limitations on disposition of assets, mergers and other fundamental changes. The Company is also obligated to meet certain financial covenants, including (i) a ratio of (x) total liabilities minus subordinated debt to (y) tangible net worth plus subordinated debt not to exceed 1.00:1.00, (ii) a ratio of current assets to current liabilities of at least 1.50:1.00 and (iii) required tangible net worth of not less than $125,000,000. The Company was in compliance with all covenants under the Credit Agreement, including specified ratios, as of December 31, 2017.
Veritex Bank has issued three letters of credit as of December 31, 2017. The first letter of credit is in the amount of $1,767,000 to support payment of certain insurance obligations of the Company. The principal amount of this letter of credit is collateralized by certain of the Company’s core equipment. The second letter of credit is in the amount of $583,000 to support the company’s workers’ compensation insurance and is secured by a certificate of deposit. The third letter of credit is unsecured and in the amount of $75,000 to support certain performance obligations of the Company. None of the letters of credit count as funds borrowed under the Company’s Line of Credit.
Other Indebtedness
The Company paid in full, during November 2017, one note payable to a finance company for various insurance premiums.
In addition, the Company leases certain seismic recording equipment and vehicles under leases classified as capital leases. The Company’s Consolidated Balance Sheets as of December 31, 2017 and 2016 include capital lease obligations of $7,865,000 and $419,000, respectively.
Maturities of Debt
The Company’s aggregate principal amount (in thousands) of outstanding notes payable and the interest rates and monthly payments as of December 31, 2017 and 2016 are as follows:
The Company’s aggregate maturities of obligations under capital leases (in thousands) at December 31, 2017 are as follows:
Interest rates on these leases ranged from 3.16% to 6.72%.
8. Stock-Based Compensation
Since the date of its effectiveness on May 5, 2016, the Company issues new grants of stock-based awards pursuant to the Dawson Geophysical Company 2016 Stock and Performance Incentive Plan (the “2016 Plan”). Upon its effectiveness, the 2016 Plan replaced: (i) the Amended and Restated Dawson Geophysical Company 2006 Stock and Performance Incentive Plan (the “Legacy Dawson Plan”), which originated from Legacy Dawson and (ii) the Amended and Restated 2006 Stock Awards Plan of Dawson Geophysical Company (formerly known as the TGC Industries, Inc. 2006 Stock Awards Plan) (the “Legacy TGC Plan”), which originated from Legacy TGC (the Legacy Dawson Plan and the Legacy TGC Plan are referred to collectively as, (the “Prior Plans”). The Company administered both of the Prior Plans as a result of the Merger, and per the 2016 Plan, no new grants of awards have been permitted under the Prior Plans after the effectiveness of the 2016 Plan. Further, the Legacy Dawson Plan and the Legacy TGC Plan expired pursuant to their terms on November 28, 2016 and March 29, 2016, respectively. Any outstanding awards previously granted under the Prior Plans continue to remain outstanding in accordance with their terms. The awards outstanding and available under the 2016 Plan and the awards outstanding under each of the Prior Plans and their associated accounting treatment are discussed below.
In 2016, the Company adopted the 2016 Plan. The 2016 Plan, which provides for the issuance of up to 1,000,000 shares of authorized Company common stock. As of December 31, 2017, there were approximately 684,416 shares available for future issuance. The 2016 Plan provides for the issuance of stock-based compensation awards, including stock options, common stock, restricted stock, restricted stock units and other forms. Stock option grant prices awarded under the 2016 Plan may not be less than the fair market value of the common stock subject to such option on the grant date, and the term of stock options shall extend no more than ten years after the grant date. The 2016 Plan terminates May 5, 2026.
In 2006, Legacy Dawson adopted the Legacy Dawson Plan, which was amended and restated in connection with the Merger. The Legacy Dawson Plan provided for the issuance of stock-based compensation awards, including stock options, common stock, restricted stock, restricted stock units and other forms. Stock option grant prices awarded under the Legacy Dawson Plan were required to be no less than the fair market value of the common stock subject to such option on the grant date, and the term of stock options was limited to no more than ten years after the grant date. The Legacy Dawson Plan terminated on November 28, 2016 and, upon the effectiveness of the 2016 Plan on May 5, 2016, has had no shares available for future issuance.
In 2006, the Company adopted the Legacy TGC Plan, which was amended and restated in connection with the Merger. The Legacy TGC Plan provided for the issuance of stock-based compensation awards, including stock options, common stock, and restricted stock. Stock option grant prices awarded under the Legacy TGC Plan were required to be no less than the fair market value of the common stock subject to such option on the grant date, and the term of stock options was limited to no more than ten years after the grant date. The Legacy TGC Plan terminated on March 29, 2016 and, since such time, has had no shares available for future issuance.
Historically, the Company’s employees and officers that held unvested restricted stock were entitled to dividends when the Company paid dividends (“participating”). The Company’s employees and officers that hold unvested restricted stock awarded during 2016 or thereafter are not entitled to dividends when the Company pays dividends (“non-participating”).
Impact of Stock-Based Compensation:
The following table summarizes stock-based compensation expense (in thousands), which is included in operating or general and administrative expense, as appropriate, in the Consolidated Statements of Operations and Comprehensive Loss, for the years ended December 31, 2017, 2016 and 2015:
Stock Options:
Legacy Dawson estimated the fair value of each stock option on the date of grant using the Black-Scholes option pricing model. Legacy TGC estimated the fair value of each stock option on the date of grant using the Binomial Lattice Model. Actual value realized with stock options, if any, is dependent on the future performance of the Company’s common stock and overall stock market conditions.
A summary of the outstanding stock options as of December 31, 2017 as well as activity during the year then ended is as follows:
Stock options issued under both the Legacy TGC plan and Legacy Dawson plans are a combination of incentive stock options and non-qualified stock options. For incentive stock options, no tax deduction is recorded when options are awarded. If an excise and sale of vested options results in a disqualifying disposition, a tax deduction for the Company occurs.
Outstanding options at December 31, 2017 expire during the period from December 2018 to July 2019. The intrinsic value of the outstanding options at December 31, 2017 was zero. There were no unrecognized compensation costs related to stock options as of December 31, 2017.
There were no options granted or vested, and there were no excess tax benefits from disqualifying dispositions during the years ended December 31, 2017, 2016 and 2015. No options were exercised during the years ended December 31, 2017, 2016 and 2015.
No cash was received from option exercises during the years ended December 31, 2017, 2016 and 2015.
Restricted Stock Awards:
There were no restricted stock grants in the year ended December 31, 2017. The Company granted 87,000 non-participating restricted stock awards during the year ended December 31, 2016 with a weighted average grant date fair value of $2.96. There were no restricted stock grants in the year ended December 31, 2015. The fair value of non-participating restricted stock awards equals the market price of the Company’s stock on the grant date and generally vest in three years or in annual increments over three years.
A summary of the status of the Company’s nonvested non-participating restricted stock awards as of December 31, 2017 and activity during the year then ended is as follows:
As of December 31, 2017, there were approximately $137,000 of unrecognized compensation costs related to nonvested non-participating restricted stock awards. These costs are expected to be recognized over a weighted average period of 1.12 years.
The aggregate vesting date fair value of restricted stock for the year ended December 31, 2017 was $84,000. There were no vestings of restricted stock for the years ended December 31, 2016 and 2015.
Restricted Stock Unit Awards:
The Company granted 227,000, 196,400, and 10,000 restricted stock unit awards during the years ended December 31, 2017, 2016 and 2015, respectively, with a weighted average grant date fair value of $3.96, $2.96 and $5.76, respectively. The fair value of restricted stock unit awards equals the market price of the Company’s stock on the grant date and generally vest in one to three years or in annual increments over three years.
A summary of the Company’s nonvested restricted stock unit awards as of December 31, 2017 and activity during the year then ended is as follows:
As of December 31, 2017, there were approximately $921,000 of unrecognized compensation costs related to nonvested restricted stock unit awards. These costs are expected to be recognized over a weighted average period of 1.81 years.
The aggregate vesting date fair value of restricted stock units for the years ended December 31, 2017, 2016 and 2015 was $422,000, $156,000 and $85,000, respectively.
Common Stock Awards:
The Company granted common stock awards with immediate vesting to outside directors and employees during the years ended December 31, 2017, 2016 and 2015 as follows:
9. Dividends
The Company has not paid dividends during calendar years 2017, 2016 and 2015. While there are currently no restrictions prohibiting the Company from paying dividends, the board of directors, after consideration of economic and market conditions affecting the energy industry in general, and the oilfield services business in particular, determined that the Company would not pay a dividend in respect of the Company’s common stock for the foreseeable future. Payment of any dividends in the future will be at the discretion of the Company’s board and will depend on our financial condition, results of operations, capital and legal requirements, and other factors deemed relevant by the board.
10. Employee Benefit Plans
The Company provides a 401(k) plan as part of its employee benefits package in order to retain quality personnel. Legacy Dawson elected to match 100% of the employee contributions up to a maximum of 6% of the participant’s applicable compensation under the Legacy Dawson 401(k) plan for the years ended December 31, 2017, 2016 and 2015. Legacy Dawson's 401(k) plan was retained in connection with the Merger. Legacy TGC’s 401(k) plan, which was terminated in connection with the Merger, is consistent with Legacy Dawson’s 401(k) plan except Legacy TGC matched 50% of the employee’s contribution up to a maximum of 6% of the participant’s applicable compensation. The Company’s matching contributions under Legacy Dawson’s 401(k) plan for the years ended December 31, 2017, 2016 and 2015 were approximately $1,480,000, $1,658,000, and $1,849,000, respectively. Legacy TGC’s employees rolled into the Legacy Dawson 401(k) plan during 2015. In addition, the Company’s matching contributions to the Legacy TGC 401(k) plan (prior to such plan’s termination) during 2015 were $98,000.
11. Advertising Costs
Advertising costs are charged to expense as incurred. Advertising costs for the years ended December 31, 2017, 2016 and 2015 totaled $371,000, $372,000, and $466,000, respectively.
12. Income Taxes
The Company’s components of loss before income taxes (in thousands) are as follows:
The Company’s components of income tax benefit (in thousands) are as follows:
The 2017 Tax Cuts and Jobs Act was enacted on December 22, 2017 resulting in significant changes to the Internal Revenue Code. This reform changed the U.S. Statutory tax rate from 35% to 21% for tax years beginning after December 31, 2017. The Company is required to recognize the effect of the tax law changes in the period of enactment, such as remeasuring the domestic deferred tax assets and liabilities as well as reassessing the net realizability of deferred tax assets and liabilities. Due to the Company’s current loss position and domestic valuation allowances, this tax reform will not have a material impact on the consolidated financials.
In December 2017, the Securities and Exchange Commission staff issued Accounting Bulleting No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”), which allows companies to record provisional amounts during a measurement period not to extend beyond one year from the enactment date. Due to the Tax Cuts and Jobs act being enacted in late fourth quarter of 2017 and subsequent guidance expected throughout the next 12 months, the accounting of deferred tax re-measurement is considered incomplete due to forthcoming guidance and the ongoing analysis of final year-end data and tax positions. Analysis is expected to be completed within the measurement period in accordance with SAB 118. Subsequent adjustments are not expected to have a material impact on the consolidated financials due to the domestic loss position and the associated valuation allowances on the domestic deferred tax assets.
The income tax provision differs from the amount computed by applying the statutory federal income tax rate to losses before income taxes as follows (in thousands):
(1)
Due to the Tax Cuts and Jobs Act enacted on December 22, 2017, the Company’s domestic deferred tax assets and liabilities were remeasured from 35% to 21% as of December 31, 2017. The change in tax rate resulted in a decrease to the gross domestic deferred tax asset which is offset by a corresponding decrease to the valuation allowance.
The principal components of the Company’s net deferred tax (liabilities) assets are as follows (in thousands):
At December 31, 2017, the Company had a NOL for U.S. federal income tax purposes of approximately $100,065,000. This NOL will begin to expire in 2027. The Company will carry forward the tax benefits related to federal NOL of approximately $21,014,000. The Company also had state NOL’s that will affect state taxes of approximately $1,935,000 at December 31, 2017. State NOL’s began to expire in 2015. The Company also had a Canadian NOL of $16,963,000 that will begin to expire in 2037.
In evaluating the possible sources of taxable income during 2017, the Company determined it is more likely than not that the remaining deferred tax assets will not be realizable. As a result, the Company recorded full valuation allowances against its federal and state deferred tax assets with the exception of its trademark intangible and the AMT credit which will be refundable within the next five years. A partial valuation allowance was recorded against foreign deferred tax assets excluding losses which are expected to be absorbed by future temporary differences.
A summary of the Company’s gross uncertain tax positions at December 31, 2017 and 2016 as well as activity for the years then ended are as follows (in thousands):
The Company’s policy is to recognize interest and penalties related to uncertain tax positions in income tax expense.
Due to the resolution of amended federal, state and foreign tax returns and the expiration of various statutes of limitations, the full uncertain tax positions balance at December 31, 2016 reversed in the twelve months ended December 31, 2017.
13. Net (Loss) Income per Share Attributable to Common Stock
Net loss per share attributable to common stock is calculated using the two-class method. The two-class method is an allocation method of calculating loss per share when a company’s capital structure includes participating securities that have rights to undistributed earnings. Historically, the Company’s employees and officers that held unvested restricted stock were entitled to dividends when the Company paid dividends (“participating”). The Company’s employees and officers that hold unvested restricted stock awarded during 2016 or thereafter are not entitled to dividends when the Company pays dividends (“non-participating”). The Company’s basic net loss per share attributable to common stock is computed by reducing the Company’s net loss by the income allocable to unvested restricted stockholders that have a right to participate in earnings. The Company’s employees and officers that hold unvested restricted stock do not participate in losses because they are not contractually obligated to do so. The undistributed earnings are allocated based on the relative percentage of the weighted average unvested participating restricted stock awards. The basic net loss per share attributable to common stock is computed by dividing the net loss attributable to common stock by the weighted average shares outstanding. The weighted average shares outstanding for the year ended December 31, 2015 was calculated by totaling (i) the product of (x) the weighted shares of Legacy Dawson Common Stock outstanding at the beginning of the year multiplied by (y) the Exchange Ratio, plus (ii) the number of shares associated with awards of Legacy Dawson participating restricted stock and restricted stock units that vested in conjunction with the Merger, weighted as of February 11, 2015, plus (iii) the number of shares of Legacy TGC Common Stock outstanding immediately prior to the Merger, weighted to reflect that such shares were outstanding from February 11, 2015 until December 31, 2015. The Company’s diluted loss per share attributable to common stock is computed by adjusting basic loss per share attributable to common stock by income allocable to unvested participating restricted stock, if any, divided by weighted average diluted shares outstanding.
A reconciliation of the loss per share attributable to common stock is as follows (in thousands, except share and per share data):
The Company had a net loss in the years ended December 31, 2017, 2016 and 2015. As a result, all stock options, restricted stock unit awards, and non-participating restricted stock awards were anti-dilutive and excluded from weighted average shares used in determining the diluted loss attributable to a share of common stock for the respective periods. The following weighted average numbers of stock options, restricted stock unit awards, and non-participating restricted stock awards have been excluded from the calculation of diluted loss per share attributable to common stock, as their effect would be anti-dilutive for the years ended December 31, 2017, 2016 and 2015:
The Company has not awarded participating restricted stock for the years ended December 31, 2017, 2016 and 2015.
14. Major Clients
The Company operates in only one business segment, contract seismic data acquisition and processing services. Sales to these clients, as a percentage of operating revenues that exceeded 10%, were as follows:
The Company does not believe that the loss of any client listed above would have a material adverse effect on the Company.
15. Areas of Operation
The U.S. and Canada are the only countries of operation for the Company.
Revenues for the year ended December 31, 2017 were $157,148,000 with $135,058,000 earned in the U.S. and $22,090,000 earned in Canada. Revenues for the year ended December 31, 2016 were $133,330,000 with $122,522,000 earned in the U.S. and $10,808,000 earned in Canada. Revenues for the year ended December 31, 2015 were $234,685,000 with $222,154,000 earned in the U.S. and $12,531,000 earned in Canada.
Net long-lived assets as of December 31, 2017 were approximately $86,573,000, with $76,751,000 located in the U.S. and $9,822,000 located in Canada. Net long-lived assets as of December 31, 2016 were approximately $110,917,000, with $105,059,000 located in the U.S. and $5,858,000 located in Canada.
16. Commitments and Contingencies
From time to time, the Company is a party to various legal proceedings arising in the ordinary course of business. Although the Company cannot predict the outcomes of any such legal proceedings, management believes that the resolution of pending legal actions will not have a material adverse effect on the Company’s financial condition, results of operations or liquidity, as the Company believes it is adequately indemnified and insured.
The Company experiences contractual disputes with its clients from time to time regarding the payment of invoices or other matters. While the Company seeks to minimize these disputes and maintain good relations with its clients, the Company has experienced in the past, and may experience in the future, disputes that could affect its revenues and results of operations in any period.
The Company has non-cancelable operating leases for office and shop space in Midland, Plano, Denison, Houston, Denver, Oklahoma City and Calgary, Alberta.
The following table summarizes payments due in specific periods related to the Company’s contractual obligations with initial terms exceeding one year as of December 31, 2017 (in thousands):
Some of the Company’s operating leases contain predetermined fixed increases of the minimum rental rate during the initial lease term. For these leases, the Company recognizes the related expense on a straight-line basis and records deferred rent as the difference between the amount charged to expense and the rent paid. Rental expense under the Company’s operating leases with initial terms exceeding one year was $1,785,000 for the year ended December 31, 2017, $1,907,000 for the year ended December 31, 2016, and $1,691,000 for the year ended December 31, 2015.
As of December 31, 2017, the Company had three letters of credit issued by Veritex Bank. The first letter of credit is in the amount of $1,767,000 to support payment of our insurance obligations. The principal amount of this letter of credit is collateralized by certain of our core equipment. The second letter of credit is in the amount of $583,000 to support the Company’s workers’ compensation insurance and is secured by a certificate of deposit. The third letter of credit is unsecured and in the amount of $75,000 to support certain of our performance obligations of the Company. None of the letters of credit count as funds borrowed under our Line of Credit.
17. Recently Issued Accounting Pronouncements
In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act passed by the U.S. federal government in December 2017. This ASU is effective for the annual period beginning after December 15, 2018, and for annual and interim periods thereafter. The Company does not believe this ASU will have a material impact on its condensed consolidated financial statements.
In May 2017, the FASB issued ASU No. 2017-09, Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting, which provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. This ASU is effective for the annual period beginning after December 15, 2017, and for annual and interim periods thereafter. The Company does not believe this ASU will have a material impact on its condensed consolidated financial statements.
In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which is intended to simplify accounting for share-based payments awarded to employees, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This ASU was effective for the annual period beginning after December 15, 2016, and for annual and interim periods thereafter. The Company adopted ASU 2016-09 in the first quarter of 2017 and elected to account for forfeitures as they occur, rather than estimate expected forfeitures. As a result of adopting this standard, the Company applied the modified retrospective approach and recorded a cumulative-effect adjustment within the Consolidated Statements of Stockholders’ Equity that had no material impact on the Company’s condensed consolidated financial statements.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases. In January 2017, the FASB issued ASU No. 2017-03, Accounting Changes and Error Corrections (Topic 250) and Investments - Equity Method and Joint Ventures (Topic 323), which stated additional qualitative disclosures should be considered to assess the significance of the impact upon adoption. This ASU is effective for the annual period beginning after December 15, 2018, and for annual and interim periods thereafter. Early adoption is permitted. In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current lease guidance in Topic 840. The Company is currently evaluating the new guidance and practical expedient to determine the impact they will have on its condensed
consolidated financial statements and believes that the most significant change will be to its Condensed Consolidated Balance Sheets as its asset and liability balances will increase for operating leases that are currently off-balance sheet.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. Entities have the option of using either a full retrospective or modified approach to adopt ASU No. 2014-09. Subsequent amendments to the initial guidance have been issued in March 2016, April 2016, May 2016, December 2016, January 2017, and September 2017 within ASU No. 2016-08, ASU No. 2016-10, ASU No. 2016-12, ASU No. 2016-20, ASU No. 2017-03, and ASU No. 2017-13 regarding principal-versus-agent, performance obligations and licensing, assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. These updates do not change the core principle of the guidance under ASU No. 2014-09, but rather provide implementation guidance. This new standard must be adopted by the Company in our calendar year beginning January 1, 2018. The Company has completed its assessment of the new standard and are adopting the standard using the full retrospective method.
The expected impact of adopting the new standard on the Company’s 2017 and 2016 consolidated financial statements will not have a material impact on the overall operating results of the Company and is reflected below. The primary impact of adopting the new standard will be delayed recognition of certain miscellaneous revenues and certain fulfillment costs that are being recognized as incurred under our current revenue recognition policy. These revenues and expenses will be estimated and allocated over the life of the contract rather than recognized as services are provided.
Select line items from the Company’s Consolidated Statements of Operations and Comprehensive Loss which reflect the expected adoption of the new standard will be as follows (in thousands except per share data):
There will be no effect on income taxes for the years ended December 31, 2017 and 2016 as the Company is in a full valuation allowance domestically.
Select line items from the Company’s Consolidated Balance Sheets which reflect the expected adoption of the new standard are as follows (in thousands):
18. Concentrations of Credit Risk
Financial instruments that potentially expose the Company to concentrations of credit risk at any given time may consist of cash and cash equivalents, money market funds and overnight investment accounts, short-term investments in certificates of deposit, trade and other receivables and other current assets. At December 31, 2017 and 2016, the Company had deposits with domestic and international banks in excess of federally insured limits. Management believes the credit risk associated with these deposits is minimal. Money market funds seek to preserve the value of the investment, but it is possible to lose money investing in these funds.
The Company’s sales are to clients whose activities relate to oil and natural gas exploration and production. The Company generally extends unsecured credit to these clients; therefore, collection of receivables may be affected by the economy surrounding the oil and natural gas industry or other economic conditions. The Company closely monitors extensions of credit and may negotiate payment terms that mitigate risk.
19. Quarterly Consolidated Financial Data (unaudited and in thousands, except per share data)
Basic and diluted loss per share attributable to common stock are computed independently for each of the quarters presented. Therefore, the sum of quarterly basic and diluted information may not equal the annual basic and diluted loss per share attributable to common stock.