UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
____________________________________________________________
Form 10-K
____________________________________________________________
(Mark One)
ý | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2013
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number 001-35281
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Forbes Energy Services Ltd.
(Exact name of registrant as specified in its charter)
____________________________________________________________
Texas | 98-0581100 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
3000 South Business Highway 281 Alice, Texas | 78332 | |
(Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code: (361) 664-0549
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class | Name of Each Exchange on Which Registered | |
Common Stock, $0.04 par value | NASDAQ Global Market |
Securities registered pursuant to Section 12(g) of the Act:
Title of Each Class
None
____________________________________________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ¨ Yes ý No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ¨ Yes ý No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ý Yes ¨ No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ý Yes ¨ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer | ¨ | Accelerated Filer | ¨ |
Non-Accelerated Filer | ý | Smaller Reporting Company | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). ¨ Yes ý No
The aggregate market value of the stock held by non-affiliates of the registrant as of the last business day of the most recently completed second fiscal quarter, June 30, 2013, was approximately $58.7 million based on the closing sales price of the registrant’s common stock as reported by the NASDAQ Global Market on June 30, 2013 of $4.02 per share and 14,608,831 shares held by non-affiliates.
As of March 24, 2014, there were 21,617,835 common shares outstanding.
FORBES ENERGY SERVICES LTD. AND SUBSIDIARIES (a/k/a the “Forbes Group”)
TABLE OF CONTENTS
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FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K and any oral statements made in connection with it include certain forward-looking statements within the meaning of the federal securities laws. You can generally identify forward-looking statements by the appearance in such a statement of words like “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project” or “should” or other comparable words or the negative of these words. When you consider our forward-looking statements, you should keep in mind the risk factors we describe and other cautionary statements we make in this Annual Report on Form 10-K. Our forward-looking statements are only predictions based on expectations that we believe are reasonable. Our actual results could differ materially from those anticipated in, or implied by, these forward-looking statements as a result of known risks and uncertainties set forth below and elsewhere in this Annual Report on Form 10-K. These factors include or relate to the following:
• | supply and demand for oilfield services and industry activity levels; |
• | potential for excess capacity; |
• | spending by the oil and natural gas industry; |
• | our level of indebtedness; |
• | possible impairment of our long-lived assets; |
• | our ability to maintain stable pricing; |
• | competition; |
• | substantial capital requirements; |
• | significant operating and financial restrictions under our indenture and revolving credit facility; |
• | technological obsolescence of operating equipment; |
• | dependence on certain key employees; |
• | concentration of customers; |
• | substantial additional costs of compliance with reporting obligations, the Sarbanes-Oxley Act and indenture covenants; |
• | material weaknesses in internal controls over financial reporting; |
• | seasonality of oilfield services activity; |
• | collection of accounts receivable; |
• | environmental and other governmental regulation, including potential climate change legislation; |
• | the potential disruption of business activities caused by the physical effects, if any, of climate change; |
• | risks inherent in our operations; |
• | market response to global demands to curtail use of oil and natural gas; |
• | ability to fully integrate future acquisitions; |
• | variation from projected operating and financial data; |
• | variation from budgeted and projected capital expenditures; |
• | volatility of global financial markets; and |
• | the other factors discussed under “Risk Factors” on page 10 of this Annual Report on Form 10-K. |
We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. To the extent these risks, uncertainties and assumptions give rise to events that vary from our expectations, the forward-looking events discussed in this Annual Report on Form 10-K may not occur. All forward-looking statements attributable to us are qualified in their entirety by this cautionary statement.
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PART I
Item 1. | Business |
Overview
Forbes Energy Services Ltd., or FES Ltd, is an independent oilfield services contractor that provides a wide range of well site services to oil and natural gas drilling and producing companies to help develop and enhance the production of oil and natural gas. These services include fluid hauling, fluid disposal, well maintenance, completion services, workovers and recompletions, plugging and abandonment, and tubing testing. Our operations are concentrated in the major onshore oil and natural gas producing regions of Texas, with additional locations in Mississippi, in Pennsylvania and, prior to the disposition of our assets in Mexico, in January 2012, which is discussed below, in Mexico. We believe that our broad range of services, which extends from initial drilling, through production, to eventual abandonment, is fundamental to establishing and maintaining the flow of oil and natural gas throughout the life cycle of our customers’ wells. Our headquarters and executive offices are located at 3000 South Business Highway 281, Alice, Texas 78332. We can be reached by phone at (361) 664-0549.
As used in this Annual Report on Form 10-K, the “Company,” the “Forbes Group,” “we,” and “our” mean FES Ltd and its subsidiaries, except as otherwise indicated. Unless otherwise indicated, all financial or operational data presented herein relate to our continuing operations, excluding our operations in Mexico, which were sold in January 2012.
We currently provide a wide range of services to a diverse group of companies. During the year ended December 31, 2013, we provided services to over 900 companies. Our blue-chip customer base includes Anadarko Petroleum Corporation, Chesapeake Energy Corporation, ConocoPhillips Company, Rosetta Resources, Inc., and Shell Oil Company, among others. John E. Crisp and Charles C. Forbes, members of our senior management team, have cultivated deep and ongoing relationships with these customers during their average of over 37 years of experience in the oilfield services industry. For the year ended December 31, 2013, we generated total revenues of approximately $419.9 million.
We currently conduct our operations through the following two business segments:
• | Well Servicing. The well servicing segment comprised 55.2% of our total revenues for the year ended December 31, 2013. At December 31, 2013, our well servicing segment utilized our modern fleet of well servicing rigs, which was comprised of 157 workover rigs and 10 swabbing rigs, as well as five coiled tubing spreads, nine tubing testing units with related assets and equipment. These assets are used to provide (i) well maintenance, including remedial repairs and removal and replacement of downhole production equipment, (ii) well workovers, including significant downhole repairs, re-completions and re-perforations, (iii) completion and swabbing activities, (iv) plugging and abandonment services, and (v) testing of oil and natural gas production tubing. |
• | Fluid Logistics. The fluid logistics segment comprised 44.8% of our total revenues for the year ended December 31, 2013. Our fluid logistics segment utilized our fleet of owned or leased fluid transport trucks and related assets, including specialized vacuum, high-pressure pump and tank trucks, frac tanks, water wells, salt water disposal wells and facilities, and related equipment. These assets are used to provide, transport, store, and dispose of a variety of drilling and produced fluids used in, and generated by, oil and natural gas production. These services are required in most workover and completion projects and are routinely used in the daily operation of producing wells. |
We believe that our two business segments are complementary and create synergies in terms of selling opportunities. Our multiple lines of service are designed to capitalize on our existing customer base to grow within existing markets, generate more business from existing customers, and increase our operating performance. By offering our customers the ability to reduce the number of vendors they use, we believe that we help improve our customers’ efficiency. This is demonstrated by the fact that 78.7% of our total revenues for the year ended December 31, 2013 were from customers that utilized services of both of our business segments. Further, by having multiple service offerings that span the life cycle of the well, we believe that we have a competitive advantage over smaller competitors offering more limited services.
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The following table summarizes the number of locations and major components of our equipment fleet as of the dates indicated.
December 31, | ||||||||
2013 | 2012 | 2011 | ||||||
Locations(1) | 27 | 25 | 25 | |||||
Well Servicing Segment: | ||||||||
Workover rigs (1) | 157 | 152 | 149 | |||||
Swabbing rigs | 10 | 10 | 10 | |||||
Tubing testing units | 9 | 9 | 9 | |||||
Coiled tubing spreads | 5 | 4 | — | |||||
Fluid logistics segment: | ||||||||
Vacuum trucks (1)(2) | 480 | 473 | 408 | |||||
High-pressure pump trucks (2) | 22 | 20 | 21 | |||||
Hot oil trucks | 5 | 1 | — | |||||
Other heavy trucks (2) | 84 | 84 | 67 | |||||
Frac tanks | 2,997 | 3,112 | 1,879 | |||||
Fluid mixing tanks | 274 | 96 | — | |||||
Salt water disposal wells (3) | 24 | 24 | 17 |
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(1) | The table above does not include 14 workover rigs, four vacuum trucks, and one operating location which were included in the disposition of substantially all of our long-lived assets located in Mexico completed on January 12, 2012. |
(2) | At December 31, 2013, 174 vacuum trucks and 21 other heavy trucks, included in the above equipment counts, were leased. |
(3) | At December 31, 2013, 18 salt water disposal wells, included in the above well count, were subject to ground leases or other operating arrangements with third parties. One of these wells is subject to an ongoing dispute over the lease. Another of these wells is currently in the process of being permitted. |
Corporate Structure
FES Ltd. was initially organized as a Bermuda exempt company on April 9, 2008 to be the holding company for FES LLC and its subsidiaries. On August 12, 2011, FES Ltd discontinued its existence as a Bermuda entity and converted into a Texas corporation, or the Texas Conversion. Both in its capacity as a Bermuda exempt company prior to the Texas Conversion and in its capacity as a Texas corporation after the Texas Conversion, FES Ltd has been and is the holding company for all of our operations. Forbes Energy Services LLC, or FES LLC, a Delaware limited liability company, is a wholly-owned subsidiary of FES Ltd. that acts as an intermediate holding company for our direct and indirect wholly-owned operating companies that have conducted our business historically, C.C. Forbes, LLC, or CCF, TX Energy Services, LLC, or TES, Superior Tubing Testers, LLC, or STT, and Forbes Energy International, LLC, or FEI.
In November 2011, we dissolved Forbes Energy Capital Inc., a subsidiary of FES LLC, which was created solely to be a co-issuer of our 11% Senior Secured Notes due 2015, or our Second Priority Notes, and our First Priority Floating Rate Notes due 2014, or our First Priority Notes, all of which have been repurchased and discharged, as discussed in Note 8 to our Consolidated Financial Statements.
Prior to January 12, 2012, the Company conducted operations in Mexico through a Mexican branch of FES Ltd and two Mexican subsidiaries, Forbes Energy Services México Servicios de Personal S. de R.L. de C.V. and Forbes Energy Services México S. de R.L. de C.V. On January 12, 2012, we sold our business and substantially all of our assets located in Mexico as well as 100% of the equity interests of Forbes Energy Services México Servicios de Personal S. de R.L. de C.V., the Mexico subsidiary which employed our employees in Mexico.
In connection with the Texas Conversion, FES Ltd. effected a 4-to-1 share consolidation, whereby each four shares of common stock of FES Ltd. of par value $0.01 per share were consolidated into a single share of common stock of par value $0.04, or the Share Consolidation. No fractional shares of common stock were issued as a result of the Share Consolidation. In
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lieu of such issuance, the Company, through American Stock Transfer & Trust Company, LLC, who acted s the Company's exchange agent for the Share Consolidation and Texas Conversion, paid holders of such fractional interests cash based on the market price immediately prior to the Share Consolidation. As a result of the Share Consolidation, eight shares of common stock, on a post consolidation basis, were eliminated. The exchange of shares associated with the Share Consolidation and Texas Conversion was registered under the Securities Act of 1933, as amended, pursuant to a registration statement on Form S-4, which was declared effective on August 11, 2011. In connection with these transactions, on August 16, 2011, the common of FES Ltd. was listed and began trading on the NASDAQ Global Markets, or NASDAQ.
Our Competitive Strengths
We believe that the following competitive strengths position us well within the oilfield services industry:
• | Young and Modern Fleet. We believe we operate one of the youngest and most modern fleets of well servicing rigs among the large well-servicing companies, based on the average age of our well servicing rigs. Approximately 71.9% of our 167 well servicing rigs at December 31, 2013 were built in the last six years. We believe that a younger, more modern fleet is more attractive to our customers because newer well servicing rigs require less down time for maintenance and generally are more reliable than older equipment. We believe that newer equipment is beneficial in retaining or expanding our employee base as there is a preference by employees to work with newer equipment. As part of our strategy, we have enhanced our design specifications to improve the operational and safety characteristics of our equipment compared with older equipment. |
• | Exposure to Revenue Streams Throughout the Life Cycle of the Well. Our maintenance and workover services expose us to demand from our customers throughout the life cycle of a well, from drilling through production and eventual abandonment. Each new well that is drilled provides us a potential multi-year stream of well servicing revenue, as our customers attempt to maximize and maintain a well’s productivity. Accordingly, demand for our production services is generally driven by the total number of producing wells in a region and is generally less volatile than demand for new well drilling services. |
• | High Level of Customer Retention with a Blue Chip Customer Base. Our top customers include many of the largest integrated and independent oil and natural gas companies operating onshore in the United States. We believe that our success in growing in our existing markets with existing customers due to the quality of our well servicing rigs, our personnel, and our safety record. We believe members of our senior management have maintained excellent working relationships with our top customers in the United States during their average of over 30 years of experience in the oilfield services industry. We believe the complementary nature of our two business segments also helps retain customers because of the efficiency we offer a customer that has multiple needs at the wellsite. Notably, 78.7% of our total revenues from the year ended December 31, 2013 were from customers that utilize services in both of our business segments. |
• | Industry-Leading Safety Record. During 2013, we had approximately 67.0% fewer reported incidents than the industry average as published by the Bureau of Labor Statistics. We believe that our safety record and reputation are critical factors to purchasing and operations managers in their decision-making process. We have a strong safety culture based on our training programs and safety seminars for our employees and customers. For example, for several years, members of our and senior management have played an integral part in joint safety training meetings with customer personnel. In addition, our deployment of new well servicing rigs with enhanced safety features has contributed to our strong safety record and reputation. |
• | Experienced Senior Management Team and Operations Staff. Our senior management team of John E. Crisp and Charles C. Forbes have over 70 years of combined experience within the oilfield services industry. In addition, our next level of management, which includes our location managers, has an average of over 30 years of experience in the industry. |
Our Business Strategy
Our strategy is to continue to do the following:
• | Maintain Maximum Asset Utilization. We constantly monitor asset usage and industry trends as we strive to maximize utilization. We accomplish this through moving assets from regions with less activity to those with more activity or that are increasing in activity. In the current economic environment, we are focusing on basins that are either predominantly oil or contain natural gas with high liquids content, such as the Eagle Ford Shale basin in South Texas, as we anticipate that these areas will experience sustained activity for the foreseeable future. |
• | A Presence in Proven and Established Oil and Liquids Rich Basins. We focus our operations on customers that operate in well-established basins which have proven production histories and that have maintained a high level |
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of activity throughout various oil and natural gas pricing environments. We believe production-related services help create a more stable revenue stream as such services we provide our customers are tied more to ongoing production from producing wells and less to drilling activity. Our experience shows that production-related services have generally withstood depressed economic conditions better than drilling services.
• | Establish and Maintain Leadership Position in Core Operating Areas. Based on our estimates, we believe that we have a significant market share in well servicing and fluid logistics in South Texas. We strive to establish and maintain significant positions within each of our core operating areas. To achieve this goal, we maintain close customer relationships and offer high-quality services and modern equipment for our customers. In addition, our significant presence in our core operating areas facilitates employee retention and hiring, and brand recognition. |
• | Maintain a Disciplined Growth Strategy. We strategically evaluate opportunities for growth and expansion. In order to maximize our ability to take advantage of growth opportunities, from time to time, we have closed or sold operations in certain areas. In January 2012, we sold our operations and substantially all of our assets located in Mexico, as well as 100% of the equity interests of our Mexican employment company. The Company reinvested the proceeds from this sale by purchasing equipment for use in the United States. |
Description of Business Segments
Well Servicing Segment
Through a modern fleet of 167 well servicing rigs, as of December 31, 2013, located in 13 operational areas across Texas, one in Mississippi, and one in Pennsylvania, we provide a comprehensive offering of well services to oil and natural gas companies in Texas and our other locations, including completions of newly drilled oil and natural gas wells, wellbore maintenance, workovers and recompletions, tubing testing, and plugging and abandonment services. During 2012 and 2013, we added five coiled tubing spreads. This equipment is used to mill, log, perforate, clean out, drill plugs, cement, acidize, and fish/retrieve tools/pipe in producing oil and gas wells. The services offered are customized to the customer's job specific requirements. Our well servicing rig fleet has an average age of less than seven years. As part of our operational strategy, we enhanced our design specifications to improve the operational and safety characteristics of our well servicing rigs compared with older well servicing rigs operated by others in the industry. These include increased derrick height and weight ratings and increased mud pump horsepower. We believe these enhanced features translate into increased demand for our equipment and services along with better pricing for our equipment and personnel. In addition, we augment our well servicing rig fleet with auxiliary equipment, such as mud pumps, power swivels, mud plants, mud tanks, blow-out preventers, lighting plants, generators, pipe racks, and tongs, which results in incremental rental revenue and increases the profitability of a typical well servicing job.
We provide the following services in our well servicing segment:
• | Completions. Utilizing our well servicing rig fleet and coiled tubing equipment, we perform completion services, which involve wellbore cleanout, well prepping for fracturing, drilling, setting and retrieving plugs, fishing operations, tool conveyance and logging, cementing, well unloading, casing and packer testing, pump-down plug, velocity strings, perforating, acidizing and/or stimulating a wellbore, along with swabbing operations that are utilized to clean a wellbore prior to production. Completion services are generally shorter term in nature and involve our equipment operating on a site for a period of two to three days, although some fishing jobs, which involve the recovery of equipment lost or stuck in the wellbore, can take longer. |
• | Maintenance. Through our fleet of well servicing rigs and coiled tubing units, we provide for the removal and repair of sucker rods, downhole pumps, and other production equipment, the repair of failed production tubing, and the removal of sand, paraffin, and other downhole production-related byproducts that impair well performance. These operations typically involve our well servicing rigs or coil tubing equipment operating on a wellsite for five to seven days. |
• | Workovers and Recompletions. We provide workover and re-completion services for existing wellbores. These services are designed to significantly enhance production by re-perforating to initiate or re-establish productivity from an oil or natural gas wellbore. In addition, we provide major downhole repairs such as casing repair, production tubing replacement, and deepening and sidetracking operations used to extend a wellbore laterally or vertically. These operations are typically longer term in nature and involve our well servicing rigs operating on a wellsite for one to two weeks at a time. |
• | Tubing Testing. Through a fleet of nine downhole testing units, we provide downhole tubing testing services that allow operators to verify tubing integrity. Tubing testing services are performed as production tubing is run into a new wellbore or on older wellbores as production tubing is replaced during a workover operation. In addition to our downhole testing units, we also have two electromagnetic scan trucks which scan tubing while out of the |
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wellbore. This scanning function provides key operational information related to corrosion pitting, holes and splits, and wall loss on tubing. Tubing testing services are complementary to our other service offerings and provide a significant opportunity for cross-selling.
• | Plugging and Abandonment. Our well servicing rigs are also used in the process of permanently closing oil and natural gas wells that are no longer capable of producing in economic quantities, become mechanically impaired or are dry holes. Plugging and abandonment work can be performed with a well servicing rig along with wireline and cementing equipment; however, this service is typically provided by companies that specialize in plugging and abandonment work. Many well operators bid this work on a “lump sum” basis to include the sale or disposal of equipment salvaged from the well as part of the compensation received. We perform plugging and abandonment work in conjunction with equipment provided by other service companies. |
Fluid Logistics Segment
Our fluid logistics segment provides an integrated array of oilfield fluid sales, transportation, storage, and disposal services that are required on most workover, drilling, and completion projects and are routinely used in daily operation of producing wells by oil and natural gas producers. We have a substantial operational footprint with 15 fluid logistics locations across Texas as of December 31, 2013, and an extensive fleet of transportation trucks, high-pressure pump trucks, hot oil trucks, frac tanks, fluid mixing tanks and salt water disposal wells. This combination of services enables us to provide a one-stop source for oil and natural gas companies. Although there are large operators in our areas, we believe that the vast majority of our smaller competitors in this segment can provide some, but not all, of the equipment and services required by customers, thereby requiring our customers to use several companies to meet their requirements and increasing their administrative burden. In addition, by pursuing an integrated approach to service, we experience increased asset utilization rates, as multiple assets are usually required to service a customer.
We provide the following services in our fluid logistics segment:
• | Fluid Hauling. At December 31, 2013, we owned or leased 480 fluid service vacuum trucks, trailers, and other hauling trucks equipped with a fluid hauling capacity of up to 150 barrels per unit, with most of the units having a capacity of 130 barrels. Each fluid service truck unit is equipped to pump fluids from or into wells, pits, tanks, and other on-site storage facilities. The majority of our fluid service truck units are also used to transport water to fill frac tanks on well locations, including frac tanks provided by us and others, to transport produced salt water to disposal wells, including injection wells owned and/or operated by us, and to transport drilling and completion fluids to and from well locations. In conjunction with the rental of frac tanks, we use fluid service trucks to transport water for use by our customers in fracturing operations. Following completion of fracturing operations by our customers, our fluid service trucks are used to transport the flowback produced as a result of the fracturing operations from the wellsite to disposal wells. We also operate several hot oil trucks which are capable of providing heated water and oil for use in well and pipe maintenance. |
• | Disposal Services. Most oil and natural gas wells produce varying amounts of salt water throughout their productive lives. Under Texas law, oil and natural gas waste and salt water produced from oil and natural gas wells are required to be disposed of in authorized facilities, including permitted salt water disposal wells. Injection wells are licensed by state authorities and are completed in permeable formations below the fresh water table. In 2012, we purchased seven additional disposal wells. At December 31, 2013, we operated 24 disposal wells in 20 locations across Texas, with an aggregate injection capacity of approximately 206,000 barrels per day. The wells are permitted to dispose of salt water and incidental non-hazardous oil and natural gas wastes throughout our operational bases in Texas. The salt water disposal wells are strategically located in close proximity to the producing wells of our customers. We maintain separators at all of our disposal wells, that permit us to reclaim residual crude oil that we sell. |
• | Equipment Rental. At December 31, 2013, we owned a fleet of 3,271 fluid storage tanks that can store up to 500 barrels of fluid each. This equipment is used by oilfield operators to store various fluids at the wellsite, including fresh water, brine and acid for frac jobs, flowback, temporary production, and drilling fluids. We transport the tanks with our trucks to well locations that are usually within a 75-mile radius of our nearest location. Frac tanks are used during all phases of the life of a producing well. A typical fracturing operation conducted by a customer can be completed within four days using five to 40 or more frac tanks. We believe we maintain one of the youngest frac tank fleets in the industry with an average equipment age of less than three years. |
• | Fluid Sales. We sell and transport a variety of chemicals and fluids used in drilling, completion, and workover operations for oil and natural gas wells. Although a relatively small percentage of our overall business, the provision of these chemicals and fluids increases utilization of and enhances revenues from the associated equipment. Through these services, we provide fresh water used in fracturing fluid, completion fluids, cement, |
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and drilling mud. In addition, we provide potassium chloride for completion fluids, brine water, and water-based drilling mud.
Financial Information about Segments and Geographic Areas
See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 14 to our consolidated financial statements included in this Annual Report on Form 10-K for further discussion regarding financial information by segment and geographic location.
Seasonality
Our operations are impacted by seasonal factors. Historically, our business has been negatively impacted during the winter months due to inclement weather, fewer daylight hours, and holidays. Our well servicing rigs are mobile and we operate a significant number of oilfield vehicles. During periods of heavy snow, ice or rain, we may not be able to move our equipment between locations, thereby reducing our ability to generate rig or truck hours. In addition, the majority of our well servicing rigs work only during daylight hours. In the winter months as daylight time becomes shorter, the amount of time that the well servicing rigs work is shortened, which has a negative impact on total hours worked. Finally, we historically have experienced significant slowdown during the Thanksgiving and Christmas holiday seasons.
Sales and Marketing
Sales and marketing functions are performed at two levels: at the field level through our operations personnel and through our sales representatives and executives at the corporate level. At the field level, our operations and rig supervisors are in constant contact with their counterparts who represent our customers. This contact includes working closely in the field to facilitate problem resolution, and 24-hour availability. Employees of our customers become accustomed to working closely with and depending on our personnel for assistance, guidance, advice, and in other areas where teams typically interact. Our objective is for our customers to see our employees as an extension of the customers’ employees and resources. These relationships not only secure business long-term, but also generate additional business as new opportunities arise.
Our sales representatives and executives perform more traditional sales activities such as calling on customers, sending proposals, and following up on jobs to ensure customer satisfaction. This includes heavy participation in customer safety programs where our executives and sales staff either participate in or teach safety classes at various customer locations. From a sales standpoint, this close involvement and support is key to establishing and maintaining long-term relationships with the major oil and natural gas companies.
We cross-market our well servicing rigs along with our fluid logistics services, thereby offering our customers the ability to minimize vendors, which we believe improves the efficiency of our customers. This is demonstrated by the fact that 78.7% of our revenues for the year ended December 31, 2013 were from customers that utilized services of both of our business segments.
Employees
At December 31, 2013, we had 2,230 employees. We provide comprehensive employee training and implement recognized standards for health and safety. None of our employees are represented by a union or employed pursuant to a collective bargaining agreement or similar arrangement. We have not experienced any strikes or work stoppages and we believe we have good relations with our employees.
Continued retention of existing qualified management and field employees and availability of additional qualified management and field employees will be a critical factor in our continued success as we work to ensure that we have adequate levels of experienced personnel to service our customers.
Competition
Our competition includes small regional service providers as well as larger companies with operations throughout the continental United States and internationally. Our larger competitors are Basic Energy Services, Inc., Superior Energy Services, Inc., Heckman Corporation, Key Energy Services, Inc., Nabors Industries Ltd., and Stallion Oilfield Services, Ltd. We believe that these larger competitors primarily have centralized management teams that direct their operations and decision-making primarily from corporate and regional headquarters. In addition, because of their size, these companies market a large portion of their work to the major oil and natural gas companies. We compete primarily on the basis of the young age and quality of our equipment, our safety record, the quality and expertise of our employees, and our responsiveness to customer needs.
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Customers
We served in excess of 900 customers during the year ended December 31, 2013. For the years ended December 31, 2013, 2012 and 2011, our largest customer in each year comprised approximately 10.5%, 9.3%, and 15.5% of our total revenues, our five largest customers comprised approximately 34.6%, 36.7%, and 42.3% of our total revenues, and our ten largest customers comprised approximately 49.7%, 57.5%, and 59.1% of our total revenues. During 2013, ConocoPhillips made up 10.5% of our total revenues. During 2012 no customer comprised 10.0% or more of our total revenues. During 2011, Chesapeake Energy Corporation comprised 15.5% of our total revenues. We have discontinued operations in Mexico and have not included PEMEX in this customer analysis, which if included would have represented 13.8% of our total revenues, including revenues from our discontinued operations, for the year ended December 31, 2011. The loss of our top customer or of several of the customers in the top ten would materially adversely affect our revenues and results of operations. There can be no assurance that lost revenues could be replaced in a timely manner or at all, especially given the market’s competitiveness.
We have master service agreements in place with most of our customers, under which jobs or projects are awarded on the basis of price, type of service, location of equipment, and the experience level of work crews. Our business segments charge customers by the hour, by the day, or by the project for the services, equipment, and personnel we provide.
Suppliers
We purchase well servicing chemicals, drilling fluids, and related supplies from various third-party suppliers. We purchase potassium chloride from two suppliers Agri-Empresa, Inc. and Tetra Technologies, Inc. For all other well servicing products, such as barite, surfactants, and drilling fluids, we purchase from various suppliers of well servicing products when needed.
Although we do not have written agreements with any of our suppliers (other than leases with respect to certain equipment), we have not historically suffered from an inability to purchase or lease equipment or purchase raw materials.
Insurance
Our operations are subject to risks inherent in the oilfield services industry, such as equipment defects, malfunctions, failures and natural disasters. In addition, hazards such as unusual or unexpected geological formations, pressures, blow-outs, fires or other conditions may be encountered in drilling and servicing wells, as well as the transportation of fluids and our assets between locations. We have obtained insurance coverage against certain of these risks which we believe is customary in the industry. We have $100,000,000 of excess liability coverage. Our workers compensation/employers liability has a zero dollar deductible. Our automobile liability policy has a $500,000 deductible for each accident. Our general liability policy is self-insured with the excess liability coverage in excess of $1,000,000 each occurrence. We also make estimates and accrue for amounts we expect to owe in excess of any insurance and to satisfy deductibles. Such insurance is subject to coverage limits and exclusions and may not be available for all of the risks and hazards to which we are exposed. In addition, no assurance can be given that such insurance will be adequate to cover our liabilities or will be generally available in the future or, if available, that premiums will be commercially justifiable. If we incur substantial liability and such damages are not covered by insurance or are in excess of policy limits, or if we incur such liability at a time when we are not able to obtain liability insurance, our business, results of operations, and financial condition could be materially and adversely affected.
Environmental Regulations
Our operations are subject to various federal, state and local laws and regulations in the United States pertaining to health, safety, and the environment. Laws and regulations protecting the environment have become more stringent over the years, and in certain circumstances may impose strict liability, rendering us liable for environmental damage without regard to negligence or fault on our part. Moreover, cleanup costs, penalties and other damages arising as a result of new, or changes to existing, environmental laws and regulations could be substantial and could have a material adverse effect on our financial condition, results of operations, and cash flows. We believe that we conduct our operations in substantial compliance with current United States federal, state, and local requirements related to health, safety and the environment.
The following is a summary of the more significant existing environmental, health, and safety laws and regulations to which our operations are subject and for which compliance may have a material adverse effect on our results of operation or financial position. See Item 1A “Risk Factors—Due to the nature of our business, we may be subject to environmental liability” on page 10 of this Annual Report on Form 10-K for further details.
The discussion below relates to the significant environmental, health, and safety laws and regulations that apply to our continuing operations, which excludes our Mexican operations that were sold in January 2012. Those Mexican operations were subject to various Mexican environmental, health and safety laws and regulations that are similar in scope and purpose as those
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governing our continuing U.S. operations. Notwithstanding the fact that we have sold our Mexican operations, we may still be subject to environmental liabilities under Mexican law and under the indemnification provisions of the asset and membership interest purchase agreement that governed the disposition of our Mexican operations, to the extent that our operations in Mexico are deemed to have been in violation of Mexican law. Nevertheless, we believe that we have conducted our operations in Mexico in substantial compliance with Mexican environmental, health, and safety laws and regulations.
Hazardous Substances and Waste
The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, or CERCLA, and comparable state laws in the United States impose liability without regard to fault or the legality of the original conduct on certain defined persons, including current and prior owners or operators of the site where a release of hazardous substances occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these responsible persons may be liable for the costs of cleaning up the hazardous substances, for damages to natural resources, and for the costs of certain health studies. In the course of our operations, we generate materials that are regulated as hazardous substances and, as a result, may incur CERCLA liability for cleanup costs. Also, claims may be filed for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants.
We also generate solid wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes. Certain materials generated in the exploration, development, or production of crude oil and natural gas are excluded from RCRA’s hazardous waste regulation, under RCRA Subtitle C, but may be subject to regulation as a solid waste under RCRA Subtitle D. Moreover, these wastes, which include wastes currently generated during our operations, could be designated as “hazardous wastes” in the future and become subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our operating expenses.
Although we have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been released at properties owned or leased by us now or in the past, or at other locations where these hydrocarbons and wastes were taken for treatment or disposal. Under CERCLA, RCRA and analogous state laws, we could be required to clean up contaminated property (including contaminated groundwater), perform remedial activities to prevent future contamination, or pay for associated natural resource damages.
Water Discharges
We operate facilities that are subject to requirements of the Clean Water Act, as amended, or CWA, and analogous state laws that impose restrictions and controls on the discharge of pollutants into navigable waters. Pursuant to these laws, permits must be obtained to discharge pollutants into state waters or waters of the United States, including to discharge storm water runoff from certain types of facilities. Spill prevention, control, and countermeasure requirements under the CWA require implementation of measures to help prevent the contamination of navigable waters in the event of a hydrocarbon spill. The CWA can impose substantial civil and criminal penalties for non-compliance. We believe that our disposal and equipment cleaning facilities are in substantial compliance with CWA requirements.
Air Emissions
Our facilities and operations are also subject to regulation under the Clean Air Act (CAA) and analogous state and local laws and regulations for air emissions. Changes in and scheduled implementation of these laws could lead to the imposition of new air pollution control requirements for our operations. Therefore, we may incur future capital expenditures to upgrade or modify air pollution control equipment or come into compliance where needed. We believe that our operations are in substantial compliance with CAA requirements.
Employee Health and Safety
We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, and comparable state laws that regulate the protection of employee health and safety. OSHA’s hazard communication standard requires that information about hazardous materials used or produced in our operations be maintained and provided to employees, state and local government authorities, and citizens. We believe that our operations are in substantial compliance with OSHA requirements.
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Climate Change Regulation
The U.S. Congress has been considering legislation to reduce the emissions of certain gases, commonly referred to as “greenhouse gases,” including carbon dioxide and methane, which according to certain scientific studies, might contribute to the warming of the Earth’s atmosphere and other climatic changes. Although it is not currently possible to predict when or if Congress may act on climate change legislation or whether the EPA would adopt more stringent regulation of greenhouse gases should Congress not act on this subject, any future federal laws or implementing regulations that may be adopted to address the emission of greenhouse gases could adversely affect demand for our services by reducing demand for the oil and natural gas produced by our customers. Such legislation or regulations could also increase our operating costs.
In December 2009, the EPA announced its finding that greenhouse gas emissions presented an endangerment to human health and the environment. These findings allow the EPA to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In September 2009, the EPA proposed regulations in anticipation of finalizing its endangerment finding that would require a reduction in greenhouse gas emissions from motor vehicles and could also trigger permit review for greenhouse gas emissions from certain stationary sources. On October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA issued regulations requiring onshore and offshore petroleum and natural gas production; natural gas processing, transmission distribution and storage facilities; and facilities that inject and store carbon dioxide underground for the purposes of geologic sequestration or enhanced oil and gas recovery to report greenhouse gas emissions on an annual basis. Reporting requirements under these new regulations were mandatory beginning in 2012 for emissions occurring in 2011.
Previously, the U.S. Congress had considered legislation that would regulate emission reporting and reduction and commodity hedging, and the U.S. Congress has evaluated proposals impacting onshore and offshore oil and gas activities and legislation such as the Oil Pollution Act. Such legislation and proposals have the potential to increase the cost of business for us and our customers and to require changes in the manner in which we operate our business. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations and the equipment and operations of our customers could require us to incur increased operating costs and could adversely affect demand for crude oil and natural gas produced by our customers, which would adversely affect demand for our services. The potential increase in the costs of our operations and the operations of our customers could include additional costs to operate and maintain equipment and facilities, install new emission controls on equipment and facilities, acquire allowances to authorize greenhouse gas emissions, pay any taxes related to greenhouse gas emissions, and administer and manage a greenhouse gas emissions program. While we may be able to include some or all of such increased operating costs in the rates we charge for our services, any recovery of such costs is uncertain.
Even if such legislation is not adopted at the national level, a number of states, acting either individually or through multi-state regional initiatives, have already begun implementing legal measures to reduce emissions of greenhouse gases. While no such legislation is currently being considered in Texas, many of our customers operate nationally and would be adversely affected by the requirements of such legislation. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition, and results of operations.
Other Laws and Regulations
We operate salt water disposal wells that are subject to the CWA, Safe Drinking Water Act, and state and local laws and regulations, including those established by the EPA’s Underground Injection Control Program which establishes the minimum program requirements. Our salt water disposal wells are located in Texas, which requires us to obtain a permit to operate each of these wells. We have such permits for each of our salt water disposal wells. The Texas regulatory agency may suspend or modify any of these permits if such well operation is likely to result in pollution of fresh water, substantial violation of permit conditions or applicable rules, or leaks to the environment. We maintain insurance against some risks associated with our well service activities, but there can be no assurance that this insurance will continue to be commercially available or available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified could have a materially adverse effect on our financial condition and operations. In addition, hydraulic fracturing practices have come under increased scrutiny in recent years as various regulatory bodies and public interest groups investigate the potential impacts of hydraulic fracturing on fresh water sources. Risks associated with potential regulation of hydraulic fracturing are discussed in more detail under Item 1A. Risk Factors, Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased cost and additional operating restrictions or delays.
Prior the disposition of our operations and substantially all the assets located in Mexico, all work related to the development of oil and other petrochemicals, including work related to oil wells, must have been authorized by Mexican authorities, which required an environmental impact statement related to such work.
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Available Information
Information regarding Forbes Energy Services Ltd. and its subsidiaries can be found on our website at http://www.forbesenergyservices.com. We make available on our website, free of charge, access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as well as other documents that we file or furnish to the Securities and Exchange Commission, or the SEC, in accordance with Sections 13 or 15(d) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. We intend to use our website as a means of disclosing material non-public information and for complying with disclosure obligations under Regulation FD. Such disclosures will be included on our website under the heading “Investor Relations.” Accordingly, investors should monitor such portion of our website, in addition to following our press releases, SEC filings and public conference calls and webcasts. Information filed with the SEC may be read or copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet website (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically. Our Employee Code of Conduct (which applies to all employees, including our Chief Executive Officer and Chief Financial Officer), Code of Business Conduct and Ethics for Members of the Board of Directors and the charters for our Audit, Nominating/Corporate Governance and Compensation Committees, can all be found on the Investor Relations page of our website under “Corporate Governance”. We intend to disclose any changes to or waivers from the Employee Code of Conduct that would otherwise be required to be disclosed under Item 5.05 of Form 8-K on our website. We will also provide printed copies of these materials to any shareholder upon request to Forbes Energy Services Ltd., Attn: Chief Financial Officer, 3000 South Business Highway 281, Alice, Texas 78332. The information on our website is not, and shall not be deemed to be, a part of this report or incorporated into any other filings we make with the Commission.
Item 1A. | Risk Factors |
The following information describes certain significant risks and uncertainties inherent in our business. You should take these risks into account in evaluating us. This section does not describe all risks applicable to us, our industry or our business, and it is intended only as a summary of known material risks that are specific to the company. You should carefully consider such risks and uncertainties together with the other information contained in this Form 10-K. If any of such risks or uncertainties actually occurs, our business, financial condition or operating results could be harmed substantially and could differ materially from the plans and other forward-looking statements included in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report on Form 10-K and elsewhere herein.
RISKS RELATING TO OUR BUSINESS
The industry in which we operate is highly volatile and dependent on domestic spending by the oil and natural gas industry, and there can be no assurance that our current levels of utilization, demand for our services, or current pricing will continue.
The levels of utilization, demand, pricing, and terms for oilfield services in our existing or future service areas largely depend upon the level of exploration and development activity for both crude oil and natural gas in the United States. Oil and natural gas industry conditions are influenced by numerous factors over which we have no control, including oil and natural gas prices, expectations about future oil and natural gas prices, levels of supply and consumer demand, the cost of exploring for, producing and delivering oil and natural gas, the expected rates of current production, the discovery rates of new oil and natural gas reserves, available pipeline and other oil and natural gas transportation capacity, political instability in oil and natural gas producing countries, merger and divestiture activity among oil and natural gas producers, political, regulatory and economic conditions, and the ability of oil and natural gas companies to raise equity capital or debt financing.
Our operations may be materially affected by severe weather conditions, such as hurricanes, drought, or extreme temperatures. Such events could result in evacuation of personnel, suspension of operations or damage to equipment and facilities. Damage from adverse weather conditions could result in a material adverse effect on our financial condition, results of operations and cash flows.
We expect that a continuation of currently depressed natural gas prices or a reduction in oil prices would have a negative effect on oil and natural gas production levels and therefore affect the demand for drilling and well services by oil and natural gas companies. Any addition to, or elimination or curtailment of, government incentives for companies involved in the exploration for and production of oil and natural gas could have a significant effect on the oilfield services industry in the United States. Lower oil and natural gas prices could also cause our customers to seek to terminate, renegotiate, or fail to honor
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our services contracts. A continued decrease in utilization, demand for our services, and pricing could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
We may be adversely affected by uncertainty in the global financial markets and any significant softening in the already limited worldwide economic recovery.
Despite the recent modest global economic recovery, our future results still may be impacted any significant reversal in such recovery or inflation, deflation, or other adverse economic conditions. These conditions may negatively affect us or parties with whom we do business. The impact on such third parties could result in their non-payment or inability to perform obligations owed to us such as the failure of customers to honor their commitments or the failure of major suppliers to complete orders. Additionally, credit market conditions may change slowing our collection efforts as customers may experience increased difficulty in obtaining requisite financing, potentially leading to lost revenue and higher than normal accounts receivable. This could result in greater expense associated with collection efforts and increased bad debt expense.
A deterioration of the economic recovery may cause institutional investors to respond to their customers by increasing interest rates, enacting tighter lending standards, or refusing to refinance existing debt upon its maturity or on terms similar to the expiring debt. We may require additional capital in the future. However, due to the above listed factors, we cannot be certain that additional funding will be available if needed and, to the extent required, on acceptable terms.
Our indebtedness and operating lease commitments could restrict our operations and make us more vulnerable to adverse economic conditions.
As of December 31, 2013, our long-term debt, including current portions, was $299.6 million and our annual commitment for operating leases for 2013 was $14.3 million. In the event we experience a decline in activity, our level of indebtedness and operating lease payment obligations may adversely affect operations and limit our growth. Our level of indebtedness and operating lease payments may affect our operations in several ways, including the following:
• | by increasing our vulnerability to general adverse economic and industry conditions; |
• | due to the fact that the covenants that are contained in the indenture governing our 9% Senior Notes and the loan agreement governing our revolving credit facility limit our ability to borrow funds, dispose of assets, pay dividends and make certain investments; |
• | due to the fact that any failure to comply with the covenants of our indenture and the loan agreement governing our revolving credit facility (including failure to make the required interest payments) could result in an event of default, which could result in some or all of our indebtedness becoming immediately due and payable; and |
• | due to the fact that our level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, or other general corporate purposes. |
These restrictions could have a material adverse effect on our business, financial position, results of operations, and cash flows, and the ability to satisfy the obligations under our indentures and the loan agreement governing our revolving credit facility. Further, due to cross-default provisions in the indenture governing our 9% Senior Notes and the loan agreement governing our revolving credit facility, with certain exceptions, a default and acceleration of outstanding debt under one debt agreement would result in the default and possible acceleration of outstanding debt under the other debt agreement. Accordingly, an event of default could result in all or a portion of our outstanding debt under our debt agreements becoming immediately due and payable. If this occurred, we might not be able to obtain waivers or secure alternative financing to satisfy all of our obligations simultaneously, which would adversely affect our business and operations.
Impairment of our long-term assets may adversely impact our financial position and results of operations.
We evaluate our long-term assets including property, equipment, and identifiable intangible assets in accordance with generally accepted accounting principles in the U.S. We use estimated future cash flows in assessing recoverability of our long-lived assets. The cash flow projections are based on our current estimates and judgmental assessments. We perform this assessment whenever facts and circumstances indicate that the carrying value of our net assets may not be recoverable due to various external or internal factors, termed a “triggering event.” Based on our evaluation for the year ended December 31, 2013, no impairment was recorded. Nevertheless, volatility in the oil and natural gas industry, which is driven by factors over which we have no control, could affect the fair market value of our equipment fleet. Under specific circumstances, this could trigger a write-down of our assets for accounting purposes, which could have a material adverse impact on our financial position and results of operations.
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We may be unable to maintain or increase pricing on our core services.
We may periodically seek to increase the prices on our services to offset rising costs or to generate higher returns for our shareholders. However, we operate in a very competitive industry and, as a result; we are not always successful in raising or maintaining our existing prices. Additionally, during periods of increased market demand, a significant amount of new service capacity may enter the market, which also puts pressure on the pricing of our services and limits our ability to increase prices.
Even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset such rising costs. In periods of high demand for oilfield services, a tighter labor market may result in higher labor costs. During such periods, our labor costs could increase at a greater rate than our ability to raise prices for our services. Also, we may not be able to successfully increase prices without adversely affecting our activity levels. The inability to maintain or increase our pricing as costs increase could have a material adverse effect on our business, financial position, and results of operations.
The industry in which we operate is highly competitive.
The oilfield services industry is highly competitive and we compete with a substantial number of companies, some of which have greater technical and financial resources than we have. Our larger competitors performing both well servicing and fluid logistics are Basic Energy Services, Inc., Superior Energy Services, Inc., Key Energy Services, Inc., and Nabors Industries Ltd. Our largest competitors that compete only with our fluid logistics segment are Heckman Corporation and Stallion Oilfield Services Ltd. Our ability to generate revenues and earnings depends primarily upon our ability to win bids in competitive bidding processes and to perform awarded projects within estimated times and costs. There can be no assurance that competitors will not substantially increase the resources devoted to the development and marketing of products and services that compete with ours or that new or existing competitors will not enter the various markets in which we are active. In certain aspects of our business, we also compete with a number of small and medium-sized companies that, like us, have certain competitive advantages such as low overhead costs and specialized regional strengths. In addition, reduced levels of activity in the oil and natural gas industry could intensify competition and the pressure on competitive pricing and may result in lower revenues or margins to us.
The indenture governing the 9% Senior Notes and the loan agreement governing our revolving credit facility impose significant operating and financial restrictions on us that may prevent us from pursuing certain business opportunities and restrict or limit our ability to operate our business.
The indenture governing the 9% Senior Notes and the loan agreement governing our revolving credit facility contain covenants that restrict or limit our ability to take various actions, such as:
• | incurring or guaranteeing additional indebtedness or issuing disqualified capital stock; |
• | creating or incurring liens; |
• | engaging in business other than our current business and reasonably related extensions thereof; |
• | making loans and investments; |
• | paying certain dividends, distributions, redeeming subordinated indebtedness or making other restricted payments; |
• | incurring dividend or other payment restrictions affecting certain subsidiaries; |
• | transferring or selling assets; |
• | entering into transactions with affiliates; and |
• | consummating a merger, consolidation or sale of all or substantially all of our assets. |
The restrictions contained in the indentures could also limit our ability to plan for or react to market conditions, meet capital needs or otherwise restrict our activities or business plans and adversely affect our ability to fund our operations, enter into acquisitions, or to engage in other business activities that would be in our interest.
Our customer base is concentrated within the oil and natural gas production industry and loss of a significant customer could cause our revenue to decline substantially.
We served in excess of 900 customers for the years ended December 31, 2013 and 2012. For those same time periods, our largest customer comprised approximately 10.5% and 9.3%, respectively, of our total revenues, our five largest customers comprised approximately 34.6% and 36.7%, respectively, of our total revenues, and our top ten customers comprised approximately 49.7% and 57.5%, respectively, of our total revenues. Our top 100 customers amounted to 91.3% and 92.4% for
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the years ended December 31, 2013 and 2012, respectively. The loss of our top customer or of several of our top customers would adversely affect our revenues and results of operations. We may be able to replace customers lost with other customers, but there can be no assurance that lost revenues could be replaced in a timely manner, with the same margins or at all.
We are subject to the risk of technological obsolescence.
We anticipate that our ability to maintain our current business and win new business will depend upon continuous improvements in operating equipment, among other things. There can be no assurance that we will be successful in our efforts in this regard or that we will have the resources available to continue to support this need to have our equipment remain technologically up to date and competitive. Our failure to do so could have a material adverse effect on us. No assurances can be given that competitors will not achieve technological advantages over us.
We are highly dependent on certain of our officers and key employees.
Our success is dependent upon our key management, technical and field personnel, especially John E. Crisp, our President and Chief Executive Officer, and Charles C. Forbes, our Executive Vice President and Chief Operating Officer. Any loss of the services of either one of these officers, or managers with strong relationships with customers or suppliers, or a sufficient number of other employees could have a material adverse effect on our business and operations. Our ability to expand our services is dependent upon our ability to attract and retain additional qualified employees. The ability to secure the services of additional personnel may be constrained in times of strong industry activity.
We expect that we will continue to incur significant costs as a result of being obligated to comply with Securities Exchange Act reporting requirements, the Sarbanes-Oxley Act, and our indenture and loan agreement covenants and that our management will be required to devote substantial time to compliance matters.
Under the indenture governing our 9% Senior Notes and the loan agreement governing our revolving credit facility, we are required to comply with several covenants, including requirements to deliver certain opinions and certificates, and file reports under the Securities Exchange Act of 1934, as amended, or the Exchange Act, with the Securities and Exchange Commission, or the SEC. In August 2011, we registered our class of common stock under Section 12 of the Exchange Act. As a result, we have reporting requirements under the Exchange Act. In addition, the Sarbanes-Oxley Act of 2002, and rules subsequently implemented by the SEC, have imposed various requirements on public companies, including the establishment and maintenance of effective disclosure controls and procedures, internal controls, and corporate governance practices. Accordingly, we expect to continue to incur significant legal, accounting and other expenses. We anticipate that our management and other personnel will continue to devote a substantial amount of time and resources to comply with these requirements.
The Sarbanes-Oxley Act of 2002 requires, among other things, that we assess internal controls for financial reporting and disclosure. We have performed and will perform system and process evaluation and testing of our internal control over financial reporting to allow management to report on the effectiveness of our internal controls over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002. Our historical testing has, and our future testing may, reveal deficiencies in our internal control over financial reporting that are deemed to be material weaknesses. We expect to continue to incur significant expense and devote substantial management effort toward ensuring compliance, in particular with Section 404. Moreover, if we are not able to comply with the requirements of Section 404 in a timely manner, if we identify, or our independent registered public accounting firm identifies, possible future deficiencies in our internal controls in addition to those discussed below that are deemed to be material weaknesses or if we fail to adequately address existing and future deficiencies, we could be subject to sanctions or investigations by the SEC or other regulatory authorities, which would entail expenditure of additional financial and management resources.
We previously identified and remediated material weaknesses in our internal control over financial reporting. Any failure to maintain effective internal control over financial reporting could result in our failure to meet our reporting obligations and cause investors to lose confidence in our reported financial information, which in turn could cause the trading price of our common stock to decline.
Our management previously identified control deficiencies that constituted material weaknesses in the design and operation of our internal control over financial reporting. A material weakness is a control deficiency that could result in a future material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.
Although we have determined that our internal control over financial reporting was effective as of December 31, 2013, we must continue to monitor and assess our internal control over financial reporting. If our management identifies one or more material weaknesses in our internal control over financial reporting in the future, we could lose investor confidence in the accuracy and completeness of our financial reports, which would likely have an adverse effect on our business and stock price.
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We engage in transactions with related parties and such transactions present possible conflicts of interest that could have an adverse effect on us.
We have entered into a significant number of transactions with related parties. The details of certain of these transactions are set forth in Note 9 to our consolidated financial statements included in this Annual Report on Form 10-K. Related party transactions create the possibility of conflicts of interest with regard to our management. Such a conflict could cause an individual in our management to seek to advance his or her economic interests above those of the Company. Further, the appearance of conflicts of interest created by related party transactions could impair the confidence of our investors. Our board of directors recently adopted a Related Persons Transaction Policy that requires the Audit Committee to approve or ratify related party transactions that involve consideration in excess of $120,000. Further, as required by the Company’s indenture, we seek the approval of the independent board members when such a related party transaction exceeds an aggregate consideration of $500,000 and an opinion regarding the fairness of such transaction from an outside firm when such a transaction exceeds an aggregate consideration of $2.5 million. Notwithstanding this, it is possible that a conflict of interest could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Activity in the oilfield services industry is seasonal and may affect our revenues during certain periods.
Our operations are impacted by seasonal factors. Historically, our business has been negatively impacted during the winter months due to inclement weather, fewer daylight hours, and holidays. Our well servicing rigs are mobile, and we operate a significant number of oilfield vehicles. During periods of heavy snow, ice or rain, we may not be able to move our equipment between locations, thereby reducing our ability to generate rig or truck hours. In addition, the majority of our well servicing rigs work only during daylight hours. In the winter months as daylight time becomes shorter, the amount of time that the well servicing rigs work is shortened, which has a negative impact on total hours worked. Finally, we historically have experienced significant slowdown during the Thanksgiving and Christmas holiday seasons.
We rely heavily on our suppliers and do not maintain written agreements with any such suppliers.
Our ability to compete and grow will be dependent on our access to equipment, including well servicing rigs, parts, and components, among other things, at a reasonable cost and in a timely manner. We do not maintain written agreements with any of our suppliers (other than operating leases for certain equipment), and we are, therefore, dependent on the relationships we maintain with them. Failure of suppliers to deliver such equipment, parts and components at a reasonable cost and in a timely manner would be detrimental to our ability to maintain existing customers and obtain new customers. No assurance can be given that we will be successful in maintaining our required supply of such items.
We rely heavily on two suppliers, Agri-Empresa, Inc. and Tetra Technologies, Inc., for potassium chloride, a principal raw material that is critical for our operations. While the materials are generally available, if we were to have a problem sourcing raw materials or transporting these materials from one of these two vendors, our ability to provide some of our services could be limited. Alternate suppliers exist for all other raw materials. The source and supply of materials has been consistent in the past, however, in periods of high industry activity, periodic shortages of certain materials have been experienced and costs have been affected. We do not have contracts with, but we do maintain relationships with, a number of suppliers in an attempt to mitigate this risk. However, if current or future suppliers are unable to provide the necessary raw materials, or otherwise fail to deliver products in the quantities required, any resulting delays in the provision of services to our customers could have a material adverse effect on our business, results of operations, financial condition, and cash flows.
We do not maintain current written agreements with respect to some of our salt water disposal wells.
Our ability to continue to provide well maintenance services depends on our continued access to salt water disposal wells. Several of our currently active salt water disposal wells are not subject to written operating agreements or are located on the premises of third parties with whom we do not have a current written lease. We do not maintain current written surface leases or right of way agreements with these third parties and we are, therefore, dependent on the relationships we maintain with them. Failure to maintain relationships with these third parties could impair our ability to access and maintain the applicable salt water disposal wells and any well servicing equipment located on their property. If that occurred, we would increase the levels of fluid injection at our remaining salt water disposal wells. However, our permits to inject fluid into the salt water disposal wells is subject to maximum pressure limitations and if multiple salt water disposal wells became unavailable, this might adversely impact our operations.
We extend credit to our customers which presents a risk of non-payment.
A substantial portion of our accounts receivable are with customers involved in the oil and natural gas industry, whose revenues may be affected by fluctuations in oil and natural gas prices. Collection of these receivables could be influenced by economic factors affecting this industry.
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Due to the nature of our business, we may be subject to environmental liability.
Our business operations and ownership of real property are subject to numerous United States federal, state and local environmental and health and safety laws and regulations, including those relating to emissions to air, discharges to water, treatment, storage and disposal of regulated materials, and remediation of soil and groundwater contamination. Our operations in Mexico, which were disposed in January 2012, were subject to equivalent Mexico laws. The nature of our business, including operations at our current and former facilities by prior owners, lessors or operators, exposes us to risks of liability under these laws and regulations due to the production, generation, storage, use, transportation, and disposal of materials that can cause contamination or personal injury if released into the environment. Environmental laws and regulations may have a significant effect on the costs of transportation and storage of raw materials as well as the costs of the transportation, treatment, storage, and disposal of wastes. We believe we are in material compliance with applicable environmental and worker health and safety requirements. However, we may incur substantial costs, including fines, damages, criminal or civil sanctions, remediation costs, or experience interruptions in our operations for violations or liabilities arising under these laws and regulations. Although we may have the benefit of insurance maintained by our customers or by other third parties or by us such insurances may not cover every expense. Further, we may become liable for damages against which we cannot adequately insure or against which we may elect not to insure because of high costs or other reasons.
Our customers are subject to similar environmental laws and regulations, as well as limits on emissions to the air and discharges into surface and sub-surface waters. Although regulatory developments that may occur in subsequent years could have the effect of reducing industry activity, we cannot predict the nature of any new restrictions or regulations that may be imposed. We may be required to increase operating expenses or capital expenditures in order to comply with any new restrictions or regulations.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for our services.
The U.S. Congress has been considering legislation to reduce the emissions of certain gases, commonly referred to as “greenhouse gases,” including carbon dioxide and methane, which according to certain scientific studies, might contribute to the warming of the Earth’s atmosphere and other climatic changes.
In December 2009, the EPA announced its finding that greenhouse gas emissions presented an endangerment to human health and the environment. These findings allow the EPA to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In September 2009, the EPA proposed regulations in anticipation of finalizing its endangerment finding that would require a reduction in greenhouse gas emissions from motor vehicles and could also trigger permit review for greenhouse gas emissions from certain stationary sources. On October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA issued regulations requiring onshore and offshore petroleum and natural gas production; natural gas processing, transmission distribution and storage facilities; and facilities that inject and store carbon dioxide underground for the purposes of geologic sequestration or enhanced oil and gas recovery to report greenhouse gas emissions on an annual basis. Reporting requirements under these new regulations were mandatory beginning in 2012 for emissions occurring in 2011.
Previously, the U.S. Congress had considered legislation that would regulate emission reporting and reduction and commodity hedging, and the U.S. Congress has evaluated proposals impacting onshore and offshore oil and gas activities and legislation such as the Oil Pollution Act. Such legislation and proposals have the potential to increase the cost of business for us and our customers and to require changes in the manner in which we operate our business. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations and the equipment and operations of our customers could require us to incur increased operating costs and could adversely affect demand for crude oil and natural gas produced by our customers, which would adversely affect demand for our services. The potential increase in the costs of our operations and the operations of our customers could include additional costs to operate and maintain equipment and facilities, install new emission controls on equipment and facilities, acquire allowances to authorize greenhouse gas emissions, pay any taxes related to greenhouse gas emissions, and administer and manage a greenhouse gas emissions program. While we may be able to include some or all of such increased operating costs in the rates we charge for our services, any recovery of such costs is uncertain.
Even if such legislation is not adopted at the national level, a number of states, acting either individually or through multi-state regional initiatives, have already begun implementing legal measures to reduce emissions of greenhouse gases. While no such legislation is currently being considered in Texas, many of our customers operate nationally and would be adversely affected by the requirements of such legislation. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition, and results of operations.
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Significant physical effects of climatic change, if they should occur, have the potential to damage oil and natural gas facilities, disrupt production activities and could cause us or our customers to incur significant costs in preparing for or responding to those effects.
In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If any such effects were to occur, they could have an adverse effect on our assets and operations or the assets and operations of our customers. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result should the potential physical effects of climate change occur. Unrecovered damages and losses incurred by our customers could result in decreased demand for our services.
Increasing trucking regulations may increase our costs and negatively affect our results of operations.
In connection with the services we provide, we operate as a motor carrier and, therefore, are subject to regulation by the U.S. Department of Transportation, or U.S. DOT, and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations and changes in the regulations that govern the amount of time a driver may drive in any specific period, onboard black box recorder devices, or limits on vehicle weight and size.
Interstate motor carrier operations are subject to safety requirements prescribed by the U.S. DOT. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations.
From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely affect the recruitment of drivers. Management cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted. We may be required to increase operating expenses or capital expenditures in order to comply with any new restrictions or regulations.
We are subject to extensive additional governmental regulation.
In addition to environmental and trucking regulations, our operations are subject to a variety of other United States federal, state, and local laws, regulations and guidelines, including laws and regulations relating to health and safety, the conduct of operations, and the manufacture, management, transportation, storage and disposal of certain materials used in our operations. Our previous Mexican operations were subject to equivalent Mexican laws. Also, we may become subject to such regulation in any new jurisdiction in which we may operate. We believe that we are in compliance with such laws, regulations and guidelines.
Although we continue to enhance our infrastructure, we have invested financial and managerial resources to comply with applicable laws, regulations and guidelines and expect to continue to do so in the future. Although regulatory expenditures have not, historically, been material to us, such laws, regulations and guidelines are subject to change. Accordingly, it is impossible for us to predict the cost or effect of such laws, regulations, or guidelines on our future operations.
Our ability to use net operating loss carryforwards may be subject to limitations under Section 382 of the Internal Revenue Code.
As of January 1, 2014, we had U.S. federal tax net operating loss carryforwards of approximately $50.7 million. Generally, net operating loss, or NOL, carryforwards, may be used to offset future taxable income and thereby reduce or eliminate U.S. federal income taxes. If we were to experience a change in ownership within the meaning of Section 382 of the Internal Revenue Code of 1986, as amended, or the Code, however, our ability to utilize our NOLs might be significantly limited or possibly eliminated. A change of ownership under Section 382 is defined as a cumulative change of 50% or more in the ownership positions of certain shareholders over a three-year period.
Based on our review of the issue, we do not believe that we have experienced an ownership change under Section 382 of the Code. However, the issuance of additional equity in the future may result in an ownership change pursuant to Section 382 of the Code. In addition, an ownership change under Section 382 could be caused by circumstances beyond our control, such as market purchases of our stock. Thus, there can be no assurance that we will not experience an ownership change that would limit our application of our net operating loss carryforwards in calculating future federal tax liabilities.
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Our operations are inherently risky, and insurance may not always be available in amounts sufficient to fully protect us.
We have an insurance and risk management program in place to protect our assets, operations, and employees. We also have programs in place to address compliance with current safety and regulatory standards. However, our operations are subject to risks inherent in the oilfield services industry, such as equipment defects, malfunctions, failures, accidents, and natural disasters. In addition, hazards such as unusual or unexpected geological formations, pressures, blow-outs, fires, or other conditions may be encountered in drilling and servicing wells, as well as the transportation of fluids and company assets between locations. These risks and hazards could expose us to substantial liability for personal injury, loss of life, business interruption, property damage or destruction, pollution, and other environmental damages.
Although we have obtained insurance against certain of these risks, such insurance is subject to coverage limits and exclusions and may not be available for the risks and hazards to which we are exposed. In addition, no assurance can be given that such insurance will be adequate to cover our liabilities or will be generally available in the future or, if available, that premiums will be commercially justifiable. If we were to incur substantial liability and such damages were not covered by insurance or were in excess of policy limits, or if we were to incur such liability at a time when we are not able to obtain liability insurance, our business, results of operations, and financial condition could be materially adversely affected.
The market for oil and natural gas may be adversely affected by global demands to curtail use of such fuels.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas and technological advances in fuel economy and energy generation devices could reduce the demand for oil and other liquid hydrocarbons. We cannot predict the effect of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on our business, financial condition, results of operations and cash flows.
We cannot predict how an exit by any of our founding principal equity investors could affect our operations or business.
As of March 24, 2014, John E. Crisp, Charles C. Forbes and Janet L. Forbes, our founding principal equity holders, beneficially owned 6.3%, 13.3%, and 10.9%, respectively, of our common stock. Our founding principal equity investors may transfer their interests in us or engage in other business combination transactions with a third party that could result in a change in ownership or a change of control of us. Any transfer of an equity interest in us or a change of control could affect our governance. We cannot be certain that such equity investors will not sell, transfer, or otherwise modify their ownership interest in us, whether in transactions involving third parties or other investors, nor can we predict how a change of equity investors or change of control would affect our operations or business.
Our principal equity investors control important decisions affecting our governance and our operations, and their interests may differ from those of our other shareholders.
Circumstances may arise in which the interest of our principal equity investors could be in conflict with those of the other shareholders. In particular, our principal equity investors may have an interest in pursuing certain strategies or transactions that, in their judgment, enhance the value of their investment in us even though these strategies or transactions may involve risks to other shareholders.
Although Texas corporate law provides certain procedural protections and requires that certain business combinations between us and certain interested or affiliated shareholders meet certain approval requirements, this does not address all conflicts of interest that may arise. For example, our principal equity investors and their affiliates are not prohibited from competing with us. Because our principal equity investors control us, conflicts of interest arising because of competition between us and a principal equity investor could be resolved in a manner adverse to us. It is possible that there will be situations where our principal equity investors’ interests are in conflict with our interests, and our principal equity investors acting through the board of directors or through our executive officers could resolve these conflicts in a manner adverse to us.
We have anti-takeover provisions in our organizational and other documents that may discourage a change of control.
Our organizational documents contain provisions that could make it more difficult for a third party to acquire us without the consent of our board of directors. These provisions provide for the following:
• | restrictions on the time period in which directors may be nominated; |
• | the ability of our board of directors to determine the powers, preferences and rights of the preferred stock and to authorize the issuance of shares of such stock without shareholder approval; and |
• | requirements that a majority of the members of our board of directors approve certain corporate transactions. |
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We also have a shareholder rights plan which can make it difficult for anyone to accumulate more than a certain percentage of our outstanding equity without approval of our board of directors. These provisions could make it more difficult for a third party to acquire us, even if the third party’s offer may be considered beneficial by many shareholders. As a result, shareholders may be limited in their ability to obtain a premium for their shares.
Future legal proceedings could adversely affect us and our operations.
Given the nature of our business, we are involved in litigation from time to time in the ordinary course of business. While we are not presently a party to any material legal proceedings, legal proceedings could be filed against us in the future. No assurance can be given as to the final outcome of any legal proceedings or that the ultimate resolution of any legal proceedings will not have a material adverse effect on us.
We may not be able to fully integrate future acquisitions.
We may undertake future acquisitions of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends in part on having the acquired assets perform as expected, successfully consolidating functions, retaining key employees and customer relationships, and integrating operations and procedures in a timely and efficient manner. Such integration may require substantial management effort, time, and resources and may divert management’s focus from other strategic opportunities and operational matters, and ultimately we may fail to realize anticipated benefits of acquisitions.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased cost and additional operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. Hydraulic fracturing involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and gas commissions but the EPA and other federal agencies are evaluating the practice, as evidenced by the EPA providing advisory materials under the Safe Drinking Water Act. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. The EPA investigation preliminarily concluded that groundwater contamination in Wyoming resulted from the process, and the EPA asserted that an operator caused groundwater contamination in Texas. Although the EPA investigations have been criticized and The Railroad Commission of Texas determined the evidence did not support the EPA’s assertion against operators in Texas, the examination of the process could result in increased regulation, lawsuits, or claims of injury to groundwater or communities. For example, the U.S. Department of Energy composed a list of practices to follow in order to protect groundwater in shale gas production. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states, including some states in which we operate (such as Texas) have adopted and other states are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. A law enacted by the Texas legislature and a rule enacted by The Railroad Commission of Texas in 2011 require disclosure regarding the composition of hydraulic fracturing products to certain parties, including The Railroad Commission of Texas. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for producers to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. The prohibition or restriction of hydraulic fracturing on the part of our customers could have a material adverse effect on our business, results of operations or financial condition.
The dividend, liquidation, and redemption rights of the holders of our Series B Senior Convertible Preferred Stock may adversely affect our financial position and the rights of the holders of our common stock.
We have shares of Series B Senior Convertible Preferred Stock, or the Series B Preferred Stock, outstanding. We have the obligation to pay to the holders of our Series B Preferred Stock quarterly dividends of five percent per annum of the original issue price, payable quarterly in cash or in-kind. No dividends may be paid to holders of common stock while accumulated dividends remain unpaid on the Series B Preferred Stock. We are current on dividends through the quarterly period ended February 28, 2014.
Further, we are required, at the seventh anniversary of the issuance of the Series B Preferred Stock on May 28, 2017, to redeem any such outstanding shares at their original issue price, plus any accumulated and unpaid dividends, to be paid, at our election, in cash or shares of common stock. The payment of the redemption price in cash is expected to result in reduced capital resources available to the Company. The payment of the redemption price in shares of common stock would directly dilute the common shareholders. The payment of dividends in-kind would also have a dilutive effect on the common
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shareholders (as any Series B Preferred Stock issued as dividends will be themselves convertible into common shares). In the event that the Company is liquidated while shares of Series B Preferred Stock is outstanding, holders of the Series B Preferred Stock will be entitled to receive a preferred liquidation distribution, plus any accumulated and unpaid dividends, before holders of common stock receive any distributions.
Holders of the Series B Preferred Stock have certain voting and other rights that may adversely affect holders of our common stock, and the holders of our Series B Preferred Stock may have different interests from, and vote their shares in a manner deemed adverse to, holders of our common stock.
In the event that we fail to pay dividends, in cash or in-kind, on the Series B Preferred Stock for an aggregate of at least eight quarterly dividend periods (whether or not consecutive), the holders of the Series B Preferred Stock will be entitled to vote at any meeting of the shareholders with the holders of the common shares and to cast the number of votes equal to the number of shares of whole common stock into which the Series B Preferred Stock held by such holders are then convertible. If the holders of the current Series B Preferred Stock were able to vote pursuant to this provision at this time or converted the Series B Preferred Stock into common stock, we believe that, as of March 24, 2014, those holders would be entitled to an aggregate of 5,292,531 votes resulting from their ownership of Series B Preferred Stock, based on shareholding information provided to us by the current holder of the Series B Preferred Stock. This together with common shares already held by these shareholders (as reported to us by such shareholders), would entitle these shareholders to just under 20%, in the aggregate, of the voting power of the Company. Further, the holders of Series B Preferred Stock may have certain voting rights with respect to the approval of amendments to the certificate of formation of the Company or certain transactions between the Company and affiliate shareholders.
The holders of Series B Preferred Stock may have different interests from the holders of our common stock and could vote their shares in a manner deemed adverse to the holders of common stock.
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Item 1B. | Unresolved Staff Comments |
None.
Item 2. | Properties |
The following sets forth the principal locations from which the Company currently conducts its operations. The Company leases or rents all of the properties set forth below, except for the Alice rig yard and San Ygnacio truck yard, which are owned by the Company.
Locations | Date in Service | Service Offering | ||
South Texas | ||||
Alice - truck location | 9/1/2003 | Fluid Logistics | ||
Alice - rig location | 9/1/2003 | Well Servicing | ||
Freer | 9/1/2003 | Fluid Logistics | ||
Laredo | 10/1/2003 | Fluid Logistics | ||
San Ygnacio | 4/1/2004 | Fluid Logistics | ||
Goliad | 8/1/2005 | Fluid Logistics | ||
Bay City | 9/1/2005 | Fluid Logistics | ||
Edna | 2/1/2006 | Well Servicing | ||
Three Rivers | 8/1/2006 | Fluid Logistics | ||
Carrizo Springs | 12/1/2006 | Fluid Logistics | ||
Victoria | 2/15/2011 | Well Servicing | ||
Pleasanton | 3/6/2013 | Well Servicing | ||
West Texas | ||||
Ozona | 3/1/2006 | Fluid Logistics | ||
San Angelo | 7/1/2006 | Well Servicing | ||
Midland | 11/1/2012 | Fluid Logistics | ||
Monahans | 8/31/2007 | Well Servicing/Fluid Logistics | ||
Odessa | 9/30/2007 | Well Servicing | ||
Big Spring | 10/15/2007 | Well Servicing/Fluid Logistics | ||
Big Lake | 7/16/2008 | Well Servicing/Fluid Logistics | ||
Andrews | 8/27/2008 | Well Servicing | ||
East Texas | ||||
Marshall | 12/1/2005 | Fluid Logistics | ||
Carthage | 3/1/2007 | Well Servicing | ||
Kilgore | 11/1/2007 | Well Servicing | ||
Crockett | 8/1/2013 | Fluid Logistics | ||
Giddings | 1/1/2013 | Well Servicing | ||
Mississippi | ||||
Laurel | 7/1/2010 | Well Servicing | ||
Pennsylvania | ||||
Indiana | 7/9/2009 | Well Servicing |
Item 3. | Legal Proceedings |
There are no pending material legal proceedings, and the Company is not aware of any material threatened legal proceedings, to which the Company is a party or to which its property is subject, other than in the ordinary course of business.
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Item 4. | Mine Safety Disclosures |
Not applicable.
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PART II
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Price Range of Common Shares
On August 12, 2011, we completed the Share Consolidation and Texas Conversion. Beginning on Tuesday, August 16, 2011, our common stock began trading on a post-consolidation, post-conversion basis on NASDAQ Global Market, or NASDAQ, under the symbol FES. The Company voluntarily delisted its common stock from the Toronto Stock Exchange, or the TSX, as of the close of trading on Friday, November 16, 2012. The following table sets forth, for the periods indicated, on NASDAQ for our common stock for the years ended December 31, 2013 and 2012.
High | Low | |||||
Fiscal Year 2013: | ||||||
Fourth Quarter | USD | 5.03 | USD | 3.25 | ||
Third Quarter | USD | 5.01 | USD | 4.14 | ||
Second Quarter | USD | 4.02 | USD | 3.31 | ||
First Quarter | USD | 4.05 | USD | 2.33 | ||
Fiscal Year 2012: | ||||||
Fourth Quarter | USD | 3.54 | USD | 1.66 | ||
Third Quarter | USD | 4.78 | USD | 2.92 | ||
Second Quarter | USD | 6.25 | USD | 4.08 | ||
First Quarter | USD | 7.00 | USD | 5.12 |
As of March 24, 2014, the last reported sales prices of our common shares on NASDAQ was USD $3.78 per share. As of March 25, 2013, we had 21,617,835 shares of common stock issued and outstanding, held by 17 shareholders of record. All common stock held in street name are recorded in the Company’s stock register as being held by one stockholder.
The Company has never declared a cash dividend on its common stock and has no plans of doing so now or in the foreseeable future. The loan agreement governing the credit facility prohibits the payment of dividends on the Company’s common stock. It does, however, permit dividend payments on the Company’s Series B Preferred Stock and the Company anticipates paying the preferred dividends in cash for the foreseeable future. Further, the indenture governing our 9% Senior Notes restricts the Company’s ability to pay dividends on our equity interests, except dividends payable in equity interests and cash dividends on the Series B Preferred Stock up to $260,000 per quarter, unless, among other things, the Company is able to incur at least $1.00 of additional Indebtedness (as defined in the indenture) pursuant to the Fixed Charge Coverage Ratio set forth in such indenture.
The Series B Preferred Stock accrues dividends at a rate of $1.25 per share per year, which, at our discretion, is payable in cash or in-kind. The Company anticipates paying the preferred dividends in cash for the foreseeable future. Other than these dividends, our board of directors presently intends to retain all earnings for use in our business and, therefore, does not anticipate paying any other cash dividends in the foreseeable future. The declaration of dividends on common equity, if any, in the future would be subject to the discretion of the board of directors, which may consider factors such as our credit facility and indenture restrictions discussed above, the Company’s results of operations, financial condition, capital needs, liquidity, and acquisition strategy, among others. Additionally, the certificate of designation that governs the Series B Preferred Stock prohibits the Company from paying a dividend on the common shares if dividends on the Series B Preferred Stock are not paid through the respective quarterly payment date. Further, if the aggregate cash payment of dividends on the common stock over a twelve month period exceeds five percent of the fair market value of the common shares, then we are required under the certificate of designation of the Series B Preferred Stock to pay the holders of such shares that amount that they would be entitled to receive had such holders converted their shares to common shares prior to the record date of such dividends.
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Item 6. | Selected Financial Data |
The following statement of operations data for the years ended December 31, 2013, 2012 and 2011 and the balance sheet data as of December 31, 2013 and 2012, have been derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K. The statement of operations data for the years ended December 31, 2010 and 2009 and the balance sheet data as of December 31, 2011, 2010 and 2009, have been derived from our audited consolidated financial statements not included in this Annual Report on Form 10-K. Our historical results are not necessarily indicative of results to be expected for any future period. The data presented below have been derived from financial statements that have been prepared in accordance with accounting principles generally accepted in the United States and should be read with our financial statements, including notes, and with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” on page 25 of this Annual Report on Form 10-K.
Year Ended December 31, | |||||||||||||||||||
2013 | 2012 | 2011 | 2010 | 2009 | |||||||||||||||
(dollars in thousands) | |||||||||||||||||||
Statement of Operations Data: | |||||||||||||||||||
Revenues | |||||||||||||||||||
Well servicing | $ | 231,930 | $ | 202,670 | $ | 177,896 | $ | 109,355 | $ | 79,812 | |||||||||
Fluid logistics | 188,003 | 269,927 | 267,887 | 178,796 | 109,822 | ||||||||||||||
Total revenues | 419,933 | 472,597 | 445,783 | 288,151 | 189,634 | ||||||||||||||
Expenses | |||||||||||||||||||
Well servicing | 182,180 | 158,302 | 141,589 | 87,164 | 74,537 | ||||||||||||||
Fluid logistics | 141,957 | 196,383 | 193,718 | 138,079 | 87,263 | ||||||||||||||
General and administrative | 30,186 | 33,382 | 31,318 | 20,039 | 17,424 | ||||||||||||||
Depreciation and amortization | 54,838 | 50,997 | 39,660 | 38,299 | 38,029 | ||||||||||||||
Total expenses | 409,161 | 439,064 | 406,285 | 283,581 | 217,253 | ||||||||||||||
Operating income (loss) | 10,772 | 33,533 | 39,498 | 4,570 | (27,619 | ) | |||||||||||||
Other income (expense) | |||||||||||||||||||
Interest income | 27 | 78 | 56 | 149 | 14 | ||||||||||||||
Interest expense | (28,211 | ) | (28,033 | ) | (27,454 | ) | (27,271 | ) | (26,923 | ) | |||||||||
Gain (loss) on early extinguishment of debt | — | — | (35,415 | ) | 19 | — | |||||||||||||
Other income (expense), net | — | — | 69 | (9 | ) | 1,421 | |||||||||||||
Income (loss) from continuing operations before income taxes | (17,412 | ) | 5,578 | (23,246 | ) | (22,542 | ) | (53,107 | ) | ||||||||||
Income tax (benefit) expense | (4,615 | ) | 3,359 | (4,677 | ) | (8,157 | ) | (25,144 | ) | ||||||||||
Income (loss) from continuing operations | (12,797 | ) | 2,219 | (18,569 | ) | (14,385 | ) | (27,963 | ) | ||||||||||
Income (loss) from discontinued operations, net of tax expense (benefit) of ($200), ($400), $6,300, $1,600, and $0, respectively | (293 | ) | (633 | ) | 6,224 | 3,075 | (1,368 | ) | |||||||||||
Net income (loss) | (13,090 | ) | 1,586 | (12,345 | ) | (11,310 | ) | (29,331 | ) | ||||||||||
Preferred stock dividends | (776 | ) | (776 | ) | (186 | ) | (1,041 | ) | — | ||||||||||
Net income (loss) attributable to common shareholders | $ | (13,866 | ) | $ | 810 | $ | (12,531 | ) | $ | (12,351 | ) | $ | (29,331 | ) | |||||
Income (loss) per share of common stock from continuing operations | |||||||||||||||||||
Basic and diluted | $ | (0.64 | ) | $ | 0.07 | $ | (0.90 | ) | $ | (0.74 | ) | $ | (1.79 | ) | |||||
Income (loss) per share of common stock from discontinued operations | |||||||||||||||||||
Basic and diluted | $ | (0.01 | ) | $ | (0.03 | ) | $ | 0.30 | $ | 0.15 | $ | (0.09 | ) | ||||||
Income (loss) per share of common stock | |||||||||||||||||||
Basic and diluted | $ | (0.65 | ) | $ | 0.04 | $ | (0.60 | ) | $ | (0.59 | ) | $ | (1.87 | ) | |||||
Weighted average number of shares outstanding | |||||||||||||||||||
Basic | 21,388 | 21,062 | 20,918 | 20,918 | 15,661 | ||||||||||||||
Diluted | 21,388 | 21,340 | 20,918 | 20,918 | 15,661 |
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Year Ended December 31, | ||||||||||||||
2013 | 2012 | 2011 | 2010 | 2009 | ||||||||||
Operating Data: | ||||||||||||||
Well servicing rigs (end of periods)(1) | 167 | 162 | 159 | 159 | 157 | |||||||||
Rig hours(1) | 449,277 | 435,560 | 411,539 | 307,377 | 228,279 | |||||||||
Heavy trucks (end of period) (1)(2) | 591 | 578 | 496 | 357 | 362 | |||||||||
Trucking hours | 1,182,429 | 1,676,778 | 1,476,664 | 1,135,227 | 863,506 | |||||||||
Salt water disposal wells (end of period) | 24 | 24 | 17 | 15 | 18 | |||||||||
Locations (end of period)(1) | 27 | 25 | 25 | 26 | 28 | |||||||||
Frac tanks (end of period) | 2,997 | 3,112 | 1,879 | 1,368 | 1,369 | |||||||||
Fluid mixing tanks (end of period) | 274 | 96 | — | — | — | |||||||||
Coiled tubing spreads | 5 | 4 | — | — | — |
____________________
(1) | The table above does not include 14 workover rigs, 4 vacuum trucks, and one operating location which were included in the disposition of substantially all of our long-lived assets located in Mexico completed on January 12, 2012. Also, the rig hours associated with our Mexico operations have been removed. |
(2) | Includes vacuum trucks, high pressure pump trucks, and other heavy trucks. As of December 31, 2013, 195 heavy trucks were leased. |
Year Ended December 31, | |||||||||||||||||||
2013 | 2012 | 2011 | 2010 | 2009 | |||||||||||||||
(dollars in thousands) | |||||||||||||||||||
Balance Sheet Data: | |||||||||||||||||||
Cash and cash equivalents | $ | 26,409 | $ | 17,619 | $ | 36,599 | $ | 30,458 | $ | 28,425 | |||||||||
Property and equipment, net | 341,869 | 348,442 | 285,945 | 256,743 | 289,781 | ||||||||||||||
Total assets | 500,558 | 512,701 | 550,423 | 451,830 | 457,432 | ||||||||||||||
Total long-term debt | 290,266 | 293,321 | 285,633 | 212,915 | 214,465 | ||||||||||||||
Total liabilities | 364,980 | 366,015 | 410,167 | 299,764 | 310,925 | ||||||||||||||
Temporary equity-preferred stock | 14,560 | 14,518 | 14,477 | 15,270 | — | ||||||||||||||
Shareholders’ equity | 121,018 | 132,168 | 125,779 | 136,795 | 146,507 |
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Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This discussion and analysis contains forward-looking statements within the meaning of the federal securities laws, including statements using terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project” or “should” or other comparable words or the negative of these words. Forward-looking statements involve various risks and uncertainties. Any forward-looking statements made by or on our behalf are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Readers are cautioned that such forward-looking statements involve risks and uncertainties in that the actual results may differ materially from those projected in the forward-looking statements. Important factors that could cause actual results to differ include risks set forth in “Part I-Item 1A. Risk Factors” included on page 10 herein.
Overview
FES Ltd. is an independent oilfield services contractor that provides a wide range of well site services to oil and natural gas drilling and producing companies to help develop and enhance the production of oil and natural gas. These services include fluid hauling, fluid disposal, well maintenance, completion services, workovers, and recompletions, plugging and abandonment, and tubing testing. Our operations are concentrated in the major onshore oil and natural gas producing regions of Texas, with additional locations in Mississippi, in Pennsylvania and, prior to the disposition of our Mexican assets in January 2012, which is discussed below, in Mexico. We believe that our broad range of services, which extends from initial drilling, through production, to eventual abandonment, is fundamental to establishing and maintaining the flow of oil and natural gas throughout the life cycle of our customers’ wells.
We currently provide a wide range of services to a diverse group of companies. Our blue-chip customer base includes Anadarko Petroleum Corporation, Chesapeake Energy Corporation, ConocoPhillips Company, Rosetta Resources, Inc., and Shell Oil Company, among others. John E. Crisp and Charles C. Forbes, our senior management team, have cultivated deep and ongoing relationships with these customers during their average of approximately 37 years of experience in the oilfield services industry. For the year ended December 31, 2013, we generated total revenues of approximately $419.9 million.
We currently conduct our operations through the following two business segments:
• | Well Servicing. The well servicing segment comprised 55.2% of our total revenues for the year ended December 31, 2013. At December 31, 2013, our well servicing segment utilized our modern fleet of 167 owned well servicing rigs, which was comprised of 157 workover rigs and ten swabbing rigs, as well as five coiled tubing spreads, nine tubing testing units, and related assets and equipment. These assets are used to provide (i) well maintenance, including remedial repairs and removal and replacement of downhole production equipment, (ii) well workovers, including significant downhole repairs, re-completions and re-perforations, (iii) completion and swabbing activities, (iv) plugging and abandonment services, and (v) testing of oil and natural gas production tubing. |
• | Fluid Logistics. The fluid logistics segment comprised 44.8% of our total revenues for the year ended December 31, 2013. Our fluid logistics segment utilized our fleet of owned or leased fluid transport trucks and related assets, including specialized vacuum, high-pressure pump and tank trucks, frac tanks, water wells, salt water disposal wells and facilities, and related equipment. These assets are used to provide, transport, store, and dispose of a variety of drilling and produced fluids used in, and generated by, oil and natural gas production. These services are required in most workover and completion projects and are routinely used in daily operations of producing wells. |
We believe that our two business segments are complementary and create synergies in terms of selling opportunities. Our multiple lines of service are designed to capitalize on our existing customer base to grow it within existing markets, generate more business from existing customers, and increase our operating performance. By offering our customers the ability to reduce the number of vendors they use, we believe that we help improve our customers’ efficiency. This is demonstrated by the fact that 78.7% of our consolidated revenues for the year ended December 31, 2013 were from customers that utilized services of both of our business segments. Further, by having multiple service offerings that span the life cycle of the well, we believe that we have a competitive advantage over smaller competitors offering more limited services.
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Factors Affecting Results of Operations
Oil and Natural Gas Prices
Demand for well servicing and fluid logistics services is generally a function of the willingness of oil and natural gas companies to make operating and capital expenditures to explore for, develop, and produce oil and natural gas, which in turn is affected by current and anticipated levels of oil and natural gas prices. Exploration and production spending is generally categorized as either operating expenditures or capital expenditures. Activities by oil and natural gas companies designed to add oil and natural gas reserves are classified as capital expenditures, and those associated with maintaining or accelerating production, such as workover and fluid logistics services, are categorized as operating expenditures. Operating expenditures are typically more stable than capital expenditures and are less sensitive to oil and natural gas price volatility. In contrast, capital expenditures by oil and natural gas companies for drilling are more directly influenced by current and expected oil and natural gas prices and generally reflect the volatility of commodity prices.
Workover Rig Rates
Our well servicing segment revenues are dependent on the prevailing market rates for workover rigs. Rates and utilization remained stable through the first half of 2012 and slightly declined though the last half of 2012. Rates stabilized through the nine months of 2013 and increased in September 2013 and remained stable through the end of the year while utilization has slightly increased in 2013 from the last half of 2012.
Fluid Logistics Rates
Our fluid logistics segment revenues are dependent on the prevailing market rates for fluid transport trucks and the related assets, including specialized vacuum, high-pressure pump and tank trucks, hot oil trucks, frac tanks, fluid mixing tanks, and salt water disposal wells. Pricing and utilization increased through the beginning of 2012 before dropping through the second half of 2012. This drop in the second half of 2012 was partially due to the increase in supply of fluid logistics equipment in the markets where the company operates. Rates continued to drop in 2013, most notably frac tank rental rates. This drop in 2013 is attributed to additional capacity in the market which created downward pressure on rates.
Operating Expenses
As utilization and demand remained strong through the beginning of 2012, we experienced cost pressures in areas such as labor where we have incurred additional cost increases primarily in the form of increased pay rates. During 2013 labor rates have been relatively stable in our fluid logistics segment even though rates and utilization fell due to greater competition for employees in our well servicing segment has resulted in increased hourly costs. Future earnings and cash flows will be dependent on our ability to manage our overall cost structure and either maintain our existing prices or obtain price increases from our customers as our operating costs increase.
Equipment rental and lease costs continue to be a significant component of our operating expenses. We made certain capital expenditures throughout 2012 that replaced certain leased or rented equipment. During 2012, we entered into operating leases for vacuum trucks, vacuum trailers, support trucks, pressure pumping units, crane trucks, nitrogen pumping units, and a transport trailer. During 2013, we entered into operating leases for certain well servicing assets. We expect that we will continue to meet certain equipment needs through rental or leasing arrangements.
Capital Expenditures and Debt Service Obligations
In 2013, we received five additional workover rigs, completed drilling of one new salt water disposal well and purchased four hot oil trucks, additional nitrogen pumping units, fluid mixing tanks, three specialty vacuum trucks and incurred the associated costs of placing this equipment in service. We have also ordered one additional coiled tubing spread that we expect to receive in the second quarter of 2014. In addition, the Company continues to evaluate salt water disposal well and facility locations to better serve its customers. Capital expenditures for the twelve months ended December 31, 2013 were $47.3 million.
Presentation
The financial information as of and for the years ended December 31, 2013, 2012, and 2011 is presented on a consolidated basis for FES Ltd. and its subsidiaries based on continuing operations. Unless otherwise indicated, all financial or operational data presented herein relates to our continuing operations, excluding our operations in Mexico that were sold in January 2012. Notwithstanding the foregoing, financial information regarding cash flows presented herein includes cash flows from our discontinued operations.
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Results of Operations
Year Ended December 31, | ||||||||||||||||||
2013 | % of Revenue | 2012 | % of Revenue | 2011 | % of Revenue | |||||||||||||
(Dollars in Thousands) | ||||||||||||||||||
Revenue | $ | 419,933 | 100.0 | % | $ | 472,597 | 100.0 | % | $ | 445,783 | 100.0 | % | ||||||
Operating expenses | 324,137 | 77.2 | % | 354,685 | 75.1 | % | 335,307 | 75.2 | % | |||||||||
General & administrative expenses | 30,186 | 7.2 | % | 33,382 | 7.1 | % | 31,318 | 7.0 | % | |||||||||
Depreciation & amortization | 54,838 | 13.1 | % | 50,997 | 10.8 | % | 39,660 | 8.9 | % | |||||||||
Operating income | 10,772 | 2.6 | % | 33,533 | 7.1 | % | 39,498 | 8.9 | % | |||||||||
Gain (loss) on early extinguishment of debt | — | — | % | — | — | % | (35,415 | ) | (7.9 | )% | ||||||||
Interest and other expenses | (28,184 | ) | (6.7 | )% | (27,955 | ) | (5.9 | )% | (27,329 | ) | (6.1 | )% | ||||||
Income (loss) from continuing operations before taxes | (17,412 | ) | (4.1 | )% | 5,578 | 1.2 | % | (23,246 | ) | (5.2 | )% | |||||||
Income tax (benefit) expense | (4,615 | ) | (1.1 | )% | 3,359 | 0.7 | % | (4,677 | ) | (1.0 | )% | |||||||
Income (loss) from continuing operations | (12,797 | ) | (3.0 | )% | 2,219 | 0.5 | % | (18,569 | ) | (4.2 | )% | |||||||
Income (loss) from discontinued operations, net of tax expense (benefit) of ($200), ($400) and $6,300, respectively | (293 | ) | (0.1 | )% | (633 | ) | (0.1 | )% | 6,224 | 1.4 | % | |||||||
Net income (loss) | $ | (13,090 | ) | (3.1 | )% | $ | 1,586 | 0.3 | % | $ | (12,345 | ) | (2.8 | )% |
Comparison of Years Ended December 31, 2013 and December 31, 2012
Revenues — For the year ended December 31, 2013, revenues decreased by $52.7 million, or 11.1%, to $419.9 million when compared to the same period in the prior year. This is a direct result of decreases in our utilization primarily for the Fluid Logistics division in 2013 as compared to 2012.
Operating Expenses — Our operating expenses decreased to $324.1 million for the year ended December 31, 2013, from $354.7 million for the year ended December 31, 2012, a decrease of $30.5 million or 8.6%. This decrease in operating expense is generally attributable to the decrease in fluid logistics trucking hours which reduced the labor and fuel expenses in that division. Operating expenses as a percentage of revenues were 77.2% and 75.1% for the years ended December 31, 2013 and December 31, 2012, respectively.
General and Administrative Expenses — General and administrative expenses from the consolidated operations decreased by approximately $3.2 million, or 9.6%, to $30.2 million. General and administrative expense as a percentage of revenues were 7.2% and 7.1% for the years ended December 31, 2013 and 2012, respectively. This change of $3.2 million was primarily due to decreases in professional fees and compensation expense.
Depreciation and Amortization — Depreciation and amortization expenses increased by $3.8 million, or 7.5%, to $54.8 million. The increase is related to our increase in capital expenditures in 2012 which increased depreciation in 2013 as these assets begin to have full impact on depreciation, as well as the capital additions in 2013.
Interest and Other Expenses—Interest and other expenses were $28.2 million in the year ended December 31, 2013, compared to $28.0 million in the year ended December 31, 2012, an increase of $0.2 million, or 0.8% due to an increase in our debt obligations.
Income Taxes — Our income tax benefit on continuing operations was $4.6 million (26.5% effective rate) on a pre-tax loss of $17.4 million for the year ended December 31, 2013, compared to an income tax expense of $3.4 million (60.2% effective rate) on pre-tax income of $5.6 million in 2012. This difference was mainly due to change in state taxes, certain non-deductible expenses and a revision in the tax basis of certain property and equipment.
Discontinued Operations — We recorded a net loss from discontinued operations of $0.3 million for the year ended December 31, 2013, compared to net loss from discontinued operations of $0.6 million for the year ended December 31, 2012. The decrease in net loss relates the winding down of our operations in Mexico.
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Comparison of Years Ended December 31, 2012 and December 31, 2011
Revenues — For the year ended December 31, 2012, revenues increased by $26.8 million, or 6.0%, to $472.6 million when compared to the same period in the prior year. This is a direct result of slight increases in our utilization and pricing in 2012 as compared to 2011.
Operating Expenses — Our operating expenses increased to $354.7 million for the year ended December 31, 2012, from $335.3 million for the year ended December 31, 2011, an increase of $19.4 million or 5.8%. This increase in operating expense is generally attributable to the increase in labor expenses offset by the decreases in rental equipment due to the purchase of new equipment to satisfy customer demand. Operating expenses as a percentage of revenues were 75.1% and 75.2% for the years ended December 31, 2012 and December 31, 2011, respectively.
General and Administrative Expenses — General and administrative expenses from the consolidated operations increased by approximately $2.1 million, or 6.6%, to $33.4 million. General and administrative expense as a percentage of revenues were 7.1% and 7.0% for the years ended December 31, 2012 and 2011, respectively. This change of $2.1 million was comprised of the following: $5.7 million related to additional compensation expense related to a workforce increase of 53 employees and increased pay rates, $0.5 million of discretionary management bonuses, $1.1 million of additional expense related to a newly implemented, performance based, management bonus plan, $1.7 million of stock based compensation expense due to the issuance of stock options in 2011, restricted stock, and restricted stock units to middle management issued in 2012, and an increase of $0.5 million in professional fees related to an information technology audit and changes in controls for Sarbanes-Oxley information technology compliance. The increases in these expenses were off-set in part by a decrease in litigation, settlement, and legal fees of $7.5 million.
Depreciation and Amortization — Depreciation and amortization expenses increased by $11.3 million, or 28.6%, to $51.0 million. The increase is related to our increase in capital expenditures. Capital expenditures incurred for the year ended December 31, 2012 were $111.9 million compared to $62.7 million for the year ended December 31, 2011.
Interest and Other Expenses—Interest and other expenses, excluding the loss on early extinguishment of debt, were $28.0 million in the year ended December 31, 2012, compared to $27.3 million in the year ended December 31, 2011, an increase of $0.6 million, or 2.3% due to an increase in our debt obligations. The loss of $35.4 million on early extinguishment of debt in the year ended December 31, 2011 was due to the retirement of the First and Second Priority Notes and was comprised of premium on early redemption of the First Priority Notes of $0.6 million, total unamortized deferred financing charges written off in connection with the redemption of First and Second Priority notes of $10.4 million and tender purchase price premium and consent fee related to the Second Priority Notes of $24.4 million.
Income Taxes — Our income tax expense on continuing operations was $3.4 million (60.2% effective rate) on pre-tax income of $5.6 million for the year ended December 31, 2012, compared to an income tax benefit of $4.7 million (20.1% effective rate) on a pre-tax loss of $23.2 million in 2011. This difference was mainly due to state franchise taxes which are calculated based on taxable gross margins and certain non deductible expenses.
Discontinued Operations — We recorded a net loss from discontinued operations of $0.6 million for the year ended December 31, 2012, compared to net income from discontinued operations of $6.2 million for the year ended December 31, 2011. The decrease in net income relates to salaries paid during the winding down of our operations in Mexico and an adjustment for the foreign currency translation that was expensed upon substantial liquidation of our operations in Mexico.
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Well Servicing
Year Ended December 31, | ||||||||||||||||||
2013 | % of Revenue | 2012 | % of Revenue | 2011 | % of Revenue | |||||||||||||
(Dollars in Thousands) | ||||||||||||||||||
Revenue | $ | 231,930 | 100.0 | % | $ | 202,670 | 100.0 | % | $ | 177,896 | 100.0 | % | ||||||
Direct operating costs | 182,180 | 78.5 | % | 158,302 | 78.1 | % | 141,589 | 79.6 | % | |||||||||
Segment profits | $ | 49,750 | 21.5 | % | $ | 44,368 | 21.9 | % | $ | 36,307 | 20.4 | % |
Results for 2013 compared to 2012 - Well Servicing
Revenues - Revenues from the well servicing segment increased by $29.3 million for the year, or 14.4% to $231.9 million compared to the prior year. Of this increase, approximately 92.5% was due to increased rig rates and 7.5% was due to increased rig hours billed for well service. We made available for utilization 167 and 162 well service rigs as of December 31, 2013 and 2012, respectively. The average rate charged per hour for our well servicing rigs during the year ended December 31, 2013 as compared to the same period in 2012 increased approximately 13.2%. Average utilization of our well service rigs during the year-ended December 31, 2013 and 2012 was 86.5% and 88.3%, respectively, calculated by comparing actual hours billed to theoretical full utilization which we based on a twelve hour day, working five days a week, except U.S. holidays. The decrease in utilization was primarily due to the addition of 5 new rigs which increased available hours by approximately 3%.
Direct Operating Costs - Direct operating costs from the well servicing segment increased by $23.9 million, or 15.1%, to $182.2 million. Well servicing direct operating costs as a percentage of well servicing revenues were 78.5% for the year ended December 31, 2013, compared to 78.1% for the year ended December 31, 2012, an increase of 0.4%.
The dollar increase in well servicing direct operating costs between the two years was due to in large part to the increase in labor costs of $8.6 million or 12.0% for the year ended December 31, 2013 compared to the prior year due to the higher headcount during 2013 and increased pay rates. The employee count in our well servicing segment at December 31, 2013 was 1,224, compared to 1,069 employees as of December 31, 2012. Labor costs as a percentage of revenue were 34.4% and 35.1% for the years ended December 31, 2013 and 2012, respectively. Parts and Supplies increased by $4.1 million to $11.1 million due to the additional parts required to service coil tubing equipment which was added during the last half of 2012 and into 2013. Equipment rental increased by approximately $4.1 million to $7.9 million in for the year ended December 31, 2013. The increase was due to the addition of leased coil tubing equipment. Insurance expense increased by $3.1 million or 33.1% due to increases of $1.9 million in general liability and auto insurance and an increase of $1.1 million in workers compensation insurance due to increased employee count. Fuel costs as of percentage of revenue were 7.2% and 7.3% for the years ended December 31, 2013 and 2012, respectively.
Results for 2012 compared to 2011 - Well Servicing
Revenues - Revenues from the well servicing segment increased by $24.8 million for the year, or 13.9% to $202.7 million compared to the prior year. Of this increase, approximately 36.2% was due to increased prices and 63.8% was due to increased rig hours for well services. We utilized 162 and 159 well service rigs as of December 31, 2012 and 2011. The average rate charged per hour during the year-ended December 31, 2012 as compared to the same period in 2011 increased approximately 3.1%. Average utilization of our well service rigs during the year-ended December 31, 2012 and 2011 was 88.3% and 84.9%, respectively, based on a twelve hour day, working five days a week, except holidays in the U.S.
Direct Operating Costs - Direct operating costs from the well servicing segment increased by $16.7 million, or 11.8%, to $158.3 million. Well servicing direct operating costs as a percentage of well servicing revenues were 78.1% for the year ended December 31, 2012, compared to 79.6% for the year ended December 31, 2011, a decrease of 1.5%. This decrease in direct operating costs as a percentage of revenue was due to an increase in utilization to 88.3% for the year ended December 31, 2012 from 84.9% for the year ended December 31, 2011, which allowed the Company to spread its fixed costs over greater revenues, thereby increasing the gross margin. This increase in utilization consisted of 63.8% of the change. The remaining 36.2% was due to price increases of approximately 3.1% in average billing rates between the two years.
The dollar increase in well servicing direct operating costs between the two years was due in large part to the increase in labor costs of $11.1 million or 16.2% for the year ended December 31, 2012 compared to the prior year due to the higher headcount during the first half of 2012 and increased pay rates. The employee count at December 31, 2012 was 1,069
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compared to 1,051 employees as of December 31, 2011. Labor costs as a percentage of revenue were 38.2% and 37.4% for the years ended December 31, 2012 and 2011, respectively. Rig hours increased 5.9% for the year ended December 31, 2012 compared to 2011, which was the main reason fuel costs increased $3.9 million, a 35.1% increase. Fuel costs as a percentage of revenue were 7.3% and 6.2% for the years ended December 31, 2012 and 2011. Contract labor cost and insurance cost increased by $2.4 million and $2.2 million, respectively. These cost increases were offset by a reduction in repairs and maintenance expense of $2.8 million. The repairs and maintenance cost was higher than normal in the prior year due to the increased activity in 2011 compared to 2012 and the need to prepare the rigs to place into service.
Fluid Logistics
Year Ended December 31, | ||||||||||||||||||
2013 | % of Revenue | 2012 | % of Revenue | 2011 | % of Revenue | |||||||||||||
(Dollars in Thousands) | ||||||||||||||||||
Revenue | $ | 188,003 | 100.0 | % | $ | 269,927 | 100.0 | % | $ | 267,887 | 100.0 | % | ||||||
Direct operating costs | 141,957 | 75.5 | % | 196,383 | 72.8 | % | 193,718 | 72.3 | % | |||||||||
Segment profit | $ | 46,046 | 24.5 | % | $ | 73,544 | 27.2 | % | $ | 74,169 | 27.7 | % |
Results for 2013 compared to 2012 - Fluid Logistics
Revenues — Revenues from the fluid logistics segment for the year ended December 31, 2013 decreased by $81.9 million, or 30.4%, to $188.0 million compared to the prior year, driven primarily by a decrease in trucking hours of 29.5%. Utilization and rate decreases resulted, in part, from more efficient drilling processes by our customers and from excess equipment in our markets, which has resulted in certain lost customer opportunities. Our principal fluid logistics assets at December 31, 2013 and December 31, 2012 were as follows:
December 31, | % Increase (decrease) | ||||||||
Asset | 2013 | 2012 | |||||||
Vacuum trucks | 480 | 473 | 1.5 | ||||||
High-pressure pump trucks | 22 | 20 | 10.0 | ||||||
Hot oil trucks | 5 | 1 | 400.0 | ||||||
Other heavy trucks | 84 | 84 | — | ||||||
Frac tanks (includes leased) | 2,997 | 3,112 | (3.7 | ) | |||||
Fluid mixing tanks | 274 | 96 | 185.4 | ||||||
Salt water disposal wells | 24 | 24 | — |
Direct Operating Costs — Direct operating costs from the fluid logistics segment decreased by $54.4 million, or 27.7%, to $142.0 million. Fluid logistics operating expenses as a percentage of fluid logistics revenue were 75.5% for the year ended December 31, 2013, compared to 72.8% for the year ended December 31, 2012.
The decrease in fluid logistics direct operating costs of $54.4 million was due primarily to a decrease in trucking hours in the fluid logistics segment which caused operating labor, fuel and other variable operating expenses to decrease. The decrease in direct operating costs was generally in line with the decrease in revenue. The majority of the decrease was due to the following: Decrease in labor cost of $14.8 million, or 21.2%, for the year-ended December 31, 2013, when compared to the same period in the prior year; A decrease in the employee count to 1,006 from 1,203 at December 31, 2013 and December 31, 2012, respectively; a decrease in fuel and oil expense of $9.4 million to $24.4 million for the year ended December 31, 2013 as compared to the same period in the prior year; a decrease in contract services from prior year by $7.4 million or 75.9% to $2.3 million; a decrease in rent equipment from prior period by $7.0 million or 44.2% to $8.8 million; a decrease in repairs and maintenance from prior period by $6.8 million or 27.9% to $17.7 million; a decrease in other operating expenses in line with revenues to make up the remainder of the $54.4 million decrease.
Results for 2012 compared to 2011 - Fluid Logistics
Revenue — Revenues from the fluid logistics segment for the year ended December 31, 2012 increased by $2.0 million, or 0.8%, to $269.9 million compared to the prior year, as a result of an increase in trucking hours of 5.2%. There was a decrease in utilization to 77.0% for the year ended December 31, 2012 as compared to 102.2% for the year ended
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December 31, 2011 primarily due to our increase in the number of available trucks. Our principal fluid logistics assets at December 31, 2012 and December 31, 2011 were as follows:
Years Ended December 31, | % Increase (decrease) | ||||||||
Asset | 2012 | 2011 | |||||||
Vacuum trucks | 473 | 408 | 15.9 | ||||||
High-pressure pump trucks | 20 | 21 | (4.8 | ) | |||||
Hot oil trucks | 1 | — | 100.0 | ||||||
Other heavy trucks | 84 | 67 | 25.4 | ||||||
Frac tanks (includes leased) | 3,112 | 1,879 | 65.6 | ||||||
Fluid mixing tanks | 96 | — | 100.0 | ||||||
Salt water disposal wells | 24 | 17 | 41.2 |
Direct operating costs — Direct operating costs from the fluid logistics segment increased by $2.7 million, or 1.4%, to $196.4 million. Fluid logistics direct operating costs as a percentage of fluid logistics revenue were 72.8% for the year ended December 31, 2012, compared to 72.3% for the year ended December 31, 2011.
The increase in fluid logistics direct operating costs of $2.7 million was due to an increase in labor cost of $13.0 million, or 25.6%, for the year-ended December 31, 2012, when compared to the same period in the prior year. The employee count at December 31, 2012 was 1,203, as compared with 1,073 employees as of December 31, 2011. This cost increase was off-set by a reduction in equipment rental of $6.5 million, or 29%, for the year-ended December 31, 2012, when compared to the same period in the prior year. The decrease in equipment rental was due to the acquisition of additional equipment to satisfy customer demand and decreasing the need to utilize outside services. The cost for product and chemical decreased by $3.8 million, or 35.9% as a result of lower utilization for the year-ended December 31, 2012. The remaining $0.1 million change is related to various expenses that were consistent with management's expectation.
Liquidity and Capital Resources
Overview
In June 2011, we issued $280.0 million aggregate principal amount of 9% Senior Notes and received net proceeds of $273.7 million. We used a substantial portion of the proceeds from such offering to purchase or redeem all outstanding Second Priority Notes and First Priority Notes.
On September 9, 2011, we entered into a loan and security agreement with certain lenders and Regions Bank, as agent for the secured parties, or the Agent. This loan and security agreement was amended, in December 2011, July 2012 and July 2013. The loan and security agreement initially provided for an asset based revolving credit facility with a maximum initial credit of $75.0 million, subject to, borrowing base availability and other limitations. The third amendment increased the maximum borrowing credit to $90.0 million, subject to borrowing base availability, any reserves established by the facility agent in its discretion, compliance with a fixed charge coverage ratio covenant if availability under the facility falls below certain thresholds and, for borrowings above $75.0 million, compliance with the debt incurrence covenant in the indenture governing the 9% Senior Notes. This indenture covenant prohibits the incurrence of debt except for certain limited exceptions, including indebtedness incurred under the permitted credit facility debt basket to the greater of $75.0 million or 18% of our Consolidated Tangible Assets (as defined in the indenture governing the 9% Senior Notes) reported for the last fiscal quarter for which financial statements are available. Under the indenture governing the 9% Senior Notes, Consolidated Tangible Assets is defined as our total assets, determined on a consolidated basis in accordance with GAAP, excluding unamortized debt discount and expenses and other unamortized deferred charges, to the extent such items are non-cash expenses or charges, goodwill, patents, trademarks, service marks, trade names, copyrights and other items properly classified as intangibles in accordance with GAAP. As of December 31, 2013, 18% of our Consolidated Tangible Assets was approximately $84.3 million. If our availability under the credit facility dropped below 15% of our total borrowing credit (as described above), we are required to maintain a trailing four-quarter fixed charge coverage ratio of 1.1 to 1. We would currently be in compliance with this covenant if it were applicable.
As of December 31, 2013, there were no amounts drawn and $5.9 million in outstanding letters of credit posted to the facility.
A downturn could require us to seek funding to meet working capital requirements. Further, should management elect to incur capital expenditures in excess of the levels projected for 2014 or to pursue other capital intensive activities, additional
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capital may be required to fund these activities. As discussed in more detail below, our ability to seek additional financing may be restricted by certain of our debt covenants.
The indenture governing the 9% Senior Notes and the loan agreement governing our senior secured revolving credit facility impose significant restrictions on us and increase our vulnerability to adverse economic and industry conditions that could limit our ability to obtain additional or replacement financing. For example, the indenture governing the 9% Senior Notes only allows us to incur indebtedness, other than certain specific types of permitted indebtedness, if such indebtedness is unsecured and if the Fixed Charge Coverage Ratio (as defined in the indenture) for the most recently completed four full fiscal quarters is at least 2.0 to 1.0. We are currently able to incur indebtedness under this ratio. Our credit facility only allows us to incur specific types of permitted indebtedness, which includes a $40 million basket of permitted indebtedness for capital leases, mortgage financings or purchase money obligations incurred for the purpose of installation or improvement of property, plant, and equipment.
Our inability to satisfy our obligations under the indenture governing the 9% Senior Notes, the loan agreement governing our credit facility, and any future debt agreements we may enter into could constitute an event of default under one or more of such agreements. Further, due to cross-default provisions in our debt agreements, a default and acceleration of our outstanding debt under one debt agreement may result in the default and acceleration of outstanding debt under the other debt agreements. Accordingly, an event of default could result in all or a portion of our outstanding debt becoming immediately due and payable. If this should occur, we might not be able to obtain waivers or secure alternative financing to satisfy all of our obligations simultaneously. Our ability to access the capital markets or to consummate any asset sales might be restricted at a time when we would like or need to raise capital. These events could have a material adverse effect on our business, financial position, results of operations and cash flows, and our ability to satisfy our obligations.
Within certain constraints, we can conserve capital by reducing or delaying capital expenditures, deferring non-regulatory maintenance expenditures, and further reducing operating and administrative costs.
We have historically funded our operations, including capital expenditures, with bank borrowings, vendor financings, cash flow from operations, the issuance of our senior notes, and the proceeds from our May 2008 Canadian initial public equity offering and simultaneous U.S. private placement, our October 2008 and December 2009 common stock offerings, and our May 2010 Series B Preferred Stock private placement.
As of December 31, 2013, we had $26.4 million in cash and cash equivalents, $299.6 million in contractual debt and capital leases, and $4.1 million of accounts payable related to equipment. Also, as of December 31, 2013, we had 588,059 outstanding shares of Series B Senior Convertible Preferred Stock which is reflected in the balance sheet as temporary equity in an amount of $14.6 million. During periods when the Company’s common stock maintains a five day volume weighted average trading price above $3.33 per share, the Series B Preferred Stock is redeemable, in whole or in part, at the Company’s option for a price of $25 per share, plus accrued and unpaid dividends. Nevertheless, if the Company elects to redeem the Series B Preferred Stock, the holders thereof would have the opportunity prior to redemption to convert each share of Series B Preferred Stock into nine shares of common stock. On May 28, 2017, the Company is required to redeem the Series B Preferred Stock at 95% of the fair market value of the common stock as determined in accordance with the certificate of designation of the Series B Preferred Stock.
The $299.6 million in contractual debt was comprised of $280.0 million in senior notes and $19.6 million in capital leases on equipment and insurance notes. Of our total debt, $290.3 million of the outstanding contractual debt was represented by long-term debt and $9.4 million was short-term debt outstanding or the current portion of long-term debt. In addition, we have $4.1 million of non-interest bearing short-term equipment vendor financings for well servicing rigs and other equipment included in accounts payable. The $19.6 million in equipment and insurance notes consisted of $15.1 million in equipment notes and $4.5 million in insurance notes related to our general liability, workers compensation and other insurances.
We project that cash flows from operations will be adequate to meet our working capital requirements over the next twelve months.
Cash Flows
Our cash flows depend, to a large degree, on the level of spending by oil and gas companies’ development and production activities. Sustained increases or decreases in the price of natural gas or oil could have a material impact on these activities, and could also materially affect our cash flows. Certain sources and uses of cash, such as the level of discretionary capital expenditures, purchases and sales of investments, issuances and repurchases of debt and of our common shares are within our control and are adjusted as necessary based on market conditions.
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Cash Flows from Operating Activities
Net cash provided by operating activities totaled $56.3 million for the year ended December 31, 2013, compared to $68.4 million for the year ended December 31, 2012, an decrease of $12.1 million. The most significant change between the years ended December 31, 2013 and 2012 related to the net loss in 2013 as opposed to a net income in 2012. Other changes included a decrease in accounts receivable of $32.8 million offset by an increase in accounts payable of $25.8 million and an increase in accrued expenses of $8.7 million . These changes are due to the decrease in revenues in the year ended December 31, 2013 compared to 2012 resulting in the net loss of $13.1 million for the year ended December 31, 2013.
Net cash provided by operating activities totaled $68.4 million for the year ended December 31, 2012, compared to $6.0 million for the year ended December 31, 2011, an increase of $62.4 million. The most significant change between the years ended December 31, 2012 and 2011 related to an increase in cash flows from a decrease in accounts receivable in the amount of $93.4 million. This resulted from collecting our Mexico accounts receivable in 2012 as we closed the operation and from the slowdown in industry activity in the last half of 2012. These changes in cash inflows, related to an increase in collection of accounts receivable, were offset partially by additional cash outflows in the amount of $39.7 million used to decrease our accounts payable. As with our accounts receivable change, this accounts payable decrease was consistent with our Mexico sale and industry activity moderation.
Cash Flows Used in Investing Activities
Net cash used in investing activities for the year ended December 31, 2013 amounted to $41.0 million compared to $82.6 million from the year ended December 31, 2012, a decrease of $41.6 million. This $41.6 million decrease resulted from a decrease in capital spending for 2013 compared to 2012.
Net cash used in investing activities for the year ended December 31, 2012 amounted to $82.6 million compared to $50.9 million from the year ended December 31, 2011, an increase of $31.7 million. This $31.7 million increase resulted from an increase of $53.4 million used for the purchases of property and equipment and a decrease in deposit on assets held for sale of $13.7 million. These cash uses were offset, in part, by proceeds from the sale of equipment of $14.7 million and the release of restricted cash from the sale of the assets of our operations in Mexico of $21.8 million.
Cash Flows from Financing Activities
Net cash used in financing activities amounted to $6.5 million for the year ended December 31, 2013, compared to net cash used in financing activities of $5.3 million for the year ended December 31, 2012. The increase in cash used in financing activities was primarily caused by payments of debt and increased debt issuance costs related to the renewal and extension of the revolving credit facility which was done during 2013.
Net cash used in financing activities amounted to $5.3 million for the year ended December 31, 2012, compared to net cash provided by financing activities of $52.1 million for the year ended December 31, 2011. The majority of the change related to the Forbes Group receiving $280.0 million in proceeds from the issuance of 9% Senior Notes Payable, less debt issuance costs of $10.2 million in the prior year. The proceeds were used to retire $212.5 million in First and Second Priority Notes. The primary use of cash flows from financing activities in 2012 was for scheduled payments on equipment installment notes in the amount of $4.5 million.
Cash Flows from Discontinued Operations
The cash flows from discontinued operations have not been separately disclosed in our consolidated statements of cash flows for the years ended December 31, 2013, 2012 and 2011. The net cash flow used in our discontinued operations was approximately $6.7 million for the year ended December 31, 2012 compared to net cash provided of $4.2 million for the year ended December 31, 2011. Cash flows from discontinued operations were not significant in 2013.
9% Senior Notes
On June 7, 2011, FES Ltd. issued $280.0 million in principal amount of 9% Senior Notes due 2019 (the “9% Senior Notes”). The proceeds of the 9% Senior Notes were used to purchase and/or redeem 100% of the First Priority Notes and the outstanding Second Priority Notes issued by Forbes Energy Services LLC and Forbes Energy Capital Inc. The 9% Senior Notes mature on June 15, 2019, and require semi-annual interest payments, in arrears, commencing December 15, 2011 at an annual rate of 9%, payable on June 15 and December 15 of each year until maturity. No principal payments are due until maturity.
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The 9% Senior Notes are guaranteed by the current domestic subsidiaries (the “Guarantor Subs”) of FES Ltd., which includes FES LLC, CCF, TES, STT and FEI LLC (but excludes Forbes Energy Capital Inc., which was dissolved in November 2011). All of the Guarantor Subs are 100% owned and each guarantees the securities on a full and unconditional and joint and several basis, subject to customary release provisions. Prior to January 12, 2012, FES Ltd had two 100% owned indirect Mexican subsidiaries or the Non-Guarantor Subs that had not guaranteed the 9% Senior Notes. In January 2012, one of those two Mexican subsidiaries was sold along with the business and substantially all of our assets located in Mexico. Prior to January 12, 2012, FES Ltd had a branch office in Mexico and conducted operations independent of the Non-Guarantor Subs. The Guarantor Subs represent the substantial majority of the Company’s operations. On or after June 15, 2015, the Forbes Group may, at its option, redeem all or part of the 9% Senior Notes from time to time at specified redemption prices and subject to certain conditions required by the indenture governing the 9% Senior Notes (the “9% Senior Indenture”). The Forbes Group is required to make an offer to purchase the notes and to repurchase any notes for which the offer is accepted at 101% of their principal amount, plus accrued and unpaid interest, if there is a change of control. The Forbes Group is required to make an offer to repurchase the notes and to repurchase any notes for which the offer is accepted at 100% of their principal amount, plus accrued and unpaid interest, following certain asset sales.
The Forbes Group is permitted under the terms of the 9% Senior Indenture to incur additional indebtedness in the future, provided that certain financial conditions set forth in the 9% Senior Indenture are satisfied. The Forbes Group is subject to certain covenants contained in the 9% Senior Indenture, including provisions that limit or restrict the Forbes Group’s and certain future subsidiaries’ abilities to incur additional debt, to create, incur or permit to exist certain liens on assets, to make certain dispositions of assets, to make payments on certain subordinated indebtedness, to pay dividends or certain other payments to equity holders, to engage in mergers, consolidations or other fundamental changes, to change the nature of its business or to engage in transactions with affiliates. Due to cross-default provisions in the indenture governing our 9% Senior Notes and the loan agreement governing our revolving credit facility, with certain exceptions, a default and acceleration of outstanding debt under one debt agreement would result in the default and possible acceleration of outstanding debt under the other debt agreement. Accordingly, an event of default could result in all or a portion of our outstanding debt under our debt agreements becoming immediately due and payable. If this occurred, we might not be able to obtain waivers or secure alternative financing to satisfy all of our obligations simultaneously, which would adversely affect our business and operations.
Details of two of the more significant restrictive covenants in the 9% Senior Indenture are set forth below:
• | Limitation on the Incurrence of Additional Debt - In addition to certain indebtedness defined in the 9% Senior Indenture as "Permitted Debt," which includes indebtedness under any credit facility not to exceed the greater of $75.0 million or 18% of the Company's Consolidated Tangible Assets (as defined in the 9% Senior Indenture), we may only incur additional debt if the Fixed Charge Coverage Ratio (as defined in the 9% Senior Indenture) for the most recently completed four full fiscal quarters is at least 2.0 to 1.0. |
• | Limitation on Restricted Payments - Subject to certain limited exceptions, including specific permission to pay cash dividends on the Company's Series B Senior Convertible Preferred Stock up to $260,000 per quarter, the Company is prohibited from (i) declaring or paying dividends or other distributions on its equity securities (other than dividends or distributions payable in equity securities), (ii) purchasing or redeeming any of the Company's equity securities, (iii) making any payment on indebtedness contractually subordinated to the 9% Senior Notes, except a payment of interest or principal at the stated maturity thereof, or (iv) making any investment defined as a "Restricted Investment," unless, at the time of and after giving effect to such payment, the Company is not in default and the Company is able to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio (as defined in the 9% Senior Indenture). Further, the amount of such payment plus all other such payments made by the Company since the issuance of the 9% Senior Notes must be less than the aggregate of (a) 50% of Consolidated Net Income (as defined in the 9% Senior Indenture) since the April 1, 2011 (or 100%, if such figure is a deficit), (b) 100% of the aggregate net cash proceeds from equity offerings since the issuance of the 9% Senior Notes, (c) if any Restricted Investments have been sold for cash, the proceeds from such sale (or the original cash investment if that amount is lower); and (d) 50% of any dividends received by the Company. |
The Company is in compliance with the covenants under the indenture governing the 9% Senior Notes at December 31, 2013.
Revolving Credit Facility
On September 9, 2011, FES Ltd. and its current domestic subsidiaries entered into a loan and security agreement with Regions Bank, SunTrust Bank, CIT Bank and Capital One Leverage Finance Corp., as lenders, and Regions Bank, as agent for the secured parties, or the Agent. This loan and security agreement was amended in December 2011, July 2012 and July 2013. Pursuant to the July 2013 amendment, the CIT Bank opted out of the lending group, with Regions Bank increasing its
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participating by taking CIT Bank's position. The loan and security agreement initially provided for an asset based revolving credit facility with a maximum initial borrowing credit of $75.0 million, subject to borrowing base availability and other limitations. The third amendment increased the maximum borrowing credit to $90.0 million, subject to borrowing base availability, any reserves established by the facility agent in its discretion, compliance with a fixed charge coverage ratio covenant if availability under the facility falls below certain thresholds and, for borrowings above $75.0 million, compliance with the debt incurrence covenant in the indenture governing the 9% Senior Notes. This indenture covenant prohibits the incurrence of debt except for certain limited exceptions, including indebtedness incurred under the permitted credit facility debt basket to the greater of $75.0 million or 18% of our Consolidated Tangible Assets (as defined int he 9% Senior Indenture) reported for the last fiscal quarter for which financial statements are available. Under the 9% Senior Indenture, Consolidated Tangible Assets is defined as our total assets, determined on a consolidated basis in accordance with GAAP, excluding unamortized debt discount and expenses and other unamortized deferred charges, to the extent such items are non-cash expenses or charges, goodwill, patents, trademarks, service marks, trade names, copyrights and other items properly classified as intangibles in accordance with GAAP. As of December 31, 2013, 18% of our Consolidated Tangible Assets was approximately $84.3 million. If our availability under the credit facility dropped below 15% of our total borrowing credit (as described above), we are required to maintain a trailing four-quarter fixed charge coverage ratio of at least 1.1 to 1. We would be currently in compliance with this covenant if it were applicable.
As of December 31, 2013, there were no amounts drawn and outstanding letters of credit in the amount of $5.9 million posted under the facility. Taking into account the limitations discussed above, we believe we have at least $78.4 million of availability under our credit facility. As amended, the loan and security agreement has a stated maturity of July 26, 2018. The proceeds of this credit facility can be used for the purchase of well services equipment, permitted acquisitions, general operations, working capital and other general corporate purposes.
Under the loan and security agreement, our borrowing base at any time is equal to (i) 85% of eligible accounts, which are determined by Agent in its reasonable discretion, plus (ii) the lesser of 85% of the appraised value, subject to certain adjustments, of our well services equipment that has been properly pledged and appraised, is in good operating condition and is located in the United States, or 100% of the net book value of such equipment, minus (iii) any reserves established by the Agent in its reasonable discretion.
Prior to the third amendment, at our option, borrowings under this credit facility would have borne interest at a rate equal to either (i) the LIBOR rate plus an applicable margin of between 2.25% to 2.75% based on borrowing availability or (ii) a base rate plus an applicable margin of between 1.25% to 1.75% based on borrowing availability, where the base rate was equal to the greater of the prime rate established by Regions Bank, the overnight federal funds rate plus 0.50% or the LIBOR rate for a one month period plus 1.00%. The third amendment decreased the revolving interest rate whereby borrowings under the Loan Agreement will bear interest at a rate equal to either (a) the LIBOR rate plus an applicable margin of between 2.00% to 2.50% based on borrowing availability or (b) a base rate plus an applicable margin of between 1.00% to 1.50% based on borrowing availability, where the base rate is equal to the greater of the prime rate established by Regions Bank, the overnight federal funds rate plus 0.5% or the LIBOR rate for a one month period plus 1%.
In addition to paying interest on outstanding principal under the facility, a fee of 0.375% per annum will accrue on unutilized availability under the credit facility. We are required to pay a fee of between 2.25% to 2.75%, based on borrowing availability, with respect to the principal amount of any letters of credit outstanding under the facility. We are also responsible for certain other administrative fees and expenses.
FES LLC, FEI LLC, TES, CCF and STT are the borrowers under the loan and security agreement. Their obligations have been guaranteed by one another and by FES Ltd. Subject to certain exceptions and permitted encumbrances, including the exemption of real property interests from the collateral package, the obligations under this facility are secured by a first priority security interest in all of our assets.
We are able to voluntarily repay outstanding loans at any time without premium or penalty (subject to the fees discussed above). If at anytime our outstanding loans under the credit facility exceed the availability under our borrowing base, we may be required to repay the excess. Further, we are required to use the net proceeds from certain events, including certain judgments, tax refunds or insurance awards to repay outstanding loans; however, we may reborrow following such repayments if the conditions to borrowing are met.
The loan and security agreement contains customary covenants for an asset-based credit facility, which include (i) restrictions on certain mergers, consolidations and sales of assets; (ii) restrictions on the creation or existence of liens; (iii) restrictions on making certain investments; (iv) restrictions on the incurrence or existence of indebtedness; (v) restrictions on transactions with affiliates; (vi) requirements to deliver financial statements, report and notices to the Agent and (vii) a springing requirement to maintain a consolidated Fixed Charge Coverage Ratio (which is defined in the loan and security
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agreement) of 1.1:1.0 in the event that our excess availability under the credit facility falls below the greater of $11.3 million or 15.0% of our maximum credit under the facility for sixty consecutive days; provided that, the restrictions described in (i)—(v) above are subject to certain exceptions and permissions limited in scope and dollar value. The loan and security agreement also contains customary representations and warranties and event of default provisions. As of December 31, 2013 we are in compliace with all covenants in the loan and security agreement.
Contractual Obligations and Financing
The table below provides estimated timing of future payments for which we were obligated as of December 31, 2013.
Actual | Total | Less than 1 Year | 1-3 Years | 3-4 Years | More than 5 Years | ||||||||||||||
(dollars in thousands) | |||||||||||||||||||
Maturities of long-term debt, including current portion, excluding capital lease obligations | $ | 284,531 | $ | 4,531 | $ | — | $ | — | $ | 280,000 | |||||||||
Capital lease obligations | 15,109 | 4,843 | 8,114 | 2,054 | 98 | ||||||||||||||
Operating lease commitments | 34,958 | 14,309 | 18,390 | 2,259 | — | ||||||||||||||
Interest on long-term debt | 139,404 | 26,065 | 51,145 | 50,457 | 11,737 | ||||||||||||||
Series B senior preferred stock dividends | 2,511 | 735 | 1,470 | 306 | — | ||||||||||||||
Series B senior preferred stock redemption | 14,700 | — | — | 14,700 | — | ||||||||||||||
Total | $ | 491,213 | $ | 50,483 | $ | 79,119 | $ | 69,776 | $ | 291,835 |
We have obligations to pay to the holders of our Series B Preferred Stock quarterly dividends of five percent per annum of the original issue price, payable in cash or in-kind.
The Company sought and received shareholder approval for a pool of Series B Preferred Stock to be issued, should the Company so choose, as in-kind dividends. Further, as opposed to the indentures that governed the First Priority Notes and Second Priority Notes, the indenture governing the 9% Senior Notes specifically allows the payment of cash dividends on the Series B Preferred Stock of up to $260,000 per quarter. Therefore, there are no contractual or stock exchange restrictions on our paying the Series B Preferred Stock dividends in cash or in-kind. The annual dividend payments for the Series B Preferred Stock is approximately $0.7 million. As of February 28, 2014, the Company has paid all required dividends on its Series B Preferred Stock for completed dividend periods.
During periods when the Company’s common stock maintains a five day volume weighted average trading price above $3.33 per share, the Series B Preferred Stock is redeemable, in whole or in part, at the Company’s option for a price of $25 per share, plus accrued and unpaid dividends. Nevertheless, if the Company elects to redeem the Series B Preferred Stock, the holders thereof would have the opportunity prior to redemption to convert each share of Series B Preferred Stock into nine shares of common stock. On May 28, 2017, we are required to redeem any of the shares of Series B Preferred Stock then outstanding. The cost of the redemption at this date will be $14.7 million. Such mandatory redemption may, at our election, be paid in cash or common stock (valued for such purpose at 95% of the then fair market value of the common stock). As of December 31, 2013, we had 588,059 shares of Series B Preferred Stock outstanding. For a discussion of the rights and preferences of the Series B Preferred Stock, see Note 15 to the consolidated financial statements for the year ended December 31, 2013 included herein.
Seasonality
Our operations are impacted by seasonal factors. Historically, our business has been negatively impacted during the winter months due to inclement weather, fewer daylight hours, and holidays. Our well servicing rigs are mobile and we operate a significant number of oilfield vehicles. During periods of heavy snow, ice or rain, we may not be able to move our equipment between locations, thereby reducing our ability to generate rig or truck hours. In addition, the majority of our well servicing rigs work only during daylight hours. In the winter months as daylight time becomes shorter, the amount of time that the well servicing rigs work is shortened, which has a negative impact on total hours worked. Finally, we historically have experienced significant slowdown during the Thanksgiving and Christmas holiday seasons.
Critical Accounting Policies and Estimates
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The preparation of our consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the dates of the financial statements and the reported amounts of revenue and expenses during the applicable reporting periods. On an ongoing basis, management reviews its estimates, particularly those related to depreciation and amortization methods, useful lives and impairment of long-lived assets, and asset retirement obligations, using currently available information. Changes in facts and circumstances may result in revised estimates, and actual results could differ from those estimates.
Estimated Depreciable Lives
A substantial portion of our total assets is comprised of equipment. Each asset included in equipment is recorded at cost and depreciated using the straight-line method, which deducts equal amounts of the cost of such assets from earnings every year over the asset’s estimated economic useful life. As a result of these estimates of economic useful lives, net equipment as of December 31, 2013 totaled $341.9 million, which represented 68.3% of total assets. Depreciation expense for the year ended December 31, 2013 totaled $52.0 million, which represented 16.0% of total operating expenses. Given the significance of equipment to our financial statements, the determination of an asset’s economic useful life is considered to be a critical accounting estimate. The estimated economic useful life is monitored by management to determine its continued appropriateness.
Impairments
Long-lived assets, which include property, equipment, and finite lived intangible assets subject to amortization, comprise a significant amount of our total assets. We review the carrying values of these assets for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. This requires us to make judgments regarding long-term forecasts of future revenues and costs related to the assets subject to review. These forecasts include assumptions related to the rates we bill our customers, equipment utilization, equipment additions, debt borrowings and repayments, staffing levels, pay rates, and other expenses. In turn, these forecasts are uncertain in that they require assumptions about demand for our products and services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period. Given the nature of these evaluations and their application to specific assets and specific times, it is not possible to reasonably quantify the impact of changes in these assumptions. We regularly assess our long-lived assets for impairment and in recent years, have concluded that no such impairment write down was necessary.
Allowance for Doubtful Accounts
The determination of the collectability of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customers’ payment history and current credit worthiness to determine that collectability is reasonably assured, as well as consideration of the overall business climate in which our customers operate. Inherently, these uncertainties require us to make frequent judgments and estimates regarding our customers’ ability to pay amounts due to us in order to determine the appropriate amount of valuation allowances required for doubtful accounts. Provisions for doubtful accounts are recorded when it becomes evident that the customer will not make the required payments at either contractual due dates or in the future. At December 31, 2013 and 2012, allowance for doubtful accounts totaled $4.0 million, or 4.8%, and $2.7 million, or 2.8%, of gross accounts receivable, respectively. The increase in our allowance for doubtful accounts balance between year end 2012 and 2013 resulted from additional allowance being added because certain customers are experiencing cash flow issues. We believe that our allowance for doubtful accounts is adequate to cover potential bad debt losses under current conditions; however, uncertainties regarding changes in the financial condition of our customers, either adverse or positive, could impact the amount and timing of any additional provisions for doubtful accounts that may be required. A five percent change in the allowance for doubtful accounts would have had an impact on income from continuing operations before income taxes of approximately $0.2 million in 2013.
Revenue Recognition
Well Servicing — Well servicing consists primarily of maintenance services, workover services, completion services, plugging and abandonment services, and tubing testing. We price well servicing primarily by the hour of service performed or on occasion, bid/turnkey pricing.
Fluid Logistics — Fluid logistics consists primarily of the sale, transportation, storage, and disposal of fluids used in drilling, production, and maintenance of oil and natural gas wells. We price fluid logistics by the job, by the hour, or by the quantities sold, disposed, or hauled.
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We recognize revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists, and the price is fixed or determinable.
Income Taxes
Our income tax benefit on continuing operations was $4.6 million (26.5% effective rate) on a pre-tax loss of $17.4 million for the year ended December 31, 2013, compared to income tax expense of $3.4 million (60.2% effective rate) on pre-tax income of $5.6 million in 2012. For the years ended December 31, 2013 and 2012, $0.3 million and $0.8 million in state tax expense was recorded and $0.2 million and $0.2 million in current foreign income tax benefit, respectively. The decrease in the effective tax rate is due to the state taxes, certain non deductible expenses and a revision in the tax basis of certain property and equipment. As of December 31, 2013 and 2012, $21.6 million and $26.6 million in deferred U.S. federal income tax liability was reflected in the FES Ltd.’s balance sheet, respectively.
Current and deferred net tax liabilities are recorded in accordance with enacted tax laws and rates. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In determining the need for valuation allowances, we have considered and made judgments and estimates regarding estimated future taxable income and ongoing prudent and feasible tax planning strategies. These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to adjust the valuation allowances for our deferred tax assets.
Deferred taxes have not been recognized on undistributed earnings of foreign subsidiaries since these amounts are not material.
Environmental
We are subject to extensive federal, state, and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge or release of materials into the environment and may require us to remove or mitigate the adverse environmental effects of the disposal or release of petroleum, chemical or other hazardous substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. We believe, on the basis of presently available information, that regulation of known environmental matters will not materially affect our liquidity, capital resources or consolidated financial condition. However, there can be no assurances that future costs and liabilities will not be material.
Recently Issued Accounting Pronouncements
In July 2013, the FASB issued ASU No. 2013-11, “Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exist” (“ASU2013-11”). ASU 2013-11 reduces diversity in practice by providing guidance on the presentation of unrecognized tax benefits and is intended to better reflect the manner in which an entity would settle at the reporting date any additional income taxes that would result from the disallowance of a tax position when net operating loss carryforwards, similar tax losses, or tax credit carryforwards exist. ASU 2013-11 became effective for the Company on January 1, 2014 and the Company does not believe it will have a material impact on the Company's consolidated financial statements.
Impact of Inflation on Operations
We are of the opinion that inflation has not had a significant impact on our business.
Off-Balance Sheet Arrangements
We are often party to certain transactions that require off-balance sheet arrangements such as performance bonds, guarantees, operating leases for equipment, and bank guarantees that are not reflected in our consolidated balance sheets. These arrangements are made in our normal course of business and they are not reasonably likely to have a current or future material adverse effect on our financial condition, results of operations, liquidity, or cash flows.
Prior to January 12, 2012, we had an arrangement in Mexico that allowed us to work jointly with a Mexican company to service PEMEX. In order to complete many of our projects there, the associate company did site preparation work and we did the well service work. Under mutual agreement, we were responsible for 70% of the required performance bond and our
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associate took 30% of the bond. Historically, Forbes performed more than 70% of the work in these projects thereby making this bond arrangement financially viable. We believe that we accurately reflected this arrangement throughout our financial statements and disclosures, and that there is no other liability to recognize from this arrangement as it was terminated in 2012.
Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
In addition to the risks inherent in our operations, we are exposed to financial, market, and economic risks. Changes in interest rates may result in changes in the fair market value of our financial instruments, interest income, and interest expense. Our financial instruments that are exposed to interest rate risk are long-term borrowings. The following discussion provides information regarding our exposure to the risks of changing interest rates and fluctuating currency exchange rates.
Our primary debt obligations are the outstanding 9% Senior Notes and any borrowings under our revolving credit facility. Changes in interest rates do not affect interest expense incurred on our 9% Senior Notes as such notes bear interest at a fixed rate. However, changes in interest rates would affect their fair values. In general, the fair market value of debt with a fixed interest rate will increase as interest rates fall. Conversely, the fair market value of debt will decrease as interest rates rise. A hypothetical change in interest rates of 10% relative to interest rates as of December 31, 2013 would have no impact on our interest expense for the 9% Senior Notes.
Our revolving credit facility has a variable interest rate and, therefore, is subject to interest rate risk. As of December 31, 2013, we have not made significant draw on this facility. For this reason, a 100 basis point increase in interest rates on our variable rate debt would not result in significant additional annual interest expense.
With the disposition of our Mexican operations in January 2012, we are no longer exposed to any significant foreign currency risk.
We have not entered into any derivative financial instrument transactions to manage or reduce market risk or for speculative purposes.
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Item 8. | Consolidated Financial Statements and Supplementary Data |
Index to Financial Statements
Forbes Energy Services Ltd and Subsidiaries (a/k/a The “Forbes Group”)
Consolidated Financial Statements
Page | |
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Report of Independent Registered Public Accounting Firm
Board of Directors and Shareholders
Forbes Energy Services, Ltd.
Alice, Texas
We have audited the accompanying consolidated balance sheets of Forbes Energy Services Ltd. and Subsidiaries as of December 31, 2013 and 2012 and the related consolidated statements of operations, comprehensive income (loss), changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2013. 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 audits.
We conducted our audits 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Forbes Energy Services Ltd. and Subsidiaries at December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.
/S/ BDO USA, LLP
Houston, Texas
March 26, 2014
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Forbes Energy Services Ltd. and Subsidiaries (a/k/a the “Forbes Group”)
Consolidated Balance Sheets
(in thousands, except per share amounts)
December 31, | |||||||
2013 | 2012 | ||||||
Assets | |||||||
Current assets | |||||||
Cash and cash equivalents | $ | 26,409 | $ | 17,619 | |||
Accounts receivable - trade, net of allowance of $4.0 million and $2.7 million for 2013 and 2012, respectively | 82,209 | 92,596 | |||||
Accounts receivable - related parties | 185 | 60 | |||||
Accounts receivable - other | 592 | 428 | |||||
Prepaid expenses | 12,378 | 13,627 | |||||
Other current assets | 1,626 | 1,324 | |||||
Total current assets | 123,399 | 125,654 | |||||
Property and equipment, net | 341,869 | 348,442 | |||||
Other intangible assets, net | 25,154 | 28,015 | |||||
Deferred financing costs, net of accumulated amortization of $3.7 million and $2.1 million for 2013 and 2012, respectively | 6,860 | 8,040 | |||||
Restricted cash | 1,380 | 1,439 | |||||
Other assets | 1,896 | 1,111 | |||||
Total assets | $ | 500,558 | $ | 512,701 | |||
Liabilities and Shareholders’ Equity | |||||||
Current liabilities | |||||||
Current portions of long-term debt | $ | 9,374 | $ | 13,026 | |||
Accounts payable - trade | 27,016 | 17,973 | |||||
Accounts payable - related parties | 559 | 154 | |||||
Accrued dividends | 61 | 61 | |||||
Accrued interest payable | 1,367 | 1,354 | |||||
Accrued expenses | 14,727 | 13,539 | |||||
Total current liabilities | 53,104 | 46,107 | |||||
Long-term debt | 290,266 | 293,321 | |||||
Deferred tax liability | 21,610 | 26,587 | |||||
Total liabilities | 364,980 | 366,015 | |||||
Temporary equity | |||||||
Series B senior convertible preferred stock | 14,560 | 14,518 | |||||
Shareholders’ equity | |||||||
Common stock, $.04 par value, 112,500 shares authorized, 21,474 and 21,093 shares issued and outstanding at December 31, 2013 and 2012, respectively | 859 | 844 | |||||
Additional paid-in capital | 193,527 | 191,602 | |||||
Accumulated deficit | (73,368 | ) | (60,278 | ) | |||
Total shareholders’ equity | 121,018 | 132,168 | |||||
Total liabilities and shareholders’ equity | $ | 500,558 | $ | 512,701 |
The accompanying notes are an integral part of these consolidated financial statements.
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Forbes Energy Services Ltd. and Subsidiaries (a/k/a the “Forbes Group”)
Consolidated Statements of Operations
(in thousands except, per share amounts)
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Revenues | |||||||||||
Well servicing | $ | 231,930 | $ | 202,670 | $ | 177,896 | |||||
Fluid logistics | 188,003 | 269,927 | 267,887 | ||||||||
Total revenues | 419,933 | 472,597 | 445,783 | ||||||||
Expenses | |||||||||||
Well servicing | 182,180 | 158,302 | 141,589 | ||||||||
Fluid logistics | 141,957 | 196,383 | 193,718 | ||||||||
General and administrative | 30,186 | 33,382 | 31,318 | ||||||||
Depreciation and amortization | 54,838 | 50,997 | 39,660 | ||||||||
Total expenses | 409,161 | 439,064 | 406,285 | ||||||||
Operating income | 10,772 | 33,533 | 39,498 | ||||||||
Other income (expense) | |||||||||||
Interest income | 27 | 78 | 56 | ||||||||
Interest expense | (28,211 | ) | (28,033 | ) | (27,454 | ) | |||||
Loss on early extinguishment of debt | — | — | (35,415 | ) | |||||||
Other income | — | — | 69 | ||||||||
Income (loss) from continuing operations before taxes | (17,412 | ) | 5,578 | (23,246 | ) | ||||||
Income tax expense (benefit) | (4,615 | ) | 3,359 | (4,677 | ) | ||||||
Income (loss) from continuing operations | (12,797 | ) | 2,219 | (18,569 | ) | ||||||
Income (loss) from discontinued operations, net of tax expense (benefit) of ($200), ($400), and $6,300, respectively | (293 | ) | (633 | ) | 6,224 | ||||||
Net income (loss) | (13,090 | ) | 1,586 | (12,345 | ) | ||||||
Preferred stock dividends | (776 | ) | (776 | ) | (186 | ) | |||||
Net income (loss) attributable to common shareholders | $ | (13,866 | ) | $ | 810 | $ | (12,531 | ) | |||
Income (loss) per share of common stock from continuing operations | |||||||||||
Basic and diluted | $ | (0.64 | ) | $ | 0.07 | $ | (0.90 | ) | |||
Income (loss) per share of common stock from discontinued operations | |||||||||||
Basic and diluted | $ | (0.01 | ) | $ | (0.03 | ) | $ | 0.30 | |||
Income (loss) per share of common stock (Note 13) | |||||||||||
Basic and diluted | $ | (0.65 | ) | $ | 0.04 | $ | (0.60 | ) | |||
Weighted average number of shares of common stock outstanding (Note 13) | |||||||||||
Basic | 21,388 | 21,062 | 20,918 | ||||||||
Diluted | 21,388 | 21,340 | 20,918 |
The accompanying notes are an integral part of these consolidated financial statements.
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Forbes Energy Services Ltd. and Subsidiaries (a/k/a the “Forbes Group”)
Consolidated Statements of Comprehensive Income (Loss)
(in thousands)
Years Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Net income (loss) | $ | (13,090 | ) | $ | 1,586 | $ | (12,345 | ) | |||
Other comprehensive income (loss) | |||||||||||
Foreign currency translation adjustment | — | 1,078 | (1,421 | ) | |||||||
Comprehensive income (loss) | $ | (13,090 | ) | $ | 2,664 | $ | (13,766 | ) |
The accompanying notes are an integral part of these consolidated financial statements.
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Forbes Energy Services Ltd. and Subsidiaries (a/k/a the “Forbes Group”)
Consolidated Statements of Changes in Shareholders’ Equity
(in thousands)
Preferred Stock | Common Stock | Additional Paid-In Capital | Accumulated Other Comprehensive Income (loss) | Accumulated Deficit | Total Shareholders’ Equity | ||||||||||||||||||||||||
Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||
Balance: | |||||||||||||||||||||||||||||
December 31, 2010 | 588 | $ | 15,270 | 20,918 | $ | 837 | $ | 185,135 | $ | 343 | $ | (49,519 | ) | $ | 136,796 | ||||||||||||||
Share-based compensation | — | — | — | — | 2,937 | — | — | 2,937 | |||||||||||||||||||||
Net loss | — | — | — | — | — | — | (12,345 | ) | (12,345 | ) | |||||||||||||||||||
Foreign currency translation adjustment | — | — | — | — | — | (1,421 | ) | (1,421 | ) | ||||||||||||||||||||
Preferred stock dividends and accretion | — | (794 | ) | — | — | (187 | ) | — | — | (187 | ) | ||||||||||||||||||
Balance: | |||||||||||||||||||||||||||||
December 31, 2011 | 588 | $ | 14,476 | 20,918 | $ | 837 | $ | 187,885 | $ | (1,078 | ) | $ | (61,864 | ) | $ | 125,780 | |||||||||||||
Share-based compensation | — | — | — | — | 3,619 | — | — | 3,619 | |||||||||||||||||||||
Net income | — | — | — | — | — | — | 1,586 | 1,586 | |||||||||||||||||||||
Foreign currency translation adjustment | — | — | — | — | — | 1,078 | 1,078 | ||||||||||||||||||||||
Common shares issued under stock plan | |||||||||||||||||||||||||||||
Exercise of stock options | — | — | 25 | 1 | 64 | — | — | 65 | |||||||||||||||||||||
Issuance of restricted stock | — | — | 150 | 6 | 810 | — | — | 816 | |||||||||||||||||||||
Preferred stock dividends and accretion | — | 42 | — | — | (776 | ) | — | — | (776 | ) | |||||||||||||||||||
Balance: | |||||||||||||||||||||||||||||
December 31, 2012 | 588 | 14,518 | 21,093 | 844 | 191,602 | — | (60,278 | ) | $ | 132,168 | |||||||||||||||||||
Share-based compensation | — | — | — | — | 2,179 | — | — | 2,179 | |||||||||||||||||||||
Net loss | — | — | — | — | — | — | (13,090 | ) | (13,090 | ) | |||||||||||||||||||
Common shares issued under stock plan: | |||||||||||||||||||||||||||||
Exercise of stock options | — | — | 3 | — | 7 | — | — | 7 | |||||||||||||||||||||
Issuance of restricted stock | — | — | 378 | 15 | 515 | — | — | 530 | |||||||||||||||||||||
Preferred stock dividends and accretion | — | 42 | — | — | (776 | ) | — | — | (776 | ) | |||||||||||||||||||
Balance: | |||||||||||||||||||||||||||||
December 31, 2013 | 588 | $ | 14,560 | 21,474 | $ | 859 | $ | 193,527 | $ | — | $ | (73,368 | ) | $ | 121,018 |
The accompanying notes are an integral part of these consolidated financial statements.
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Forbes Energy Services Ltd. and Subsidiaries (a/k/a the “Forbes Group”)
Consolidated Statements of Cash Flows
(in thousands)
Years Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Cash flows from operating activities: | |||||||||||
Net income (loss) | $ | (13,090 | ) | $ | 1,586 | $ | (12,345 | ) | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||
Depreciation expense | 51,977 | 48,136 | 38,971 | ||||||||
Amortization expense | 2,861 | 2,861 | 2,861 | ||||||||
Amortization of Second Priority Notes OID | — | — | 324 | ||||||||
Share-based compensation | 2,852 | 4,430 | 2,937 | ||||||||
Deferred tax benefit | (4,977 | ) | (867 | ) | (2,194 | ) | |||||
Loss on disposal of assets, net | 443 | 1,000 | 1,902 | ||||||||
Gain on disposal of discontinued operations, net | — | (2,964 | ) | — | |||||||
Loss on early extinguishment of debt | — | — | 10,403 | ||||||||
Bad debt expense | 1,353 | 807 | 1,202 | ||||||||
Amortization of deferred financing cost | 1,518 | 1,471 | 1,608 | ||||||||
Changes in operating assets and liabilities: | |||||||||||
Accounts receivable | 8,857 | 41,655 | (51,739 | ) | |||||||
Accounts receivable - related parties | (125 | ) | 1,552 | (1,395 | ) | ||||||
Prepaid expenses and other current assets | (3,229 | ) | (3,180 | ) | (1,219 | ) | |||||
Accounts payable - trade | 6,278 | (19,535 | ) | 20,133 | |||||||
Accounts payable - related parties | 405 | (1,148 | ) | (6,886 | ) | ||||||
Accrued expenses | 1,202 | (7,504 | ) | 9,244 | |||||||
Accrued interest payable | 13 | 134 | (7,808 | ) | |||||||
Net cash provided by operating activities | 56,338 | 68,434 | 5,999 | ||||||||
Cash flows from investing activities: | |||||||||||
Purchases of property and equipment | (42,541 | ) | (111,769 | ) | (58,206 | ) | |||||
Proceeds from sale of property and equipment | 1,449 | 14,461 | 676 | ||||||||
Restricted cash | 59 | 14,711 | (7,107 | ) | |||||||
Deposit on assets held for sale | — | — | 13,700 | ||||||||
Net cash used in investing activities | (41,033 | ) | (82,597 | ) | (50,937 | ) | |||||
Cash flows from financing activities: | |||||||||||
Payments for debt issuance costs | (338 | ) | (107 | ) | (10,159 | ) | |||||
Proceeds from the exercise of stock options | 7 | 65 | — | ||||||||
Proceeds from the issuance of restricted stock | — | 5 | — | ||||||||
Borrowings on debt | — | — | 280,000 | ||||||||
Purchase and retirement of First Priority Notes | — | — | (20,000 | ) | |||||||
Purchase and retirement of Second Priority Notes | — | — | (192,500 | ) | |||||||
Repayments of other debt | (5,306 | ) | (4,478 | ) | (4,346 | ) | |||||
Dividends paid on Series B Senior Convertible Preferred Stock | (735 | ) | (735 | ) | (919 | ) | |||||
Payments of tax withholding obligations related to restricted stock | (143 | ) | — | — | |||||||
Net cash provided by (used) in financing activities | (6,515 | ) | (5,250 | ) | 52,076 | ||||||
Effect of currency translation on cash and cash equivalents | — | 432 | (996 | ) | |||||||
Net increase (decrease) in cash and cash equivalents | 8,790 | (18,981 | ) | 6,142 | |||||||
Cash and cash equivalents: | |||||||||||
Beginning of year | 17,619 | 36,600 | 30,458 | ||||||||
End of year | $ | 26,409 | $ | 17,619 | $ | 36,600 |
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Forbes Energy Services Ltd. and Subsidiaries (a/k/a the “Forbes Group”)
Notes to Consolidated Financial Statements
1. Organization and Nature of Operations
Nature of Business
Forbes Energy Services Ltd. (“FES Ltd”) is an independent oilfield services contractor that provides a wide range of well site services to oil and natural gas drilling and producing companies to help develop and enhance the production of oil and natural gas. These services include fluid hauling, fluid disposal, well maintenance, completion services, workovers and recompletions, plugging and abandonment, and tubing testing. Our operations are concentrated in the major onshore oil and natural gas producing regions of Texas, with additional locations in Mississippi, Pennsylvania and, prior to the disposition of our assets in Mexico in January 2012. We believe that our broad range of services, which extends from initial drilling, through production, to eventual abandonment, is fundamental to establishing and maintaining the flow of oil and natural gas throughout the life cycle of our customers’ wells.
As used in these consolidated financial statements, the “Company,” the “Forbes Group,” “we,” and “our” mean FES Ltd and its direct and indirect subsidiaries, except as otherwise indicated.
2. Risk and Uncertainties
As an independent oilfield services contractor that provides a broad range of drilling-related and production-related services to oil and natural gas companies, primarily onshore in Texas, our revenue, profitability, cash flows and future rate of growth are substantially dependent on our ability to (1) maintain adequate equipment utilization, (2) maintain adequate pricing for the services we provide, and (3) maintain a trained work force. Failure to do so could adversely affect our financial position, results of operations, and cash flows.
Because our revenues are generated primarily from customers who are subject to the same factors generally impacting the oil and natural gas industry, our operations are also susceptible to market volatility resulting from economic, cyclical, weather related, or other factors related to such industry. Changes in the level of operating and capital spending in the industry, decreases in oil and natural gas prices, or industry perception about future oil and natural gas prices could materially decrease the demand for our services, adversely affecting our financial position, results of operations and cash flows.
3. Summary of Significant Accounting Policies
Reclassification
Certain prior year amounts have been reclassified to conform to the current year presentation.
Principles of Consolidation
The Company’s consolidated financial statements as of December 31, 2013 and 2012 and for each of the three years ended December 31, 2013, 2012, and 2011 include the accounts of FES Ltd and all of its wholly owned, direct and indirect subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of consolidated financial statements in conformity with Accounting Principles Generally Accepted in the United States of America (“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 consolidated balance sheets and the reported amounts of revenues and expenses during the reporting period. Actual results could materially differ from those estimates. Management believes that these estimates and assumptions provide a reasonable basis for the fair presentation of the consolidated financial statements.
Revenue Recognition
Well Servicing –Well servicing consists primarily of maintenance services, workover services, completion services, plugging and abandonment services, and tubing testing. The Forbes Group prices well servicing by the hour of service performed, or on occasion, bid/turnkey pricing.
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Fluid Logistics – Fluid logistics consists primarily of the sale, transportation, storage, and disposal of fluids used in drilling, production, and maintenance of oil and natural gas wells. The Company prices fluid logistics services by the job, by the hour, or by the quantities sold, disposed, or hauled.
The Company recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists, and the price is fixed or determinable. In accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 605-45 “Principal Agent Considerations” (“ASC 605-45”) revenues are presented net of any sales taxes collected by the Forbes Group from its customers that are remitted to governmental authorities.
Income Taxes
The Company recognized deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized. Additionally, the Company records uncertain tax positions at their net recognizable amount, based on the amount that management deems is more likely than not to be sustained upon ultimate settlement with tax authorities in the jurisdictions in which we operate.
ASC 740 prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Benefits from tax positions should be recognized in the financial statements only when it is more likely than not that the tax position will be sustained upon examination by the appropriate taxing authority that would have full knowledge of all the relevant information. A tax position that meets the more-likely-than-not recognition threshold is measured at the largest amount of benefit that is greater than fifty percent likely of being realized upon ultimate settlement. Tax positions that previously failed to meet the more-likely-than not recognition threshold should be recognized in the first subsequent financial reporting period in which that threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not recognition threshold should be derecognized in the first subsequent financial reporting period in which that threshold is no longer met. The Company’s policy for recording interest and penalties associated with uncertain tax positions is to record such items as a component of tax expense. The Company has not recognized any material uncertain tax positions for the years ended December 31, 2013, 2012 and 2011.
Cash and Cash Equivalents
The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Restricted Cash
Restricted cash is serving as collateral for certain outstanding letters of credit. Restricted cash of $1.4 million at December 31, 2013 and 2012, is classified as a long-term asset as it collateralizes certain long-term insurance notes.
Foreign Currency Translation
The functional currency of our Mexican subsidiaries was the Mexican peso. Accordingly, all balance sheet accounts of this operation were translated into United States dollars using the current exchange rate in effect at the balance sheet date. The expenses of our Mexican subsidiaries were translated using the average exchange rates in effect during the period, and the gains and losses from foreign currency translation were recorded in accumulated other comprehensive income (loss). Our Mexican subsidiaries were substantially liquidated during 2012 and, consequently, the accumulated other comprehensive income (loss) totaling $0.8 million was recognized in the consolidated statement of operations for 2012 in discontinued operations.
Earnings per Share
The Company presents basic and diluted earnings per share “EPS” data for its common stock. Basic EPS is calculated by dividing the net income attributable to common shareholders of the Company by the weighted average number of shares of common stock outstanding during the period. Diluted EPS is determined by adjusting the profit or loss attributable to common shareholders and the weighted average number of shares of common stock outstanding adjusted for the effects of all dilutive potential common shares comprised of options granted, restricted stock, and restricted stock units. Preferred stock is a participating security under ASC 260 which means the security may participate in undistributed earnings with common stock. In accordance with ASC 260, securities are deemed to not be participating in losses if there is no obligation to fund such losses.
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The holders of the Series B Preferred Stock would be entitled to share in dividends, on an as-converted basis, if the holders of common stock were to receive dividends in excess of 5% of the then current common stock market price on a cumulative basis over the past twelve months, provided that the holders of the Series B Preferred Stock would only share in that portion of the dividend that exceeds 5%. The Series B Preferred Stock was not deemed to be participating since there were net losses from operations for the years ended December 31, 2013 and 2011. The Series B Preferred Stock was not deemed to be participating since income from operations was not in excess of the amounts above for the year ended December 31, 2012.
Fair Value of Financial Instruments
The following is a summary of the carrying amounts and estimated fair values of our financial instruments as of December 31, 2013 and 2012. Fair value is defined as the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
The carrying amounts of cash and cash equivalents, accounts receivable-trade, accounts receivable-related
parties, accounts receivable – other, other current assets, accounts payable – trade, prepaid expenses, accounts payable-related parties, insurance notes, deposits on assets held for sale, and accrued expenses approximate fair value because of the short maturity of these instruments. The fair values of third party notes and equipment notes are level two inputs in the fair value hierarchy, and approximate their carrying values, based on current market rates at which the company could borrow funds with similar maturities.
December 31, 2013 | December 31, 2012 | |||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
(dollars in thousands) | ||||||||||||||||
9.0% Senior Notes | $ | 280,000 | $ | 275,800 | $ | 280,000 | $ | 249,200 |
The fair value of our 9% Senior Notes is a level one input within the fair value hierarchy and is based on the dealer quoted market prices at December 31, 2013 and 2012.
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable are based on earned revenues. The Forbes Group provides an allowance for doubtful accounts, which is based on a review of outstanding receivables, historical collection information, and existing economic conditions. Provisions for doubtful accounts are recorded when it becomes evident that the customer will not be likely to make the required payments at either contractual due dates or in the future. The accounts are written off against the provision when it becomes evident that the account is not collectable. The allowance for doubtful accounts totaled $4.0 million and $2.7 million as of December 31, 2013 and 2012, respectively.
The following reflects changes in our allowance for doubtful accounts:
Balance as of January 1, 2011 | $ | 6,404 | |
Provision | 1,202 | ||
Bad debt write-off | (1,173 | ) | |
Balance as of December 31, 2011 | 6,433 | ||
Provision | 807 | ||
Bad debt write-off | (4,581 | ) | |
Balance as of December 31, 2012 | 2,659 | ||
Provision | 1,353 | ||
Bad debt write-off | (60 | ) | |
Balance as of December 31, 2013 | $ | 3,952 |
Property and Equipment
Property and equipment are recorded at cost. Improvements or betterments that extend the useful life of the assets are capitalized. Expenditures for maintenance and repairs are charged to expense when incurred. The costs of assets retired or otherwise disposed of and the related accumulated depreciation are eliminated from the accounts in the period of disposal. Gains or losses resulting from property disposals are credited or charged to operations currently. Depreciation is recorded using
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the straight-line method over the estimated useful lives of the assets for book purposes. Depreciation expense from continuing operations was $52.0 million, $48.1 million, and $39.0 million for the years ended December 31, 2013, 2012, and 2011, respectively. For tax purposes, property and equipment are depreciated under appropriate methods prescribed by the Internal Revenue Code of 1986, as amended, and the regulations promulgated thereunder.
Other Intangibles
Other intangible assets are assets (not including financial assets) that lack physical substance. We account for other intangible assets under the provisions of ASC Topic 350 “Intangibles – Goodwill and Other” (“ASC 350”). Other finite-lived intangible assets are subject to amortization for the period of time which the assets are expected to contribute directly or indirectly to future cash flows as described in ASC 350.
Impairments
In accordance with ASC Topic 360 “Property, Plant and Equipment” (“ASC 360”), long-lived assets, such as property, and equipment, and finite-lived intangibles subject to amortization, are reviewed whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Company evaluated its asset group in accordance with ASC 360 which resulted in no impairment for the years ended December 31, 2013, 2012, and 2011.
Environmental
The Company is subject to extensive federal, state, and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Forbes Group to remove or mitigate the adverse environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.
Deferred Financing Costs
The Company amortizes the deferred financing costs for the costs incurred with our 9% Senior Notes and for the loan agreement governing our revolving credit facility. These costs are amortized over the period of the agreements governing the 9% Senior Notes and the revolving credit facility on an effective interest basis, as a component of interest expense. For the years ended December 31, 2013, 2012, and 2011 amortization of deferred financing costs was $1.5 million, $1.5 million, and $1.6 million, respectively.
Share-Based Compensation
The Company accounts for share-based compensation in accordance with ASC Topic 718 “Compensation – Stock Compensation”, (“ASC 718”). Upon adoption of ASC 718, the Company selected the Black-Scholes option pricing model as the most appropriate model for determining the estimated fair value for stock options. The Company measures share-based compensation cost as of the grant date based on the estimated fair value of the award less an estimated rate for pre-vesting forfeitures, and recognizes compensation expense on a straight-line basis over the vesting period. Compensation expense is recognized with an off-setting credit to additional paid-in capital. When the award is distributed or the option is exercised, an entry is made to additional paid-in capital with the off-set to common stock equal to the par value times the number of shares. Consideration received on the exercise of stock options is also credited to additional paid-in capital.
Recent Accounting Pronouncements
In July 2013, the FASB issued ASU No. 2013-11, “Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exist” (“ASU2013-11”). ASU 2013-11 reduces diversity in practice by providing guidance on the presentation of unrecognized tax benefits and is intended to better reflect the manner in which an entity would settle at the reporting date any additional income taxes that would result from the disallowance of a tax position when net operating loss carryforwards, similar tax losses, or tax credit carryforwards exist. ASU 2013-11 became effective for the Company on January 1, 2014 and the Company does not believe it will have a material impact on the Company's consolidated financial statements.
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4. Other Intangible Assets
Other intangible assets are subject to amortization for the period of time which the assets are expected to contribute directly or indirectly to future cash flows under the guidance of ASC 350.
Our major classes of intangible assets subject to amortization under ASC 350 consist of our customer relationships, trade name, safety training program, and dispatch software. The Company expenses costs associated with extensions or renewals of intangibles assets. There were no such extensions or renewals in the years ended December 31, 2013, 2012 or 2011. Amortization expense is calculated using the straight-line method over the period indicated. Amortization expense for each of the years ended December 31, 2013, 2012, and 2011 was $2.9 million. Estimated amortization expense for the years 2014-2017 is $2.9 million per year and in 2018 the estimated amortization expense is $2.7 million. The weighted average amortization period remaining for intangible assets is 8.8 years.
The following sets forth the identified intangible assets by major asset class:
December 31, 2013 | December 31, 2012 | ||||||||||||||||||||||||
Useful Life (years) | Gross Carrying Value | Accumulated Amortization | Net Book Value | Gross Carrying Value | Accumulated Amortization | Net Book Value | |||||||||||||||||||
Customer relationships | 15 | $ | 31,896 | $ | 12,758 | $ | 19,138 | $ | 31,896 | $ | 10,632 | $ | 21,264 | ||||||||||||
Trade names | 15 | 8,050 | 3,220 | 4,830 | 8,050 | 2,683 | 5,367 | ||||||||||||||||||
Safety training program | 15 | 1,182 | 473 | 709 | 1,182 | 394 | 788 | ||||||||||||||||||
Dispatch software | 10 | 1,135 | 681 | 454 | 1,135 | 568 | 567 | ||||||||||||||||||
Other | 10 | 58 | 35 | 23 | 58 | 29 | 29 | ||||||||||||||||||
$ | 42,321 | $ | 17,167 | $ | 25,154 | $ | 42,321 | $ | 14,306 | $ | 28,015 |
5. Share-Based Compensation
Incentive Compensation Plans
From time to time, the Company grants stock options, restricted stock units, or other awards to its employees, including executive officers, and directors. Prior to July 9, 2012, these awards were granted pursuant to the Company's 2008 Incentive Compensation Plan, or the 2008 Plan. On July 9, 2012, at the Company's 2012 Annual Meeting of Shareholders, the Company's shareholders approved the Company's 2012 Incentive Compensation Plan, or the 2012 Plan. No further awards will be made under the 2008 Plan, however, outstanding awards granted under the 2008 Plan will remain subject to the terms and conditions of the 2008 Plan. Any shares of common stock that are available to be granted under the 2008 Plan, but which are not subject to outstanding awards under the 2008 Plan, including shares that become available due to the future lapse or forfeiture of outstanding awards, will be added to the 1,022,500 shares of common stock authorized for issuance under the 2012 Plan. After taking into account the restricted stock and restricted stock units granted during 2013 (as discussed in the Restricted Stock and Restricted Stock Units paragraph below), there were 1,346,546 shares available for future grants under the 2012 Incentive Compensation Plan. There have been no stock option awards issued under the 2012 Plan.
Stock Options
Stock options issued in 2008 originally vested over a three-year period. On August 11, 2011, the Company exchanged 667,500 of these 2008 options in a 0.72 to 1 exchange for 480,600 options (the “Exchange Options”). These Exchange Options vested one-third every four months from the exchange date and the Company recognized $0.1 million of compensation expense for this exchange over such 12 month period. For the 2011 stock option issuances other than the Exchange Options, the standard option vested over a three year period, with one-third vesting on the annual anniversary of the award date and one third vesting every year thereafter, until fully vested. For most grantees, options expire at the earlier of either one year after the termination of grantee’s employment by reason of death, disability or retirement, ninety days after termination of the grantee’s employment other than upon grantee’s death, disability or retirement, or ten years after the date of grant.
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The following table presents a summary of the Company’s stock option activity for the years ended December 31, 2013 and 2012:
Shares | Weighted- Average Exercise Price | Weighted- Average Remaining Contractual Term | Aggregate Intrinsic Value | |||||||||
Options outstanding at December 31, 2011 | 2,285,425 | $ | 7.49 | 8.79 years | $ | 2,297,344 | ||||||
Stock options: | ||||||||||||
Granted | — | — | ||||||||||
Exercised | (25,000 | ) | 2.60 | |||||||||
Forfeited | (262,500 | ) | 8.87 | |||||||||
Options outstanding at December 31, 2012 | 1,997,925 | 7.51 | 7.73 years | — | ||||||||
Stock options: | ||||||||||||
Granted | — | — | ||||||||||
Exercised | (2,500 | ) | 2.60 | |||||||||
Forfeited | (595,000 | ) | 8.76 | |||||||||
Options outstanding at December 31, 2013 | 1,400,425 | $ | 6.99 | 6.47 years | $ | 316,994 | ||||||
Vested and expected to vest at December 31, 2013 | 1,214,275 | $ | 6.65 | 6.30 years | $ | 316,994 | ||||||
Exercisable at December 31, 2011 | 419,888 | $ | 4.44 | 8.12 years | $ | 1,148,672 | ||||||
Exercisable at December 31, 2012 | 1,287,725 | $ | 6.60 | 7.24 years | $ | — | ||||||
Exercisable at December 31, 2013 | 1,214,275 | $ | 6.65 | 6.30 years | $ | 316,994 |
During the years ended December 31, 2013, 2012 and 2011, the Company recorded total stock-based compensation expense related to stock options of $0.7 million, $3.0 million, and $2.9 million, respectively. No stock-based compensation costs were capitalized in 2013, 2012 or 2011. As of December 31, 2013, total unrecognized stock-based compensation cost for stock options amounted to $1.2 million, (net of estimated forfeitures) and is expected to be recorded over a weighted-average period of 0.66 years.
There were no stock options granted during the year ended December 31, 2013 and 2012. At December 31, 2013, outstanding options had a weighted average remaining contractual term of 6.47 years. The amount of unrecognized stock-based compensation will be affected by any future stock option grants and any termination of employment by any employee that has received stock option grants that are unvested as of their termination date. Under the true-up provisions of ASC 718, the Company will record additional expense if the actual forfeiture rate is lower than estimated, and will record a recovery of prior expense if the actual forfeiture is higher than estimated.
Assumptions for Estimating Fair Value of Stock Option Grants
Upon adoption of ASC 718, the Company selected the Black-Scholes option pricing model as the most appropriate model for determining the estimated fair value for stock options. The use of the Black-Scholes model requires the use of extensive actual employee exercise behavior data and the use of a number of complex assumptions including expected volatility and expected term.
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There were no stock options granted in 2013 or 2012. The following table summarizes the assumptions used to value options granted during the year ended:
2011 | |
Expected term | 4 years - 6.5 years |
Risk-free interest rate | 0.68% - 1.45% |
Volatility | 97% |
Dividend yield | 0 % |
Grant date fair value per share | $6.28 - $8.00 |
The expected term of employee stock options represents the weighted-average period that the stock options are expected to remain outstanding. The risk-free interest rate is based on the U.S. Treasury constant maturity interest rate with a term consistent with the expected life of the options. For the 2011 options, the Company’s historical common stock value was used to calculate the expected volatility. The dividend yield assumption is based on the Company’s expectation of no dividend payouts.
Restricted Stock
There was no restricted stock granted during 2013. The table below presents restricted stock activity for the years ended December 31, 2013 and 2012.
Number of Units | Grant Date Average Fair Value Per Unit | |||||
Outstanding at December 31, 2011 | — | $ | — | |||
Granted | 208,332 | 5.92 | ||||
Vested | (125,000 | ) | 5.76 | |||
Forfeited | (41,666 | ) | 6.15 | |||
Nonvested at December 31, 2012 | 41,666 | $ | 6.15 | |||
Granted | — | — | ||||
Vested | (41,666 | ) | 6.15 | |||
Forfeited | — | — | ||||
Nonvested at December 31, 2013 | — | $ | — |
There was less than $0.1 million and $1.0 million in stock based compensation expense recognized for these restricted stock grants for the years ended December 31, 2013 and 2012, respectively.
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Restricted Stock Units
The following table presents a summary of restricted stock unit activity for the years ended December 31, 2013 and 2012:
Number of Units | Grant Date Average Fair Value Per Unit | |||||
Outstanding at December 31, 2011 | — | $ | — | |||
Granted | 148,945 | 3.51 | ||||
Vested | (24,192 | ) | 3.78 | |||
Forfeited | — | — | ||||
Nonvested at December 31, 2012 | 124,753 | $ | 3.45 | |||
Granted | 930,284 | 3.44 | ||||
Vested | (374,848 | ) | 3.38 | |||
Forfeited | (5,400 | ) | 2.65 | |||
Nonvested at December 31, 2013 | 674,789 | $ | 3.49 |
In the twelve months ended December 31, 2013, participants utilized a net withholding exercise method, in which restricted stock units were surrendered to cover payroll withholding tax. The cumulative net shares issued to the participants who chose the net withholding exercise was 116,549 shares compared to 155,400 granted shares of restricted stock units and shown in the shares vested for the year of 374,848. The total pretax cash outflow, as included in withholding tax payments in our condensed consolidated statements of cash flows, for this net withholding exercise was $0.1 million.
Stock compensation expense of $2.1 million and $0.1 million was recognized for the restricted stock units granted for the years ended 2013 and 2012, respectively. The remaining compensation expense to be recognized over a weighted-average period of 2.0 year is $1.6 million.
6. Property and Equipment
Property and equipment at December 31, 2013 and 2012, consisted of the following:
Estimated Life in Years | December 31, | ||||||||
2013 | 2012 | ||||||||
(in thousands) | |||||||||
Well servicing equipment | 3-15 years | $ | 411,237 | $ | 390,443 | ||||
Autos and trucks | 5-10 years | 103,443 | 102,874 | ||||||
Disposal wells | 5-15 years | 43,754 | 32,437 | ||||||
Building and improvements | 5-30 years | 13,544 | 11,188 | ||||||
Furniture and fixtures | 3-15 years | 5,395 | 3,870 | ||||||
Land | 1,876 | 1,227 | |||||||
579,249 | 542,039 | ||||||||
Accumulated depreciation | (237,380 | ) | (193,597 | ) | |||||
$ | 341,869 | $ | 348,442 |
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The Company is obligated under various capital leases for certain vehicles and equipment that expire at various dates during the next five years. The gross amount of property and equipment and related accumulated depreciation recorded under capital leases and included above consists of the following:
December 31, | |||||||
2013 | 2012 | ||||||
(in thousands) | |||||||
Well servicing equipment | $ | 9,281 | $ | 11,079 | |||
Autos and trucks | 5,839 | 6,350 | |||||
15,120 | 17,429 | ||||||
Accumulated depreciation | (6,163 | ) | (3,017 | ) | |||
$ | 8,957 | $ | 14,412 |
Depreciation of assets held under capital leases of approximately $3.1 million , $2.6 million, and $0.4 million for the years ended December 31, 2013, 2012, and 2011, respectively is included in depreciation and amortization expense in the consolidated statements of operations.
7. Accounts Payable and Accrued Expenses
Accrued expenses and accounts payable – trade at December 31, 2013 and 2012, consisted of the following:
December 31, | |||||||
2013 | 2012 | ||||||
(in thousands) | |||||||
Accrued wages | $ | 6,968 | $ | 5,011 | |||
Accrued payroll taxes | 660 | 694 | |||||
Accrued insurance | 4,601 | 4,580 | |||||
Accrued sales tax - US | 191 | 147 | |||||
Accrued franchise tax | 83 | 815 | |||||
Accrued federal income tax payable | 301 | 351 | |||||
Other accrued expenses | 1,923 | 1,941 | |||||
Total accrued expenses | $ | 14,727 | $ | 13,539 | |||
Accounts payable - vendor financings | $ | 4,082 | $ | 1,390 | |||
Accounts payable - other | 22,934 | 16,583 | |||||
Total accounts payable - trade | $ | 27,016 | $ | 17,973 |
8. Long-Term Debt
Debt at December 31, 2013 and 2012, consisted of the following :
December 31, | |||||||
2013 | 2012 | ||||||
(in thousands) | |||||||
9% Senior Notes | $ | 280,000 | $ | 280,000 | |||
Third party equipment notes and capital leases | 15,109 | 18,425 | |||||
Insurance notes | 4,531 | 7,922 | |||||
Revolving credit facility | — | — | |||||
299,640 | 306,347 | ||||||
Less: Current portion | (9,374 | ) | (13,026 | ) | |||
$ | 290,266 | $ | 293,321 |
Aggregate maturities of long-term debt as of December 31, 2013 are as follows (in thousands):
2014 | $ | 9,374 | |
2015 | 4,904 | ||
2016 | 3,210 | ||
2017 | 2,057 | ||
2018 | 81 | ||
Thereafter | 280,014 | ||
Total | $ | 299,640 |
9% Senior Notes
On June 7, 2011, FES Ltd issued $280.0 million in principal amount of 9% Senior Notes due 2019 (the “9% Senior Notes”). The proceeds of the 9% Senior Notes were used to purchase and/or redeem 100% of the First Priority Floating Rate Notes due 2014 and the outstanding Second Priority Notes (as defined below) issued by Forbes Energy Services LLC and Forbes Energy Capital Inc. The 9% Senior Notes mature on June 15, 2019, and require semi-annual interest payments, in arrears, at an annual rate of 9% on June 15 and December 15 of each year until maturity commencing December 15, 2011. No principal payments are due until maturity.
The 9% Senior Notes are guaranteed by the current domestic subsidiaries (the “Guarantor Subs”) of FES Ltd, which include Forbes Energy Services LLC (“FES LLC”), C.C. Forbes, LLC (“CCF”), TX Energy Services, LLC (“TES”), Superior Tubing Testers, LLC (“STT”) and Forbes Energy International, LLC (“FEI LLC”). All of the Guarantor Subs are 100% owned and each guarantees the securities on a full and unconditional and joint and several basis, subject to customary release provisions. Prior to January 12, 2012, FES Ltd had two 100% owned indirect Mexican subsidiaries or the Non-Guarantor Subs that had not guaranteed the 9% Senior Notes. In January 2012, one of those two Mexican subsidiaries was sold along with the business and substantially all of our long-lived assets located in Mexico. Prior to January 12, 2012, FES Ltd had a branch office in Mexico and conducted operations independent of the Non-Guarantor Subs. The Guarantor Subs represent the substantial majority of the Company’s operations. On or after June 15, 2015, the Forbes Group may, at its option, redeem all or part of the 9% Senior Notes from time to time at specified redemption prices and subject to certain conditions required by the indenture governing the 9% Senior Notes (the “9% Senior Indenture”). The Forbes Group is required to make an offer to purchase the notes and to repurchase any notes for which the offer is accepted at 101% of their principal amount, plus accrued and unpaid interest, if there is a change of control. The Forbes Group is required to make an offer to repurchase the notes and to repurchase any notes for which the offer is accepted at 100% of their principal amount, plus accrued and unpaid interest, following certain asset sales.
The Forbes Group is permitted under the terms of the 9% Senior Indenture to incur additional indebtedness in the future, provided that certain financial conditions set forth in the 9% Senior Indenture are satisfied. The Forbes Group is subject to
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certain covenants contained in the 9% Senior Indenture, including provisions that limit or restrict the Forbes Group’s and certain future subsidiaries’ abilities to incur additional debt, to create, incur or permit to exist certain liens on assets, to make certain dispositions of assets, to make payments on certain subordinated indebtedness, to pay dividends or certain other payments to equity holders, to engage in mergers, consolidations or other fundamental changes, to change the nature of its business or to engage in transactions with affiliates. Due to cross-default provisions in the indenture governing our 9% Senior Notes and the loan agreement governing our revolving credit facility, with certain exceptions, a default and acceleration of outstanding debt under one debt agreement would result in the default and possible acceleration of outstanding debt under the other debt agreement. Accordingly, an event of default could result in all or a portion of our outstanding debt under our debt agreements becoming immediately due and payable. If this occurred, we might not be able to obtain waivers or secure alternative financing to satisfy all of our obligations simultaneously, which would adversely affect our business and operations.
Details of two of the more significant restrictive covenants in the 9% Senior Indenture are set forth below:
• | Limitation on the Incurrence of Additional Debt - In addition to certain indebtedness defined in the 9% Senior Indenture as "Permitted Debt," which includes indebtedness under any credit facility not to exceed the greater of $75.0 million or 18% of the Company's Consolidated Tangible Assets (as defined in the 9% Senior Indenture), we may only incur additional debt if the Fixed Charge Coverage Ratio (as defined in the 9% Senior Indenture) for the most recently completed four full fiscal quarters is at least 2.0 to 1.0. |
• | Limitation on Restricted Payments - Subject to certain limited exceptions, including specific permission to pay cash dividends on the Company's Series B Senior Convertible Preferred Stock up to $260,000 per quarter, the Company is prohibited from (i) declaring or paying dividends or other distributions on its equity securities (other than dividends or distributions payable in equity securities), (ii) purchasing or redeeming any of the Company's equity securities, (iii) making any payment on indebtedness contractually subordinated to the 9% Senior Notes, except a payment of interest or principal at the stated maturity thereof, or (iv) making any investment defined as a "Restricted Investment," unless, at the time of and after giving effect to such payment, the Company is not in default and the Company is able to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio (as defined in the 9% Senior Indenture). Further, the amount of such payment plus all other such payments made by the Company since the issuance of the 9% Senior Notes must be less than the aggregate of (a) 50% of Consolidated Net Income (as defined in the 9% Senior Indenture) since the April 1, 2011 (or 100%, if such figure is a deficit), (b) 100% of the aggregate net cash proceeds from equity offerings since the issuance of the 9% Senior Notes, (c) if any Restricted Investments have been sold for cash, the proceeds from such sale (or the original cash investment if that amount is lower); and (d) 50% of any dividends received by the Company. |
The Company is in compliance with the covenants under the indenture governing the 9% Senior Notes at December 31, 2013.
Second Priority Notes
On February 12, 2008, FES LLC and Forbes Energy Capital Inc. (“FES CAP”), a subsidiary of FES LLC that was dissolved in November 2011, issued $205.0 million in principal amount of 11.0% senior secured notes due 2015 (together with notes issued in exchange therefore, the “Second Priority Notes”). Pursuant to the requirements of the indenture governing the Second Priority Notes (the “Second Priority Indenture”), during 2009 and 2010, we had repurchased a total of $10.0 million in aggregate principal amount of Second Priority Notes. In May 2011, we commenced a cash tender offer to purchase any and all of the Second Priority Notes then outstanding. In connection with this tender offer, we successfully solicited consents to proposed amendments that would eliminate most of the restrictive covenants and event of default provisions contained in the Second Priority Indenture. In June 2011, pursuant to this tender offer, we purchased 99.8% of the outstanding principal amount of the Second Priority Notes. As a result of the completion of the tender offer, the fourth supplemental indenture to the Second Priority Indenture, which contained the amendments proposed in the consent solicitation, became effective eliminating most of the restrictive covenants and event of default provisions of the Second Priority Indenture. On June 27, 2011, the Company redeemed the remaining outstanding Second Priority Notes, which was closed on July 27, 2011. Second Priority Notes redeemed or purchased in 2011 totaled $192.5 million. As a result, the Second Priority Indenture was discharged and all liens relating thereto were released. The tender purchase price premium and consent fee paid was $24.4 million or 12.8% or 9.8%, depending on date tendered. Unamortized deferred financing charges and discounts written off in connection with the redemption were $9.5 million. Total loss on early extinguishment of debt related to Second Priority Notes was $33.9 million.
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First Priority Notes
On October 2, 2009, FES LLC and FES CAP issued to Goldman, Sachs & Co. $20.0 million in aggregate principal amount of First Lien Floating Rate Notes due 2014 (the “First Priority Notes”), in a private placement in reliance on an exemption from registration under the Securities Act of 1933, as amended. On June 7, 2011, FES Ltd used a portion of the proceeds of the offering of the 9% Senior Notes to purchase all of the $20.0 million in aggregate principal amount of the First Priority Notes outstanding at which time the indenture governing the First Priority was discharged and the liens related thereto were released. The penalty payment on the early redemption was $0.6 million or 3.0%. Unamortized deferred financing charges written off in connection with the redemption were $0.9 million. Total loss on early extinguishment of debt related to First Priority Notes was $1.5 million.
Revolving Credit Facility
On September 9, 2011, FES Ltd. and its current domestic subsidiaries entered into a loan and security agreement with Regions Bank, SunTrust Bank, CIT Bank and Capital One Leverage Finance Corp., as lenders, and Regions Bank, as agent for the secured parties, or the Agent. This loan and security agreement was amended in December 2011, July 2012 and July 2013. On the July 2013 amendment, the CIT Bank opted out of the lending group, with Regions Bank increasing its participation by taking CIT Bank's position. The loan and security agreement initially provided for an asset based revolving credit facility with a maximum initial borrowing credit of $75.0 million, subject to borrowing base availability and other limitations. The third amendment increased the maximum borrowing credit to $90.0 million, subject to borrowing base availability, any reserves established by the facility agent in its discretion, compliance with a fixed charge coverage ratio covenant if availability under the facility falls below certain thresholds and, for borrowings above $75.0 million, compliance with the debt incurrence covenant in the indenture governing the 9% Senior Notes this indenture covenant prohibits the incurrence of debt except for certain limited exceptions, including indebtedness incurred under the permitted credit facility debt basket to the greater of $75.0 million or 18% of our Consolidated Tangible Assets (as defined in the 9% Senior Indenture) reported for the last fiscal quarter for which financial statements are available. As of December 31, 2013, 18% of our Consolidated Tangible Assets (as defined in the 9% Senior Indenture) was approximately $84.3 million. If our availability under the credit facility dropped below 15% of our total borrowing credit (as described above), we are required to maintain a trailing four-quarter fixed charge coverage ratio of at least 1.1 to 1. We would currently be in compliance with this covenant if it were applicable.
As of December 31, 2013, there were no amounts drawn and outstanding letters of credit in the amount of $5.9 million posted under the facility. Taking into account the limitations discussed above, we have at least $78.4 million of availability under our credit facility. As amended, the loan and security agreement has a stated maturity of July 26, 2018. The proceeds of this credit facility can be used for the purchase of well services equipment, permitted acquisitions, general operations, working capital and other general corporate purposes.
Under the loan and security agreement, our borrowing base at any time is equal to (i) 85% of eligible accounts, which are determined by Agent in its reasonable discretion, plus (ii) the lesser of 85% of the appraised value, subject to certain adjustments, of our well services equipment that has been properly pledged and appraised, is in good operating condition and is located in the United States, or 100% of the net book value of such equipment, minus (iii) any reserves established by the Agent in its reasonable discretion.
Prior to the third amendment, at our option, borrowings under this credit facility would have borne interest at a rate equal to either (i) the LIBOR rate plus an applicable margin of between 2.25% to 2.75% based on borrowing availability or (ii) a base rate plus an applicable margin of between 1.25% to 1.75% based on borrowing availability, where the base rate was equal to the greater of the prime rate established by Regions Bank, the overnight federal funds rate plus 0.50% or the LIBOR rate for a one month period plus 1.00%. The third amendment decreased the revolving interest rate whereby borrowings under the Loan Agreement will bear interest at a rate equal to either (a) the LIBOR rate plus an applicable margin of between 2.00% to 2.50% based on borrowing availability or (b) a base rate plus an applicable margin of between 1.00% to 1.50% based on borrowing availability, where the base rate is equal to the greater of the prime rate established by Regions Bank, the overnight federal funds rate plus 0.5% or the LIBOR rate for a one month period plus 1%.
In addition to paying interest on outstanding principal under the facility, a fee of 0.375% per annum will accrue on unutilized availability under the credit facility. We are required to pay a fee of between 2.25% to 2.75%, based on borrowing availability, with respect to the principal amount of any letters of credit outstanding under the facility. We are also responsible for certain other administrative fees and expenses.
FES LLC, FEI LLC, TES, CCF and STT are the borrowers under the loan and security agreement. Their obligations have been guaranteed by one another and by FES Ltd. Subject to certain exceptions and permitted encumbrances, including the exemption of real property interests from the collateral package, the obligations under this facility are secured by a first priority security interest in all of our assets.
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We are able to voluntarily repay outstanding loans at any time without premium or penalty (subject to the fees discussed above). If at any time our outstanding loans under the credit facility exceed the availability under our borrowing base, we may be required to repay the excess. Further, we are required to use the net proceeds from certain events, including certain judgments, tax refunds or insurance awards to repay outstanding loans, however, we may reborrow following such repayments if the conditions to borrowing are met.
The loan and security agreement contains customary covenants for an asset-based credit facility, which include (i) restrictions on certain mergers, consolidations and sales of assets; (ii) restrictions on the creation or existence of liens; (iii) restrictions on making certain investments; (iv) restrictions on the incurrence or existence of indebtedness; (v) restrictions on transactions with affiliates; (vi) requirements to deliver financial statements, report and notices to the Agent and (vii) a springing requirement to maintain a consolidated Fixed Charge Coverage Ratio (which is defined in the loan and security agreement) of 1.1:1.0 in the event that our excess availability under the credit facility falls below the greater of $11.3 million or 15.0% of our maximum credit under the facility for sixty consecutive days; provided that, the restrictions described in (i)-(v) above are subject to certain exceptions and permissions limited in scope and dollar value. The loan and security agreement also contains customary representations and warranties and event of default provisions. As of December 31, 2013 we are in compliance with all applicable covenants in the loan and security agreement.
Third Party Equipment Notes and Capital Leases
During the past few years, the Forbes Group financed the purchase of certain vehicles and equipment through commercial loans with Paccar Financial Group, Mack Financial Services, Enterprise Fleet Management, and Regions Equipment Finance and capital leases, with aggregate principal amounts outstanding as of December 31, 2013 and 2012 of approximately $15.1 million and $18.4 million, respectively. These loans are repayable in a range of 42 to 60 monthly installments with the maturity dates ranging from May 2013 to January 2018. Interest accrues at rates ranging from 4.7% to 8.42% and is payable monthly. The loans are collateralized by equipment purchased with the proceeds of such loans. The Forbes Group paid total principal payments of approximately $5.3 million, $4.5 million, and $4.3 million for the years ended December 31, 2013, 2012, and 2011, respectively.
Insurance Notes
During 2013 and 2012, the Forbes Group entered into promissory notes with First Insurance Funding for the payment of insurance premiums in an aggregate principal amount outstanding as of December 31, 2013 and December 31, 2012 of approximately $4.5 million and $7.9 million, respectively during the period of the insurance coverage. These notes are or were payable in twelve monthly installments with maturity dates of October 15, 2014 and October 15, 2013, respectively. Interest accrues or accrued at a rate of approximately 2.9% and 3.3% for 2013 and 2012, respectively, and is payable monthly. The amount outstanding could be substantially offset by the cancellation of the related insurance coverage.
Deferred Financing Costs
The Company incurred deferred financing costs associated with our 9% Senior Notes and the loan agreement governing our revolving credit facility. Costs incurred were $0.3 million, $0.1 million, and $10.2 million for the years ended December 31, 2013, 2012, and 2011, respectively.
9. Related Party Transactions
The Forbes Group enters into transactions with related parties in the normal course of conducting business. The following tables represent related party transactions.
As of December 31, | ||||||||||||
2013 | 2012 | |||||||||||
(in thousands) | ||||||||||||
Related parties cash and cash equivalents balances: | ||||||||||||
Balance at Texas Champion Bank (1) | $ | 698 | $ | 983 | ||||||||
Balance at Brush Country Bank (2) | 469 | 209 | ||||||||||
Related parties receivable: |
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Alice Environmental Services, LP/Alice Environmental Holding LLC (3) | $ | 1 | $ | — | ||||||||
Dorsal Services, Inc. (4) | 61 | 60 | ||||||||||
Wolverine Construction, Inc. (5) | 123 | — | ||||||||||
$ | 185 | $ | 60 | |||||||||
Related parties payable: | ||||||||||||
Alice Environmental Services, LP/Alice Environmental Holding LLC (3) | $ | 218 | $ | 10 | ||||||||
Dorsal Services, Inc. (4) | 256 | — | ||||||||||
Tasco Tool Services, Inc. (6) | 16 | — | ||||||||||
Resonant Technology Partners (7) | — | 19 | ||||||||||
Wolverine Construction, Inc. (5) | — | 39 | ||||||||||
JITSU Services, LLC (8) | 30 | — | ||||||||||
Texas Quality Gate Guard Services, LLC (9) | 29 | — | ||||||||||
Texas Water Disposal, LLC (18) | 10 | 86 | ||||||||||
$ | 559 | $ | 154 | |||||||||
Years ended December, 31 | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(in thousands) | ||||||||||||
Related parties capital expenditures: | ||||||||||||
Alice Environmental Services, LP/Alice Environmental Holding LLC (3) | $ | — | $ | 15,567 | $ | — | ||||||
Dorsal Services, Inc. (4) | — | — | 9 | |||||||||
Tasco Tool Services, Inc. (6) | 64 | 196 | 104 | |||||||||
Resonant Technology Partners (7) | 63 | 289 | 28 | |||||||||
Energy Fishing And Rentals, Inc. (10) | — | — | 3 | |||||||||
LA Contractors LTD (11) | — | — | 71 | |||||||||
$ | 127 | $ | 16,052 | $ | 215 | |||||||
Related parties revenue activity: | ||||||||||||
Alice Environmental Services, LP/Alice Environmental Holding LLC (3) | $ | — | $ | — | $ | — | ||||||
CJ Petroleum Service LLC (12) | — | 18 | — | |||||||||
Dorsal Services, Inc. (4) | 18 | — | 29 | |||||||||
Tasco Tool Services, Inc. (6) | 3 | 1 | 3 | |||||||||
C.W. Hahl Lease(13) | — | — | 109 | |||||||||
Wolverine Construction, Inc. (5) | 152 | 41 | 1,100 | |||||||||
Texas Quality Gate Guard Services, LLC (9) | — | 4 | 7 | |||||||||
Energy Fishing And Rentals, Inc. (10) | — | 6 | — | |||||||||
Testco Well Services, LLC (14) | 69 | 18 | 9 | |||||||||
Texas Water Disposal, LLC (18) | 15 | 22 | 6 | |||||||||
$ | 257 | $ | 110 | $ | 1,263 | |||||||
Related parties expense activity: | ||||||||||||
Alice Environmental Services, LP/Alice Environmental Holding LLC (3) | $ | 1,810 | $ | 3,832 | $ | 6,900 | ||||||
CJ Petroleum Service LLC (12) | — | 294 | 416 | |||||||||
Dorsal Services, Inc. (4) | 498 | 139 | 395 | |||||||||
Tasco Tool Services, Inc. (6) | 128 | 179 | 165 | |||||||||
FCJ Management, LLC (15) | 36 | 36 | 36 | |||||||||
C&F Partners, LLC (16) | — | 199 | 416 | |||||||||
Resonant Technology Partners (7) | 384 | 444 | 344 | |||||||||
Wolverine Construction, Inc. (5) | — | 37 | 10,300 |
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JITSU Services, LLC (8) | 396 | 405 | 405 | |||||||||
Texas Quality Gate Guard Services, LLC (9) | 363 | 362 | 310 | |||||||||
Animas Holdings, LLC (17) | 670 | 26 | 338 | |||||||||
Energy Fishing And Rentals, Inc. (10) | — | 343 | 310 | |||||||||
LA Contractors LTD (11) | — | — | 2 | |||||||||
Testco Well Services, LLC (14) | 32 | 5 | 4 | |||||||||
Texas Water Disposal, LLC (18) | 498 | 1,159 | — | |||||||||
$ | 4,815 | $ | 7,460 | $ | 20,341 |
(1)The Company has a deposit relationship with Texas Champion Bank. Travis Burris, one of the directors of FES Ltd., is also the President, Chief Executive Officer, and director of Texas Champion Bank. Mr. Crisp, our President and Chief Executive Officer, serves on the board of directors.
(2)Messrs. Crisp and Forbes are directors and shareholders of Brush Country Bank, an institution with which the Company conducts business and has deposits.
(3)Messrs. John E. Crisp and Charles C. Forbes, Jr., executive officers and directors of FES Ltd., are owners of Alice Environmental Services, LP, or AES. The Company leases or rents land and buildings, disposal wells, aircraft, and other equipment from AES.
(4)Dorsal Services, Inc. provides trucking services to the Company. Mr. Crisp, an executive officer and director is a partial owner of Dorsal Services, Inc.
(5)Wolverine Construction, Inc. is an entity that is owned by two sons of Mr. Crisp, an executive officer and director of FES Ltd. Wolverine provided construction and site preparation services to certain customers of the Company.
(6)Tasco Tool Services, Inc. is a down-hole tool company that is partially owned and managed by a company that is owned by Mr. Forbes, both an executive officer and director of FES Ltd., along with Robert Jenkins a manager of one of the subsidiaries of FES Ltd. Tasco rents and sells tools to the Company from time to time.
(7)Resonant Technology Partners is a computer networking group that provides services to the Company. Travis Burris, a director of the Company had a noncontrolling interest in the computer networking company, which was sold in July 2012.
(8)JITSU Services, LLC or JITSU, is a financial leasing company owned by Janet Forbes, a director of the Company and Mr. Crisp. The Company currently leases ten vacuum trucks from JITSU.
(9)Texas Quality Gate Guard Services, LLC, or Texas Quality Gate Guard Services, is an entity owned by Messrs. Crisp and Forbes and a son of Mr. Crisp, an executive officer and director of FES Ltd. Texas Quality Gate Guard Services has provided security services to the Company.
(10)Energy Fishing and Rentals, Inc., or EFR, a specialty oilfield tool company that is partially owned by Messrs. Crisp and Forbes. EFR rents and sells tools to the company from time to time. Messrs. Crisp and Forbes sold their interest in EFR in November of 2011. Because they are no longer a related party no amounts have been disclosed for fiscal year 2013 or 2012.
(11)LA Contractors Ltd. is a bulk material hauling company partially owned by the sons of Mr. Crisp. The interest was sold January 2011 and the Company stopped using the services of LA Contractors by April 2012.
(12)CJ Petroleum Service LLC or CJ Petroleum, is a company that owns salt water disposal wells and is owned by Messrs. Crisp and Forbes, two sons of Mr. Crisp and Janet Forbes, a director of FES Ltd. The Company paid CJ Petroleum to purchase it's rights to certain disposal wells which are no longer being rented from CJ Petroleum. Nevertheless, the Company must still pay the underlying landowners for access to these wells.
(13)C.W. Hahl Lease, an oil and gas lease, is owned by Mr. Forbes. Mr. Forbes no longer owns this lease.
(14)Testco Well Services, LLC is a company that provides valve and gathering system testing services to the Company. Messrs. Crisp and Forbes, executive officers and directors of FES Ltd, along with a son of Mr. Crisp are partial owners of Testco. In August 2013, Testco Well Services, LLC was sold to an unrelated third party and as such is no longer a related party. The amounts for 2013 reflect only the period prior to the sale.
(15)FCJ Management, LLC or FCJ, is an entity that leases land and facilities to the Company and is owned by Messrs. Crisp, and Forbes and Robert Jenkins, a manager of one of the subsidiaries of FES Ltd.
(16)C&F Partners, LLC is an entity that is owned by Messrs. Crisp and Forbes. The Company had expenses with regard to C&F Partners, LLC related to aircraft rental.
(17)Animas Holdings, LLC or Animas, is a property and disposal company that is owned by the two sons of Mr. Crisp and three children of Mr. Forbes and Ms. Forbes. The Company pays Animas for waste water disposal and lease facilities.
(18) Texas Water Disposal, LLC. is partially owned by a brother of Mr. Crisp, an executive officer and director of FES Ltd. Texas Water Disposal, LLC is a company that owns a salt water disposal well that is used by the Company.
10. Commitments and Contingencies
Concentrations of Credit Risk
Financial instruments which subject the Company to credit risk consist primarily of cash balances maintained in excess of federal depository insurance limits and trade receivables. All of our non-interest bearing cash balances were fully insured at December 31, 2012 due to a temporary federal program in effect from December 31, 2010 through December 31, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts. In 2013, insurance coverage reverted to $250,000 per depositor at each financial institution, and our non-interest bearing cash balances exceeded federally insured limits. The Company restricts investment of temporary cash investments to financial institutions with high credit standings. The
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Company’s customer base consists primarily of multi-national and independent oil and natural gas producers. The Company does not require collateral on its trade receivables. For the year ended December 31, 2013 the Company’s largest customer, five largest customers, and ten largest customers constituted 10.5%, 34.6%, and 49.7% of total revenues, respectively. For the year ended December 31, 2012 the Company’s largest customer, five largest customers, and ten largest customers constituted 9.3%, 36.7%, and 57.5% of total revenues, respectively. For the year ended December 31, 2011 the Company’s largest customer, five largest, and ten largest customers constituted 15.5%, 42.3%, and 59.1% of total revenues, respectively. The loss of any one of our top five customers would have a materially adverse effect on the revenues and profits of the company. Further, our trade accounts receivable are from companies within the oil and natural gas industry and as such the Company is exposed to normal industry credit risks. As of December 31, 2013, the Company's largest customer, five largest customers, and ten largest customers constituted 8.6%, 21.0%, and 30.5% of accounts receivable, respectively. As of December 31, 2012, the Company's largest customer, five largest customers, and ten largest customers consisted of 12.6%, 38.4%, and 55.3% of accounts receivable, respectively. The Company continually evaluates its reserves for potential credit losses and establishes reserves for such losses.
Major Customers
Major customers are defined as 10.0% or more of total revenue during a year. The Company had one customer that represented over 10.5% of total revenues for the year ended December 31, 2013. The Company did not have any customer that represented 10.0% of total consolidated revenues for the year ended December 31, 2012. The Company had one customer that represented 15.5% of total consolidated revenues for the year ended December 31, 2011.
Employee Benefit Plan
In 2005, the Company has a 401(k) retirement plan for substantially all of its employees based on certain eligibility requirements. The Company may provide profit sharing contributions to the plan at the discretion of management. No such discretionary contributions have been made since inception of the plan.
Self-Insurance
The Company is self-insured under its Employee Group Medical Plan for the first $250,000 per individual and as of October 15, 2013, the Company purchased our Auto Liability and General Liability insurances and is now self-insured for the first $0.5 million and $1.0 million, respectively. Incurred and unprocessed claims under all policies as of December 31, 2013 and 2012 amount to approximately $1.2 million and $4.6 million, respectively. These claims are unprocessed; therefore their values are estimated and included in accrued expenses in the accompanying consolidated balance sheets. In addition, to accruals for the self-insured portion of the Employee Group Medical Benefits Plan, the liability for incurred and unprocessed claims also includes estimated “run off” liabilities payable at future dates related to the worker’s compensation, general liability and automobile liability self-insurance program that was eliminated in October 2009.
Litigation
The Company is subject to various other claims and legal actions that arise in the ordinary course of business. We do not believe that any of these claims and actions, separately or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations, or cash flows, although we cannot guarantee that a material adverse effect will not occur.
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Leases
Future minimum lease payments under non-cancellable operating leases as of December 31, 2013 are as follows (in thousands):
Related Party | Other | Total | |||||||||
2014 | $ | 1,922 | $ | 12,388 | $ | 14,309 | |||||
2015 | 1,552 | 10,299 | 11,851 | ||||||||
2016 | 1,536 | 5,003 | 6,539 | ||||||||
2017 | 1,144 | 694 | 1,838 | ||||||||
2018 | 416 | 6 | 422 | ||||||||
Thereafter | — | — | — | ||||||||
Total | $ | 6,570 | $ | 28,390 | $ | 34,959 |
Rent expense for the years ended December 31, 2013, 2012 and 2011 totaled approximately $20.8 million, $23.3 million and $22.5 million, respectively.
11. Supplemental Cash Flow Information
Years Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(in thousands) | |||||||||||
Cash paid for | |||||||||||
Interest | $ | 26,635 | $ | 26,458 | $ | 22,784 | |||||
Income tax | (281 | ) | 3,731 | 249 | |||||||
Supplemental schedule of non-cash investing and financing activities | |||||||||||
Financing of insurance notes | $ | 6,198 | $ | 11,237 | $ | 8,803 | |||||
Changes in accounts payable related to capital expenditures | 2,766 | (13,693 | ) | 11,083 | |||||||
Capital leases on equipment | 1,990 | 13,872 | 8,460 | ||||||||
Preferred stock dividends and accretion costs | (42 | ) | (42 | ) | (187 | ) | |||||
Change in deposit on assets held for sale | — | (13,700 | ) | — |
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12. Income Taxes
The geographical sources of income (loss) from continuing operations before income taxes for each of the three years ended December 31 were as follows:
2013 | 2012 | 2011 | |||||||||
(in thousands) | |||||||||||
Domestic | $ | (17,412 | ) | $ | 5,578 | $ | (23,246 | ) | |||
Foreign | — | — | — |
Income tax expense (benefit) included in the consolidated statements of operations for the years ended December 31 was as follows (in thousands):
2013 | 2012 | 2011 | |||||||||
(in thousands) | |||||||||||
Continuing operations: | |||||||||||
Current: | |||||||||||
Federal | $ | (48 | ) | $ | 351 | $ | — | ||||
State | 252 | 815 | 687 | ||||||||
Foreign | — | — | 196 | ||||||||
Total current income tax expense from continuing operations | $ | 204 | $ | 1,166 | $ | 883 | |||||
Deferred: | |||||||||||
Federal | $ | (4,865 | ) | $ | 2,103 | $ | (8,121 | ) | |||
State | 46 | 90 | 12 | ||||||||
Foreign | — | — | 2,549 | ||||||||
Total deferred income tax expense (benefit) from continuing operations | $ | (4,819 | ) | $ | 2,193 | $ | (5,560 | ) | |||
Total income tax expense (benefit) from continuing operations | $ | (4,615 | ) | $ | 3,359 | $ | (4,677 | ) | |||
Discontinued operations: | |||||||||||
Current: | |||||||||||
Federal | $ | — | $ | — | $ | — | |||||
State | — | — | |||||||||
Foreign | (88 | ) | 2,701 | 2,933 | |||||||
Total current income tax expense from discontinued operations | $ | (88 | ) | $ | 2,701 | $ | 2,933 | ||||
Deferred: | |||||||||||
Federal | $ | — | $ | (580 | ) | $ | 3,348 | ||||
State | — | — | — | ||||||||
Foreign | (158 | ) | (2,480 | ) | 18 | ||||||
Total deferred income tax expense (benefit) from discontinued operations | $ | (158 | ) | $ | (3,060 | ) | $ | 3,366 | |||
Total income tax expense (benefit) from discontinued operations | $ | (246 | ) | $ | (359 | ) | $ | 6,299 | |||
Total income tax expense (benefit) | $ | (4,861 | ) | $ | 3,000 | $ | 1,622 |
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The provision for income taxes attributable to loss from continuing operations differed from the amount obtained by applying the federal statutory income tax rate to loss from continuing operations before taxes, as follows:
2013 | 2012 | 2011 | |||||||||
(in thousands) | |||||||||||
Income tax expense (benefit) at statutory rate of 35% | $ | (6,094 | ) | $ | 1,952 | $ | (8,136 | ) | |||
Nondeductible expenses | 513 | 586 | 492 | ||||||||
State taxes, net of federal benefit | 354 | 619 | 459 | ||||||||
Foreign income taxes, net of federal benefit | — | — | 1,580 | ||||||||
Change in deferred tax valuation allowance | — | — | 899 | ||||||||
Revision related to tax basis of property and equipment | 553 | — | — | ||||||||
Foreign rate difference | — | — | (33 | ) | |||||||
Other | 59 | 202 | 62 | ||||||||
$ | (4,615 | ) | $ | 3,359 | $ | (4,677 | ) |
Our income tax expense (benefit) attributable to income (loss) from discontinued operations was ($0.2) million (45.6% effective rate) on pre-tax loss of $0.5 million for the year ended December 31, 2013, $(0.4) million (36.2% effective rate) on pre-tax loss of $1.0 million for the year ended December 31, 2012 and $6.3 million (50.3% effective rate) on pre-tax income of $12.5 million for the year ended December 31, 2011.
The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31 were as follows:
2013 | 2012 | ||||||
(in thousands) | |||||||
Deferred tax assets: | |||||||
Net operating loss carryforwards | $ | 17,814 | $ | 26,436 | |||
Foreign tax credits | 796 | 796 | |||||
Alternative minimum tax credit | 975 | 1,021 | |||||
Stock - based compensation | 5,505 | 4,853 | |||||
Bad debts | 1,392 | 931 | |||||
Other | 1,572 | 131 | |||||
Total gross deferred tax assets | 28,054 | 34,168 | |||||
Less: valuation allowance | (796 | ) | (796 | ) | |||
Total deferred tax assets, net | $ | 27,258 | $ | 33,372 | |||
Deferred tax liabilities: | |||||||
Tax over book depreciation | $ | (40,030 | ) | $ | (50,171 | ) | |
Intangible assets | (8,838 | ) | (9,788 | ) | |||
Other | — | — | |||||
Total gross deferred tax liabilities | (48,868 | ) | (59,959 | ) | |||
Net deferred tax liability | $ | (21,610 | ) | $ | (26,587 | ) |
We had a U.S. net operating loss carryforward at December 31, 2013 of approximately $50.7 million which is subject to expiration in various amounts from 2028 to 2031. We have no net operating loss carryforwards in Mexico at December 31, 2013. Realization of deferred tax assets associated with net operating loss carryforwards is dependent upon generating sufficient taxable income in the appropriate jurisdiction prior to their expiration. Management believes it is more likely than not that the U.S. deferred tax asset associated with the net operating loss carryforward will be realized through future taxable income or reversal of taxable temporary differences. The amount of net operating loss that was used in 2013 was $8.7 million for a current tax cash savings of $3.0 million.
As of December 31, 2013, Management has elected to claim a deduction for foreign income taxes rather than a foreign tax credit due to the existence of an overall foreign loss position and the lack of future foreign source income, as a result of a
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subsequent sale of the Mexican operations. A valuation allowance in the amount of $0.8 million has been established as of December 31, 2013 against the foreign tax credit generated in previous years.
Deferred taxes have not been recognized on undistributed earnings of foreign subsidiaries since these amounts were not material at December 31, 2013 and 2012.
The Company files U.S. federal, U.S. state, and foreign tax returns, and is generally no longer subject to tax examinations for fiscal years prior to 2009.
13. Earnings (loss) per Share
Basic net earnings (loss) per share is computed by dividing net income (loss) available to common shareholders by the weighted average shares of common stock outstanding during the period. Diluted earnings (loss) per share takes into account the potential dilution that could occur if securities or other contracts to issue common shares, such as options, unvested restricted stock and restricted stock units, and convertible preferred stock, were exercised and converted into common stock. Potential common stock equivalents that have been issued by the Company relate to outstanding stock options, unvested restricted stock and restricted stock units, which are determined using the treasury stock method, and to the shares of Series B Senior Convertible Preferred Stock (the "Series B Preferred Stock"), which are determined using the “if converted” method. In applying the if-converted method, conversion is not assumed for purposes of computing diluted EPS if the effect would be antidilutive. As of December 31, 2013 and 2012, there were 1,400,425 and 1,997,925 options to purchase common stock outstanding, and 588,059 and 588,059 Series B Senior Convertible Preferred Stock outstanding, respectively. The preferred stock is convertible at a rate of nine common shares to one share of Series B Preferred Stock.
The Company has determined that the Series B Preferred Stock are participating securities under ASC 260. Under ASC 260, a security is considered a participating security if the security may participate in undistributed earnings with common stock, whether the participation is conditioned upon the occurrence of a specified event or not. In accordance with ASC 260, a company is required to use the two-class method when computing EPS when a company has a security that qualifies as a “participating security.” The two-class method is an earnings allocation formula that determines EPS for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. A participating security is included in the computation of basic EPS using the two-class method. Under the two-class method, basic EPS for the Company’s common stock is computed by dividing net income applicable to common stock by the weighted-average common stock outstanding during the period. Under the certificate of designation for our Series B Preferred Stock (the "Series B Certificate of Designation"), if at any time the Company declares a dividend in cash which is greater in value than five percent on a cumulative basis over the previous twelve month period of the then current "Common Share Fair Market Value," as that term is defined in the Series B Certificate of Designation, the Series B Preferred Stock will be entitled to receive a dividend payable in cash equal to the amount in excess of five percent of the then Common Share Fair Market Value per common share they would have received if all outstanding Series B Preferred Stock had been converted into common shares. There were no earnings allocated to the Series B Preferred Stock for the years ended December 31, 2013, 2012, or 2011 and there was a net loss from operations for the years ended December 31, 2013 and 2011 and earnings for the year ended December 31, 2012 were not in excess of amounts prescribed by the Series B Certificate of Designation for our Series B Preferred Stock. Diluted EPS for the Company’s common stock is computed using the more dilutive of the two-class method or the if-converted method. The following table sets forth the reconciliation of weighted average shares outstanding and diluted weighted average shares outstanding, in thousands:
2013 | 2012 | 2011 | ||||
Weighted average shares outstanding | 21,388 | 21,062 | 20,918 | |||
Dilutive effect of stock options and restricted stock | — | 278 | — | |||
Diluted weighted average shares outstanding | 21,388 | 21,340 | 20,918 |
2013
There were 1,400,425 stock options, 674,789 units of unvested restricted stock units, and 5,292,531 shares of common stock equivalents underlying the series B Preferred stock outstanding as of December 31, 2013 that were not included in the calculation of diluted EPS because their effect would have been antidilutive.
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2012
For the year ended December 31, 2012, the 5,292,531 shares of common stock equivalents underlying the series B Preferred stock was not included in the calculation of diluted EPS because the effect would have been antidilutive.
2011
There were 2,285,425 stock options, no unvested restricted stock units, and 5,292,531 shares of common stock equivalents underlying the series B Preferred stock outstanding as of December 31, 2011 that were not included in the calculation of diluted EPS because their effect would have been antidilutive.
The following table sets forth the computation of basic and diluted loss per share:
Years Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(in thousands, except per share amounts) | |||||||||||
Basic: | |||||||||||
Net income (loss) | $ | (13,090 | ) | $ | 1,586 | $ | (12,345 | ) | |||
Preferred stock dividends and accretion | (776 | ) | (776 | ) | (186 | ) | |||||
Net income (loss) attributable to common shareholders | (13,866 | ) | 810 | (12,531 | ) | ||||||
Weighted-average common shares | 21,388 | 21,062 | 20,918 | ||||||||
Basic earnings (loss) per share | (0.65 | ) | 0.04 | (0.60 | ) | ||||||
Diluted: | |||||||||||
Net income (loss) | $ | (13,090 | ) | $ | 1,586 | $ | (12,345 | ) | |||
Preferred stock dividends and accretion | (776 | ) | (776 | ) | (186 | ) | |||||
Net income (loss) attributable to common shareholders | (13,866 | ) | 810 | (12,531 | ) | ||||||
Effect of dilutive securities | — | 278 | — | ||||||||
Weighted average common shares | 21,388 | 21,062 | 20,918 | ||||||||
Weighted-average diluted shares | 21,388 | 21,340 | 20,918 | ||||||||
Diluted earnings (loss) per share | $ | (0.65 | ) | $ | 0.04 | $ | (0.60 | ) |
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14. Business Segment Information
The Company has determined that it has two reportable segments organized based on its products and services—well servicing and fluid logistics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies.
Well Servicing
At December 31, 2013, our well servicing segment utilized our modern fleet of 167 owned well servicing rigs, which included 157 workover rigs and 10 swabbing rigs, five coiled tubing spreads, nine tubing testing units, and related assets and equipment. These assets are used to provide (i) well maintenance, including remedial repairs and removal and replacement of down-hole production, (ii) well workovers, including significant down-hole repairs, re-completions and re-perforations, (iii)completion and swabbing activities, (iv) plugging and abandonment services, and (v) pressure testing of oil and natural gas production tubing and scanning tubing for pitting and wall thickness using tubing testing units.
Fluid Logistics
The fluid logistics segment consists of operations in the U.S., which provide, transport, store and dispose of a variety of drilling and produced fluids used in and generated by oil and natural gas production activities. These services are required in most workover and completion projects and are routinely used in daily producing well operations.
The following table sets forth certain financial information from continuing operations with respect to the Company’s reportable segments (dollars in thousands):
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Well Servicing | Fluid Logistics | Consolidated | |||||||||
2013 | |||||||||||
Operating revenues | $ | 231,930 | $ | 188,003 | $ | 419,933 | |||||
Direct operating costs | 182,180 | 141,957 | 324,137 | ||||||||
Segment profits | $ | 49,750 | $ | 46,046 | $ | 95,796 | |||||
Depreciation and amortization | $ | 23,207 | $ | 31,631 | $ | 54,838 | |||||
Capital expenditures | 22,979 | 24,329 | 47,308 | ||||||||
Total assets | 584,271 | 483,771 | 1,068,042 | ||||||||
Long lived assets | 199,692 | 142,177 | 341,869 | ||||||||
2012 | |||||||||||
Operating revenues | $ | 202,670 | $ | 269,927 | $ | 472,597 | |||||
Direct operating costs | 158,302 | 196,383 | 354,685 | ||||||||
Segment profits | $ | 44,368 | $ | 73,544 | $ | 117,912 | |||||
Depreciation and amortization | $ | 22,902 | $ | 28,095 | $ | 50,997 | |||||
Capital expenditures | 28,494 | 83,454 | 111,948 | ||||||||
Total assets | 530,986 | 468,402 | 999,388 | ||||||||
Long lived assets | 200,296 | 148,146 | 348,442 | ||||||||
2011 | |||||||||||
Operating revenues | $ | 177,896 | $ | 267,887 | $ | 445,783 | |||||
Direct operating costs | 141,589 | 193,718 | 335,307 | ||||||||
Segment profits | $ | 36,307 | $ | 74,169 | $ | 110,476 | |||||
Depreciation and amortization | $ | 20,643 | $ | 19,017 | $ | 39,660 | |||||
Capital expenditures | 25,780 | 36,932 | 62,712 | ||||||||
Total assets | 482,381 | 377,488 | 859,869 | ||||||||
Long lived assets | 195,245 | 90,700 | 285,945 | ||||||||
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Reconciliation of the Forbes Group Operating Income (Loss) As Reported: | |||||||||||
Segment profits | $ | 95,796 | $ | 117,912 | $ | 110,476 | |||||
General and administrative expense | 30,186 | 33,382 | 31,318 | ||||||||
Depreciation and amortization | 54,838 | 50,997 | 39,660 | ||||||||
Operating income | 10,772 | 33,533 | 39,498 | ||||||||
Other income and expenses, net | (28,184 | ) | (27,955 | ) | (62,744 | ) | |||||
Income (loss) from continuing operations before taxes | $ | (17,412 | ) | $ | 5,578 | $ | (23,246 | ) |
December 31, | |||||||
2013 | 2012 | ||||||
Reconciliation of the Forbes Group Assets As Reported: | |||||||
Total reportable segments | $ | 1,068,042 | $ | 999,388 | |||
Elimination of internal transactions | (1,640,530 | ) | (1,510,855 | ) | |||
Parent | 1,073,046 | 1,024,168 | |||||
Total assets | $ | 500,558 | $ | 512,701 |
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15. Equity Securities
Common Stock
Holders of common stock have no pre-emptive, redemption, conversion, or sinking fund rights. Holders of common stock are entitled to one vote per share on all matters submitted to a vote of holders of common stock. Unless a different majority is required by law or by the bylaws, resolutions to be approved by holders of common stock require approval by a simple majority of votes cast at a meeting at which a quorum is present. In the event of the liquidation, dissolution, or winding up of the Company, the holders of common stock are entitled to share equally and ratably in the Company’s assets, if any, remaining after the payment of all of its debts and liabilities, subject to any liquidation preference on any issued and outstanding preferred stock.
Series B Senior Convertible Preferred Stock
Under our Certificate of Designation, we are authorized to issue 825,000 shares of Series B Senior Convertible Preferred Stock (the “Series B Preferred Stock”), par value $0.01 per share. On May 28, 2010 the Company completed a private placement of 580,800 shares of Series B Preferred Stock at a price per share of CAD $26.37 for an aggregate purchase price in the amount of USD $14.5 million based on the exchange rate between U.S. dollars and Canadian dollars then in effect of $1.00 to CDN $1.0547. The Company received net proceeds of USD $13.8 million after closing fee paid to investors of $0.3 million and legal fees and other offering costs of $0.4 million. This is presented as temporary equity on the balance sheet. The common stock into which the Series B Preferred Stock is convertible has certain demand and “piggyback” registration rights.
The Company paid a closing fee to the Investors of $0.3 million which is netted with the proceeds from the sale of the Series B Preferred Stock in temporary equity on the consolidated balance sheet. The value of the Series B Preferred Stock, for accounting purposes, is being accreted up to redemption value from the date of issuance to the earliest redemption date of the instrument using the effective interest rate method. If the Series B Preferred Stock had been redeemed as of December 31, 2013 and 2012, the redemption amount would have been approximately $14.6 million and $14.5 million.
The terms of the Series B Preferred Stock is as follows:
Rank - The Series B Preferred Stock ranks senior in right of payment to the common stock and any class or series of capital stock that is junior to the Series B Preferred Stock, and pari passu with any series of the Company's preferred stock that is by its terms ranks pari passu in right of payment as to dividends and liquidation with the Series B Preferred Stock.
Conversion - The Series B Preferred Stock is convertible into the Company's common stock at an initial rate of nine common shares per share of Series B Preferred Stock (as adjusted for the Share Consolidation) (subject to further adjustment). If all such Series B Preferred Stock is converted, at the initial conversion rate, 5,292,531 shares of common stock will be issued to holders of the Series B Preferred Stock. Notwithstanding the foregoing, pursuant to Certificate of Designation, no holder of the Series B Preferred Stock is entitled to effect a conversion of Series B Preferred Stock if such conversion would result in the holder (and affiliates) beneficially owning 20% or more of the Company's common stock. Redeemable preferred stock (and, if ever any other redeemable financial instrument we may enter into) is initially evaluated for possible classification as a liability or equity pursuant to ASC 480 - Distinguishing Liabilities from Equity. Redeemable preferred stock that does not, in its entirety, require liability classification is evaluated for embedded features that may require bifurcation and separate classification as derivative liabilities. In determining the appropriate accounting for the conversion feature for the Series B Preferred Stock, the Company determined that the conversion feature does not require bifurcation, and as a result is not considered a derivative under the provisions of ASC 815 - Derivatives and Hedging.
Dividends Rights - The Series B Preferred Stock is entitled to receive preferential dividends equal to five percent (5%) per annum of the original issue price per share, payable quarterly in February, May, August and November of each year. Such dividends may be paid by the Company in cash or in kind (in the form of additional shares of Series B Preferred Stock). In the event that the payment in cash or in kind of any such dividend would cause the Company to violate a covenant under its debt agreements, the obligation to pay, in cash or in kind, will be suspended until the earlier to occur of (i) and only to the extent any restrictions under the debt agreements lapse or are no longer applicable or (ii) February 16, 2015. During any such suspension period, the preferential dividends shall continue to accrue and accumulate. As shares of the Series B Preferred Stock are convertible into shares of our common stock, each dividend paid in kind will have a dilutive effect on our shares of common stock. Dividends for all quarterly
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periods in the years ended December 31, 2013 and 2012 have been paid in cash. The Company intends to pay all future dividends in cash.
Liquidation - Upon any voluntary or involuntary liquidation, dissolution or winding up of the Company, no distribution shall be made as follows:
(i) | to the holders of shares ranking junior to the Series B Preferred Stock unless the holders of Series B Preferred Stock shall have received an amount equal to the original issue price per share of the Series B Preferred Stock (subject to adjustment) plus an amount equal to accumulated and unpaid dividends and distributions thereon to the date of such payment, and |
(ii) | to the holders of shares ranking on a parity with the Series B Preferred Stock, unless simultaneously therewith distributions are made ratably on the Series B Preferred Stock and all other such parity stock in proportion to the total amounts to which the holders of Series B Preferred Stock are entitled. |
Voting Rights - The holders of Series B Preferred Stock are not entitled to any voting rights except as provided in the following sentence, in the Company's bylaws or otherwise under the Texas law. If the preferential dividends on the Series B Preferred Stock have not been declared and paid in full in cash or in kind for eight or more quarterly dividend periods (whether or not consecutive), the holders of the Series B Preferred Stock shall be entitled to vote at any meeting of shareholders with the holders of common stock and to cast the number of votes equal to the number of whole Common Shares into which the Series B Preferred Stock held by such holders are then convertible.
Redemption - All or any number of the shares of Series B Preferred Stock may be redeemed by the Company at any time after May 28, 2013 at a redemption price of $25 per share plus accrued and unpaid dividends and provided that the current equity value of our common stock exceeds a five day volume weighted average of $3.33 per share. On May 28, 2017, the Company is required to redeem any Series B Preferred Stock then outstanding at a redemption price determined in accordance with the Certificate of Designation plus accrued but unpaid dividends. Such mandatory redemption may, at the Company's election, be paid in cash or in common shares (valued for such purpose at 95% of the then fair market value of the common stock). In the event certain corporate transactions occur (such as a reorganization, recapitalization, reclassification, consolidation or merger) under which the Company's common stock (but not the Series B Preferred Stock) is converted into or exchanged for securities, cash or other property, then following such transaction, each share of Series B Preferred Stock shall thereafter be convertible into the same kind and amount of securities, cash or other property.
Certain of the redemption features are outside of the Company's control, and as a result, the Series B Preferred Stock have been reflected in the consolidated balance sheet as temporary equity.
Dividends
The Series B Preferred Stock is entitled to receive preferential dividends equal to five percent (5.0%) per annum of the original issue price per share, payable quarterly in February, May, August and November of each year. Such dividends may be paid by the Company in cash or in kind (in the form of additional shares of Series B Preferred Stock). In the event that the payment in cash or in kind of any such dividend would cause the Company to violate a covenant under its debt agreements, the obligation to pay, in cash or in kind, will be suspended until the earlier to occur of (i) and only to the extent any restrictions under the debt agreements lapse or are no longer applicable or (ii) February 16, 2015. During any such suspension period, the preferential dividends shall continue to accrue and accumulate. As shares of the Series B Preferred Stock are convertible into shares of our common stock, each dividend paid in kind will have a dilutive effect on our shares of common stock. Through the dividend quarterly period ended May 28, 2011 the Company had also accrued, but not paid dividends for the dividend period ended November 28, 2010, February 28, 2011, and May 28, 2011 due to the Toronto Stock Exchange requiring shareholder approval to issue shares to pay dividends in kind. The Company received shareholder approval to issue shares to pay dividends in kind. The Company received shareholder approval at its annual meeting on June 27, 2011 for a pool of Series B Preferred Stock to be issued as in-kind dividends for this particular quarterly period and for future quarterly periods. Further, after the extinguishment of the Second Priority Notes and the First Priority Notes, the Company was no longer restricted from paying cash dividends as the indenture governing the 9% Senior Notes specifically allowed cash dividends on the Series B Preferred Stock up to specific levels. On July 29, 2011, the Company paid in cash all previously accrued but unpaid dividends. The Company had previously accrued for these dividends based on the estimated fair market value of the share expected to be issued in-kind. When determined that the dividends were to be paid in cash, cumulative preferred share dividends were remeasured using the 5% contractual rate and released from temporary equity to liabilities.
Preferred stock dividends are recorded at their fair value. If paid in cash, the amount paid represents fair value. If paid in kind, the fair value of the preferred stock dividends is determined using valuation techniques that include a component representing the intrinsic value of the dividends (which represents the fair value of the common stock into which the preferred stock could be converted) and an option component (which is determined using a Black-Scholes Option Pricing Model).
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Dividends and accretion for the years ended December 31, 2013 and 2012 were $0.8 million and $0.8 million. The Company has paid the quarterly dividends through February 28, 2014.
16. Guarantor and Non-Guarantor Consolidating Financial Statements
Prior to January 12, 2012, when the Company completed the disposition of its business and substantially all of its assets in Mexico, the Company had certain foreign subsidiaries that did not guarantee the 9% Senior Notes discussed in Note 8 and, accordingly, is required to present the following condensed consolidating financial information pursuant to Rule 3-10 of Regulation S-X. These schedules are presented using the equity method of accounting for all periods presented. Under this method, investments in subsidiaries are recorded at cost and adjusted for the Company’s share in the subsidiaries’ cumulative results of operations, capital contributions and distributions and other changes in equity. Elimination entries relate primarily to the elimination of investments in subsidiaries and associated intercompany balances and transactions. As of December 31, 2013 and 2012, the subsidiaries that are guarantors are 100% owned directly or indirectly by FES Ltd, the guarantees are full and unconditional, joint and several, subject to customary release provisions.
There are no significant restrictions on FES Ltd.'s ability or the ability of any guarantor to obtain funds from its subsidiaries by such means as a dividend or loan.
As of December 31, 2013 and 2012, the parent/issuer had no independent assets and for the year ended December 31, 2013 and 2012 the parent/issuer had no independent operations. As of and for the year ended December 31, 2013 and 2012, independent assets and operations of the non-guarantor subsidiary were minor as defined by Regulation S-X.
Supplemental financial information for Forbes Energy Services Ltd., the issuer of the 9% Senior Notes, our combined subsidiary guarantors and our non-guarantor subsidiaries is presented below for the year ended December 31, 2011.
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Forbes Energy Services Ltd. and Subsidiaries (a/k/a the “Forbes Group”)
Condensed Consolidated Statement of Operations
For the year ended December 31, 2011
Parent/Issuer | Guarantors | Non- Guarantors | Eliminations | Consolidated | |||||||||||||||
(in thousands) | |||||||||||||||||||
Revenue | |||||||||||||||||||
Well servicing | $ | — | $ | 177,896 | $ | — | $ | — | $ | 177,896 | |||||||||
Fluid logistics | — | 267,887 | — | — | 267,887 | ||||||||||||||
Total revenues | — | 445,783 | — | — | 445,783 | ||||||||||||||
Expenses | |||||||||||||||||||
Well servicing | 1,473 | 140,116 | — | — | 141,589 | ||||||||||||||
Fluid logistics | — | 193,718 | — | — | 193,718 | ||||||||||||||
General and administrative | 7,142 | 24,176 | — | — | 31,318 | ||||||||||||||
Depreciation and amortization | — | 39,660 | — | — | 39,660 | ||||||||||||||
Total expenses | 8,615 | 397,670 | — | — | 406,285 | ||||||||||||||
Operating income (loss) | (8,615 | ) | 48,113 | — | — | 39,498 | |||||||||||||
Other income (expense) | |||||||||||||||||||
Interest expense - net | (14,971 | ) | (12,427 | ) | — | — | (27,398 | ) | |||||||||||
Equity in income (loss) of affiliates | 1,593 | — | — | (1,593 | ) | — | |||||||||||||
Loss on early extinguishment of debt | — | (35,415 | ) | — | — | (35,415 | ) | ||||||||||||
Other income (expense), net | — | 69 | — | — | 69 | ||||||||||||||
Income (loss) before taxes | (21,993 | ) | 340 | — | (1,593 | ) | (23,246 | ) | |||||||||||
Income tax benefit | (3,424 | ) | (1,253 | ) | — | — | (4,677 | ) | |||||||||||
Net income (loss) from continuing operations | (18,569 | ) | 1,593 | — | (1,593 | ) | (18,569 | ) | |||||||||||
Net income (loss) from discontinued operations, net of tax expense | 6,224 | — | — | — | 6,224 | ||||||||||||||
Net income (loss) | $ | (12,345 | ) | $ | 1,593 | $ | — | $ | (1,593 | ) | $ | (12,345 | ) |
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Forbes Energy Services Ltd. and Subsidiaries (a/k/a the “Forbes Group”)
Condensed Consolidated Statement of Cash Flows
For the year ended December 31, 2011
Parent/Issuer | Guarantors | Non- Guarantors | Consolidated | ||||||||||||
(in thousands) | |||||||||||||||
Cash flows from operating activities: | |||||||||||||||
Net cash provided by (used in) operating activities | $ | 10,380 | $ | (4,312 | ) | $ | (69 | ) | $ | 5,999 | |||||
Cash flows from investing activities: | |||||||||||||||
Proceeds from sale of property and equipment | — | 676 | — | 676 | |||||||||||
Restricted cash | — | (7,107 | ) | — | (7,107 | ) | |||||||||
Purchases of property and equipment | — | (58,206 | ) | — | (58,206 | ) | |||||||||
Change in deposits on assets held for sale | 13,700 | 13,700 | |||||||||||||
Net cash used in investing activities | — | (50,937 | ) | — | (50,937 | ) | |||||||||
Cash flows from financing activities: | |||||||||||||||
Payments on debt | — | (4,346 | ) | — | (4,346 | ) | |||||||||
Retirement of First and Second | |||||||||||||||
Priority Notes | — | (212,500 | ) | — | (212,500 | ) | |||||||||
Proceeds from issuance of | |||||||||||||||
Senior Notes | — | 280,000 | — | 280,000 | |||||||||||
Payments for debt issuance costs | — | (10,159 | ) | — | (10,159 | ) | |||||||||
Other | (919 | ) | — | — | (919 | ) | |||||||||
Net cash provided by (used in) financing activities | (919 | ) | 52,995 | — | 52,076 | ||||||||||
Effect of currency translation | (996 | ) | — | — | (996 | ) | |||||||||
Net increase (decrease) in cash | 8,465 | (2,254 | ) | (69 | ) | 6,142 | |||||||||
Cash and cash equivalents | |||||||||||||||
Beginning of year | 7,102 | 23,241 | 115 | 30,458 | |||||||||||
End of year | $ | 15,567 | $ | 20,987 | $ | 46 | $ | 36,600 |
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17. Discontinued Operations
On January 12, 2012, the Company completed the previously announced sale of substantially all of its assets located in Mexico, as well as its equity interest in Forbes Energy Services México Servicios de Personal, S. de R.L. de C.V., for aggregate cash consideration of approximately $30.0 million (excluding amounts paid to cover certain Mexican taxes). The Company recognized a gain on disposal of approximately $2.9 million this transaction.
The following table presents the results of discontinued operations:
Years Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(dollars in thousands) | |||||||||||
Revenues | $ | — | $ | 1,337 | $ | 71,471 | |||||
Expenses | |||||||||||
Direct costs | — | 2,882 | 54,154 | ||||||||
General and administrative | 534 | 2,408 | 2,642 | ||||||||
Depreciation and amortization | — | — | 2,172 | ||||||||
Total expenses | 534 | 5,290 | 58,968 | ||||||||
Operating income (loss) | (534 | ) | (3,953 | ) | 12,503 | ||||||
Interest income | — | — | 22 | ||||||||
Interest expense | (5 | ) | (3 | ) | (7 | ) | |||||
Other income | — | 2,964 | 5 | ||||||||
Income (loss) before income taxes | (539 | ) | (992 | ) | 12,523 | ||||||
Income tax expense (benefit) | (246 | ) | (359 | ) | 6,299 | ||||||
Net income (loss) | $ | (293 | ) | $ | (633 | ) | $ | 6,224 |
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18. Supplemental Financial Information Quarterly Financial Data (Unaudited)
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
(in thousands except for per share amounts) | |||||||||||||||
2013: | |||||||||||||||
Revenues | $ | 101,738 | $ | 103,682 | $ | 104,854 | $ | 109,659 | |||||||
Operating income (loss) | 3,631 | 5,921 | (1,523 | ) | 2,743 | ||||||||||
Net loss from continuing operations | (2,599 | ) | (666 | ) | (5,652 | ) | (3,880 | ) | |||||||
Preferred stock dividends | (194 | ) | (194 | ) | (194 | ) | (194 | ) | |||||||
Loss from continuing operations attributable to common shares | (2,793 | ) | (860 | ) | (5,846 | ) | (4,074 | ) | |||||||
Loss per share: | |||||||||||||||
Basic | (0.13 | ) | (0.04 | ) | (0.27 | ) | (0.19 | ) | |||||||
Diluted | (0.13 | ) | (0.04 | ) | (0.27 | ) | (0.19 | ) | |||||||
2012: | |||||||||||||||
Revenues | $ | 131,485 | $ | 119,785 | $ | 114,320 | $ | 107,007 | |||||||
Operating income | 15,450 | 12,438 | 5,297 | 348 | |||||||||||
Net income (loss) from continuing operations | 5,211 | 2,646 | (1,270 | ) | (4,369 | ) | |||||||||
Preferred stock dividends | (194 | ) | (194 | ) | (194 | ) | (194 | ) | |||||||
Income (loss) from continuing operations attributable to common shares | 5,017 | 2,452 | (1,464 | ) | (4,563 | ) | |||||||||
Earnings (loss) per share: | |||||||||||||||
Basic | 0.24 | 0.12 | (0.07 | ) | (0.22 | ) | |||||||||
Diluted | 0.20 | 0.10 | (0.07 | ) | (0.22 | ) |
Item 9. | Changes in or Disagreements with Accountants on Accounting and Financial Disclosure |
Not applicable.
Item 9A. | Controls and Procedures |
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our chief executive officer and chief financial officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2013. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended or the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SECs rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Based on the evaluation of our disclosure controls and procedures as of December 31, 2013, our chief executive officer and chief financial officer concluded that, as of such date, our disclosure controls and procedures over financial reporting were effective.
Management's Report on Internal Control Over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13(a)-15(f) or Rule15d-15(f) under the Exchange Act. Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of our financial reporting for external purposes in accordance with U.S. generally accepted accounting principles. Internal control over financial reporting includes maintaining
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records that, in reasonable detail, accurately and fairly reflect our transactions; providing reasonable assurance that transactions are recorded as necessary for preparation of our financial statements in accordance with U.S. generally accepted accounting principles; providing reasonable assurance that receipts and expenditures of company assets are made in accordance with authorizations of the Company’s management and board of directors; and providing reasonable assurance that unauthorized acquisition, use or disposition of company assets that could have a material effect on our financial statements would be prevented or detected on a timely basis.
Our management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the evaluation of our internal control over financial reporting as of December 31, 2013, our chief executive officer and chief financial officer concluded that, as of such date, our internal control over financial reporting is effective.
Changes in Internal Control Over Financial Reporting
Other than changes and remediation measures described in this section, no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the fourth quarter of 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Material Weakness Previously Identified
As previously reported in our annual report on Form 10-K for the year ended December 31, 2012, we identified control deficiencies that constituted material weaknesses in the design and operation of our internal control over financial reporting.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis.
The following material weakness was present at December 31, 2012 and 2011.
We did not design or maintain effective controls over the billing process to ensure timely recognition of revenue. Specifically, we identified field tickets, which represented completed but unbilled revenue that had not been entered resulting in a post-closing adjustment.
This control deficiency could have resulted in a material misstatement to the annual or interim combined financial statements that would not be prevented or detected. Accordingly, we determined that the above control deficiency represented a material weakness.
The following material weakness was present at December 31, 2012.
We did not design and maintain effective controls over the review of the accuracy of the income tax provision related to foreign taxes.
This control deficiency could have resulted in a misstatement to the annual consolidated financial statements, however, it was corrected in a post-closing adjustment. Accordingly, we determined that the above control deficiency represented a material weakness.
Remediation
We have subsequently modified the design of our information system, process, and procedures which we believe addressed the material weakness relating to our billing process. The new processes and procedures were communicated to senior management and to the field personnel. These processes and procedures have been tested and are being continuously monitored. As such, we believe that the remediation initiative outlined above was sufficient to remediate the material weakness in internal control over financial reporting as discussed above during the fourth quarter of 2013.
Additionally, we have implemented remedial measures to address the our material weakness in our internal controls related to foreign taxes. We engaged a third party consulting group to assist with foreign tax matters as tax matters in Mexico wind down. In January 2012, the Company completed the sale of substantially liquidated in 2012 resulting in limited foreign
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tax expense or benefit for future periods. We believe that the remediation initiative outlined above was sufficient to remediate the material weakness in internal control over financial reporting as discussed above during the first quarter of 2013.
Item 9B. | Other Information |
On March 25, 2014, the Company entered into new indemnification agreements with its directors, officers and certain key employees pursuant to a form updated to reflect the Company’s status as a Texas corporation.
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PART III
Item 10. | Directors, Executive Officers and Corporate Governance |
The information required under this item will be filed in a definitive proxy statement within 120 days after December 31, 2013 pursuant to General Instruction G(3) of Form 10-K.
Item 11. | Executive Compensation |
The information required under this item will be filed in a definitive proxy statement within 120 days after December 31, 2013 pursuant to General Instruction G(3) of Form 10-K.
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The information required under this item will be filed in a definitive proxy statement within 120 days after December 31, 2013 pursuant to General Instruction G(3) of Form 10-K.
Item 13. | Certain Relationships and Related Transaction, and Director Independence |
The information required under this item will be filed in a definitive proxy statement within 120 days after December 31, 2013 pursuant to General Instruction G(3) of Form 10-K.
Item 14. | Principal Accounting Fees and Services |
The information required under this item will be filed in a definitive proxy statement within 120 days after December 31, 2013 pursuant to General Instruction G(3) of Form 10-K.
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PART IV
Item 15. | Exhibits, Financial Statement Schedules |
(a) | The following items are filed as part of this report: |
1. | Financial Statements. The financial statements and information required by Item 8 appear on pages 44 through 83 of this report. The Index to Consolidated Financial Statements appears on page 44. |
2. | Financial Statement Schedules. All schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes thereto. |
3. | Exhibits. |
Number | Description of Exhibits | |
2.1 — | Plan of Conversion of Forbes Energy Services Ltd. (incorporated by reference to Exhibit 2.1 to the Company’s Registration Statement on Form 8-A filed August 12, 2011). | |
2.2 — | Certificate of Conversion of Forbes Energy Services Ltd. (incorporated by reference to Exhibit 2.2 to the Company’s Registration Statement on Form 8-A filed August 12, 2011). | |
3.1 — | Certificate of Formation of Forbes Energy Services Ltd. (including the certificates of designation for the Company’s Series A Preferred Stock and Series B Preferred Stock attached as appendices thereto) (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form 8-A filed August 12, 2011). | |
3.2 — | Amended and Restated Bylaws of Forbes Energy Services Ltd. (incorporated by reference to Exhibit 3.2 to the Company’s Registration Statement on Form 8-A filed August 12, 2011). | |
4.1 — | Indenture, dated as of February 12, 2008 among Forbes Energy Services LLC and Forbes Energy Capital Inc., as issuers, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008). | |
4.2 — | Supplemental Indenture (First Supplemental Indenture), dated as of May 29, 2008 among Forbes Energy Services Ltd., Forbes Energy Services LLC, Forbes Energy Capital Inc., the other Guarantors (as defined in the Indenture referred to therein) and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008). | |
4.3 — | Supplemental Indenture (Second Supplemental Indenture, dated as of October 6, 2008 among Forbes Energy Services Ltd., Forbes Energy Services LLC, Forbes Energy Capital Inc., the other Guarantors (as defined in the Indenture referred to therein) and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008). | |
4.4 — | Third Supplemental Indenture, dated as of February 6, 2009 among Forbes Energy Services Ltd., Forbes Energy Services LLC, Forbes Energy Capital Inc., the other Guarantors (as defined in the Indenture referred to therein) and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated February 6, 2009). | |
4.5 — | Fourth Supplemental Indenture, dated as of May 24, 2011, among Forbes Energy Services Ltd., Forbes Energy Services LLC, Forbes Energy Capital Inc., the other guarantors (as defined therein) and Wells Fargo Bank, National Association, as trustee and collateral agent (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated May 20, 2011). | |
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Number | Description of Exhibits | |
4.6 — | Indenture dated as of October 2, 2009, by and among Forbes Energy Services LLC and Forbes Energy Capital Inc., as issuers, the guarantors party thereto and Wilmington Trust FSB, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated October 10, 2009). | |
4.7 — | Notation of Guarantee from Forbes Energy Services Ltd. (incorporated by reference to Exhibit 4.5 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008). | |
4.8 — | Notation of Guarantee from Forbes Energy International, LLC (incorporated by reference to Exhibit 4.6 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008). | |
4.9 — | Specimen 144A Global 11% Senior Secured Exchange Note due 2015 (incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
4.10 — | Rights Agreement dated as of May 19, 2008 between Forbes Energy Services Ltd. and CIBC Mellon Trust Company, as Rights Agent, which includes as Exhibit A the Certificate of Designations of Series A Junior Participating Preferred Shares, as Exhibit B the form of Right Certificate and as Exhibit C the form of Summary of Rights to Purchase Shares (incorporated by reference to Exhibit 4.8 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
4.11 — | Indenture dated June 7, 2011, among Forbes Energy Services Ltd., as issuer, the guarantors party thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed June 7, 2011). | |
4.12 — | Amended and Restated Certificate of Designation of the Series B Senior Convertible Preferred Shares (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed January 25, 2011). | |
4.13 — | Specimen Certificate for the Company’s common stock, $0.04 par value (incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form 8-A filed August 12, 2011). | |
4.14 — | Specimen Global 9% Senior Note Due 2019 (incorporated by reference to Exhibit 4.15 to the Company’s Registration Statement on Form S-4/A filed October 6, 2011, Registration No. 333-176794-5). | |
10.1 — | Forbes Energy Services Ltd. Incentive Compensation Plan effective May 19, 2008 (incorporated by reference to Exhibit 10.1 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
10.2 — | Amendment to 2008 Incentive Compensation Plan (incorporated by reference to Exhibit 10.18 to the Company’s Registration Statement on Form S-4/A filed on August 8, 2011, Registration No. 333-170741). | |
10.3 — | Employment Agreement effective May 1, 2008 by and between John E. Crisp and Forbes Energy Services LLC (incorporated by reference to Exhibit 10.2 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
10.4 — | Employment Agreement effective May 1, 2008 by and between Charles C. Forbes and Forbes Energy Services LLC (incorporated by reference to Exhibit 10.3 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
10.5 — | Employment Agreement effective May 1, 2008 by and between L. Melvin Cooper and Forbes Energy Services LLC (incorporated by reference to Exhibit 10.4 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
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Number | Description of Exhibits | |
10.6 — | Form of Indemnification Agreement for directors, officers and key employees (incorporated by reference to Exhibit 10.5 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
10.7 — | Form of Executive Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.6 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
10.8 — | Form of Director Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.7 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
10.9 — | Subscription Agreement dated as of May 17, 2010, by and among Forbes Energy Services Ltd., West Face Long Term Opportunities Limited Partnership, West Face Long Term Opportunities (USA) Limited Partnership and West Face Long Term Opportunities Master Fund L.P, including the Form of Certificate of Designation of Series B Senior Convertible Preferred Shares and Form of Registration Rights Agreement attached as exhibits thereto (incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010). | |
10.10 — | Registration Rights Agreement dated as of May 28, 2010 between Forbes Energy Services Ltd. and the Shareholders listed therein (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 28, 2010). | |
10.11 — | Loan and Security Agreement, dated as of September 9, 2011, by and among Forbes Energy Services LLC, Forbes Energy International, LLC, TX Energy Services, LLC, C.C. Forbes, LLC and Superior Tubing Testers, LLC, as borrowers, Forbes Energy Services Ltd., as guarantor, certain lenders party thereto, and Regions Bank, as administrative agent for the lenders (incorporated by reference to Exhibit 10.15 to the Company’s Registration Statement on Form S-4 filed September 13, 2011, Registration No. 333-176794). | |
10.12 — | Asset and Membership Interest Purchase Agreement dated December 8, 2011, by and among Forbes Energy Services Ltd., Forbes Energy Services LLC, Forbes Energy International, LLC, C.C. Forbes, LLC, Forbes Energy Services de México, S. de R. L. de C.V., Dirivera Investments LLC and RGV Holding, S.A. de C.V (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed December 13, 2011).** | |
10.13 — | First Amendment to Loan and Security Agreement, dated as of December 13, 2011, by and among Forbes Energy Services LLC, Forbes Energy International, LLC, TX Energy Services, LLC, C.C. Forbes, LLC and Superior Tubing Testers, LLC, as borrowers, Forbes Energy Services Ltd., as guarantor, certain lenders party thereto, and Regions Bank, as administrative agent for the lenders (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed December 19, 2011). | |
10.14 — | First Amendment to Asset and Membership Interest Purchase Agreement, dated as of December 23, 2011, by and among Forbes Energy Services Ltd., Forbes Energy Services LLC, Forbes Energy International, LLC, C.C. Forbes, LLC, Forbes Energy Services de México, S. de R. L. de C.V., Dirivera Investments LLC and RGV Holding, S.A. de C.V. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed December 28, 2011). | |
10.15 — | Letter Agreement, dated January 12, 2012, by and among Forbes Energy Services Ltd., Forbes Energy Services LLC, Forbes Energy International, LLC, C.C. Forbes, LLC, Forbes Energy Services de México, S. de R. L. de C.V., Dirivera Investments LLC, RGV Holding, S.A. de C.V. and RGV Enterprises S.A. de C.V. (incorporated by reference to exhibit 10.1 to the Company's Current Report on Form 8-K filed January 18, 2012). | |
10.16 — | Master Agreement dated June 6, 2012 among TX Energy Services, LLC, C.C. Forbes, LLC, Regions Equipment Finance Corporation, and Regions Commercial Equipment Finance, LLC, including the First Amendment to Master Agreement dated as of July 12, 2012 (incorporated by reference to exhibit 10.3 to the Company's Quarterly Report on form 10-Q for the quarter ended June 30, 2012). | |
82
Number | Description of Exhibits | |
10.17 — | Continuing Guaranty Agreement dated June 6, 2012 among Forbes Energy Services Ltd., TX Energy Services, LLC< C.C. Forbes, LLC, Regions Equipment Finance Corporation and Regions Commercial Equipment Finance, LLC (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012). | |
10.18 — | Second Amendment to Loan and Security Agreement, dated as of July 3, 2012, by and among Forbes Energy Services LLC, Forbes Energy International, LLC, TX Energy Services, LLC, C.C. Forbes, LLC, and Superior Tubing Testers, LLC, as borrowers, Forbes Energy Services Ltd., as guarantor, certain lender party thereto, and Regions Bank, as administrative agent for the lenders (incorporated by reference to Exhibit 10.1 to the Company's Current Report on form 8-K filed July 10, 2012). | |
10.19 — | 2012 Incentive Compensation Plan of Forbes Energy Services Ltd. (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed on July 10, 2012). | |
10.20* — | Form of Restricted Stock Award Agreement for directors. | |
10.21 — | Form of Restricted Stock Award Agreement for consultants and employees (incorporated by reference to Exhibit 10.24 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012). | |
10.22 — | Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.25 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012). | |
10.23 — | Annual Bonus Plan (incorporated by reference to Exhibit 10.26 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012). | |
10.24* — | Form of Texas Indemnification Agreement for directors, officers, and key employees. | |
21.1* — | Subsidiaries of Forbes Energy Services Ltd. | |
23.1* — | Consent of BDO USA, LLP. | |
31.1* — | Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a). | |
31.2* — | Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a). | |
32.1* — | Certification of Chief Executive Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
32.2* — | Certification of Chief Financial Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
101* — | Interactive Data Files |
____________________
* | Filed herewith. |
** | The schedules and other attachments to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K and the registrant undertakes to furnish supplementally copies of any of the omitted schedules upon request by the Securities and Exchange Commission. |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Alice, the State of Texas, on March 26, 2014.
83
FORBES ENERGY SERVICES LTD. | ||
By: | /S/ JOHN E. CRISP | |
John E. Crisp | ||
President and Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature | Title | Date | ||
/s/ JOHN E. CRISP (John E. Crisp) | Chairman of the Board, President, Chief Executive Officer and Director (Principal Executive Officer) | March 26, 2014 | ||
/s/ L. MELVIN COOPER (L. Melvin Cooper) | Senior Vice President, Chief Financial Officer and Secretary (Principal Financial and Accounting Officer) | March 26, 2014 | ||
/s/ CHARLES C. FORBES (Charles C. Forbes) | Director | March 26, 2014 | ||
/s/ DALE W. BOSSERT (Dale W. Bossert) | Director | March 26, 2014 | ||
/s/ TRAVIS H. BURRIS (Travis H. Burris) | Director | March 26, 2014 | ||
/s/ JANET L. FORBES (Janet L. Forbes) | Director | March 26, 2014 | ||
/s/ WILLIAM W. SHERRILL (William W. Sherrill) | Director | March 26, 2014 | ||
/s/ TED W. IZATT (Ted W. Izatt) | Director | March 26, 2014 |
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EXHIBIT INDEX
Number | Description of Exhibits | |
2.1 — | Plan of Conversion of Forbes Energy Services Ltd. (incorporated by reference to Exhibit 2.1 to the Company’s Registration Statement on Form 8-A filed August 12, 2011). | |
2.2 — | Certificate of Conversion of Forbes Energy Services Ltd. (incorporated by reference to Exhibit 2.2 to the Company’s Registration Statement on Form 8-A filed August 12, 2011). | |
3.1 — | Certificate of Formation of Forbes Energy Services Ltd. (including the certificates of designation for the Company’s Series A Preferred Stock and Series B Preferred Stock attached as appendices thereto) (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form 8-A filed August 12, 2011). | |
3.2 — | Amended and Restated Bylaws of Forbes Energy Services Ltd. (incorporated by reference to Exhibit 3.2 to the Company’s Registration Statement on Form 8-A filed August 12, 2011). | |
4.1 — | Indenture, dated as of February 12, 2008 among Forbes Energy Services LLC and Forbes Energy Capital Inc., as issuers, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008). | |
4.2 — | Supplemental Indenture (First Supplemental Indenture), dated as of May 29, 2008 among Forbes Energy Services Ltd., Forbes Energy Services LLC, Forbes Energy Capital Inc., the other Guarantors (as defined in the Indenture referred to therein) and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008). | |
4.3 — | Supplemental Indenture (Second Supplemental Indenture, dated as of October 6, 2008 among Forbes Energy Services Ltd., Forbes Energy Services LLC, Forbes Energy Capital Inc., the other Guarantors (as defined in the Indenture referred to therein) and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008). | |
4.4 — | Third Supplemental Indenture, dated as of February 6, 2009 among Forbes Energy Services Ltd., Forbes Energy Services LLC, Forbes Energy Capital Inc., the other Guarantors (as defined in the Indenture referred to therein) and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated February 6, 2009). | |
4.5 — | Fourth Supplemental Indenture, dated as of May 24, 2011, among Forbes Energy Services Ltd., Forbes Energy Services LLC, Forbes Energy Capital Inc., the other guarantors (as defined therein) and Wells Fargo Bank, National Association, as trustee and collateral agent (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated May 20, 2011). | |
4.6 — | Indenture dated as of October 2, 2009, by and among Forbes Energy Services LLC and Forbes Energy Capital Inc., as issuers, the guarantors party thereto and Wilmington Trust FSB, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated October 10, 2009). | |
4.7 — | Notation of Guarantee from Forbes Energy Services Ltd. (incorporated by reference to Exhibit 4.5 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008). | |
4.8 — | Notation of Guarantee from Forbes Energy International, LLC (incorporated by reference to Exhibit 4.6 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008). | |
85
Number | Description of Exhibits | |
4.9 — | Specimen 144A Global 11% Senior Secured Exchange Note due 2015 (incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
4.10 — | Rights Agreement dated as of May 19, 2008 between Forbes Energy Services Ltd. and CIBC Mellon Trust Company, as Rights Agent, which includes as Exhibit A the Certificate of Designations of Series A Junior Participating Preferred Shares, as Exhibit B the form of Right Certificate and as Exhibit C the form of Summary of Rights to Purchase Shares (incorporated by reference to Exhibit 4.8 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
4.11 — | Indenture dated June 7, 2011, among Forbes Energy Services Ltd., as issuer, the guarantors party thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed June 7, 2011). | |
4.12 — | Amended and Restated Certificate of Designation of the Series B Senior Convertible Preferred Shares (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed January 25, 2011). | |
4.13 — | Specimen Certificate for the Company’s common stock, $0.04 par value (incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form 8-A filed August 12, 2011). | |
4.14 — | Specimen Global 9% Senior Note Due 2019 (incorporated by reference to Exhibit 4.15 to the Company’s Registration Statement on Form S-4/A filed October 6, 2011, Registration No. 333-176794-5). | |
10.1 — | Forbes Energy Services Ltd. Incentive Compensation Plan effective May 19, 2008 (incorporated by reference to Exhibit 10.1 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
10.2 — | Amendment to 2008 Incentive Compensation Plan (incorporated by reference to Exhibit 10.18 to the Company’s Registration Statement on Form S-4/A filed on August 8, 2011, Registration No. 333-170741). | |
10.3 — | Employment Agreement effective May 1, 2008 by and between John E. Crisp and Forbes Energy Services LLC (incorporated by reference to Exhibit 10.2 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
10.4 — | Employment Agreement effective May 1, 2008 by and between Charles C. Forbes and Forbes Energy Services LLC (incorporated by reference to Exhibit 10.3 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
10.5 — | Employment Agreement effective May 1, 2008 by and between L. Melvin Cooper and Forbes Energy Services LLC (incorporated by reference to Exhibit 10.4 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
10.6 — | Form of Indemnification Agreement for directors, officers and key employees (incorporated by reference to Exhibit 10.5 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
10.7 — | Form of Executive Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.6 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
10.8 — | Form of Director Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.7 to the Company’s Registration Statement on Form S-4/A filed June 27, 2008, Registration No. 333-150853). | |
86
Number | Description of Exhibits | |
10.9 — | Subscription Agreement dated as of May 17, 2010, by and among Forbes Energy Services Ltd., West Face Long Term Opportunities Limited Partnership, West Face Long Term Opportunities (USA) Limited Partnership and West Face Long Term Opportunities Master Fund L.P, including the Form of Certificate of Designation of Series B Senior Convertible Preferred Shares and Form of Registration Rights Agreement attached as exhibits thereto (incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010). | |
10.10 — | Registration Rights Agreement dated as of May 28, 2010 between Forbes Energy Services Ltd. and the Shareholders listed therein (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 28, 2010). | |
10.11 — | Loan and Security Agreement, dated as of September 9, 2011, by and among Forbes Energy Services LLC, Forbes Energy International, LLC, TX Energy Services, LLC, C.C. Forbes, LLC and Superior Tubing Testers, LLC, as borrowers, Forbes Energy Services Ltd., as guarantor, certain lenders party thereto, and Regions Bank, as administrative agent for the lenders (incorporated by reference to Exhibit 10.15 to the Company’s Registration Statement on Form S-4 filed September 13, 2011, Registration No. 333-176794). | |
10.12 — | Asset and Membership Interest Purchase Agreement dated December 8, 2011, by and among Forbes Energy Services Ltd., Forbes Energy Services LLC, Forbes Energy International, LLC, C.C. Forbes, LLC, Forbes Energy Services de México, S. de R. L. de C.V., Dirivera Investments LLC and RGV Holding, S.A. de C.V (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed December 13, 2011).** | |
10.13 — | First Amendment to Loan and Security Agreement, dated as of December 13, 2011, by and among Forbes Energy Services LLC, Forbes Energy International, LLC, TX Energy Services, LLC, C.C. Forbes, LLC and Superior Tubing Testers, LLC, as borrowers, Forbes Energy Services Ltd., as guarantor, certain lenders party thereto, and Regions Bank, as administrative agent for the lenders (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed December 19, 2011). | |
10.14 — | First Amendment to Asset and Membership Interest Purchase Agreement, dated as of December 23, 2011, by and among Forbes Energy Services Ltd., Forbes Energy Services LLC, Forbes Energy International, LLC, C.C. Forbes, LLC, Forbes Energy Services de México, S. de R. L. de C.V., Dirivera Investments LLC and RGV Holding, S.A. de C.V. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed December 28, 2011). | |
10.15 — | Letter Agreement, dated January 12, 2012, by and among Forbes Energy Services Ltd., Forbes Energy Services LLC, Forbes Energy International, LLC, C.C. Forbes, LLC, Forbes Energy Services de México, S. de R. L. de C.V., Dirivera Investments LLC, RGV Holding, S.A. de C.V. and RGV Enterprises S.A. de C.V. (incorporated by reference to exhibit 10.1 to the Company's Current Report on Form 8-K filed January 18, 2012). | |
10.16 — | Master Agreement dated June 6, 2012 among TX Energy Services, LLC, C.C. Forbes, LLC, Regions Equipment Finance Corporation, and Regions Commercial Equipment Finance, LLC, including the First Amendment to Master Agreement dated as of July 12, 2012 (incorporated by reference to exhibit 10.3 to the Company's Quarterly Report on form 10-Q for the quarter ended June 30, 2012). | |
10.17 — | Continuing Guaranty Agreement dated June 6, 2012 among Forbes Energy Services Ltd., TX Energy Services, LLC< C.C. Forbes, LLC, Regions Equipment Finance Corporation and Regions Commercial Equipment Finance, LLC (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012). | |
10.18 — | Second Amendment to Loan and Security Agreement, dated as of July 3, 2012, by and among Forbes Energy Services LLC, Forbes Energy International, LLC, TX Energy Services, LLC, C.C. Forbes, LLC, and Superior Tubing Testers, LLC, as borrowers, Forbes Energy Services Ltd., as guarantor, certain lender party thereto, and Regions Bank, as administrative agent for the lenders (incorporated by reference to Exhibit 10.1 to the Company's Current Report on form 8-K filed July 10, 2012). |
87
Number | Description of Exhibits | |
10.19 — | 2012 Incentive Compensation Plan of Forbes Energy Services Ltd. (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed on July 10, 2012). | |
10.20* — | Form of Restricted Stock Award Agreement for directors | |
10.21 — | Form of Restricted Stock Award Agreement for consultants and employees (incorporated by reference to Exhibit 10.24 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012). | |
10.22 — | Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.25 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012). | |
10.23 — | Annual Bonus Plan (incorporated by reference to Exhibit 10.26 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012). | |
10.24* — | Form of Texas Indemnification Agreement for directors, officers and key employees. | |
21.1* — | Subsidiaries of Forbes Energy Services Ltd | |
23.1* — | Consent of BDO USA, LLP. | |
31.1* — | Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a). | |
31.2* — | Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a). | |
32.1* — | Certification of Chief Executive Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
32.2* — | Certification of Chief Financial Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
101* — | Interactive Data Files. |
____________________
* | Filed herewith. |
** | The schedules and other attachments to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K and the registrant undertakes to furnish supplementally copies of any of the omitted schedules upon request by the Securities and Exchange Commission. |
88