UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K

 

Commission file number: 000-25142

Mitcham Industries, Inc.

(Exact name of registrant as specified in its charter)

 

 

936-291-2277
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:

 

 

Securities registered pursuant to Section 12(g) of the Act:

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     No þ

 

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 o     No þ

 

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.  Yes þ     No o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the proceeding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o     No o

 

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 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.

 

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.

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ

 

As of July 31, 2010, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $68,264,499 based on the closing sale price as reported on the National Association of Securities Dealers Automated Quotation System National Market System.

 

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

 

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the definitive proxy statement of Mitcham Industries, Inc. for the 2011 Annual Meeting of Shareholders, which will be filed within 120 days of January 31, 2011, are incorporated by reference into Part III of this Annual Report on Form 10-K.

 

 

MITCHAM INDUSTRIES, INC.
ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

 

 

Certain statements contained in this Annual Report on Form 10-K (this “Form-10-K”) may be deemed to be forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and Section 27A of the Securities Act of 1933, as amended (the “Securities Act”). This information includes, without limitation, statements concerning:

 

 

Although we believe that the expectations reflected in these forward-looking statements are reasonable, we can not assure you that these expectations will prove to be correct. When used in this Form 10-K, the words “anticipate,” “believe,” “estimate,” “expect,” “may” and similar expressions, as they relate to our company and management, are intended to identify forward-looking statements. The actual results of future events described in these forward-looking statements could differ materially from the results described in the forward-looking statements due to risks and uncertainties, including those set forth in Item 1A — “Risk Factors,” Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere within this Form 10-K and in our reports and registration statement filed with the Securities and Exchange Commission (“SEC”) and other announcements we make from time to time. We caution readers to not place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any of these forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

 

 

We operate in two business segments, equipment leasing (“Equipment Leasing”) and equipment manufacturing. Our equipment manufacturing segment is conducted by our Seamap subsidiaries and, therefore, is referred to in this Form 10-K as our “Seamap” segment. Mitcham Industries, Inc. (“MII”), a Texas corporation, was incorporated in 1987.

 

Our Equipment Leasing segment is engaged in the leasing of seismic equipment to companies in the oil and gas industry throughout the world. We conduct our leasing business through MII, through our wholly-owned subsidiaries and through our branches in Colombia and Peru. We are also engaged in the sale of new and used seismic equipment and in the design, manufacture and sale of marine seismic equipment. The subsidiaries that conduct our leasing business are Mitcham Canada Ltd (“MCL”), Seismic Asia Pacific Pty Ltd. (“SAP”), Mitcham Seismic Eurasia LLC (“MSE”), and Absolute Equipment Solutions, Inc. (“AES”). We acquired AES in March 2010. AES, which is located in Calgary, Alberta, Canada, produces, leases and sells “heli-pickers” and related equipment. This equipment is utilized by seismic contractors and helicopter operators to more efficiently and safely deploy and retrieve seismic equipment in the field. See Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information about the acquisition of AES.

 

Our Equipment Leasing segment also sells new and used seismic equipment from time to time and, through SAP, leases and sells oceanographic and hydrographic equipment, primarily in the Pacific Rim.

 

Our Seamap segment, or “Seamap,” is engaged in the design, production and sale of marine seismic equipment. The operations of this segment are conducted through wholly-owned subsidiaries, Seamap (UK) Ltd (“Seamap UK”) and Seamap Pte. Ltd (“Seamap Singapore”).

 

For additional information about our business segments, including related financial information, see Note 13 to our consolidated financial statements and Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-K.

 

We lease and sell geophysical and other equipment used primarily by seismic data acquisition contractors to perform seismic data acquisition surveys on land, in transition zones (marsh and shallow water areas) and marine areas. We conduct our operations on a worldwide basis and believe that we are the world’s largest independent lessor of seismic equipment. We believe that our competitors, in general, do not have as extensive a seismic equipment lease pool as ours, as broad of geographic presence as we do and do not have similar exclusive lease referral agreements with seismic equipment suppliers.

 

Prior to the Fall of 2008, we had experienced an extended period of growth in our business, as had most businesses involved in providing seismic related goods and services. This growth was, we believe, driven primarily by worldwide oil and gas exploration activity, which was in turn driven by the demand for oil and gas and historically high prices for oil and natural gas. With the global economic and financial crisis that arose in the fall of 2008, we saw demand for our products decline, especially within certain markets such as North America and the Commonwealth of Independent States (“CIS”), which consists of 11 former Soviet Republics. The onslaught of the global recession and the resulting decline in demand for oil and gas, coupled with a relatively high supply of those commodities, resulted in a dramatic decline in the price for oil and natural gas. This, we believe, resulted in a dramatic reduction in oil and gas exploration activity and, therefore, a corresponding decline in demand for seismic related goods and services. In fiscal 2011, we began to see a recovery in seismic exploration activity and, therefore, an increase in demand for our goods and services. We believe that this recovery has been driven in large part by the recovery of global oil prices. While natural gas prices in North America have generally not recovered, there has been renewed activity in exploration for natural gas surrounding various unconventional gas reservoirs, commonly referred to as “shale plays.” There also appears to be growing interest in similar natural gas prospects in other parts of the world, such as eastern Europe. While the oil and gas industry has been, and we expect will be, subject to significant cyclicality, we believe that our business will benefit from a long-term demand for oil and gas.

 

Our equipment is utilized in a variety of geographic regions throughout the world, which are described in “— Customers, Sales, Backlog and Marketing.”

We own a variety of technologically advanced equipment acquired from the leading seismic manufacturers. Our lease pool includes many types of equipment used in seismic data acquisition, including various electronic components of land, transition zone and marine seismic data acquisition systems, geophones and cables, earth vibrators, peripheral equipment, survey and other equipment. The majority of our seismic equipment lease pool is provided by the Sercel subsidiaries of Compagnie Generale de Geophysique-Veritas (“Sercel”). However, we also purchase equipment from a number of other equipment manufacturers, including ION Geophysical Corporation (“ION”), Oyo Geospace Corporation (“Oyo”) and INOVA Geophysical Equipment Limited, an affiliate of ION. At January 31, 2011, approximately 44% of our equipment lease pool, on a cost basis, consisted of seismic recording channels and related equipment, with the remainder consisting of geophones, compressors, energy source controllers and other peripheral equipment.

 

For the past several years, we have had a series of supply and exclusive lease referral agreements with Sercel, which we believe have provided us with certain competitive advantages, primarily due to preferential pricing and expedited delivery arrangements under the agreements. Under these agreements, we have been the exclusive worldwide short-term leasing representative for certain products. In September 2009, we renewed our agreement with Sercel. See “— Key Supplier Agreements — The Sercel Lease Agreement” for further information about this agreement.

 

We lease our equipment on a short-term basis, generally for two to six months, to seismic contractors who need additional capacity to complete a seismic survey. Certain equipment that is used in vertical seismic profiling, or “downhole” operations, is generally leased to oil field service companies and generally for shorter periods ranging from a few days to two weeks. Short-term leasing agreements enable our customers to achieve operating and capital investment efficiencies. A typical seismic crew uses a wide variety of equipment to perform seismic data acquisition surveys. Our customers may lease a small amount of equipment to expand an existing crew’s capabilities or a complete seismic data acquisition system to equip an entire crew. Demand for short-term seismic equipment leases is affected by many factors, including: (i) the highly variable size and technological demands of individual seismic surveys, (ii) seasonal weather patterns and sporadic demand for seismic surveys in certain regions, (iii) the term of the lease and (iv) the cost of seismic equipment. We believe these factors allow seismic contractors to use short-term seismic equipment leasing as a cost-effective alternative to purchasing additional equipment. Our equipment lease rates vary according to an item’s expected useful life, utilization, acquisition cost and the term of the lease.

 

SAP sells equipment, consumables, systems integration, engineering hardware and software maintenance support services to companies in the seismic, hydrographic, oceanographic, environmental and defense industries throughout Southeast Asia and Australia. MII and MCL also sell a broad range of used seismic equipment on a worldwide basis. AES owns certain patent rights related to, and produces, leases and sells, “heli-pickers” and related equipment to the seismic industry. We believe that AES is the dominant provider of this equipment to the seismic industry.

 

Seamap designs, manufactures and sells a broad range of proprietary products for the seismic, hydrographic and offshore industries. Seamap’s primary products include the GunLink seismic source acquisition and control systems, which provide operators of marine seismic surveys more precise control of energy sources, and the BuoyLink RGPS tracking system, which is used to provide precise positioning of seismic sources and streamers. We believe that Seamap, with the GunLink product line, is now the primary provider of new energy source controllers in the seismic industry.

 

For information regarding our net income and total assets by segment, see Note 13 to our consolidated financial statements.

 

Business Strategy

 

Our business strategy is to meet the needs of the seismic industry by leasing a wide range of equipment and to provide technologically advanced solutions for marine seismic applications. To accomplish this, we have identified the following major objectives:

 

 

 

Seismic Technology and the Oil Service Industry

 

Seismic surveys are a principal source of information used by oil and gas companies to identify geological conditions that are favorable for the accumulation of oil and gas and to evaluate the potential for successful drilling, development and production of oil and gas. Seismic technology has been used by the oil and gas industry since the 1920s, and has advanced significantly with improvements in computing and electronic technologies. Beginning in the early 1990s, the oil and gas industry significantly expanded its use of 3-D seismic data. 3-D seismic data provides a more comprehensive subsurface image and is believed to have contributed to improved drilling success rates, particularly in mature oil and gas basins such as those in North America. Additionally, 2-D seismic data continues to be used in many areas where 3-D data acquisition is cost prohibitive or logistical access is limited.

 

Oil and gas exploration companies utilize seismic data generated from the use of digital seismic systems and peripheral equipment in determining optimal locations for drilling oil and gas wells, in the development of oil and gas reserves and in reservoir management for the production of oil and gas. A complete digital seismic data acquisition system generally consists of (i) a central electronics unit that records and stores digital data (“CEU”), (ii) seismic recording channel boxes that contain from one to eight seismic channels (“channel boxes”), (iii) geophones, or seismic sensors, (iv) energy sources including dynamite, air guns or earth vibrators that create the necessary acoustic wave to be recorded, (v) cables that transmit digital seismic data from the channel boxes to the CEU, (vi) geographic survey equipment, (vii) drilling equipment used in the seismic survey and (viii) other peripheral, or accessory, equipment.

 

In certain applications, specialized seismic recording devices are deployed vertically within a well bore. Multiple recording channels, or “levels” are generally deployed within a given well and are referred to as “downhole” or “VSP” (vertical seismic profiling) tools. These applications are used to provide additional data points in a traditional seismic survey, to monitor and analyze reservoir properties, and to monitor and analyze fluid treatment operations, as well as a variety of other uses.

 

In seismic data acquisition, an acoustic wave is generated at or below the earth’s surface through the discharge of compressed air, the detonation of small explosive charges or the use of large mechanical vibrators. As the acoustic wave travels through the earth, it is partially reflected by the underlying rock layers and the reflected energy is captured by sensors, such as geophones, which are situated at intervals along paths from the point of acoustical impulse. The resulting signals are then transmitted to the channel boxes, which convert the signals from analog to digital data and transmit this data via cable to the CEU. The CEU stores the seismic data on magnetic tape, disk or other recording media for processing. The digital data is then input into a specialized seismic processing system that uses sophisticated computer software programs to enhance the recorded signal and produce an image of

the subsurface strata. By interpreting seismic data, oil and gas exploration companies create detailed maps of exploration prospects and oil and gas reservoirs.

 

Historically, a 2-D seismic survey was the standard data acquisition technique used to map geologic formations over a broad area. 2-D seismic data can be visualized as a single vertical plane of subsurface information. Data gathered from a 3-D seismic survey is best visualized as a cube of information that can be sliced into numerous planes, providing different views of a geologic structure with much higher resolution than is available with traditional 2-D seismic survey techniques. 3-D seismic surveys generally require a larger amount of equipment than 2-D surveys. By using a greater number of channels and flexible configuration, 3-D seismic data provides more extensive and detailed information regarding the subsurface geology than 2-D data. As a result, 3-D data allows the geophysicists interpreting the data to more closely select the optimal location of a prospective drill site or define an oil and gas reservoir.

 

In the exploration and development process, oil and gas companies establish requirements for seismic data acquisition programs based on their technical objectives. Because of the expense associated with drilling oil and gas wells, decisions regarding whether or where to drill are critical to the overall process. Since 3-D seismic data increases drilling success rates and reduces costs, we believe that 3-D seismic surveys are now predominant. As a result of the increasing requirements for this higher resolution data, which in turn requires additional channels to collect and transmit data, seismic data acquisition systems have been expanding in size during the past several years.

 

Industry advances include the use of high resolution 3-D, three-component geophones (“3D-3C”), which enhance the 3-D image of the sub-surface, and time lapse (“4-D”) seismic techniques, where surveys are periodically reacquired to allow the monitoring of producing oil and gas fields for optimal production and reserve recovery. These and other technical advances have contributed to increased drilling success rates and reduced oil and gas finding costs.

 

With the expanded use of seismic technology, particularly 3-D seismic surveys, the size of data acquisition surveys has increased substantially in the past several years. Demand for higher resolution data, larger surveys and more rapid completion of such surveys now requires seismic contractors to use data acquisition systems with a greater number of seismic recording channels. Additionally, the size of seismic surveys varies significantly, requiring frequent changes in the configuration of equipment and crews used for seismic surveys. As a result of these changes, the number of seismic survey channels has increased from smaller 2-D surveys, which typically averaged 120 channels, to larger 3-D surveys, which today average more than 5,000 channels and sometimes use as many as 100,000 channels. We believe that many seismic contractors will continue to meet changes in equipment needs by leasing incremental equipment to expand crew size as necessary, thereby reducing the substantial capital expenditures required to purchase such equipment.

 

Seismic surveys utilizing 2-D, 3-D or 4-D techniques require essentially the same equipment. The manner in which the equipment is deployed and the resulting data analyzed differs, however. Accordingly, our equipment can generally be utilized in 2-D, 3-D and 4-D seismic surveys. Since 3-D and 4-D seismic surveys generally utilize significantly more equipment than 2-D seismic surveys, the potential to lease our seismic equipment has increased from earlier periods.

 

Business and Operations

 

Equipment Leasing.  We own a comprehensive lease pool of seismic equipment for short-term leasing to our customers, who are primarily seismic data acquisition contractors and oil field service providers (in the case of downhole equipment). We lease this equipment multiple times until the earlier of the end of its useful life or its sale. Our equipment leasing services generally include the lease of the various components of seismic data acquisition systems and related equipment to meet a customer’s job specifications. These specifications frequently vary as to the number of required recording channels, geophones, energy sources (e.g., earth vibrators) and other equipment. Our customers generally lease seismic equipment to supplement their own inventory of recording channels and related equipment.

 

Our land equipment lease pool includes a total of over 134,000 seismic recording land channels (each channel capable of electronically converting seismic data from analog to digital format and transmitting the digital data),

geophones and cables, and other peripheral equipment. Our lease pool of marine seismic equipment includes more than 19 kilometers of streamers (recording channels that are towed behind a vessel), air compressors, air guns, streamer positioning equipment, energy source controllers and other equipment. Our lease pool of downhole equipment includes approximately 290 levels of downhole seismic tools. Our lease pool equipment is manufactured by leading seismic equipment manufacturers and is widely used in the seismic industry. Our marine lease pool includes energy source controllers and RGPS tracking systems that are manufactured by our Seamap segment.

 

Our equipment leases generally have terms of two to six months, a few days to two weeks in the case of downhole equipment, and are typically renewable following the initial rental period. Our equipment lease rates vary according to an item’s expected useful life, utilization, initial cost and the term of the lease. We provide maintenance of our leased equipment during the lease term for malfunctions due to failure of material and parts and will provide replacement equipment, as necessary. In addition, we provide field technical support services when requested by our customers. The customer is responsible for the cost of repairing equipment damages other than normal wear and tear and replacing destroyed or lost equipment under the terms of our standard lease agreements. The customer is also normally responsible for the costs of shipping the equipment from and to one of our facilities and is responsible for all taxes, other than income taxes, related to the lease of the equipment. The customer is required to obtain and maintain insurance for the replacement value of the equipment and a specified minimum amount of general liability insurance. While it is our general practice to lease our seismic equipment on a monthly basis, in certain circumstances we lease equipment on a day rate usage basis.

 

Seismic equipment leasing is susceptible to weather patterns in certain geographic regions. In Canada and Russia, a significant percentage of the seismic survey activity occurs in the winter months, from December through March or April. During the months in which the weather is warmer, certain areas are not accessible to trucks, earth vibrators and other heavy equipment because of the unstable terrain. In other areas of the world, such as Southeast Asia and the Pacific Rim, periods of heavy rain, known as monsoons, can impair seismic operations. We are able, in many cases, to transfer our equipment from one region to another in order to deal with seasonal demand and to increase our equipment utilization. For additional information about the impact of seasonality and weather, see Item 1A — “Risk Factors.”

 

Upon completion of a lease, the equipment must generally be returned to one of our facilities for inspection, testing and, if necessary, repair. While the customer is normally responsible for the costs of shipping and repairs, during this time the equipment is not available for lease to another customer. Therefore, managing this process and the utilization of the equipment is an important aspect of our operations. Given the short term of most of our leases, we believe that the highest achievable annual utilization for most of our equipment is approximately 65%. However, many factors can affect this utilization rate, including the term of our leases, the shipping time required to return equipment to one of our facilities, the time required to inspect, test and repair equipment after return from a lease and the demand for the equipment.

 

Historically, the majority of the inspection, testing and repair have been done in our Huntsville, Texas or Calgary, Alberta facilities. In recent years, however, we have added inspection and testing capabilities to our facilities in Ufa, Bashkortostan, Russia and Singapore. With the establishment of our branch operations in Colombia and Peru, we also added inspection, test and repair capabilities in those countries. We believe that by expanding these capabilities we have been able to more effectively utilize our equipment and reduce costs associated with these operations, although it is not possible to quantify the effect of any such improvement. The incremental cost for these additional facilities was not material.

 

Lease Pool Equipment Sales.  On occasion, we sell used equipment from our lease pool, normally in response to specific customer demand or to declining demand for rental of specific equipment. Used equipment sold from our lease pool can have a wide range of gross margins depending upon the amount of depreciation that has been recorded on the item. When used equipment is sold from our lease pool, the net book value plus any cost associated with the sale is recorded to cost of goods sold. Sales of our lease pool equipment typically occur as opportunities arise and do not have a significant seasonal aspect. Sales of lease pool equipment amounted to approximately $2.5 million, $3.3 million and $3.0 million in each of the three fiscal years ended January 31, 2011, 2010 and 2009, respectively. We typically do not seek to sell our lease pool equipment. However, we will evaluate any opportunities

for the sale of equipment from our lease pool, and based upon our evaluation, may sell additional equipment. Such sales of lease pool equipment could be material.

 

Other Equipment Sales.  The “Other equipment sales” included in our Equipment Leasing segment fall into two broad categories:

 

 

Seamap Equipment Sales.  Seamap designs, manufactures and sells a broad range of proprietary products for the seismic, hydrographic and offshore industries. Seamap’s primary products include (i) the GunLink seismic source acquisition and control systems, which are designed to provide operators of marine seismic surveys more precise control of energy sources, and (ii) the BuoyLink RGPS tracking system used to provide precise positioning of seismic sources and streamers. Seamap’s design operations are located in the United Kingdom and in Singapore and its manufacturing facilities are located in Singapore.

 

Key Supplier Agreements

 

The Sercel Lease Agreement

 

In September 2009, we entered into a new exclusive equipment lease agreement with Sercel (the “Exclusive Equipment Lease Agreement”), which replaced an agreement that expired in December 2008. Under the current agreement, we are, with some exceptions, the exclusive worldwide authorized lessor for Sercel’s DSU3 428XL three component digital sensors and the exclusive authorized lessor for Sercel’s downhole seismic tools in North and South America through December 2011.

 

Under the agreement, we agreed not to offer financing leases or leases with terms greater than one year related to the Exclusive Products (as defined in the agreement) without Sercel’s prior consent. Sercel agreed to refer any inquires for short-term rentals of the Exclusive Products for use within the Exclusive Territory (as defined in the agreement) to us and to not recommend any competitor of ours as a source of such rentals. Sercel and we agreed to cooperate in the promotion and marketing of the Exclusive Products.

 

The agreement provides that Sercel grant us specified pricing for the purchase of the Exclusive Products and certain other products. In return, we agreed to purchase a total of 9,000 stations, or 27,000 channels, of DSU3 428XL three component digital sensors and 300 levels of downhole tools by December 31, 2011. As of January 31, 2011, we had purchased 3,000 stations of DSU3 428XL and approximately 200 levels of downhole tools pursuant to this agreement. See Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information regarding our plans to meet these purchase obligations.

 

Other Agreements

 

SAP has a number of manufacturer’s representation agreements for major product lines, including: acoustic positioning systems, data acquisition systems, geophones, hydrophones, connectors, cables, test equipment, GPS systems, heave compensators and attitude sensors, hydrographic data acquisition systems, magnetometers, tide gauges and current meters, radio positioning equipment, side-scan sonar and sub-bottom profiling systems, underwater communications and location devices, echo sounders and transducers.

 

Certain software utilized by Seamap’s GunLink products was developed by Tanglesolve Instrumentation, Ltd. (“Tanglesolve”) under a cooperation agreement with Seamap. Under this agreement, Tanglesolve received a royalty

payment from the sale of each GunLink product. In December 2007, Seamap acquired all of the capital stock of Tanglesolve. At the time, Tanglesolve’s only material assets were the cooperation agreement and the intellectual property related to the GunLink software. In connection with this transaction, Seamap entered into a new cooperation agreement with the former shareholders of Tanglesolve whereby they provide certain on-going support services. In December 2009, the cooperation agreement was extended through December 2011 by mutual consent, as provided for in the agreement.

 

Customers, Sales, Backlog and Marketing

 

Our lease customers generally are seismic data acquisition contractors. We typically have a small number of lease customers, the composition of which changes yearly as leases are negotiated and concluded and equipment needs vary. As of January 31, 2011, we had approximately 54 lease customers with 104 active leases of various lengths, but typically for less than a year.

 

We do not maintain a backlog of orders relating to our Equipment Leasing segment. As of January 31, 2011, our Seamap segment had a backlog of orders amounting to approximately $8.6 million, compared to $9.3 million as of January 31, 2010. We expect all of these orders to be fulfilled during our fiscal year ending January 31, 2012.

 

We participate in both domestic and international trade shows and expositions to inform the industry of our products and services and we advertise in major geophysical trade journals.

 

A summary of our revenues from customers by geographic region is as follows (in thousands):

 

 

 

 

The net book value of our long-lived assets in our various geographic locations is as follows (in thousands):

 

For information regarding the risks associated with our foreign operations, see Item 1A-“Risk Factors.” For fiscal 2011, one customer, CGV accounted for approximately 19% of our consolidated revenues. In fiscal 2010, three customers accounted for 10% or more of our consolidated revenues. The Polarcus Group of Companies, CGV and Global Geophysical Services represented approximately 14%, 11% and 10%, respectively, of our consolidated revenues for fiscal 2010. In fiscal 2009, one customer, CGV, accounted for approximately 23%, of our consolidated revenues. The loss of any of these customers could have a material adverse effect on our results of operations. No other customer accounted for 10% or more of our revenues during these periods.

 

Competition

 

Our major competitors are the major seismic equipment manufacturers who sell equipment on financed terms and seismic contractors who might have excess equipment available for lease from time to time. We face lesser competition from several companies that engage in seismic equipment leasing, but this competition has historically been fragmented and our competitors have not had as extensive a seismic equipment lease pool nor as wide geographic presence as we do. We compete for seismic equipment leases on the basis of (i) price and delivery, (ii) variety and availability of both peripheral seismic equipment and complete data acquisition systems and (iii) length of lease term. We believe that our infrastructure and broad geographic presence also provide a major competitive advantage by contributing to our operational efficiencies.

 

We compete in the used equipment sales market with a broad range of seismic equipment owners, including seismic data acquisition contractors, who use and eventually dispose of seismic equipment. Many of these competitors have substantially greater financial resources than our own.

 

Suppliers

 

We have several suppliers of seismic equipment for our lease pool. We acquire the majority of our seismic lease pool equipment from Sercel. However, we also acquire lease pool equipment from a number of other suppliers including ION and OYO. Management believes that our current relationships with our suppliers are satisfactory. For the years ended January 31, 2011, 2010 and 2009, approximately 35%, 32% and 42%, respectively, of our revenues were generated from the rental of products we acquired from Sercel. For additional information regarding the risk associated with our suppliers, see Item 1A- “Risk Factors.”

 

Employees

 

As of January 31, 2011, we employed 125 people full-time, none of whom were represented by a union or covered by a collective bargaining agreement. We consider our employee relations to be satisfactory.

 

Intellectual Property

 

The products designed, manufactured and sold by our Seamap segment utilize significant intellectual property that we have developed or have licensed from others. Our internally developed intellectual property consists of product designs and trade secrets. We currently have no patents covering any of this intellectual property.

 

In connection with the acquisition of AES in March 2010, we acquired intellectual property relating to the design and manufacture of heli-pickers. This intellectual property includes United States, Canadian, Australian and United Kingdom patents.

 

For additional information regarding the risks associated with our intellectual property, see Item 1A-“Risk Factors.”

 

Environmental Regulation

 

We are subject to stringent governmental laws and regulations pertaining to protection of the environment and the manner in which chemicals and materials used in our manufacturing processes are handled and wastes generated from such operations are disposed. We have established and implemented proactive environmental procedures for the management of these chemicals and materials as well as the handling and recycling or disposal of wastes resulting from our operations. Compliance with these laws and regulations may require the acquisition of permits

for regulated activities, capital expenditures to limit or prevent emissions and discharges, and special precautions for disposal of certain wastes. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties and the issuance of injunctive relief. Spills or releases of chemicals, materials and wastes at our facilities or at offsite locations where they are transported for recycling or disposal could subject us to environmental liability, which may be strict, joint and several, for the costs of cleaning up chemicals, materials and wastes released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by such spills or releases. As a result of such actions, we could be required to remove previously disposed wastes, remediate environmental contamination, and undertake measures to prevent future contamination. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment and thus any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could have a material adverse effect on our operations and financial position. For instance, the adoption of laws or implementing regulations with regard to climate change that have the effect of lowering the demand for carbon-based fuels or with regard to hydraulic fracturing that have the effect of decreasing the performance of exploratory activities by energy companies could have a material adverse effect on our business. While we believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us, we cannot give any assurance that this trend of compliance and avoidance of material costs or other liabilities will continue in the future. For additional information regarding the risk associated with environmental matters, see Item 1A — “Risk Factors.”

 

Website Access to Our Periodic SEC Reports

 

Our internet address is http://www.mitchamindustries.com. We file and furnish Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, and amendments to these reports, with the SEC, which are available free of charge through our website as soon as reasonably practicable after such reports are filed with or furnished to the SEC. Materials we file with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. Information on the 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 at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding our company that we file and furnish electronically with the SEC.

 

We may from time to time provide important disclosures to investors by posting them in the investor relations section of our website, as allowed by SEC rules. Information on our website is not incorporated by reference into this Form 10-K and you should not consider information on our website as part of this Form 10-K.

 

 

The risks described below could materially and adversely affect our business, financial condition and results of operations and the actual outcome of matters as to which forward-looking statements are made in this Form 10-K. The risk factors described below are not the only risks we face. Our business, financial condition and results of operations may also be affected by additional factors that are not currently known to us or that we currently consider immaterial or that are not specific to us, such as general economic conditions.

 

You should refer to the explanation of the qualifications and limitations on forward-looking statements included under “Cautionary Statements About Forward-Looking Statements” of this Form 10-K. All forward-looking statements made by us are qualified by the risk factors described below.

 

If economic conditions weaken or commodity prices become depressed or decline, our results of operations could be adversely affected.

 

Historically, the demand for our products and services has been sensitive to the level of exploration spending by oil and gas companies. During the period of depressed commodity prices, such as that experienced in late 2008 and 2009, many oil and gas exploration and production companies significantly reduced their levels of capital spending, including amounts dedicated to the leasing or purchasing our seismic equipment. A return of depressed

commodity prices, or a decline in existing commodity prices, could adversely affect demand for the services and equipment we provide, and therefore adversely affect our revenue and profitability. Further, perceptions of a long-term decrease in commodity prices by oil and gas companies could similarly reduce or defer major expenditures given the long-term nature of many large-scale development projects. Lower levels of activity result in a corresponding decline in the demand for our products and services, which could have a material adverse effect on our revenue and profitability. Additionally, these factors may adversely impact our statement of financial position if they are determined to cause impairment of our goodwill or other intangible assets or of our other long-lived assets.

 

Demand for seismic data is not assured.

 

Demand for our services depends on the level of spending by oil and gas companies for exploration, production and development activities, as well as on the number of crews conducting land, transition zone and marine seismic data acquisition worldwide. The levels of such spending are influenced by:

 

 

The cyclical nature of the oil and gas industry can have a significant effect on our revenues and profitability. Historically, oil and natural gas prices, as well as the level of exploration and developmental activity, have fluctuated significantly. These fluctuations have in the past, and may in the future, adversely affect our business. We are unable to predict future oil and natural gas prices or the level of oil and gas industry activity. A prolonged low level of activity in the oil and gas industry will likely depress development activity, adversely affecting the demand for our products and services and our financial condition and results of operations.

 

Our revenues are subject to fluctuations that are beyond our control, which could materially adversely affect our results of operations in a given financial period.

 

Projects awarded to and scheduled by our customers can be delayed or cancelled due to factors that are outside of their control, which can affect the demand for our products and services. These factors include budgetary or other financial issues of the oil and gas exploration companies, adverse weather conditions, difficulties in obtaining permits or other regulatory issues, the availability of other equipment required for a particular project, political unrest or security concerns in certain foreign locations, as well as a variety of other factors.

 

A limited number of customers account for a significant portion of our revenues, and the loss of one of these customers could harm our results of operations.

 

We typically lease and sell significant amounts of seismic equipment to a relatively small number of customers, the composition of which changes from year to year as leases are initiated and concluded and as customers’ equipment needs vary. Therefore, at any one time, a large portion of our revenues may be derived from a limited number of customers. In the fiscal years ended January 31, 2011, 2010 and 2009, our single largest customer accounted for approximately 19%, 14% and 23%, respectively, of our consolidated revenues. Our six largest customers accounted for approximately 50% of our consolidated revenues in the fiscal year ended January 31, 2011.

There has recently been considerable consolidation among certain of our customers and this trend may continue. This consolidation could result in the loss of one or more of our customers and could result in a decrease in the demand for our equipment.

 

The financial soundness of our customers could materially affect our business and operating results.

 

As a result of the disruptions in the financial markets and other macro-economic challenges that continue to affect the economy of the United States and other parts of the world, our customers may experience cash flow concerns. As a result, if customers’ operating and financial performance deteriorates, or if they are unable to make scheduled payments or obtain credit, customers may not be able to pay, or may delay payment of, accounts receivable owed to us. Any inability of customers to pay us for services could adversely affect our financial condition and results of operations.

 

As of January 31, 2011, we had approximately $22.8 million of customer accounts and contracts receivable, of which approximately $6.3 million was over 90 days past due. For the years ended January 31, 2011, 2010 and 2009, we had charges of approximately $1.8 million, $1.4 million and $2.9 million, respectively, to our provision for doubtful accounts. Significant payment defaults by our customers in excess of the allowance would have a material adverse effect on our financial position and results of operations.

 

We derive significant revenues from foreign sales, which pose additional risks to our operations.

 

Many of our foreign operations are conducted in currencies other than U.S. dollars. Those currencies include the Canadian dollar, the Australian dollar, the Singapore dollar, the Russian ruble and the British pound sterling. These internationally-sourced revenues are subject to the risk of taxation policies, expropriation, political turmoil, civil disturbances, armed hostilities, and other geopolitical hazards as well as foreign currency exchange controls (in which payment could not be made in U.S. dollars) and fluctuations. For example, for accounting purposes, balance sheet accounts of our operating subsidiaries are translated at the current exchange rate as of the end of the accounting period. Statement of operations items are translated at average currency exchange rates. The resulting translation adjustment is recorded as a separate component of comprehensive income within shareholders’ equity. This translation adjustment has in the past been, and may in the future be, material because of the significant amount of assets held by our international subsidiaries and the fluctuations in the foreign exchange rates.

 

Capital requirements for our operations are large. If we are unable to finance these requirements, we may not be able to maintain our competitive advantage.

 

Our sources of working capital are limited. We have historically funded our working capital requirements with cash generated from operations, cash reserves and short-term borrowings from commercial banks. Our working capital requirements continue to increase, primarily due to the expansion of our infrastructure in response to client demand for more recording channels, which has increased as the industry strives for improved data quality with greater subsurface resolution images. If we were to expand our operations at a rate exceeding operating cash flow, or current demand or pricing of our services were to decrease substantially or if technical advances or competitive pressures required us to acquire new equipment faster than our cash flow could sustain, additional financing could be required. Global financial markets and economic conditions have been uncertain and volatile over recent periods. The debt and equity capital markets, while somewhat improved recently, were distressed for an extended period of time. These issues, along with significant losses in the financial services sector, the re-pricing of credit risk and the current uncertain economic conditions could make it difficult to obtain funding in the capital markets. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide any new funding.

 

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be

unable to grow our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our financial condition and results of operations.

 

Our operations and financial condition will be materially adversely affected if we are unable to continually obtain additional lease contracts.

 

Our seismic equipment leases typically have a term of two to six months and provide gross revenues that recover only a portion of our capital investment on the initial lease. Our ability to generate lease revenues and profits is dependent on obtaining additional lease contracts after the termination of an original lease. However, lease customers are under no obligation to, and frequently do not, continue to lease seismic equipment after the expiration of a lease. Although we have been successful in obtaining additional lease contracts with other customers after the termination of the original leases, we cannot assure you that we will continue to do so. Our failure to obtain additional leases or extensions beyond the initial lease term would have a material adverse effect on our operations and financial condition.

 

Our failure to attract and retain key personnel could adversely affect our operations.

 

Our success is dependent on, among other things, the services of certain key personnel, including specifically Billy F. Mitcham, Jr., our President and Chief Executive Officer. The loss of the services of Mr. Mitcham or other personnel could have a material adverse effect on our operations.

 

The high fixed costs of our operations could adversely affect our results of operations.

 

Our business has high fixed costs, which primarily consist of depreciation expenses associated with our lease pool of seismic data acquisition equipment. In periods of significant downtime these fixed costs do not decline as rapidly as our revenues. As a result, any significant downtime or low productivity caused by reduced demand could adversely affect our results of operations.

 

Our long-lived assets may be subject to impairment due to the current financial crisis.

 

We periodically review our long-lived assets, including goodwill, other intangible assets and our lease pool of equipment, for impairment. If we expect significant sustained decreases in oil and natural gas prices in the future, we may be required to write down the value of these assets if the future cash flows anticipated to be generated from the related the assets falls below net book value. Declines in oil and natural gas prices, if sustained, could result in future impairments. If we are forced to write down the value of our long-lived assets, these noncash asset impairments could negatively affect our results of operations in the period in which they are recorded. See the discussion included in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies — Long-Lived Assets.”

 

Our seismic lease pool is subject to technological obsolescence.

 

We have a substantial capital investment in seismic data acquisition equipment. The development by manufacturers of seismic equipment of newer technology systems or component parts that have significant competitive advantages over seismic systems and component parts now in use could have an adverse effect on our ability to profitably lease and sell our existing seismic equipment. Significant improvements in technology may also require us to recognize an asset impairment charge to our lease pool investment and to correspondingly invest significant sums to upgrade or replace our existing lease pool with newer-technology equipment demanded by our customers, which could affect our ability to compete as well as have a material adverse effect on our financial condition.

 

Seasonal conditions cause fluctuations in our operating results.

 

The first and fourth quarters of our fiscal year have historically accounted for a greater portion of our lease revenues than do our second and third quarters. This seasonality in leasing revenues is primarily due to the increased seismic survey activity in Canada and Russia from January through March or April. This seasonal pattern may cause

our results of operations to vary significantly from quarter to quarter. Accordingly, period-to-period comparisons are not necessarily meaningful and should not be relied on as indicative of future results.

 

We face competition in our seismic equipment leasing activities.

 

We have several competitors engaged in seismic equipment leasing and sales, including seismic equipment manufacturers and data acquisition contractors that use seismic equipment, many of which have substantially greater financial resources than our own. There are also several smaller competitors that, in the aggregate, generate significant revenues from the sale of seismic survey equipment. Pressures from existing or new competitors could adversely affect our business operations.

 

We rely on a small number of suppliers and disruption in vendor supplies could adversely affect our results of operations.

 

We purchase the majority of our seismic equipment for our lease pool from a small number of suppliers. Should our relationships with our suppliers deteriorate, we may have difficulty in obtaining new technology required by our customers and maintaining our existing equipment in accordance with manufacturers’ specifications. In addition, we may, from time to time, experience supply or quality control problems with suppliers, and these problems could significantly affect our ability to meet our lease commitments. Reliance on certain suppliers, as well as industry supply conditions, generally involve several risks, including the possibility of a shortage or a lack of availability of key products and increases in product costs and reduced control over delivery schedules; any of these events could adversely affect our future results of operations.

 

Equipment in our lease pool may be subject to the intellectual property claims of others that could adversely affect our ability to generate revenue from the lease of the equipment.

 

Certain of the equipment in our lease pool is proprietary to us. The equipment we acquired with the acquisition of AES, see Item 1 — “Business,” includes heli-pickers and associated equipment that is manufactured by AES and is subject to various patents, see Item 1 — “Business — Intellectual Property.” We also have some equipment in our lease pool that is manufactured by our Seamap segment, which is subject to intellectual property rights and protection as discussed below. We may be subject to infringement claims and other intellectual property disputes as competition in the marketplace continues to intensify. In the future, we may be subject to litigation and may be required to defend against claimed infringements of the rights of others or to determine the scope and validity of the proprietary rights of others. Any such litigation could be costly and divert management’s attention from operations. In addition, adverse determinations in such litigation could, among other things:

 

 

Additionally, the equipment that we acquire from other suppliers may be subject to the intellectual property infringement claims from third parties. We generally are indemnified by our suppliers against any claims that may be brought against us by third parties related to equipment they sold to us. However, such claims could affect our ability to acquire additional such products or to lease them in the future. The loss of this future revenue could adversely affect our business and would not generally be covered by the indemnities from our suppliers.

 

In February 2011, ION obtained a judgment against Sercel as a result of a patent infringement suit. One aspect of the judgment restricts the importation and use of certain seismic equipment in the United States, including Sercel’s 428XL DSU3 products. We currently own a significant amount of this equipment and have agreed to purchase additional amounts pursuant to our Exclusive Equipment Lease Agreement with Sercel. We believe that essentially all of this equipment that we currently own is not subject to any restrictions as to use in the United States. However, if we are unable to import into or use in the United States any of equipment that we buy in the future, our

financial condition and results of operations could be adversely affected. We understand that Sercel has appealed this judgment, but the potential results or timing of any ruling on this appeal are unknown.

 

The operations of Seamap are subject to special risks that could have a material adverse effect on our operations.

 

The design and manufacturing operations of our Seamap segment are subject to risks not associated with our equipment leasing business. These risks include the following:

 

Risks Associated with Intellectual Property.  We rely on a combination of copyright, trademark and trade secret laws, and restrictions on disclosure to protect our intellectual property. We also enter into confidentiality or license agreements with our employees, consultants and corporate partners and control access to and distribution of our design information, documentation and other proprietary information. These intellectual property protection measures may not be sufficient to prevent wrongful misappropriation of our technology. In addition, these measures will not prevent competitors from independently developing technologies that are substantially equivalent or superior to our technology. The laws of many foreign countries may not protect intellectual property rights to the same extent as the laws of the United States. Failure to protect proprietary information could result in, among other things, loss of competitive advantage, loss of customer orders and decreased revenues. Monitoring the unauthorized use of our products is difficult and we cannot be certain that the steps we have taken will prevent unauthorized use of our technology, particularly in foreign countries where the laws may not protect our proprietary rights as fully as in the United States. If competitors are able to use our technology, our ability to compete effectively could be impaired.

 

We may be subject to infringement claims and other intellectual property disputes as competition in the marketplace continues to intensify. In the future, we may be subject to litigation and may be required to defend against claimed infringements of the rights of others or to determine the scope and validity of the proprietary rights of others. Any such litigation could be costly and divert management’s attention from operations. In addition, adverse determinations in such litigation could, among other things:

 

 

If we are forced to take any of the foregoing actions, our business may be seriously harmed. Any litigation to protect our intellectual property or to defend ourselves against the claims of others could result in substantial costs and diversion of resources and may not ultimately be successful.

 

Risks Related to Product Performance.  The production of new products with high technology content involves occasional problems while the technology and manufacturing methods mature. If significant reliability or quality problems develop, including those due to faulty components, a number of negative effects on our business could result, including:

 

 

Although we maintain accruals for product warranties, actual costs could exceed these amounts. From time to time, there may be interruptions or delays in the activation of products at a customer’s site. These interruptions or delays may result from product performance problems or from aspects of the installation and activation activities, some of which are outside our control. If we experience significant interruptions or delays that cannot be promptly resolved, confidence in our products could be undermined, which could have a material adverse effect on our operations.

 

Risks Related to Raw Materials.  We depend on a limited number of suppliers for components of our products, as well as for equipment used to design and test our products. Certain components used in our products may be available from a sole source or limited number of vendors. If these suppliers were to limit or reduce the sale of such components to us, or if these suppliers were to experience financial difficulties or other problems that prevented them from supplying us with the necessary components, these events could have a material adverse effect on our business, financial condition and results of operations. These sole source and other suppliers are each subject to quality and performance issues, materials shortages, excess demand, reduction in capacity and other factors that may disrupt the flow of goods to us; thereby adversely affecting our business and customer relationships. Some of the sole source and limited source vendors are companies who, from time to time, may allocate parts to equipment manufacturers due to market demand for components and equipment. We have no guaranteed supply arrangements with our suppliers and there can be no assurance that our suppliers will continue to meet our requirements. Many of our competitors are much larger and may be able to obtain priority allocations from these shared vendors, thereby limiting or making our sources of supply unreliable for these components. If our supply arrangements are interrupted, we cannot assure you that we would be able to find another supplier on a timely or satisfactory basis. Any delay in component availability for any of our products could result in delays in deployment of these products and in our ability to recognize revenues.

 

If we are unable to obtain a sufficient supply of components from alternative sources, reduced supplies and higher prices of components will significantly limit our ability to meet scheduled product deliveries to customers. A delay in receiving certain components or the inability to receive certain components could harm our customer relationships and our results of operations.

 

Failures of components affect the reliability and performance of our products, can reduce customer confidence in our products, and may adversely affect our financial performance. From time to time, we may experience delays in receipt of components and may receive components that do not perform according to their specifications. Any future difficulty in obtaining sufficient and timely delivery of components could result in delays or reductions in product shipments that could harm our business. In addition, a consolidation among suppliers of these components or adverse developments in their businesses that affect their ability to meet our supply demands could adversely impact the availability of components that we depend on. Delayed deliveries from these sources could adversely affect our business.

 

We are subject to a variety of environmental laws and regulations that could increase our costs of compliance and impose significant liabilities.

 

We are subject to stringent governmental laws and regulations relating to protection of the environment and the handling of chemicals and materials used in our manufacturing processes as well as the recycling and disposal of wastes generated by those processes. These laws and regulations may impose joint and several strict liability and failure to comply with such laws and regulations could result in the assessment of administrative, civil and criminal penalties, imposition of remedial obligations, and issuance of orders enjoining some or all of our operations. These laws and regulations could require us to acquire permits to conduct regulated activities, install and maintain costly equipment and pollution control technologies, conduct remediation of contaminated soils and groundwater, remove previously disposed water, or undertake measures to prevent future contamination or incur other significant environmental-related expenses. Public interest in the protection of the environment has increased dramatically in recent years. We anticipate that the trend of more expansive and stricter environmental laws and regulations will continue, the occurrence of which may require us to increase our capital expenditures or could result in increased operating expenses.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in reduced demand for oil and natural gas, thereby adversely affecting our business, while the physical effects of climate change could disrupt our manufacturing of seismic equipment and cause us to incur significant costs in preparing for or responding to those effects.

 

In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations that restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA already has adopted two sets of rules regulating GHG emissions under the Clean Air Act, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs, effective January 2, 2011. This stationary source rule “tailors” these permitting programs to apply to certain stationary sources in a multi-step process, with the largest sources first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that will be established by the states or, in some instances, by the EPA on a case-by-case basis. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing, or requiring state environmental agencies to implement, the rules. In addition, on November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage, and distribution activities, beginning in 2012 for emissions occurring in 2011. Also, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. The adoption and implementation of any laws and regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, oil and gas exploration and production activities could have an adverse effect on the demand for our seismic equipment and associated services. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could adversely affect or delay our manufacturing of seismic equipment and cause us to incur significant costs in preparing for or responding to those effects.

 

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in additional operating restrictions or delays and adversely affect our business.

 

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations such as shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with initial results of the study expected to be available in late 2012. In addition, legislation was introduced in the past session of Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process, and such legislation could be introduced and adopted in the current session of Congress. Also, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could make it more

difficult to complete natural gas wells in certain formations and adversely affect demand for our seismic equipment and associated services.

 

The Deepwater Horizon event and its aftermath, including any additional regulations that cause delays or deter new drilling, could adversely affect our financial position, results of operations and cash flows.

 

As a result of the Deepwater Horizon explosion and related oil leak last April 2010 in the U.S. Gulf of Mexico, the Secretary of the U.S. Department of the Interior directed the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) to issue a suspension, until November 30, 2010, of drilling activities for specified drilling configurations and technologies. Although this moratorium was lifted on October 12, 2010, we cannot predict with certainty when drilling operations will fully resume in the U.S. Gulf of Mexico. The BOEMRE has also issued new guidelines and regulations regarding safety, environmental matters, drilling equipment and decommissioning applicable to drilling in the U.S. Gulf of Mexico, and may take other additional steps that could increase the costs of exploration and production, reduce the area of operations and result in permitting delays. Notwithstanding the lifting of the moratorium, we anticipate that there will continue to be delays in the resumption of drilling-related activities, including delays in the issuance of drilling permits, as these various regulatory initiatives are implemented.

 

In addition to the new requirements recently imposed by the BOEMRE, there have been a variety of proposals to change existing laws and regulations, including the proposal to significantly increase the ability to demonstrate the minimum financial responsibility under the Federal Oil Pollution Act of 1990. Implementation of any one or more of the various proposed changes could materially adversely affect operations in the U.S. Gulf of Mexico by raising operating costs, increasing insurance premiums, delaying drilling operations and increasing regulatory requirements, and, further, could lead to a wide variety of other unforeseeable consequences that make operations in the U.S. Gulf of Mexico and other offshore waters more difficult, more time consuming, and more costly. Any one or more of these factors that lead to an increase in the cost of operations in offshore waters or any decrease or delay in offshore exploration and production activity could have a material adverse effect on the operation of the offshore exploration and development industry, which could adversely affect our financial condition, cash flows and results of operations.

 

Our stock price is subject to volatility.

 

Energy and energy service company stock prices, including our stock price, have been extremely volatile from time to time. Stock price volatility could adversely affect our business operations by, among other things, impeding our ability to attract and retain qualified personnel and to obtain additional financing.

 

We have significant operations outside of the United States that expose us to certain additional risks.

 

We operate in a number of foreign locations and have subsidiaries or branches in foreign countries, including Russia, Peru and Colombia. Our equipment is also often temporarily located in other foreign locations while under rent by our customers. These operations expose us to political and economic risks and uncertainties. Should current circumstances change, we could encounter difficulties in operating in some countries and may not be able to retrieve our equipment that is located within these counties. This could result in a material adverse effect on our financial positions and results of operations.

 

Because we have no plans to pay any dividends for the foreseeable future, investors must look solely to stock appreciation for a return on their investment in us.

 

We have not paid cash dividends on our common stock since our incorporation and do not anticipate paying any cash dividends in the foreseeable future. We currently intend to retain any future earnings to support our operations and growth. Any payment of cash dividends in the future will be dependent on the amount of funds legally available, our financial condition, capital requirements and other factors that our Board of directors may deem relevant. Accordingly, investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize any future gains on their investment.

Provisions in our articles of incorporation and Texas law could discourage a takeover attempt, which may reduce or eliminate the likelihood of a change of control transaction and, therefore, the ability of our shareholders to sell their shares for a premium.

 

Provisions of our Articles of Incorporation and the Texas Business Organizations Code may tend to delay, defer or prevent a potential unsolicited offer or takeover attempt that is not approved by our Board of Directors but that our shareholders might consider to be in their best interest, including an attempt that might result in shareholders receiving a premium over the market price for their shares. Because our Board of Directors is authorized to issue preferred stock with preferences and rights as it determines, it may afford the holders of any series of preferred stock preferences, rights or voting powers superior to those of the holders of common stock. Although we have no shares of preferred stock outstanding and no present intention to issue any shares of our preferred stock, there can be no assurance that we will not do so in the future.

 

 

None.

 

 

We occupy the following principal facilities that we believe are adequately utilized for our current operations:

 

 

 

From time to time, we are a party to legal proceedings arising in the ordinary course of business. We are not currently a party to any legal proceedings that we believe could have a material adverse effect on our results of operations or financial condition.

 

 

 

Market Information for Common Stock

 

Our common stock is traded on the NASDAQ Global Select Market under the symbol “MIND.” The following table sets forth, for the periods indicated, the high and low sales prices of our common stock as reported on the NASDAQ Global Select Market.

 

 

As of April 4 2011, there were approximately 6,000 beneficial holders of our common stock.

 

Dividend Policy

 

We have not paid any cash dividends on the common stock since our inception, and our Board of Directors does not contemplate the payment of cash dividends in the foreseeable future. It is the present policy of our Board of Directors to retain earnings, if any, for use in developing and expanding our business. In the future, our payment of dividends will also depend on the amount of funds available, our financial condition, capital requirements and such other factors as our Board of Directors may consider.

 

As of January 31, 2011, we had deposits in foreign banks equal to approximately $13.3 million. These funds may generally be transferred to our accounts in the United States without restriction. However, the transfer of these funds may result in withholding taxes payable to foreign taxing authorities. Any such withholding taxes generally may be credited against our federal income tax obligations in the United States. Additionally, the transfer of funds from our foreign subsidiaries to the United States may result in currently taxable income in the United States. These factors could limit our ability to pay cash dividends in the future.

Performance Graph

 

This performance graph shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Section 18 of the Exchange Act, nor shall it be deemed incorporated by reference in any of our filings under the Securities Act.

 

The following graph compares our common stock’s cumulative total shareholder return for the period beginning January 31, 2006 through January 31, 2011, to the cumulative total shareholder return on (i) the S&P’s Smallcap 600 stock index and (ii) an index of peer companies we selected. The cumulative total return assumes that the value of an investment in our common stock and each index was $100 on January 31, 2006, and that all dividends were reinvested.

 

 

 

The Peer Company Index consists of: Compagnie Generale de Geophysique-Veritas (NYSE: CGV), Dawson Geophysical Company (NASDAQ: DWSN) and Ion Geophysical Corp. (NYSE: IO).

 

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

 

Neither we nor any affiliated purchaser purchased any of our equity securities during the fourth quarter of the fiscal year ended January 31, 2011.

 

 

The selected consolidated financial information contained below is derived from our Consolidated Financial Statements and should be read in conjunction with Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited consolidated financial statements including the notes thereto. Our historical results may not be indicative of the operating results to be expected in future periods.

 

 

See Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of matters affecting the comparability of the above information.

 

 

Overview

 

We operate in two segments, Equipment Leasing and Seamap. Our equipment leasing operations are conducted from our Huntsville, Texas headquarters and from our locations in Calgary, Canada; Brisbane, Australia; Lima, Peru; Bogota, Colombia; and Ufa, Russia. This includes the operations of our MCL, SAP and MSE subsidiaries and our branches in Peru and Colombia. These branches were established late in fiscal 2010 and did not contribute material revenues prior to the year ended January 31, 2011. Seamap operates from its locations near Bristol, United Kingdom and in Singapore.

 

Management believes that the performance of our Equipment Leasing segment is indicated by revenues from equipment leasing and by the level of our investment in lease pool equipment. Management further believes that the performance of our Seamap segment is indicated by revenues from equipment sales and by gross profit from those sales. Management monitors EBITDA and Adjusted EBITDA, both as defined in the following table, as key indicators of our overall performance and liquidity.

The following table presents certain operating information by operating segment:

 

 

 

 

In our Equipment Leasing segment, we lease seismic data acquisition equipment primarily to seismic data acquisition companies conducting land, transition zone and marine seismic surveys worldwide. We provide short-term leasing of seismic equipment to meet a customer’s requirements. All active leases at January 31, 2011 were for a term of less than one year. Seismic equipment held for lease is carried at cost, net of accumulated depreciation. We acquire some marine lease pool equipment from our Seamap segment. These amounts are carried in our lease pool at the cost to our Seamap segment, less accumulated depreciation. From time to time, we sell lease pool equipment to our customers. These sales are usually transacted when we have equipment for which we do not have near term needs in our leasing business. We also occasionally sell new seismic equipment that we acquire from other manufacturers. AES produces and sells, as well as leases, equipment used to deploy and retrieve seismic equipment with helicopters. In addition to leasing seismic equipment, SAP sells equipment, consumables, systems integration,

engineering hardware and software maintenance support services to the seismic, hydrographic, oceanographic, environmental and defense industries throughout Southeast Asia and Australia.

 

Our Seamap segment designs, manufactures and sells a variety of products used primarily in marine seismic applications. Seamap’s primary products include the (i) GunLink seismic source acquisition and control systems, which provide marine operators more precise control of exploration tools, and (ii) the BuoyLink RGPS tracking system used to provide precise positioning of seismic sources and streamers (marine recording channels that are towed behind a vessel).

 

Seismic equipment leasing is susceptible to weather patterns in certain geographic regions. In Canada and Russia, a significant percentage of the seismic survey activity normally occurs in the winter months, from December through March or April. During the months in which the weather is warmer, certain areas are not accessible to trucks, earth vibrators and other heavy equipment because of the unstable terrain. In other areas of the world, such as Southeast Asia and the Pacific Rim, periods of heavy rain, known as monsoons, can impair seismic operations. We are able, in many cases, to transfer our equipment from one region to another in order to deal with seasonal demand and to increase our equipment utilization.

 

Business Outlook

 

Our revenues are directly related to the level of worldwide oil and gas exploration activities and the profitability and cash flows of oil and gas companies and seismic contractors, which, in turn, are affected by expectations regarding the supply and demand for oil and natural gas, energy prices and finding and development costs. Land seismic data acquisition activity levels are measured in terms of the number of active recording crews, known as the “crew count,” and the number of recording channels deployed by those crews, known as “channel count.” Because an accurate and reliable census of active crews does not exist, it is not possible to make definitive statements regarding the absolute levels of seismic data acquisition activity. Furthermore, a significant number of seismic data acquisition contractors are either private or state-owned enterprises and information about their activities is not available in the public domain.

 

In recent months, there has been a recovery in global crude oil prices and, to a much lesser extent, North American natural gas prices. As a result of this, we have seen an increase in activity in areas such as Russia, Southeast Asia and South America. However, activity in North America has not recovered to the same degree. There are continued indications of improving business conditions in the seismic services industry, including recently some related to North America. The majority of activity in the United States is taking place within various so called “shale plays.” These indications include increased bid activity in our business and higher activity reported by certain seismic contractors. However, the magnitude and breadth of this recovery is uncertain. Uncertainty about the breadth and sustainability of the global economic recovery, we believe, contributes to this unsettled situation in the energy industry.

 

Prior to the turmoil in global financial markets, which arose during 2008, the oil and gas exploration industry enjoyed generally sustained growth for a period of more than four years, fueled primarily by historically high commodity prices for oil and natural gas. We, along with much of the seismic industry, benefited from this growth. These higher prices resulted in increased activity within the oil and gas industry and, in turn, resulted in an increased demand for seismic services. Beginning in approximately October 2008, there was a dramatic decline in oil and gas prices that resulted in a significant reduction in oil and gas exploration activity. Accordingly, beginning in the fourth quarter of fiscal 2009, we began to see a decline in demand for our products and services. This decline was the most dramatic in North America, Russia and the CIS. In North America, we believe the decline resulted from the decrease in oil and natural gas prices and from difficulties in the credit markets, which limited the amount of capital available to independent oil and gas exploration companies. In Russia and the CIS, we think the decline in global oil prices and the devaluation of the ruble had a dramatic negative effect on the economics of oil and gas exploration and production operations. Furthermore, the global financial crisis had a material adverse effect on the liquidity available to these companies in Russia and the CIS. During this period, there were some areas where oil and gas exploration activities continued. We believe that this continued activity was largely driven by the super major oil and gas companies and by national oil companies.

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in ultra-deep water in the Gulf of Mexico. As a result of the explosion, ensuing fire and apparent failure of the blowout preventers, the rig sank and created a catastrophic oil spill that produced widespread economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, there have been many proposals by governmental and private constituencies to address the direct impact of the disaster and to prevent similar disasters in the future. The BOEMRE implemented a moratorium on deepwater drilling activities in the U.S. Gulf of Mexico that was lifted by Secretary of the Interior Ken Salazar on October 12, 2010. The moratorium effectively halted deepwater drilling of wells using subsea blowout preventers (“BOPs”) or surface BOPs on a floating facility. In addition, while the moratorium was in place, the BOEMRE issued a series of NTLs and adopted changes to its regulations to impose a variety of new safety and operating measures intended to help prevent a similar disaster in the future. For example, before being allowed to resume drilling in deepwater, outer continental shelf operators must certify compliance with all applicable operating regulations found in 30 C.F.R. Part 250, including those rules recently placed into effect, such as rules relating to well casing and cementing, BOPs, safety certification, emergency response, and worker training. Operators also must demonstrate the availability of adequate spill response and blowout containment resources. This oil spill and the regulatory actions taken by BOEMRE in response to the incident have had an adverse effect on seismic exploration programs in the affected areas. Notwithstanding the lifting of the moratorium, we anticipate that there will continue to be delays in the resumption of drilling-related activities in deepwater, including delays in the issuance of drilling permits, as these various regulatory initiatives are fully implemented. These new requirements also have slowed the issuance of permits for new wells in shallow waters that were not subject to the moratorium.

 

In addition to the new requirements recently imposed by the BOEMRE, there have been a variety of proposals to change existing laws and regulations that could adversely affect drilling operations and cause operators to incur increased costs. Implementation of any one or more of the various proposed changes could materially adversely affect operations in the Gulf of Mexico by raising operating costs, increasing insurance premiums, delaying drilling operations and increasing regulatory burdens, and, further, could lead to a wide variety of other unforeseeable consequences that make operations in the Gulf of Mexico and other offshore waters more difficult, more time consuming, and more costly. For example, Congress considered a variety of amendments to the Oil Pollution Act of 1990, or “OPA,” legislation in its last session in response to the Deepwater Horizon incident that, including increasing the level of financial responsibility required of offshore operators to cover costs that could be incurred in responding to an oil spill as well as increasing or totally eliminating limits for damages arising from an oil spill from a covered offshore facility that might be imposed on such operators, and it is unknown if similar legislation will be introduced and adopted in the current session of Congress. The adoption of any such amendments to OPA could significantly increase the costs of drilling and operating wells in offshore waters and thereby reduce the level of exploration and productions activities on the outer continental shelf. Any increase in the cost of operations in offshore waters and any decrease in offshore exploration and production activity could have a material adverse effect on the operation of the offshore exploration and development industry, which could have an adverse effect on our business, financial position and results of operation. While we have provided equipment for some marine seismic surveys in the Gulf of Mexico and these surveys have been delayed or cancelled, we do not expect the impact of these actions to be adversely material to us.

 

Due to the factors discussed above, the current outlook for our business remains uncertain. However, the geographic breadth of our operations and our expansive lease pool of equipment, as well as our generally stable financial position and our $35.0 million credit line position us, we believe, to address any downturn in the seismic industry for the foreseeable future.

 

The market for products sold by Seamap and the demand for the leasing of marine seismic equipment is dependent upon activity within the offshore, or marine, seismic industry, including the re-fitting of existing seismic vessels and the equipping of new vessels. Seamap has enjoyed increases in revenues over the past three fiscal years, despite of a general downturn in the marine seismic market during this period. Our Seamap business has benefited from equipping new-build vessels and from re-equipping older vessels with newer, more efficient technology. In addition, as Seamap has expanded its installed base of products, our business for replacements, spare parts, repair and support services has expanded. Certain existing and potential customers continue to express interest in our

GunLink and BuoyLink products. Some of this interest involves the upgrade of exiting GunLink and BuoyLink products to newer versions or systems with greater functionality.

 

Over the past several years we have made significant additions to our lease pool of equipment, amounting to approximately $137 million in equipment purchases during the five years ended January 31, 2011. By adding this equipment we have not only expanded the amount of equipment that we have, but have also increased the geographic expanse of our leasing operations and have expanded the types of equipment that we have in our lease pool. Additions to our lease pool during fiscal 2011 amounted to approximately $31.1 million. During fiscal 2010, we added approximately $19.6 million of new lease pool equipment, despite the decline in demand for equipment during this period. Although we did experience an overall decline in demand in fiscal 2010, there was an increase in demand for certain types of equipment, such as downhole seismic tools and three-component digital sensors. In fiscal 2009 we added approximately $34.9 million of equipment to our lease pool. As demand warrants, and as our access to capital allows, we will continue to make additions to our lease pool. Subsequent to January 31, 2011, we have added, or committed to add, approximately $25 million of additional equipment, primarily for markets such as South America and Europe. We have expanded our lease pool by acquiring different types of equipment or equipment that can be used in different types of seismic applications. For example, we added marine seismic equipment to our lease pool and have purchased downhole seismic equipment that can be utilized in a wide array of applications, some of which are not related to oil and gas exploration. These applications include 3-D surface seismic surveys, well and reservoir monitoring, analysis of fluid treatments of oil and gas wells and underground storage monitoring. We also have recently added cable-free recording technology to our lease pool of ground recording equipment. In the future we may seek to further expand the breadth of our lease pool, which could increase the amount we expend on the acquisition of lease pool equipment.

 

We also have expanded the geographic breadth of our operations by acquiring or establishing operating facilities in new locations. Most recently, in fiscal 2010, we established branch operations in Peru and in Colombia. We may seek to expand our operations in to additional locations in the future either through establishing “green field” operations or by acquiring existing operations. However, we do not currently have any specific plans to establish any such operations.

 

A significant portion of our revenues are generated from foreign sources. For the years ended January 31, 2011, 2010 and 2009, revenues from international customers totaled approximately $59.7 million, $40.0 million and $52.0 million, respectively. These amounts represent 84%, 72% and 78% of consolidated revenues in those fiscal years, respectively. The decrease in the proportion of our revenues from foreign sources in fiscal 2010 was the result of a specific contract in the United States during that period and was not, we believe, indicative of a trend. The majority of our transactions with foreign customers are denominated in United States, Australian, Canadian and Singapore dollars, Russian rubles and British pounds sterling. We have not entered, nor do we intend to enter, into derivative financial instruments for hedging or speculative purposes.

 

Our revenues and results of operations have not been materially impacted by inflation or changing prices in the past three fiscal years, except as described above.

 

Results of Operations

 

For the fiscal year ended January 31, 2011, we recorded operating income of approximately $6.9 million, compared to approximately $871,000 for the fiscal year ended January 31, 2010 and approximately $11.5 million for the fiscal year ended January 31, 2009. The increase in fiscal 2011 reflects increased leasing revenue associated with the recovery in demand for seismic equipment. The significant decline in fiscal 2010 was primarily the result of reduced equipment leasing revenues, reduced equipment sales within our leasing segment and higher lease pool depreciation charges. These declines in fiscal 2010 were offset by improved sales and gross profits from our Seamap segment and by lower general and administrative expense.

 

The gross profit for our Equipment Leasing segment increased to approximately $15.5 million in fiscal 2011, compared to approximately $7.6 million in fiscal 2010. This increase resulted from higher leasing revenues, increased sales of new seismic, hydrographic and oceanographic equipment and is despite increased depreciation expense related to our lease pool of equipment. Our Equipment Leasing segment recorded decreased gross profit in the year ended January 31, 2010, as compared to the $24.8 million for the year ended January 31, 2009. Decreased

leasing and equipment sales revenues, combined with higher direct costs and lease pool depreciation contributed to this decline. Our Seamap segment recorded gross profits of $11.2 million, $10.5 million and $8.0 million in the years ended January 31, 2011, 2010 and 2009, respectively. Seamap revenues increased in each of these years despite the overall downturn in the seismic industry that incurred during fiscal 2009 because certain customers continued to buy new equipment in order to enhance efficiency by upgrading technology. The improvement in revenues is also due in part to on-going support activities from our installed base of these products. Gross margins between fiscal 2011 and 2010 remained unchanged as approximately 50%. We improved gross profit margins for fiscal 2010 as compared to fiscal 2009 primarily through improved production efficiencies.

 

Revenues and Cost of Sales

 

Equipment Leasing

 

Revenues and cost of sales from our Equipment Leasing segment were comprised of the following:

 

 

During fiscal 2011 we began to experience a recovery in demand for seismic equipment from the decline that began in the fourth quarter of fiscal 2009, resulting in a 33% increase in leasing revenues in fiscal 2011 as compared to fiscal 2010. Geographically we experienced increased demand in South America, North America, Russia, Europe and the Middle East, and this demand appears to be continuing into fiscal 2012. We were able to respond to this increase in demand partially because of the additions we had made to our lease pool of equipment over the past few years. Also contributing to the increase in leasing revenues was our acquisition of AES in March of 2010, resulting in approximately $1.0 million in additional leasing revenues.

 

Leasing revenues for fiscal 2010 declined approximately 27% from fiscal 2009. The demand for equipment in Canada and Russia that normally occurs with the onset of winter was lower than in prior years and was significantly less than had been anticipated earlier in the year. This decline was due to significant reductions in oil and gas exploration activity as discussed above. The reduced activity in North America and the CIS, as well as other parts of the world, continued throughout fiscal 2010. During fiscal 2010, there were areas of improving demand such as South America and the Pacific Rim and late in 2010 demand began to increase in Russia and for marine equipment. These improvements did not, however, offset the overall decline in demand. During fiscal 2010, we generated approximately $5.4 million in equipment leasing revenues from one project in the United States. This was an unusually large contract and there can be no assurance that we will obtain similar contracts in the future.

From time to time, we sell equipment from our lease pool based on specific customer demand or in order to redeploy our capital in other lease pool assets. These transactions tend to occur as opportunities arise and accordingly are difficult to predict. The gross profit and related gross profit margin from the sales of lease pool equipment amounted to approximately $1.3 million (54%) in fiscal 2011, $755,000 (23%) in fiscal 2010, and $1.5 million (50%) in fiscal 2009. Often, the equipment that is sold from our lease pool has been held by us, and therefore depreciated, for some period of time. Accordingly, the equipment sold may have a relatively low net book value at the time of the sale, resulting in a relatively high gross profit from the transaction. The amount of the gross profit on a particular transaction varies greatly based primarily upon the age of the equipment.

 

Occasionally, we sell new seismic equipment that we acquire from other manufacturers, and AES regularly sells equipment that it produces for use in deploying and retrieving seismic equipment by helicopter. Often, the sales of new seismic equipment are structured with a significant down payment, with the balance financed over a period of time at a market rate of interest. The gross profit and related gross profit margin from the sales of new seismic equipment amounted to approximately $1.7 million (28%) in fiscal 2011, $188,000 (56%) in fiscal 2010 and $1.2 million (31%) in fiscal 2009. The down turn in oil and gas exploration activity in late 2009 resulted in a significant decline in demand for the purchase of new and used land seismic equipment during fiscal 2010. During fiscal 2011, AES contributed approximately $1.6 million to new and used equipment sales.

 

SAP regularly sells new hydrographic and oceanographic equipment to customers in Australia and throughout the Pacific Rim. The gross profit and related gross profit margin from the sale of new seismic, hydrographic and oceanographic equipment by SAP amounted to approximately $916,000 (20%) in fiscal 2011, $422,000 (13%), in fiscal 2010, and $1.4 million (26%) in fiscal 2009. Included in SAP equipment sales for the year ended January 31, 2011 and 2010 is approximately $500,000 and $1.0 million, respectively, related to an approximately $3.5 million contract with the Australian government. This contract was accounted for using the percentage of completion method and resulted in a gross loss of approximately $94,000 in fiscal 2010. During fiscal 2010, we incurred approximately $200,000 in unexpected costs related to the fulfillment of this contract which amounts were not reimbursed. This contract was completed and all amounts owing related to it were collected in fiscal 2011. The sale of hydrographic and oceanographic equipment in fiscal 2010 declined, we believe, due to the budgetary concerns of various governmental agencies in light of the global financial crisis. These concerns caused projects and purchases to be cancelled or postponed. In fiscal 2011 we saw a partial recovery, however, this business remains subject to uncertainty due to governmental budgetary issues in many parts of the Pacific Rim.

 

Depreciation expense related to lease pool equipment for fiscal 2011 amounted to approximately $21.5 million, as compared to approximately $17.7 million in fiscal 2010 and approximately $15.0 million in fiscal 2009. The increase in depreciation expense in each of the periods resulted from the significant additions to our lease pool of equipment that we have made in recent periods. At January 31, 2011, lease pool assets with an acquisition cost of approximately $39.7 million were fully depreciated, yet remained in service. This compares to $48.9 million at January 31, 2010 and approximately $38.6 million at January 31, 2009. These assets, though fully depreciated, are expected to continue to generate revenues through leasing activity.

 

Our business generally parallels trends in the oil and gas industry. Increased demand for our equipment results in higher revenues and generally has no impact on depreciation in the short term as our equipment is depreciated from the first month it is placed in service until it is fully depreciated. Depreciation expense is recorded monthly whether or not the equipment is actually generating revenues on a lease contract. During periods of high demand, our ability to lease older equipment, (including fully depreciated equipment) is enhanced; whereas in periods of low, the opposite is true. As a result, revenues and depreciation expense will not necessarily directly correlate. Over the long-term, depreciation expense is impacted by increases in equipment purchases to meet demand for our leased equipment. We have been able to purchase equipment at discounts through volume purchase arrangements. A lower purchase price results in lower depreciation expense than in previous periods. Although some of the equipment in our lease pool has reached the end of its depreciable life the equipment continues to be in service and continues to generate revenues. Because the depreciable life of our equipment in our industry is determined more by technical obsolescence than by usage or wear and tear, some of our equipment, although fully depreciated, is still capable of functioning appropriately.

We recorded direct costs related to seismic leasing for fiscal 2011 in the amount of approximately $3.7 million as compared to approximately $3.8 million in fiscal 2010 and approximately $2.0 million in fiscal 2009. Direct costs typically fluctuate with leasing revenues, as the three main components of direct costs are freight, repairs and sublease expense. In fiscal 2010, costs increased despite the decline in leasing revenues due to the cost of importing equipment into Russia, Peru and Colombia and due to costs associated with sub-leasing certain equipment. Fiscal 2011 direct costs were higher in relation to leasing revenues than in fiscal 2009 due to on-going sublease and transportation costs.

 

Seamap

 

Revenues and cost of sales for our Seamap segment were as follows:

 

 

Demand for Seamap’s products is generally dependent upon offshore oil and gas exploration activity. A large portion of Seamap’s sales consist of large discrete orders the timing of which is dictated by our customers. This timing generally relates to the availability of a vessel in port so that our equipment can be installed. Accordingly, there can be significant variation in sales from one period to another that does not necessarily indicate a fundamental change in demand for these products. Despite the overall decline in oil and gas exploration activity discussed above, we did not experience a decline in the demand for Seamap’s products in fiscal 2011 or fiscal 2010. We believe that we have continued to experience relatively strong demand during this period because operators of marine seismic vessels have been adding newly built vessels to replace older, less efficient vessels and have been upgrading technology on remaining vessels in order to improve operating efficiency. During fiscal 2011 we delivered four GunLink 4000 units and seven BuoyLink units, as compared to four and nine units, respectively in fiscal 2010 and one and eight units, respectively in fiscal 2009. As we have increased our installed base of GunLink and BuoyLink, as well as other products, we have generated increased revenues from the sale of spare parts, repairs and support services. As of January 31, 2011, Seamap had a backlog of approximately $8.6 million, as compared to approximately $9.3 million as of January 31, 2010 and $11.2 million as of January 31, 2009. The gross profit margin from the sale of Seamap equipment was essentially unchanged between fiscal 2011 and fiscal 2010, as production levels were approximately the same in each period and our production operations in Singapore remained stable. In both of the last two fiscal years we have been able to plan production and purchasing activities efficiently due to good visibility of the delivery requirements of our customers. This has contributed to higher gross margins than that experienced in fiscal 2009.

 

Operating Expenses

 

General and administrative expenses for fiscal 2011 amounted to approximately $16.8 million, compared to approximately $15.0 million and $17.5 million in fiscal 2010 and 2009, respectively. The increase in fiscal 2011 as compared to fiscal 2010 resulted primarily from higher compensation costs, including incentive compensation, and higher travel costs. In fiscal 2010, general and administrative expenses declined as compared to fiscal 2009 due to lower stock-based compensation, incentive compensation, travel and legal expenses. In fiscal 2011, we recorded stock-based compensation expense of approximately $1.1 million, as compared to approximately $1.4 million in fiscal 2010 and $2.2 million in fiscal 2009. Under Accounting Standards Codification (“ASC”) 718, the fair value of stock-based awards, such as stock options and restricted stock, is estimated at the time of the grant. This estimated value is then amortized over the expected vesting period of the award as compensation expense.

 

During fiscal 2011, 2010 and 2009, we recorded a provision for doubtful accounts in the amount of approximately $1.8 million, $1.4 million, and $2.9 million, respectively. The provision for doubtful accounts in fiscal 2011 and fiscal 2010 includes approximately $1.0 million related to one customer located in the CIS. Also

included in the provision for doubtful accounts are approximately $645,000 in fiscal 2011, $600,000 in fiscal 2010 and $900,000 in fiscal 2009 related to a contract receivable. The customer defaulted on this obligation and we foreclosed on the equipment and other assets that were pledged as collateral; however, we were not able to recover some of the equipment. We have reduced the carrying value of this contract receivable to an amount equal to the fair market value of the equipment we did recover, based on an independent appraisal, less the costs to retrieve the equipment. The recovered equipment, which had an appraised value of approximately $3.2 million, was added to our lease pool in fiscal 2011. We have filed a claim with our insurance carrier relating to this matter and have a claim against the bankruptcy estate of the customer. However, the amount the recovery, if any, from these claims is uncertain and therefore have not been considered in determining the amount recoverable. At January 31, 2011 and 2010, we had trade accounts and note receivables over 90 days past due of approximately $6.3 million and $6.8 million, respectively. In our industry, and in our experience, it is not unusual for accounts to become delinquent from time to time and this is not necessarily indicative of an account becoming uncollectable. As of January 31, 2011 and 2010, our allowance for doubtful accounts receivable amounted to approximately $2.7 million and $2.4 million, respectively.

 

Depreciation and amortization, other than lease pool depreciation, relates primarily to the depreciation of furniture, fixtures and office equipment and the amortization of intangible assets arising from the acquisition of Seamap.

 

Other Income and Expense

 

We completed the acquisition of AES on March 1, 2010. The fair value of the assets and liabilities we acquired, as determined by a third-party appraisal, exceeded the total consideration we paid by approximately $1.3 million. Accordingly, pursuant to the provisions of ASC 805 we recorded a gain from the bargain purchase as of the acquisition date. See Note 2 to our Consolidated Financial Statements.

 

Interest income reflects amounts earned on invested funds and finance charges related to seismic equipment sold under financing arrangements. Interest expense primarily reflects interest costs arising from borrowings under our revolving line of credit. Interest expense increased in fiscal 2011 and fiscal 2010 due to borrowings under our line of credit used to finance purchases of lease pool.

 

Other income for the year ended January 31, 2011, 2010 and 2009 includes expense of approximately $958,000, income of approximately $183,000 and income of approximately $250,000, respectively, related to net foreign exchange losses and gains. These gains resulted primarily from transactions of our foreign subsidiaries denominated in U.S. dollars.

 

Provision for Income Taxes

 

Our provision for income taxes in fiscal 2011 amounted to approximately $2.1 million. This amount included a current tax provision of approximately $2.3 million, a deferred tax benefit of approximately $230,000, a provision of approximately $23,000 related to the potential impact of uncertain tax benefits, and estimated penalties and interest of approximately $256,000 related to the potential impact of uncertain tax positions. The current tax provision is made up of a benefit of approximately $171,000 in United States taxes and approximately $2.0 million payable to foreign jurisdictions, primarily the United Kingdom, Canada, Australia, Singapore and Russia. In accordance with the provisions ASC 740, we have estimated the amount of penalties and interest that might accrue during the period should certain uncertain tax positions be resolved not in our favor. This amount is recorded as income tax expense. See Note 10 to our consolidated financial statements.

 

Certain of our Canadian tax returns have been audited by the Canadian Revenue Agency (“CRA”). See Note 10 to our Consolidated Financial Statements. In connection with these audits, the CRA and provincial taxing authorities have assessed additional taxes, penalties and interest of approximately $7.6 million. The matters giving rise to these assessments relate, we believe, primarily to issues as to whether deductions are properly taken in Canada, or should be taken in the United States. Therefore, we have made application to the CRA and to the Internal Revenue Service (“IRS”) for competent authority assistance in order to avoid potential double taxation as provided for under the tax treaty between the United States and Canada. Accordingly, we expect these issues to be resolved pursuant to the competent authority process between the CRA and IRS. We have, however, filed protective protests

with the CRA and with the Province of Alberta in case our request for competent authority assistance is denied. The issues involved in these assessments are included in our analysis of uncertain tax positions. In connection with the protests, we were required to make a payment totaling approximately $3.1 million against these potential obligations. Should we prevail in our request for assistance or in our appeals, all, or a portion, of this payment will be refunded. We are unable to estimate how long it will take to resolve these matters.

 

Our provision for income taxes in fiscal 2010 amounted to approximately $119,000. This amount included a current tax benefit of $31,000, a deferred tax benefit of $120,000, a provision of $532,000 related to the potential impact of uncertain tax benefits and the reduction of estimated penalties and interest of $262,000 related to the potential impact of uncertain tax positions. The current tax provision is made up of a benefit of approximately $1.2 million in United States taxes and approximately $1.2 million payable to foreign jurisdictions, primarily the United Kingdom, Singapore and Russia.

 

Our provision for income taxes in fiscal 2009 amounted to approximately $3.1 million. This amount included current taxes of $2.6 million, deferred taxes of $1.2 million, a benefit of $1.1 million related to the recognition of certain tax benefits and estimated penalties and interest of $400,000 related to the potential impact of uncertain tax positions. The current tax provision is made up of approximately $900,000 in United States taxes and approximately $1.7 million payable to foreign jurisdictions, primarily Australia, Singapore and Russia. Income taxes currently payable in the United States were reduced by approximately $121,000 due to deductions arising from the exercise of non-qualified stock options. This amount did not reduce our current tax provision but is credited directly to paid-in capital in accordance with the provisions of ASC 718. The $1.1 million tax benefit was recognized upon the resolution of specific uncertain tax positions. This uncertainty was resolved upon the expiration of the period in which certain of our U.S. tax returns could be examined by the IRS. In accordance with the provisions ASC 740 we have estimated the amount of penalties and interest that might accrue during the period should certain uncertain tax positions be resolved not in our favor. This amount is recorded as income tax expense. See Note 10 — to our consolidated financial statements.

 

Liquidity and Capital Resources

 

Our principal source of liquidity and capital over the past three fiscal years has been cash flows provided by operating activities and our revolving credit agreement. The principal factor that has affected our cash flows is in the level of oil and gas exploration and development activities as discussed above.

 

As of January 31, 2011, we had working capital of approximately $29.2 million and cash and cash equivalents of approximately $14.6 million, as compared to working capital of approximately $23.2 million and cash and temporary investments of approximately $6.7 million at January 31, 2010. Our working capital increased from January 31, 2010 to January 31, 2011 primarily due to working capital generated by operations and from the use of proceeds from our revolving credit facility to reduce accounts payable. The accounts payable arose primarily from the purchase of lease pool equipment.

 

Cash flows provided by operating activities amounted to approximately $30.1 million in fiscal 2011 as compared to approximately $14.1 million in fiscal 2010 and $17.6 million in fiscal 2009. In fiscal 2011, the primary sources of cash provided by operating activities were net income of $4.7 million and non-cash charges, including depreciation and amortization totaling approximately $22.7 million, provision for doubtful accounts of approximately $1.8 million and stock-based compensation of approximately $1.1 million. These were offset by non-operating cash items consisting of the gain from bargain purchase of approximately $1.3 million and the gross profit from the sale of lease pool equipment of approximately $1.3 million. The net change in other current assets and liabilities increased net cash provided by operating activities for fiscal 2011 by approximately $1.9 million. The most significant items contributing to this decrease in net cash provided by operating activities were a decrease in trade accounts and contracts receivable of approximately $2.0 million and net receipt of approximately $1.0 million related to income taxes.

 

In fiscal 2011, 2010 and 2009, we acquired approximately $31.1 million, $19.6 million and $34.9 million, respectively, of new lease pool equipment; however, the cash expenditures for these purchases did not all occur within those respective periods. As of January 31, 2011, our accounts payable included approximately $3.3 million related to lease pool purchases. As of January 31, 2010, the amount in accounts payable related to lease pool

purchases was approximately $4.9 million, while the comparable amount as of January 31, 2009 was approximately $12.0 million. Accordingly, our Consolidated Statements of Cash Flows for the years ended January 31, 2011, 2010 and 2009 indicated purchases of equipment held for lease of approximately $32.7 million, $26.7 million and $31.5 million, respectively. Subsequent to January 31, 2011 we have purchased, or committed to purchase, approximately $25.0 million of additional lease pool equipment.

 

Cash flows from investing activities for each of the three fiscal years, 2011, 2010 and 2009 reflect proceeds of approximately $2.5 million, $3.3 million and $3.0 million, respectively, from the sale of used lease pool equipment. We generally do not seek to sell our lease pool equipment; however, from time to time we will do so in response to particular customer demand. In determining whether or not to sell lease pool equipment, we weigh expected future leasing revenues from that equipment versus the potential proceeds that may be received upon the sale of the equipment. During fiscal 2011 we expended approximately $2.1 million related to the acquisition of AES. In fiscal 2009, we received an insurance settlement of approximately $1.7 million arising from the destruction of equipment during Hurricane Ike. Included within financing activities are net borrowings under our revolving line of credit of approximately $6.3 million, $9.4 million and $6.0 million in fiscal 2011, 2010 and 2009, respectively. The proceeds from these borrowings are used primarily to temporarily finance purchases of new lease pool equipment. In fiscal 2011 we entered into a note payable with an equipment supplier in the amount of approximately $3.7 million in connection with the purchase of certain lease pool equipment. Payments on borrowings in fiscal 2011 represent installment payments made on this obligation. Financing activities also include the issuance of common stock upon the exercise of stock options. These transactions resulted in cash infusions of $396,000 and $140,000 in fiscal 2011 and 2009, respectively. In fiscal 2009, SAP purchased approximately $1.4 million in short-term investments, consisting of time deposits with an Australian bank. These deposits were then pledged as collateral for performance bonds issued in connection with SAP’s contract with the Australian government. Approximately $684,000 and $744,000 of these investments were redeemed in fiscal 2011 and 2010, respectively, as the collateral was released. Due to the financing nature of this transaction, the purchase of the temporary investments is reflected within cash flows from financing activities.

 

In connection with the temporary importation of our lease pool equipment into some countries we are required to post import bonds with the customs authorities of that country. These bonds are normally provided by local insurance or surety companies. In some cases the surety requires that we post collateral to secure our obligations under the bonds. As of April 4, 2011, we have provided stand-by letters of credit totaling approximately $1.0 million as security for customs bonds.

 

In July 2010, we entered into an amended revolving credit agreement with First Victoria National Bank (the “Bank”), which provides for borrowings of up to $35.0 million. Amounts available for borrowing are determined by a borrowing base. The borrowing base is computed based upon eligible accounts receivable and eligible lease pool assets. Based upon the latest calculation of the borrowing base we believe that the entire $35.0 million of the facility is available to us, less amounts outstanding as described below. The revolving credit agreement matures on May 31, 2012. However, at any time prior to that maturity, we can convert any or all outstanding balances into a series of 48-month notes. The agreement provides that up to $7.0 million of the amount available for borrowing may be used to secure letters of credit. The credit agreement is secured by essentially all of our domestic assets. Interest is payable monthly at the prime rate plus 50 basis points. The credit agreement also provides that we may not incur or maintain indebtedness in excess of $1.0 million without the prior written consent of the Bank, except for borrowings related to the credit agreement. As of April 4, 2011, we had approximately $21.2 million outstanding under this agreement and $1.0 million of the facility had been reserved to support outstanding letters of credit. Accordingly, approximately $12.8 million was available under the facility as of that date. The credit agreement contains certain financial covenants that require us, among other things, to maintain a maximum debt to shareholders’ equity ratio, maintain a minimum ratio of current assets to current liabilities ratio and produce quarterly earnings before interest,

taxes, depreciation and amortization (“EBITDA”) of not less than a specified amount. We are in compliance with all of these covenants as more fully described as follows:

 

 

Under the terms of the revolving credit facility we may convert any outstanding balances into a series of 48-month notes. We do not currently anticipate utilizing this option, but if we were to do so we would be required to make monthly payments to amortize these notes. As of January 31, 2011, there was approximately $21.7 million outstanding under this facility. If we were to convert the entire amount into 48-month notes, our required monthly principal payments would be approximately $452,000. We would also be required to make monthly interest payments on the remaining principal balance at the then prime rate plus 50 basis points.

 

Our average borrowing levels under our revolving credit agreement for each of the years ended January 31, 2011, 2010 and 2009 were $15,700,000, $9,833,000 and $5,263,000, respectively.

 

In October 2010, in connection with the purchase of certain lease pool equipment, we entered into a secured promissory note with a supplier in the amount of approximately $3.6 million. The note is repayable in 18 monthly installments, bears interest at 8% annually and is secured by the equipment purchased. Pursuant to the terms of our revolving credit agreement we sought and received the consent of the bank for this transaction.

 

On March 1, 2010, we acquired AES for a total purchase price of approximately $3.8 million. The consideration consisted of approximately $2.1 million of cash at closing, approximately $1.4 million in promissory notes and approximately $300,000 in deferred cash payments. The promissory notes bear interest at 6% annually, payable semi-annually. The principal amount of the notes is repayable in two equal installments on March 1, 2011 and 2012. The deferred cash payments will be made upon the expiration of certain indemnity periods. The deferred cash payment bears interest at 6% annually. We may offset amounts due pursuant to the promissory notes or the deferred cash payments against indemnity claims due from the sellers. In addition, the sellers may be entitled to additional cash payments of up to approximately $750,000 should AES attain certain levels of revenues during the 24-month period following the closing.

 

Pursuant to our exclusive equipment lease agreement with Sercel, see Part I — Item 1 — “Business,” we have agreed to purchase certain amounts of equipment through December 31, 2011. As of January 31, 2011, we had purchased or placed non-cancellable orders for a portion of that equipment, which amounts are reflected in the table of contractual obligations below. In order to fulfill the required purchases under the agreement, we will be required to place orders for approximately $10.0 million of additional equipment through December 31, 2012. Should we fail to meet these obligations, Sercel will have the right to terminate the agreement, including our exclusive referral arrangement. We are negotiating an amendment and extension to this agreement; however, there can be no assurance that we will successfully conclude these negotiations.

 

The following table sets forth estimates of future payments of our consolidated contractual obligations as of January 31, 2011 (in thousands):

 

At January 31, 2011, we had unrecognized tax benefits of approximately $4.9 million related to uncertain tax positions, including approximately $3.5 million of non-current income taxes payable. We are not able to reasonably estimate when, if ever, these obligations will be paid.

 

We believe that our liquidity needs will be met from cash on hand, cash provided by operating activities and from proceeds of our existing working capital facility. However, should our needs for liquidity increase or should we decide to repay all, or a portion of, our revolving credit agreement, we may seek to issue other debt or equity securities. In March 2011, we filed a shelf registration statement with the SEC. Upon effectiveness, we may issue from time to time up to $60 million in common stock, warrants, preferred stock, debt securities or any combination thereof under the shelf registration statement. We currently have no plans to issue any such securities.

 

As of January 31, 2011, we had deposits in foreign banks equal to approximately $13.3 million. These funds may generally be transferred to our accounts in the United States without restriction. However, the transfer of these funds may result in withholding taxes payable to foreign taxing authorities. Any such transfer taxes generally may be credited against our federal income tax obligations in the United States. Additionally, the transfer of funds from our foreign subsidiaries to the United States may result in currently taxable income in the United States.

 

Off-Balance Sheet Arrangements

 

We do not have any off-balance sheet arrangements as defined by Item 303(a)(4)(ii) of Regulation S-K.

 

Critical Accounting Policies

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions in determining the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Significant estimates made by us in the accompanying consolidated financial statements relate to the allowances for uncollectible accounts receivable and inventory obsolescence; the useful lives of our lease pool assets and amortizable intangible assets and the impairment assessments of our lease pool and various intangible assets. Other areas where we have made significant estimates include the valuation of stock options, the assessment of the need for a valuation allowance related to deferred tax assets and the assessment of uncertain tax positions.

 

Critical accounting policies are those that are most important to the portrayal of a company’s financial position and results of operations and require management’s subjective judgment. Below is a brief discussion of our critical accounting policies.

 

Revenue Recognition

 

 

Allowance for Doubtful Accounts

 

We make provisions to the allowance for doubtful accounts based on a detailed review of outstanding receivable balances. Factors considered include the age of the receivable, the payment history of the customer, the general financial condition of the customer and any financial or operational leverage we may have in a particular situation. We typically do not charge fees on past due accounts, although we reserve the right to do so in most of our contractual arrangements with our customers. As of January 31, 2011, the average age of our accounts receivable was approximately 76 days.

 

Long-Lived Assets

 

We carry our lease pool of equipment and other property and equipment at cost, net of accumulated depreciation, and compute depreciation on the straight-line method over the estimated useful lives of the property and equipment, which range from two to 10 years. Cables are depreciated over two years, geophones over three years, channel boxes over five to seven years and earth vibrators and other heavy equipment are depreciated over a 10-year period. Buildings are depreciated over 30 years, property improvements are amortized over 10 years and leasehold improvements are amortized over the shorter of useful life and the life of the lease. Intangible assets are amortized from three to 15 years.

 

The estimated useful lives for rental equipment are based on our experience as to the economic useful life of our products. We review and consider industry trends in determining the appropriate useful life for our lease pool equipment, including technological obsolescence, market demand and actual historical useful service life of our lease pool equipment. Additionally, to the extent information is available publicly, we compare our depreciation policies to those of other companies in our industry for reasonableness. When we purchase new equipment for our lease pool, we begin to depreciate it upon its first use and depreciation continues each month until the equipment is fully depreciated, whether or not the equipment is actually in use during that entire time period.

 

Our policy regarding the removal of assets that are fully depreciated from our books is the following: if an asset is fully depreciated and is still expected to generate revenue, then the asset will remain on our books. However, if a fully depreciated asset is not expected to have any revenue generating capacity, then it is removed from our books.

 

In accordance with ASC 360-10, Impairment or Disposal of Long-Lived Assets, we annually assess our lease pool equipment for potential impairment. This analysis compares the estimated future undiscounted cash flows to be generated by these assets to the carrying value of the seismic equipment lease pool. Such analysis indicated that no impairment was required during fiscal 2011, 2010 or 2009. Additionally, we assess the need for impairment of our seismic equipment lease pool upon changes in circumstances that might indicate the carrying value of the assets is not recoverable. Such changes in circumstances might include a material decline in the demand for and cash flow generated by the equipment or technological advances that render a portion of the equipment obsolete. See Part 1- Item 1A — “Risk Factors.”

 

Goodwill and Other Intangible Assets

 

We carry our amortizable intangible assets at cost, net of accumulated amortization. Amortization is computed on a straight-line method over the estimated life of the asset. Currently, proprietary rights are amortized over a 12.5 to 15-year period, while covenants-not-to-compete are amortized over a three-year period. The basis for the proprietary right lives are generally based upon the results of valuation reports commissioned from third parties. Covenants-not-to-compete are amortized over the term of the contract. Goodwill is not subject to systematic amortization, but rather is tested for impairment annually.

 

Under ASC 350, Intangibles-Goodwill and Other, we perform an impairment test on goodwill and other intangibles on an annual basis and at any time circumstances indicate that an impairment may have occurred. Impairment testing compares the carrying amount of the goodwill and other intangible assets with their fair value.

When the carrying value of the goodwill and other intangible assets exceeds its fair value, an impairment charge is recorded.

 

All of our goodwill and other intangible assets relate to our Seamap segment and we have determined that our Seamap segment is the reporting unit for purposes of impairment testing. Accordingly, we estimate fair value based upon estimated discounted cash flows of that segment. As of January 31, 2011 goodwill amounted to approximately $4.3 million. The estimated fair value of the reporting unit exceeded its carrying value by approximately 116%.

 

In performing the analysis of discounted cash flows, we projected cash flow from the Seamap segment for the next four fiscal years. To determine the value of cash flows beyond the fourth year, we applied a terminal value which is expressed as a multiple of the fourth year’s cash flow. These cash flow streams are then discounted using our estimated cost of capital. The key variables utilized in this analysis are (i) the level of projected cash flows, including the growth rate for the cash flows, (ii) the terminal value applied to the estimated cash flows and (iii) our cost of capital. The sensitivity of the estimated fair value to changes in these assumptions is indicated in the following table:

 

 

These changes in assumptions, individually and in the aggregate, would not have altered our conclusion that there was no impairment of our goodwill and other intangible assets as of January 31, 2011. The level of projected cash flows used in this analysis is consistent with historical results. However, any developments or circumstances that would materially adversely impact the results of our Seamap segment could have a material adverse effect on the estimated fair value. Such developments could include a material decline in demand for marine seismic equipment or other risk factors affecting our Seamap segment. See Part 1- Item 1A- Risk Factors.

 

Income Taxes

 

Deferred tax assets and liabilities are determined based on temporary differences between income and expenses reported for financial reporting and tax reporting. We have assessed, using all available positive and negative evidence, the likelihood that the deferred tax assets will be recovered from future taxable income.

 

Under ASC 740, Income Taxes (“ASC 740”), an enterprise must use judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence should be commensurate with the extent to which it can be objectively verified. The more negative evidence that exists (i) the more positive evidence is necessary and (ii) the more difficult it is to support a conclusion that a valuation allowance is not needed for some portion, or all, of the deferred tax asset. Among the more significant types of evidence that we consider are:

 

 

In determining the valuation allowance, we consider the following positive indicators:

 

 

 

We also considered the following negative indicators:

 

 

Based on our evaluation of the evidence, as of January 31, 2011 and 2010 we did not provided a valuation allowance against our deferred tax assets.

 

The evaluation of a tax position in accordance with ASC 740 is a two-step process. In the first step, we determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that would have full knowledge of all relevant information. In the second step, a tax position that meets the more-likely-than-not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. Differences between tax positions taken in a tax return and amounts recognized in the financial statements will generally result in (1) an increase in a liability for income taxes payable or (2) a reduction of an income tax refund receivable or a reduction in a deferred tax asset or an increase in a deferred tax liability or both (1) and (2). The evaluation of tax positions and the measurement of the related benefit require significant judgment on the part of management.

 

We adopted provisions of the authoritative guidance included in ACS 740 effective February 1, 2007. As a result of the adoption we recorded a reduction in our deferred tax assets in the amount of approximately $3.4 million, recognized a liability for unrecognized tax benefits of approximately $1.2 million and decreased the February 1, 2007 balance in retained earnings by approximately $4.6 million. (See Note 10 to our consolidated financial statements.)

 

Stock-Based Compensation

 

Effective February 1, 2006, we adopted the provisions of authoritative guidance included in ASC 718 Compensation-Stock Compensation (“ASC 718”), using the modified prospective transition method. Under this method, stock-based compensation expense recognized for share-based awards includes (i) compensation expense for all stock-based compensation awards granted prior to, but not yet vested as of, February 1, 2006, based on the grant date fair value estimated in accordance with authoritative guidance in effect prior to February of 2006, and (ii) compensation expense for all stock-based compensation awards granted subsequent to February 1, 2006, based on the grant date fair value estimated in accordance with the provisions of authoritative guidance included in ASC 718.

 

Determining the grant date fair value under both ASC 718 and prior authoritative guidance requires management to make estimates regarding the variables used in the calculation of the grant date fair value. Those variables are the future volatility of our common stock price, the length of time an optionee will hold their options until exercising them (the “expected term”), and the number of options or shares that will be forfeited before they are exercised (the “forfeiture rate”). We utilize various mathematical models in calculating the variables. Share-based compensation expense could be different if we used different models to calculate the variables.

 

Market Risk

 

We are exposed to market risk, which is the potential loss arising from adverse changes in market prices and rates. We have not entered, nor do we intend to enter, into derivative financial instruments for hedging or speculative purposes.

 

Foreign Currency Risk

 

We operate in a number of foreign locations, which gives rise to risk from changes in foreign currency exchange rates. To the extent possible, we attempt to denominate our transactions in foreign locations in U.S. dollars. For those cases in which transactions are not denominated in U.S. dollars, we are exposed to risk from changes in exchange rates to the extent that non-U.S. dollar revenues exceed non-U.S. dollar expenses related to those operations. Our non-U.S. dollar transactions are denominated primarily in British pounds sterling, Russian rubles, Canadian dollars, Australian dollars and Singapore dollars. As a result of these transactions, we generally hold cash balances that are denominated in these foreign currencies. At January 31, 2011, our consolidated cash and cash equivalents included foreign currency denominated amounts equivalent to approximately $4.0 million in U.S. dollars. A 10% increase in the U.S. dollar as compared to each of these currencies would result in a loss of approximately $400,000 in the U.S. dollar value of these deposits, while a 10% decrease would result in an equal amount of gain. We do not currently hold or issue foreign exchange contracts or other derivative instruments to hedge these exposures.

 

Some of our foreign operations are conducted through wholly owned foreign subsidiaries that have functional currencies other than the U.S. dollar. We currently have subsidiaries whose functional currencies are the Canadian dollar, British pound sterling, Russian ruble, Australian dollar and the Singapore dollar. Assets and liabilities from these subsidiaries are translated into U.S. dollars at the exchange rate in effect at each balance sheet date. The resulting translation gains or losses are reflected as Accumulated Other Comprehensive Income in the Shareholders’ Equity section of our Consolidated Balance Sheets. Approximately 59% of our net assets were impacted by changes in foreign currencies in relation to the U.S. dollar. During the year ended January 31, 2011, the U.S. dollar generally decreased in value versus the above currencies. As a result of this decline, we have recognized an increase of approximately $3.4 million in Accumulated Other Comprehensive Income, primarily related to changes in the relative exchange rate of the U.S. dollar against the Canadian dollar, British pound sterling and the Australian dollar.

 

Interest Rate Risk

 

As of January 31, 2011 there was approximately $21.7 million outstanding under our revolving credit agreement. This agreement contains a floating interest rate based on the prime rate plus 50 basis points which was 3.75% as of January 31, 2011. Assuming the outstanding balance remains unchanged, a change of 100 basis points in the prime rate would result in an increase in annual interest expense of approximately $217,000. We have not entered into interest rate hedging arrangements in the past, and have no plans to do so. Do to fluctuating balances in the amount outstanding under this debt agreement we do not believe such arrangements to be cost effective.

 

 

The information required by this item appears beginning on page F-1 and is incorporated herein by reference.

 

 

There have been no changes in or disagreements on any matters of accounting principles or financial statement disclosure between us and our independent registered public accountants.

 

Evaluation of Disclosure Controls and Procedures

 

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our principal executive officer and principal financial officer have concluded that our current disclosure controls and procedures were effective as of January 31, 2011 at the reasonable assurance level.

 

Management’s Report on Internal Control Over Financial Reporting

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

As required by Rule 13a-15(c) under the Exchange Act, our management, including our principal executive officer and principal financial officer, assessed the effectiveness of our internal control over financial reporting as of January 31, 2011. In making this assessment, we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control Integrated Framework. Based on this assessment, our management, including our principal executive officer and principal financial officer, concluded that, as of January 31, 2011, our internal control over financial reporting was effective based on those criteria.

 

Changes in Internal Control over Financial Reporting

 

There was no change in our system of internal control over financial reporting during our fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

 

None.

 

 

Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this item the information to be disclosed in our definitive proxy statement for our 2011 Annual Meeting of Shareholders, which will be filed with the SEC within 120 business days of January 31, 2011.

 

We have adopted a Code of Business Conduct and Ethics, which covers a wide range of business practices and procedures. The Code of Business Conduct and Ethics represents the code of ethics applicable to our principal executive officer, principal financial officer, and principal accounting officer or controller and persons performing similar functions (“senior financial officers”). A copy of the Code of Business Conduct and Ethics is available on our website, http://www.mitchamindustries.com, and a copy will be mailed without charge, upon written request, to Mitcham Industries, Inc., P.O. Box 1175, Huntsville, Texas, 77342-1175, Attention: Robert P. Capps. We intend to disclose any amendments to or waivers of the Code of Business Conduct and Ethics on behalf of our senior financial officers on our website, at http://www.mitchamindustries.com promptly following the date of the amendment or waiver.

 

 

Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this item the information to be disclosed in our definitive proxy statement for our 2011 Annual Meeting of Shareholders, which will be filed with the SEC within 120 business days of January 31, 2011.

 

 

Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this item the information to be disclosed in our definitive proxy statement for our 2011 Annual Meeting of Shareholders, which will be filed with the SEC within 120 business days of January 31, 2011.

 

 

Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this item the information to be disclosed in our definitive proxy statement for our 2011 Annual Meeting of Shareholders, which will be filed with the SEC within 120 business days of January 31, 2011.

 

 

Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this item the information to be disclosed in our definitive proxy statement for our 2011 Annual Meeting of Shareholders, which will be filed with the SEC within 120 business days of January 31, 2011.

 

 

 

(1) Financial Statements

 

The financial statements filed as part of this Annual Report are listed in “Index to Consolidated Financial Statements” on page F-l.

 

(2) Financial Statement Schedules

 

Schedule II — Valuation and Qualifying Accounts.

(3) Exhibits

 

The exhibits required by Item 601 of Regulation S-K are listed in subparagraph (b) below.

 

 

The exhibits marked with the cross symbol (†) are filed (or furnished in the case of Exhibits 32.1 and 32.2) with this Form 10-K. The exhibits marked with the asterisk symbol (*) are management contracts or compensatory plans or arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.

 

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 6th day of April 2011.

 

 

MITCHAM INDUSTRIES, INC.

 

Billy F. Mitcham, Jr.,

President and Chief Executive Officer

(Principal Executive Officer)

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

 

 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

To the Board of Directors and Shareholders

Mitcham Industries, Inc.

Huntsville, Texas

 

We have audited the accompanying consolidated balance sheets of Mitcham Industries, Inc. and subsidiaries (the “Company”) as of January 31, 2011 and 2010, and the related consolidated statements of income, changes in shareholders’ equity and comprehensive income and cash flows for each of the three years in the period ended January 31, 2011. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our 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 Mitcham Industries, Inc. and subsidiaries as of January 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended January 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

 

We were not engaged to examine management’s assertion about the effectiveness of Mitcham Industries, Inc.’s internal control over financial reporting as of January 31, 2011 included in Item 9A of Part II in the Company’s Annual Report on Form 10-K for the year ended January 31, 2011 and, accordingly, we do not express an opinion thereon.

 

Hein & Associates LLP

 

Houston, Texas

April 6, 2011

 

 

The accompanying notes are an integral part of these consolidated financial statements.