t64662_10k.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
FORM 10-K
 
 (Mark One)
x
Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
o
Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the fiscal year ended December 31, 2008
Commission File No. 1-8726
 
RPC, INC.
 
Delaware
(State of Incorporation)
58-1550825
(I.R.S. Employer Identification No.)
 
2801 BUFORD HIGHWAY
SUITE  520
ATLANTA, GEORGIA 30329
(404) 321-2140
 
Securities registered pursuant to Section 12(b) of the Act:
 
Title of each class
COMMON STOCK, $0.10 PAR VALUE
Name of each exchange on which registered
 NEW YORK STOCK EXCHANGE
 
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.
 
o Yes x No
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes x No
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x 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. x
 
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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o
Accelerated filer x
Non-accelerated filer o
Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o No x
 
The aggregate market value of RPC, Inc. Common Stock held by non-affiliates on June 30, 2008, the last business day of the registrant’s most recently completed second fiscal quarter, was $472,396,172 based on the closing price on the New York Stock Exchange on June 30, 2008 of $16.80 per share.
 
RPC, Inc. had 98,419,782 shares of Common Stock outstanding as of February 13, 2009.
 
Documents Incorporated by Reference
 
Portions of the Proxy Statement for the 2009 Annual Meeting of Stockholders of RPC, Inc. are incorporated by reference into Part III, Items 10 through 14 of this report.
 



 
PART I
 
Throughout this report, we refer to RPC, Inc., together with its subsidiaries, as “we,” “us,” “RPC” or “the Company.”
 
Forward-Looking Statements

Certain statements made in this report that are not historical facts are “forward-looking statements” under the Private Securities Litigation Reform Act of 1995. Such forward-looking statements may include, without limitation, statements that relate to our business strategy, plans and objectives, and our beliefs and expectations regarding future demand for our products and services and other events and conditions that may influence the oilfield services market and our performance in the future.  Forward-looking statements made elsewhere in this report include without limitation statements regarding our belief that the long term prospects for our business are favorable due to growing demand for oil and natural gas and declining production of these commodities; our belief that the gas-directed drilling will represent at least 75 percent of the total drilling rig count in the foreseeable future; our belief that drilling activity and demand for our services appears to be weakening in the first quarter of 2009; our expectation to continue to focus on the development of international business opportunities in current and other international markets; our belief that the high returns on our purchases of revenue-producing equipment will continue, thus justifying the funding of these expenditures with debt; our ability to obtain other customers in the event of a loss of our largest customers; the adequacy of our insurance coverage; the impact of lawsuits, legal proceedings and claims on our business and financial condition; our expectation to continue to pay cash dividends to the common stockholders, subject to the earnings and financial condition of the Company and other relevant factors; our expectation that our consolidated revenues for 2009 will decrease compared to 2008; our expectations regarding capital expenditures in 2009; our ability to maintain sufficient liquidity and a conservative capital structure; our belief that the Company will not make any additional contributions to the defined benefit pension plan in 2009; our ability to reduce the amount drawn on our credit facility over the course of 2009; our ability to fund capital requirements in the future; the adequacy of our liquidity in the future; the estimated amount of our capital expenditures and contractual obligations for future periods; estimates made with respect to our critical accounting policies; and the effect of new accounting standards.
 
The words “may,” “will,” “expect,” “believe,” “anticipate,” “project,” “estimate,” and similar expressions generally identify forward-looking statements. Such statements are based on certain assumptions and analyses made by our management in light of its experience and its perception of historical trends, current conditions, expected future developments and other factors it believes to be appropriate. We caution you that such statements are only predictions and not guarantees of future performance and that actual results, developments and business decisions may differ from those envisioned by the forward-looking statements.  See “Risk Factors” contained in Item 1A. for a discussion of factors that may cause actual results to differ from our projections.
 
Item 1. Business
 
Organization and Overview
 
RPC is a Delaware corporation originally organized in 1984 as a holding company for several oilfield services companies and is headquartered in Atlanta, Georgia.
 
RPC provides a broad range of specialized oilfield services and equipment primarily to independent and major oil and gas companies engaged in the exploration, production and development of oil and gas properties throughout the United States, including the Gulf of Mexico, mid-continent, southwest and Rocky Mountain regions, and in selected international markets. The services and equipment provided include, among others, (1) pressure pumping services, (2) coiled tubing services, (3) snubbing services (also referred to as hydraulic workover services), (4) nitrogen services, (5) the rental of drill pipe and other specialized oilfield equipment, (6) downhole tool rental services and (7) firefighting and well control. RPC acts as a holding company for its operating units, Cudd Energy Services, Patterson Rental and Fishing Tools, Bronco Oilfield Services, Thru Tubing Solutions, Well Control School, and others.  As of December 31, 2008, RPC had approximately 2,500 employees.
 
Business Segments
 
RPC’s service lines have been aggregated into two reportable oil and gas services business segments, Technical Services and Support Services, because of the similarities between the financial performance and approach to managing the service lines within each of the segments, as well as the economic and business conditions impacting their business activity levels.
 
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Technical Services include RPC’s oil and gas service lines that utilize people and equipment to perform value-added completion, production and maintenance services directly to a customer’s well. The demand for these services is generally influenced by customers’ decisions to invest capital toward initiating production in a new oil or natural gas well, improving production flows in an existing formation, or to address well control issues. This business segment consists primarily of pressure pumping, coiled tubing, snubbing, nitrogen, well control, downhole tools, wireline, and fishing. The principal markets for this business segment include the United States, including the Gulf of Mexico, mid-continent, southwest and Rocky Mountain regions, and contract or project work in selected international locations in the last three years including primarily Africa, Canada, China, Eastern Europe, Latin America and the Middle East. Customers include major multi-national and independent oil and gas producers, and selected nationally owned oil companies.
 
Support Services include RPC’s oil and gas service lines that primarily provide equipment for customer use or services to assist customer operations. The equipment and services include drill pipe and related tools, pipe handling, pipe inspection and storage services, and oilfield training services. The demand for these services tends to be influenced primarily by customer drilling-related activity levels. The principal markets for this segment include the United States, including the Gulf of Mexico, mid-continent and Rocky Mountain regions and project work in selected international locations in the last three years including primarily Canada, Latin America and the Middle East. Customers primarily include domestic operations of major multi-national and independent oil and gas producers, and selected nationally owned oil companies.
 
Technical Services
 
The following is a description of the primary service lines conducted within the Technical Services business segment:
 
Pressure Pumping. Pressure pumping services, which accounted for approximately 41 percent of 2008 revenues, 40 percent of 2007 revenues and 38 percent of 2006 revenues, are provided to customers throughout the Gulf Coast, mid-continent and Rocky Mountain regions of the United States and are generally utilized to initiate production in new or enhance production in existing customer wells. Pressure pumping services involve using complex, truck or skid-mounted equipment designed and constructed for each specific pumping service offered. The mobility of this equipment permits pressure pumping services to be performed in varying geographic areas. Principal materials utilized in the pressure pumping business include fracturing proppants, acid and bulk chemical additives. Generally, these items are available from several suppliers, and the Company utilizes more than one supplier for each item. Pressure pumping services offered include:
 
Fracturing — Fracturing services are performed to stimulate production of oil and natural gas by increasing the permeability of a formation. The fracturing process consists of pumping nitrogen or a fluid gel into a cased well at sufficient pressure to fracture the formation at desired depths. Sand, bauxite or synthetic proppant, which is suspended in the gel, is pumped into the fracture. When the pressure is released at the surface, the fluid gel returns to the well, but the proppant remain in the fracture, thus keeping it open so that oil and natural gas can flow through the fracture into the well. In some cases, fracturing is performed in formations with a high amount of carbonate rock by an acid solution pumped under pressure without a proppant or with small amounts of proppant.
 
Acidizing — Acidizing services are also performed to stimulate production of oil and natural gas, but they are used in wells that have undergone formation damage due to the buildup of various materials that block the formation. Acidizing entails pumping large volumes of specially formulated acids into reservoirs to dissolve barriers and enlarge crevices in the formation, thereby eliminating obstacles to the flow of oil and natural gas. Acidizing services can also enhance production in limestone formations.
 
Coiled Tubing. Coiled tubing services, which accounted for approximately nine percent of 2008 and 2007 revenues,  and 10 percent of 2006 revenues, involve the injection of coiled tubing into wells to perform various applications and functions for use principally in well-servicing operations. Coiled tubing is a flexible steel pipe with a diameter of less than four inches manufactured in continuous lengths of thousands of feet and wound or coiled around a large reel. It can be inserted through existing production tubing and used to perform workovers without using a larger, more costly workover rig. Principal advantages of employing coiled tubing in a workover operation include: (i) not having to “shut-in” the well during such operations, (ii) the ability to reel continuous coiled tubing in and out of a well significantly faster than conventional pipe, (iii) the ability to direct fluids into a wellbore with more precision, and (iv) enhanced access to remote or offshore fields due to the smaller size and mobility of a coiled tubing unit compared to a workover rig.  There are several manufacturers of flexible steel pipe used in coiled tubing services, and the Company believes that its sources of supply are adequate.
 
Snubbing. Snubbing (also referred to as hydraulic workover services), which accounted for approximately seven percent of 2008 revenues, 10 percent of 2007 revenues, and 11 percent of 2006 revenues, involves using a hydraulic workover rig that permits an operator to repair damaged casing, production tubing and downhole production equipment in a high-pressure environment. A snubbing unit makes it possible to remove and replace downhole equipment while maintaining pressure in the well. Customers benefit because these operations can be performed without removing the pressure from the well, which stops production and can damage the formation, and because a snubbing rig can perform many applications at a lower cost than other alternatives. Because this service involves a very hazardous process that entails high risk, the snubbing segment of the oil and gas services industry is limited to a relatively few operators who have the experience and knowledge required to perform such services safely and efficiently.
 
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Nitrogen. Nitrogen accounted for approximately eight percent of 2008 revenues, seven percent of 2007 revenues, and eight percent of 2006 revenues.  There are a number of uses for nitrogen, an inert, non-combustible element, in providing services to oilfield customers and industrial users outside of the oilfield. For our oilfield customers, nitrogen can be used to clean drilling and production pipe and displace fluids in various drilling applications. It also can be used to create a fire-retardant environment in hazardous blowout situations and as a fracturing medium for our fracturing service line. In addition, nitrogen can be complementary to our snubbing and coiled tubing service lines, because it is a non-corrosive medium and is frequently injected into a well using coiled tubing. Nitrogen is complementary to our pressure pumping service line as well, because foam-based nitrogen stimulation is appropriate in certain sensitive formations in which the fluids used in fracturing or acidizing would damage a customer's well.
 
For non-oilfield industrial users, nitrogen can be used to purge pipelines and create a non-combustible environment. RPC stores and transports nitrogen and has a number of pumping unit configurations that inject nitrogen in its various applications. Some of these pumping units are set up for use on offshore platforms or inland waters. RPC purchases its nitrogen in liquid form from several suppliers and believes that these sources of supply are adequate.
 
Downhole Tools. Thru Tubing Solutions (“TTS”) accounted for approximately nine percent of 2008 revenues, seven percent of 2007 revenues, and six percent of 2006 revenues.  TTS provides services and proprietary downhole motors, fishing tools and other specialized downhole tools and processes to operators and service companies in drilling and production operations, including casing perforation at the completion stage of an oil or gas well.  The services that TTS provides are especially suited for unconventional drilling and completion activities.  TTS’ experience providing reliable tool services allows it to work in a pressurized environment with virtually any coiled tubing unit or snubbing unit.
 
Well Control. Cudd Energy Services specializes in responding to and controlling oil and gas well emergencies, including blowouts and well fires, domestically and internationally. In connection with these services, Cudd Energy Services, along with Patterson Services, has the capacity to supply the equipment, expertise and personnel necessary to restore affected oil and gas wells to production. In the last nine years, the Company has responded to well control situations in several international locations including Algeria, Argentina, Australia, Bolivia, Canada, Colombia, Egypt, India, Kuwait, Peru, Qatar, Taiwan, Trinidad and Venezuela.
 
The Company’s professional firefighting staff has many years of aggregate industry experience in responding to well fires and blowouts. This team of 11 experts responds to well control situations where hydrocarbons are escaping from a well bore, regardless of whether a fire has occurred. In the most critical situations, there are explosive fires, the destruction of drilling and production facilities, substantial environmental damage and the loss of hundreds of thousands of dollars per day in well operators’ production revenue. Since these events ordinarily arise from equipment failures or human error, it is impossible to predict accurately the timing or scope of this work. Additionally, less critical events frequently occur in connection with the drilling of new wells in high-pressure reservoirs. In these situations, the Company is called upon to supervise and assist in the well control effort so that drilling operations can resume as promptly as safety permits.
 
Wireline Services. Wireline is classified into two types of services: slick or braided line and electric line.  In both, a spooled wire is unwound and lowered into a well, conveying various types of tools or equipment.  Slick or braided line services use a non-conductive line primarily for jarring objects into or out of a well, as in fishing or plug-setting operations.  Electric line services lower an electrical conductor line into a well allowing the use of electrically-operated tools such as perforators, bridge plugs and logging tools.  Wireline services can be an integral part of the plug and abandonment process, near the end of the life cycle of a well.
 
Fishing. Fishing involves the use of specialized tools and procedures to retrieve lost equipment from a well drilling operation and producing wells. It is a service required by oil and gas operators who have lost equipment in a well. Oil and natural gas production from an affected well typically declines until the lost equipment can be retrieved. In some cases, the Company creates customized tools to perform a fishing operation. The customized tools are maintained by the Company after the particular fishing job for future use if a similar need arises.
 
Support Services
 
The following is a description of the primary service lines conducted within the Support Services business segment:
 
Rental Tools. Rental tools accounted for approximately 11 percent of 2008 revenues, and 13 percent of 2007 and 2006 revenues.  The Company rents specialized equipment for use with onshore and offshore oil and gas well drilling, completion and workover activities. The drilling and subsequent operation of oil and gas wells generally require a variety of equipment. The equipment needed is in large part determined by the geological features of the production zone and the size of the well itself. As a result, operators and drilling contractors often find it more economical to supplement their tool and tubular inventories with rental items instead of owning a complete inventory. The Company’s facilities are strategically located to serve the major staging points for oil and gas activities in the Gulf of Mexico, mid-continent region and Rocky Mountains.
 
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 Patterson Rental Tools offers a broad range of rental tools including:
 
Blowout Preventors
Diverters
High Pressure Manifolds and Valves
Drill Pipe
Hevi-wate Drill Pipe
Drill Collars
Tubing
Handling Tools
Production Related Rental Tools
Coflexip Hoses
Pumps
 
 
Oilfield Pipe Inspection Services, Pipe Management and Pipe Storage. Pipe inspection services include Full Body Electromagnetic and Phased Array Ultrasonic inspection of pipe used in oil and gas wells. These services are provided at both the Company’s inspection facilities and at pipe mills in accordance with negotiated sales and/or service contracts. Our customers are major oil companies and steel mills, for which we provide in-house inspection services, inventory management and process control of tubing, casing, and drill pipe.  Our locations in Channelview, Texas and Morgan City, Louisiana are equipped with large capacity cranes, specially designed forklifts and a computerized inventory system to serve a variety of storage and handling services for both the oilfield and non-oilfield customers.
 
Well Control School. Well Control School provides industry and government accredited training for the oil and gas industry both in the United States and in several international locations. Well Control School provides this training in various formats including conventional classroom training, interactive computer training including training delivered over the internet, and mobile simulator training.
 
Energy Personnel International. Energy Personnel International provides drilling and production engineers, well site supervisors, project management specialists, and workover and completion specialists on a consulting basis to the oil and gas industry to meet customers’ needs for staff engineering and wellsite management.
 
Refer to Note 12 in the Notes to the Consolidated Financial Statements for additional financial information on our business segments.
 
Industry
 
United States. RPC provides its services to its domestic customers through a network of facilities strategically located to serve the Gulf of Mexico, the mid-continent, the southwest and the Rocky Mountains production fields. Demand for RPC’s services in the U.S. tends to be extremely volatile and fluctuates with current and projected price levels of oil and natural gas and activity levels in the oil and gas industry. Customer activity levels are influenced by their decisions about capital investment toward the development and production of oil and gas reserves.
 
Due to aging oilfields and lower-cost sources of oil internationally, the drilling rig count in the U.S. has declined by approximately 62 percent from its peak in 1981. Due to enhanced technology, however, more wells are being drilled and the domestic production of oil and natural gas remains roughly equivalent to prior years.  Record low drilling activity levels were experienced in 1986, 1992, 1999 (with April 1999 recording the lowest U.S. drilling rig count in the industry’s history) and again in 2002.  At the beginning of 2008, there were 1,774 domestic working drilling rigs, up 37 percent from the third quarter 2001 peak during that industry cycle.  U.S. domestic drilling activity rose during the first three quarters of 2008 and peaked in the third quarter at a rig count of 2,031, which was 57 percent higher than the third quarter 2001 peak.  In 2008 the average rig count of 1,879 increased seven percent compared to the prior year.  During 2008 the average price of natural gas increased by approximately 27 percent, and the average price of oil increased by over 37 percent.   However, the price of oil fell almost 37 percent during the fourth quarter of 2008 compared to the prior year and the price of natural gas fell almost 10 percent during the period compared to the prior year.  The average domestic rig count was more than six percent higher in the fourth quarter of 2008 than the prior year.  However, it began to fall during the fourth quarter of 2008 as declining commodity prices and the global economic slowdown, coupled with declining availability of capital for drilling projects, caused industry activity levels to decline.  The change in domestic drilling activity was consistent with the change in the prices of oil and natural gas.  We are concerned that the current prices of oil and natural gas are not high enough to sustain recent exploration and production activity levels.  However, we also believe, along with our customers, that the long term prospects for our business are favorable due to growing demand for oil and natural gas and declining production of these commodities.
 
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Gas drilling rigs have represented an increasing percentage of the total drilling rig count, and have represented at least 75 percent of the drilling rig count each year since 2001.  In 2008, gas drilling rigs represented 79 percent of total drilling activity. This percentage, which is lower than in previous years, is partly due to the tremendous increase in the price of oil that occurred in 2008.  Demand for natural gas is continuing to rise, primarily as a result of increased emphasis on gas-fired power generation, although demand fluctuates in the short term due to factors such as economic activity and the weather. Also, unlike oil, foreign imports of natural gas do not compete with domestic production. This lack of foreign competition tends to keep prices high. Based on current demand levels for natural gas as well as the high oil and gas well depletion rates experienced over the past several years, it is anticipated that gas-directed drilling will represent at least 75 percent of the total drilling rig count in the foreseeable future. The demand for RPC’s services is driven more by gas-directed drilling than oil-directed drilling, because our services are particularly useful for deeper, higher pressure wells, which tend to be the wells that produce natural gas.  In addition, there are certain types of wells, predominately natural gas, being drilled in the U.S. domestic market for which there is a higher demand for RPC’s services.  Known as either directional or horizontal wells, these natural gas wells are more difficult and costly to complete.  Because they are drilled through a narrow formation, they require additional stimulation when they are completed, and since they are not drilled in a straight vertical direction from the Earth’s surface, they require tools and drilling mechanisms that are flexible, rather than rigid, and can be steered once they are downhole.  Specifically, these types of wells require RPC’s pressure pumping and coiled tubing services, as well as our downhole tools and services.
 
Thus, in North America the demand for our services and products depends more on natural gas than oil development.  Drilling activity and demand for our services was very strong during the first three quarters of 2008 but decreased during the fourth quarter of 2008 and appears to be weakening early in the first quarter of 2009.
 
International. RPC has historically operated in several countries outside of the United States, although international revenues have never accounted for more than 10 percent of total revenues.  Over the past several years, RPC has continued its focus on developing international opportunities, although our equipment investments over the last couple of years has emphasized domestic rather than international expansion.  International revenues for 2008 decreased due to lower customer activity levels in Turkmenistan and Hungary.  During 2008, RPC provided snubbing and oilfield training services in Australia, Bolivia, Canada, Egypt, Gabon, Mexico, Oman, Saudi Arabia and the United Arab Emirates, among other countries. We also provided rental tools, well control services, downhole motors, fishing tool services and oilfield training to customers located in Australia, Bolivia and Mexico.  We continue to focus on the development of international opportunities in these and other markets, although we believe that it will continue to be less than 10 percent of total revenues.
 
RPC provides services to its international customers through branch locations or wholly-owned foreign subsidiaries. The international market is prone to political uncertainties, including the risk of civil unrest and conflicts. However, due to the significant investment requirement and complexity of international projects, customers’ drilling decisions relating to such projects tend to be evaluated and monitored with a longer-term perspective with regard to oil and natural gas pricing, and therefore have the potential to be more stable than most U.S. domestic operations.  Additionally, the international market is dominated by major oil companies and national oil companies which tend to have different objectives and more operating stability than the typical independent oil and gas producer in the U.S.  Predicting the timing and duration of contract work is not possible.  Pursuing selective international opportunities for revenue growth continues to be a strong emphasis for RPC. Refer to Note 12 in the Notes to Consolidated Financial Statements for further information on our international operations.
 
Growth Strategies
 
RPC’s primary objective is to generate excellent long-term returns on investment through the effective and conservative management of its invested capital, thus yielding strong cash flow and asset appreciation. This objective continues to be pursued through strategic investments and opportunities designed to enhance the long-term value of RPC while improving market share, product offerings and the profitability of existing businesses. Growth strategies are focused on selected areas and markets in which we believe there exist opportunities for higher growth, market penetration, or enhanced returns achieved through consolidations or through providing proprietary value-added products and services. RPC intends to focus on specific market segments in which it believes that it has a competitive advantage or there exists significant growth potential.
 
RPC seeks to expand its service capabilities through a combination of internal growth, acquisitions, joint ventures and strategic alliances. Because of the fragmented nature of the oil and gas services industry, RPC believes a number of attractive acquisition opportunities exist.  However, near-term business conditions do not justify sellers’ price expectations, so we believe we generate better returns growing organically in service lines and geographic locations in which we have experience and presence.
 
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RPC has traditionally had a conservative capital structure with minimal debt.  During 2006, however, we established a new revolving credit facility to fund the purchase of revenue-producing equipment and other working capital requirements to pursue our growth plan. We pursued this capital source because of the high returns on investment that had been generated by many of our service lines during the previous several years, and because of the low cost and ready availability of debt capital. By 2008, purchases of revenue-producing equipment under our growth plan were substantially complete, and we believe that the high returns on investment generated by many of our service lines will continue, thus justifying the funding of these expenditures with debt.  At the end of 2008, RPC easily complied with the debt covenants in our revolving credit agreement and our level of debt was conservative compared to a number of our peers.
 
Customers
 
Demand for RPC’s services and products depends primarily upon the number of oil and natural gas wells being drilled, the depth and drilling conditions of such wells, the number of well completions and the level of production enhancement activity worldwide. RPC’s principal customers consist of major and independent oil and natural gas producing companies. During 2008, RPC provided oilfield services to several hundred customers, none of which accounted for more than 10 percent of consolidated revenues. While the loss of certain of RPC’s largest customers could have a material adverse effect on Company revenues and operating results in the near term, management believes RPC would be able to obtain other customers for its services in the event of a loss of any of its largest customers. Sales are generated by RPC’s sales force and through referrals from existing customers. There are long-term written contracts for services and equipment with certain international and domestic customers, although revenues earned under such contracts are a small percentage of total revenues. Due to the short lead time between ordering services or equipment and providing services or delivering equipment, there is no significant sales backlog in most of our service lines.
 
Competition
 
RPC operates in highly competitive areas of the oilfield services industry. RPC’s products and services are sold in highly competitive markets, and its revenues and earnings are affected by changes in prices for our services, fluctuations in the level of customer activity in major markets, general economic conditions and governmental regulation. RPC competes with many large and small oilfield industry competitors, including the largest integrated oilfield services companies. RPC believes that the principal competitive factors in the market areas that it serves are product and service quality and availability, reputation for safety and technical proficiency, and price.
 
The oil and gas services industry includes a small number of dominant global competitors including, among others, Halliburton Energy Services Group, a division of Halliburton Company, BJ Services Company and Schlumberger Ltd., and a significant number of locally oriented businesses.
 
Facilities/Equipment
 
RPC’s equipment consists primarily of oil and gas services equipment used either in servicing customer wells or provided on a rental basis for customer use. Substantially all of this equipment is Company owned.  RPC purchases oilfield service equipment from a limited number of manufacturers.  These manufacturers of our oilfield service equipment may not be able to meet our requests for timely delivery during periods of high demand which may result in delayed deliveries of equipment and higher prices for equipment.
 
RPC both owns and leases regional and district facilities from which its oilfield services are provided to land-based and offshore customers. RPC’s principal executive offices in Atlanta, Georgia are leased. The Company has two primary administrative buildings, one in Houston, Texas that includes the Company’s operations, engineering, sales and marketing headquarters, and one in Houma, Louisiana that includes certain administrative functions. RPC believes that its facilities are adequate for its current operations.  For additional information with respect to RPC’s lease commitments, see Note 9 of the Notes to Consolidated Financial Statements.
 
Governmental Regulation
 
RPC’s business is affected by state, federal and foreign laws and other regulations relating to the oil and gas industry, as well as laws and regulations relating to worker safety and environmental protection. RPC cannot predict the level of enforcement of existing laws and regulations or how such laws and regulations may be interpreted by enforcement agencies or court rulings, whether additional laws and regulations will be adopted, or the effect such changes may have on it, its businesses or financial condition.
 
In addition, our customers are affected by laws and regulations relating to the exploration for and production of natural resources such as oil and natural gas. These regulations are subject to change, and new regulations may curtail or eliminate our customers’ activities in certain areas where we currently operate. We cannot determine the extent to which new legislation may impact our customers’ activity levels, and ultimately, the demand for our services.
 
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Intellectual Property
 
RPC uses several patented items in its operations, which management believes are important but are not indispensable to RPC’s success. Although RPC anticipates seeking patent protection when possible, it relies to a greater extent on the technical expertise and know-how of its personnel to maintain its competitive position.
 
Availability of Filings
 
RPC makes available, free of charge, on its website, www.rpc.net, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports on the same day as they are filed with the Securities and Exchange Commission.
 
1A. Risk Factors
 
Demand for our products and services is affected by the volatility of oil and natural gas prices.
 
Oil prices affect demand throughout the oil and natural gas industry, including the demand for our products and services. Our business depends in large part on the conditions of the oil and gas industry, and specifically on the capital investments of our customers related to the exploration and production of oil and natural gas. When these capital investments decline, our customers’ demand for our services declines.
 
Although the production sector of the oil and gas industry is less immediately affected by changing prices, and, as a result, less volatile than the exploration sector, producers react to declining oil and gas prices by curtailing capital spending, which would adversely affect our business. A prolonged low level of customer activity in the oil and gas industry will adversely affect the demand for our products and services and our financial condition and results of operations.
 
The relationship between the prices of oil and natural gas and our customers’ drilling and production activities may not be highly correlated in the future.
 
Historically, fluctuations in the prices of oil and natural gas have led to immediate corresponding changes in our customers’ drilling and production activities as measured by the domestic rig count. This relationship was very strong in 2008 and recent years, although it was not as strong several years ago. If this correlation is weak in the future, then it is possible that increases in the prices of oil and natural gas will not lead to an increase in our customers’ activities, and our future operating results could be negatively impacted.
 
We may be unable to compete in the highly competitive oil and gas industry in the future.
 
We operate in highly competitive areas of the oilfield services industry. The products and services in our industry segments are sold in highly competitive markets, and our revenues and earnings have in the past been affected by changes in competitive prices, fluctuations in the level of activity in major markets and general economic conditions. We compete with the oil and gas industry’s many large and small industry competitors, including the largest integrated oilfield service providers. We believe that the principal competitive factors in the market areas that we serve are product and service quality and availability, reputation for safety, technical proficiency and price. Although we believe that our reputation for safety and quality service is good, we cannot assure you that we will be able to maintain our competitive position.
 
We may be unable to identify or complete acquisitions.
 
Acquisitions have been and may continue to be a key element of our business strategy. We cannot assure you that we will be able to identify and acquire acceptable acquisition candidates on terms favorable to us in the future. We may be required to incur substantial indebtedness to finance future acquisitions and also may issue equity securities in connection with such acquisitions. The issuance of additional equity securities could result in significant dilution to our stockholders. We cannot assure you that we will be able to integrate successfully the operations and assets of any acquired business with our own business. Any inability on our part to integrate and manage the growth from acquired businesses could have a material adverse effect on our results of operations and financial condition.
 
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Our operations are affected by adverse weather conditions.
 
Our operations are directly affected by the weather conditions in several domestic regions, including the Gulf of Mexico, the Gulf Coast, the mid-continent and the Rocky Mountains. Hurricanes and other storms prevalent in the Gulf of Mexico and along the Gulf Coast during certain times of the year may also affect our operations, and severe hurricanes may affect our customers' activities for a period of several years.  While the impact of these storms may increase the need for certain of our services over a longer period of time, such storms can also decrease our customers' activities immediately after they occur.  Such hurricanes may also affect the prices of oil and natural gas by disrupting supplies in the short term, which may increase demand for our services in geographic areas not damaged by the storms.  Prolonged rain, snow or ice in many of our locations may temporarily prevent our crews and equipment from reaching customer work sites.  Due to seasonal differences in weather patterns, our crews may operate more days in some periods than others. Accordingly, our operating results may vary from quarter to quarter, depending on the impact of these weather conditions.
 
Our inability to attract and retain skilled workers may impair growth potential and profitability.
 
Our ability to remain productive and profitable will depend substantially on our ability to attract and retain skilled workers. Our ability to expand our operations is in part impacted by our ability to increase our labor force. The demand for skilled oilfield employees is high, and the supply is very limited. A significant increase in the wages paid by competing employers could result in a reduction in our skilled labor force, increases in the wage rates paid by us, or both. If either of these events occurred, our capacity and profitability could be diminished, and our growth potential could be impaired.
 
Our concentration of customers in one industry may impact our overall exposure to credit risk.
 
Substantially all of our customers operate in the energy industry. This concentration of customers in one industry may impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. We perform ongoing credit evaluations of our customers and do not generally require collateral in support of our trade receivables.
 
Our business has potential liability for litigation, personal injury and property damage claims assessments.
 
Our operations involve the use of heavy equipment and exposure to inherent risks, including blowouts, explosions and fires. If any of these events were to occur, it could result in liability for personal injury and property damage, pollution or other environmental hazards or loss of production. Litigation may arise from a catastrophic occurrence at a location where our equipment and services are used. This litigation could result in large claims for damages. The frequency and severity of such incidents will affect our operating costs, insurability and relationships with customers, employees and regulators. These occurrences could have a material adverse effect on us. We maintain what we believe is prudent insurance protection. We cannot assure you that we will be able to maintain adequate insurance in the future at rates we consider reasonable or that our insurance coverage will be adequate to cover future claims and assessments that may arise.
 
Our operations may be adversely affected if we are unable to comply with regulatory and environmental laws.
 
Our business is significantly affected by stringent environmental laws and other regulations relating to the oil and gas industry and by changes in such laws and the level of enforcement of such laws. We are unable to predict the level of enforcement of existing laws and regulations, how such laws and regulations may be interpreted by enforcement agencies or court rulings, or whether additional laws and regulations will be adopted. The adoption of laws and regulations curtailing exploration and development of oil and gas fields in our areas of operations for economic, environmental or other policy reasons would adversely affect our operations by limiting demand for our services. We also have potential environmental liabilities with respect to our offshore and onshore operations, and could be liable for cleanup costs, or environmental and natural resource damage due to conduct that was lawful at the time it occurred, but is later ruled to be unlawful. We also may be subject to claims for personal injury and property damage due to the generation of hazardous substances in connection with our operations. We believe that our present operations substantially comply with applicable federal and state pollution control and environmental protection laws and regulations. We also believe that compliance with such laws has had no material adverse effect on our operations to date. However, such environmental laws are changed frequently. We are unable to predict whether environmental laws will, in the future, materially adversely affect our operations and financial condition. Penalties for noncompliance with these laws may include cancellation of permits, fines, and other corrective actions, which would negatively affect our future financial results.
 
Our international operations could have a material adverse effect on our business.
 
Our operations in various countries including, but not limited to, Africa, Canada, China, Eastern Europe, Latin America and the Middle East are subject to risks. These risks include, but are not limited to, political changes, expropriation, currency restrictions and changes in currency exchange rates, taxes, boycotts and other civil disturbances.  The occurrence of any one of these events could have a material adverse effect on our operations.
 
9

 
Our common stock price has been volatile.
 
Historically, the market price of common stock of companies engaged in the oil and gas services industry has been highly volatile. Likewise, the market price of our common stock has varied significantly in the past.
 
Our management has a substantial ownership interest, and public shareholders may have no effective voice in the management of the Company.
 
The Company has elected the “Controlled Corporation” exemption under Rule 303A of the New York Stock Exchange (“NYSE”) Company Guide. The Company is a “Controlled Corporation” because a group that includes the Company’s Chairman of the Board, R. Randall Rollins and his brother, Gary W. Rollins, who is also a director of the Company, and certain companies under their control, controls in excess of fifty percent of the Company’s voting power. As a “Controlled Corporation,” the Company need not comply with certain NYSE rules including those requiring a majority of independent directors.
 
RPC’s executive officers, directors and their affiliates hold directly or through indirect beneficial ownership, in the aggregate, approximately 71 percent of RPC’s outstanding shares of common stock. As a result, these stockholders effectively control the operations of RPC, including the election of directors and approval of significant corporate transactions such as acquisitions and other matters requiring stockholder approval. This concentration of ownership could also have the effect of delaying or preventing a third party from acquiring control over the Company at a premium.
 
Our management has a substantial ownership interest, and the availability of the Company’s common stock to the investing public may be limited.
 
The availability of RPC’s common stock to the investing public may be limited to those shares not held by the executive officers, directors and their affiliates, which could negatively impact RPC’s stock trading prices and affect the ability of minority stockholders to sell their shares. Future sales by executive officers, directors and their affiliates of all or a portion of their shares could also negatively affect the trading price of our common stock.
 
Provisions in RPC's Certificate of Incorporation and Bylaws may inhibit a takeover of RPC.
 
RPC’s certificate of incorporation, bylaws and other documents contain provisions including advance notice requirements for shareholder proposals and staggered terms of office for the Board of Directors.  These provisions may make a tender offer, change in control or takeover attempt that is opposed by RPC’s Board of Directors more difficult or expensive.
 
Some of our equipment and several types of materials used in providing our services are available from a limited number of suppliers.
 
We purchase equipment provided by a limited number of manufacturers who specialize in oilfield service equipment.  During periods of high demand, these manufacturers may not be able to meet our requests for timely delivery, resulting in delayed deliveries of equipment and higher prices for equipment.  There are a limited number of suppliers for certain materials used in pressure pumping services, our largest service line.  While these materials are generally available, supply disruptions can occur due to factors beyond our control.  Such disruptions, delayed deliveries, and higher prices can limit our ability to provide services, or increase the costs of providing services, thus reducing our revenues and profits.
 
We have used outside financing to accomplish our growth strategy, and outside financing may become unavailable or may be unfavorable to us.
 
Our business requires a great deal of capital in order to maintain our equipment and increase our fleet of equipment to expand our operations, and we have access to our $296.5 million credit facility to fund our capital requirements. Most of our existing credit facility bears interest at a floating rate, which exposes us to market risks as interest rates rise.  If our existing capital resources become unavailable, inadequate or unfavorable for purposes of funding our capital requirements, we would need to raise additional funds through alternative debt or equity financings to maintain our equipment and continue our growth.  Such additional financing sources may not be available when we need them, or may not be available on favorable terms.  If we fund our growth through the issuance of public equity, the holdings of shareholders will be diluted.  If capital generated either by cash provided by operating activities or outside financing is not available or sufficient for our needs, we may be unable to maintain our equipment, expand our fleet of equipment, or take advantage of other potentially profitable business opportunities, which could reduce our future revenues and profits.
 
10

 
Item 1B. Unresolved Staff Comments
 
None.
 
Item 2. Properties
 
RPC owns or leases approximately 100 offices and operating facilities. The Company leases approximately 13,400 square feet of office space in Atlanta, Georgia that serves as its headquarters, a portion of which is allocated and charged to Marine Products Corporation.  See “Related Party Transactions” contained in Item 7.  The lease agreement on the headquarters is effective through October 2013.  RPC believes its current operating facilities are suitable and adequate to meet current and reasonably anticipated future needs although as our business continues to grow we are evaluating the need for additional facilities.  Descriptions of the major facilities used in our operations are as follows:
 
Owned Locations
 
Houma, Louisiana — Administrative office
 
Houston, Texas — Pipe storage terminal and inspection sheds
 
Houston, Texas — Operations, sales and administrative office
 
Elk City, Oklahoma — Operations, sales and equipment storage yards
 
Rock Springs, Wyoming — Operations, sales and equipment storage yards
 
Lafayette, Louisiana — Operations, sales and equipment storage yards
 
Conway, Arkansas  — Operations, sales and equipment storage yards
 
Fruita, Colorado — Operations, sales and equipment storage yards
 
Kilgore, Texas — Pumping services facility
 
Leased Locations
 
Seminole, Oklahoma — Pumping services facility
 
Oklahoma City, Oklahoma — Operations, sales and administrative office
 
Houston, Texas — Operations, sales and administrative office
 
Odessa, Texas — Operations, sales and equipment storage yards
 
Item 3. Legal Proceedings
 
RPC is a party to various routine legal proceedings primarily involving commercial claims, workers’ compensation claims and claims for personal injury. RPC insures against these risks to the extent deemed prudent by its management, but no assurance can be given that the nature and amount of such insurance will, in every case, fully indemnify RPC against liabilities arising out of pending and future legal proceedings related to its business activities. While the outcome of these lawsuits, legal proceedings and claims cannot be predicted with certainty, management believes that the outcome of all such proceedings, even if determined adversely, would not have a material adverse effect on RPC’s business or financial condition.
 
Item 4. Submission of Matters to a Vote of Security Holders
 
There were no matters submitted to a vote of security holders during the fourth quarter of 2008.
 
11

 
Item 4A. Executive Officers of the Registrant
 
Each of the executive officers of RPC was elected by the Board of Directors to serve until the Board of Directors’ meeting immediately following the next annual meeting of stockholders or until his or her earlier removal by the Board of Directors or his or her resignation. The following table lists the executive officers of RPC and their ages, offices, and terms of office with RPC.
 

Name and Office with Registrant
Age
Date First Elected to Present Office
R. Randall Rollins (1)
77
1/24/84
Chairman of the Board
   
Richard A. Hubbell (2)
64
4/22/03
President and
Chief Executive Officer
   
Linda H. Graham (3)
72
1/27/87
Vice President and
Secretary
   
Ben M. Palmer (4)
48
7/8/96
Vice President,
Chief Financial Officer and
Treasurer
   
 
(1)
R. Randall Rollins began working for Rollins, Inc. (consumer services) in 1949. At the time of the spin-off of RPC from Rollins, Inc., in 1984, Mr. Rollins was elected Chairman of the Board and Chief Executive Officer of RPC. He remains Chairman of RPC and stepped down as the Chief Executive Officer effective April 22, 2003. He has served as Chairman of the Board of Marine Products Corporation (boat manufacturing) since it was spun off from RPC in February 2001 and Chairman of the Board of Rollins, Inc. since October 1991. He is also a director of Dover Downs Gaming and Entertainment, Inc. and Dover Motorsports, Inc.
   
(2)
Richard A. Hubbell has been the President of RPC since 1987 and Chief Executive Officer since April 22, 2003. He has also been the President and Chief Executive Officer of Marine Products Corporation since it was spun off from RPC in February 2001. Mr. Hubbell serves on the Board of Directors for both of these companies.
   
(3)
Linda H. Graham has been the Vice President and Secretary of RPC since 1987.  She has also been the Vice President and Secretary of Marine Products Corporation since it was spun off from RPC in February 2001. Ms. Graham serves on the Board of Directors for both of these companies.
   
(4)
Ben M. Palmer has been the Vice President, Chief Financial Officer and Treasurer of RPC since 1996.  He has also been the Vice President, Chief Financial Officer and Treasurer of Marine Products Corporation since it was spun off from RPC in February 2001.
 
12

 
PART II
 
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
RPC’s common stock is listed for trading on the New York Stock Exchange under the symbol RES.  At February 13, 2009, there were 98,419,782 shares of common stock outstanding and approximately 4,300 holders of record of common stock.  The following table sets forth the high and low prices of RPC’s common stock and dividends paid for each quarter in the years ended December 31, 2008 and 2007:
 
   
2008
   
2007
 
Quarter
 
High
   
Low
   
Dividends
   
High
   
Low
   
Dividends
 
First
  $ 15.32     $ 8.52     $ 0.06     $ 18.35     $ 14.20     $ 0.05  
Second
    17.80       12.50       0.06       18.94       15.77       0.05  
Third
    18.91       13.15       0.06       17.25       11.34       0.05  
Fourth
    14.10       6.02       0.06       14.40       10.65       0.05  
 
On January 27, 2009, the Board of Directors approved an increase in the quarterly cash dividend per common share from $0.06 to $0.07, payable March 10, 2009 to stockholders of record at the close of business February 10, 2009.  The Company expects to continue to pay cash dividends to the common stockholders, subject to the earnings and financial condition of the Company and other relevant factors.
 
Issuer Purchases of Equity Securities
 
Shares repurchased in the fourth quarter of 2008 are outlined below.
 
Period
 
Total Number
of Shares (or
Units)
Purchased
   
Average Price
Paid Per Share
(or Unit)
   
Total Number of
Shares (or Units)
Purchased as Part of
Publicly Announced
Plans or Programs
   
Maximum Number (or
Approximate Dollar
Value) of Shares (or Units)
that May Yet Be
Purchased Under the Plans
or Programs
 
                         
October 1, 2008 to October 31, 2008
    -     $ -       -       3,207,265  
                                 
November 1, 2008 to November 30, 2008
    556,250 (1)     8.53       400,000       2,807,265  
                                 
December 1, 2008 to December 31, 2008
    -       -       -       2,807,265  
                                 
Totals
    556,250     $ 8.53       400,000       2,807,265  
 
 
(1)
Includes shares purchased by an “affiliated purchaser” under Rule 10b - 18 of the Securities Exchange Act in open market transactions.  These affiliated purchases were made by Henry B. Tippie who is a Director of the Company.
 
The Company’s Board of Directors announced a stock buyback program in March 1998 authorizing the repurchase of 11,812,500 shares in the open market.  Currently the program does not have a predetermined expiration date.
 
Performance Graph
 
The following graph shows a five year comparison of the cumulative total stockholder return based on the performance of the stock of the Company, assuming dividend reinvestment, as compared with both a broad equity market index and an industry or peer group index.  The indices included in the following graph are the Russell 2000 Index (“Russell 2000”), the Philadelphia Stock Exchange’s Oil Service Index (“OSX”), and a peer group which includes companies that are considered peers of the Company, as discussed below (the “Peer Group”).  The Company has voluntarily chosen to provide both an industry and a peer group index.
 
13

 
The Russell 2000 is a stock index representing small capitalization U.S. stocks.  The components of the index had an average market capitalization in 2008 of $881 million, and the Company was a component of the Russell 2000 during 2008.  The Russell 2000 was chosen because it represents companies with comparable market capitalizations to the Company.  The OSX is a stock index of 15 U.S. companies that provide oil drilling and production services, oilfield equipment, support services and geophysical/reservoir services.  The Company is not a component of the OSX, but it was chosen because it represents a large group of companies that provide the same or similar products and services as the Company.  The companies included in the Peer Group are Weatherford International, Inc., BJ Services Company, Superior Energy Services, Inc., and Halliburton Company. The companies included in the peer group have been weighted according to each respective issuer's stock market capitalization at the beginning of each year.
GRAPHIC
 
Item 6. Selected Financial Data
 
The following table summarizes certain selected financial data of the Company.  The historical information may not be indicative of the Company’s future results of operations.  The information set forth below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and the notes thereto included elsewhere in this document.

14

 
STATEMENT OF OPERATIONS DATA:
 
Years Ended December 31,
 
2008
   
2007
   
2006
   
2005
   
2004
 
   
(in thousands, except employee and per share amounts)
 
Revenues
  $ 876,977     $ 690,226     $ 596,630     $ 427,643     $ 339,792  
Cost of revenues
    503,631       368,175       287,037       227,492       193,659  
Selling, general and administrative expenses
    117,140       107,800       91,051       75,478       65,871  
Depreciation and amortization
    118,403       78,506       46,711       39,129       34,473  
Gain on disposition of assets, net (a)
    (6,367 )     (6,293 )     (5,969 )     (12,169 )     (5,551 )
Operating profit
    144,170       142,038       177,800       97,713       51,340  
Interest expense
    (5,282 )     (4,179 )     (356 )     (127 )     (311 )
Interest income
    73       70       319       1,077       243  
Other (expense) income, net
    (1,176 )     1,905       1,085       2,077       1,931  
Income before income taxes
    137,785       139,834       178,848       100,740       53,203  
Income tax provision (b)
    54,382       52,785       68,054       34,256       18,430  
Net income (b)
  $ 83,403     $ 87,049     $ 110,794     $ 66,484     $ 34,773  
Earnings per share:
                                       
Basic
  $ 0.86     $ 0.90     $ 1.16     $ 0.70     $ 0.36  
Diluted
  $ 0.85     $ 0.89     $ 1.13     $ 0.67     $ 0.36  
Dividends paid per share
  $ 0.240     $ 0.200     $ 0.133     $ 0.071     $ 0.036  
OTHER DATA:
                                       
Operating margin percent
    16.4 %     20.6 %     29.8 %     22.8 %     15.1 %
Net cash provided by operations
  $ 177,320     $ 141,872     $ 118,228     $ 66,362     $ 50,374  
Net cash used for investing activities
    (158,953 )     (239,624 )     (151,085 )     (62,415 )     (37,215 )
Net cash (used for) provided by financing activities
    (21,668 )     101,361       22,777       (20,774 )     (5,825 )
Depreciation and amortization
    118,403       78,506       46,711       39,129       34,500  
Capital expenditures
  $ 170,318     $ 248,758     $ 159,831     $ 72,808     $ 49,869  
Employees at end of period
    2,532       2,370       2,000       1,649       1,596  
BALANCE SHEET DATA AT END OF YEAR:
                                 
Accounts receivable, net
  $ 210,375     $ 176,154     $ 148,469     $ 107,428     $ 75,793  
Working capital
    200,494       144,338       111,302       95,215       77,509  
Property, plant and equipment, net
    470,115       433,126       262,797       141,218       114,222  
Total assets
    793,461       701,015       478,007       311,785       262,942  
Current portion of long-term debt
                            2,700  
Long-term debt (c)
    174,450       156,400       35,600             2,100  
Total stockholders’ equity
  $ 449,084     $ 409,272     $ 335,287     $ 232,501     $ 181,423  
 
(a)
Gain on disposition of assets, net in 2005 includes a $10.7 million pre-tax gain ($0.07 after tax per diluted share) on the sale of certain operating assets during the third quarter of 2005.  In 2004 the gain on disposition, net includes a $3.3 million pre-tax gain ($0.02 after tax per diluted share) on the sale of certain operating assets during the fourth quarter of 2004.
(b)
During the fourth quarter of 2005, the income tax provision and net income reflect the receipt of tax refunds of $3.5 million related to the successful resolution of certain tax matters, which had a positive impact of $0.04 after tax per diluted share.
(c)
Effective September 2006, the Company closed on a new revolving credit facility that was expanded to $296.5 million in the second quarter of 2008.  In February 2005, the Company prepaid a $2.8 million promissory note and the remaining balance of long-term debt was paid in full upon maturity of a promissory note in July 2005.
 
15

 
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Overview
 
The following discussion should be read in conjunction with “Selected Financial Data,” and the Consolidated Financial Statements included elsewhere in this document. See also “Forward-Looking Statements” on page 2.
 
RPC, Inc. (“RPC”) provides a broad range of specialized oilfield services primarily to independent and major oilfield companies engaged in exploration, production and development of oil and gas properties throughout the United States, including the Gulf of Mexico, mid-continent, southwest and Rocky Mountain regions, and selected international locations.  The Company’s revenues and profits are generated by providing equipment and services to customers who operate oil and gas properties and invest capital to drill new wells and enhance production or perform maintenance on existing wells.
 
Our key business and financial strategies are:
 
 
-
To focus our management resources on and invest our capital in equipment and geographic markets that we believe will earn high returns on capital, and maintain an appropriate capital structure.
     
 
-
To maintain a flexible cost structure that can respond quickly to volatile industry conditions and business activity levels.
     
 
-
To deliver equipment and services to our customers safely.
     
 
-
To maintain and increase market share.
     
 
-
To maximize shareholder return by optimizing the balance between cash invested in the Company's productive assets, the payment of dividends to shareholders, and the repurchase of our common stock on the open market.
     
 
-
To align the interests of our management and shareholders.
     
 
-
To maintain an efficient, low-cost capital structure, which includes an appropriate use of debt.
 
In assessing the outcomes of these strategies and RPC’s financial condition and operating performance, management generally reviews periodic forecast data, monthly actual results, and other similar information.  We also consider trends related to certain key financial data, including revenues, utilization of our equipment and personnel, pricing for our services and equipment, profit margins, selling, general and administrative expenses, cash flows and the return on our invested capital.  We continuously monitor factors that impact the level of current and expected customer activity levels, such as the price of oil and natural gas, changes in pricing for our services and equipment and utilization of our equipment and personnel.  Our financial results are affected by geopolitical factors such as political instability in the petroleum-producing regions of the world, overall economic conditions and weather in the United States, the prices of oil and natural gas, and our customers’ drilling and production activities.
 
Current industry conditions include natural gas prices that have been very volatile, and while high by historical levels, declined tremendously during 2008.  Oil prices are also extremely volatile, having reached record highs at the beginning of the third quarter of 2008, prior to declining to a low of slightly more than $32 per barrel by the end of the year, which is the lowest level for oil prices since the first quarter of 2005.  In the beginning of 2009, natural gas prices are falling dramatically compared to 2008, and during the first quarter are approximately 38 percent lower than the same period last year.  The price of oil has fallen as well, and is approximately 56 percent lower than the same period last year.  The average rig count in 2008 increased by 6.3 percent compared to the prior year, but fell during the fourth quarter of 2008 and into early 2009.  During the first quarter the average rig count is approximately 16 percent lower than the same period last year.  In addition to the overall rig count, the Company also monitors the number of horizontal and directional wells drilled in the U.S. domestic market, because this type of well is more service-intensive than a vertical oil or gas well, thus requiring more of the Company’s services provided for a longer period of time.  The number of horizontal and directional wells drilled in the United States increased in 2008, and was 49 percent of total wells drilled during the year.  During the first part of 2009, the percentage of horizontal and directional wells drilled as a percentage of total wells increased to approximately 56 percent.  Over the past several years, the supply of oilfield service equipment in the U.S. domestic market has increased tremendously, both from existing service companies and new entrants to the oilfield services business.  Although the supply of oilfield equipment did not increase as much in 2008 as in prior years, the large supply of equipment and service providers has caused pricing for the Company’s services to decrease, which has had a negative impact on the Company’s financial results and returns.  The Company responded by reducing its capital expenditures during 2008, closely monitoring its competitors’ activities, and scrutinizing planned capital expenditures more closely for acceptable financial returns.  In spite of increased competition and declining financial results, the Company’s returns are still high by historical standards, and cash flow from operations as well as proceeds from our revolving credit facility have allowed us to make significant capital expenditures during 2008.
 
16

 
Income before income taxes was $137.8 million in 2008 compared to $139.8 million in the prior year.  The effective tax rate for 2008 was 39.5 percent compared to 37.7 percent in the prior year.  Diluted earnings per share decreased to $0.85 in 2008 compared to $0.89 for the prior year.  Cash flows from operating activities were $177.3 million in 2008 compared to $141.9 million in the prior year, and cash and cash equivalents were $3.0 million at December 31, 2008, a decrease of $3.3 million compared to December 31, 2007.  During the second quarter of 2008, we expanded our revolving credit facility to $296.5 million.   As of December 31, 2008, there was $174.5 million in outstanding borrowings on our revolving credit facility.
 
Cost of revenues as a percentage of revenues increased approximately 4.1 percentage points in 2008 compared to 2007, because of lower pricing for our services due to competition and higher cost for materials and supplies, personnel and fuel.
 
Selling, general and administrative expenses as a percentage of revenues decreased approximately 2.2 percentage points in 2008 compared to 2007, which was primarily due to positive leverage of these costs realized from the higher revenues.
 
Consistent with our strategy to selectively grow our capacity and maintain our existing fleet of high demand equipment, capital expenditures were $170.3 million in 2008.
 
Outlook
 
Drilling activity in the U.S. domestic oilfields, as measured by the rotary drilling rig count, has been stable or gradually increasing for several years, and the overall domestic rig count during the fourth quarter of 2008 was approximately 6.3 percent higher than in the comparable period in 2007. The average price of oil during the fourth quarter fell by approximately 37 percent as compared to the prior year while the average price of natural gas fell by approximately 10 percent.  Horizontal and directional wells drilled during 2008 were 49 percent of total domestic activity, an increase from 44 percent in the prior year, and the highest percentage of total drilling activity during the time that this data has been reported.  This trend has continued in early 2009.  The price of oil has fallen dramatically due in part to low global demand, especially among newly-industrializing countries such as China and India, in spite of political instability and conflict in the oil-producing regions of the Middle East.  While the overall drilling rig count has increased, it began to fall in the fourth quarter of 2008 as declining commodity prices and the global economic slowdown, coupled with declining availability of capital for drilling projects, caused industry activity levels to decline.  These declines continued during the early part of 2009, and do not show signs of improvement in the near term.
 
The Company continues to monitor the competitive environment in 2009, and is concerned about the rapidly-declining rig count and commodity prices, especially in light of the higher level of competition which has arisen from the large amount of additional equipment that has been placed in service in the domestic market during the past several years.  The Company’s response to these deteriorating industry conditions is to reduce our planned capital expenditures, implement cost-reduction plans and enhance our sales and marketing efforts.  The Company understands that factors influencing the industry are unpredictable, and our response to the industry's potential uncertainty is to maintain sufficient liquidity and a conservative capital structure and monitor our discretionary spending.  Although we used our bank credit facility to finance our expansion, we will still maintain a conservative financial structure, and intend to reduce the amount drawn on this facility over the course of 2009.  Based on current industry conditions and the deep global recession, we expect consolidated revenues for 2009 to decrease compared to 2008.

17

 
Results of Operations

Years Ended December 31,
 
2008
   
2007
   
2006
 
Consolidated revenues
  $ 876,977     $ 690,226     $ 596,630  
Revenues by business segment:
                       
Technical
  $ 745,991     $ 574,723     $ 495,090  
Support
    130,986       115,503       101,540  
                         
Consolidated operating profit
  $ 144,170     $ 142,038     $ 177,800  
Operating profit by business segment:
                       
Technical
  $ 110,648     $ 116,493     $ 153,126  
Support
    36,515       29,955       30,953  
Corporate expenses
    (9,360 )     (10,703 )     (12,248 )
Gain on disposition of assets, net
    6,367       6,293       5,969  
                         
Net income
  $ 83,403     $ 87,049     $ 110,794  
Earnings per share — diluted
  $ 0.85     $ 0.89     $ 1.13  
Percentage of cost of revenues to revenues
    57 %     53 %     48 %
Percentage of selling, general and administrative expenses to revenues
    13 %     16 %     15 %
Percentage of depreciation and amortization expense to revenues
    14 %     11 %     8 %
Effective income tax rate
    39.5 %     37.7 %     38.1 %
Average U.S. domestic rig count
    1,879       1,768       1,649  
Average natural gas price (per thousand cubic feet (mcf))
  $ 8.81     $ 6.93     $ 6.65  
Average oil price (per barrel)
  $ 99.96     $ 72.78     $ 66.36  
 
Year Ended December 31, 2008 Compared To Year Ended December 31, 2007
 
Revenues. Revenues for 2008 increased $186.8 million or 27.1 percent compared to 2007.  The Technical Services segment revenues for 2008 increased 29.8 percent from the prior year due primarily to a higher drilling rig count and increased capacity driven by higher capital expenditures partially offset by lower pricing for services.  The Support Services segment revenues for 2008 increased 13.4 percent from the prior year due to increased capacity driven by higher capital expenditures as well as a more profitable job mix in the rental tool service line, the largest within this segment.
 
Domestic revenues increased 30 percent to $846.2 million during 2008 compared to 2007 due to increased capacity in our largest service lines, such as pressure pumping and rental tools.  The average price of natural gas increased by 27 percent and the average price of oil increased by approximately 37 percent during 2008 compared to the prior year.  In conjunction with the increase in natural gas prices, the average domestic rig count during 2008 was seven percent higher than in 2007.  This increase in drilling activity had a positive impact on our financial results.  We believe that our activity levels are affected more by the price of natural gas than by the price of oil, because the majority of U.S. domestic drilling activity relates to natural gas, and many of our services are more appropriate for gas wells than oil wells.  Foreign revenues, which decreased from $41.1 million in 2007 to $30.8 million in 2008, were four percent of consolidated revenues.  These revenue decreases were due mainly to lower customer activity levels in Turkmenistan and Hungary compared to the prior year.  Our international revenues are impacted by the timing of project initiation and their ultimate duration.
 
Cost of revenues.  Costs of revenues in 2008 was $503.6 million compared to $368.2 million in 2007, an increase of $135.4 million or 36.8 percent.  The increase in these costs was due to the variable nature of many of these expenses, including materials and supplies, compensation, and maintenance and repairs.  Cost of revenues, as a percent of revenues, increased in 2008 from 2007 due to more competitive pricing, higher costs of proppant used in our pressure pumping service line and increased maintenance and repairs expenses.
 
Selling, general and administrative expenses.  Selling, general and administrative expenses increased 8.7 percent to $117.1 million in 2008 compared to $107.8 million in 2007.  This increase was primarily due to higher employment costs consistent with higher activity levels and geographic expansion under RPC’s long-term growth plan.  As a percentage of revenues, selling, general and administrative expenses decreased to 13.4 percent in 2008 compared to 15.6 percent in 2007.
 
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Depreciation and amortization.  Depreciation and amortization were $118.4 million in 2008, an increase of $39.9 million or 50.8 percent compared to $78.5 million in 2007. This increase resulted from a higher level of capital expenditures during recent quarters within both Support Services and Technical Services to increase capacity and to maintain our existing equipment.
 
Gain on disposition of assets, net. Gain on the disposition of assets, net increased due primarily to gains related to various property and equipment dispositions or sales to customers of lost or damaged rental equipment.
 
Other(expense) income, net.  Other (expense), net in 2008 was $(1.2) million, a decrease of $3.1 million compared to other income of $1.9 million in 2007.  The decrease is mainly due to the current year decline in the fair value of  trading securities held in the non-qualified Supplemental Retirement Plan.   In addition to changes in the fair value of trading securities, other (expense) income includes gains from settlements of various legal and insurance claims and royalty payments.
 
Interest expense.   Interest expense was $5.3 million in 2008 compared to $4.2 million in 2007.  The increase is due to higher interest expense in 2008 incurred on larger outstanding interest bearing advances on our revolving line of credit.
 
Interest income.   Interest income increased to $73 thousand in 2008 compared to $70 thousand in 2007 as a result of a higher average investable cash balance in 2008 compared to 2007.
 
Income tax provision.  The income tax provision increased to $54.4 million in 2008 from $52.8 million in 2007.  The increase is due to an increase in the effective tax rate to 39.5 percent in 2008 from 37.7 percent in 2007.   
 
Net income and diluted earnings per share.   Net income decreased 4.2 percent to $83.4 million, or $0.85 earnings per diluted share, compared to $87.0 million, or $0.89 earnings per diluted share in 2007.  This decrease is due to higher costs of revenues, selling, general and administrative expenses, depreciation expense, other expense, and interest expense partially offset by increased revenues.
 
Year Ended December 31, 2007 Compared To Year Ended December 31, 2006
 
Revenues. Revenues for 2007 increased $93.6 million or 15.7 percent compared to 2006.  The Technical Services segment revenues for 2007 increased 16.1 percent from the prior year due primarily to increased capacity driven by higher capital expenditures partially offset by lower pricing for services and increased drilling rig count.  The Support Services segment revenues for 2007 increased 13.8 percent from the prior year due to increased capacity driven by higher capital expenditures as well as a more profitable job mix in the rental tool service line, the largest within this segment.
 
Domestic revenues increased 15 percent to $649.1 million during 2007 compared to 2006 due to increased capacity in our largest service lines, such as pressure pumping and rental tools.  The average price of natural gas increased by four percent and the average price of oil increased by approximately ten percent during 2007 compared to 2006.  In conjunction with the increase in natural gas prices, the average domestic rig count during 2007 was seven percent higher than in 2006.  This increase in drilling activity had a positive impact on our financial results.  Foreign revenues, which increased from $30.0 million in 2006 to $41.1 million in 2007, were six percent of consolidated revenues.  These revenue increases were realized due mainly to higher customer activity levels in Bolivia, Canada, Egypt and Turkmenistan compared to the prior year.  Our international revenues are impacted by the timing of project initiation and their ultimate duration.
 
Cost of revenues.  Costs of revenues in 2007 was $368.2 million compared to $287.0 million in 2006, an increase of $81.2 million or 28.3 percent.  The increase in these costs was due to the variable nature of many of these expenses, including compensation, materials and supplies, fuel and maintenance and repair costs.  Cost of revenues, as a percent of revenues, increased in 2007 from 2006 due to upward cost pressures for materials and supplies, personnel, fuel, delays in the delivery of revenue producing equipment and resulting inefficiencies, as well as lower pricing for our services, due to increased competition.
 
Selling, general and administrative expenses.  Selling, general and administrative expenses increased 18.4 percent to $107.8 million in 2007 compared to $91.1 million in 2006.  This increase was primarily due to higher employment costs consistent with higher activity levels and geographic expansion under RPC’s long-term growth plan.  As a percentage of revenues, selling, general and administrative expenses increased to 15.6 percent in 2007 compared to 15.3 percent in 2006.
 
Depreciation and amortization.  Depreciation and amortization were $78.5 million in 2007, an increase of $31.8 million or 68.1 percent compared to $46.7 million in 2006. This increase resulted from a higher level of capital expenditures during 2006 and 2007 within both Support Services and Technical Services to increase capacity and to maintain our existing equipment.
 
Gain on disposition of assets, net. Gain on the disposition of assets, net increased due primarily to gains related to various property and equipment dispositions or sales to customers of lost or damaged rental equipment.
 
Other income, net.  Other income, net in 2007 was $1.9 million, an increase of $0.8 million compared to $1.1 million in 2006.  Other income includes gains from settlements of various legal and insurance claims and royalty payments.
 
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Interest expense.   Interest expense was $4.2 million in 2007 compared to $356 thousand in 2006.  The increase is due to higher interest expense in 2007 incurred on larger outstanding interest bearing advances on our revolving line of credit.
 
Interest Income.   Interest income declined to $70 thousand in 2007 compared to $319 thousand in 2006 as a result of a lower average investable cash balance in 2007 compared to 2006.
 
Income tax provision.  The income tax provision decreased to $52.8 million in 2007 from $68.1 million in 2006.  The decrease is due to the decline in income before taxes coupled with a decrease in the effective tax rate to 37.7 percent in 2007 from 38.1 percent in 2006.
 
Net income and diluted earnings per share.   Net income decreased 21.4 percent to $87.0 million, or $0.89 earnings per diluted share, compared to $110.8 million, or $1.13 earnings per diluted share in 2006.
 
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Liquidity and Capital Resources
 
Cash and Cash Flows
 
The Company’s cash and cash equivalents were $3.0 million as of December 31, 2008, $6.3 million as of December 31, 2007 and $2.7 million as of December 31, 2006.
 
The following table sets forth the historical cash flows for the years ended December 31:

   
(in thousands)
 
   
2008
   
2007
   
2006
 
Net cash provided by operating activities
  $ 177,320     $ 141,872     $ 118,228  
Net cash used for investing activities
    (158,953 )     (239,624 )     (151,085 )
Net cash (used for) provided by financing activities
    (21,668 )     101,361       22,777  

2008
 
Cash provided by operating activities increased by $35.4 million in 2008 compared to the prior year.  Although net income decreased $3.6 million in 2008 compared to 2007, cash provided by operating activities increased due primarily to an increase in depreciation due to higher capital expenditures and a higher deferred tax provision due to accelerated tax depreciation.  Increased business activity levels and revenues in 2008 resulted in higher accounts receivable, inventories and prepaid expenses partially offset by increased accounts payable and accrued payroll including bonuses.
 
Cash used for investing activities in 2008 decreased by $80.7 million compared to 2007, primarily as a result of lower capital expenditures.
 
Cash (used for) provided by financing activities in 2008 increased by $123.0 million compared to 2007, primarily due to lower net borrowings from notes payable to banks during 2008, an increase in common stock purchased and retired, and a 20 percent increase in dividends paid per share to common shareholders.

2007
 
Cash provided by operating activities increased by $23.6 million in 2007 compared to the prior year.  Although net income decreased $23.7 million in 2007 compared to 2006, cash provided by operating activities increased due primarily to an increase in depreciation due to higher capital expenditures, a higher deferred tax provision due to accelerated tax depreciation and lower growth in working capital requirements.  Increased business activity levels and revenues in 2007 resulted in higher accounts receivable, inventories and prepaid expenses partially offset by increased accounts payable and accrued payroll including bonuses.
 
Cash used for investing activities in 2007 increased by $88.5 million compared to 2006, primarily as a result of higher capital expenditures to increase capacity and maintain our existing equipment.
 
Cash provided by financing activities in 2007 increased by $78.6 million compared to 2006, primarily due to net borrowings from notes payable to banks during 2007, partially offset by a 50 percent increase in dividends paid per share to common shareholders.
 
Financial Condition and Liquidity
 
The Company’s financial condition as of December 31, 2008, remains strong.  We believe the liquidity provided by our existing cash and cash equivalents, our overall strong capitalization which includes a revolving credit facility and cash expected to be generated from operations will provide sufficient capital to meet our requirements for at least the next twelve months.  During the third quarter of 2006, the Company replaced its $50 million line of credit with a $250 million revolving credit facility (the "Revolving Credit Agreement"), with a term of five years. During the second quarter of 2008, the Company entered into a certain Commitment Increase Amendment to the Revolving Credit Agreement to increase the amount of the credit facility by $46.5 million to its current amount of $296.5 million.  The Revolving Credit Agreement contains customary terms and conditions, including certain financial covenants including covenants restricting RPC's ability to incur liens, merge or consolidate with another entity.  A total of $99.9 million was available under our facility as of December 31, 2008; approximately $22.2 million of the credit facility supports outstanding letters of credit relating to self-insurance programs or contract bids.  For additional information with respect to RPC’s credit facility, see Note 6 of the Notes to Consolidated Financial Statements.
 
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The Company’s decisions about the amount of cash to be used for investing and financing purposes are influenced by its capital position, including access to borrowings under our credit facility, and the expected amount of cash to be provided by operations.  We believe our liquidity will continue to provide the opportunity to grow our asset base and revenues during periods with positive business conditions and strong customer activity levels.  The Company's decisions about the amount of cash to be used for investing and financing activities could be influenced by the financial covenants in our credit facility but we do not expect the covenants to restrict our planned activities.
 
Cash Requirements
 
Capital expenditures were $170.3 million in 2008, and we currently expect capital expenditures to be approximately $90.0 million in 2009.  We expect these expenditures to be primarily directed towards revenue-producing equipment in our larger, core service lines including pressure pumping, snubbing, nitrogen, and rental tools.  The actual amount of 2009 expenditures will depend primarily on equipment maintenance requirements, expansion opportunities, and equipment delivery schedules.

The Company’s Retirement Income Plan, a multiple employer trusteed defined benefit pension plan, provides monthly benefits upon retirement at age 65 to eligible employees.  The Company does not currently expect to make any contributions to the defined benefit pension plan in 2009 to meet its funding objectives.

The Company’s Board of Directors announced a stock buyback program on March 9, 1998 authorizing the repurchase of up to 11,812,500 shares of which 2,807,265 additional shares were available to be repurchased as of December 31, 2008.  The program does not have a predetermined expiration date.
 
On January 27, 2009, the Board of Directors approved an increase in the quarterly cash dividend per common share, from $0.06 to $0.07, payable March 10, 2009 to stockholders of record at the close of business February 10, 2009.  The Company expects to continue to pay cash dividends to common stockholders, subject to the earnings and financial condition of the Company and other relevant factors.
 
Contractual Obligations
 
The Company’s obligations and commitments that require future payments include a bank demand note, certain non-cancelable operating leases, purchase obligations and other long-term liabilities. The following table summarizes the Company’s significant contractual obligations as of December 31, 2008:

Contractual obligations
 
Payments due by period
 
(in thousands)
 
Total
   
Less than
1 year
   
1-3 
years
   
3-5
years
   
More than
5 years
 
Long-term debt obligations
  $ 174,450     $ -     $ 174,450     $ -     $ -  
Interest on long-term debt obligations
    9,705       3,611       6,094       -       -  
Capital lease obligations
    -       -       -       -       -  
Operating leases (1)
    12,784       344       8,838       2,461       1,141  
Purchase obligations (2)
    6,435       6,435       -       -       -  
Other long-term liabilities (3)
    2,718       -       2,718       -       -  
Total contractual obligations
  $ 206,092     $ 10,390     $ 192,100     $ 2,461     $ 1,141  

(1)
Operating leases include agreements for various office locations, office equipment, and certain operating equipment.
(2)
Includes agreements to purchase goods or services that have been approved and that specify all significant terms (pricing, quantity, and timing).  As part of the normal course of business the Company enters into purchase commitments to manage its various operating needs.
(3)
Includes expected cash payments for long-term liabilities reflected on the balance sheet where the timing of the payments are known. These amounts include incentive compensation. These amounts exclude pension obligations with uncertain funding requirements and deferred compensation liabilities.
 
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Inflation
 
The Company purchases its equipment and materials from suppliers who provide competitive prices, and employs skilled workers from competitive labor markets.  If inflation in the general economy increases, the Company’s costs for equipment, materials and labor could increase as well.  Due to the increases in activity in the domestic oilfield over the past several years, as well as a shortage of a skilled work force due to historically high activity in the oilfield, the Company has experienced some upward wage pressures in the labor markets from which it hires employees.  Also over the past several years, the price of steel, for both the commodity and for products manufactured with steel, has increased dramatically.  Recently, steel prices have moderated, although they remain high by historical standards.  This factor has affected the Company's operations by extending time for deliveries of new equipment and receipt of price quotations that may only be valid for a limited period of time.  If this factor continues, it is possible that the cost of the Company's new equipment will increase which would result in higher capital expenditures and depreciation expense. RPC attempts to recover such increased costs through price increases to its customers, although competitive pressures have recently adversely affected the Company’s ability to do so.
 
Off Balance Sheet Arrangements
 
The Company does not have any material off balance sheet arrangements.
 
Related Party Transactions
 
Marine Products Corporation
 
Effective February 28, 2001, the Company spun off the business conducted through Chaparral Boats, Inc. (“Chaparral”), RPC’s former powerboat manufacturing segment.  RPC accomplished the spin-off by contributing 100 percent of the issued and outstanding stock of Chaparral to Marine Products Corporation (a Delaware corporation) (“Marine Products”), a newly formed wholly-owned subsidiary of RPC, and then distributing the common stock of Marine Products to RPC stockholders.  In conjunction with the spin-off, RPC and Marine Products entered into various agreements that define the companies’ relationship.
 
In accordance with a Transition Support Services agreement, which may be terminated by either party, RPC provides certain administrative services, including financial reporting and income tax administration, acquisition assistance, etc., to Marine Products.  Charges from the Company (or from corporations that are subsidiaries of the Company) for such services aggregated approximately $842,000 in 2008, $957,000 in 2007 and $739,000 in 2006. The Company’s receivable due from Marine Products for these services as of December 31, 2008 and 2007 was approximately $70,000 and $223,000.  The Company’s directors are also directors of Marine Products and all of the executive officers are employees of both the Company and Marine Products.
 
Other
 
The Company periodically purchases in the ordinary course of business products or services from suppliers, who are owned by significant officers or shareholders, or affiliated with the directors of RPC. The total amounts paid to these affiliated parties were approximately $393,000 in 2008, $1,035,000 in 2007 and $1,248,000 in 2006.
 
RPC receives certain administrative services and rents office space from Rollins, Inc. (a company of which Mr. R. Randall Rollins is also Chairman and which is otherwise affiliated with RPC).  The service agreements between Rollins, Inc. and the Company provide for the provision of services on a cost reimbursement basis and are terminable on six months notice.  The services covered by these agreements include office space, administration of certain employee benefit programs, and other administrative services. Charges to the Company (or to corporations which are subsidiaries of the Company) for such services and rent totaled $90,000 in 2008, $72,000 in 2007 and $70,000 in 2006.
 
Critical Accounting Policies
 
The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States, which require significant judgment by management in selecting the appropriate assumptions for calculating accounting estimates. These judgments are based on our historical experience, terms of existing contracts, trends in the industry, and information available from other outside sources, as appropriate.  Senior management has discussed the development, selection and disclosure of its critical accounting estimates with the Audit Committee of our Board of Directors.  The Company believes the following critical accounting policies involve estimates that require a higher degree of judgment and complexity:
 
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Allowance for doubtful accounts — Substantially all of the Company’s receivables are due from oil and gas exploration and production companies in the United States, selected international locations and foreign, nationally owned oil companies.  Our allowance for doubtful accounts is determined using a combination of factors to ensure that our receivables are not overstated due to uncollectibility.  Our established credit evaluation procedures seek to minimize the amount of business we conduct with higher risk customers. Our customers’ ability to pay is directly related to their ability to generate cash flow on their projects and is significantly affected by the volatility in the price of oil and natural gas. Provisions for doubtful accounts are recorded in selling, general and administrative expenses.  Accounts are written-off against the allowance for doubtful accounts when the Company determines that amounts are uncollectible and recoveries of amounts previously written off are recorded when collected.  Significant recoveries will generally reduce the required provision in the period of recovery.  Therefore, the provision for doubtful accounts can fluctuate significantly from period to period.  Recoveries in 2008 totaled $1.5 million, causing a reduction in bad debt expense.  Recoveries in 2007 and 2006 were insignificant.  We record specific provisions when we become aware of a customer's inability to meet its financial obligations to us, such as in the case of bankruptcy filings or deterioration in the customer's operating results or financial position. If circumstances related to customers change, our estimates of the realizability of receivables would be further adjusted, either upward or downward.
 
The estimated allowance for doubtful accounts is based on our evaluation of the overall trends in the oil and gas industry, financial condition of our customers, our historical write-off experience, current economic conditions, and in the case of international customers, our judgments about the economic and political environment of the related country and region.  In addition to reserves established for specific customers, we establish general reserves by using different percentages depending on the age of the receivables.  Excluding the effect of the recoveries referred to above, the annual provisions for doubtful accounts have ranged from 0.10 percent to 0.45 percent of revenues over the last three years.  Increasing or decreasing the estimated general reserve percentages by 0.50 percentage points as of December 31, 2008 would have resulted in a change of approximately $1.1 million to the allowance for doubtful accounts and a corresponding change to selling, general and administrative expenses.
 
Income taxes — The effective income tax rates were 39.5 percent in 2008, 37.7 percent in 2007, and 38.1 percent in 2006.  Our effective tax rates vary due to changes in estimates of our future taxable income, fluctuations in the tax jurisdictions in which our earnings and deductions are realized, and favorable or unfavorable adjustments to our estimated tax liabilities related to proposed or probable assessments.  As a result, our effective tax rate may fluctuate significantly on a quarterly or annual basis.
 
We establish a valuation allowance against the carrying value of deferred tax assets when we determine that it is more likely than not that the asset will not be realized through future taxable income.  Such amounts are charged to earnings in the period in which we make such determination. Likewise, if we later determine that it is more likely than not that the net deferred tax assets would be realized, we would reverse the applicable portion of the previously provided valuation allowance. We have considered future market growth, forecasted earnings, future taxable income, the mix of earnings in the jurisdictions in which we operate, and prudent and feasible tax planning strategies in determining the need for a valuation allowance.
 
We calculate our current and deferred tax provision based on estimates and assumptions that could differ from the actual results reflected in income tax returns filed during the subsequent year. Adjustments based on filed returns are recorded when identified, which is generally in the third quarter of the subsequent year for U.S. federal and state provisions.  Deferred tax liabilities and assets are determined based on the differences between the financial and tax bases of assets and liabilities using enacted tax rates in effect in the year the differences are expected to reverse.
 
The amount of income taxes we pay is subject to ongoing audits by federal, state and foreign tax authorities, which often result in proposed assessments. Our estimate for the potential outcome for any uncertain tax issue is highly judgmental. We believe we have adequately provided for any reasonably foreseeable outcome related to these matters. However, our future results may include favorable or unfavorable adjustments to our estimated tax liabilities in the period the assessments are made or resolved or when statutes of limitation on potential assessments expire. Additionally, the jurisdictions in which our earnings or deductions are realized may differ from our current estimates.
 
Insurance expenses – The Company self insures, up to certain policy-specified limits, certain risks related to general liability, workers’ compensation, vehicle and equipment liability.  The cost of claims under these self-insurance programs is estimated and accrued using individual case-based valuations and statistical analysis and is based upon judgment and historical experience; however, the ultimate cost of many of these claims may not be known for several years. These claims are monitored and the cost estimates are revised as developments occur relating to such claims.  The Company has retained an independent third party actuary to assist in the calculation of a range of exposure for these claims.  As of December 31, 2008, the Company estimates the range of exposure to be from $11.3 million to $14.9 million.  The Company has recorded liabilities at December 31, 2008 of approximately $13.0 million which represents management’s best estimate of probable loss.
 
Depreciable life of assets — RPC’s net property, plant and equipment at December 31, 2008 was $470.1 million representing 59.2 percent of the Company’s consolidated assets.  Depreciation and amortization expenses for the year ended December 31, 2008 were $118.4 million, or 16.0 percent of total operating costs.  Management judgment is required in the determination of the estimated useful lives used to calculate the annual and accumulated depreciation and amortization expense.
 
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Property, plant and equipment are reported at cost less accumulated depreciation and amortization, which is generally provided on a straight-line basis over the estimated useful lives of the assets. The estimated useful life represents the projected period of time that the asset will be productively employed by the Company and is determined by management based on many factors including historical experience with similar assets.  Assets are monitored to ensure changes in asset lives are identified and prospective depreciation and amortization expense is adjusted accordingly.  We have not made any changes to the estimated lives of assets resulting in a material impact in the last three years.
 
Defined benefit pension plan – In 2002, the Company ceased all future benefit accruals under the defined benefit plan, although the Company remains obligated to provide employees benefits earned through March 2002.  The Company accounts for the defined benefit plan in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of FASB Statements No. 87, 88, 106, and 132(R)” and engages an outside actuary to calculate its obligations and costs.  With the assistance of the actuary, the Company evaluates the significant assumptions used on a periodic basis including the estimated future return on plan assets, the discount rate, and other factors, and makes adjustments to these liabilities as necessary.
 
The Company chooses an expected rate of return on plan assets based on historical results for similar allocations among asset classes, the investments strategy, and the views of our investment adviser.   Differences between the expected long-term return on plan assets and the actual return are amortized over future years.  Therefore, the net deferral of past asset gains (losses) ultimately affects future pension expense.  The Company’s assumption for the expected return on plan assets is eight percent which is unchanged from the prior year.
 
The discount rate reflects the current rate at which the pension liabilities could be effectively settled at the end of the year. In estimating this rate, the Company utilizes a yield curve approach.  The approach utilizes an economic model whereby the Company’s expected benefit payments over the life of the plan is forecasted and then compared to a portfolio of investment grade corporate bonds that will mature at the same time that the benefit payments are due in any given year.  The economic model then calculates the one discount rate to apply to all benefit payments over the life of the plan which will result in the same total lump sum as the payments from the corporate bonds.   A lower discount rate increases the present value of benefit obligations.  The discount rate was 6.84 percent as of December 31, 2008 compared to 6.25 percent in 2007 and 5.50 percent in 2006.
 
As of December 31, 2008, the defined benefit plan was under-funded and the recorded change within accumulated other comprehensive loss decreased stockholders’ equity by $6.1 million after tax.   Holding all other factors constant, a decrease in the discount rate used to measure plan liabilities by 0.25 percentage points would result in a pre-tax increase of $0.5 million to the net loss related to pension in accumulated other comprehensive loss and an increase in the discount rate used to measure plan liabilities by 0.25 percentage points would result in a pre-tax decrease of $0.5 million to the net loss related to pension in accumulated other comprehensive loss.
 
The Company recognized pre-tax pension (income) expense of $(0.4) million in 2008, $0.3 million in 2007, and $0.8 million in 2006.  Based on the under-funded status of the defined benefit plan as of December 31, 2008 due primarily to declines in pension assets, the Company expects to recognize pension expense of $2.0 million in 2009.  Holding all other factors constant, a change in the expected long-term rate of return on plan assets by 0.50 percentage points would result in an increase or decrease in pension expense/income of approximately $0.1 million in 2009.   Holding all other factors constant, a change in the discount rate used to measure plan liabilities by 0.25 percentage points would result in an increase or decrease in pension expense/income of approximately $0.1 million in 2009.
 
New Accounting Standards

In December 2008, the FASB issued FASB Staff Position (FSP) FAS 132R-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” The FASB issued the FSP, which amends FASB Statement 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits, in order to provide adequate transparency about the types of assets and associated risks in employers’ postretirement plans.  Disclosures are designed to provide an understanding of how investment decisions are made: the major categories of plan assets; the inputs and valuation techniques used to measure the fair value of plan assets; the effect of fair value measurements using significant unobservable inputs (Level 3 measurements in FASB Statement 157, Fair Value Measurements) on changes in plan assets for the period; and significant concentrations of risk within plan assets.  The disclosures about plan assets required by this FSP are required to be provided for fiscal years ending after December 15, 2009, with the provisions of this FSP not required for earlier periods that are presented for comparative purposes, upon initial application. Earlier application of the provisions of this FSP is permitted. The Company is currently in the process of determining the additional disclosures required upon the adoption of this FSP.
 
25

 
In October 2008, the FASB issued FASB Staff Position (FSP) No. FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active.”   FSP 157-3 clarifies the application of SFAS No. 157, “Fair Value Measurements,” in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active.  The FSP stipulates that determining fair value in a dislocated market depends on the facts and circumstances and may require the use of significant judgment when evaluating individual transactions or broker quotes which are some of the sources of the fair value measurement.  In addition, FSP FAS 157-3 states that if an entity uses its own assumptions to determine fair value, it must include appropriate risk adjustments that market participants would make for nonperformance and liquidity risks.  FSP FAS 157-3 is effective upon issuance, including prior periods for which financial statements have not been issued.  The Company adopted FSP FAS 157-3 in the third quarter of 2008 and has concluded that it does not have a material effect on its consolidated financial statements.

In September 2008, the FASB issued FSP No. FAS 133-1 and FIN 45-4, “Disclosures about Credit Derivatives and Certain Guarantees – An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161.”   This FSP amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” to require disclosures by sellers of credit derivatives, including credit derivatives embedded in a hybrid instrument.  This FSP also amends FASB Interpretation No. (FIN) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” to require an additional disclosure about the current status of the payment/performance risk of a guarantee.   Further this FSP clarifies the FASB’s intent about the effective date of SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.”  The provisions of this FSP that amend SFAS No. 161 and FIN 45 are effective for reporting periods ending after November 15, 2008 and the clarification of the effective date of SFAS No. 161 is effective upon issuance of this FSP.  The Company adopted FSP FAS 133-1 and FIN 45-4 in the fourth quarter of 2008 and has concluded that it does not have a material effect on its consolidated financial statements.

In June 2008, the FASB issued FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” to clarify that all outstanding unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities. An entity must include participating securities in its calculation of basic and diluted earnings per share (EPS) pursuant to the two-class method, as described in FASB Statement 128, Earnings per Share. FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. The Company intends to adopt FSP EITF 03-6-1 effective January 1, 2009 and apply its provisions retrospectively to all prior-period EPS data presented in its financial statements. The Company has periodically issued share-based payment awards that contain non-forfeitable rights to dividends and does not expect the adoption of this accounting guidance to have a material effect on its consolidated financial statements or EPS.

In May 2008, the FASB issued SFAS 162, “The Hierarchy of Generally Accepted Accounting Principles.”   SFAS 162 is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in financial statements that are presented in conformity with U.S. generally accepted accounting principles for nongovernmental entities.    This Statement became effective on November 15, 2008. The Company adopted SFAS 162 in the fourth quarter of 2008 and has concluded that it does not have a material effect on its consolidated financial statements.

In April 2008, the FASB issued FSP FAS No. 142-3, which amends the factors that must be considered in developing renewal or extension assumptions used to determine the useful life over which to amortize the cost of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The FSP requires an entity that is estimating the useful life of a recognized intangible asset to consider its historical experience in renewing or extending similar arrangements or, in the absence of historical experience, must consider assumptions that market participants would use about renewal or extension that are both consistent with the asset’s highest and best use and adjusted for entity-specific factors under SFAS No. 142.  The FSP is effective for fiscal years beginning after December 15, 2008, and the guidance for determining the useful life of a recognized intangible asset must be applied prospectively to intangible assets acquired after the effective date. The Company does not expect the adoption of FSP FAS No. 142-3 to have a material effect on its consolidated financial statements.
 
26

 
In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities - an Amendment of FASB Statement No. 133.” SFAS 161 requires enhanced disclosures regarding how: (a) an entity uses derivative instruments; (b) derivative instruments and related hedged items are accounted for under FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities;” and (c) derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows.  SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008 with early application being encouraged.  The Company does not expect the adoption of SFAS 161 to have a significant impact on the Company’s consolidated financial statements.

In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements that Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” and FSP FAS 157-2, “Effective Date of FASB Statement No. 157.” These FSPs:
•     Exclude certain leasing transactions accounted for under FASB Statement No. 13, Accounting for Leases, from the scope of FASB Statement No. 157, “Fair Value Measurements” (Statement 157). The exclusion does not apply to fair value measurements of assets and liabilities recorded as a result of a lease transaction but measured pursuant to other pronouncements within the scope of Statement 157.
•     Defer the effective date in Statement 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).
FSP FAS 157-1 is effective upon the initial adoption of Statement 157.  FSP FAS 157-2 is effective February 12, 2008.  The Company adopted the provisions of FSP 157-1 and 157-2 in the first quarter of 2008.  See Note 8 for details regarding impact of adoption.
 
Item 7A. Quantitative and Qualitative Disclosures about Market Risk

The Company is subject to interest rate risk exposure through borrowings on its credit facility.  As of December 31, 2008, there are outstanding interest-bearing advances of $174.5 million on our credit facility which bear interest at a floating rate. Effective December 2008 we entered into a $50,000,000 interest rate swap agreement that effectively converted this portion of the outstanding variable-rate borrowings under the revolving credit agreement to a fixed-rate basis, thereby hedging against the impact of potential interest rate changes.  Under this agreement we pay a fixed interest rate of 2.07%. In return, the issuing lender refunds us the variable-rate interest paid to the syndicate of lenders under our revolving credit agreement on the same notional amount, excluding the margin.  The agreement terminates on September 8, 2011.  As of December 31, 2008 the interest rate swap had a negative fair value of $830,000.  An increase in interest rates of one percent would result in the interest rate swap having a positive fair value of approximately $407,000 at December 31, 2008.  A decrease in interest rates of one percent would result in the interest rate swap having a negative fair value of approximately $2,176,000 at December 31, 2008.   A change in interest rates will have no impact on the interest expense associated with the $50,000,000 of borrowings under the revolving credit agreement that are subject to the interest rate swap.  A change in interest rates of one percent on the balance outstanding on the revolving credit agreement at December 31, 2008 not subject to the interest rate swap would cause a change of $1.2 million in total annual interest costs.
 
Additionally, the Company is exposed to market risk resulting from changes in foreign exchange rates.  However, since the majority of the Company’s transactions occur in U.S. currency, this risk is not expected to have a material effect on its consolidated results of operations and financial condition.
 
27

 
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
 
To the Stockholders of RPC, Inc.:
 
The management of RPC, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting for the Company.  RPC, Inc. maintains a system of internal accounting controls designed to provide reasonable assurance, at a reasonable cost, that assets are safeguarded against loss or unauthorized use and that the financial records are adequate and can be relied upon to produce financial statements in accordance with accounting principles generally accepted in the United States of America. The internal control system is augmented by written policies and procedures, an internal audit program and the selection and training of qualified personnel. This system includes policies that require adherence to ethical business standards and compliance with all applicable laws and regulations.
 
There are inherent limitations to the effectiveness of any controls system.  A controls system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the controls system are met.  Also, no evaluation of controls can provide absolute assurance that all control issues and any instances of fraud, if any, within the Company will be detected.  Further, the design of a controls system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. The Company intends to continually improve and refine its internal controls.
 
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operations of our internal control over financial reporting as of December 31, 2008 based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management’s assessment is that RPC, Inc. maintained effective internal control over financial reporting as of December 31, 2008.
 
 The independent registered public accounting firm, Grant Thornton LLP, has audited the consolidated financial statements as of and for the year ended December 31, 2008, and has also issued their report on the effectiveness of the Company’s internal control over financial reporting, included in this report on page 29.
 
     
/s/ Richard A. Hubbell   /s/ Ben M. Palmer
Richard A. Hubbell
President and Chief Executive Officer
 
Ben M. Palmer
Chief Financial Officer and Treasurer
 
Atlanta, Georgia
March 3, 2009
 
28

 
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

Board of Directors and Stockholders
RPC, Inc.
   
We have audited RPC, Inc.’s (a Delaware Corporation) and subsidiaries (the “Company”) internal control over financial reporting as of December 31, 2008 based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting.  Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by COSO. 
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2008 and 2007, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008 and our report dated March 3, 2009 expressed an unqualified opinion on those consolidated financial statements.
 

/s/ Grant Thornton LLP
 
Atlanta, Georgia
March 3, 2009

29

 
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements

Board of Directors and Stockholders
RPC, Inc.

We have audited the accompanying consolidated balance sheets of RPC, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008.  Our audits of the basic consolidated financial statements included the financial statement schedule listed in the index appearing under Item 15.  These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule 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 the Company as of December 31, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As described in Note 5 to the consolidated financial statements, the Company adopted the provisions of Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement 109” during 2007.  As described in Note 1 to the consolidated financial statements, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” during 2006.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 3, 2009 expressed an unqualified opinion thereon.
 

/s/ Grant Thornton LLP
 
Atlanta, Georgia
March 3, 2009

30

 
Item 8. Financial Statements and Supplementary Data
 
CONSOLIDATED BALANCE SHEETS
RPC, INC. AND SUBSIDIARIES
 
(in thousands except share information)
 
December 31,
 
2008
   
2007
 
ASSETS
 
Cash and cash equivalents
  $ 3,037     $ 6,338  
Accounts receivable, net
    210,375       176,154  
Inventories
    49,779       29,602  
Deferred income taxes
    6,187       3,974  
Income taxes receivable
    15,604       12,296  
Prepaid expenses and other current assets
    7,841       6,696  
Current assets
    292,823       235,060  
Property, plant and equipment, net
    470,115       433,126  
Goodwill
    24,093       24,093  
Other assets
    6,430       8,736  
Total assets
  $ 793,461     $ 701,015  
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
LIABILITIES
               
Accounts payable
  $ 61,217     $ 61,371  
Accrued payroll and related expenses
    20,398       17,972  
Accrued insurance expenses
    4,640       4,753  
Accrued state, local and other taxes
    2,395       1,719  
Income taxes payable
    3,359       4,340  
Other accrued expenses
    320       567  
Current liabilities
    92,329       90,722  
Long-term accrued insurance expenses
    8,398       8,166  
Notes payable to banks
    174,450       156,400  
Long-term pension liabilities
    11,177       4,527  
Other long-term liabilities
    3,628       2,692  
Deferred income taxes
    54,395       29,236  
Total liabilities
    344,377       291,743  
Commitments and contingencies
               
STOCKHOLDERS’ EQUITY
               
Preferred stock, $0.10 par value, 1,000,000 shares authorized, none issued
    -       -  
Common stock, $0.10 par value, 159,000,000 shares authorized, 97,705,142 and 98,039,336 shares issued and outstanding in 2008 and 2007, respectively
    9,770       9,804  
Capital in excess of par value
    3,990       16,728  
Retained earnings
    445,356       385,281  
Accumulated other comprehensive loss
    (10,032 )     (2,541 )
Total stockholders’ equity
    449,084       409,272  
Total liabilities and stockholders’ equity
  $ 793,461     $ 701,015  
 
The accompanying notes are an integral part of these statements.
31

 
CONSOLIDATED STATEMENTS OF OPERATIONS
RPC, INC. AND SUBSIDIARIES
 
(in thousands except per share data)

Years ended December 31,
 
2008
   
2007
   
2006
 
REVENUES
  $ 876,977     $ 690,226     $ 596,630  
COSTS AND EXPENSES:
                       
Cost of revenues
    503,631       368,175       287,037  
Selling, general and administrative expenses
    117,140       107,800       91,051  
Depreciation and amortization
    118,403       78,506       46,711  
Gain on disposition of assets, net
    (6,367 )     (6,293 )     (5,969 )
Operating profit
    144,170       142,038       177,800  
Interest expense
    (5,282 )     (4,179 )     (356 )
Interest income
    73       70       319  
Other (expense) income, net
    (1,176 )     1,905       1,085  
Income before income taxes
    137,785       139,834       178,848  
Income tax provision
    54,382       52,785       68,054  
Net income
  $ 83,403     $ 87,049     $ 110,794  
EARNINGS PER SHARE
                       
Basic
  $ 0.86     $ 0.90     $ 1.16  
Diluted
  $ 0.85     $ 0.89     $ 1.13  
Dividends paid per share
  $ 0.240     $ 0.200     $ 0.133  
 
The accompanying notes are an integral part of these statements.
32

 
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
RPC, INC. AND SUBSIDIARIES
 
(in thousands)
 
                     
Capital in
               
Accumulated
       
                     
Excess of
               
Other
       
Three Years Ended  
Comprehensive
   
Common Stock
   
Par
   
Deferred
   
Retained
   
Comprehensive
       
December 31, 2008
 
Income (Loss)
   
Shares
   
Amount
   
Value
   
Compensation
   
Earnings
   
Loss
   
Total
 
Balance, December 31, 2005
          96,678     $ 9,668     $ 16,012     $ (5,391 )   $ 219,907     $ (7,695 )   $ 232,501  
Stock issued for stock incentive plans, net
          491       49       2,533                         2,582  
Stock purchased and retired
          (119 )     (12 )     (3,252 )                       (3,264 )
Net income
  $ 110,794                               110,794             110,794  
Minimum pension liability, net of taxes
    2,108                                     2,108       2,108  
Unrealized loss on securities, net of taxes
    (147 )                                   (147 )     (147 )
Comprehensive income
  $ 112,755                                                          
Dividends declared
                                    (12,996 )           (12,996 )
Stock-based compensation
                        2,384                         2,384  
Excess tax benefits for share- based payments
                        1,325                         1,325  
Adoption of SFAS 123(R)
                        (5,391 )     5,391                    
Three-for-two stock split
            164       16       (16 )                        
Balance, December 31, 2006
            97,214       9,721       13,595             317,705       (5,734 )     335,287  
Stock issued for stock incentive plans, net
            989       99       1,654                         1,753  
Stock purchased and retired
            (163 )     (16 )     (2,838 )                       (2,854 )
Net income
  $ 87,049                               87,049             87,049  
Pension adjustment, net of taxes
    2,535                                     2,535       2,535  
Unrealized gain on securities, net of taxes
    486                                     486       486  
Foreign currency translation, net of taxes
    172                                     172       172  
Comprehensive income
  $ 90,242                                                          
Dividends declared
                                    (19,473 )           (19,473 )
Stock-based compensation
                        3,189                         3,189  
Excess tax benefits for share- based payments
                        1,128                         1,128  
Balance, December 31, 2007
            98,040       9,804       16,728             385,281       (2,541 )     409,272  
Stock issued for stock incentive plans, net
            1,288       128       1,922                         2,050  
Stock purchased and retired
            (1,623 )     (162 )     (19,238 )                       (19,400 )
Net income
  $ 83,403                               83,403             83,403  
Pension adjustment, net of taxes
    (6,053 )                                   (6,053 )     (6,053 )
Loss on cash flow hedge, net of taxes
    (527 )                                   (527 )     (527 )
Unrealized loss on securities, net of taxes
    (585 )                                   (585 )     (585 )
Foreign currency translation, net of taxes
    (326 )                                   (326 )     (326 )
Comprehensive income
  $ 75,912                                                          
Dividends declared
                                    (23,328 )           (23,328 )
Stock-based compensation
                        3,732                         3,732  
Excess tax benefits for share- based payments
                        846                         846  
Balance, December 31, 2008
            97,705     $ 9,770     $ 3,990     $     $ 445,356     $ (10,032 )   $ 449,084  
 
The accompanying notes are an integral part of these statements.
33

 
CONSOLIDATED STATEMENTS OF CASH FLOWS
RPC, Inc. and Subsidiaries
 
(in thousands)
 
Years ended December 31,
 
2008
   
2007
   
2006
 
OPERATING ACTIVITIES
                 
Net income
  $ 83,403     $ 87,049     $ 110,794  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation, amortization and other non-cash charges
    118,444       78,493       46,726  
Stock-based compensation expense
    3,732       3,189       2,384  
Gain on disposition of assets, net
    (6,367 )     (6,293 )     (5,969 )
Deferred income tax provision
    27,199       15,738       2,817  
Excess tax benefits for share-based payments
    (846 )     (1,128 )     (1,325 )
Changes in current assets and liabilities:
                       
Accounts receivable
    (34,508 )     (27,497 )     (41,093 )
Income taxes receivable
    (2,462 )     (7,229 )     (1,347 )
Inventories
    (20,377 )     (8,316 )     (7,886 )
Prepaid expenses and other current assets
    (2,231 )     (568 )     (1,463 )
Accounts payable
    9,691       7,826       8,958  
Income taxes payable
    (981 )     123       774  
Accrued payroll and related expenses
    2,426       4,683       3,713  
Accrued insurance expenses
    (113 )     1,426       (368 )
Accrued state, local and other taxes
    676       (1,078 )     1,597  
Other accrued expenses
    (203 )     46       (90 )
Changes in working capital
    (48,082 )     (30,584 )     (37,205 )
Changes in other assets and liabilities:
                       
Accrued pension
    (481 )     (3,067 )     (802 )
Accrued insurance expenses
    232       1,274       724  
Other non-current assets
    (20 )     (1,173 )     (1,118 )
Other non-current liabilities
    106       (1,626 )     1,202  
Net cash provided by operating activities
    177,320       141,872       118,228  
INVESTING ACTIVITIES
                       
Capital expenditures
    (170,318 )     (248,758 )     (159,831 )
Proceeds from sale of assets
    11,365       9,134       8,746  
Net cash used for investing activities
    (158,953 )     (239,624 )     (151,085 )
FINANCING ACTIVITIES
                       
Payment of dividends
    (23,328 )     (19,473 )     (12,996 )
Borrowings from notes payable to banks
    392,300       478,600       115,171  
Repayments of notes payable to banks
    (374,250 )     (357,800 )     (79,571 )
Debt issue costs for notes payable to banks
    (94 )           (469 )
Excess tax benefits for share-based payments
    846       1,128       1,325  
Cash paid for common stock purchased and retired
    (17,489 )     (1,730 )     (2,024 )
Proceeds received upon exercise of stock options
    347       636       1,341  
Net cash (used for) provided by financing activities
    (21,668 )     101,361       22,777  
Net (decrease) increase in cash and cash equivalents
    (3,301 )     3,609       (10,080 )
Cash and cash equivalents at beginning of year
    6,338       2,729       12,809  
Cash and cash equivalents at end of year
  $ 3,037     $ 6,338     $ 2,729  
 
The accompanying notes are an integral part of these statements.
34

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
RPC, Inc. and Subsidiaries
Years ended December 31, 2008, 2007 and 2006
 
Note 1: Significant Accounting Policies
 
Principles of Consolidation and Basis of Presentation
 
The consolidated financial statements include the accounts of RPC, Inc. and its wholly-owned subsidiaries (“RPC” or the “Company”). All significant intercompany accounts and transactions have been eliminated.
 
Nature of Operations
 
RPC provides a broad range of specialized oilfield services and equipment primarily to independent and major oil and gas companies engaged in the exploration, production and development of oil and gas properties throughout the United States, including the Gulf of Mexico, mid-continent, southwest and Rocky Mountain regions, and in selected international markets. The services and equipment provided include Technical Services such as pressure pumping services, coiled tubing services, snubbing services (also referred to as hydraulic workover services), nitrogen services, and firefighting and well control, and Support Services such as the rental of drill pipe and other specialized oilfield equipment and oilfield training.
 
Dividends
 
On January 27, 2009, the Board of Directors approved an increase in the quarterly cash dividend per common share from $0.06 to $0.07, payable March 10, 2009 to stockholders of record at the close of business February 10, 2009.
 
Use of Estimates in the Preparation of Financial Statements
 
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
 
Significant estimates are used in the determination of the allowance for doubtful accounts, income taxes, accrued insurance expenses, depreciable lives of assets, and pension liabilities.
 
Revenues
 
RPC’s revenues are generated principally from providing services and the related equipment.  Revenues are recognized when the services are rendered and collectibility is reasonably assured.  Revenues from services and equipment are based on fixed or determinable priced purchase orders or contracts with the customer and do not include the right of return.  Rates for services and equipment are priced on a per day, per unit of measure, per man hour or similar basis.  Sales tax charged to customers is presented on a net basis within the consolidated statement of operations and excluded from revenues.
 
Concentration of Credit Risk
 
Substantially all of the Company’s customers are engaged in the oil and gas industry. This concentration of customers may impact overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions.  The Company provided oilfield services to several hundred customers, none of which accounted for more than 10 percent of consolidated revenues.
 
Cash and Cash Equivalents
 
Highly liquid investments with original maturities of three months or less when acquired are considered to be cash equivalents. The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits.  RPC maintains cash equivalents and investments in one or more large financial institutions, and RPC’s policy restricts investment in any securities rated less than “investment grade” by national rating services.

35

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
RPC, Inc. and Subsidiaries
Years ended December 31, 2008, 2007 and 2006
 
Investments
 
Investments classified as available-for-sale are stated at their fair values, with the unrealized gains and losses, net of tax, reported as a separate component of stockholders’ equity. The cost of securities sold is based on the specific identification method. Realized gains and losses, declines in value judged to be other than temporary, interest, and dividends with respect to available-for-sale securities are included in interest income. The Company did not realize any gains or losses on securities during 2008, 2007 and 2006 on its available-for-sale securities.  Securities that are held in the non-qualified Supplemental Retirement Plan (“SERP”) are classified as trading.   See Note 10 for further information regarding the SERP.  The change in fair value of trading securities is presented in other (expense) income on the consolidated statements of operations.
 
Management determines the appropriate classification of investments at the time of purchase and re-evaluates such designations as of each balance sheet date.
 
Accounts Receivable
 
The majority of the Company’s accounts receivable are due principally from major and independent oil and natural gas exploration and production companies.  Credit is extended based on evaluation of a customer’s financial condition and, generally, collateral is not required.  Accounts receivable are considered past due after 60 days and are stated at amounts due from customers, net of an allowance for doubtful accounts.
 
Allowance for Doubtful Accounts
 
Accounts receivable are carried at the amount owed by customers, reduced by an allowance for estimated amounts that may not be collectible in the future. The estimated allowance for doubtful accounts is based on our evaluation of industry trends, financial condition of our customers, our historical write-off experience, current economic conditions, and in the case of our international customers, our judgments about the economic and political environment of the related country and region. Accounts are written off against the allowance for doubtful accounts when the Company determines that amounts are uncollectible and recoveries of previously written-off accounts are recorded when collected.
 
Inventories
 
Inventories, which consist principally of (i) raw materials and supplies that are consumed in RPC’s services provided to customers, (ii) spare parts for equipment used in providing these services and (iii) manufactured components and attachments for equipment used in providing services, are recorded at the lower of weighted average cost or market value. Market value is determined based on replacement cost for material and supplies. The Company regularly reviews inventory quantities on hand and records provisions for excess or obsolete inventory based primarily on its estimated forecast of product demand, market conditions, production requirements and technological developments.
 
Derivative Instruments and Hedging Activities
 
The Company is subject to interest rate risk on the variable component of the interest rate under our revolving credit agreement.  Effective December 2008, the Company entered into a $50,000,000 interest rate swap agreement.  The agreement terminates on September 8, 2011.  The Company has designated the interest rate swap as a cash flow hedge.  Changes in the fair value of the effective portion of the interest rate swap are recognized in other comprehensive loss until the hedge item is recognized in earnings.
 
36

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
RPC, Inc. and Subsidiaries
Years ended December 31, 2008, 2007 and 2006
 
Property, Plant and Equipment
 
Property, plant and equipment, including software costs, are reported at cost less accumulated depreciation and amortization, which is generally provided on a straight-line basis over the estimated useful lives of the assets.  Annual depreciation and amortization expense is computed using the following useful lives: operating equipment, 3 to 10 years; buildings and leasehold improvements, 15 to 30 years; furniture and fixtures, 5 to 7 years; software, 5 years; and vehicles, 3 to 5 years. The cost of assets retired or otherwise disposed of and the related accumulated depreciation and amortization are eliminated from the accounts in the year of disposal with the resulting gain or loss credited or charged to income from operations. Expenditures for additions, major renewals, and betterments are capitalized. Expenditures for restoring an identifiable asset to working condition or for maintaining the asset in good working order constitute repairs and maintenance and are expensed as incurred.
 
RPC records impairment losses on long-lived assets used in operations when events and circumstances indicate that the assets might be impaired and the undiscounted cash flows estimated to be generated by those assets are less than the carrying amount of those assets. The Company periodically reviews the values assigned to long-lived assets, such as property, plant and equipment and other assets, to determine if any impairments should be recognized. Management believes that the long-lived assets in the accompanying balance sheets have not been impaired.
 
Goodwill and Other Intangibles
 
Goodwill represents the excess of the purchase price over the fair value of net assets of businesses acquired.  The carrying amount of goodwill was $24,093,000 at December 31, 2008 and 2007.  Goodwill is reviewed annually for impairment in accordance with the provisions of Statement of Financial Accounting Standard (“SFAS”) No. 142, “Goodwill and Other Intangible Assets.”  In reviewing goodwill for impairment, potential impairment is measured by comparing the estimated fair value of a reporting unit with its carrying value.  Based upon the results of these analyses, the Company has concluded that no impairment of its goodwill has occurred for the years ended December 31, 2008, 2007 and 2006.
 
Other intangibles primarily represent non-compete agreements related to businesses acquired.  Non-compete agreements are amortized on a straight-line basis over the period of the agreement, as this method best estimates the ratio that current revenues bear to the total of current and anticipated revenues.  These non-compete agreements are fully amortized as of December 31, 2008 and 2007.
 
Advertising
 
Advertising expenses are charged to expense during the period in which they are incurred.  Advertising expenses totaled $1,957,000 in 2008, $1,594,000 in 2007 and $1,180,000 in 2006.
 
Insurance Expenses
 
RPC self insures, up to certain policy-specified limits, certain risks related to general liability, workers’ compensation, vehicle and equipment liability, and employee health insurance plan costs. The estimated cost of claims under these self-insurance programs is estimated and accrued as the claims are incurred (although actual settlement of the claims may not be made until future periods) and may subsequently be revised based on developments relating to such claims. The portion of these estimated outstanding claims expected to be paid more than one year in the future is classified as long-term accrued insurance expenses.
 
Income Taxes
 
Deferred tax liabilities and assets are determined based on the difference between the financial and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The Company establishes a valuation allowance against the carrying value of deferred tax assets when the Company determines that it is more likely than not that the asset will not be realized through future taxable income.
 
37

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
RPC, Inc. and Subsidiaries
Years ended December 31, 2008, 2007 and 2006
 
Defined Benefit Pension Plan
 
The Company has a defined benefit pension plan that provides monthly benefits upon retirement at age 65 to eligible employees. In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - An Amendment of FASB Statements No. 87, 88, 106, and 132(R).” SFAS 158 requires the Company to recognize the funded status of its defined benefit pension plan in the Company’s consolidated balance sheets. Effective for fiscal years ending after December 15, 2008, SFAS 158 also removes the existing option to use a plan measurement date that is up to 90 days prior to the date of the balance sheet. The recognition and disclosure provisions of SFAS 158 are effective for fiscal years ending after December 15, 2006, for entities with publicly traded equity securities that have defined benefit plans and is to be applied as of the year of adoption. Accordingly, the Company has adopted the recognition and disclosure provisions of SFAS 158 as of December 31, 2006 which did not result in a material impact to its consolidated financial statements. The Company uses a December 31 measurement date for its pension plan and thus the measurement date provisions did not affect the Company. See Note 10 for a full description of this plan and the related accounting and funding policies.
 
Share Repurchases
 
The Company records the cost of share repurchases in stockholders’ equity as a reduction to common stock to the extent of par value of the shares acquired and the remainder is allocated to capital in excess of par value.
 
Earnings per Share
 
SFAS No. 128, “Earnings Per Share,” requires a basic earnings per share and diluted earnings per share presentation. The two calculations differ as a result of the dilutive effect of stock options and time lapse restricted and performance restricted shares included in diluted earnings per share, but excluded from basic earnings per share. A reconciliation of the weighted shares outstanding is as follows:

   
2008
   
2007
   
2006
 
Basic
    96,565,148       96,267,732       95,242,593  
Dilutive effect of stock options and restricted shares
    1,299,890       2,094,333       2,953,428  
Diluted
    97,865,038       98,362,065       98,196,021  
 
Fair Value of Financial Instruments
 
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, marketable securities, accounts payable, an interest rate swap, and debt. The carrying value of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value due to the short-term nature of such instruments.  The marketable securities classified as available-for-sale and the securities held in the SERP classified as trading are carried at fair value in the accompanying consolidated balance sheets.  The interest rate swap is carried at fair value, which is based on quotes from the issuer of the swap and represents the estimated amounts that we would expect to pay to terminate the swap.  The carrying value of debt approximates fair value since the interest rates are market based and are adjusted periodically.
 
Stock-Based Compensation
 
Effective January 1, 2006, the Company adopted the provisions of SFAS No. 123 (revised 2004), “Share-Based Payments” (“SFAS 123(R)”), which revises SFAS 123, “Accounting for Stock-Based Compensation,” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be measured based on their fair values and recognized in the financial statements over the requisite service period. See Note 10 regarding the Company’s adoption of SFAS 123(R).
 
38

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
RPC, Inc. and Subsidiaries
Years ended December 31, 2008, 2007 and 2006
 
Prior to January 1, 2006, the Company provided the disclosures required by SFAS 123, as amended by SFAS 148, “Accounting for Stock-Based Compensation - Transition and Disclosures,” and accounted for all of its stock-based compensation under the provisions of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” using the intrinsic value method prescribed therein. Accordingly, the Company did not recognize compensation expense for the options granted since the exercise price was the same as the market price of the shares on the date of grant. Compensation cost on the restricted stock was recorded as deferred compensation in stockholders’ equity based on the fair market value of the shares on the date of issuance and amortized ratably over the respective vesting period. Forfeitures related to restricted stock were previously accounted for as they occurred. See Note 10 for additional information.
 
New Accounting Standards

In December 2008, the FASB issued FASB Staff Position (FSP) FAS 132R-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” The FASB issued the FSP, which amends FASB Statement 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits, in order to provide adequate transparency about the types of assets and associated risks in employers’ postretirement plans.  Disclosures are designed to provide an understanding of how investment decisions are made: the major categories of plan assets; the inputs and valuation techniques used to measure the fair value of plan assets; the effect of fair value measurements using significant unobservable inputs (Level 3 measurements in FASB Statement 157, Fair Value Measurements) on changes in plan assets for the period; and significant concentrations of risk within plan assets.  The disclosures about plan assets required by this FSP are required to be provided for fiscal years ending after December 15, 2009, with the provisions of this FSP not required for earlier periods that are presented for comparative purposes, upon initial application. Earlier application of the provisions of this FSP is permitted. The Company is currently in the process of determining the additional disclosures required upon the adoption of this FSP.

In October 2008, the FASB issued FASB Staff Position (FSP) No. FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active.”   FSP 157-3 clarifies the application of SFAS No. 157, “Fair Value Measurements,” in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active.  The FSP stipulates that determining fair value in a dislocated market depends on the facts and circumstances and may require the use of significant judgment when evaluating individual transactions or broker quotes which are some of the sources of the fair value measurement.  In addition, FSP FAS 157-3 states that if an entity uses its own assumptions to determine fair value, it must include appropriate risk adjustments that market participants would make for nonperformance and liquidity risks.  FSP FAS 157-3 is effective upon issuance, including prior periods for which financial statements have not been issued.  The Company adopted FSP FAS 157-3 in the third quarter of 2008 and has concluded that it does not have a material effect on its consolidated financial statements.

In September 2008, the FASB issued FSP No. FAS 133-1 and FIN 45-4, “Disclosures about Credit Derivatives and Certain Guarantees – An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161.”   This FSP amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” to require disclosures by sellers of credit derivatives, including credit derivatives embedded in a hybrid instrument.  This FSP also amends FASB Interpretation No. (FIN) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” to require an additional disclosure about the current status of the payment/performance risk of a guarantee.   Further this FSP clarifies the FASB’s intent about the effective date of SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.”  The provisions of this FSP that amend SFAS No. 161 and FIN 45 are effective for reporting periods ending after November 15, 2008 and the clarification of the effective date of SFAS No. 161 is effective upon issuance of this FSP.  The Company adopted FSP FAS 133-1 and FIN 45-4 in the fourth quarter of 2008 and has concluded that it does not have a material effect on its consolidated financial statements.

39

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
RPC, Inc. and Subsidiaries
Years ended December 31, 2008, 2007 and 2006