Edgar Filing: RPC INC

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, 2006

Commission File No. 1-8726

RPC, INC.

Delaware	58-1550825
(State of Incorporation)	(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	Name of each exchange on which registered
COMMON STOCK, $0.10 PAR VALUE	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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o

Accelerated filer x

Non-accelerated filer 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, 2006, the last business day of the registrant’s most recently completed second fiscal quarter, was $510,582,153 based on the closing price on the New York Stock Exchange on June 30, 2006 of $16.19 per share.

RPC, Inc. had 97,753,233 shares of Common Stock outstanding as of February 15, 2007.

Documents Incorporated by Reference

Portions of the Proxy Statement for the 2007 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 expectations regarding continued increases in oil and gas exploration and production, our belief that high returns on our investments will continue long-term, 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 expectations regarding revenues in 2007, our expectations regarding capital expenditures in 2007, our ability to maintain sufficient liquidity and a conservative capital structure, 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, our expectation to continue to pay cash dividends, 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) snubbing services (also referred to as hydraulic workover services), (3) coiled tubing 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 (acquired in April 2004), Thru-Tubing Solutions, Well Control School, and others. As of December 31, 2006, RPC had approximately 2,000 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. The Other business segment aggregates information concerning RPC’s business units that do not qualify for separate segment reporting, including an interactive training software developer (until its sale in May 2005) and an overhead crane fabricator (until its sale in April 2004).

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, snubbing, coiled tubing, nitrogen, well control, down-hole tools, wireline, fluid pumping and casing installation services (until its sale in August 2005). The principal markets for this business segment include the United States, including the Gulf of Mexico, mid-continent, southwest and Rocky Mountain regions, and international locations 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, work platform marine vessels (until its sale in October 2004) 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 international locations 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 38 percent of 2006 revenues, 37 percent of 2005 revenues and 31 percent of 2004 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 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.

Snubbing. Snubbing (also referred to as hydraulic workover services), which accounted for approximately 11 percent of 2006 revenues, 11 percent of 2005 revenues and 12 percent of 2004 revenues, involves using a hydraulic workover rig that permits an operator to repair damaged casing, production tubing and down-hole production equipment in a high-pressure environment. A snubbing unit makes it possible to remove and replace down-hole 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.

Coiled Tubing. Coiled tubing services, which accounted for approximately 10 percent of 2006 and 2005 revenues and 11 percent of 2004 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.

Nitrogen. Nitrogen accounted for approximately eight percent of 2006 and 2005 revenues and nine percent of 2004 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.

Well Control. Cudd Pressure Control 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, 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 eight 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 19 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.

Down-hole Tools. ThruTubing Solutions (“TTS”), a division of the Company, provides services and proprietary down-hole motors and fishing tools to operators and service companies in drilling and production operations. TTS’ experience providing reliable tool services allows it to work in a pressurized environment with virtually any coiled tubing unit or snubbing unit that is equipped for the task.

Wireline Services. A wireline unit is a spooled wire that can be unwound and lowered into a well carrying various types of tools. Wireline services are used for a variety of purposes, such as accessing a well to assist in data acquisition or logging activities, fishing tool operations to retrieve lost or broken equipment, pipe recovery and remedial activities. In addition, wireline services are 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 drill operations 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 13 percent of 2006 revenues, 10 percent of 2005 revenues and 11 percent of 2004 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.

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

Pipe Inspection and Handling Services. Pipe inspection services involve the inspection and testing of the integrity of pipe used in oil and gas wells. These services are provided primarily at the Company’s inspection yards located on a water channel near Houston, Texas, and in Morgan City, Louisiana. Customers rely on tubular inspection services to avoid failure of in-service tubing, casing, flowlines, and drill pipe. Such tubular failures are expensive and, in some cases, catastrophic. Our facility in Houston, Texas is equipped with bulkhead waterfronts, large capacity cranes, specially designed forklifts and a computerized inventory system to serve a variety of storage and handling services for both 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 and mobile simulator training. Well Control School also develops customized training solutions for clients.

Energy Personnel International. Energy Personnel International provides drilling and production engineers, project management specialists and workover 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 more than 61 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 2006, there were 1,464 domestic working drilling rigs, up 13 percent from the third quarter 2001 peak during that industry cycle. U.S. domestic drilling activity steadily rose during 2006 and peaked in the third quarter at a rig count of 1,762, which was 36 percent higher than the third quarter 2001 peak. In 2006 the average rig count of 1,649 increased 19 percent compared to the prior year. During 2006 the average price of natural gas declined by almost 25 percent, and the average price of oil increased by over 17 percent. We believe that the change in the U.S. domestic rig count was not positively correlated with the changes in the prices of oil and natural gas as in prior years for several reasons. One factor is that the prices of oil and natural gas in late 2005 were extraordinarily high due to disruptions in domestic oil and gas infrastructure caused by the hurricanes in the Gulf of Mexico during 2005. Also, we believe that the current prices of oil and natural gas are high enough to encourage our customers to undertake exploration and production activities, that many of them have entered into hedging contracts to sell their production at higher prices, and that our customers believe that in the long-term, the prices of oil and natural gas will remain high enough to yield profitable returns for their exploration and production activities.

Gas drilling rigs have represented an increasing percentage of the total drilling rig count, and have represented at least 80 percent of the drilling rig count each year since 2001. In 2006, gas drilling rigs represented 83 percent of total drilling activity. Demand for natural gas is continuing to rise, primarily as a result of increased emphasis on gas-fired power generation. 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 80 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 more applicable to deeper, higher pressure wells, which tend to be the wells that produce natural gas. In addition, there are certain types of gas wells 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 associated with natural gas development is currently more robust than demand related to oil drilling. Drilling activity and demand for our services have continued to increase and are expected to continue increasing with domestic economic improvements.

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 increased its focus on developing international opportunities, although our long-term growth plan emphasizes domestic rather than international expansion. As a result of this focus, international revenues for 2006 increased due to higher customer activity levels in Angola, Argentina, Canada and Turkmenistan. During 2006, RPC performed snubbing work in Cameroon, China, Gabon, Hungary, Kuwait and Turkmenistan, among other countries. We also provided rental tools, well control services, downhole motors, fishing tool services and oilfield training to customers located in Algeria, Angola, Argentina, Australia, Bahrain, Bolivia, Canada, Chile, China, Ecuador, Equatorial Guinea, India, Indonesia, Mexico, Peru, Qatar, the United Kingdom and Venezuela. 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 will 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. Although current price expectations reduce the near-term possibility of completing a transaction, we believe we generate better returns growing organically in service lines and geographic locations in which we have experience and presence.

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. RPC is pursuing this growth plan, including funding with debt, because of the high returns on investment historically generated by many of its service lines, RPC’s belief that these high returns will continue long-term with minimal downside risk, and the low cost and ready availability of debt capital.

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 2006, 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. With the exception of certain international customers, there are no long-term written contracts for services or equipment. 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 and unencumbered. 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. At the end of 2006, the Company experienced a delay of new equipment deliveries anticipated for the fourth quarter of 2006 due to high manufacturing backlogs resulting from high demand; however, we have received the majority of this equipment by the first two months of 2007 and expect to receive the remainder of the 2006 deliveries by the end of the first quarter of 2007.

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, 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 but as the business continues to grow, we are evaluating the need for additional facilities. 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.

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, a rise in the prices of oil and natural gas has led to an immediate increase in our customers’ drilling and production activities as measured by the domestic rig count. However, this relationship has not been as strong in the recent past as it was historically, due in part to limited drilling rig capacity in the United States. For example, during 2006 the average drilling rig count rose by 19 percent, despite the 25 percent decline in the average price of natural gas and the 17 percent increase in the average price of oil. 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 may be affected by the following factors: changes in competitive prices, fluctuations in the level of activity in major markets, general economic conditions, and governmental regulation. 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 will 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.

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 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, and boycotts and other civil disturbances. The occurrence of any one of these events could have a material adverse effect on our operations.

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 67 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.

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. 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. 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 may decide to seek outside financing to accomplish our growth strategy, and outside financing may not be available 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 $250 million credit facility to fund our capital requirements. 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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

RPC owns or leases approximately 85 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

Morgan City, Louisiana — Pipe cleaning facility

Elk City, Oklahoma — Operations, sales and equipment storage yards

Rock Springs, Wyoming — Operations, sales and equipment storage yards

Leased Locations

Seminole, Oklahoma — Pumping services facility

Elk City, Oklahoma — Operations, sales and equipment storage yards

Kilgore, Texas — Pumping services facility

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 2006.

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)	75	1/24/84
Chairman of the Board

Richard A. Hubbell (2)	62	4/22/03
President and Chief Executive Officer

Linda H. Graham (3)	70	1/27/87
Vice President and Secretary

Ben M. Palmer (4)	46	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, 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 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. and, until April 2004, he served as a director of SunTrust Banks, Inc. and SunTrust Banks of Georgia.

(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 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 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 in February 2001.

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. On October 24, 2006, RPC’s Board of Directors declared a three-for-two stock split of the Company’s common shares. The additional shares were distributed on December 11, 2006, to shareholders of record on November 10, 2006. All share, earnings per share, and dividends per share data presented throughout this document have been adjusted to reflect this stock split. At February 15, 2007, there were 97,753,233 shares of common stock outstanding and approximately 6,896 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, 2006 and 2005:

	2006						2005
Quarter	High		Low		Dividends		High		Low		Dividends
First	$	23.72	$	12.33	$	0.033	$	8.91	$	6.22	$	0.018
Second		23.19		12.83		0.033		7.77		5.85		0.018
Third		16.97		11.53		0.033		11.72		7.40		0.018
Fourth		17.95		11.17		0.033		17.92		9.35		0.018

On January 23, 2007, the Board of Directors approved a quarterly cash dividend per common share of $0.05 payable March 12, 2007 to stockholders of record at the close of business February 12, 2007. 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 2006 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, 2006 to October 31, 2006		—	(1)		—		—		4,066,965
November 1, 2006 to November 30, 2006		2,331	(1)		14.74		—		4,066,965
December 1, 2006 to December 31, 2006		245,986	(2)		15.60		—		4,066,965
Totals		248,317		$	15.59		—		4,066,965

(1)	All shares shown were tendered to the Company in connection with employee stock option exercises.

(2)

Consists of 9,986 shares tendered to the Company in connection with employee stock option exercises. Also includes 236,000 shares purchased by “affiliated purchasers” under Rule 10b - 18 of the Securities Exchange Act of open market transactions. These affiliated purchases were made by RFT Investment Co. LLC of which LOR, Inc. is the manager. Mr. R. Randall Rollins and Mr. Gary W. Rollins having voting control of LOR, Inc.

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. During the fourth quarter of 2006, there were no open market purchases of the Company’s shares under this stock repurchase program. 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.

The Russell 2000 is a stock index representing small capitalization U.S. stocks. The components of the index had an average market capitalization in 2006 of $1.25 billion, and the Company was a component of the Russell 2000 during 2006. 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.

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.

STATEMENT OF OPERATIONS DATA:

Years Ended December 31,	2006			2005			2004			2003			2002
	(in thousands, except employee and per share amounts)
Revenues	$	596,630		$	427,643		$	339,792		$	270,527		$	209,030
Cost of services rendered and goods sold		287,037			227,492			193,659			168,766			143,362
Selling, general and administrative expenses		91,051			75,478			65,871			52,268			44,852
Depreciation and amortization		46,711			39,129			34,473			33,094			31,242
Gain on disposition of assets, net (a)		(5,969	)		(12,169	)		(5,551	)		(36	)		(1,597	)
Operating profit (loss)		177,800			97,713			51,340			16,435			(8,829	)
Interest expense		(418	)		(127	)		(311	)		(284	)		(210	)
Interest income		381			1,077			243			131			136
Other income, net		1,085			2,077			1,931			1,288			749
Income (loss) before income taxes		178,848			100,740			53,203			17,570			(8,154	)
Income tax provision (benefit) (b)		68,054			34,256			18,430			6,677			(2,894	)
Net income (loss) (b)	$	110,794		$	66,484		$	34,773		$	10,893		$	(5,260	)
Earnings (loss) per share:
Basic	$	1.16		$	0.70		$	0.36		$	0.11		$	(0.06	)
Diluted	$	1.13		$	0.67		$	0.36		$	0.11		$	(0.06	)
Dividends paid per share	$	0.133		$	0.071		$	0.036		$	0.030		$	0.030
OTHER DATA:
Operating margin percent		29.8	%		22.8	%		15.1	%		6.1	%		(4.2	%)
Net cash provided by operations	$	118,228		$	66,362		$	50,374		$	50,631		$	27,556
Net cash used for investing activities		(151,085	)		(62,415	)		(37,215	)		(34,670	)		(21,831	)
Net cash provided by (used for) financing activities		22,777			(20,774	)		(5,825	)		(5,192	)		(4,927	)
Depreciation and amortization (c)		46,711			39,129			34,500			33,182			31,342
Capital expenditures	$	159,831		$	72,808		$	49,869		$	30,356		$	22,481
Employees at end of period		2,000			1,649			1,596			1,529			1,419
BALANCE SHEET DATA AT END OF YEAR:
Accounts receivable, net	$	148,469		$	107,428		$	75,793		$	53,719		$	40,168
Working capital		111,302			95,215			77,509			63,226			52,646
Property, plant and equipment, net		262,797			141,218			114,222			109,163			105,338
Total assets		474,307			311,785			262,942			226,864			195,954
Current portion of long-term debt		—			—			2,700			1,110			552
Long-term debt (d)		35,600			—			2,100			4,800			2,410
Total stockholders’ equity	$	335,287		$	232,501		$	181,423		$	151,106		$	145,081

(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 assets during 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)

Prior to the sale of our overhead crane fabricator in April 2004, depreciation and amortization differed from depreciation and amortization presented in the statements of operations. This difference is due to depreciation related to the manufacturing of goods which was included in cost of services rendered and goods sold.

(d)

Effective September 2006, the Company closed on a new revolving credit facility for up to $250 million. In 2005, the Company prepaid a $2.8 million promissory note and the remaining balance was paid in full upon maturity of a promissory note in July 2005.

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, while high by historical levels, are extremely volatile and have recently declined significantly compared to prior year. Oil prices are historically high, although they have declined somewhat during the second half of 2006. During 2006, the price of natural gas increased at the beginning of the year compared to 2005, as U.S. natural gas production continued to be disrupted as a result of the severe hurricanes in the Gulf of Mexico in the third quarter of 2005, which significantly disrupted U.S. natural gas production. However, during the second half of 2006 natural gas prices decreased dramatically due to a much less severe 2006 hurricane season, increasing natural gas storage levels, and expectations of warm weather in the winter of 2007. In spite of these volatile, declining commodity prices, the rig count increased steadily throughout the year, as our customers continued to earn strong returns on their investments and believed that the long-term operating environment would be profitable. These trends in 2006 resulted in higher pricing for the Company’s services and equipment, high utilization of new equipment placed in service during the year, and continued high utilization of our existing equipment and personnel. Cash flow generated by our improved results and proceeds from our revolving credit facility have also allowed us to make higher capital expenditures, which has led to an increase in capacity for providing services to our customers.

The results of our strategies are reflected in our 2006 financial and operational performance. We generated record revenues and profitability in 2006 because of better industry conditions, improved pricing, increased capacity and growth in the utilization of our personnel and equipment. Revenues in 2006 of $596.6 million increased 39.5 percent compared to the prior year. The growth in revenues resulted primarily from improved pricing for our equipment and services, increased capacity due to our expenditures for new equipment and maintenance on existing equipment, and a slight increase in utilization consistent with higher customer activity levels. The increase in prices is partially attributable to the issuance of new price books during the third quarter of 2005 and the first and third quarters of 2006. International revenues for 2006 increased due to higher customer activity levels in Angola, Argentina, Canada and Turkmenistan. We continue to focus on developing international growth opportunities; however, it is difficult to predict when contracts and projects will be initiated and their ultimate duration. International revenues remain less than 10 percent of consolidated revenues. Based on current industry conditions and trends during 2007 and our planned capital expenditures, we expect consolidated revenues for 2007 to increase compared to 2006, although the volatility in our industry makes accurate near-term forecasts unreliable.

Income before income taxes was $178.8 million in 2006 compared to $100.7 million in the prior year. The effective tax rate for 2006 was 38.1 percent compared to 34.0 percent in the prior year. Diluted earnings per share increased to $1.13 in 2006 compared to $0.67 for the prior year, which included an after tax gain of $7.1 million or $0.07 diluted earnings per share due to sale of certain assets in the third quarter of 2005. Cash flows from operating activities were $118.2 million in 2006 compared to $66.4 million in the prior year, and cash and cash equivalents were $2.7 million at December 31, 2006, a decrease of $10.1 million compared to December 31, 2005. This decrease in cash and cash equivalents occurred despite higher cash flows from operating activities primarily because of increased capital expenditures to expand our fleet of revenue producing equipment. During the third quarter of 2006, we replaced our $50 million credit facility with a new $250 million revolving credit facility in order to support our growth plan. As of December 31, 2006, there was $35.6 million in outstanding borrowings on our revolving credit facility.

Cost of services rendered and goods sold as a percentage of revenues decreased approximately 5.1 percentage points in 2006 compared to 2005. This improvement was due to improved pricing and higher equipment and personnel utilization resulting in the leverage of our fixed costs over higher revenues.

Selling, general and administrative expenses as a percentage of revenues decreased approximately 2.3 percentage points in 2006 compared to 2005, which was due to the leverage of these costs over higher revenues partially offset by an increase in employment costs consistent with higher activity levels, and increased incentive compensation consistent with improved financial results.

Consistent with our strategy to selectively grow our capacity and maintain our existing fleet of high demand equipment, capital expenditures were $159.8 million in 2006. In September 2006, we selected a group of banks that put a credit facility in place that allows for up to $250 million in borrowings. Although we currently expect capital expenditures to be approximately $275 million during 2007, the total amount of 2007 expenditures will depend primarily on equipment maintenance requirements and the ultimate delivery dates for equipment on order. We expect these expenditures to be primarily directed toward our larger, core service lines including primarily pressure pumping, but also hydraulic workover, coiled tubing, nitrogen, and rental tools.

On October 24, 2006, RPC’s Board of Directors declared a three-for-two stock split of the Company’s common shares. The additional shares were distributed on December 11, 2006, to shareholders of record on November 10, 2006. All share, earnings per share, and dividends per share data presented throughout this document, including the accompanying financial statements and management’s discussion and analysis, have been adjusted to reflect this stock split.

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 2006 was approximately 16 percent higher than in the comparable period in 2005. The average price of oil rose by approximately one percent while the average price of natural gas declined by more than 44 percent during the fourth quarter compared to the prior year. The natural gas price was substantially higher one year ago because of the reduction in gas production following hurricanes Katrina and Rita. While the overall drilling rig count has increased, drilling activity in the Gulf of Mexico has been weak, although it has recently improved. The Company has responded to these trends by emphasizing investments in more robust domestic markets and making only selective investments in the Gulf of Mexico market. In spite of recent strong industry conditions, the Company understands that factors influencing the industry are unpredictable. The Company is monitoring recent declines in oil and natural gas prices for any signs of weakness in domestic customer activity levels. Our response to the industry’s potential uncertainty is to maintain sufficient liquidity and a conservative capital structure. Although we have recently decided to expand our bank credit facility to finance our expansion, we will still maintain a conservative financial structure. Based on current industry conditions and trends during 2006, we expect consolidated revenues for 2007 to increase compared to 2006.

The high activity levels in the domestic oilfield have increased demand for equipment from the manufacturers of equipment and components used in the Company’s business. This increased demand has increased the lead times for ordering and delivery of such equipment and components. If this increased demand and resulting delays in delivery extends indefinitely, it could constrain the Company’s ability to expand its capacity, which would negatively impact the Company’s future financial results.

Results of Operations

Years Ended December 31,	2006			2005			2004
Consolidated revenues	$	596,630		$	427,643		$	339,792
Revenues by business segment:
Technical	$	495,090		$	363,139		$	279,070
Support		101,540			64,487			56,917
Other		—			17			3,805

Consolidated operating profit	$	177,800		$	97,713		$	51,340
Operating profit by business segment:
Technical	$	153,126		$	84,048		$	47,027
Support		30,953			11,990			8,287
Other		—			(273	)		(975	)
Corporate expenses		(12,248	)		(10,221	)		(8,550	)
Gain on disposition of assets, net		5,969			12,169			5,551

Net income	$	110,794		$	66,484		$	34,773
Earnings per share — diluted	$	1.13		$	0.67		$	0.36
Percentage of cost of services rendered and goods sold to revenues		48	%		53	%		57	%
Percentage of selling, general and administrative expenses to revenues		15	%		18	%		19	%
Percentage of depreciation and amortization expense to revenues		8	%		9	%		10	%
Effective income tax rate		38.1	%		34.0	%		34.6	%
Average U.S. domestic rig count		1,649			1,383			1,190
Average natural gas price (per thousand cubic feet (mcf))	$	6.65		$	8.86		$	5.88
Average oil price (per barrel)	$	66.36		$	56.61		$	41.35

Year Ended December 31, 2006 Compared To Year Ended December 31, 2005

Revenues. Revenues for 2006 increased $169.0 million or 39.5 percent compared to 2005. The Technical Services segment revenues for 2006 increased 36.3 percent from the prior year due primarily to improved pricing and increased capacity driven by higher capital expenditures. The Support Services segment revenues for 2006 increased 57.5 percent from the prior year due to increased capacity driven by higher capital expenditures in the rental tool service line, the largest within this segment, as well as improved pricing in the service lines which comprise this segment.

Domestic revenues increased 37 percent to $566.6 million during 2006 compared to the prior year. The increase in revenues is due to higher pricing and increased capacity in our largest service lines, such as pressure pumping and rental tools. The increase in pricing is mostly attributed to price book adjustments effective during the third quarter of 2005 and the first and third quarters of 2006 and higher customer demand for our services. The average price of natural gas decreased by almost 25 percent and the average price of oil increased by over 17 percent during 2006 compared to the prior year. In spite of the decrease in natural gas, the average domestic rig count during 2006 was 19 percent higher than the same period in 2005. 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 increased from $14.3 million in 2005 to $30.0 million in 2006, or only five percent of consolidated revenues. Revenue increases were realized due mainly to higher customer activity levels in Angola, Argentina, Canada and Turkmenistan compared to the prior year. Our international revenues are impacted by the timing of project initiation and their ultimate duration.

Cost of services rendered and goods sold. Costs of services rendered and goods sold in 2006 was $287.0 million compared to $227.5 million in 2005, an increase of $59.5 million or 26.2 percent. The increase in these costs was due to the variable nature of many of these expenses, including compensation, materials and supplies expenses and maintenance and repair expenses. Cost of services rendered and goods sold, as a percent of revenues, decreased in 2006 from 2005 due to leveraging of fixed costs over higher revenues as a result of improved pricing and increased equipment and personnel utilization.

Selling, general and administrative expenses. Selling, general and administrative expenses increased 20.6 percent to $91.1 million in 2006 compared to $75.5 million in 2005. This increase was primarily due to higher employee headcount consistent with higher activity levels, and increased compensation costs consistent with improved profitability. These costs as a percent of revenues, however, decreased due to leveraging of these expenses, most of which are of a fixed nature, over higher revenues.

Depreciation and amortization. Depreciation and amortization were $46.7 million in 2006, an increase of $7.6 million or 19.4 percent compared to $39.1 million in 2005. This increase in depreciation and amortization 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 decreased due primarily to the sale of operating and intangible assets related to the hammer, casing, laydown and casing torque-turn service lines which generated a pre-tax gain of $10.7 million in the third quarter of 2005. The remaining gain on disposition of assets, net during 2006 and 2005 includes gains or losses related to various property and equipment dispositions or sales to customers of lost or damaged rental equipment.

Other income, net. Other income, net in 2006 was $1.1 million, a decrease of $1.0 million compared to $2.1 million in 2005. The decrease is primarily due to proceeds from a litigation settlement that were realized during the first quarter of 2005. The remaining other income, net primarily includes gains from settlements of various other legal and insurance claims.

Interest expense and interest income. Interest expense was $418 thousand in 2006 compared to $127 thousand in 2005. The increase is due primarily to higher interest expense in 2006 incurred on outstanding interest bearing advances on our revolving line of credit. Interest income declined to $381 thousand in 2006 compared to $1.1 million in 2005 as a result of a lower average cash balance in 2006 compared to 2005 and $412 thousand of interest income related to income tax refunds received during the fourth quarter of 2005.

Income tax provision. The income tax provision increased to $68.1 million in 2006 from $34.3 million in 2005. The increase is due to the increase in income before taxes and an increase in the effective tax rate to 38.1 percent in 2006 from 34.0 percent in 2005. Adjustments of $3.5 million in 2005 related to receipt of income tax refunds resulted in an income tax benefit of 3.4 percent.

Net income and diluted earnings per share. Net income increased 66.6 percent to $110.8 million, or $1.13 earnings per diluted share, compared to $66.5 million, or $0.67 earnings per diluted share in 2005, which included an after-tax gain on the sale of certain assets in the third quarter of 2005 of $0.07 diluted earnings per share.

Year Ended December 31, 2005 Compared To Year Ended December 31, 2004

Revenues. Revenues for 2005 increased $87.9 million or 25.9 percent compared to 2004. The Technical Services segment revenues for 2005 increased 30.1 percent from the prior year due primarily to increases in capacity driven by higher capital expenditures, improved utilization, and increased pricing driven by higher customer demand for our services. This increase was partially offset by the disposal of our casing installation services in the third quarter of 2005. The Support Services segment revenues for 2005 increased 13.3 percent from the prior year as a result of higher capacity, equipment utilization and increased pricing in rental tools, which is the largest service line within this segment. The growth in this segment was lower than the change in the domestic rig count and in Technical Services due to this segment’s exposure to the Gulf of Mexico, a region in which activity has been very weak since the hurricanes in the third quarter of 2005. In addition, these increases were also offset by the lack of revenues for 2005 from our marine liftboat division, which was sold in the fourth quarter of 2004. The marine liftboat division generated revenues of $3.3 million in 2004.

Domestic revenues increased during 2005 due to increased customer demand for our services, which we were able to meet with increases in capacity, utilization and improved pricing as a result of new price books issued during the third quarter of 2005. The average domestic rig count during 2005 was 16 percent higher than the same period in 2004. In addition, the average price of natural gas increased by approximately 51 percent and the average price of oil increased by approximately 37 percent during 2005 compared to the prior year. This increase in oil and gas prices and the resulting increase in drilling activity had a positive impact on our financial results. These increases were partially offset by continued weakness in the Gulf of Mexico market, which was especially weak in the third and fourth quarters as a result of the hurricanes that occurred in the third quarter. Foreign revenues decreased from $15.9 million in 2004 to $14.3 million in 2005 due to a large decline in our Kuwait operation. This decline was due to the sporadic nature of the contract as well as customer-imposed delays. This decline was offset by increases in almost all of our other international locations as well as the inception of a new contract in Turkmenistan. These increases were due to our increased focus on international business and our business development efforts.

Cost of services rendered and goods sold. Costs of services rendered and goods sold in 2005 was $227.5 million compared to $193.7 million in 2004, an increase of $33.8 million or 17.5 percent. The increase in these costs was due to the variable nature of many of these expenses, including compensation, materials and supplies, maintenance and repair, and fuel costs and the increase in the price of fuel. Cost of services rendered and goods sold, as a percent of revenues, decreased to 53.2 percent in 2005 from 57.0 percent in 2004 as a result of higher utilization of personnel and operating equipment, improved pricing, and the leveraging of fixed costs over higher revenues.

Selling, general and administrative expenses. Selling, general and administrative expenses increased 14.6 percent to $75.5 million in 2005 compared to $65.9 million in 2004. However, as a percentage of revenues, these expenses decreased 1.7 percentage points to 17.7 percent. The increase was primarily due to higher employment costs associated with additions to field administrative personnel to handle higher business activity levels and costs to implement additional information technology to support operational efficiencies.

Depreciation and amortization. Depreciation and amortization were $39.1 million in 2005, an increase of $4.6 million or 13.3 percent compared to $34.5 million in 2004. This increase in depreciation and amortization resulted from various capital expenditures made during 2005 within Support Services and Technical Services. A larger percentage of the increase in depreciation and amortization was due to capital expenditures made in the Support Services segment than the Technical Services segment, despite its smaller relative revenues and total assets, because of investments made in the rental tools service line, the largest service line within Support Services, and a new Support Services operational facility that was constructed in 2005.

Gain on disposition of assets, net. Gain on the disposition of assets, net increased primarily due to the sale of certain assets of the hammer, casing, laydown and casing torque-turn service lines for net proceeds of $15.7 million which generated a pre-tax gain of $10.7 million, or $0.07 after tax gain per diluted share. The gain on disposition of assets in 2004 was due primarily to the pre-tax gain of $3.3 million on the sale of the domestic liftboat fleet which occurred during the fourth quarter of 2004. The remaining gain on disposition of assets, net in 2005 and 2004 also includes gains or losses related to various real property and equipment dispositions or sales to customers of lost or damaged rental equipment.

Other income, net. Other income, net in 2005 of $2.1 million primarily includes proceeds of approximately $1.3 million from a litigation settlement in the first quarter of 2005. The remaining other income, net in 2005 and 2004 also includes gains from various other legal and insurance claims.

Interest expense and interest income. Interest expense decreased to $127 thousand in 2005 compared to $311 thousand in 2004. The decrease resulted primarily from the reduction in outstanding debt through annual principal payments made during 2004 and 2005. Interest income increased to $1.1 million in 2005 compared to $243 thousand in 2004 as a result of $412 thousand of interest income related to income tax refunds received during the fourth quarter of 2005 and higher percentage yields on a slightly higher average cash balance in 2005 compared to 2004.

Income tax provision. The effective tax rate was 34.0 percent in 2005 and 34.6 percent in 2004. Adjustments of $3.5 million in 2005 resulted in an income tax benefit of 3.4 percent related to income tax refunds received primarily during the fourth quarter of 2005. Adjustments of $1.1 million in 2004 resulted in an income tax benefit of 3.2 percent primarily related to the recognition of previously reserved foreign tax credit carryovers and an adjustment to the liability for foreign taxes.

Net income and diluted earnings per share. Net income for 2005 was $66.5 million, or $0.67 earnings per diluted share. This included a $7.1 million after tax gain, or $0.07 per diluted share, related to the sale of the operating and intangible assets of the hammer, casing, laydown and casing torque-turn service lines. Net income for 2004 was $34.8 million or $0.36 earnings per diluted share, and included a pre-tax gain of $3.3 million related to the sale of the domestic liftboat fleet.

Liquidity and Capital Resources

Cash and Cash Flows

The Company’s cash and cash equivalents were $2.7 million as of December 31, 2006, $12.8 million as of December 31, 2005 and $29.6 million as of December 31, 2004.

The following table sets forth the historical cash flows for the year ended December 31:

	(in thousands)
	2006			2005			2004
Net cash provided by operating activities	$	118,228		$	66,362		$	50,374
Net cash used for investing activities		(151,085	)		(62,415	)		(37,215	)
Net cash provided by (used for) financing activities		22,777			(20,774	)		(5,825	)

2006

Cash provided by operating activities increased by $51.9 million in 2006 compared to the prior year. This increase is due primarily to the $44.3 million increase in net income partially offset by a small increase in working capital requirements. Increased business activity levels and revenues resulted in higher accounts receivable, inventories and prepaid expenses partially offset by the increased accounts payable and accrued payroll.

Cash used for investing activities in 2006 increased by $88.7 million compared to 2005, primarily as a result of higher capital expenditures to increase capacity and maintain our existing equipment. This increase was partially offset by earnout payments made in the second and third quarters of 2005 which did not recur in the current period.

Cash provided by financing activities in 2006 increased by $43.6 million compared to 2005, primarily due to net borrowings from notes payable to banks during the third and fourth quarters of 2006, a decrease in repurchases of common shares, principal loan repayments made in the first and third quarters of 2005 which did not recur in the current year and excess tax benefits for share-based payments. This increase was partially offset by an 88 percent increase in dividends paid to common shareholders.

2005

Cash provided by operating activities was $66.4 million in 2005 compared to $50.4 million in 2004. The large improvement in operating results and increased gains on sale of assets was partially offset by higher working capital requirements and a lower cash contribution to the defined benefit pension plan in 2005 compared to 2004. Increased business activity levels and revenues resulted in increased accounts receivable and inventories which was partially offset by higher accounts payable. Also, the company received income tax refunds of $3.5 million in 2005 that did not occur in 2004.

Cash used for investing activities in 2005 increased by $25.2 million compared to 2004, primarily as a result of an increase in capital expenditures to increase capacity and maintain our existing equipment and an increase of $5.5 million in 2005 compared to 2004 in earnout payments for acquisitions. These increases were partially offset by higher proceeds from the sale of assets.

Cash used for financing activities in 2005 increased by $14.9 million compared to 2004, due to increased cost of open market share repurchases of Company common stock, a 100 percent increase in dividends paid to common shareholders, and principal repayments totaling $4.8 million during the first and third quarters of 2005.

Financial Condition and Liquidity

The Company’s financial condition as of December 31, 2006, 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. 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 $199.4 million was available under our facility as of December 31, 2006 and $190.6 million was available as of February 28, 2007; approximately $15.0 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 7 of the Notes to Consolidated Financial Statements.

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 $159.8 million in 2006, and we currently expect capital expenditures to be approximately $275 million in 2007. 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 2007 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. During the first quarter of 2006, the Company contributed $2.6 million to the pension plan. We expect that additional contributions to the defined benefit pension plan of approximately $4.75 million will be required in 2007 to achieve the Company’s funding objective.

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 4,066,965 additional shares were available to be repurchased as of December 31, 2006. The program does not have a predetermined expiration date.

On January 23, 2007, the Board of Directors approved an increase in the quarterly cash dividend per common share, from $0.03 to $0.05, payable March 12, 2007 to stockholders of record at the close of business February 12, 2007. 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, 2006:

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	$	35,600	$	—	$	—	$	35,600	$	—
Interest on long-term debt obligations		10,346		2,072		6,248		2,026		—
Capital lease obligations		—		—		—		—		—
Operating leases (1)		9,627		182		6,065		2,056		1,324
Purchase obligations (2)		55,356		55,356		—		—		—
Other long-term liabilities (3)		8,132		4,750		3,382		—		—
Total contractual obligations	$	119,061	$	62,360	$	15,695	$	39,682	$	1,324

(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 primarily known pension plan funding obligations and incentive compensation. These amounts exclude pension obligations with uncertain funding requirements and deferred compensation liabilities.

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 low 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 has been able to recover such increased costs through price increases to its customers, but it may not be able to do so in the future, thereby reducing the Company’s future profits.

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 $739,000 in 2006, $616,000 in 2005 and $546,000 in 2004. The Company’s receivable due from Marine Products for these services as of December 31, 2006 and 2005 was approximately $236,000 and $66,000. 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.

The Tax Sharing and Indemnification Agreement provides for, among other things, the treatment of income tax matters for periods through February 28, 2001, the date of the spin-off, and responsibility for any adjustments as a result of audits by any taxing authority. The general terms provide for the indemnification for any tax detriment incurred by one party caused by the other party’s action. In accordance with the agreement, RPC transferred approximately $19,000 in 2004 to Marine Products for tax settlements.

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 $1,248,000 in 2006, $926,000 in 2005 and $529,000 in 2004.

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 to $70,000 in 2006, $71,000 in 2005 and $76,000 in 2004.

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:

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. There were no large recoveries in 2006, 2005 and 2004. 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 0.25 percent to 0.40 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, 2006 would have resulted in a change of approximately $0.8 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 38.1 percent in 2006, 34.0 percent in 2005, and 34.6 percent in 2004. 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, 2006, the Company estimates the range of exposure to be from $8.9 million to $11.6 million. The Company has recorded liabilities at December 31, 2006 of approximately $10.2 million which represents management’s best estimate of probable loss.

Depreciable life of assets — RPC’s net property, plant and equipment at December 31, 2006 was $262.8 million representing 55.4 percent of the Company’s consolidated assets. Depreciation and amortization expenses for the year ended December 31, 2006 were $46.7 million, or 11.0 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.

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 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 8.0 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 the Moody’s Aa long-term corporate bond yield with a yield adjustment made for the longer duration of the Company’s obligations. A lower discount rate increases the present value of benefit obligations. The Company determined a discount rate of 5.50 percent as of December 31, 2006 and 2005, compared to a discount rate of 5.75 percent in 2004.

In 2006, the change in the minimum pension liability within accumulated other comprehensive loss increased stockholders’ equity by $2.1 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 an after tax increase of approximately $0.7 million 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 an after tax decrease of approximately $0.8 million in accumulated other comprehensive loss.

The Company recognized pre-tax pension expense of $0.8 million in 2006, $1.1 million in 2005, and $1.2 million in 2004. Pension expense is anticipated to decrease by 62 percent to approximately $0.5 million in 2007. 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 of approximately $0.1 million in 2007. 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 of approximately $0.1 million in 2006.

New Accounting Standards

In February 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140”, to permit fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation in accordance with the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” This statement is effective for fiscal years beginning after September 15, 2006. Accordingly, the Company will adopt SFAS No. 155 in fiscal year 2007. The adoption of this Statement is not expected to have a material effect on the Company’s consolidated operating results and financial condition.

In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets—an amendment of FASB Statement No. 140,” that provides guidance on accounting for separately recognized servicing assets and servicing liabilities. In accordance with the provisions of SFAS No. 156, separately recognized servicing assets and servicing liabilities must be initially measured at fair value, if practicable. Subsequent to initial recognition, the Company may use either the amortization method or the fair value measurement method to account for servicing assets and servicing liabilities within the scope of this Statement. This statement will be effective for the fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company will adopt SFAS No. 156 in fiscal year 2008. The adoption of this Statement is not expected to have a material effect on the Company’s consolidated results of operations and financial condition.

In June 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement 109” (“FIN 48”). FIN 48 prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. This interpretation is effective for fiscal years beginning after December 15, 2006. The Company is currently evaluating the impact of applying the provisions of FIN 48.

In June 2006, the FASB ratified a consensus opinion reached by the Emerging Issues Task Force (“EITF”) on EITF Issue 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation).” The guidance in EITF Issue 06-3 requires disclosure in interim and annual financial statements of the amount of taxes on a gross basis, if significant, that are assessed by a governmental authority that are imposed on and concurrent with a specific revenue producing transaction between a seller and customer such as sales, use, value added, and some excise taxes. Additionally, the income statement presentation (gross or net) of such taxes is an accounting policy decision that must be disclosed. The consensus in EITF Issue 06-3 is effective for interim and annual reporting periods beginning after December 15, 2006. The Company intends to adopt EITF Issue 06-3 effective January 1, 2007, and does not believe that the adoption will have a significant effect on its financial statements as it does not intend to change its existing accounting policy which is to present taxes within the scope of EITF Issue 06-3 on a net basis.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” that provides guidance for using fair value to measure assets and liabilities. Under SFAS No. 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the

reporting entity transacts business. SFAS No. 157 establishes a fair value hierarchy that prioritizes the information used to develop the assumptions that market participants would use when pricing the asset or liability. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. In addition, SFAS 157 requires that fair value measurements be separately disclosed by level within the fair value hierarchy. This standard will be effective for financial statements issued for fiscal periods beginning after November 15, 2007 and interim periods within those fiscal years. The Company is currently evaluating the impact of applying the various provisions of SFAS 157.

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). This Statement improves financial reporting by requiring an employer to recognize the over-funded or under-funded status of a defined benefit pension plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. This Statement also requires the Company to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. The requirement to recognize the funded status of a benefit plan and the disclosure requirements are effective as of the fiscal year ending after December 15, 2006. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. Effective December 31, 2006, the Company has adopted the recognition provisions of SFAS 158 which did not result in a material impact to its consolidated results of operations and financial condition. The Company currently measures the plan assets and benefit obligations as of its fiscal year-end and therefore adoption of the measurement provisions will not have an affect on its consolidated results of operation and financial condition. See Note 10 to the consolidated financial statements for further information.

In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (‘SAB”) 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”. SAB 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. The SEC staff believes that registrants should quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. The guidance in SAB 108 must be applied to annual financial statements for fiscal years ending after November 15, 2006. The Company has adopted SAB 108 which did not result in a material impact to its consolidated results of operations and financial condition.

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, 2006, there are outstanding interest-bearing advances of $35.6 million on our credit facility which bear interest at a floating rate. A change in the interest rate of one percent on the balance outstanding at December 31, 2006 would cause a change of $360,000 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.

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, 2006 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, 2006.

The independent registered public accounting firm, Grant Thornton LLP, has audited the consolidated financial statements as of and for the year ended December 31, 2006, and has also issued their report on management’s assessment 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

February 27, 2007

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

Board of Directors and Stockholders of RPC, Inc.

We have audited management’s assessment included in Management’s Report on Internal Control Over Financial Reporting included in RPC, Inc.’s Form 10-K for 2006, that RPC, Inc. (a Delaware Corporation) and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2006 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, 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, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the COSO. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the COSO.

We have also 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, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006 and our report dated February 27, 2007 expressed an unqualified opinion on those consolidated financial statements.

Atlanta, Georgia

February 27, 2007

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements

Board of Directors and Stockholders of RPC, Inc.

We have audited the accompanying consolidated balance sheets of RPC, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the 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, 2006 and 2005, and the consolidated results of its operations and its consolidated cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

Our audits were conducted for the purpose of forming an opinion on the basic consolidated financial statements taken as a whole. Schedule II, as listed in the Index, is presented for purposes of additional analysis and is not a required part of the basic consolidated financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic consolidated financial statements taken as a whole.

As described in Note 1 to the consolidated financial statements, the Company adopted the recognition provisions of Statement of Financial Accounting Standards 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 also 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 effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, 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 February 27, 2007 expressed an unqualified opinion.

Atlanta, Georgia

February 27, 2007

Item 8. Financial Statements and Supplementary Data

CONSOLIDATED BALANCE SHEETS

RPC, INC. AND SUBSIDIARIES

(in thousands except share information)

December 31,	2006			2005
ASSETS
Cash and cash equivalents	$	2,729		$	12,809
Accounts receivable, net		148,469			107,428
Inventories		21,188			13,298
Deferred income taxes		4,384			5,304
Income taxes receivable		239			—
Prepaid expenses and other current assets		5,245			4,004
Current assets		182,254			142,843
Property, plant and equipment, net		262,797			141,218
Goodwill		24,093			24,093
Other assets		5,163			3,631
Total assets	$	474,307		$	311,785
LIABILITIES AND STOCKHOLDERS’ EQUITY
LIABILITIES
Accounts payable	$	50,568		$	30,437
Accrued payroll and related expenses		13,289			9,576
Accrued insurance expenses		3,327			3,695
Accrued state, local and other taxes		3,314			2,585
Income taxes payable		—			791
Other accrued expenses		454			544
Current liabilities		70,952			47,628
Long-term accrued insurance expenses		6,892			6,168
Notes payable to banks		35,600			—
Long-term pension liabilities		9,185			13,614
Deferred income taxes		12,073			8,758
Other long-term liabilities		4,318			3,116
Total liabilities		139,020			79,284
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, 97,213,668 and 96,678,759 shares issued and outstanding in 2006 and 2005, respectively		9,721			9,668
Capital in excess of par value		13,595			16,012
Deferred compensation		—			(5,391	)
Retained earnings		317,705			219,907
Accumulated other comprehensive loss		(5,734	)		(7,695	)
Total stockholders’ equity		335,287			232,501
Total liabilities and stockholders’ equity	$	474,307		$	311,785

The accompanying notes are an integral part of these statements.

CONSOLIDATED STATEMENTS OF OPERATIONS

RPC, INC. AND SUBSIDIARIES

(in thousands except per share data)

Years ended December 31,	2006			2005			2004
REVENUES	$	596,630		$	427,643		$	339,792
COSTS AND EXPENSES:
Cost of services rendered and goods sold		287,037			227,492			193,659
Selling, general and administrative expenses		91,051			75,478			65,871
Depreciation and amortization		46,711			39,129			34,473
Gain on disposition of assets, net		(5,969	)		(12,169	)		(5,551	)
Operating profit		177,800			97,713			51,340
Interest expense		(418	)		(127	)		(311	)
Interest income		381			1,077			243
Other income, net		1,085			2,077			1,931
Income before income taxes		178,848			100,740			53,203
Income tax provision		68,054			34,256			18,430
Net income	$	110,794		$	66,484		$	34,773
EARNINGS PER SHARE
Basic	$	1.16		$	0.70		$	0.36
Diluted	$	1.13		$	0.67		$	0.36
Dividends paid per share	$	0.133		$	0.071		$	0.036

The accompanying notes are an integral part of these statements.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

RPC, INC. AND SUBSIDIARIES

(in thousands)

Three Years Ended	Comprehensive			Common Stock						Capital in Excess of Par			Deferred			Retained			Accumulated Other Comprehensive
December 31, 2006	Income (Loss)			Shares			Amount			Value			Compensation			Earnings			Loss			Total
Balance, December 31, 2003					64,409		$	6,441		$	23,217		$	(1,076	)	$	128,824		$	(6,300	)	$	151,106
Stock issued for stock incentive plans, net					354			36			4,074			(3,087	)		—			—			1,023
Stock purchased and retired					(170	)		(17	)		(2,312	)		—			—			—			(2,329	)
Net income	$	34,773			—			—			—			—			34,773			—			34,773
Minimum pension liability, net of taxes		(605	)		—			—			—			—			—			(605	)		(605	)
Unrealized gain on securities, net of taxes		19			—			—			—			—			—			19			19
Comprehensive income	$	34,187
Dividends declared					—			—			—			—			(3,408	)		—			(3,408	)
Stock-based compensation					—			—			—			636			—			—			636
Excess tax benefits for share-based payments					—			—			208			—			—			—			208
Three-for-two stock split					32,641			3,263			(3,263	)		—			—			—			—
Balance, December 31, 2004					97,234			9,723			21,924			(3,527	)		160,189			(6,886	)		181,423
Stock issued for stock incentive plans, net					417			42			5,344			(3,125	)		—			—			2,261
Stock purchased and retired					(739	)		(74	)		(11,332	)		—			—			—			(11,406	)
Net income	$	66,484			—			—			—			—			66,484			—			66,484
Minimum pension liability, net of taxes		(987	)		—			—			—			—			—			(987	)		(987	)
Unrealized gain on securities, net of taxes		178			—			—			—			—			—			178			178
Comprehensive income	$	65,675
Dividends declared					—			—			—			—			(6,766	)		—			(6,766	)
Stock-based compensation					—			—			—			1,261			—			—			1,261
Excess tax benefits for share-based payments					—			—			53			—			—			—			53
Three-for-two stock split					(234	)		(23	)		23			—			—			—			—
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) See Note 10					—			—			(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

The accompanying notes are an integral part of these statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS

RPC, Inc. and Subsidiaries

(in thousands)

Years ended December 31,	2006			2005			2004
OPERATING ACTIVITIES
Net income	$	110,794		$	66,484		$	34,773
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		46,726			39,129			34,418
Stock-based compensation		2,384			1,261			636
Gain on disposition of assets, net		(5,969	)		(12,169	)		(5,551	)
Deferred income tax provision (benefit)		2,817			(1,851	)		(756	)
Excess tax benefits from share based-payments		(1,325	)		—			—
Changes in current assets and liabilities:
Accounts receivable		(41,093	)		(31,635	)		(22,074	)
Income taxes receivable		1,086			—			4,472
Inventories		(7,886	)		(2,445	)		(530	)
Prepaid expenses and other current assets		(1,463	)		(81	)		41
Accounts payable		8,958			7,048			3,786
Income taxes payable		(791	)		796			113
Accrued payroll and related expenses		3,713			(49	)		2,316
Accrued insurance expenses		(368	)		(180	)		1,023
Accrued state, local and other taxes		729			402			520
Other accrued expenses		(90	)		(381	)		391
Changes in working capital		(37,205	)		(26,525	)		(9,942	)
Changes in other assets and liabilities:
Pension liabilities		(802	)		643			(2,568	)
Accrued insurance expenses		724			(283	)		595
Other non-current assets		(1,118	)		(871	)		(875	)
Other non-current liabilities		1,202			544			(356	)
Net cash provided by operating activities		118,228			66,362			50,374
INVESTING ACTIVITIES
Capital expenditures		(159,831	)		(72,808	)		(49,869	)
Purchase of businesses		—			(8,836	)		(3,310	)
Proceeds from sale of assets		8,746			19,229			15,964
Net cash used for investing activities		(151,085	)		(62,415	)		(37,215	)
FINANCING ACTIVITIES
Payment of dividends		(12,996	)		(6,766	)		(3,408	)
Borrowings from notes payable to banks		115,171			—			—
Repayments of notes payable to banks		(79,571	)		—			—