Edgar Filing: RPC INC

t72617_10k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)
x	Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

o	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2011

Commission File No. 1-8726

RPC, INC.

Delaware

(State of Incorporation)

58-1550825

(I.R.S. Employer Identification No.)

2801 BUFORD HIGHWAY, SUITE 520

ATLANTA, GEORGIA 30329

(404) 321-2140

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

Title of each class

COMMON STOCK, $0.10 PAR VALUE

Name of each exchange on which registered

NEW YORK STOCK EXCHANGE

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. x Yes o 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 whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

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

The aggregate market value of RPC, Inc. Common Stock held by non-affiliates on June 30, 2011, the last business day of the registrant’s most recently completed second fiscal quarter, was $1,050,367,129 based on the closing price on the New York Stock Exchange on June 30, 2011 of $24.54 per share.

RPC, Inc. had 146,333,777 shares of Common Stock outstanding as of February 17, 2012.

Documents Incorporated by Reference

Portions of the Proxy Statement for the 2012 Annual Meeting of Stockholders of RPC, Inc. are incorporated by reference into Part III, Items 10 through 14 of this report.

PART I

Throughout this report, we refer to RPC, Inc., together with its subsidiaries, as “we,” “us,” “RPC” or “the Company.”

Forward-Looking Statements

Certain statements made in this report that are not historical facts are “forward-looking statements” under the Private Securities Litigation Reform Act of 1995. Such forward-looking statements may include, without limitation, statements that relate to our business strategy, plans and objectives, and our beliefs and expectations regarding future demand for our products and services and other events and conditions that may influence the oilfield services market and our performance in the future. Forward-looking statements made elsewhere in this report include without limitation statements regarding our belief that sources of supply for various of our raw materials are adequate; our belief that the long-term prospects for our business are favorable due to the continued demand for oil and natural gas; our belief that the long-term demand outlook for natural gas is still favorable in spite of near-term price weakness; our belief that oil-directed drilling will continue to represent the majority of the total drilling rig count in the immediate future; our expectation to continue to focus on the development of international business opportunities in current and other international markets; our ability to obtain other customers in the event of a loss of our largest customers; the adequacy of our insurance coverage; the impact of lawsuits, legal proceedings and claims on our business and financial condition; our expectation to continue to pay cash dividends to the common stockholders subject to the earnings and financial condition of the Company and other relevant factors; our intention to increase our presence in areas in which drilling activity is directed towards oil; our belief that continued increases in U.S. domestic rig count during 2012 are unlikely; our belief that the trend of an increased percentage of oil-directed drilling and a decreased percentage of gas-directed drilling will continue in the near term; our belief that an increase in the supply in oilfield equipment in our markets can cause a decrease in the price we receive for our services if commodity prices and drilling activity do not also increase and that this effect may be more pronounced in the current environment; our expectation that our consolidated revenues and financial performance will improve in 2012 compared to 2011; our ability to maintain sufficient liquidity and a conservative capital structure; our belief about the amount of the contribution to the defined benefit pension plan in 2012; our ability to fund capital requirements in the future; the estimated amount of our capital expenditures and contractual obligations for future periods; estimates made with respect to our critical accounting policies; and the effect of new accounting standards.

The words “may,” “will,” “expect,” “believe,” “anticipate,” “project,” “estimate,” and similar expressions generally identify forward-looking statements. Such statements are based on certain assumptions and analyses made by our management in light of its experience and its perception of historical trends, current conditions, expected future developments and other factors it believes to be appropriate. We caution you that such statements are only predictions and not guarantees of future performance and that actual results, developments and business decisions may differ from those envisioned by the forward-looking statements. See “Risk Factors” contained in Item 1A. for a discussion of factors that may cause actual results to differ from our projections.

Item 1. Business

Organization and Overview

RPC is a Delaware corporation originally organized in 1984 as a holding company for several oilfield services companies and is headquartered in Atlanta, Georgia.

RPC provides a broad range of specialized oilfield services and equipment primarily to independent and major oil and gas companies engaged in the exploration, production and development of oil and gas properties throughout the United States, including the southwest, mid-continent, Gulf of Mexico, Rocky Mountain and Appalachian regions, and in selected international markets. The services and equipment provided include, among others, (1) pressure pumping services, (2) downhole tool services (3) coiled tubing services, (4) snubbing services (also referred to as hydraulic workover services), (5) nitrogen services, (6) the rental of drill pipe and other specialized oilfield equipment, and (7) well control. RPC acts as a holding company for its operating units, Cudd Energy Services, Patterson Rental and Fishing Tools, Bronco Oilfield Services, Thru Tubing Solutions, Well Control School, and others. As of December 31, 2011, RPC had approximately 3,400 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.

During 2011, approximately two percent of RPC’s consolidated revenues were generated from offshore operations in the U.S. Gulf of Mexico. In addition, less than one percent of RPC’s consolidated revenues were generated from offshore operations in the offshore territory of New Zealand. We also estimate that 45 percent of our 2011 revenues were related to drilling and production activities for oil, and 55 percent were related to drilling and production activities for natural gas.

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, downhole tools, coiled tubing, snubbing, nitrogen, well control, wireline and fishing. The principal markets for this business segment include the United States, including the southwest, mid-continent, Gulf of Mexico, Rocky Mountain and Appalachian regions, and in selected international markets. Customers include major multi-national and independent oil and gas producers, and selected nationally owned oil companies.

Support Services include RPC’s oil and gas service lines that primarily provide equipment for customer use or services to assist customer operations. The equipment and services include drill pipe and related tools, pipe handling, pipe inspection and storage services, and oilfield training services. The demand for these services tends to be influenced primarily by customer drilling-related activity levels. The principal markets for this segment include the United States, including the Gulf of Mexico, mid-continent, Rocky Mountain and Appalachian regions and project work in selected international locations in the last three years including primarily Canada, Latin America and the Middle East. Customers primarily include domestic operations of major multi-national and independent oil and gas producers, and selected nationally owned oil companies.

Technical Services

The following is a description of the primary service lines conducted within the Technical Services business segment:

Pressure Pumping. Pressure pumping services, which accounted for approximately 55 percent of 2011 revenues, 48 percent of 2010 revenues and 38 percent of 2009 revenues are provided to customers throughout Texas and the Appalachian and other mid-continent regions of the United States. We primarily provide these services to customers in order to enhance the initial production of hydrocarbons in formations that have low permeability. 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. Fracturing is particularly important in shale formations, which have low permeability, and unconventional completion, because the formation containing hydrocarbons is not concentrated in one area and requires multiple fracturing operations. The fracturing process consists of pumping fluid gel and sometimes nitrogen into a cased well at sufficient pressure to fracture the formation at desired locations and depths. Sand, bauxite or synthetic proppant, which is often suspended in gel, is pumped into the fracture. When the pressure is released at the surface, the fluid gel returns to the well surface, but the proppant remains in the fracture, thus keeping it open so that oil and natural gas can flow through the fracture into the production tubing and ultimately the well surface. 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.

Downhole Tools. Thru Tubing Solutions (“TTS”) accounted for approximately 12 percent of 2011 revenues, 12 percent of 2010 revenues and 15 percent of 2009 revenues. TTS provides services and proprietary downhole motors, fishing tools and other specialized downhole tools and processes to operators and service companies in drilling and production operations, including casing perforation at the completion stage of an oil or gas well. The services that TTS provides are especially suited for unconventional drilling and completion activities. TTS’ experience providing reliable tool services allows it to work in a pressurized environment with virtually any coiled tubing unit or snubbing unit.

Coiled Tubing. Coiled tubing services, which accounted for approximately 11 percent of 2011 revenues, 10 percent of 2010 revenues and nine percent of 2009 revenues, involve the injection of coiled tubing into wells to perform various applications and functions for use principally in well-servicing operations and more recently to facilitate completion of horizontal wells. 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. Increasingly, coiled tubing units are also used to support completion activities in directional and horizontal wells. Such completion activities usually require multiple entrances in a wellbore in order to complete multiple fractures in a pressure pumping operation. A coiled tubing unit can accomplish this type of operation because its flexibility allows it to be steered in a direction other than vertical, which is necessary in this type of wellbore. At the same time, the strength of the coiled tubing string allows various types of tools or motors to be conveyed into the well effectively. The uses for coiled tubing in directional and horizontal wells have been enhanced by improved fabrication techniques and higher-diameter coiled tubing which allows coiled tubing units to be used effectively over greater distances, thus allowing them to function in more of the completion activities currently taking place in the U.S. domestic market. There are several manufacturers of flexible steel pipe used in coiled tubing services, and the Company believes that its sources of supply are adequate.

Snubbing. Snubbing (also referred to as hydraulic workover services), which accounted for approximately four percent of 2011 revenues, five percent of 2010 revenues and eight percent of 2009 revenues, involves using a hydraulic workover rig that permits an operator to repair damaged casing, production tubing and downhole production equipment in a high-pressure environment. A snubbing unit makes it possible to remove and replace downhole equipment while maintaining pressure on 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 relative few operators who have the experience and knowledge required to perform such services safely and efficiently. Increasingly, snubbing units are used for unconventional completions at the outer reaches of long wellbores which cannot be serviced by coiled tubing because coiled tubing has a more limited range than drill pipe conveyed by a snubbing unit.

Nitrogen. Nitrogen accounted for approximately four percent of 2011 revenues, five percent of 2010 revenues and seven percent of 2009 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. Increasingly, it is used as a displacement medium to increase production in older wells in which production has depleted. 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 Energy Services specializes in responding to and controlling oil and gas well emergencies, including blowouts and well fires, domestically and internationally. In connection with these services, Cudd Energy Services, along with Patterson Services, has the capacity to supply the equipment, expertise and personnel necessary to restore affected oil and gas wells to production. The Company has responded to well control situations in several international locations including Algeria, Argentina, Australia, Bolivia, Canada, Colombia, Egypt, Hungary, India, Kuwait, Libya, Mexico, Peru, Qatar, Taiwan, Trinidad, Turkmenistan 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 experts responds to well control situations where hydrocarbons are escaping from a well bore, regardless of whether a fire has occurred. In the most critical situations, there are explosive fires, the destruction of drilling and production facilities, substantial environmental damage and the loss of hundreds of thousands of dollars per day in well operators’ production revenue. Since these events ordinarily arise from equipment failures or human error, it is impossible to predict accurately the timing or scope of this work. Additionally, less critical events frequently occur in connection with the drilling of new wells in high-pressure reservoirs. In these situations, the Company is called upon to supervise and assist in the well control effort so that drilling operations can resume as promptly as safety permits.

Wireline Services. Wireline is classified into two types of services: slick or braided line and electric line. In both, a spooled wire is unwound and lowered into a well, conveying various types of tools or equipment. Slick or braided line services use a non-conductive line primarily for jarring objects into or out of a well, as in fishing or plug-setting operations. Electric line services lower an electrical conductor line into a well allowing the use of electrically-operated tools such as perforators, bridge plugs and logging tools. Wireline services can be an integral part of the plug and abandonment process, near the end of the life cycle of a well.

Fishing. Fishing involves the use of specialized tools and procedures to retrieve lost equipment from a well drilling operation and producing wells. It is a service required by oil and gas operators who have lost equipment in a well. Oil and natural gas production from an affected well typically declines until the lost equipment can be retrieved. In some cases, the Company creates customized tools to perform a fishing operation. The customized tools are maintained by the Company after the particular fishing job for future use if a similar need arises.

Support Services

The following is a description of the primary service lines conducted within the Support Services business segment:

Rental Tools. Rental tools accounted for approximately six percent of 2011 revenues, eight percent of 2010 revenues and eight percent of 2009 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, Appalachian region and the 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	Wear KnotTM Drill Pipe

Oilfield Pipe Inspection Services, Pipe Management and Pipe Storage. Pipe inspection services include Full Body Electromagnetic and Phased Array Ultrasonic inspection of pipe used in oil and gas wells. These services are provided at both the Company’s inspection facilities and at independent tubular mills in accordance with negotiated sales and/or service contracts. Our customers are major oil companies and steel mills, for which we provide in-house inspection services, inventory management and process control of tubing, casing and drill pipe. Our locations in Channelview, Texas and Morgan City, Louisiana are equipped with large capacity cranes, specially designed forklifts and a computerized inventory system to serve a variety of storage and handling services for both 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 limited international locations. Well Control School provides training in various formats including conventional classroom training, interactive computer training including training delivered over the internet, and mobile simulator training.

Energy Personnel International. Energy Personnel International provides drilling and production engineers, well site supervisors, project management specialists, and workover and completion specialists on a consulting basis to the oil and gas industry to meet customers’ needs for staff engineering and well site 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 oil and gas production of its customers in the Gulf of Mexico, the mid-continent, the southwest, the Rocky Mountains and the Appalachian region. Demand for RPC’s services in the U.S. tends to be extremely volatile and fluctuates with current and projected price levels of oil and natural gas and activity levels in the oil and gas industry. Customer activity levels are influenced by their decisions about capital investment toward the development and production of oil and gas reserves.

Due to aging oilfields and lower-cost sources of oil internationally, the drilling rig count in the U.S. has declined by approximately 56 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. Oil and gas industry activity levels have historically been volatile, experiencing multiple up and down cycles including 1986, 1992, 1999 (with April 1999 recording the lowest U.S. drilling rig count in the industry’s history), 2002 and again in 2009.

The rig count during the peak of the most recent prior cycle occurred at the end of the third quarter of 2008, and began to decline sharply during the fourth quarter of 2008. U.S. domestic drilling activity declined by 57 percent from the third quarter of 2008 to the second quarter of 2009, which was the steepest annualized decline rate in the industry’s history. Between the second quarter of 2009 and the end of 2011, U.S. domestic drilling activity increased by 129 percent, and is approximately equal to the prior cyclical peak in the third quarter of 2008. As of a recent date in 2012, U.S. domestic drilling activity is approximately equal to the fourth quarter of 2011 although the industry is experiencing shifts in activity from gas-directed plays to oil and more liquids rich plays.

The increase in domestic drilling activity to a level equal to the prior cyclical peak is consistent with the recovery in the prices of oil and natural gas, the overall economic recovery following the recession in 2008 and 2009, and the high financial returns from drilling in unconventional shale plays during the past several years. During 2011 the average price of natural gas decreased by approximately 33 percent, while the average price of oil increased by approximately 12 percent. The increase in the price of oil has increased the attractiveness of drilling for oil and petroleum liquids in several unconventional basins in the U.S. domestic market. The growth in this type of drilling activity is the sole cause of the increase in overall drilling activity that occurred during 2011. Although our market has repeatedly demonstrated that it is cyclical, and the price of natural gas has recently declined to the lowest level in approximately 10 years, we continue to believe in the long-term growth opportunities for our business due to the continued high demand for oil and natural gas. Furthermore, we note that the techniques used to extract oil and natural gas in the U.S. domestic market increasingly require the types of services that RPC provides to its customers.

From 2001 to 2009, gas drilling rigs on average represented over 80 percent of the drilling rig count. In 2010, the percentage of drilling rigs drilling for natural gas began to decline, and by the end of 2011 represented approximately 40 percent of total drilling activity. Although the demand for natural gas has remained stable, the price of natural gas has remained low in recent years due to increased domestic reserves and productivity of new wells. The price of natural gas has continued to fall during the first quarter of 2012 due to an unseasonably warm winter in the United States. In contrast, the price of oil has increased, and producers in the domestic market have started to exploit new resource plays that are economical at current high oil prices. The long-term demand outlook for natural gas is still favorable because, unlike oil, foreign imports of natural gas do not compete with domestic production to a meaningful degree. This lack of foreign competition tends to keep prices high enough to ensure that domestic drilling and production will continue at certain minimum levels. Because of the unseasonably warm winter in 2012, the high price of oil, and the new opportunities to drill for oil in the United States, we anticipate that oil-directed drilling will continue to represent the majority of the total drilling rig count for the immediate future.

There are certain types of 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 wells are more difficult and costly to complete. These wells have become an increasingly large percentage of the U.S. domestic market, and since the third quarter of 2008, have consistently comprised the majority of U.S. domestic drilling. These wells have predominantly been natural gas wells, although a growing percentage are being drilled for heavier petroleum liquids and oil as well. Because they are drilled through a narrow formation and the formation is typically a relatively impermeable formation such as shale, they require additional stimulation when they are completed. Also, many of these formations require high pumping rates of stimulation fluids under high pressures, which in turn means that there is a great deal of pressure pumping horsepower required to complete the well. Furthermore, 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.

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. RPC’s equipment investments over the last couple of years have emphasized domestic rather than international expansion because of higher expected financial returns. International revenues for 2011 decreased due to lower customer activity levels in Colombia, New Zealand and Qatar, and accounted for approximately three percent of consolidated RPC revenues. International revenues increased in Canada, Mexico and Saudi Arabia. During 2011, RPC provided snubbing, well control and oilfield training services in New Zealand, Gabon, and Saudi Arabia, among other countries. We also provided rental tools in Canada, Mexico, Oman and Tunisia. We continue to focus on the selective 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. This objective continues to be pursued through strategic investments and opportunities designed to enhance the long-term value of RPC while improving market share, product offerings and the profitability of existing businesses. Growth strategies are focused on selected customers and markets in which we believe there exist opportunities for higher growth, customer and 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 and on potential large customers who have a long-term need for our services in markets in which we operate.

RPC seeks to expand its service capabilities through a combination of internal growth, acquisitions, joint ventures and strategic alliances. Because of the fragmented nature of the oil and gas services industry, RPC believes a number of attractive acquisition opportunities exist. However, current strong business conditions have encouraged potential sellers of businesses to expect high prices for their businesses, so we believe we generate better returns on investments growing organically in service lines and geographic locations in which we have experience and presence.

RPC has a revolving credit facility to fund the purchase of revenue-producing equipment and other working capital requirements. At December 31, 2011, this facility had a remaining term of almost four years. We have pursued this capital source because of the high returns on investment that have been generated by many of our service lines during the previous several years, and because of the low cost and ready availability of debt capital. During 2010 and 2011, we increased our purchases of revenue-producing equipment to support industry growth and significant customer agreements. Despite increased capital expenditures and working capital requirements during 2011, as well as large purchases of scarce raw materials in the fourth quarter of 2011, at the end of the year our level of debt was conservative compared to a number of our peers.

Customers

Demand for RPC’s services and products depends primarily upon the number of oil and natural gas wells being drilled, the depth and drilling conditions of such wells, the number of well completions and the level of production enhancement activity worldwide. RPC’s principal customers consist of major and independent oil and natural gas producing companies. During 2011, RPC provided oilfield services to several hundred customers. Of these customers, only one, Chesapeake Energy Corporation at approximately 12 percent of revenues, accounted for more than 10 percent of revenues. RPC believes that its relationship with this customer is good. Although the Company believes that we would be able to obtain other customers for our services in the event of the loss of this major customer, the loss of this customer could have a material adverse effect on Company revenues and operating results in the near term.

Sales are generated by RPC’s sales force and through referrals from existing customers. Over the past two years we have entered into several agreements, with terms beyond one year, to provide services to certain domestic customers. These agreements represent a growing percentage of our revenues, and we monitor closely the financial condition of these customers, their capital expenditure plans, and other indications of their drilling and completion activities. 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. Recent strong oilfield activity and the availability of capital have encouraged several new, smaller companies to seek debt and equity capital and accelerate their growth rates. Several of these competitors have filed registration statements to sell equity securities in initial public offerings, which further increases their access to capital markets. RPC believes that the principal competitive factors in the market areas that it serves are product availability and quality of our equipment service, 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, Baker Hughes and Schlumberger Ltd., and a significant number of locally oriented businesses.

Facilities/Equipment

RPC’s equipment consists primarily of oil and gas services equipment used either in servicing customer wells or provided on a rental basis for customer use. Substantially all of this equipment is Company owned. RPC purchases oilfield service equipment from a limited number of manufacturers. These manufacturers of our oilfield service equipment may not be able to meet our requests for timely delivery during periods of high demand which may result in delayed deliveries of equipment and higher prices for equipment.

RPC both owns and leases regional and district facilities from which its oilfield services are provided to land-based and offshore customers. RPC’s principal executive offices in Atlanta, Georgia are leased. The Company owns two primary administrative buildings, one in Houston, Texas that includes the Company’s operations, engineering, sales and marketing headquarters, and one in Houma, Louisiana that includes certain administrative functions. RPC believes that its facilities are adequate for its current operations. For additional information with respect to RPC’s lease commitments, see Note 9 of the Notes to Consolidated Financial Statements.

Governmental Regulation

RPC’s business is affected by state, federal and foreign laws and other regulations relating to the oil and gas industry, as well as laws and regulations relating to worker safety and environmental protection. RPC cannot predict the level of enforcement of existing laws and regulations or how such laws and regulations may be interpreted by enforcement agencies or court rulings, whether additional laws and regulations will be adopted, or the effect such changes may have on it, its businesses or financial condition.

In addition, our customers are affected by laws and regulations relating to the exploration for and production of natural resources such as oil and natural gas. These regulations are subject to change, and new regulations may curtail or eliminate our customers’ activities in certain areas where we currently operate. We cannot determine the extent to which new legislation may impact our customers’ activity levels, and ultimately, the demand for our services.

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.

Item 1A. Risk Factors

Demand for our products and services is affected by the volatility of oil and natural gas prices.

Oil and natural gas prices affect demand throughout the oil and 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.

We are becoming increasingly reliant on a few large customers and long-term contractual relationships, the loss of any of which may adversely affect our revenues and profits.

Over the past several years, the U.S. domestic oilfield services market has come to be dominated by unconventional shale resource plays. A number of our large customers in these resource plays have entered into multi-year contractual relationships with us to provide services that enable them to operate more efficiently in these plays. If we do not perform adequately under the terms of these relationships, or if our customers decide to terminate these relationships, our revenues and profits may be adversely affected. At the end of the terms of these relationships, we may not be able to renew them on favorable terms, or may not be able to renew them at all. In any of these cases, our future revenues and profits may be adversely affected.

We may be unable to compete in the highly competitive oil and gas industry in the future.

We operate in highly competitive areas of the oilfield services industry. The products and services in our industry segments are sold in highly competitive markets, and our revenues and earnings have in the past been affected by changes in competitive prices, fluctuations in the level of activity in major markets and general economic conditions. We compete with the oil and gas industry’s many large and small industry competitors, including the largest integrated oilfield service providers. We believe that the principal competitive factors in the market areas that we serve are product and service quality and availability, reputation for safety, technical proficiency and price. Although we believe that our reputation for safety and quality service is good, we cannot assure you that we will be able to maintain our competitive position.

We may be unable to identify or complete acquisitions.

Acquisitions have been and may continue to be a key element of our business strategy. We cannot assure you that we will be able to identify and acquire acceptable acquisition candidates on terms favorable to us in the future. We may be required to incur substantial indebtedness to finance future acquisitions and also may issue equity securities in connection with such acquisitions. The issuance of additional equity securities could result in significant dilution to our stockholders. We cannot assure you that we will be able to integrate successfully the operations and assets of any acquired business with our own business. Any inability on our part to integrate and manage the growth from acquired businesses could have a material adverse effect on our results of operations and financial condition.

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, the Rocky Mountains and the Appalachian region. 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 ability to attract and retain skilled workers may impact growth potential and profitability.

Our ability to be 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. A significant increase in the wages paid by competing employers could result in a reduction in our skilled labor force, increases in the wage rates paid by us, or both. If either of these events occurred, our capacity and profitability could be diminished, and our growth potential could be impaired.

Our concentration of customers in one industry may impact our overall exposure to credit risk.

Substantially all of our customers operate in the energy industry. This concentration of customers in one industry may impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. We perform ongoing credit evaluations of our customers and do not generally require collateral in support of our trade receivables.

Reliance upon a large customer may adversely affect our revenues and operating results.

During 2011, one of our largest customers accounted for approximately 12 percent of our total revenues. This reliance on a large customer for a significant portion of our total revenues exposes us to the risk that the loss or reduction in revenues from this customer, which could occur unexpectedly, could have a material and disproportionate adverse impact upon our revenues and operating results.

Our business has potential liability for litigation, personal injury and property damage claims assessments.

RPC’s subsidiaries have a number of agreements of various types in place with our customers. In general, these agreements indemnify RPC and its subsidiaries against damage or liabilities that arise from the actions of our employees or the operation of our equipment. The provisions in these agreements do not make a distinction among the types of services that RPC provides or the location of the work. These agreements also require that RPC maintain a certain level and type of insurance coverage against any claims that are determined to be our responsibility. RPC has insurance coverage in place with several well-capitalized insurance companies for accidental environmental claims.

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, the Middle East and New Zealand are subject to risks. These risks include, but are not limited to, political changes, expropriation, currency restrictions and changes in currency exchange rates, taxes, boycotts and other civil disturbances. The occurrence of any one of these events could have a material adverse effect on our operations.

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 stockholders may have no effective voice in the management of the Company.

The Company has elected the “Controlled Corporation” exemption under Rule 303A of the New York Stock Exchange (“NYSE”) Company Guide. The Company is a “Controlled Corporation” because a group that includes the Company’s Chairman of the Board, R. Randall Rollins and his brother, Gary W. Rollins, who is also a director of the Company, and certain companies under their control, controls in excess of fifty percent of the Company’s voting power. As a “Controlled Corporation,” the Company need not comply with certain NYSE rules including those requiring a majority of independent directors.

RPC’s executive officers, directors and their affiliates hold directly or through indirect beneficial ownership, in the aggregate, approximately 71 percent of RPC’s outstanding shares of common stock. As a result, these stockholders effectively control the operations of RPC, including the election of directors and approval of significant corporate transactions such as acquisitions and other matters requiring stockholder approval. This concentration of ownership could also have the effect of delaying or preventing a third party from acquiring control over the Company at a premium.

Our management has a substantial ownership interest, and the availability of the Company’s common stock to the investing public may be limited.

The availability of RPC’s common stock to the investing public may be limited to those shares not held by the executive officers, directors and their affiliates, which could negatively impact RPC’s stock trading prices and affect the ability of minority stockholders to sell their shares. Future sales by executive officers, directors and their affiliates of all or a portion of their shares could also negatively affect the trading price of our common stock.

Provisions in RPC’s Certificate of Incorporation and Bylaws may inhibit a takeover of RPC.

RPC’s certificate of incorporation, bylaws and other documents contain provisions including advance notice requirements for stockholder proposals and staggered terms for the Board of Directors. These provisions may make a tender offer, change in control or takeover attempt that is opposed by RPC’s Board of Directors more difficult or expensive.

Some of our equipment and several types of materials used in providing our services are available from a limited number of suppliers.

We purchase equipment provided by a limited number of manufacturers who specialize in oilfield service equipment. During periods of high demand, these manufacturers may not be able to meet our requests for timely delivery, resulting in delayed deliveries of equipment and higher prices for equipment. There are a limited number of suppliers for certain materials used in pressure pumping services, our largest service line. While these materials are generally available, supply disruptions can occur due to factors beyond our control. Such disruptions, delayed deliveries, and higher prices can limit our ability to provide services, or increase the costs of providing services, thus reducing our revenues and profits.

We have used outside financing to accomplish our growth strategy, and outside financing may become unavailable or may be unfavorable to us.

Our business requires a great deal of capital in order to maintain our equipment and increase our fleet of equipment to expand our operations, and we have access to our $350 million credit facility to fund our necessary working capital and equipment requirements. Most of our existing credit facility bears interest at a floating rate, which exposes us to market risks as interest rates rise. If our existing capital resources become unavailable, inadequate or unfavorable for purposes of funding our capital requirements, we would need to raise additional funds through alternative debt or equity financings to maintain our equipment and continue our growth. Such additional financing sources may not be available when we need them, or may not be available on favorable terms. If we fund our growth through the issuance of public equity, the holdings of stockholders 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 100 offices and operating facilities. The Company leases approximately 17,000 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. Descriptions of the major facilities used in our operations are as follows:

Owned Locations

Conway, Arkansas — Operations, sales and equipment storage yards

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

Houma, Louisiana — Administrative office

Houston, Texas — Pipe storage terminal and inspection sheds

Houston, Texas — Operations, sales and administrative office

Kilgore, Texas — Pumping services facility

Lafayette, Louisiana — Operations, sales and equipment storage yards

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

Leased Locations

Canton, Pennsylvania — Pumping services facility

Houston, Texas — Operations, sales and administrative office

Odessa, Texas — Operations, sales and equipment storage yards

Oklahoma City, Oklahoma — Operations, sales and administrative office

Seminole, Oklahoma — Pumping services facility

Washington, Pennsylvania — 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. Mine Safety Disclosures.

Not Applicable.

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)	80	1/24/84
Chairman of the Board

Richard A. Hubbell (2)	67	4/22/03
President and Chief Executive Officer

Linda H. Graham (3)	75	1/27/87
Vice President and Secretary

Ben M. Palmer (4)	51	7/8/96
Vice President, Chief Financial Officer and Treasurer

(1)

R. Randall Rollins began working for Rollins, Inc. (consumer services) in 1949. Mr. Rollins has served as Chairman of the Board of RPC since the spin-off of RPC from Rollins, Inc. in 1984. He has served as Chairman of the Board of Marine Products Corporation (boat manufacturing) since it was spun off from RPC in 2001 and Chairman of the Board of Rollins, Inc. since October 1991. He is also a director of Dover Downs Gaming and Entertainment, Inc. and Dover Motorsports, Inc.

(2)

Richard A. Hubbell has been the President of RPC since 1987 and Chief Executive Officer since 2003. He has also been the President and Chief Executive Officer of Marine Products Corporation since it was spun off from RPC in February 2001. Mr. Hubbell serves on the Board of Directors for both of these companies.

(3)	Linda H. Graham has been the Vice President and Secretary of RPC since 1987. She has also been the Vice President and Secretary of Marine Products Corporation since it was spun off from RPC in 2001. Ms. Graham serves on the Board of Directors for both of these companies.

(4)	Ben M. Palmer has been the Vice President, Chief Financial Officer and Treasurer of RPC since 1996. He has also been the Vice President, Chief Financial Officer and Treasurer of Marine Products Corporation since it was spun off from RPC in 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. At February 17, 2012 there were 146,333,777 shares of common stock outstanding and approximately 8,788 beneficial holders 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, 2011 and 2010:

	2011						2010
Quarter	High		Low		Dividends		High		Low		Dividends
First	$	25.73	$	15.83	$	0.07	$	9.00	$	7.07	$	0.027
Second		29.05		19.82		0.07		10.00		6.61		0.027
Third		27.31		17.29		0.08		14.47		8.69		0.040
Fourth		22.32		14.21		0.10		22.53		13.64		0.047

On January 24, 2012 RPC’s Board of Directors declared a three-for-two stock split of the Company’s common shares. The split will be effected by issuing an additional share of common stock for every two shares of common stock held. The additional shares will be distributed on March 9, 2012 to stockholders of record on February 10, 2012. The stock split will increase the Company’s outstanding shares from approximately 146,333,777 shares to 219,500,666 shares. Our historical outstanding shares will be recast upon the distribution. Additionally, the Board of Directors approved a $0.12 per share cash dividend, payable March 9, 2012 to stockholders of record at the close of business on February 10, 2012. 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 2011 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, 2011 to October 31, 2011		-	$	-		-		3,400,521
November 1, 2011 to November 30, 2011		696,455		18.89		696,455		2,704,066
December 1, 2011 to December 31, 2011		140,000		17.20		140,000		2,564,066
Totals		836,455	$	18.60		836,455		2,564,066

The Company’s Board of Directors announced a stock buyback program in March 1998 authorizing the repurchase of 17,718,750 shares in the open market. There were 836,455 shares repurchased as part of this program during the fourth quarter of 2011. 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 1000 Index (“Russell 1000”), 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 Company was a component of the Russell 1000 during 2011. The Russell 1000 is a stock index representing large capitalization U.S. stocks with high historical growth in revenues and earnings. The components of the index had a weighted average market capitalization in 2011 of $97.5 billion, and a median market capitalization of $5.6 billion. The Russell 1000 was chosen because it represents companies with comparable market capitalizations to the Company, and because the Company is a component of the index. The performance of the Russell 2000 Index (“Russell 2000”) is also included in the following graph because the Company was previously a component of the Russell 2000 and the performance of the Russell 2000 was formerly included in the following graph. The OSX is a stock index of 15 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 this index 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., Basic Energy Services, Inc., 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,	2011			2010			2009			2008			2007
	(in thousands, except employee and per share amounts)
Revenues	$	1,809,807		$	1,096,384		$	587,863		$	876,977		$	690,226
Cost of revenues		992,704			606,098			393,806			503,631			368,175
Selling, general and administrative expenses		151,286			121,839			97,672			117,140			107,800
Depreciation and amortization		179,905			133,360			130,580			118,403			78,506
Loss (gain) on disposition of assets, net		3,831			(3,758	)		(1,143	)		(6,367	)		(6,293	)
Operating profit (loss)		482,081			238,845			(33,052	)		144,170			142,038
Interest expense		(3,453	)		(2,662	)		(2,176	)		(5,282	)		(4,179	)
Interest income		18			46			147			73			70
Other income (expense), net		169			1,303			1,582			(1,176	)		1,905
Income (loss) before income taxes		478,815			237,532			(33,499	)		137,785			139,834
Income tax provision (benefit)		182,434			90,790			(10,754	)		54,382			52,785
Net income (loss)	$	296,381		$	146,742		$	(22,745	)	$	83,403		$	87,049
Earnings (loss) per share :
Basic	$	2.04		$	1.01		$	(0.16	)	$	0.57		$	0.60
Diluted	$	2.02		$	1.00		$	(0.16	)	$	0.57		$	0.59
Dividends paid per share	$	0.320		$	0.141		$	0.148		$	0.160		$	0.133
OTHER DATA:
Operating margin percent		26.6	%		21.8	%		(5.6	)%		16.4	%		20.6	%
Net cash provided by operating activities	$	386,007		$	168,657		$	168,740		$	177,320		$	141,872
Net cash used for investing activities		(391,637	)		(171,769	)		(61,144	)		(158,953	)		(239,624	)
Net cash provided by (used for) financing activities		3,988			7,658			(106,144	)		(21,668	)		101,361
Depreciation and amortization		179,905			133,360			130,580			118,403			78,506
Capital expenditures	$	416,400		$	187,486		$	67,830		$	170,318		$	248,758
Employees at end of period		3,400			2,500			1,980			2,532			2,370
BALANCE SHEET DATA AT END OF YEAR:
Accounts receivable, net	$	461,272		$	294,002		$	130,619		$	210,375		$	176,154
Working capital		447,089			281,174			151,681			200,494			144,338
Property, plant and equipment, net		675,360			453,017			396,222			470,115			433,126
Total assets		1,338,211			887,871			649,043			793,461			701,015
Long-term debt		203,300			121,250			90,300			174,450			156,400
Total stockholders’ equity	$	762,592		$	538,895		$	409,723		$	449,084		$	409,272

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 southwest, mid-continent, Gulf of Mexico, Rocky Mountain and Appalachian regions, and in selected international markets. 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 maintain an appropriate blend of revenues between long-term committed contractual relationships and spot market revenues. Committed contractual relationships allow us to plan our operations with more certainty and efficiency. Under spot market work, we work at prevailing market rates and can take advantage of short-term opportunities which may be more profitable under certain circumstances.

	-	To maintain high asset utilization, which leads to increased revenues and leverage of direct and overhead costs, while also ensuring that increased maintenance resulting from high utilization does not interfere with customer performance requirements or jeopardize safety.

	-	To deliver equipment and services to our customers safely.

	-	To secure adequate sources of supplies of certain high-demand raw materials used in our operations, both in order to conduct our operations and to enhance our competitive position.

	-	To maintain and selectively increase market share.

	-	To maximize stockholder return by optimizing the balance between cash invested in the Company’s productive assets, the payment of dividends to stockholders, and the repurchase of our common stock on the open market.

	-	To align the interests of our management and stockholders.

	-	To maintain an efficient, low-cost capital structure, which includes an appropriate use of debt financing.

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, maintenance and repair expenses, 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 are characterized by natural gas prices which have declined steadily during 2010 and 2011, and continue to decline during the first quarter of 2012. Average natural gas prices during the first quarter of 2012 are at their lowest level since the first quarter of 2002. This has negative implications for our industry, because almost 40 percent of U.S. domestic drilling activity during the first quarter of 2012 is directed towards the production of natural gas, and low natural gas prices discourage our customers from conducting drilling activities directed towards natural gas. Oil prices have steadily increased since the fourth quarter of 2009, and continue to increase during the first quarter of 2012. This trend has positive implications for our industry, since the majority of drilling activity in the United States is directed currently towards oil for the first time in many years. RPC has operations in most of the areas in which drilling activity is directed towards oil, and we intend to increase our presence in these areas. The average U.S. rig count increased by 22 percent during 2011. During the first quarter of 2012, the rig count was approximately 17 percent higher than the first quarter of 2011 and comparable to the fourth quarter of 2011. The rig count during the first quarter of 2012 is less than one percent lower than the peak rig count attained during the prior U.S. drilling cycle, which occurred during the third quarter of 2008. Continued increases in the U.S. domestic rig count during 2012 are unlikely due to weak natural gas prices and a limited number of rigs available to drill new wells.

In addition to the overall rig count, the Company also monitors the number of horizontal and directional wells drilled in the U.S. domestic market, because this type of well is more service-intensive than a vertical oil or gas well, thus requiring more of the Company’s services provided for a longer period of time. The number of horizontal and directional wells drilled in the United States increased in 2011, and was 70 percent of total wells drilled during the year. During the first part of 2012, the percentage of horizontal and directional wells drilled as a percentage of total wells was approximately 69 percent. In addition, the percentage of wells drilled for oil increased during 2011, and we believe that this percentage will increase in 2012 due to the continued high price of oil and the low price of natural gas. During 2011, the increase in U.S. domestic oilfield activity and the increasingly service-intensive nature of this activity caused the demand for the Company’s services to increase. This increased demand was especially evident in the Company’s service lines which are used in unconventional completion work, such as pressure pumping, coiled tubing and downhole tools. Also, due to the repetitive nature of this work and the long-term capital commitment required by our customers to execute their drilling programs, several of our large customers continued to enter into contractual relationships with us to provide services to support their drilling and completion programs in 2010 and 2011. These arrangements typically have terms that are greater than one year, and include activity commitments and some financial arrangements which allow us to plan our activities with some certainty. These arrangements also serve to supplement our financial returns to us in the event that the customer’s activities decline for any reason.

The Company’s response to the operating environment during the past several years has been to increase our fleet of equipment, and in some cases, to open new operational locations in close proximity to new resource plays, to support higher industry activity levels and significant customer relationships. The capital expenditures have been funded by cash flows from operating activities as well as borrowings under our revolving credit facility. The Company has a syndicated revolving credit facility in order to maintain sufficient liquidity to fund its capital expenditure requirements.

Income before income taxes was $478.8 million in 2011 compared to $237.5 million in the prior year. The effective tax rate for 2011 was 38.1 percent compared to 38.2 percent in the prior year. Diluted earnings per share were $2.02 in 2011 compared to $1.00 for the prior year. Cash flows from operating activities were $386.0 million in 2011 and $168.7 million in 2010 and cash and cash equivalents were $7.4 million at December 31, 2011, a decrease of $1.6 million compared to December 31, 2010. As of December 31, 2011, there was $203.3 million in outstanding borrowings under our credit facility.

Cost of revenues increased $386.7 million in 2011 compared to the prior year due to the variable nature of many of these expenses and was approximately 55 percent of revenues in 2011 and 2010.

Selling, general and administrative expenses as a percentage of revenues decreased approximately 2.7 percentage points in 2011 compared to 2010, which was due to the fixed nature of many of these expenses which we were able to leverage over higher revenues.

Consistent with our strategy to selectively grow our capacity, support our significant customer relationships and maintain our existing fleet of high demand equipment, capital expenditures increased to $416.4 million in 2011, a significant increase compared to $187.5 million last year.

Outlook

Drilling activity in the U.S. domestic oilfields, as measured by the rotary drilling rig count, reached a recent cyclical peak of 2,031 during the third quarter of 2008. The global recession that began during the fourth quarter of 2007 precipitated the steepest annualized rig count decline in U.S. domestic oilfield history. From the third quarter of 2008 to the second quarter of 2009, the U.S. domestic rig count dropped almost 57 percent, reaching a trough of 876 in June 2009. Since June 2009, the rig count has increased by 129 percent to 2,008 early in the first quarter of 2012, approximately the same rig count level as the most recent cyclical rig count peak. Unconventional drilling activity, which requires more of RPC’s services, accounted for 67 percent of total U.S. domestic drilling during 2010. Unconventional activity as a percentage of total oilfield activity has grown steadily over the past several years and was 70 percent of total wells drilled during 2011. During the first quarter of 2012, unconventional drilling activity as a percentage of total wells drilled was 69 percent. The current and projected prices of oil and natural gas are important catalysts for U.S. domestic drilling activity. The price of natural gas has declined steadily during 2010, 2011 and the first quarter of 2012. During the first quarter of 2012, the price of natural gas was the lowest it had been since the first quarter of 2002. This trend has negative implications for our near-term activity levels, since a large percentage of U.S. drilling is directed towards natural gas. On the other hand, the price of oil has risen steadily since the fourth quarter of 2009, and continues to rise during the first quarter of 2012. This is a positive development for our industry, since there are a number of significant U.S. domestic shale resource plays which produce oil and petroleum liquids, and activity in these basins has increased significantly.

The effect of these trends is evident in the current composition of the U.S. domestic rig count, approximately 60 percent of which was directed towards oil during the first quarter of 2012. We believe that the trend of an increased percentage of oil-directed drilling and a decreased percentage of gas-directed drilling will continue in the near term. We believe that this trend will continue due to the mild winter in 2012 and the increased production of natural gas, as well as continued high oil prices and increased oil-directed drilling in the recently developed shale resource plays in the U.S. domestic market. We do not believe that the overall rig count will increase significantly during 2012, however, due to a limited supply of drilling rigs and the impact of the decline in natural gas drilling.

We continue to monitor the market for our services and the competitive environment in 2012. We are encouraged by the high overall rig count and the service-intensive nature of the completion activities in our markets. However, we are also concerned about the declining price of natural gas, and the fact that the cost of completing wells is high in many unconventional shale plays, thus discouraging our customers from conducting drilling and completion activities in these areas. Also, we are concerned about the fact that many of the oil-directed wells that are being drilled in 2012 also produce a significant amount of natural gas, which increases overall supply and may depress natural gas prices. We are monitoring the competitive environment very closely, because the high financial returns in our industry continue to attract new entrants and encourage existing service companies to purchase additional revenue-producing equipment. An increased fleet of revenue-producing equipment in our industry can cause a decrease in the prices we receive for our services. This effect may be more pronounced in the current environment, as the drilling activity that our customers are curtailing is particularly service intensive, which further increases the amount of available revenue-producing equipment. We increased our equipment purchases in 2011 and will take delivery of some of the equipment in the first and second quarters of 2012. This is consistent with our business and financial strategies because we believe that the equipment will produce high financial returns. However, we are concerned about the current market for our services and anticipate that our equipment purchases will be lower in 2012 than in 2011. Our consistent response to the industry’s potential uncertainty is to maintain sufficient liquidity and a conservative capital structure and monitor our discretionary spending. Although we used our bank credit facility to finance our expansion, we will still maintain a conservative financial structure by industry standards. Based on current industry conditions, we believe that the Company’s consolidated revenues will increase in 2012 compared to 2011 and financial performance for the same period will also improve.

Stock Split

Results of Operations

Years Ended December 31,	2011			2010			2009
(in thousands except per share amounts and industry data)
Consolidated revenues	$	1,809,807		$	1,096,384		$	587,863
Revenues by business segment:
Technical	$	1,663,793		$	979,834		$	513,289
Support		146,014			116,550			74,574

Consolidated operating profit (loss)	$	482,081		$	238,845		$	(33,052	)
Operating profit (loss) by business segment:
Technical	$	451,259		$	217,144		$	(20,328	)
Support		51,672			31,086			(1,636	)
Corporate expenses		(17,019	)		(13,143	)		(12,231	)
(Loss) gain on disposition of assets, net		(3,831	)		3,758			1,143

Net income (loss)	$	296,381		$	146,742		$	(22,745	)
Earnings (loss) per share — diluted	$	2.02		$	1.00		$	(0.16	)
Percentage of cost of revenues to revenues		55	%		55	%		67	%
Percentage of selling, general and administrative expenses to revenues		8	%		11	%		17	%
Percentage of depreciation and amortization expenses to revenues		10	%		12	%		22	%
Effective income tax rate		38.1	%		38.2	%		32.1	%
Average U.S. domestic rig count		1,877			1,543			1,089
Average natural gas price (per thousand cubic feet (mcf))	$	3.95		$	4.34		$	3.90
Average oil price (per barrel)	$	94.94		$	79.39		$	61.90

Year Ended December 31, 2011 Compared To Year Ended December 31, 2010

Revenues. Revenues in 2011 increased $713.4 million or 65.1 percent compared to 2010. The Technical Services segment revenues for 2011 increased 69.8 percent from the prior year due primarily to a larger fleet of revenue-producing equipment, higher activity levels from expanded customer commitments and improved pricing. The Support Services segment revenues for 2011 increased 25.3 percent from the prior year due to improved pricing and higher activity levels.

Domestic revenues increased 69 percent during 2011 compared to 2010 to $1,757.7 million due to increased customer activity levels coupled with increased capacity of equipment and improved pricing. The average price of oil increased by approximately 20 percent while the average price of natural gas decreased by nine percent during 2011 compared to the prior year. The average domestic rig count during 2011 was 22 percent higher than in 2010. Our revenues and earnings grew at a greater rate than the changes in these industry indicators because of an increased capacity of revenue-producing equipment, higher equipment utilization and improved pricing compared to 2010. This increase in drilling activity, as well as the increased amount of horizontal and directional drilling, had a positive impact on our financial results. At the present time, we believe that our activity levels are affected equally by the price of natural gas and the price of oil, since oil-directed activity as a percentage of total U.S. activity has increased significantly during 2011. We also believe that the total number of directional and horizontal wells more directly affect our activity levels, regardless of whether the wells are directed towards oil or natural gas. This belief is based on the fact that directional and horizontal wells require more of several of the services within our technical services segment. International revenues, which decreased slightly from $54.9 million in 2010 to $52.1 million in 2011, were three percent of consolidated revenues in 2011 compared to five percent of revenues in 2010. These international revenue decreases were due mainly to lower customer activity levels in New Zealand and Qatar partially offset by an increase in activity in Canada, compared to the prior year. Our international revenues are impacted by the timing of project initiation and their ultimate duration.

Cost of revenues. Cost of revenues in 2011 was $992.7 million compared to $606.1 million in 2010, an increase of $386.6 million or 63.8 percent. The increase in these costs was due to the variable nature of most of these expenses as cost of revenues, as a percent of revenues was unchanged in 2011 compared to 2010.

Selling, general and administrative expenses. Selling, general and administrative expenses increased 24.2 percent to $151.3 million in 2011 compared to $121.8 million in 2010. This increase was primarily due to increases in total employment costs, including increased incentive compensation consistent with improved operating results. However, as a percentage of revenues, selling, general and administrative expenses decreased to 8.4 percent in 2011 compared to 11.1 percent in 2010 due to leverage of the fixed costs over higher revenues.

Depreciation and amortization. Depreciation and amortization were $179.9 million in 2011, an increase of $46.5 million or 34.9 percent compared to $133.4 million in 2010. This increase resulted from a higher level of capital expenditures during recent quarters within both Technical Services and Support Services to increase capacity and to maintain our existing equipment. However, as a percentage of revenues, depreciation and amortization decreased to 9.9 percent in 2011 compared to 12.2 percent in 2010 due to leverage over higher revenues.

(Loss) gain on disposition of assets, net. Loss on disposition of assets, net was $3.8 million in 2011 compared to a gain on disposition of assets, net of $3.8 million in 2010. The (loss) gain on disposition of assets, net includes gains or losses related to various property and equipment dispositions including certain equipment components experiencing increased wear and tear which requires early dispositions, or sales to customers of lost or damaged rental equipment.

Other income, net. Other income, net was $0.2 million in 2011, a decrease of $1.1 million compared to $1.3 million in 2010. The decrease is mainly due to mark-to-market net losses on investments held in the non-qualified Supplemental Retirement Plan during 2011 compared to net gains in 2010.

Interest expense. Interest expense was $3.5 million in 2011 compared to $2.7 million in 2010. The increase is primarily due to a higher average balance on our revolving credit facility in 2011 compared to 2010.

Interest income. Interest income decreased to $18 thousand in 2011 compared to $46 thousand in 2010.

Income tax provision (benefit). The income tax provision was $182.4 million in 2011 compared to $90.8 million in 2010. This increase was due to higher income before taxes in 2011 compared to 2010 as the effective tax rate of 38.1 percent in 2011 was similar to the effective tax rate of 38.2 percent in 2010.

Net income and diluted earnings per share. Net income was $296.4 million in 2011, or $2.02 per diluted share, compared to net income of $146.7 million, or $1.00 per diluted share in 2010. This improvement was due to increased revenues and lower, as a percentage of revenues, costs of revenues, selling, general and administrative expenses, and depreciation and amortization expenses.

Year Ended December 31, 2010 Compared To Year Ended December 31, 2009

Revenues. Revenues in 2010 increased $508.5 million or 86.5 percent compared to 2009. The Technical Services segment revenues for 2010 increased 90.9 percent from the prior year due primarily to higher activity levels from expanded customer commitments and improved pricing. The Support Services segment revenues for 2010 increased 56.3 percent from the prior year due to higher activity levels and improved pricing.

Domestic revenues increased 92 percent during 2010 compared to 2009 to $1,041.5 million due to increased customer activity levels coupled with increased capacity of equipment. The average price of natural gas increased by 12 percent and the average price of oil increased by approximately 28 percent during 2010 compared to the prior year. In conjunction with the increase in natural gas prices, the average domestic rig count during 2010 was 41 percent higher than in 2009. 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. International revenues, which increased from $44.8 million in 2009 to $54.9 million in 2010, were five percent of consolidated revenues. These international revenue increases were due mainly to higher customer activity levels in Canada and Qatar, compared to the prior year. Our international revenues are impacted by the timing of project initiation and their ultimate duration.

Cost of revenues. Cost of revenues in 2010 was $606.1 million compared to $393.8 million in 2009, an increase of $212.3 million or 53.9 percent. The increase in these costs was due to the variable nature of most of these expenses. However, cost of revenues, as a percent of revenues, decreased significantly due to leverage of employment and other direct costs over higher activity levels coupled with improved pricing for our services in 2010 compared to 2009.

Selling, general and administrative expenses. Selling, general and administrative expenses increased 24.7 percent to $121.8 million in 2010 compared to $97.7 million in 2009. This increase was primarily due to increases in total employment costs, including increased incentive compensation consistent with improved operating results. However, as a percentage of revenues, selling, general and administrative expenses decreased to 11.1 percent in 2010 compared to 16.6 percent in 2009 due to leverage of the fixed costs over higher revenues.

Depreciation and amortization. Depreciation and amortization were $133.4 million in 2010, an increase of $2.8 million or 2.1 percent compared to $130.6 million in 2009. This increase resulted from a higher level of capital expenditures during late 2010 quarters within both Support Services and Technical Services to increase capacity and to maintain our existing equipment.

Gain on disposition of assets, net. Gain on the disposition of assets, net increased due primarily to increased gains related to various property and equipment dispositions or sales to customers of lost or damaged rental equipment due to the increased intensity of work.

Other income, net. Other income, net was $1.3 million in 2010, a decrease of $279 thousand compared to other expense of $1.6 million in 2009. The increase is mainly due to the 2010 increase in the fair value of trading securities held in the non-qualified Supplemental Retirement Plan.

Interest expense. Interest expense was $2.7 million in 2010 compared to $2.2 million in 2009. The increase is primarily due to higher interest rates in 2010 incurred on outstanding interest bearing advances on our revolving credit facility.

Interest income. Interest income decreased to $46 thousand in 2010 compared to $147 thousand in 2009 as a result of a lower average investable cash balance in 2010 compared to 2009.

Income tax provision (benefit). The income tax provision was $90.8 million in 2010 compared to an income tax benefit of $10.8 million in 2009. The change is due to the level of income before income tax in 2010, coupled with an increase in the effective tax rate to 38.2 percent in 2010 from 32.1 percent in 2009.

Net income (loss) and diluted earnings (loss) per share. Net income was $146.7 million in 2010, or $1.00 per diluted share, compared to net loss of $22.7 million, or $0.16 per share in 2009. This improvement was due to increased revenues and lower, as a percentage of revenues, costs of revenues, selling, general and administrative expenses and depreciation expense.

Liquidity and Capital Resources

Cash and Cash Flows

The Company’s cash and cash equivalents were $7.4 million as of December 31, 2011, $9.0 million as of December 31, 2010 and $4.5 million as of December 31, 2009.

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

	(in thousands)
	2011			2010			2009
Net cash provided by operating activities	$	386,007		$	168,657		$	168,740
Net cash used for investing activities		(391,637	)		(171,769	)		(61,144	)
Net cash provided by (used for) financing activities		3,988			7,658			(106,144	)

2011

Cash provided by operating activities increased $217.4 million in 2011 compared to the prior year due primarily to a $149.6 million increase in net income in 2011 compared to 2010. This improvement in net income was partially offset by increases in working capital requirements. Increased business activity levels and revenues in 2011 resulted in increased inventory, other current assets and accounts receivables, partially offset by an increase in accounts payable.

Cash used for investing activities in 2011 increased by $219.9 million compared to 2010, primarily as a result of higher capital expenditures made to increase our fleet of revenue-producing equipment.

Cash provided by financing activities for 2011 decreased by $3.7 million compared to 2010, as a result of higher common stock dividends in 2011 compared to the prior year, coupled with cost of higher open market share repurchases during 2011 partially offset by a net increase in borrowings under our credit facility during 2011 to fund working capital requirements and capital expenditures.

2010

Cash provided by operating activities was comparable in 2010 compared to the prior year despite net income increasing significantly to $146.7 million in 2010 compared to net loss of $22.7 million in 2009. This contribution of net income to cash provided by operating activities was largely offset by increases in working capital requirements. Increased business activity levels and revenues in 2010 resulted in higher accounts receivable and increased inventory, partially offset by increases in accounts payable and accrued payroll including bonuses, consistent with higher activity levels and profitability.

Cash used for investing activities in 2010 increased by $110.6 million compared to 2009, primarily as a result of higher capital expenditures.

Cash provided by (used for) financing activities in 2010 increased by $113.8 million compared to 2009, primarily due to the net increase in borrowings under our credit facility during 2010 to fund working capital requirements and capital expenditures.

Financial Condition and Liquidity

The Company’s financial condition as of December 31, 2011, 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. The Company currently has a $350 million revolving credit facility that matures in August 2015. The facility 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 $128.3 million was available under the facility as of December 31, 2011; approximately $18.4 million of the facility supports outstanding letters of credit relating to self-insurance programs or contract bids. For additional information with respect to RPC’s facility, see Note 6 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 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. The Company is in compliance with these financial covenants.

Cash Requirements

Capital expenditures were $416.4 million in 2011, and we currently expect capital expenditures to be in excess of $350 million in 2012. We expect these expenditures to be primarily directed towards revenue-producing equipment in several of our larger, core service lines such as pressure pumping and coiled tubing, as well as towards refurbishment of our existing fleet of revenue-producing equipment. The actual amount of 2012 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 2011, the Company contributed $0.6 million to the pension plan. The Company expects that additional contributions to the defined benefit pension plan of $0.6 million will be required in 2012 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 17,718,750 shares of which 2,564,066 additional shares were available to be repurchased as of December 31, 2011. The program does not have a predetermined expiration date.

On January 24, 2012, the Board of Directors approved a $0.12 per share cash dividend, payable March 9, 2012 to stockholders of record at the close of business on February 10, 2012. 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 our credit facility, 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, 2011:

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	$	203,300	$	-	$	-	$	203,300	$	-
Interest on long-term debt obligations		15,281		4,168		8,335		2,778		-
Capital lease obligations		-		-		-		-		-
Operating leases (1)		27,985		6,085		9,415		5,405		7,080
Purchase obligations (2)		186,724		183,382		3,342		-		-
Other long-term liabilities (3)		3,445		-		3,445		-		-
Total contractual obligations	$	436,735	$	193,635	$	24,537	$	211,483	$	7,080

(1)	Operating leases include agreements for various office locations, office equipment, and certain operating equipment.

(2)	Includes agreements to purchase raw materials, 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 occasionally enters into purchase commitments to manage its various operating needs.

(3)	Includes expected cash payments for long-term liabilities reflected on the balance sheet where the timing of the payments are known. These amounts include incentive compensation. These amounts exclude pension obligations with uncertain funding requirements and deferred compensation liabilities.

Fair Value Measurements

The Company’s assets and liabilities measured at fair value are classified in the fair value hierarchy (Level 1, 2 or 3) based on the inputs used for valuation. Assets and liabilities that are traded on an exchange with a quoted price are classified as Level 1. Assets and liabilities that are valued using significant observable inputs in addition to quoted market prices are classified as Level 2. The Company currently has no assets or liabilities measured on a recurring basis that are valued using unobservable inputs and therefore no assets or liabilities measured on a recurring basis are classified as Level 3. For defined benefit plan assets classified as Level 3, the values are computed using inputs such as cost, discounted future cash flows, independent appraisals and market based comparable data or on net asset values calculated by the fund and not publicly available.

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. Also, increases in activity in the domestic oilfield can cause upward wage pressures in the labor markets from which it hires employees as well as increases in the costs of certain materials and key equipment components used to provide services to the Company’s customers. During 2011, the Company incurred higher costs for fuel and several of the materials used to provide its services. Fuel costs increased significantly due to increased diesel fuel prices compared to 2010. In addition, the prices of certain raw materials used to provide the Company’s services increased significantly during 2011 as compared to 2010. The price of diesel fuel and the prices of these raw materials continue to remain high during the first quarter of 2012. Also, the Company was subjected to upward wage pressures in 2011, and believes that these upward wage pressures will continue, though to a lesser degree, in 2012. The Company has attempted to mitigate the risk of cost increases by securing materials through additional sources and increasing amounts held in inventory, although no assurance can be given that these efforts will be successful.

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 $639,000 in 2011, $689,000 in 2010 and $713,000 in 2009. The Company’s receivable due from Marine Products for these services as of December 31, 2011 was approximately $3,000 and as of December 31, 2010 was approximately $65,000. The Company’s directors are also directors of Marine Products and all of the executive officers are employees of both the Company and Marine Products.

Other

The Company periodically purchases in the ordinary course of business products or services from suppliers, who are owned by significant officers or stockholders, or affiliated with the directors of RPC. The total amounts paid to these affiliated parties were approximately $1,469,000 in 2011, $551,000 in 2010 and $409,000 in 2009.

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 $102,000 in 2011, $94,000 in 2010 and $87,000 in 2009.

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. Recoveries were insignificant in 2011, 2010 and 2009. 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 which we adjust periodically based on management judgment and the economic strength of our customers. The net provisions for doubtful accounts have ranged from 0.11 percent to 0.45 percent of revenues over the last three years. Increasing or decreasing the estimated general reserve percentages by 0.50 percentage points as of December 31, 2011 would have resulted in a change of approximately $2.3 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 2011, 38.2 percent in 2010 and 32.1 percent in 2009. 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 may 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, 2011, the Company estimates the range of exposure to be from $12.8 million to $16.7 million. The Company has recorded liabilities at December 31, 2011 of approximately $14.7 million which represents management’s best estimate of probable loss.

Depreciable life of assets — RPC’s net property, plant and equipment at December 31, 2011 was $675.4 million representing 50.5 percent of the Company’s consolidated assets. Depreciation and amortization expenses for the year ended December 31, 2011 were $179.9 million. 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 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 FASB ASC 715, “Compensation – Retirement Benefits” 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 was seven percent for 2011, 2010 and 2009.

The discount rate reflects the current rate at which the pension liabilities could be effectively settled at the end of the year. In estimating this rate, the Company utilizes a yield curve approach. The approach utilizes an economic model whereby the Company’s expected benefit payments over the life of the plan are forecasted and then compared to a portfolio of investment grade corporate bonds that will mature at the same time that the benefit payments are due in any given year. The economic model then calculates the one discount rate to apply to all benefit payments over the life of the plan which will result in the same total lump sum as the payments from the corporate bonds. A lower discount rate increases the present value of benefit obligations. The discount rate was 5.00 percent as of December 31, 2011 compared to 5.49 percent as of December 31, 2010 and 6.00 percent in 2009.

As set forth in note 10 to the Company’s financial statements, included among the asset categories for the Plan’s investments are real estate, tactical composite and alternative investments comprised of investments in real estate and hedge funds. These investments are categorized as level 3 investments and are valued using significant non-observable inputs which do not have a readily determinable fair value. In accordance with ASU No. 2009-12 “Investments In Certain Entities That Calculate Net Asset Value per Share (Or Its Equivalent),” these investments are valued based on the net asset value per share calculated by the funds in which the plan has invested. These valuations are subject to judgments and assumptions of the funds which may prove to be incorrect, resulting in risks of incorrect valuation of these investments. The Company seeks to mitigate against these risks by evaluating the appropriateness of the funds’ judgments and assumptions by reviewing the financial data included in the funds’ financial statements for reasonableness.

As of December 31, 2011, the defined benefit plan was under-funded and the recorded change within accumulated other comprehensive loss decreased stockholders’ equity by approximately $3.0 million after tax. Holding all other factors constant, a change in the discount rate used to measure plan liabilities by 0.25 percentage points would result in a pre-tax increase or decrease of approximately $1.2 million to the net loss related to pension reflected in accumulated other comprehensive loss.

The Company recognized pre-tax pension (income) expense of $0.5 million in 2011, $0.6 million in 2010 and $2.0 million in 2009. Based on the under-funded status of the defined benefit plan as of December 31, 2011, the Company expects to recognize pension expense of $0.9 million in 2012. 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 2012. 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 $0.01 million in 2012.

RECENT ACCOUNTING PRONOUNCEMENTS:

During the year ended December 31, 2011, the Financial Accounting Standards Board (FASB) issued the following Accounting Standards Updates (ASU):

Recently Adopted Accounting Pronouncement:

●

ASU 2011-08, Intangibles-Goodwill and Other (Topic 350): Testing Goodwill for Impairment. The amendments in this codification permits an entity to first assess qualitative factors to determine whether it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount. This can be used as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. These amendments are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted, including for annual and interim goodwill impairment tests performed as of a date before September 15, 2011, if an entity’s financial statements for the most recent annual or interim period have not yet been issued. The Company adopted these provisions in the fourth quarter of 2011, for annual and interim goodwill impairment tests performed starting this year. Adoption of these provisions did not have a material impact on the Company’s consolidated financial statements.

Recently Issued Accounting Pronouncements Not Yet Adopted:

●

Accounting Standards Update 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. The amendments to the Codification in this ASU defer the presentation of reclassification adjustments out of accumulated other comprehensive income on the components of net income and other comprehensive income for all periods presented. This ASU supersedes certain presentation requirements in ASU No. 2011-05, Comprehensive Income, discussed below, so that entities will not be required to comply with the presentation requirements in ASU No. 2011-05 that ASU No. 2011-12 is deferring. While the presentation requirements are being re-deliberated, entities are required to continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before ASU No. 2011-05. The amendments to this ASU are effective at the same time as the amendments in ASU No. 2011-05. The Company plans to adopt these provisions in the first quarter of 2012 and is currently evaluating the impact of the adoption of these provisions on the presentation of its consolidated financial statements.

●

Accounting Standards Update 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. The amendments to the Codification in this ASU are part of an ongoing effort to bring congruence between U.S. GAAP and International Financial Reporting Standards. The amendments in this ASU require an entity to disclose information about derivatives that are subject to a legally enforceable netting arrangement with the same party where rights of set-off are only available in the event of default or bankruptcy and can be presented as a single net amount in the statement of financial position. The amendments in this ASU are effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods, with the required disclosures being provided retrospectively for all comparative periods presented. The Company is currently evaluating the impact of adoption of these provisions in the first quarter of 2013.

●

ASU 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. The amendments to the Codification in this ASU allow an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. The amendments to the Codification in the ASU do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amendments are to be applied retrospectively and are effective for fiscal years beginning after December 15, 2011. The Company plans to adopt these provisions in the first quarter of 2012 and is currently evaluating the impact of the adoption of these provisions on the presentation of its consolidated financial statements.

●

ASU 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs . This ASU represents the converged guidance of the FASB and the International Accounting Standards Board on fair value measurement. These amendments have resulted in common requirements for measuring fair value and for disclosing information about fair value measurements, including a consistent meaning of the term “fair value.” The common requirements are expected to result in greater comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards. The amendments are to be applied prospectively and are effective for fiscal years beginning after December 15, 2011. The Company plans to adopt these provisions in the first quarter of 2012. Adoption of these provisions is not expected to have a material impact on the Company’s consolidated financial statements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

The Company is subject to interest rate risk exposure through borrowings on its credit agreement. As of December 31, 2011, there are outstanding interest-bearing advances of $203.3 million on our credit facility which bear interest at a floating rate. A change in interest rates of one percent on the balance outstanding on the credit facility at December 31, 2011 would cause a change of approximately $2.0 million in total annual interest costs.

Additionally, the Company is exposed to market risk resulting from changes in foreign exchange rates. However, since the majority of the Company’s transactions occur in U.S. currency, this risk is not expected to have a material effect on its consolidated results of operations or 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, 2011 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, 2011.

The independent registered public accounting firm, Grant Thornton LLP, has audited the consolidated financial statements as of and for the year ended December 31, 2011, and has also issued their report on the effectiveness of the Company’s internal control over financial reporting, included in this report on page 31.


/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 29, 2012

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

Board of Directors and Stockholders

RPC, Inc.

We have audited RPC, Inc. (a Delaware Corporation) and subsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011 and our report dated February 29, 2012 expressed an unqualified opinion on those consolidated financial statements.

/s/ Grant Thorton LLP

Atlanta, Georgia

February 29, 2012

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements

Board of Directors and Stockholders

RPC, Inc.

We have audited the accompanying consolidated balance sheets of RPC, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits of the basic consolidated financial statements included the financial statement schedule listed in the index appearing under Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our 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, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2011, 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 29, 2012 expressed an unqualified opinion thereon.

/s/ Grant Thorton LLP

Atlanta, Georgia

February 29, 2012

Item 8. Financial Statements and Supplementary Data

CONSOLIDATED BALANCE SHEETS
RPC, INC. AND SUBSIDIARIES

(in thousands except share information)

December 31,	2011			2010
ASSETS
Cash and cash equivalents	$	7,393		$	9,035
Accounts receivable, net		461,272			294,002
Inventories		100,438			64,059
Deferred income taxes		7,183			7,426
Income taxes receivable		10,805			17,251
Prepaid expenses		8,478			5,695
Other current assets		30,986			1,210
Current assets		626,555			398,678
Property, plant and equipment, net		675,360			453,017
Goodwill		24,093			24,093
Other assets		12,203			12,083
Total assets	$	1,338,211		$	887,871
LIABILITIES AND STOCKHOLDERS’ EQUITY
LIABILITIES
Accounts payable	$	122,987		$	78,743
Accrued payroll and related expenses		33,680			23,881
Accrued insurance expenses		5,744			5,141
Accrued state, local and other taxes		5,066			2,988
Income taxes payable		10,705			5,788
Other accrued expenses		1,284			963
Current liabilities		179,466			117,504
Long-term accrued insurance expenses		9,000			8,489
Notes payable to banks		203,300			121,250
Long-term pension liabilities		24,445			18,397
Other long-term liabilities		3,480			2,448
Deferred income taxes		155,928			80,888
Total liabilities		575,619			348,976
Commitments and contingencies
STOCKHOLDERS’ EQUITY
Preferred stock, $0.10 par value, 1,000,000 shares authorized, none issued		-			-
Common stock, $0.10 par value, 349,000,000 shares authorized, 147,458,440 and 148,175,995 shares issued and outstanding in 2011 and 2010, respectively		14,746			14,818
Capital in excess of par value		-			6,460
Retained earnings		760,492			527,150
Accumulated other comprehensive loss		(12,646	)		(9,533	)
Total stockholders’ equity		762,592			538,895
Total liabilities and stockholders’ equity	$	1,338,211		$	887,871

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,	2011			2010			2009
REVENUES	$	1,809,807		$	1,096,384		$	587,863
COSTS AND EXPENSES:
Cost of revenues		992,704			606,098			393,806
Selling, general and administrative expenses		151,286			121,839			97,672
Depreciation and amortization		179,905			133,360			130,580
Loss (gain) on disposition of assets, net		3,831			(3,758	)		(1,143	)
Operating profit (loss)		482,081			238,845			(33,052	)
Interest expense		(3,453	)		(2,662	)		(2,176	)
Interest income		18			46			147
Other income, net		169			1,303			1,582
Income (loss) before income taxes		478,815			237,532			(33,499	)
Income tax provision (benefit)		182,434			90,790			(10,754	)
Net income (loss)	$	296,381		$	146,742		$	(22,745	)
EARNINGS (LOSS) PER SHARE
Basic	$	2.04		$	1.01		$	(0.16	)
Diluted	$	2.02		$	1.00		$	(0.16	)
Dividends paid per share	$	0.32		$	0.141		$	0.148

The accompanying notes are an integral part of these statements.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

RPC, INC. AND SUBSIDIARIES

(in thousands)

									Capital in Excess of Par Value						Accumulated Other Comprehensive Income (Loss)

Three Years Ended December 31, 2011	Comprehensive Income (Loss)			Common Stock								Retained Earnings
Three Years Ended December 31, 2011	Comprehensive Income (Loss)			Shares		Amount						Retained Earnings						Total
Balance, December 31, 2008				146,558		$	14,655		$	(895	)	$	445,356		$	(10,032	)	$	449,084
Stock issued for stock incentive plans, net				911			91			4,323			—			—			4,414
Stock purchased and retired				(252	)		(25	)		(2,096	)		—			—			(2,121	)
Net loss	$	(22,745	)	—			—			—			(22,745	)		—			(22,745	)
Pension adjustment, net of taxes		897		—			—			—			—			897			897
Gain on cash flow hedge, net of taxes		7		—			—			—			—			7			7
Unrealized gain on securities, net of taxes		91		—			—			—			—			91			91
Foreign currency translation, net of taxes		231		—			—			—			—			231			231
Comprehensive loss	$	(21,519	)
Dividends declared				—			—			—			(21,556	)		—			(21,556	)
Excess tax benefits for share-based payments				—			—			1,421			—			—			1,421
Three-for-two stock splits				330			33			(33	)								—
Balance, December 31, 2009				147,547			14,754			2,720			401,055			(8,806	)		409,723
Stock issued for stock incentive plans, net				587			59			4,889			—			—			4,948
Stock purchased and retired				(144	)		(14	)		(1,781	)		—			—			(1,795	)
Net income	$	146,742		—			—			—			146,742			—			146,742
Pension adjustment, net of taxes		(1,350	)	—			—			—			—			(1,350	)		(1,350	)
Gain on cash flow hedge, net of taxes		133		—			—			—			—			133			133
Unrealized gain on securities, net of taxes		281		—			—			—			—			281			281
Foreign currency translation, net of taxes		209		—			—			—			—			209			209
Comprehensive income	$	146,015
Dividends declared				—			—			—			(20,647	)		—			(20,647	)
Excess tax benefits for share-based payments				—			—			651			—			—			651
Three-for-two stock splits				186			19			(19	)								—
Balance, December 31, 2010				148,176			14,818			6,460			527,150			(9,533	)		538,895
Stock issued for stock incentive plans, net				1,218			122			9,455			—			—			9,577
Stock purchased and retired				(1,936	)		(194	)		(19,286	)		(15,712	)		—			(35,192	)
Net income	$	296,381		—			—			—			296,381			—			296,381
Pension adjustment, net of taxes		(3,048	)	—			—			—			—			(3,048	)		(3,048	)
Gain on cash flow hedge, net of taxes		387		—			—			—			—			387			387
Unrealized gain on securities, net of taxes		(314	)	—			—			—			—			(314	)		(314	)
Foreign currency translation, net of taxes		(138	)	—			—			—			—			(138	)		(138	)
Comprehensive income	$	293,268
Dividends declared				—			—			—			(47,327	)		—			(47,327	)
Excess tax benefits for share-based payments				—			—			3,371			—			—			3,371
Balance, December 31, 2011				147,458		$	14,746		$	—		$	760,492		$	(12,646	)	$	762,592

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,	2011			2010			2009
OPERATING ACTIVITIES
Net income (loss)	$	296,381		$	146,742		$	(22,745	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and other non-cash charges		179,787			133,253			130,581
Stock-based compensation expense		8,075			4,909			4,440
Loss (gain) on disposition of assets, net		3,831			(3,758	)		(1,143	)
Deferred income tax provision		77,074			22,262			1,669
Excess tax benefits for share-based payments		(3,371	)		(651	)		(1,421	)
Changes in current assets and liabilities:
Accounts receivable		(167,312	)		(163,162	)		80,035
Income taxes receivable		9,817			1,584			(1,159	)
Inventories		(36,511	)		(8,130	)		(5,798	)
Prepaid expenses		(2,783	)		(1,041	)		2,567
Other current assets		(30,524	)		189			8
Accounts payable		30,102			14,191			(5,711	)
Income taxes payable		4,917			5,141			(2,712	)
Accrued payroll and related expenses		9,799			13,173			(9,690	)
Accrued insurance expenses		603			826			(325	)
Accrued state, local and other taxes		2,078			987			(394	)
Other accrued expenses		958			112			(167	)
Changes in working capital		(178,856	)		(136,130	)		56,654
Changes in other assets and liabilities:
Pension liabilities		1,249			1,628			4,882
Accrued insurance expenses		511			(108	)		199
Other non-current assets		294			(920	)		(2,597	)
Other non-current liabilities		1,032			1,430			(1,779	)
Net cash provided by operating activities		386,007			168,657			168,740
INVESTING ACTIVITIES
Capital expenditures		(416,400	)		(187,486	)		(67,830	)
Proceeds from sale of assets		24,763			15,717			6,686
Net cash used for investing activities		(391,637	)		(171,769	)		(61,144	)
FINANCING ACTIVITIES
Payment of dividends		(47,327	)		(20,647	)		(21,556	)
Borrowings from notes payable to banks		940,850			516,600			276,100
Repayments of notes payable to banks		(858,800	)		(485,650	)		(360,250	)
Debt issue costs for notes payable to banks		(415	)		(1,886	)		(234	)
Excess tax benefits for share-based payments		3,371			651			1,421
Cash paid for common stock purchased and retired		(34,419	)		(1,650	)		(1,747	)
Proceeds received upon exercise of stock options		728			240			122
Net cash provided by (used for) financing activities		3,988			7,658			(106,144	)
Net (decrease) increase in cash and cash equivalents		(1,642	)		4,546			1,452
Cash and cash equivalents at beginning of year		9,035			4,489			3,037
Cash and cash equivalents at end of year	$	7,393		$	9,035		$	4,489

The accompanying notes are an integral part of these statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries
Years ended December 31, 2011, 2010 and 2009

Note 1: Significant Accounting Policies

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of RPC, Inc. and its wholly-owned subsidiaries (“RPC” or the “Company”). All significant intercompany accounts and transactions have been eliminated.

Nature of Operations

RPC provides a broad range of specialized oilfield services and equipment primarily to independent and major oil and gas companies engaged in the exploration, production and development of oil and gas properties throughout the United States, including the southwest, mid-continent, Gulf of Mexico, Rocky Mountain and Appalachian regions, and in selected international markets. The services and equipment provided include Technical Services such as pressure pumping services, coiled tubing services, snubbing services (also referred to as hydraulic workover services), nitrogen services, and firefighting and well control, and Support Services such as the rental of drill pipe and other specialized oilfield equipment and oilfield training.

Common Stock

RPC is authorized to issue 349,000,000 shares of common stock, $0.10 par value. Holders of common stock are entitled to receive dividends when, as, and if declared by the Board of Directors out of legally available funds. Each share of common stock is entitled to one vote on all matters submitted to a vote of stockholders. Holders of common stock do not have cumulative voting rights. In the event of any liquidation, dissolution or winding up of the Company, holders of common stock are entitled to ratable distribution of the remaining assets available for distribution to stockholders.

Preferred Stock

RPC is authorized to issue up to 1,000,000 shares of preferred stock, $0.10 par value. As of December 31, 2011, there were no shares of preferred stock issued. The Board of Directors is authorized, subject to any limitations prescribed by law, to provide for the issuance of preferred stock as a class without series or, if so determined from time to time, in one or more series, and by filing a certificate pursuant to the applicable laws of the state of Delaware and to fix the designations, powers, preferences and rights, exchangeability for shares of any other class or classes of stock. Any preferred stock to be issued could rank prior to the common stock with respect to dividend rights and rights on liquidation.

Dividends

On January 24, 2012, the Board of Directors approved a $0.12 per share cash dividend payable March 9, 2012 to stockholders of record at the close of business on February 10, 2012.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Significant estimates are used in the determination of the allowance for doubtful accounts, income taxes, accrued insurance expenses, depreciable lives of assets, and pension liabilities.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries
Years ended December 31, 2011, 2010 and 2009

Revenues

RPC’s revenues are generated principally from providing services and the related equipment. Revenues are recognized when the services are rendered and collectibility is reasonably assured. Revenues from services and equipment are based on fixed or determinable priced purchase orders or contracts with the customer and do not include the right of return. Rates for services and equipment are priced on a per day, per unit of measure, per man hour or similar basis. Sales tax charged to customers is presented on a net basis within the consolidated statement of operations and excluded from revenues.

Concentration of Credit Risk

Substantially all of the Company’s customers are engaged in the oil and gas industry. This concentration of customers may impact overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. The Company provided oilfield services to several hundred customers. One customer at approximately 12 percent of revenues in 2011 and approximately 15 percent of revenues in 2010, accounted for more than ten percent of the Company’s revenues. Two customers individually accounted for 13 percent and 12 percent of the Company’s 2009 revenues. Additionally, one customer accounted for approximately 19 percent of accounts receivable as of December 31, 2011 and approximately 15 percent of accounts receivable as of December 31, 2010.

Cash and Cash Equivalents

Highly liquid investments with original maturities of three months or less when acquired are considered to be cash equivalents. The Company maintains its cash in bank accounts which, at times, may exceed federally insured limits. RPC maintains cash equivalents and investments in one or more large financial institutions, and RPC’s policy restricts investment in any securities rated less than “investment grade” by national rating services.

Investments

Investments classified as available-for-sale are stated at their fair values, with the unrealized gains and losses, net of tax, reported as a separate component of stockholders’ equity. The cost of securities sold is based on the specific identification method. Realized gains and losses, declines in value judged to be other than temporary, interest, and dividends with respect to available-for-sale securities are included in interest income. The Company did not realize any gains or losses on securities during 2011, 2010 or 2009 on its available-for-sale securities. Securities that are held in the non-qualified Supplemental Retirement Plan (“SERP”) are classified as trading. See Note 10 for further information regarding the SERP. The change in fair value of trading securities is presented in other income (expense) on the consolidated statements of operations.

Management determines the appropriate classification of investments at the time of purchase and re-evaluates such designations as of each balance sheet date.

Accounts Receivable

The majority of the Company’s accounts receivable are due principally from major and independent oil and natural gas exploration and production companies. Credit is extended based on evaluation of a customer’s financial condition and, generally, collateral is not required. Accounts receivable are considered past due after 60 days and are stated at amounts due from customers, net of an allowance for doubtful accounts.

Allowance for Doubtful Accounts

Accounts receivable are carried at the amount owed by customers, reduced by an allowance for estimated amounts that may not be collectible in the future. The estimated allowance for doubtful accounts is based on an evaluation of industry trends, financial condition of customers, historical write-off experience, current economic conditions, and in the case of international customers, judgments about the economic and political environment of the related country and region. Accounts are written off against the allowance for doubtful accounts when the Company determines that amounts are uncollectible and recoveries of previously written-off accounts are recorded when collected.

Inventories

Inventories, which consist principally of (i) raw materials and supplies that are consumed providing services to the Company’s customers, (ii) spare parts for equipment used in providing these services and (iii) manufactured components and attachments for equipment used in providing services, are recorded at the lower of weighted average cost or market value. Market value is determined based on replacement cost for materials and supplies. The Company regularly reviews inventory quantities on hand and records provisions for excess or obsolete inventory based primarily on its estimated forecast of product demand, market conditions, production requirements and technological developments.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries
Years ended December 31, 2011, 2010 and 2009

Derivative Instruments and Hedging Activities

The Company is subject to interest rate risk on the variable component of the interest rate under our credit facility. Effective December 2008, the Company entered into a $50 million interest rate swap agreement. The Company designated the interest rate swap as a cash flow hedge. Changes in the fair value of the effective portion of the interest rate swap were recognized in other comprehensive loss until the hedged item was recognized in earnings. This agreement terminated on September 8, 2011.

Property, Plant and Equipment

Property, plant and equipment, including software costs, are reported at cost less accumulated depreciation and amortization, which is provided on a straight-line basis over the estimated useful lives of the assets. Annual depreciation and amortization expenses are computed using the following useful lives: operating equipment, 3 to 10 years; buildings and leasehold improvements, 15 to 30 years; furniture and fixtures, 5 to 7 years; software, 5 years; and vehicles, 3 to 5 years. The cost of assets retired or otherwise disposed of and the related accumulated depreciation and amortization are eliminated from the accounts in the year of disposal with the resulting gain or loss credited or charged to income from operations. Expenditures for additions, major renewals, and betterments are capitalized. Expenditures for restoring an identifiable asset to working condition or for maintaining the asset in good working order constitute repairs and maintenance and are expensed as incurred.

RPC records impairment losses on long-lived assets used in operations when events and circumstances indicate that the assets might be impaired and the undiscounted cash flows estimated to be generated by those assets are less than the carrying amount of those assets. The Company periodically reviews the values assigned to long-lived assets, such as property, plant and equipment and other assets, to determine if any impairments should be recognized. Management believes that the long-lived assets in the accompanying balance sheets have not been impaired.

Goodwill and Other Intangibles

Goodwill represents the excess of the purchase price over the fair value of net assets of businesses acquired. The carrying amount of goodwill was $24,093,000 at December 31, 2011 and 2010. Goodwill is reviewed annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount, for impairment. In accordance with recently adopted accounting guidance, the Company completed a comprehensive qualitative assessment of the various factors that impact goodwill and concluded it is more likely than not that the fair value of its reporting units exceeds their carrying amounts on the annual test date. Therefore the Company did not proceed to Step 1 of the goodwill impairment test in 2011. In prior years, the Company completed the Step 1 quantitative analysis by comparing the estimated fair value of a reporting unit with its carrying value. Based on the qualitative assessment and results of prior years’ analyses, the Company has concluded that no impairment of its goodwill has occurred for the years ended December 31, 2011, 2010 and 2009.

Other intangibles primarily represent non-compete agreements related to businesses acquired. Non-compete agreements are amortized on a straight-line basis over the period of the agreement, as this method best estimates the ratio that current revenues bear to the total of current and anticipated revenues. These non-compete agreements are fully amortized as of December 31, 2011 and 2010.

Advertising

Advertising expenses are charged to expense during the period in which they are incurred. Advertising expenses totaled $2,406,000 in 2011, $1,782,000 in 2010 and $1,065,000 in 2009.

Insurance Expenses

RPC self insures, up to certain policy-specified limits, certain risks related to general liability, workers’ compensation, vehicle and equipment liability, and employee health insurance plan costs. The estimated cost of claims under these self-insurance programs is estimated and accrued as the claims are incurred (although actual settlement of the claims may not be made until future periods) and may subsequently be revised based on developments relating to such claims. The portion of these estimated outstanding claims expected to be paid more than one year in the future is classified as long-term accrued insurance expenses.

Income Taxes

Deferred tax liabilities and assets are determined based on the difference between the financial and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The Company establishes a valuation allowance against the carrying value of deferred tax assets when the Company determines that it is more likely than not that the asset will not be realized through future taxable income.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries
Years ended December 31, 2011, 2010 and 2009

Defined Benefit Pension Plan

The Company has a defined benefit pension plan that provides monthly benefits upon retirement at age 65 to eligible employees with at least one year of service prior to 2002. In 2002, the Company’s Board of Directors approved a resolution to cease all future retirement benefit accruals under the defined benefit pension plan. See Note 10 for a full description of this plan and the related accounting and funding policies.

Share Repurchases

The Company records the cost of share repurchases in stockholders’ equity as a reduction to common stock to the extent of par value of the shares acquired and the remainder is allocated to capital in excess of par value and retained earnings if capital in excess of par value is depleted.

Earnings per Share

FASB ASC Topic 260-10 “Earnings Per Share-Overall,” requires a basic earnings per share and diluted earnings per share presentation. During 2009, the Company adopted certain amendments to ASC 260-10 which requires that all outstanding unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether paid or unpaid, be considered participating securities and included in the calculation of its basic earnings per share.

The Company has periodically issued share-based payment awards that contain non-forfeitable rights to dividends, and therefore are considered participating securities. See Note 10 for further information on restricted stock granted to employees.

The basic and diluted calculations differ as a result of the dilutive effect of stock options and time lapse restricted shares and performance restricted shares included in diluted earnings per share, but excluded from basic earnings per share. Basic and diluted earnings per share are computed by dividing net income (loss) by the weighted average number of shares outstanding during the respective periods.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries
Years ended December 31, 2011, 2010 and 2009

A reconciliation of weighted average shares outstanding along with the earnings (loss) per share attributable to restricted shares of common stock (participating securities) is as follows:

(In thousands except per share data )	2011			2010			2009
Net income (loss) available for stockholders:	$	296,381		$	146,742		$	(22,745	)
Less: Dividends paid
Common stock		(46,479	)		(20,294	)		(21,229	)
Restricted shares of common stock		(848	)		(353	)		(327	)
Undistributed earnings (loss)	$	249,054		$	126,095		$	(44,301	)

Allocation of undistributed earnings:
Common stock	$	244,053		$	123,536		$	(43,408	)
Restricted shares of common stock		5,001			2,559			(893	)

Basic shares outstanding :
Common stock		142,102			141,866			141,390
Restricted shares of common stock		3,020			3,123			3,068
		145,122			144,989			144,458
Diluted shares outstanding :
Common stock		142,102			141,866			141,390
Dilutive effect of options		1,711			1,548			-
		143,813			143,414			141,390
Restricted shares of common stock		3,020			3,123			3,068
		146,833			146,537			144,458
Basic earnings per share:
Common stock:
Distributed earnings	$	0.32		$	0.14		$	0.15
Undistributed earnings (loss)		1.72			0.87			(0.31	)
	$	2.04		$	1.01		$	(0.16	)
Restricted shares of common stock:
Distributed earnings	$	0.28		$	0.11		$	0.11
Undistributed earnings (loss)		1.66			0.82			(0.29	)
	$	1.94		$	0.93		$	(0.18	)
Diluted earnings per share:
Common Stock:
Distributed earnings	$	0.32		$	0.14		$	0.15
Undistributed earnings (loss)		1.70			0.86			(0.31	)
	$	2.02		$	1.00		$	(0.16	)

During the year ended December 31, 2009, the Company incurred a net loss from continuing operations and consequently the common stock equivalents were excluded from the computation of diluted loss per share because the effect would have been anti-dilutive. See Note 13 for information regarding the three-for-two stock split.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, marketable securities, accounts payable, an interest rate swap, and debt. The carrying value of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value due to the short-term nature of such instruments. The marketable securities classified as available-for-sale and the securities held in the SERP classified as trading are carried at fair value in the accompanying consolidated balance sheets. The interest rate swap which expired in September of 2011 was carried at fair value based on quotes from the issuer of the swap and represented the estimated amount that the Company expected to pay to terminate the swap. See Note 8 for additional information.

Stock-Based Compensation

Stock-based compensation expense is recognized for all share-based payment awards, net of an estimated forfeiture rate. Thus, compensation cost is amortized for those shares expected to vest on a straight-line basis over the requisite service period of the award. See Note 10 for additional information.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries
Years ended December 31, 2011, 2010 and 2009

Reclassifications

In the current year the Company classified prepaid expenses and other current assets separately. For comparative purposes, amounts in the prior year have been reclassified to conform to current year presentation.

RECENT ACCOUNTING PRONOUNCEMENTS:

During the year ended December 31, 2011, the Financial Accounting Standards Board (FASB) issued the following Accounting Standards Updates (ASU):

Recently Adopted Accounting Pronouncement:

●

Recently Issued Accounting Pronouncements Not Yet Adopted:

●

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries
Years ended December 31, 2011, 2010 and 2009

●

ASU 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. This ASU represents the converged guidance of the FASB and the International Accounting Standards Board on fair value measurement. These amendments have resulted in common requirements for measuring fair value and for disclosing information about fair value measurements, including a consistent meaning of the term “fair value.” The common requirements are expected to result in greater comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards. The amendments are to be applied prospectively and are effective for fiscal years beginning after December 15, 2011. The Company plans to adopt these provisions in the first quarter of 2012. Adoption of these provisions is not expected to have a material impact on the Company’s consolidated financial statements.

Note 2: Accounts Receivable

Accounts receivable, net consists of the following:

December 31,	2011			2010
(in thousands)
Trade receivables:
Billed	$	367,718		$	216,201
Unbilled		99,913			84,977
Other receivables		1,734			1,519
Total		469,365			302,697
Less: allowance for doubtful accounts		(8,093	)		(8,695	)
Accounts receivable, net	$	461,272		$	294,002

Trade receivables relate to sale of our services and products, for which credit is extended based on our evaluation of the customer’s credit worthiness. Unbilled receivables represent revenues earned but not billed to the customer until future dates, usually within one month. Other receivables consist primarily of amounts due from purchasers of Company property and rebates from suppliers.

Changes in the Company’s allowance for doubtful accounts are as follows:

Years Ended December 31,	2011			2010
(in thousands)
Beginning balance	$	8,695		$	3,210
Bad debt expense		2,868			4,812
Accounts written-off		(3,820	)		(730	)
Recoveries		350			1,403
Ending balance	$	8,093		$	8,695

Note 3: Inventories

Inventories are $100,438,000 at December 31, 2011 and $64,059,000 at December 31, 2010 and consist of raw materials, parts and supplies.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries
Years ended December 31, 2011, 2010 and 2009

Note 4: Property, Plant and Equipment

Property, plant and equipment are presented at cost net of accumulated depreciation and consist of the following:

December 31,	2011			2010
(in thousands)
Land	$	17,403		$	15,053
Buildings and leasehold improvements		94,152			82,457
Operating equipment		990,186			755,028
Capitalized software		18,662			15,899
Furniture and fixtures		5,679			4,690
Vehicles		306,716			219,555
Construction in progress		9,828			1,821
Gross property, plant and equipment		1,442,626			1,094,503
Less: accumulated depreciation		(767,266	)		(641,486	)
Net property, plant and equipment	$	675,360		$	453,017

Depreciation expense was $179.9 million in 2011, $133.4 million in 2010 and $130.6 million in 2009. There are no capital leases outstanding as of December 31, 2011 and December 31, 2010. The Company had accounts payable for purchases of property and equipment of approximately $32.7 million as of December 31 2011, $18.1 million as of December 31, 2010 and $3.7 million as of December 31, 2009.

Note 5: Income Taxes

The following table lists the components of the provision (benefit) for income taxes:

Years ended December 31,	2011		2010			2009
(in thousands)
Current provision (benefit):
Federal	$	91,415	$	56,289		$	(13,490	)
State		12,938		11,180			235
Foreign		1,007		1,059			832
Deferred provision (benefit):
Federal		70,599		22,833			1,698
State		6,475		(571	)		(29	)
Total income tax provision (benefit)	$	182,434	$	90,790		$	(10,754	)

Reconciliation between the federal statutory rate and RPC’s effective tax rate is as follows:

Years ended December 31,	2011			2010			2009
Federal statutory rate		35.0	%		35.0	%		35.0	%
State income taxes, net of federal benefit		3.1			2.9			(2.4	)
Tax credits		(0.2	)		(0.6	)		1.3
Non-deductible expenses		0.4			0.4			(2.6	)
Other		(0.2	)		0.5			0.8
Effective tax rate		38.1	%		38.2	%		32.1	%

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries
Years ended December 31, 2011, 2010 and 2009

Significant components of the Company’s deferred tax assets and liabilities are as follows:

December 31,	2011			2010
(in thousands)
Deferred tax assets:
Self-insurance	$	6,344		$	5,643
Pension		8,922			6,715
State net operating loss carryforwards		1,671			2,955
Bad debts		3,044			3,219
Accrued payroll		2,099			1,460
Stock-based compensation		3,680			2,538
All others		1			232
Valuation allowance		(1,295	)		(1,295	)
Gross deferred tax assets		24,466			21,467
Deferred tax liabilities:
Depreciation		(166,190	)		(89,456	)
Goodwill amortization		(5,707	)		(5,020	)
All Others		(1,314	)		(453	)
Gross deferred tax liabilities		(173,211	)		(94,929	)
Net deferred tax liabilities	$	(148,745	)	$	(73,462	)

Historically and currently, undistributed earnings of the Company’s foreign subsidiaries are considered indefinitely reinvested and, accordingly, no provision for U.S. federal income taxes has been recorded. Deferred taxes are provided for earnings outside the United States when those earnings are not considered indefinitely reinvested.

As of December 31, 2011, the Company has net operating loss carryforwards related to state income taxes of approximately $38.2 million that will expire between 2012 and 2030. As of December 31, 2011 the Company has a valuation allowance of approximately $1.3 million, representing the tax effected amount of loss carryforwards that the Company does not expect to utilize, against the corresponding deferred tax asset.

Total net income tax payments (refunds) were $90,729,000 in 2011, $61,632,000 in 2010, and ($8,351,000) in 2009.

The Company’s policy is to record interest and penalties related to income tax matters as income tax expense. Accrued interest and penalties were immaterial to the financial statements as of December 31, 2011 and 2010.

In accordance with the accounting guidance relating to the accounting for uncertainty in income tax reporting, which provides criteria for the recognition, measurement, presentation and disclosure of uncertain tax positions, the Company did not recognize a material adjustment in the liability for unrecognized income tax benefits.

The Company’s liability for unrecognized tax benefits was $35,000 as of December 31, 2011 and $33,000 as of December 31, 2010, all of which would affect our effective rate if recognized. A reconciliation of the beginning and ending amount of unrecognized tax benefits for 2011 and 2010 are as follows:

Years Ended December 31,	2011		2010
(in thousands)
Beginning balance	$	33	$	30
Additions based on tax positions related to current year		-		-
Additions for tax positions of prior years		2		3
Reductions for tax positions of prior years		-		-
Ending balance	$	35	$	33

The Company and its subsidiaries are subject to U.S. federal and state income tax in multiple jurisdictions. In many cases our uncertain tax positions are related to tax years that remain open and subject to examination by the relevant taxing authorities. The Company’s 2008 through 2011 tax years remain open to examination.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries
Years ended December 31, 2011, 2010 and 2009

It is reasonably possible that the amount of the unrecognized tax benefits with respect to our unrecognized tax positions will increase or decrease in the next 12 months. These changes may be the result of, among other things, state tax settlements under Voluntary Disclosure Agreements. However, quantification of an estimated range cannot be made at this time.

Note 6: Long-Term Debt

On August 31, 2010, the Company replaced its $200 million credit facility with a new $350 million revolving credit facility with Banc of America Securities, LLC, SunTrust Robinson Humphrey, Inc., and Regions Capital Markets as Joint Lead Arrangers and Joint Book Managers, and a syndicate of other lenders. The facility includes a full and unconditional guarantee by the Company’s 100% owned domestic subsidiaries whose assets equal substantially all of the consolidated assets of RPC and its subsidiaries. The subsidiaries of the Company that are not guarantors are considered minor.

The facility has a general term of five years and provides for an unsecured line of credit of up to $350 million, which includes a $50 million letter of credit subfacility, and a $25 million swingline subfacility. The maturity date of all revolving loans under the Credit Agreement is August 31, 2015. The Company has incurred loan origination fees and other debt related costs associated with the Revolving Credit Agreement in the aggregate of approximately $2.3 million. These costs are being amortized to interest expense over the five year term of the loan, and the net amount is classified as non-current other assets on the consolidated balance sheets.

Revolving loans under the facility bear interest at one of the following two rates, at the Company’s election:

● the Base Rate, which is the highest of Bank of America’s “prime rate” for the day of the borrowing, a fluctuating rate per annum equal to the Federal Funds Rate plus 0.50%, and a rate per annum equal to the one (1) month LIBOR rate plus 1.00%, in each case plus a margin that ranges from 0.25% to 1.25% based on a quarterly debt covenant calculation; or

● with respect to any Eurodollar borrowings, Adjusted LIBOR (which equals LIBOR as increased to account for the maximum reserve percentages established by the U.S. Federal Reserve) plus a margin ranging from 1.25% to 2.25%, based upon a quarterly debt covenant calculation.

In addition, the Company pays an annual fee ranging from 0.25% to 0.35%, based on a quarterly debt covenant calculation, of the unused portion of the credit facility.

The facility contains customary terms and conditions, including certain financial covenants and restrictions on indebtedness, dividend payments, business combinations and other related items. Further, the facility contains financial covenants limiting the ratio of the Company’s consolidated debt-to-EBITDA to no more than 2.5 to 1, and limiting the ratio of the Company’s consolidated EBITDA to interest expense to no less than 2 to 1. The Company was in compliance with these covenants as of and for the year ended December 31, 2011.

As of December 31, 2011, RPC has outstanding borrowings of $203.3 million under the facility. Interest incurred on the facility was $4,146,000 in 2011, $3,170,000 in 2010, and $2,327,000 in 2009. The weighted average interest rate was 2.8% in 2011, 3.0% in 2010, and 1.8% in 2009. The Company capitalized interest incurred of $627,000 in 2011, $554,000 in 2010 and $150,000 in 2009 related to facilities and equipment under construction. Additionally there were letters of credit relating to self-insurance programs and contract bids outstanding for $18.4 million as of December 31, 2011.

Cash interest paid (net of capitalized interest) was approximately $3,168,000 in 2011, $1,899,000 in 2010 and $2,192,000 in 2009.

Effective December 2008 the Company entered into an interest rate swap agreement that effectively converted $50 million of the Company’s variable-rate debt to a fixed rate basis, thereby hedging against the impact of potential interest rate changes on future interest expense. Under this agreement the Company and the issuing lender settled on a monthly basis for the difference between a fixed interest rate of 2.07% and a comparable one month LIBOR rate. This agreement terminated on September 8, 2011.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries
Years ended December 31, 2011, 2010 and 2009

Note 7: Accumulated Other Comprehensive (Loss) Income

Accumulated other comprehensive (loss) income consists of the following (in thousands):

	Pension Adjustment			Unrealized Gain (Loss) On Securities			Foreign Currency Translation			Net Loss On Cash Flow Hedge			Total
Balance at December 31, 2009	$	(8,583	)	$	220		$	77		$	(520	)	$	(8,806	)
Change during 2010:
Before-tax amount		(2,125	)		441			329			209			(1,146	)
Tax expense (benefit)		775			(160	)		(120	)		(76	)		419
Total activity in 2010		(1,350	)		281			209			133			(727	)
Balance at December 31, 2010	$	(9,933	)	$	501		$	286		$	(387	)	$	(9,533	)
Change during 2011:
Before-tax amount		(4,800	)		(495	)		(218	)		610			(4,903	)
Tax expense (benefit)		1,752			181			80			(223	)		1,790
Total activity in 2011		(3,048	)		(314	)		(138	)		387			(3,113	)
Balance at December 31, 2011	$	(12,981	)	$	187		$	148		$	-		$	(12,646	)

Note 8: Fair Value Disclosures

The various inputs used to measure assets at fair value establish a hierarchy that distinguishes between assumptions based on market data (observable inputs) and the Company’s assumptions (unobservable inputs). The hierarchy consists of three broad levels as follows:

	1.	Level 1 – Quoted market prices in active markets for identical assets or liabilities.
	2.	Level 2 – Quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-based valuation techniques for which all significant assumptions are observable in the market or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
	3.	Level 3 – Unobservable inputs developed using the Company’s estimates and assumptions, which reflect those that market participants would use.

The following table summarizes the valuation of financial instruments measured at fair value on a recurring basis on the balance sheet as of December 31, 2011 and 2010:

	Fair Value Measurements at December 31, 2011 with:
(in thousands)	Quoted prices in active markets for identical assets		Significant other observable inputs		Significant unobservable inputs
	(Level 1)		(Level 2)		(Level 3)
Assets:
Trading securities	$	-	$	8,251	$	-
Available-for-sale securities – equity securities	$	629	$	-	$	-

	Fair Value Measurements at December 31, 2010 with:
(in thousands)	Quoted prices in active markets for identical assets		Significant other observable inputs		Significant unobservable inputs
	(Level 1)		(Level 2)		(Level 3)
Assets:
Trading securities	$	-	$	8,445	$	-
Available-for-sale securities – equity securities		1,124		-		-
Liabilities:
Interest rate swap	$	-	$	610	$	-

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries
Years ended December 31, 2011, 2010 and 2009

The Company determines the fair value of the marketable securities that are available-for-sale through quoted market prices. The total fair value is the final closing price, as defined by the exchange in which the asset is actively traded, on the last trading day of the period, multiplied by the number of units held without consideration of transaction costs. The trading securities are comprised of the SERP assets, as described in Note 10, and are recorded primarily at their net cash surrender values, which approximates fair value, as provided by the issuing insurance company. Significant observable inputs, in addition to quoted market prices, were used to value the trading securities. As a result, the Company classified these investments as using level 2 inputs.

At December 31, 2011 and 2010, there was $203,300,000 and $121,250,000 outstanding under the Company’s credit facility and based on quotes from the lender (level 2 inputs) is similar to the fair values of these borrowings. The borrowings under our revolving credit facility bear interest at the variable rate described in Note 6. The Company is subject to interest rate risk on the variable component of the interest rate. In 2008 the Company entered into an interest rate swap agreement effectively converting a portion of the outstanding borrowings under the revolving credit facility to a fixed-rate, thereby hedging against the impact of potential interest rate changes on future interest expense; this agreement terminated in September of 2011. The fair value of this swap was negative $610,000 at December 31, 2010 and was reflected in other accrued expenses.

The carrying amounts of other financial instruments reported in the balance sheet for current assets and current liabilities approximate their fair values because of the short maturity of these instruments. The Company currently does not use the fair value option to measure any of its existing financial instruments and has not determined whether or not it will elect this option for financial instruments it may acquire in the future.

Note 9: Commitments and Contingencies

Lease Commitments - Minimum annual rentals, principally for noncancelable real estate and equipment leases with terms in excess of one year, in effect at December 31, 2011, are summarized in the following table:

(in thousands)
2012	$	5,005
2013		5,210
2014		4,205
2015		3,408
2016		1,997
Thereafter		7,080
Total rental commitments	$	26,905

Total rental expense, including short-term rentals, charged to operations was approximately $19,814,000 in 2011, $11,970,000 in 2010 and $10,787,000 in 2009.

Income Taxes - The amount of income taxes the Company pays is subject to ongoing audits by federal and state tax authorities, which often result in proposed assessments. Other long-term liabilities include $35,000 as of December 31, 2011 and $33,000 as of December 31, 2010, that represents the Company’s estimated liabilities for the probable assessments payable.

Sales and Use Taxes - The Company has ongoing sales and use tax audits in various jurisdictions and may be subjected to varying interpretations of statute that could result in unfavorable outcomes that cannot be currently estimated.

Litigation - 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, after consultation with legal counsel, believes that the outcome of all such proceedings, even if determined adversely, would not have a material adverse effect on the Company’s business or financial condition.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries
Years ended December 31, 2011, 2010 and 2009

Note 10: Employee Benefit Plans

Defined Benefit Pension Plan

The Company’s Retirement Income Plan, a trusteed defined benefit pension plan, provides monthly benefits upon retirement at age 65 to substantially all employees with at least one year of service prior to 2002. During 2001, the plan became a multiple employer plan, with Marine Products Corporation as an adopting employer.

The Company’s projected benefit obligation exceeds the fair value of the plan assets under its pension plan by $14.1 million and thus the plan was under-funded as of December 31, 2011.

The following table sets forth the funded status of the Retirement Income Plan and the amounts recognized in RPC’s consolidated balance sheets:

December 31,	2011			2010
(in thousands)
Accumulated Benefit Obligation at end of year	$	38,278		$	35,873

CHANGE IN PROJECTED BENEFIT OBLIGATION:
Benefit obligation at beginning of year	$	35,873		$	32,190
Service cost		—			—
Interest cost		1,916			1,893
Amendments		—			—
Actuarial (gain) loss		2,123			3,362
Benefits paid		(1,634	)		(1,572	)
Projected benefit obligation at end of year	$	38,278		$	35,873
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year	$	26,523		$	24,932
Actual return on plan assets		(1,309	)		2,548
Employer contribution		600			614
Benefits paid		(1,634	)		(1,572	)
Fair value of plan assets at end of year		24,180			26,522

Funded status at end of year	$	(14,098	)	$	(9,351	)

December 31,	2011			2010
(in thousands)
AMOUNTS RECOGNIZED IN THE CONSOLIDATED BALANCE SHEETS CONSIST OF:
Noncurrent assets	$	—		$	—
Current liabilities		—			—
Noncurrent liabilities		(14,098	)		(9,351	)
	$	(14,098	)	$	(9,351	)

December 31,	2011		2010
(in thousands)
AMOUNTS (PRE-TAX) RECOGNIZED IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) CONSIST OF:
Net loss (gain)	$	20,441	$	15,642
Prior service cost (credit)		—		—
Net transition obligation (asset)		—		—
	$	20,441	$	15,642

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries
Years ended December 31, 2011, 2010 and 2009

The accumulated benefit obligation for the Retirement Income Plan at December 31, 2011 and 2010 has been disclosed above. The Company uses a December 31 measurement date for this qualified plan.

Amounts recognized in the consolidated balance sheets consist of:

December 31,	2011			2010
(in thousands)
Funded status	$	(14,098	)	$	(9,351	)
SERP contributions/deferrals		(10,347	)		(9,046	)
Long-term pension liabilities	$	(24,445	)	$	(18,397	)

RPC’s funding policy is to contribute to the defined benefit pension plan the amount required, if any, under the Employee Retirement Income Security Act of 1974. RPC contributed $600,000 in 2011 and $614,000 in 2010.

The components of net periodic benefit cost are summarized as follows:

Years ended December 31,	2011			2010			2009
(in thousands)
Service cost for benefits earned during the period	$	—		$	—		$	—
Interest cost on projected benefit obligation		1,916			1,893			1,938
Expected return on plan assets		(1,831	)		(1,720	)		(1,521	)
Amortization of net loss		463			409			1,538
Net periodic benefit plan cost (credit)	$	548		$	582		$	1,955

The Company recognized pre-tax decreases (increases) to the funded status in comprehensive loss of $4,800,000 in 2011, $2,125,000 in 2010, and $(1,413,000) in 2009. There were no previously unrecognized prior service costs as of December 31, 2011, 2010 and 2009. The pre-tax amounts recognized in comprehensive loss for the years ended December 31, 2011, 2010 and 2009 are summarized as follows:

(in thousands)	2011			2010			2009
Net loss (gain)	$	5,263		$	2,534		$	125
Amortization of net (loss) gain		(463	)		(409	)		(1,538	)
Net transition obligation (asset)		—			—			—
Amount recognized in other comprehensive loss	$	4,800		$	2,125		$	(1,413	)

The amounts in accumulated other comprehensive loss expected to be recognized as components of net periodic benefit cost in 2012 are as follows:

(in thousands)	2012
Amortization of net loss (gain)	$	673
Prior service cost (credit)		—
Net transition obligation (asset)		—
Estimated net periodic benefit plan cost	$	673

The weighted average assumptions as of December 31 used to determine the projected benefit obligation and net benefit cost were as follows:

December 31,	2011			2010			2009
Projected Benefit Obligation:
Discount rate		5.00	%		5.49	%		6.00	%
Rate of compensation increase		N/A			N/A			N/A
Net Benefit Cost:
Discount rate		5.49	%		6.00	%		6.84	%
Expected return on plan assets		7.00	%		7.00	%		7.00	%
Rate of compensation increase		N/A			N/A			N/A

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries

Years ended December 31, 2011, 2010 and 2009

The Company’s expected return on assets assumption is derived from a detailed periodic assessment conducted by its management and its investment adviser. It includes a review of anticipated future long-term performance of individual asset classes and consideration of the appropriate asset allocation strategy given the anticipated requirements of the plan to determine the average rate of earnings expected on the funds invested to provide for the pension plan benefits. While the study gives appropriate consideration to recent fund performance and historical returns, the rate of return assumption is derived primarily from a long-term, prospective view. Based on its recent assessment, the Company has concluded that its expected long-term return assumption of seven percent is reasonable.

The Plan’s weighted average asset allocation at December 31, 2011 and 2010 by asset category along with the target allocation for 2012 are as follows:

Asset Category	Target Allocation for 2012			Percentage of Plan Assets as of December 31, 2011			Percentage of Plan Assets as of December 31, 2010
Debt Securities – Core Fixed Income		15.0% – 50.0	%		23.2	%		26.2	%
Tactical – Fund of Equity and Debt Securities		10.0% – 20.0	%		16.3	%		10.1	%
Domestic Equity Securities		20.0% – 40.0	%		15.2	%		26.4	%
Global Equity Securities		10.0% – 20.0	%		14.8	%		4.3	%
International Equity Securities		10.0% – 20.0	%		14.6	%		13.8	%
Real Estate		0.0% – 10.0	%		5.6	%		4.6	%
Real Return		0.0% – 10.0	%		9.6	%		5.6	%
Other		0.0% – 5.0	%		0.7	%		9.0	%
Total		100	%		100.0	%		100.0	%

The Company’s overall investment strategy is to achieve a mix of approximately 70 percent of investments for long-term growth and 30 percent for near-term benefit payments, with a wide diversification of asset types, fund strategies and fund managers. Equity securities primarily include investments in large-cap and mid-cap companies. Fixed-income securities include corporate bonds of companies in diversified securities, mortgage-backed securities, and U.S. Treasuries. Other types of investments include hedge funds and private equity funds that follow several different investment strategies. For each of the asset categories in the pension plan, the investment strategy is identical – maximize the long-term rate of return on plan assets with an acceptable level of risk in order to minimize the cost of providing pension benefits. The investment policy establishes a target allocation for each asset class which is rebalanced as required. The plans utilize a number of investment approaches, including individual market securities, equity and fixed income funds in which the underlying securities are marketable, and debt funds to achieve this target allocation.

Some of our assets, primarily our private equity, real estate and hedge funds, do not have readily determinable market values given the specific investment structures involved and the nature of the underlying investments. For the December 31, 2011 plan asset reporting, publicly traded asset pricing was used where possible. For assets without readily determinable values, estimates were derived from investment manager discussions focusing on underlying fundamentals and significant events.

Included among the asset categories for the Plans’ investments are real estate and other investments comprised of investments in real estate and hedge funds. These investments are categorized as level 3 investments and are valued using significant non-observable inputs which do not have a readily determinable fair value. In accordance with ASU No. 2009-12 “Investments In Certain Entities That Calculate Net Asset Value per Share (Or Its Equivalent),” these investments are valued based on the net asset value per share calculated by the funds in which the plan has invested. These valuations are subject to judgments and assumptions of the funds which may prove to be incorrect, resulting in risks of incorrect valuation of these investments. The Company seeks to mitigate against these risks by evaluating the appropriateness of the funds’ judgments and assumptions by reviewing the financial data included in the funds’ financial statements for reasonableness.

The following tables present our plan assets using the fair value hierarchy as of December 31, 2011 and December 31, 2010. The fair value hierarchy has three levels based on the reliability of the inputs used to determine fair value. See Note 8 for a brief description of the three levels under the fair value hierarchy.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries

Years ended December 31, 2011, 2010 and 2009

Fair Value Hierarchy as of December 31, 2011:

Investments (in thousands)		Total		Level 1		Level 2		Level 3
Cash and Cash Equivalents	(1)	$	175	$	175	$	-	$	-
Fixed Income Securities	(2)		5,608		-		5,608		-
Domestic Equity Securities			3,680		3,680		-		-
Global Equity Securities			3,568		3,568		-		-
International Equity Securities	(3)		3,537		1,671		1,866		-
Tactical Composite	(4)		3,935		-		3,935		-
Real Estate	(5)		1,350		-		-		1,350
Real Return	(6)		2,327		-		2,327
		$	24,180	$	9,094	$	13,736	$	1,350

Fair Value Hierarchy as of December 31, 2010:

Investments (in thousands)		Total		Level 1		Level 2		Level 3
Cash and Cash Equivalents	(1)	$	2,081	$	2,081	$	-	$	-
Fixed Income Securities	(2)		6,937		-		6,937		-
Domestic Equity Securities			7,015		7,015		-		-
Global Equity Securities			1,153		-		1,153		-
International Equity Securities	(3)		3,672		1,636		2,036		-
Tactical Composite	(4)		2,687		-		2,687		-
Real Estate	(5)		1,210		-		-		1,210
Real Return	(6)		1,492		-		1,492		-
Alternative Investments	(7)		275		-		-		275
		$	26,522	$	10,732	$	14,305	$	1,485

(1)

Cash and cash equivalents, which are used to pay benefits and plan administrative expenses, are held in Rule 2a-7 money market funds.

(2)

Fixed income securities are primarily valued using a market approach with inputs that include broker quotes, benchmark yields, base spreads and reported trades.

(3)

Some international equity securities are valued using a market approach based on the quoted market prices of identical instruments in their respective markets.

(4)

Tactical composite funds invest in stocks, bonds and cash, both domestic and international. These assets are valued primarily using a market approach based on the quoted market prices of identical instruments in their respective markets.

(5)

Real estate fund values are primarily reported by the fund manager and are based on valuation of the underlying investments, which include inputs such as cost, discounted future cash flows, independent appraisals and market based comparable data.

(6)

Real return funds invest in global equities, commodities and inflation protected core bonds that are valued primarily using a market approach based on the quoted market prices of identical instruments in their respective markets.

(7)

Alternative investments consist of fund-of-fund LLC or commingled fund structures. The LLCs are primarily valued based on Net Asset Values [NAV] calculated by the fund and are not publicly available. Liquidity for the LLCs is monthly and is subject to liquidity of the underlying funds. The commingled fund NAV is calculated by the manager on a daily basis and has monthly liquidity.

The following table presents a reconciliation of Level 3 assets held during the year ended December 31, 2011:

Investments (in thousands)	Balance at December 31, 2010		Net Realized and Unrealized Gains/(Losses)			Net Purchases, Issuances and Settlements			Net Transfers In to (Out of) Level 3		Balance at December 31, 2011

Real Estate	$	1,210	$	142		$	-		$	-	$	1,352

Alternative Investments		275		(2	)		(273	)		-		-
	$	1,485	$	140		$	(273	)	$	-	$	1,352

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries

Years ended December 31, 2011, 2010 and 2009

The following table presents a reconciliation of Level 3 assets held during the year ended December 31, 2010:

Investments (in thousands)	Balance at December 31, 2009		Net Realized and Unrealized Gains/(Losses)			Net Purchases, Issuances and Settlements			Net Transfers In to (Out of) Level 3			Balance at December 31, 2010

Real Estate	$	1,039	$	171		$	-		$	-		$	1,210

Alternative Investments		4,357		(235	)		(2,127	)		(1,720	)		275
	$	5,396	$	(64	)	$	(2,127	)	$	(1,720	)	$	1,485

The Company expects to contribute approximately $600,000 to the Retirement Income Plan in 2012 and does not expect to receive a refund in 2012.

The Company estimates that the future benefits payable for the Retirement Income Plan over the next ten years are as follows:

(in thousands)
2012			1,730
2013			1,841
2014			1,940
2015			2,020
2016			2,212
2017-2021			12,027

Supplemental Executive Retirement Plan (SERP)

The Company permits selected highly compensated employees to defer a portion of their compensation into the SERP. The SERP assets are invested primarily in company-owned life insurance (“COLI”) policies as a funding source for the deferred compensation obligations in the SERP. The assets are subject to claims by creditors, and the Company can designate them to another purpose at any time. Investments in COLI policies consisted of $17.7 million in variable life insurance policies as of December 31, 2011 and $17.3 million as of December 31, 2010. In the COLI policies, the Company is able to allocate investment of the assets across a set of choices provided by the insurance company, including fixed income securities and equity funds. The COLI policies are recorded at their net cash surrender values, which approximates fair value, as provided by the issuing insurance company, whose Standard & Poor’s credit rating was A+.

The Company classifies the SERP assets as trading securities as described in Note 1. The fair value of these assets totaled $8,251,000 as of December 31, 2011 and $8,445,000 as of December 31, 2010. The SERP assets are reported in other assets on the balance sheet. The changes in the fair value of these assets, and normal insurance expenses are recorded in the consolidated statement of operations as part of other income (expense), net. Trading gains (losses) related to the SERP assets totaled $(194,000) in 2011, $701,000 for 2010, and $1,373,000 for 2009. The SERP deferrals and the contributions are recorded on the balance sheet in pension liabilities with any change in the fair value of the liabilities recorded as compensation cost in the statement of operations.

401(k) Plan

RPC sponsors a defined contribution 401(k) plan that is available to substantially all full-time employees with more than three months of service. This plan allows employees to make tax-deferred contributions from one to 25 percent of their annual compensation, not exceeding the permissible contribution imposed by the Internal Revenue Code. RPC matches 50 percent of each employee’s contributions that do not exceed six percent of the employee’s compensation, as defined by the plan. Employees vest in the RPC contributions after three years of service. The charges to expense for the Company’s contributions to the 401(k) plan were approximately $4,074,000 in 2011, $2,485,000 in 2010, and $2,621,000 in 2009.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries

Years ended December 31, 2011, 2010 and 2009

Stock Incentive Plans

The Company has issued stock options and restricted stock to employees under two 10 year stock incentive plans that were approved by stockholders in 1994 and 2004. The 1994 plan expired in 2004. The Company reserved 7,593,750 shares of common stock under the 2004 Plan which expires in 2014. This plan provides for the issuance of various forms of stock incentives, including, among others, incentive and non-qualified stock options and restricted stock which are discussed in detail below. As of December 31, 2011, there were approximately 2,059,000 shares available for grants. The Company issues new shares from its authorized but unissued share pool.

The Company recognizes compensation expense for the unvested portion of awards outstanding over the remainder of the service period. The compensation cost recorded for these awards is based on their fair value at grant date less the cost of estimated forfeitures. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods to reflect actual forfeitures. Cash flows related to share-based payment awards to employees that result in tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing activity in the accompanying consolidated statements of cash flows.

Pre-tax stock-based employee compensation expense was $8,075,000 in 2011 ($5,128,000 after tax), $4,909,000 in 2010 ($3,117,000 after tax), and $4,440,000 in 2009 ($2,819,000 after tax).

Stock Options

Stock options are granted at an exercise price equal to the fair market value of the Company’s common stock at the date of grant except for grants of incentive stock options to owners of greater than 10 percent of the Company’s voting securities which must be made at 110 percent of the fair market value of the Company’s common stock. Options generally vest ratably over a period of five years and expire in 10 years, except incentive stock options granted to owners of greater than 10 percent of the Company’s voting securities, which expire in five years.

The Company estimates the fair value of stock options as of the date of grant using the Black-Scholes option pricing model. The Company has not granted stock options to employees since 2003.

Transactions involving RPC’s stock options for the year ended December 31, 2011 were as follows:

	Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life		Aggregate Intrinsic Value
Outstanding at January 1, 2011		1,070,388		$	2.26	1.23 years
Granted		-			-	N/A
Exercised		(600,594	)		2.50	N/A
Forfeited		-			-	N/A
Expired		-			-	N/A
Outstanding and exercisable at December 31, 2011		469,794		$	1.96	0.99 years	$	7,653,000

The total intrinsic value of stock options exercised was approximately $11,882,000 during 2011, $2,293,000 during 2010 and $1,519,000 during 2009. Tax benefits associated with the exercise of stock options exercised totaled $799,000 during 2011 and were credited to capital in excess of par value and are classified as financing cash flows. There were no recognized excess tax benefits associated with the exercise of stock options during 2010. Recognized excess tax benefits associated with the exercise of stock options were approximately $353,000 during 2009.

Restricted Stock

The Company has granted employees two forms of restricted stock: time lapse restricted and performance restricted.

Time lapse restricted shares

Time lapse restricted shares vest after a stipulated number of years from the grant date, depending on the terms of the issue. Time lapse restricted shares issued in years 2003 and prior vest after ten years. Time lapse restricted shares issued subsequent to fiscal year 2003 vest in 20 percent increments annually starting with the second anniversary of the grant, over six years from the date of grant. Grantees receive dividends declared and retain voting rights for the granted shares.

Performance restricted shares

The performance restricted shares are granted, but not earned and issued until certain five-year tiered performance criteria are met. The performance criteria are predetermined market prices of RPC’s common stock. On the date the common stock appreciates to each level (determination date), 20 percent of performance shares are earned. Once earned, the performance shares vest five years from the determination date. After the determination date, the grantee will receive dividends declared and voting rights to the shares. The Company has not granted performance restricted shares since 1999.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries

Years ended December 31, 2011, 2010 and 2009

The agreements under which the restricted stock is issued provide that shares awarded may not be sold or otherwise transferred until restrictions established under the stock plans have lapsed. Upon termination of employment from RPC or, in certain cases, termination of employment from Marine Products Corporation or Chaparral Boats, Inc., shares with restrictions must be returned to RPC.

The following is a summary of the changes in non-vested restricted shares for the year ended December 31, 2011:

	Shares			Weighted Average Grant-Date Fair Value
Non-vested shares at January 1, 2011		3,007,353		$	7.58
Granted		740,500			17.39
Vested		(664,248	)		7.43
Forfeited		(123,051	)		9.18
Non-vested shares at December 31, 2011		2,960,554		$	9.93

The fair value of restricted awards is based on the market price of the Company’s stock on the date of the grant and is amortized to compensation expense on a straight-line basis over the requisite service period. The weighted average grant date fair value of these restricted stock awards was $17.39, $8.21 and $5.70 for the years ended December 31, 2011, 2010 and 2009. The total fair value of shares vested was approximately $11,861,000 during 2011, $5,079,000 during 2010 and $3,976,000 during 2009. The tax benefit for compensation tax deductions in excess of compensation expense was credited to capital in excess of par value aggregating $2,572,000 for 2011, $651,000 for 2010 and $1,068,000 for 2009. The excess tax deductions are classified as a financing activity in the accompanying consolidated statements of cash flows.

Other Information

As of December 31, 2011, total unrecognized compensation cost related to non-vested restricted shares was approximately $25,614,000 which is expected to be recognized over a weighted-average period of 3.5 years. As of December 31, 2011, there was no unrecognized compensation cost related to non-vested stock options.

The Company received cash from options exercised of $728,000 during 2011, $240,000 during 2010, and $122,000 during 2009. These cash receipts are classified as a financing activity in the accompanying consolidated statements of cash flows. The fair value of shares tendered to exercise employee stock options totaled approximately $720,000 during 2011, $144,000 during 2010 and $389,000 during 2009 and have been excluded from the consolidated statements of cash flows.

Note 11: Related Party Transactions

Related Party Transactions

Marine Products Corporation

Other

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries

Years ended December 31, 2011, 2010 and 2009

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.

Note 12: Business Segment Information

RPC’s service lines have been aggregated into two reportable oil and gas services 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. Corporate includes selected administrative costs incurred by the Company.

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. These services include pressure pumping services, coiled tubing, snubbing, nitrogen pumping, well control consulting and firefighting, downhole tools, wireline, and fluid pumping services. These Technical Services are primarily used in the completion, production and maintenance of oil and gas wells. The principal markets for this segment include the United States, including the Gulf of Mexico, the mid-continent, southwest, Rocky Mountain and Appalachian regions, and international locations including primarily Africa, Canada, China, Latin America, the Middle East and New Zealand. 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, inspection and storage services, and oilfield training services. The demand for these services tends to be influenced primarily by customer drilling-related activity levels. The principal markets for this segment include the United States, including the Gulf of Mexico, the mid-continent and Appalachian regions, and international locations, including primarily Canada, Latin America, and the Middle East. Customers include domestic operations of major multi-national and independent oil and gas producers, and selected nationally-owned oil companies.

The accounting policies of the reportable segments are the same as those described in Note 1 to these consolidated financial statements. RPC evaluates the performance of its segments based on revenues, operating profits and return on invested capital. Gains or losses on disposition of assets are reviewed by the Company’s chief decision maker on a consolidated basis, and accordingly the Company does not report gains or losses at the segment level. Inter-segment revenues are generally recorded in segment operating results at prices that management believes approximate prices for arm’s length transactions and are not material to operating results.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RPC, Inc. and Subsidiaries

Years ended December 31, 2011, 2010 and 2009

Summarized financial information concerning RPC’s reportable segments for the years ended December 31, 2011, 2010 and 2009 are shown in the following table:

	Technical Services			Support Services			Corporate			(Loss) Gain on disposition of assets, net			Total
(in thousands)
2011
Revenues	$	1,663,793		$	146,014		$	—		$	—		$	1,809,807
Operating profit (loss)		451,259			51,672			(17,019	)		(3,831	)		482,081
Capital expenditures		369,568			42,837			3,995			—			416,400
Depreciation and amortization		152,252			27,464			189			—			179,905
Identifiable assets		1,103,341			177,974			56,896			—			1,338,211
2010
Revenues	$	979,834		$	116,550		$	—		$	—		$	1,096,384
Operating profit (loss)		217,144			31,086			(13,143	)		3,758			238,845
Capital expenditures		163,362			23,012			1,112			—			187,486
Depreciation and amortization		106,480			26,640			240			—			133,360
Identifiable assets		668,081			158,577			61,213			—			887,871
2009
Revenues	$	513,289		$	74,574		$	—		$	—		$	587,863
Operating profit (loss)		(20,328	)		(1,636	)		(12,231	)		1,143			(33,052	)
Capital expenditures		48,175			19,220			435			—			67,830
Depreciation and amortization		101,780			28,085			715			—			130,580
Identifiable assets		453,133			144,905			51,005			—			649,043

The following summarizes selected information between the United States and all international locations combined for the years ended December 31, 2011, 2010 and 2009. The revenues are presented based on the location of the use of the product or service. Assets related to international operations are less than 10 percent of RPC’s consolidated assets, and therefore are not presented.

Years ended December 31,	2011		2010		2009
(in thousands)
United States Revenues	$	1,757,661	$	1,041,461	$	543,026
International Revenues		52,146		54,923		44,837
	$	1,809,807	$	1,096,384	$	587,863

Note 13: Stock Split

On January 24, 2012, RPC’s Board of Directors declared a three-for-two stock split of the Company’s common shares. The split will be effected by issuing an additional share of common stock for every two shares of common stock held. The additional shares will be distributed on March 9, 2012 to stockholders of record on February 10, 2012. The stock split will increase the Company’s outstanding shares from approximately 146,333,777 shares to 219,500,666 shares. Our historical outstanding shares will be recast upon the distribution.

Below is an estimate of the pro forma effects of the stock split on the Company’s Stockholders’ equity.

(in thousands)	December 31, 2011 (Audited)			Adjustment (Unaudited)			December 31, 2011 (Pro forma) (Unaudited)
STOCKHOLDERS’ EQUITY

Preferred stock, $0.10 par value, 1,000,000 shares authorized, none issued	$	-		$			$	-
Common stock, $0.10 par value, 349,000,000 shares authorized, Shares issued(1) and outstanding – 221,187,660 outstanding in 2011 and 222,263,993 outstanding in 2010	$	14,746			7,373			22,119
Capital in excess of par value		-
Retained earnings		760,492			(7,373	)		753,119
Accumulated other comprehensive loss		(12,646	)					(12,646	)
Total stockholders’ equity	$	762,592		$	-		$	762,592

(1) Shares issued increased as follows: 2011- 73,729,220; 2010 – 74,087,998

Below is an estimate of the pro forma effects of the stock split on the Company’s earnings per share:

(in thousands, except per share amounts)	December 31, 2011 (Audited)		Adjustment (unaudited)			December 31,2011 (Pro forma) (unaudited)
Net income	$	296,381	$	-		$	296,381

Basic Earnings Per Share		2.04		(0.68	)		1.36
Diluted Earnings Per Share		2.02		(0.67	)		1.35

Shares used for computation:
Basic		145,122		72,561			217,683
Diluted		146,833		73,417			220,250

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of disclosure controls and procedures — The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in its Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms, and that such information is accumulated and communicated to its management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, December 31, 2011 (the “Evaluation Date”), the Company carried out an evaluation, under the supervision and with the participation of its management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of its disclosure controls and procedures. Based upon this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective at a reasonable assurance level as of the Evaluation Date.

Management’s report on internal control over financial reporting — Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Management’s report on internal control over financial reporting is included on page 30 of this report. Grant Thornton LLP, the Company’s independent registered public accounting firm, has audited the effectiveness of internal control as of December 31, 2011 and issued a report thereon which is included on page 31 of this report.

Changes in internal control over financial reporting — Management’s evaluation of changes in internal control did not identify any changes in the Company’s internal control over financial reporting that occurred during the Company’s most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information concerning directors and executive officers will be included in the RPC Proxy Statement for its 2012 Annual Meeting of Stockholders, in the section titled “Election of Directors.” This information is incorporated herein by reference. Information about executive officers is contained on page 13 of this document.

Audit Committee and Audit Committee Financial Expert

Information concerning the Audit Committee of the Company and the Audit Committee Financial Expert(s) will be included in the RPC Proxy Statement for its 2012 Annual Meeting of Stockholders, in the section titled “Corporate Governance and Board of Directors, Committees and Meetings – Audit Committee.” This information is incorporated herein by reference.

Code of Ethics

RPC, Inc. has a Code of Business Conduct that applies to all employees. In addition, the Company has a Code of Business Conduct and Ethics for Directors and Executive Officers and Related Party Transaction Policy. Both of these documents are available on the Company’s Web site at www.rpc.net. Copies are available at no charge by writing to Attention: Human Resources, RPC, Inc., 2801 Buford Highway, Suite 520, N.E., Atlanta, GA 30329.

RPC, Inc. intends to satisfy the disclosure requirement under Item 10 of Form 8-K regarding an amendment to, or waiver from, a provision of its code that relates to any elements of the code of ethics definition enumerated in SEC rules by posting such information on its internet website, the address of which is provided above.

Section 16(a) Beneficial Ownership Reporting Compliance

Information regarding compliance with Section 16(a) of the Exchange Act will be included under “Section 16(a) Beneficial Ownership Reporting Compliance” in the Company’s Proxy Statement for its 2012 Annual Meeting of Stockholders, which is incorporated herein by reference.

Item 11. Executive Compensation

Information concerning director and executive compensation will be included in the RPC Proxy Statement for its 2012 Annual Meeting of Stockholders, in the sections titled “Compensation Committee Interlocks and Insider Participation,” “Director Compensation,” “Compensation Discussion and Analysis,” “Compensation Committee Report” and “Executive Compensation.” This information is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information concerning security ownership will be included in the RPC Proxy Statement for its 2012 Annual Meeting of Stockholders, in the sections “Capital Stock” and “Election of Directors.” This information is incorporated herein by reference.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth certain information regarding equity compensation plans as of December 31, 2011.

Plan Category	(A) Number of Securities To Be Issued Upon Exercise of Outstanding Options, Warrants and Rights		(B) Weighted Average Exercise Price of Outstanding Options, Warrants and Rights		(C) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (A))
Equity compensation plans approved by securityholders		469,794	$	1.96		2,058,679	(1)
Equity compensation plans not approved by securityholders		-		-		-
Total		469,794	$	1.96		2,058,679

(1)	All of the securities can be issued in the form of restricted stock or other stock awards.

See Note 10 to the Consolidated Financial Statements for information regarding the material terms of the equity compensation plans.

Item 13. Certain Relationships and Related Party Transactions and Director Independence

Information concerning certain relationships and related party transactions will be included in the RPC Proxy Statement for its 2012 Annual Meeting of Stockholders, in the sections titled, “Certain Relationships and Related Party Transactions.” Information regarding director independence will be included in the RPC Proxy Statement for its 2012 Annual Meeting of Stockholders in the section titled “Director Independence and NYSE Requirements.” This information is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services

Information regarding principal accountant fees and services will be included in the section titled “Independent Registered Public Accounting Firm” in the RPC Proxy Statement for its 2012 Annual Meeting of Stockholders. This information is incorporated herein by reference.

PART IV

Item 15. Exhibits and Financial Statement Schedules

Consolidated Financial Statements, Financial Statement Schedule and Exhibits

1.	Consolidated financial statements listed in the accompanying Index to Consolidated Financial Statements and Schedule are filed as part of this report.

2.	The financial statement schedule listed in the accompanying Index to Consolidated Financial Statements and Schedule is filed as part of this report.

3.	Exhibits listed in the accompanying Index to Exhibits are filed as part of this report. The following such exhibits are management contracts or compensatory plans or arrangements:

	10.1	2004 Stock Incentive Plan (incorporated herein by reference to Appendix B to the Registrant’s definitive Proxy Statement filed on March 24, 2004).

	10.6	Form of stock option grant agreement (incorporated herein by reference to Exhibit 10.1 to Form 10-Q filed on November 2, 2004).

	10.7	Form of time lapse restricted stock grant agreement (incorporated herein by reference to Exhibit 10.2 to Form 10-Q filed on November 2, 2004).

	10.8	Form of performance restricted stock grant agreement (incorporated herein by reference to Exhibit 10.3 to Form 10-Q filed on November 2, 2004).

	10.9	Supplemental Retirement Plan (incorporated herein by reference to Exhibit 10.11 to the Form 10-K filed on March 16, 2005).

	10.10	First Amendment to 1994 Employee Stock Incentive Plan and 2004 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.14 to the Form 10-K filed on March 2, 2007).

	10.11	Performance-Based Incentive Cash Compensation Plan (incorporated by reference to Exhibit 10.1 to the Form 8-K filed April 28, 2006).

	10.12	Summary of Compensation Arrangements with Executive Officers (incorporated herein by reference to Exhibit 10.17 to the Form 10-K filed on March 3, 2010).

	10.14	Summary of Compensation Arrangements with Non-Employee Directors (incorporated herein by reference to Exhibit 10.19 to the Form 10-K filed on March 4, 2011).

Exhibits (inclusive of item 3 above):

Exhibit Number		Description
3.1A		Restated certificate of incorporation of RPC, Inc. (incorporated herein by reference to exhibit 3.1 to the Annual Report on Form 10-K for the fiscal year ended December 31, 1999).

3.1B		Certificate of Amendment of Certificate of Incorporation of RPC, Inc. (incorporated by reference to Exhibit 3.1(B) to the Quarterly Report on Form 10-Q filed May 8, 2006).

3.1C		Certificate of Amendment of Certificate of Incorporation of RPC, Inc. (incorporated by reference to Exhibit 3.1(C) to the Quarterly Report on Form 10-Q filed August 2, 2011).

3.2		Bylaws of RPC, Inc. (incorporated herein by reference to Exhibit 3.1 to the Form 8-K filed on October 25, 2007).

4		Form of Stock Certificate (incorporated herein by reference to the Annual Report on Form 10-K for the fiscal year ended December 31, 1998).

10.1		2004 Stock Incentive Plan (incorporated herein by reference to Appendix B to the Registrant’s definitive Proxy Statement filed on March 24, 2004).

10.2		Agreement Regarding Distribution and Plan of Reorganization, dated February 12, 2001, by and between RPC, Inc. and Marine Products Corporation (incorporated herein by reference to Exhibit 10.2 to the Form 10-K filed on February 13, 2001).

10.3		Employee Benefits Agreement dated February 12, 2001, by and between RPC, Inc., Chaparral Boats, Inc. and Marine Products Corporation (incorporated herein by reference to Exhibit 10.3 to the Form 10-K filed on February 13, 2001).

10.4		Transition Support Services Agreement dated February 12, 2001 by and between RPC, Inc. and Marine Products Corporation (incorporated herein by reference to Exhibit 10.4 to the Form 10-K filed on February 13, 2001).

10.5		Tax Sharing Agreement dated February 12, 2001, by and between RPC, Inc. and Marine Products Corporation (incorporated herein by reference to Exhibit 10.5 to the Form 10-K filed on February 13, 2001).

10.6		Form of stock option grant agreement (incorporated herein by reference to Exhibit 10.1 to the Form 10-Q filed on November 2, 2004).

10.7		Form of time lapse restricted stock grant agreement (incorporated herein by reference to Exhibit 10.2 to the Form 10-Q filed on November 2, 2004).

10.8		Form of performance restricted stock grant agreement (incorporated herein by reference to Exhibit 10.3 to the Form 10-Q filed on November 2, 2004).

10.9		Supplemental Retirement Plan (incorporated herein by reference to Exhibit 10.11 to the Form 10-K filed on March 16, 2005).

10.10		First Amendment to 1994 Employee Stock Incentive Plan and 2004 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.14 to the Form 10-K filed on March 2, 2007).

10.11		Performance-Based Incentive Cash Compensation Plan (incorporated by reference to Exhibit 10.1 to the Form 8-K filed April 28, 2006).

10.12		Summary of Compensation Arrangements with Executive Officers (incorporated herein by reference to Exhibit 10.17 to the Form 10-K filed on March 3, 2010).

10.13		Second Amendment to Revolving Credit Agreement dated as of September 2, 2009 by and among the Company, the several banks and other financial institutions from time to time party thereto and SunTrust Bank, in its capacity as administrative agent (incorporated herein by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K dated September 2, 2009).

10.14		Summary of Compensation Arrangements with Non-Employee Directors (incorporated herein by reference to Exhibit 10.19 to the Form 10-K filed on March 4, 2011).

10.15		Credit Agreement dated August 31, 2010 between the Company, Banc of America, N.A., SunTrust Bank, Regions Bank and certain other lenders party thereto (incorporated herein by reference to Exhibit 99.1 to the Form 8-K filed on September 7, 2010)

10.16		Amendment and No. 1 to Credit Agreement dated as of June 16, 2011 between the Company, the Subsidiary Loan Parties party thereto, Bank of America, N.A. and certain other lenders party thereto.

21		Subsidiaries of RPC

23		Consent of Grant Thornton LLP

24		Powers of Attorney for Directors

31.1		Section 302 certification for Chief Executive Officer

31.2		Section 302 certification for Chief Financial Officer

32.1		Section 906 certifications for Chief Executive Officer and Chief Financial Officer

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

SIGNATURES

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

	RPC, Inc.

	/s/ Richard A. Hubbell
	Richard A. Hubbell
	President and Chief Executive Officer
	(Principal Executive Officer)

	February 29, 2012

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

	Name		Title		Date

/s/ Richard A. Hubbell
Richard A. Hubbell		President and Chief Executive Officer (Principal Executive Officer)		February 29, 2012
/s/ Ben M. Palmer
Ben M. Palmer		Chief Financial Officer (Principal Financial and Accounting Officer)		February 29, 2012

The Directors of RPC (listed below) executed a power of attorney, appointing Richard A. Hubbell their attorney-in-fact, empowering him to sign this report on their behalf.

R. Randall Rollins, Director	James A. Lane, Jr., Director

Wilton Looney, Director	Linda H. Graham, Director

Gary W. Rollins, Director	Bill J. Dismuke, Director

Henry B. Tippie, Director	Larry L. Prince, Director

James B. Williams, Director

/s/ Richard A. Hubbell
Richard A. Hubbell
Director and as Attorney-in-fact
February 29, 2012

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS, REPORTS AND SCHEDULE

The following documents are filed as part of this report.

FINANCIAL STATEMENTS AND REPORTS	PAGE

Management’s Report on Internal Control Over Financial Reporting	30

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting	31

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements	32

Consolidated Balance Sheets as of December 31, 2011 and 2010	33

Consolidated Statements of Operations for the three years ended December 31, 2011	34

Consolidated Statements of Stockholders’ Equity for the three years ended December 31, 2011	35

Consolidated Statements of Cash Flows for the three years ended December 31, 2011	36

Notes to Consolidated Financial Statements	37 - 58

SCHEDULE
Schedule II — Valuation and Qualifying Accounts	65

Schedules not listed above have been omitted because they are not applicable or the required information is included in the consolidated financial statements or notes thereto.

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

	For the years ended December 31, 2011, 2010 and 2009
(in thousands)		Balance at Beginning of Period		Charged to Costs and Expenses		Net (Deductions) Recoveries				Balance at End of Period
Year ended December 31, 2011
Allowance for doubtful accounts		$	8,694	$	2,868	$	(3,469	)	(1)	$	8,093
Deferred tax asset valuation allowance		$	1,295	$	—	$	—			$	1,295
Year ended December 31, 2010
Allowance for doubtful accounts		$	3,210	$	4,812	$	672		(1)	$	8,694
Deferred tax asset valuation allowance		$	1,550	$	—	$	(255	)	(2)	$	1,295
Year ended December 31, 2009
Allowance for doubtful accounts		$	6,199	$	660	$	(3,649	)	(1)	$	3,210
Deferred tax asset valuation allowance		$	1,454	$	96	$	—		(2)	$	1,550

(1)	Net (deductions) recoveries in the allowance for doubtful accounts principally reflect the write-off of previously reserved accounts net of recoveries.
(2)	The valuation allowance for deferred tax assets is increased or decreased each year to reflect the state net operating losses that management believes will not be utilized before they expire.

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

Quarters ended	March 31		June 30		September 30		December 31
(in thousands except per share data)
2011
Revenues	$	381,761	$	443,029	$	502,235	$	482,782
Net income	$	65,524	$	73,165	$	83,111	$	74,581
Net income per share — basic (a)	$	0.45	$	0.50	$	0.57	$	0.51
Net income per share — diluted (a)	$	0.45	$	0.50	$	0.57	$	0.51
2010
Revenues	$	213,144	$	252,896	$	302,200	$	328,144
Net income	$	13,400	$	31,602	$	46,269	$	55,471
Net income per share — basic (a)	$	0.09	$	0.22	$	0.32	$	0.38
Net income per share — diluted (a)	$	0.09	$	0.21	$	0.31	$	0.38

(a)	The sum of the income (loss) per share for the four quarters may differ from annual amounts due to the required method of computing the weighted average shares for the respective periods.