Edgar Filing: RPC INC

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

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

For the fiscal year ended December 31, 2013

Commission File No. 1-8726

RPC, INC.

Delaware

(State of Incorporation)

58-1550825

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

2801 BUFORD HIGHWAY NE, 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, 2013, the last business day of the registrant’s most recently completed second fiscal quarter, was $852,785,460 based on the closing price on the New York Stock Exchange on June 30, 2013 of $13.81 per share.

RPC, Inc. had 219,289,400 shares of Common Stock outstanding as of February 14, 2014.

Documents Incorporated by Reference

Portions of the Proxy Statement for the 2014 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 beliefs regarding natural gas prices, production levels and drilling activities; our belief that oil-directed drilling will continue to represent the majority of the total drilling rig count unless the sustained level of demand for natural gas increases tremendously; our expectation to continue to focus on the development of international business opportunities in current and other international markets; 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 belief that no catalysts exist which will change overall industry activity in the near term; our belief that the consistently high price of oil over the past three years and during the beginning of the first quarter of 2014 holds positive implications for RPC’s activity levels for 2014; our belief that the percentage of wells drilled for oil will remain high in 2014; our expectation not to enter into additional contractual arrangements with customers on terms similar to those having expired during 2012 and 2013; our belief that the high price of oil should continue to have a positive impact on our customers’ activity levels and our financial results; our belief that the overall rig count will not increase significantly during 2014 unless the price of natural gas observed during the beginning of the first quarter of 2014 is sustained during the year; our belief that the excess service capacity in the industry is still an issue in the U.S. domestic market; our plans not to significantly increase the size of our revenue-producing fleet of equipment during 2014; 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 2013; 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, 2013, RPC had approximately 3,900 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 2013, approximately three percent of RPC’s consolidated revenues were generated from offshore operations in the U.S. Gulf of Mexico and in the Gulf of Alaska. We also estimate that 64 percent of our 2013 revenues were related to drilling and production activities for oil, and 36 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 2013 revenues, 53 percent of 2012 revenues and 55 percent of 2011 revenues are provided to customers throughout Texas, and the Appalachian, mid-continent and Rocky Mountain 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 16 percent of 2013 revenues, 14 percent of 2012 revenues and 12 percent of 2011 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 nine percent of 2013 revenues and 11 percent of 2012 and 2011 revenues, involve the injection of coiled tubing into wells to perform various applications and functions for use principally in well-servicing operations and 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 revenues in 2013, 2012 and 2011, 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 revenues in 2013, 2012 and 2011. 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. During the past several years, the Company has responded to well control situations in several international locations including Algeria, Argentina, Australia, Bolivia, Canada, Colombia, Egypt, Kuwait, Mexico, Qatar, Taiwan, Trinidad, Turkmenistan, Tanzania, Abu Dhabi 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 wellbore, 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 four percent of 2013 revenues, five percent of 2012 revenues and six percent of 2011 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 Texas, 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 drilling and production activities of its customers in Texas, the Gulf of Mexico, the mid-continent, the southwest, the Rocky Mountains and the Appalachian regions. 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 61 percent from its peak in 1981. However, due to recently enhanced technology, more wells are being drilled, and these wells are increasingly productive. For these reasons, the domestic production of natural gas has risen to record levels, and we estimate that the domestic production of crude oil during 2013 was at its highest level since 1989. Oil and gas industry activity levels have historically been volatile, experiencing multiple cycles, including down cycle troughs in 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 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 fourth quarter of 2011, U.S. domestic drilling activity increased by 129 percent before declining gradually throughout the remainder of 2011 and 2012. At the end of 2013, the U.S. domestic rig count was approximately 100 percent higher than the cyclical trough recorded during the second quarter of 2009.

The fluctuations in domestic drilling activity since 2008 are consistent with the changes in the prices of oil and natural gas, the overall economic recovery following the recession in 2008 and 2009, and the financial returns from drilling in unconventional shale plays during the past several years. During 2013 the average price of natural gas increased by approximately 36 percent and the price of benchmark natural gas liquids was unchanged compared to prior year. The average price of oil increased by approximately four percent during 2013 compared to 2012. The current sustained high price of oil has increased the attractiveness of drilling for oil in several unconventional basins in the U.S. domestic market. During 2013, oil-directed drilling activity increased slightly, offset by a decrease in natural gas-directed drilling during the year. The price of natural gas liquids has become an increasingly important determinant of our customers’ activity levels, since it is produced in many of the shale resource plays which also produce oil, and production of various natural gas liquids has increased to a level comparable to that of natural gas. The price of benchmark natural gas liquids peaked during the third quarter of 2008, and declined by approximately 69 percent during the third and fourth quarters of 2008. Thereafter, the price of benchmark natural gas liquids climbed steadily until the third quarter of 2011, but declined by 45 percent by the end of 2012. The average price of benchmark natural gas liquids was unchanged in 2013 compared to 2012, but its price increased by approximately 46 percent between the beginning and the end of 2013, and early in the first quarter of 2014 increased by approximately 43 percent compared to the average price in 2013.

From 2001 to 2009, gas drilling rigs 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 2013 had fallen to approximately 21 percent of total drilling activity. Although the demand for natural gas has remained stable, the price of natural gas has fallen in recent years due to increased domestic reserves and productivity of new wells. The price of natural gas rose during 2013 and has risen again early in 2014 to levels not observed since the first quarter of 2010, and the amount of U.S. domestic natural gas in storage was approximately 27 percent below its five-year average. Although the current industry metrics regarding natural gas are favorable, we do not believe that they are sufficient to encourage renewed natural gas-directed drilling because of continued record natural gas production levels and the opinion among our customers that the high price of natural gas is due to unseasonably cold weather in the first quarter of 2014 and will not be sustainable in the near term. Although the price of oil did not increase significantly during 2013 or early in the first quarter of 2014, it remains high, and producers are exploiting resource plays that are economical at current high oil prices. Although natural gas-directed drilling activity has declined to its lowest level in almost 19 years, 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. We anticipate that oil-directed drilling will continue to represent the majority of the total drilling rig count unless the sustained level of demand for natural gas increases significantly due to U.S. exports of natural gas or changes in demand due to increased use of natural gas as a transportation fuel or for other purposes. We continue to believe in the long-term growth opportunities for our business due to the continued high demand for hydrocarbons generally and the growing production of oil in the domestic U.S. market in particular. 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, so the composition of the U.S. domestic drilling rig count is not as meaningful as the overall level of drilling activity.

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. They 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. Because they are drilled through a typically narrow and 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 requires a great deal of pressure pumping horsepower 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 several years have emphasized domestic rather than international expansion because of higher expected financial returns. International revenues for 2013 decreased compared to 2012 due to lower customer activity levels in New Zealand and Mexico, and in the aggregate accounted for approximately four percent of consolidated RPC revenues. International revenues in 2013 compared to 2012 increased in Equatorial Guinea, Gabon, Australia, Argentina and Bolivia. During 2013, RPC provided snubbing, well control and oilfield training services in several countries including Gabon, Australia and China. We also provided downhole motors and tools in Canada, Mexico, China, Argentina, Tunisia and Oman. We continue to focus on the selected 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 in 2014.

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. 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 to generate 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 acquisition opportunities exist. However, the favorable long-term outlook for our industry and the strong historical profitability of many potential acquisitions has encouraged potential sellers of businesses to expect high valuations for their businesses. Due to these high valuations and the potential difficulty of integrating acquired businesses into our existing operations, we believe we generate better returns on investments growing organically in service lines and geographic locations in which we have experience and presence. We will continue to be selective in pursuing growth through acquisitions of existing businesses.

RPC has a revolving credit facility to fund the purchase of revenue-producing equipment and other working capital requirements. In January 2014, this facility was extended for five 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 2011 and the first two quarters of 2012, we purchased additional revenue-producing equipment to support high industry activity levels. Our scheduled purchases of equipment declined during the third and fourth quarters of 2012 and during 2013 as pricing for our services became increasingly competitive, and the anticipated near-term financial returns of a larger fleet of revenue-producing equipment also declined. The outstanding balance on our credit facility at the end of 2013 was lower than at the end of the prior year due to a reduction in capital expenditures and working capital, and our ratio of debt to total capitalization continues to be 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 2013, RPC provided oilfield services to several hundred customers, none of which accounted for more than 10 percent of revenues.

Sales are generated by RPC’s sales force and through referrals from existing customers. Over the past three years we have from time to time entered into agreements, with terms beyond one year, to provide services to certain domestic customers. 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. Our products and services are sold in highly competitive markets, and the revenues and earnings generated 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. Strong oilfield activity during the past several years and the availability of capital have encouraged several new, smaller companies to seek debt and equity capital and accelerate their growth rates. The presence of these new competitors has increased competitive pricing pressures as domestic oilfield activity moderated during the third and fourth quarters of 2011 and throughout 2012 and 2013. Although the growth in the overall domestic fleet of revenue-producing equipment has moderated, pricing for our services remains competitive. RPC believes that the principal competitive factors in the market areas that it serves are product availability and quality of our equipment and raw materials used to provide our services, service quality, 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 has two primary administrative buildings, one it leases in The Woodlands, Texas that includes the Company’s operations, engineering, sales and marketing headquarters, and one it owns 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 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.

At times our business has had a concentration of one or more major customers. In 2013 and 2012, none of our customers exceeded 10 percent of our total revenues, while in 2011, one of our customers accounted for approximately 12 percent of our total revenues. In addition, no customer accounted for more than ten percent of accounts receivable as of December 31, 2013 and 2012. Reliance on a large customer for a significant portion of our total revenues could expose 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 regulations 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.

Compliance with federal and state regulations relating to hydraulic fracturing and designation of economic development zones related to natural gas-directed drilling from shale formations could increase our operating costs, cause operational delays, and could reduce or eliminate the demand for our pressure pumping services.

RPC’s pressure pumping services are the subject of continuing federal, state and local regulatory oversight. This scrutiny is prompted in part by public concern regarding the potential impact on drinking and ground water and other environmental issues arising from the growing use of hydraulic fracturing. Among these regulatory entities is the White House Council on Environmental Quality, which is coordinating a review of hydraulic fracturing practices. In addition, a committee of the United States House of Representatives has investigated hydraulic fracturing practices and publicized information regarding the materials used in hydraulic fracturing. The U.S. Environmental Protection Agency has also undertaken a study of the environmental impact of hydraulic fracturing practices, and is expected to issue its findings in 2014. One of the results of this scrutiny has been to require disclosure of materials used in hydraulic fracturing on certain public lands. RPC participates in this disclosure process and has cooperated fully with all governmental requests for information regarding our operations. In addition, during the first quarter of 2014, the federal government proposed that specific geographic areas in which natural gas-directed drilling and production from shale formations be set aside as economic development zones. Such designations, if they arise in geographic areas in which RPC conducts its operations, may increase demand for our customers’ natural gas production, thus increasing demand for RPC’s services. Such designations may also increase our operating costs due to the cost of compliance with increased regulation as well as subsidies paid by firms engaged in natural gas-directed drilling to other industries which establish operations in these economic development zones. We are unable to predict whether the scrutiny of RPC’s pressure pumping business and any resulting regulatory change will impact our business through increased operational costs, operational delays, or a reduction in demand for hydraulic fracturing services. Also, we are unable to predict the magnitude and timing of the impact on our operations and operational costs, if any, of the creation of economic development zones in geographic areas in which natural gas-directed drilling and production from shale formations take place.

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 Section 303A of the New York Stock Exchange (“NYSE”) Listed Company Manual. 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 72 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 120 offices and operating facilities. The Company leases approximately 18,600 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 2020. 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

Broussard, Louisiana — Operations, sales and equipment storage yards

Vilonia, Arkansas — Maintenance and rebuild facilities

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

Houma, Louisiana — Administrative office

Houston, Texas — Pipe storage terminal and inspection sheds

Kilgore, Texas — Operations, sales and equipment storage yards

Odessa, Texas — Operations, sales and equipment storage yards

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

Vernal, Utah — Operations, sales and equipment storage yards

Williston, North Dakota — Operations, sales and equipment storage yards

Leased Locations

Canton, Pennsylvania — Pumping services facility

Hobbs, New Mexico — Pumping services facility

Odessa, Texas — Operations, sales and equipment storage yards

Oklahoma City, Oklahoma — Operations, sales and administrative office

San Antonio, Texas — Operations, sales and equipment storage yards

Seminole, Oklahoma — Pumping services facility

The Woodlands, Texas — Operations, sales and administrative office

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

The information required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Form 10-K.

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)	82	1/24/84
Chairman of the Board
Richard A. Hubbell (2)	69	4/22/03
President and Chief Executive Officer
Linda H. Graham (3)	77	1/27/87
Vice President and Secretary
Ben M. Palmer (4)	53	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 of 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 of 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. As of February 14, 2014 there were 219,289,400 shares of common stock outstanding and approximately 22,300 beneficial holders of our 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, 2013 and 2012:

	2013						2012
Quarter	High		Low		Dividends		High		Low		Dividends
First	$	17.40	$	12.46	$	0.10	$	14.03	$	9.31	$	0.08
Second		15.55		12.41		0.10		11.95		8.75		0.08
Third		15.94		13.48		0.10		14.64		11.04		0.08
Fourth		18.88		15.34		0.10		12.70		10.45		0.28

On January 28, 2014 RPC’s Board of Directors approved a $0.105 per share cash dividend, payable March 10, 2014 to stockholders of record at the close of business on February 10, 2014. 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

The Company has a stock buyback program initially adopted in 1993 that authorizes the repurchase of up to 26,578,125 shares. On June 5, 2013, the Board of Directors authorized an additional 5,000,000 shares for repurchase under this program. There were no shares repurchased as part of this program during the fourth quarter of 2013. As of December 31, 2013, there are 4,712,234 shares available to be repurchased under the current authorization. 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 (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 2013. 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 2013 of $108.9 billion, and a median market capitalization of $7.5 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 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,	2013			2012			2011			2010			2009
	(in thousands, except employee and per share amounts)
Revenues	$	1,861,489		$	1,945,023		$	1,809,807		$	1,096,384		$	587,863
Cost of revenues		1,178,412			1,105,886			992,704			606,098			393,806
Selling, general and administrative expenses		185,165			175,749			151,286			121,839			97,672
Depreciation and amortization		213,128			214,899			179,905			133,360			130,580
Loss (gain) on disposition of assets, net		9,371			6,099			3,831			(3,758	)		(1,143	)
Operating profit (loss)		275,413			442,390			482,081			238,845			(33,052	)
Interest expense		(1,822	)		(1,976	)		(3,453	)		(2,662	)		(2,176	)
Interest income		419			30			18			46			147
Other income, net		2,260			2,175			169			1,303			1,582
Income (loss) before income taxes		276,270			442,619			478,815			237,532			(33,499	)
Income tax provision (benefit)		109,375			168,183			182,434			90,790			(10,754	)
Net income (loss)	$	166,895		$	274,436		$	296,381		$	146,742		$	(22,745	)
Earnings (loss) per share:
Basic	$	0.77		$	1.28		$	1.36		$	0.67		$	(0.11	)
Diluted	$	0.77		$	1.27		$	1.35		$	0.67		$	(0.11	)
Dividends paid per share	$	0.40		$	0.52		$	0.21		$	0.09		$	0.10
OTHER DATA:
Operating margin percent		14.8	%		22.7	%		26.6	%		21.8	%		(5.6	)%
Net cash provided by operating activities	$	365,624		$	559,933		$	386,007		$	168,657		$	168,740
Net cash used for investing activities		(207,654	)		(315,838	)		(391,637	)		(171,769	)		(61,144	)
Net cash (used for) provided by financing activities		(163,433	)		(237,325	)		3,988			7,658			(106,144	)
Capital expenditures	$	201,681		$	328,936		$	416,400		$	187,486		$	67,830
Employees at end of period		3,900			3,600			3,400			2,500			1,980
BALANCE SHEET DATA AT END OF YEAR:
Accounts receivable, net	$	437,132		$	387,530		$	461,272		$	294,002		$	130,619
Working capital		436,873			403,316			447,089			281,174			151,681
Property, plant and equipment, net		726,307			756,326			675,360			453,017			396,222
Total assets		1,383,860			1,367,163			1,338,211			887,871			649,043
Long-term debt		53,300			107,000			203,300			121,250			90,300
Total stockholders’ equity	$	968,702		$	899,232		$	762,592		$	538,895		$	409,723

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.

To maintain a flexible cost structure that can respond quickly to volatile industry conditions and business activity levels.

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

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.

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 overall industry metrics which are significantly less volatile than historical norms. Moreover, we do not believe that any catalysts exist which will change overall industry activity in the near term. For example, although the average U.S. domestic rig count declined by 8.2 percent during 2013 as compared to 2012, the domestic rig count during 2013 changed by less than one percent. The average price of oil during 2013 increased by 3.9 percent and remained high enough that our customers continued to conduct oil-directed drilling activities. During the beginning of the first quarter of 2014, each of these industry indicators remained essentially unchanged compared to the end of 2013. In contrast, the price of natural gas increased significantly during 2013 and the beginning of the first quarter of 2014, partially due to winter weather that was colder than average in both years. However, these price increases have not been sufficient to encourage our customers to increase their natural gas-related drilling activities, which during the beginning of the first quarter of 2014 remained at depressed levels not observed since the second quarter of 1995. Furthermore, we do not believe that natural gas-directed drilling will increase during the near term because domestic natural gas production during 2013 was higher than in 2012, due to the high natural gas production from existing wells including residual production from new oil-directed wells. The consistently high price of oil over the past three years and during the beginning of the first quarter of 2014 holds positive implications for RPC’s activity levels for 2014. RPC has operations in most of the areas in which drilling activity is directed towards oil, and we maintained our presence in these areas during 2013. During the beginning of the first quarter of 2014, the rig count was less than one percent higher the same period in 2013 and the fourth quarter of 2013. The U.S. domestic rig count may increase during 2014, but any increases are likely to be prompted by current high natural gas prices and probably will not lead to a long-term trend of increased drilling directed towards natural gas.

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 average number of horizontal and directional wells drilled in the United States decreased by approximately three percent in 2013, and was 75 percent of total wells drilled during the year. During the first part of 2014, the percentage of horizontal and directional wells drilled as a percentage of total wells was approximately 78 percent. In addition, the percentage of wells drilled for oil increased to 78 percent during 2013 compared to 71 percent during 2012. During the beginning of the first quarter of 2014, the percentage of wells drilled for oil increased slightly to 79 percent. We believe that this percentage will remain high in 2014 due to the continued high price of oil and the high production levels of natural gas. During 2013 we also began to monitor the U.S. domestic well count, which is a measure of wells drilled by the existing drilling rig fleet. We believe that the well count is an important measure of our potential activity levels because it reflects changes in rig efficiencies. During 2013, the total U.S. domestic well count decreased by approximately three percent. In the markets in which RPC has operational locations, the well count increased by approximately seven percent. During 2013, a combination of a larger U.S. domestic fleet of revenue-producing equipment and relatively flat activity levels continued to negatively impact pricing for the Company’s services. These negative impacts were most pronounced in the Company’s pressure pumping service line, which is highly utilized in unconventional completion work, and is a service line which has seen a significant increase in the overall fleet of revenue-producing equipment during the last several years. During the past several years, a number of our customers entered into contractual relationships with us to provide services to support their completion programs. Such arrangements were advantageous to our customers because of the repetitive nature of this type of activity and their need to have service providers dedicated exclusively to their drilling programs. These arrangements also positively impacted the Company’s financial results, because of increased utilization of our revenue-producing equipment and increased efficiency. All of these arrangements expired during 2012 and 2013 and were not renewed at the same or similar terms. We do not expect to enter into additional contractual arrangements with such terms during 2014.

During 2013 the Company reduced our purchases of revenue-producing equipment, and concentrated instead on optimizing the utilization of our existing fleet of revenue-producing equipment. In support of this objective, we have increased the capitalized maintenance expenditures of our equipment fleet. Cash flows from operating activities as well as borrowings under our revolving credit facility have been sufficient to fund the Company’s lower capital expenditures which decreased to $201.7 million in 2013 compared to $328.9 million in 2012. The Company has a syndicated revolving credit facility in order to maintain sufficient liquidity to fund its capital expenditure and other funding requirements.

Revenues during 2013 totaled $1.9 billion, a decrease of 4.3 percent compared to 2012. Cost of revenues increased $72.5 million in 2013 compared to the prior year due to higher materials and supplies expense and employment costs associated with higher activity levels and was approximately 63 percent of revenues in 2013 compared to 57 percent of revenues in 2012. Selling, general and administrative expenses as a percentage of revenues increased approximately 0.9 percentage points in 2013 compared to 2012.

Income before income taxes declined due to competitive pricing to $276.3 million in 2013 compared to $442.6 million in the prior year. Diluted earnings per share were $0.77 in 2013 compared to $1.27 for the prior year.

Cash flows from operating activities decreased primarily due to lower earnings to $365.6 million in 2013 compared to $559.9 million in 2012. As of December 31, 2013, there were $53.3 million in outstanding borrowings under our credit facility, a decline from $107.0 million at December 31, 2012.

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. Between its cyclical trough in the second quarter of 2009 and the fourth quarter of 2011, U.S. domestic drilling activity increased by approximately 129 percent, before declining during the remainder of 2011 and throughout 2012. Between the beginning of 2013 and the first quarter of 2014, domestic drilling activity was essentially unchanged, varying by slightly more than one percent during the period. However, unconventional activity as a percentage of total oilfield activity has grown steadily over the past several years and was 75 percent of total wells drilled during 2013. Early in the first quarter of 2014, unconventional drilling activity was 78 percent of total U.S. domestic drilling activity.

The current and projected prices of oil and natural gas are important catalysts for U.S. domestic drilling activity. The price of natural gas declined steadily during 2011 and the first quarter of 2012. The price of natural gas began to recover during the third and fourth quarters of 2012 and throughout 2013, and during the first quarter of 2014 had risen to the highest price observed since the first quarter of 2010. In spite of these increases, the price expectations for natural gas has not risen adequately to encourage drilling in the service-intensive natural gas resource shale plays in the U.S. domestic market due in part to record U.S. natural gas production. The price of natural gas liquids has become an increasingly important determinant of our customers’ activities, since its sales comprise a large part of our customers’ revenues, and it is produced in many of the shale resource plays that also produce oil. During 2013, the average price of benchmark natural gas liquids was unchanged compared to the prior year, but it increased by 43 percent early in the first quarter of 2014 compared to the prior year. The average price of oil has remained high during 2013 and early in the first quarter of 2014. In general, these trends have positive implications for our near-term activity levels. In particular, the high price of oil should continue to have a positive impact on our customers’ activity levels and our financial results, since many U.S. domestic shale resource plays produce oil and petroleum liquids, and RPC has operational locations and revenue-producing equipment in these locations.

The effect of the sustained high price of oil is evident in the current composition of the U.S. domestic rig count, approximately 79 percent of which was directed towards oil during the beginning of the first quarter of 2014. We believe that oil-directed drilling will remain a very high percentage of domestic drilling, and that natural gas-directed drilling will remain a low percentage of U.S. domestic drilling in the near term. We believe that this relationship will continue due to relatively low prices for natural gas, high production from existing natural gas wells, and industry projections of limited increases in domestic natural gas demand during the near term. We do not believe that the overall rig count will increase significantly during 2014 unless the price of natural gas observed during the beginning of the first quarter of 2014 is sustained during the year.

We continue to monitor the market for our services and the competitive environment in 2014. We are encouraged that the price of oil has remained high and that our customers’ oil-directed drilling activities have remained high also. Furthermore, we are encouraged by the recent increases in the prices of natural gas and natural gas liquids, although we believe that these increases are the result of unseasonably cold weather in the first quarter of 2014 and thus may not be sustainable for a long period of time. We also monitor the competitive environment because many new service companies have entered the industry over the past few years, and existing service companies have purchased additional revenue-producing equipment. The new entrants and larger service companies in the oilfield services industry have created downward pressure on pricing for our services, as well as increased the costs for skilled labor by recruiting skilled employees from existing service companies. Although these increased competitive pressures have begun to subside, we believe that excess service capacity is still an issue in the U.S. domestic market, given the fact that domestic drilling activity has not changed since the beginning of 2013. Because of these concerns, we do not plan to significantly increase the size of our revenue-producing fleet of equipment during 2014. 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 have used our bank credit facility to finance our expansion, we will continue to maintain a conservative financial and capital structure by industry standards.

Results of Operations

Years Ended December 31,	2013			2012			2011
*(in thousands except per share amounts and industry data)*
Consolidated revenues	$	1,861,489		$	1,945,023		$	1,809,807
Revenues by business segment:
Technical	$	1,729,732		$	1,794,015		$	1,663,793
Support		131,757			151,008			146,014

Consolidated operating profit	$	275,413		$	442,390		$	482,081
Operating profit by business segment:
Technical	$	276,246		$	420,231		$	451,259
Support		26,223			45,912			51,672
Corporate expenses		(17,685	)		(17,654	)		(17,019	)
Loss on disposition of assets, net		(9,371	)		(6,099	)		(3,831	)

Net income	$	166,895		$	274,436		$	296,381
Earnings per share — diluted	$	0.77		$	1.27		$	1.35
Percentage of cost of revenues to revenues		63	%		57	%		55	%
Percentage of selling, general and administrative expenses to revenues		10	%		9	%		8	%
Percentage of depreciation and amortization expenses to revenues		11	%		11	%		10	%
Effective income tax rate		39.6	%		38.0	%		38.1	%
Average U.S. domestic rig count		1,762			1,919			1,877
Average natural gas price (per thousand cubic feet (mcf))	$	3.71		$	2.73		$	3.95
Average oil price (per barrel)	$	98.06		$	94.20		$	94.94

Year Ended December 31, 2013 Compared To Year Ended December 31, 2012

Revenues. Revenues in 2013 decreased $83.5 million or 4.3 percent compared to 2012. The Technical Services segment revenues for 2013 decreased 3.6 percent from the prior year due primarily to lower pricing experienced in most of our service lines within this segment partially offset by higher service intensity and activity in our pressure pumping service line. The Support Services segment revenues for 2013 decreased 12.7 percent compared to 2012 due primarily to lower pricing in the rental tool service line, which is the largest service line within this segment. Operating profit in the both Technical Services and Support Services segment declined due to lower pricing. Operating profit in the Technical Services segment also declined due to higher materials and supplies expense consistent with increased service intensity.

Domestic revenues decreased 4.0 percent during 2013 compared to 2012 to $1.8 billion due primarily to continued competitive pricing for our services in most service lines. The average price of oil increased by four percent while the average price of natural gas increased by 36 percent during 2013 compared to the prior year. The average domestic rig count during 2013 was eight percent lower than in 2012. Increasingly competitive pricing for our services negatively impacted our operating income, income before income taxes, net income and earnings per share. At the present time, we believe that our activity levels are affected primarily by the price of oil, since oil-directed activity has become the majority of total U.S. drill activity. The prices of natural gas and natural gas liquids also impact our activity levels because of the service-intensive nature of the drilling and completion associated with this type of drilling and completion. 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 some of the services within our technical services segment. International revenues, which decreased from $74.2 million in 2012 to $65.9 million in 2013, were four percent of consolidated revenues in 2013 and 2012. These international revenue decreases were due mainly to lower customer activity levels in New Zealand and Mexico in 2013 partially offset by an increase in activity in Equatorial Guinea, Gabon, Australia, Argentina and Bolivia, 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 2013 was $1.2 billion compared to $1.1 billion in 2012, an increase of $72.5 million or 6.6 percent. The increase in these costs was due to the variable nature of these expenses especially materials and supplies expenses and employment costs associated with higher activity levels. Cost of revenues, as a percent of revenues, increased in 2013 compared to 2012 due primarily to competitive pricing for our services.

Selling, general and administrative expenses. Selling, general and administrative expenses increased 5.4 percent to $185.2 million in 2013 compared to $175.7 million in 2012. This increase was due primarily to increases in total employment costs and bad debt expense. As a percentage of revenues, selling, general and administrative expenses increased to 9.9 percent in 2013 compared to 9.0 percent in 2012.

Depreciation and amortization. Depreciation and amortization were $213.1 million in 2013, a decrease of $1.8 million, compared to $214.9 million in 2012. As a percentage of revenues, depreciation and amortization remained relatively unchanged at 11.4 percent in 2013 compared to 11.0 percent in 2012.

Loss on disposition of assets, net. Loss on disposition of assets, net was $9.4 million in 2013 compared to $6.1 million in 2012. The loss of 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 $2.3 million in 2013 compared to $2.2 million in 2012. Other income, net primarily includes mark to market gains and losses of investments in the non-qualified benefit plan.

Interest expense and interest income. Interest expense was $1.8 million in 2013 compared to $2.0 million in 2012. The decrease in 2013 is due to a lower average debt balance on our revolving credit facility partially offset by slightly higher interest rates net of interest capitalized on equipment and facilities under construction. Interest income increased to $419 thousand in 2013 compared to $30 thousand in 2012.

Income tax provision. The income tax provision was $109.4 million in 2013 compared to $168.2 million in 2012. This decrease was due to lower income before taxes in 2013 compared to 2012 partially offset by an increase in the effective tax rate to 39.6 percent in 2013 compared to the effective tax rate of 38.0 percent in 2012.

Net income and diluted earnings per share. Net income was $166.9 million in 2013, or $0.77 per diluted share, compared to net income of $274.4 million, or $1.27 per diluted share in 2012. This decline was due to lower profitability.

Year Ended December 31, 2012 Compared To Year Ended December 31, 2011

Revenues. Revenues in 2012 increased $135.2 million or 7.5 percent compared to 2011. The Technical Services segment revenues for 2012 increased 7.8 percent from the prior year due primarily to an increase in the fleet of revenue-producing equipment and higher activity levels partially offset by lower pricing for our services within this segment. The Support Services segment revenues for 2012 increased 3.4 percent compared to 2011 due primarily to higher activity levels in several of the service lines. Operating profit in the Technical Services segment declined due to lower personnel and equipment utilization as well as lower pricing. Operating profit in the Support Services segment declined due primarily to lower utilization and pricing in our rental tools service line.

Domestic revenues increased 6.4 percent during 2012 compared to 2011 to $1.9 billion due primarily to a larger fleet of revenue-producing equipment and higher activity levels in several service lines partially offset by lower pricing for our services in most service lines. The average price of oil remained stable while the average price of natural gas decreased by 31 percent during 2012 compared to the prior year. The average domestic rig count during 2012 was two percent higher than in 2011. Our revenues grew at a higher rate than the changes in our industry indicators because of increases in our fleet of revenue-producing equipment compared to 2011. However, increasingly competitive pricing for our services, as well as lower utilization of our revenue-producing equipment and personnel in 2012 compared to 2011, negatively impacted our operating income, income before income taxes, net income and earnings per share. International revenues, which increased from $52.1 million in 2011 to $74.2 million in 2012, were four percent of consolidated revenues in 2012 compared to three percent of revenues in 2011. These international revenue increases were due mainly to higher customer activity levels in Canada, China, Mexico and New Zealand in 2012 partially offset by a decrease in activity in Australia, Gabon and Saudi Arabia, compared to the prior year.

Cost of revenues. Cost of revenues in 2012 was $1.1 billion compared to $992.7 million in 2011, an increase of $113.2 million or 11.4 percent. The increase in these costs was due to the variable nature of most of these expenses. Cost of revenues, as a percent of revenues, increased in 2012 compared to 2011 due primarily to lower pricing and inefficiencies resulting from lower utilization of our equipment and personnel.

Selling, general and administrative expenses. Selling, general and administrative expenses increased 16.2 percent to $175.7 million in 2012 compared to $151.3 million in 2011. This increase was primarily due to increases in total employment costs. As a percentage of revenues, selling, general and administrative expenses increased to 9.0 percent in 2012 compared to 8.4 percent in 2011.

Depreciation and amortization. Depreciation and amortization expense were $214.9 million in 2012, an increase of $35.0 million or 19.5 percent, compared to $179.9 million in 2011. This increase resulted from capital expenditures within both Technical Services and Support Services to increase capacity and to maintain our existing fleet of equipment. As a percentage of revenues, depreciation and amortization increased to 11.0 percent in 2012 compared to 9.9 percent in 2011.

Loss on disposition of assets, net. Loss on disposition of assets, net was $6.1 million in 2012 compared to $3.8 million in 2011. The loss of 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 $2.2 million in 2012, an increase of $2.0 million compared to $0.2 million in 2011. Other income, net primarily includes mark to market gains and losses of investments in the non-qualified benefit plan.

Interest expense and interest income. Interest expense was $2.0 million in 2012 compared to $3.5 million in 2011. The decrease in 2012 is due to a lower average debt balance on our revolving credit facility coupled with slightly lower interest rates net of interest capitalized on equipment and facilities under construction. Interest income increased to $30 thousand in 2012 compared to $18 thousand in 2011.

Income tax provision. The income tax provision was $168.2 million in 2012 compared to $182.4 million in 2011. This decrease was due to lower income before taxes in 2012 compared to 2011 as the effective tax rate of 38.0 percent in 2012 was comparable to the effective tax rate of 38.1 percent in 2011.

Net income and diluted earnings per share. Net income was $274.4 million in 2012, or $1.27 per diluted share, compared to net income of $296.4 million, or $1.35 per diluted share in 2011. This decline was due to higher, as a percentage of revenues, costs of revenues, selling, general and administrative expenses, and depreciation and amortization expenses.

Liquidity and Capital Resources

Cash and Cash Flows

The Company’s cash and cash equivalents were $8.7 million as of December 31, 2013, $14.2 million as of December 31, 2012 and $7.4 million as of December 31, 2011.

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

	(in thousands)
	2013			2012			2011
Net cash provided by operating activities	$	365,624		$	559,933		$	386,007
Net cash used for investing activities		(207,654	)		(315,838	)		(391,637	)
Net cash (used for) provided by financing activities		(163,433	)		(237,325	)		3,988

2013

Cash provided by operating activities decreased $194.3 million in 2013 compared to the prior year due primarily to a decrease in net income of $107.5 million, an unfavorable change in deferred taxes of $17.9 million due to a decrease in tax depreciation benefits resulting from lower capital expenditures coupled with an unfavorable change in working capital of $83.2 million.

The unfavorable change in working capital is primarily due to the following: an unfavorable change of $123.8 million in accounts receivable due to slightly higher business activity levels at the end of 2013 compared to declining activity levels at the end of the prior year; an unfavorable change of $25.1 million in other current assets due to lower deposits for raw materials; an unfavorable net change of $9.8 million in net current income taxes receivable/payable; and an unfavorable change of $4.6 million in accrued state, local and other taxes due to the timing of payments. These unfavorable changes were partially offset by a favorable change of $54.4 million in inventories due to improved sourcing of critical materials and supplies that require longer lead times.

Cash used for investing activities in 2013 decreased by $108.2 million compared to 2012, primarily as a result of lower capital expenditures in response to highly competitive pricing.

Cash used for financing activities in 2013 decreased by $73.9 million primarily as a result of lower net loan repayments coupled with lower open market share repurchases, partially offset by a 25 percent increase in the per share common stock dividend declared during 2013 compared to the prior year.

2012

Cash provided by operating activities increased $173.9 million in 2012 compared to the prior year due primarily to a net decrease in working capital requirements in 2012 compared to 2011. This decrease in working capital requirements was partially offset by a decrease in the deferred tax provision and net income. Decreasing business activity levels in 2012 resulted in decreased accounts receivable, other current assets and accounts payable partially offset by an increase in inventory.

Cash used for investing activities in 2012 decreased by $75.8 million compared to 2011, primarily as a result of lower capital expenditures.

Cash used for financing activities in 2012 increased by $241.3 million primarily as a result of higher net loan repayments during 2012 compared to the prior year as a result of improvements in working capital and an increase in common stock dividends during 2012 compared to the prior year.

Financial Condition and Liquidity

The Company’s financial condition as of December 31, 2013, 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. On January 17, 2014, the Company amended a $350 million revolving credit facility which extended the maturity of the loan to January 2019. 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 $272.6 million was available under the facility as of December 31, 2013; $24.1 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 $201.7 million in 2013, and we currently expect capital expenditures to be approximately $200 million in 2014. We expect that a majority of these expenditures in 2014 will be directed towards maintenance of our revenue-producing equipment and refurbishment of our existing fleet of pressure pumping equipment. The remaining capital expenditures will be directed towards the purchase of revenue-producing equipment in several of our core service lines, including pressure pumping, coiled tubing and rental tools. The actual amount of expenditures will depend primarily on equipment maintenance requirements, customer 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 2013, the Company contributed $0.8 million to the pension plan. The Company expects that additional contributions to the defined benefit pension plan of approximately $0.8 million will be required in 2014 to achieve the Company’s funding objective.

The Company has a stock buyback program initially adopted in 1998 that authorizes the repurchase of up to 26,578,125 shares. On June 5, 2013, the Board of Directors authorized an additional 5,000,000 shares for repurchase under this program. There were 1,511,614 shares purchased on the open market during 2013, and 4,712,234 shares remain available to be repurchased under the current authorization as of December 31, 2013. The Company may repurchase outstanding common shares periodically based on market conditions and our capital allocation strategies considering restrictions under our credit facility. The stock buyback program does not have a predetermined expiration date.

On January 28, 2014, the Board of Directors approved a $0.105 per share cash dividend, payable March 10, 2014 to stockholders of record at the close of business on February 10, 2014. 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, 2013:

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	$	53,300	$	—	$	—	$	—	$	53,300
Interest on long-term debt obligations		9,917		1,951		3,901		3,901		164
Capital lease obligations		—		—		—		—		—
Operating leases (1)		35,408		11,604		12,594		5,220		5,990
Purchase obligations (2)		16,467		16,467		—		—		—
Other long-term liabilities (3)		2,885		—		2,785		100		—
Total contractual obligations	$	117,977	$	30,022	$	19,280	$	9,221	$	59,454

(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 2012 and 2013, the Company incurred higher employment costs due to a continued shortage of skilled labor in many of its markets. Although these costs pressure subsided somewhat during the third and fourth quarters of 2013, our employment costs remain high and the Company expects that they will remain high during 2014. During 2012, the prices of certain raw materials used to provide the Company’s services fluctuated significantly. The Company mitigated some of the cost increases for raw materials by securing materials through additional sources, and the Company continued to source raw materials from these additional sources in 2013. Increased availability of many of these raw materials in response to high market prices has caused prices of some of these raw materials to decline. Furthermore, favorable crop yields have improved the availability of certain of these raw materials, thus decreasing these costs. Finally, the price of equipment used to provide services to the Company’s customers has remained relatively constant in spite of declining demand, and in certain cases has decreased due to lower demand in the current environment for such equipment by oilfield service companies.

Off Balance Sheet Arrangements

The Company does not have any material off balance sheet arrangements.

Related Party Transactions

Marine Products Corporation

Effective in 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 were $670,000 in 2013, $544,000 in 2012, and $639,000 in 2011. The Company’s receivable due from Marine Products for these services was $145,000 as of December 31, 2013 and $94,000 as of December 31, 2012. 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 $1,039,000 in 2013, $1,676,000 in 2012 and $1,469,000 in 2011.

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 $83,000 in 2013 and 2012, and $102,000 in 2011.

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.

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 2013, 2012 and 2011. 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 0.47 percent to 0.15 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, 2013 would have resulted in a change of approximately $2.2 million to the allowance for doubtful accounts and a corresponding change to selling, general and administrative expenses.

Income taxes — The effective income tax rates were 39.6 percent in 2013, 38.0 percent in 2012 and 38.1 percent in 2011. 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, 2013, the Company estimates the range of exposure to be from $14.1 million to $18.6 million. The Company has recorded liabilities at December 31, 2013 of approximately $16.3 million which represents management’s best estimate of probable loss.

Depreciable life of assets — RPC’s net property, plant and equipment at December 31, 2013 was $726.3 million representing 52.5 percent of the Company’s consolidated assets. Depreciation and amortization expenses for the year ended December 31, 2013 were $215.4 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 2013, 2012 and 2011.

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 5.20 percent as of December 31, 2013 compared to 4.16 percent as of December 31, 2012 and 5.00 percent in 2011.

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 and tactical composite investments comprised of investments in real estate funds and private equity 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, 2013, the defined benefit plan was under-funded and the recorded change within accumulated other comprehensive loss increased stockholders’ equity by approximately $4.9 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 $1.1 million to the net loss related to pension reflected in accumulated other comprehensive loss.

The Company recognized pre-tax pension expense of $0.5 million in 2013, $0.7 million in 2012 and $0.5 million in 2011. Based on the under-funded status of the defined benefit plan as of December 31, 2013, the Company expects to recognize pension expense of $0.1 million in 2014. 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 $0.2 million in 2014. 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 $3 thousand in 2014.

Recent Accounting Pronouncements

During the year ended December 31, 2013, the Financial Accounting Standards Board (FASB) issued the following applicable Accounting Standards Updates (ASU):

Recently Adopted Accounting Pronouncements:

Accounting Standards Update 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. The amendments in this ASU do not change the current requirements for reporting net income or other comprehensive income in financial statements. All of the information that this ASU requires already is required to be disclosed elsewhere in the financial statements under U.S. GAAP. In addition, an entity is required to present (either on the face of the statement where net income is presented or in the notes) the effects on the line items of net income of significant amounts reclassified out of accumulated other comprehensive income, but only if the item reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. The Company adopted these provisions in the first quarter of 2013 and has included the required additional disclosures in the accompanying financial statements and notes.

Recently Issued Accounting Pronouncements Not Yet Adopted:

Accounting Standards Update 2013-05, Foreign Currency Matters (Topic 830): Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity The amendments in this ASU requires that when a reporting entity (parent) ceases to have a controlling financial interest in a subsidiary or group of assets within a foreign entity, the parent should release the cumulative translation adjustment into net income only if the sale or transfer results in the complete or substantially complete liquidation of the foreign entity in which the subsidiary or group of assets had resided. Additionally, the amendments in this ASU clarify that the sale of an investment in a foreign entity includes both: (1) events that result in the loss of a controlling financial interest in a foreign entity; and (2) events that result in an acquirer obtaining control of an acquiree in which it held an equity interest immediately before the acquisition date. Upon the occurrence of those events, the cumulative translation adjustment should be released into net income. The amendments in this ASU are effective prospectively for fiscal years beginning after December 15, 2013 and for interim reporting periods within those years, with early adoption being permitted. The Company plans to adopt these provisions in the first quarter of 2014 and does not expect the adoption to have a material impact on the Company’s consolidated financial statements.

Accounting Standards Update 2013-11, Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. The amendments in this ASU requires an unrecognized tax benefit, or a portion of thereof, to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. The only exception would be if the deferred taxes related to these items are not available to settle any additional income taxes that would result from the disallowance of a tax position either by statute or at the entity’s choosing. In such cases, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The amendments in this ASU are effective prospectively for fiscal years beginning after December 15, 2013 and for interim reporting periods within those years, with early adoption being permitted. The Company plans to adopt these provisions in the first quarter of 2014 and does not expect the adoption 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, 2013, there are outstanding interest-bearing advances of $53.3 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, 2013 would cause a change of approximately $0.5 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, 2013 based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management’s assessment is that RPC, Inc. maintained effective internal control over financial reporting as of December 31, 2013.

The independent registered public accounting firm, Grant Thornton LLP, has audited the consolidated financial statements as of and for the year ended December 31, 2013, and has also issued their report on the effectiveness of the Company’s internal control over financial reporting, included in this report on page 30.


/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 28, 2014

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

Board of Directors and Shareholders

RPC, Inc.

We have audited the internal control over financial reporting of RPC, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2013, based on criteria established in the 1992 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, 2013, based on criteria established in the 1992 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 financial statements of the Company as of and for the year ended December 31, 2013, and our report dated February 28, 2014 expressed an unqualified opinion on those financial statements

/S/ GRANT THORNTON LLP

Atlanta, Georgia

February 28, 2014

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements

Board of Directors and Shareholders

RPC, Inc.

We have audited the accompanying consolidated balance sheets of RPC, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2013. Our audits of the basic consolidated financial statements included the financial statement schedule listed in the index appearing under Item 15(2). 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 RPC, Inc. and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. 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, 2013, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2014 expressed an unqualified opinion thereon..

/S/ GRANT THORNTON LLP

Atlanta, Georgia

February 28, 2014

Item 8. Financial Statements and Supplementary Data

CONSOLIDATED BALANCE SHEETS

RPC, INC. AND SUBSIDIARIES

(in thousands except share information)


December 31,	2013				2012
ASSETS
Cash and cash equivalents		$	8,700		$	14,163
Accounts receivable, net			437,132			387,530
Inventories			126,604			140,867
Deferred income taxes			14,185			5,777
Income taxes receivable			5,720			4,234
Prepaid expenses			9,143			10,762
Other current assets			3,441			4,494
Current assets			604,925			567,827
Property, plant and equipment, net			726,307			756,326
Goodwill			31,861			24,093
Other assets			20,767			18,917
Total assets		$	1,383,860		$	1,367,163
LIABILITIES AND STOCKHOLDERS’ EQUITY
LIABILITIES
Accounts payable		$	119,170		$	109,846
Accrued payroll and related expenses			36,638			32,053
Accrued insurance expenses			6,072			6,152
Accrued state, local and other taxes			5,002			7,326
Income taxes payable			—			6,428
Other accrued expenses			1,170			2,706
Current liabilities			168,052			164,511
Long-term accrued insurance expenses			10,225			10,400
Notes payable to banks			53,300			107,000
Long-term pension liabilities			21,966			26,543
Deferred income taxes			153,176			155,007
Other long-term liabilities			8,439			4,470
Total liabilities			415,158			467,931
Commitments and contingencies (Note 9)
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, 218,985,816 and 220,144,287 shares issued and outstanding in 2013 and 2012, respectively			21,899			22,014
Capital in excess of par value			—			—
Retained earnings			956,918			891,464
Accumulated other comprehensive loss			(10,115	)		(14,246	)
Total stockholders’ equity			968,702			899,232
Total liabilities and stockholders’ equity		$	1,383,860		$	1,367,163

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,	2013			2012			2011
REVENUES	$	1,861,489		$	1,945,023		$	1,809,807
COSTS AND EXPENSES:
Cost of revenues (exclusive of items shown separately below)		1,178,412			1,105,886			992,704
Selling, general and administrative expenses		185,165			175,749			151,286
Depreciation and amortization		213,128			214,899			179,905
Loss on disposition of assets, net		9,371			6,099			3,831
Operating profit		275,413			442,390			482,081
Interest expense		(1,822	)		(1,976	)		(3,453	)
Interest income		419			30			18
Other income, net		2,260			2,175			169
Income before income taxes		276,270			442,619			478,815
Income tax provision		109,375			168,183			182,434
Net income	$	166,895		$	274,436		$	296,381
EARNINGS PER SHARE
Basic	$	0.77		$	1.28		$	1.36
Diluted	$	0.77		$	1.27		$	1.35
Dividends paid per share	$	0.40		$	0.52		$	0.21

The accompanying notes are an integral part of these statements.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

RPC, INC. AND SUBSIDIARIES

(in thousands except per share data)


Years ended December 31,	2013			2012			2011
NET INCOME	$	166,895		$	274,436		$	296,381
OTHER COMPREHENSIVE INCOME, NET OF TAXES:
Pension adjustment		4,928			(1,707	)		(3,048	)
Cash flow hedge		—			—			387
Foreign currency translation		(778	)		265			(138	)
Unrealized loss on securities and reclassification adjustments		(19	)		(158	)		(314	)
COMPREHENSIVE INCOME	$	171,026		$	272,836		$	293,268

The accompanying notes are an integral part of these statements.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

RPC, INC. AND SUBSIDIARIES

(in thousands)

Three Years Ended December 31, 2013	Common Stock						Capital in Excess of Par Value			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Three Years Ended December 31, 2013	Shares			Amount			Capital in Excess of Par Value			Retained Earnings						Total
Balance, December 31, 2010		222,264		$	22,227		$	—		$	526,201		$	(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	)		(12,862	)		(22,136	)		—			(35,192	)
Net income		—			—			—			296,381			—			296,381
Pension adjustment, net of taxes		—			—			—			—			(3,048	)		(3,048	)
Gain on cash flow hedge, net of taxes		—			—			—			—			387			387
Foreign currency translation, net of taxes		—			—			—			—			(138	)		(138	)
Unrealized gain on securities, net of taxes		—			—			—			—			(314	)		(314	)
Dividends declared		—			—			—			(47,327	)		—			(47,327	)
Excess tax benefits for share-based payments		—			—			3,371			—			—			3,371
Three-for-two stock split		(358	)		(36	)		36									—
Balance, December 31, 2011		221,188			22,119			—			753,119			(12,646	)		762,592
Stock issued for stock incentive plans and other, net		1,530			152			11,105			—			—			11,257
Stock purchased and retired		(2,011	)		(201	)		(13,885	)		(16,515	)		—			(30,601	)
Increased ownership interest in subsidiary, net of taxes		—			—			—			(5,507	)		—			(5,507	)
Net income		—			—			—			274,436			—			274,436
Pension adjustment, net of taxes		—			—			—			—			(1,707	)		(1,707	)
Foreign currency translation, net of taxes		—			—			—			—			265			265
Unrealized loss on securities, net of taxes		—			—			—			—			(158	)		(158	)
Dividends declared		—			—			—			(114,069	)		—			(114,069	)
Excess tax benefits for share-based payments		—			—			2,724			—			—			2,724
Three-for-two stock split		(563	)		(56	)		56									—
Balance, December 31, 2012		220,144			22,014			—			891,464			(14,246	)		899,232
Stock issued for stock incentive plans and other, net		699			70			8,107			—			—			8,177
Stock purchased and retired		(1,857	)		(185	)		(11,285	)		(13,652	)		—			(25,122	)
Net income		—			—			—			166,895			—			166,895
Pension adjustment, net of taxes		—			—			—			—			4,928			4,928
Foreign currency translation, net of taxes		—			—			—			—			(778	)		(778	)
Unrealized loss on securities, net of taxes		—			—			—			—			(19	)		(19	)
Dividends declared		—			—			—			(87,789	)		—			(87,789	)
Excess tax benefits for share-based payments		—			—			3,178			—			—			3,178
Balance, December 31, 2013		218,986		$	21,899		$	—		$	956,918		$	(10,115	)	$	968,702

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,	2013			2012			2011
OPERATING ACTIVITIES
Net income	$	166,895		$	274,436		$	296,381
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and other non-cash charges		215,812			214,153			179,787
Stock-based compensation expense		8,177			7,860			8,075
Loss on disposition of assets, net		9,371			6,099			3,831
Deferred income tax (benefit) provision		(13,060	)		4,821			77,074
Excess tax benefits for share-based payments		(3,178	)		(2,724	)		(3,371	)
(Increase) decrease in assets:
Accounts receivable		(49,959	)		73,809			(167,312	)
Income taxes receivable		1,692			9,295			9,817
Inventories		14,078			(40,354	)		(36,511	)
Prepaid expenses		1,519			(2,284	)		(2,783	)
Other current assets		1,114			26,189			(30,524	)
Other non-current assets		(1,881	)		(6,415	)		294
(Increase) decrease in liabilities:
Accounts payable		14,062			(4,929	)		30,102
Income taxes payable		(6,428	)		(4,277	)		4,917
Accrued payroll and related expenses		4,585			(1,627	)		9,799
Accrued insurance expenses		(80	)		408			603
Accrued state, local and other taxes		(2,324	)		2,260			2,078
Other accrued expenses		(1,548	)		1,412			958
Pension liabilities		3,183			(589	)		1,249
Long-term accrued insurance expenses		(175	)		1,400			511
Other long-term liabilities		3,769			990			1,032
Net cash provided by operating activities		365,624			559,933			386,007
INVESTING ACTIVITIES
Capital expenditures		(201,681	)		(328,936	)		(416,400	)
Increased ownership interest in subsidiary		—			(6,211	)		—
Proceeds from sale of assets		11,071			19,309			24,763
Purchase of business		(17,044	)		—			—
Net cash used for investing activities		(207,654	)		(315,838	)		(391,637	)
FINANCING ACTIVITIES
Payment of dividends		(87,789	)		(114,069	)		(47,327	)
Borrowings from notes payable to banks		686,700			844,050			940,850
Repayments of notes payable to banks		(740,400	)		(940,350	)		(858,800	)
Debt issue costs for notes payable to banks		—			—			(415	)
Excess tax benefits for share-based payments		3,178			2,724			3,371
Cash paid for common stock purchased and retired		(25,122	)		(30,224	)		(34,419	)
Proceeds received upon exercise of stock options		—			544			728
Net cash (used for) provided by financing activities		(163,433	)		(237,325	)		3,988
Net (decrease) increase in cash and cash equivalents		(5,463	)		6,770			(1,642	)
Cash and cash equivalents at beginning of year		14,163			7,393			9,035
Cash and cash equivalents at end of year	$	8,700		$	14,163		$	7,393

The accompanying notes are an integral part of these statements.

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, 2013, 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 28, 2014, the Board of Directors approved a $0.105 per share cash dividend payable March 10, 2014 to stockholders of record at the close of business on February 10, 2014.

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.

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. In 2013 and 2012, there were no customers that accounted for more than 10 percent of the Company’s revenues. In 2011, one of our customers accounted for approximately 12 percent of revenues. Additionally, no customer accounted for more than 10 percent of accounts receivable as of December 31, 2013 and 2012.

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 securities 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 during 2013, 2012 or 2011 on its available-for-sale securities. Securities that are held in the non-qualified Supplemental Executive 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 is 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 cost or market value. Cost is determined using first-in, first-out (“FIFO”) method or the weighted average cost method. 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.

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 in September 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 20 years; buildings and leasehold improvements, 15 to 39 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

Goodwill represents the excess of the purchase price over the fair value of net assets of businesses acquired. The carrying amount of goodwill was $31,861,000 at December 31, 2013 and $24,093,000 at December 31, 2012. During 2013, the Company completed an acquisition of assets of a business totaling $17,044,000 that included goodwill of $7,768,000. 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. 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 2013, 2012 and 2011. Based on the qualitative assessment, the Company has concluded that no impairment of its goodwill occurred for the years ended December 31, 2013, 2012 and 2011.

Advertising

Advertising expenses are charged to expense during the period in which they are incurred. Advertising expenses totaled $3,458,000 in 2013, $2,965,000 in 2012, and $2,406,000 in 2011.

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.

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. The Company considers all outstanding unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether paid or unpaid, to be participating securities. 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.

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 )	2013			2012			2011
Net income available for stockholders:	$	166,895		$	274,436		$	296,381
Less: Dividends paid
Common stock		(86,282	)		(111,966	)		(46,479	)
Restricted shares of common stock		(1,507	)		(2,103	)		(848	)
Undistributed earnings	$	79,106		$	160,367		$	249,054

Allocation of undistributed earnings:
Common stock	$	77,620		$	157,093		$	244,053
Restricted shares of common stock		1,486			3,274			5,001

Basic shares outstanding:
Common stock		211,305			210,707			213,153
Restricted shares of common stock		4,199			4,534			4,530
		215,504			215,241			217,683
Diluted shares outstanding:
Common stock		211,305			210,707			213,153
Dilutive effect of stock-based awards		1,229			1,555			2,567
		212,534			212,262			215,720
Restricted shares of common stock		4,199			4,534			4,530
		216,733			216,796			220,250
Basic earnings per share:
Common stock:
Distributed earnings	$	0.40		$	0.53		$	0.22
Undistributed earnings		0.37			0.75			1.14
	$	0.77		$	1.28		$	1.36
Restricted shares of common stock:
Distributed earnings	$	0.36		$	0.46		$	0.19
Undistributed earnings		0.35			0.72			1.10
	$	0.71		$	1.18		$	1.29
Diluted earnings per share:
Common Stock:
Distributed earnings	$	0.40		$	0.53		$	0.22
Undistributed earnings		0.37			0.74			1.13
	$	0.77		$	1.27		$	1.35

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, investments, 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 Company’s investments are classified as available-for-sale securities with the exception of investments held in the non-qualified Supplemental Executive Retirement Plan (“SERP”) which are classified as trading securities. All of these securities are carried at fair value in the accompanying consolidated balance sheets. 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.

Recent Accounting Pronouncements

During the year ended December 31, 2013, the Financial Accounting Standards Board (FASB) issued the following applicable accounting Standards Updates (ASU):

Recently Adopted Accounting Pronouncements:

Accounting Standards Update 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. The amendments in this ASU do not change the current requirements for reporting net income or other comprehensive income in financial statements. All of the information that this ASU requires already is required to be disclosed elsewhere in the financial statements under U.S. GAAP. In addition, an entity is required to present (either on the face of the statement where net income is presented or in the notes) the effects on the line items of net income of significant amounts reclassified out of accumulated other comprehensive income - but only if the item reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. The Company adopted these provisions in the first quarter of 2013 and has included the required additional disclosures in the accompanying financial statements and notes.

Recently Issued Accounting Pronouncements Not Yet Adopted:

Note 2: Accounts Receivable

Accounts receivable, net consists of the following:

December 31,	2013			2012
*(in thousands)*
Trade receivables:
Billed	$	368,583		$	310,997
Unbilled		80,806			82,649
Other receivables		1,240			2,994
Total		450,629			396,640
Less: allowance for doubtful accounts		(13,497	)		(9,110	)
Accounts receivable, net	$	437,132		$	387,530

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,	2013			2012
*(in thousands)*
Beginning balance	$	9,110		$	8,093
Bad debt expense		8,815			1,784
Accounts written-off		(5,421	)		(1,132	)
Recoveries		993			365
Ending balance	$	13,497		$	9,110

Note 3: Inventories

Inventories are $126,604,000 at December 31, 2013 and $140,867,000 at December 31, 2012 and consist of raw materials, parts and supplies.

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,	2013			2012
*(in thousands)*
Land	$	19,264		$	17,420
Buildings and leasehold improvements		130,072			111,986
Operating equipment		1,231,504			1,155,600
Computer software		17,121			20,581
Furniture and fixtures		7,737			7,232
Vehicles		387,854			357,913
Construction in progress		2,076			9,829
Gross property, plant and equipment		1,795,628			1,680,561
Less: accumulated depreciation		(1,069,321	)		(924,235	)
Net property, plant and equipment	$	726,307		$	756,326

Depreciation expense was $215.4 million in 2013, $214.9 million in 2012, and $179.9 million in 2011, and includes amounts recorded as costs of sales and inventory. There were no capital leases outstanding as of December 31, 2013 and December 31, 2012. The Company had accounts payable for purchases of property and equipment of $19.7 million as of December 31, 2013, $24.4 million as of December 31, 2012, and $32.7 million as of December 31, 2011.

Note 5: Income Taxes

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

Years ended December 31,	2013			2012			2011
*(in thousands)*
Current provision:
Federal	$	104,890		$	147,580		$	91,415
State		15,627			14,673			12,938
Foreign		1,918			1,109			1,007
Deferred (benefit) provision:
Federal		(12,025	)		5,027			70,599
State		(1,035	)		(206	)		6,475
Total income tax provision	$	109,375		$	168,183		$	182,434

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

Years ended December 31,	2013			2012			2011
Federal statutory rate		35.0	%		35.0	%		35.0	%
State income taxes, net of federal benefit		3.8			3.2			3.1
Tax credits		(0.3	)		(0.3	)		(0.2	)
Non-deductible expenses		0.5			0.5			0.4
Other		0.6			(0.4	)		(0.2	)
Effective tax rate		39.6	%		38.0	%		38.1	%

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

December 31,	2013			2012
*(in thousands)*
Deferred tax assets:
Self-insurance	$	7,247		$	7,417
Pension		8,018			9,688
State net operating loss carryforwards		484			1,165
Bad debts		4,748			3,489
Accrued payroll		2,019			2,038
Stock-based compensation		5,183			4,567
Tangible property regulations 481(a)		7,665			—
All others		1,541			274
Valuation allowance		(83	)		(1,003	)
Gross deferred tax assets		36,822			27,635
Deferred tax liabilities:
Depreciation		(165,960	)		(168,717	)
Goodwill amortization		(7,094	)		(6,394	)
All Others		(2,759	)		(1,754	)
Gross deferred tax liabilities		(175,813	)		(176,865	)
Net deferred tax liabilities	$	(138,991	)	$	(149,230	)

As of December 31, 2013, undistributed earnings of the Company’s foreign subsidiaries amounted to $12.0 million. Those earnings are considered to be indefinitely reinvested and, accordingly, no U.S. federal and state income taxes have been provided thereon. Upon distribution of those earnings in the form of dividends or otherwise, the Company would be subject to both U.S. income taxes and withholding taxes payable to the foreign countries. The Company’s current intention is to permanently reinvest funds held in our foreign subsidiaries outside of the U.S., with the possible exception of repatriation of funds that have been previously subject to U.S. federal and state taxation or when it would be tax effective through the utilization of foreign tax credits, or would otherwise create no additional U.S. tax cost.

As of December 31, 2013, the Company has net operating loss carry forwards related to state income taxes of approximately $11.8 million that will expire between 2014 and 2033. As of December 31, 2013 the Company has a valuation allowance of approximately $0.1 million, representing the tax affected amount of loss carry forwards that the Company does not expect to utilize, against the corresponding deferred tax asset.

Total net income tax payments were $122,916,000 in 2013, $158,700,000 in 2012, and $90,729,000 in 2011.

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 2010 through 2013 tax years remain open to examination. Additional years may be open to the extent attributes are being carried forward to an open year. The Internal Revenue Service (IRS) commenced an examination of the Company’s US federal income tax return for the 2011 tax year during the fourth quarter of 2013 that is anticipated to be completed by the end of 2014. As of December 31, 2013, the IRS has not proposed any adjustments in connection with the examination.

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 recognized a significant increase in its liability for unrecognized tax benefits in the current year related primarily to refund claims filed for state income taxes.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	2013		2012
Balance at January 1	$	38,000	$	35,000
Additions based on tax positions related to the current year		3,430,000		—
Additions for tax positions of prior years		12,877,000		3,000
Balance at December 31	$	16,345,000	$	38,000

The Company’s liability for unrecognized tax benefits as disclosed above, would affect our effective rate if recognized. Additionally, interest and penalties related to the unrecognized tax benefits as disclosed above as of December 31, 2013 and December 31, 2012 amounted to $276,000 and $3,000, respectively.

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, 2013 and 2012.

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

The American Taxpayer Relief Act of 2012 was signed into law on January 2, 2013 and included an extension for one year of the 50% bonus depreciation allowance. The provision specifically applied to qualifying property placed in service before January 1, 2014. The acceleration of deductions on 2013 qualifying capital expenditures resulting from the bonus depreciation provision had no impact on our 2013 effective tax rate.

On September 23, 2013, the U.S. Department of the Treasury issued final regulations under Internal Revenue Code Sections 162(a) and 263(a) that provide guidance on the deduction and capitalization of expenditures related to tangible property. These regulations will result in our adoption of certain mandatory and elective accounting methods with respect to property and equipment, inventory and supplies. The regulations are generally effective for taxable years beginning on or after January 1, 2014.

In connection with the issuance of the regulations, RPC has assessed and estimated the impact of the method changes on its financial statements. We have estimated favorable IRC Section 481(a) adjustments of approximately $21 million (gross). The tax affected amount of the assessment ($7.7 million) has been separately disclosed in our schedule of deferred tax assets and liabilities. This amount is subject to change as we finalize our analysis and file method changes under the new regulations during 2014.

Note 6: Long-Term Debt

In August 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 $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 a commitment 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, 2013.

As of December 31, 2013, RPC has outstanding borrowings of $53.3 million under the facility. Additionally there were letters of credit relating to self-insurance programs and contract bids outstanding for $24.1 million as of December 31, 2013. Interest incurred and paid on the credit facility, interest capitalized related to facilities and equipment under construction, and the related weighted average interest rates were as follows for the periods indicated:

Years Ended December 31,	2013			2012			2011
(in thousands except interest rate data)
Interest incurred	$	2,090		$	2,936		$	4,146
Capitalized interest	$	935		$	1,026		$	627
Interest paid (net of capitalized interest)	$	618		$	1,498		$	3,168
Weighted average interest rate		3.7	%		2.3	%		2.8	%

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 in September 2011.

On January 17, 2014, the Company amended the Credit Agreement which extended the maturity date of all the revolving loans from August 31, 2015 to January 17, 2019 (as amended, the “Credit Agreement”.) RPC incurred commitment fees and other debt related costs associated with the amendment of approximately $0.7 million. Interest rates on the revolving loans under the Credit Agreement are reduced by 0.125% at all pricing levels under the Credit Agreement. The amount of the swing line sub-facility under the Credit Agreement has increased from $25 million to $35 million.

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			Total
Balance at December 31, 2011	$	(12,981	)	$	187		$	148		$	(12,646	)
Change during 2012:
Before-tax amount		(3,355	)		(249	)		180			(3,424	)
Tax benefit		1,224			91			85			1,400
Reclassification adjustment, net of taxes:
Amortization of net loss (1)		424			—			—			424
Total activity in 2012		(1,707	)		(158	)		265			(1,600	)
Balance at December 31, 2012	$	(14,688	)	$	29		$	413		$	(14,246	)
Change during 2013:
Before-tax amount		6,976			(30	)		(778	)		6,168
Tax (expense) benefit		(2,546	)		11			—			(2,535	)
Reclassification adjustment, net of taxes:
Amortization of net loss (1)		498			—			—			498
Total activity in 2013		4,928			(19	)		(778	)		4,131
Balance at December 31, 2013	$	(9,760	)	$	10		$	(365	)	$	(10,115	)

(1)

Reported as part of selling, general and administrative expenses.

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:

Level 1 – Quoted market prices in active markets for identical assets or liabilities.

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.

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, 2013 and 2012:

	Fair Value Measurements at December 31, 2013 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	$	—	$	13,963	$	—
Available-for-sale securities – equity securities	$	445	$	—	$	—

	Fair Value Measurements at December 31, 2012 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	$	—	$	11,103	$	—
Available-for-sale securities – equity securities	$	380	$	—	$	—

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. The Company’s policy is to recognize transfers between levels at the beginning of quarterly reporting periods. For the year ended December 31, 2013 there were no significant transfers in or out of levels 1, 2 or 3.

At December 31, 2013 and 2012, amounts outstanding under the Company’s credit facility were $53,300,000 and $107,000,000 and based on quotes from the lender (level 2 inputs) is similar to the fair values of these amounts at the respective dates. 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.

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, 2013, are summarized in the following table:

*(in thousands)*
2014	$	8,984
2015		7,664
2016		4,929
2017		2,989
2018		2,231
Thereafter		5,991
Total rental commitments	$	32,788

Total rental expense, including short-term rentals, charged to operations was $20,582,000 in 2013, $18,224,000 in 2012, $19,814,000 in 2011.

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.

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. Any probable and estimable assessment costs are included in accrued state, local and other taxes.

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.

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 $5.1 million and thus the plan was under-funded as of December 31, 2013.

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,	2013			2012
*(in thousands)*
Accumulated Benefit Obligation at end of year	$	37,528		$	42,699

CHANGE IN PROJECTED BENEFIT OBLIGATION:
Benefit obligation at beginning of year	$	42,699		$	38,278
Service cost		—			—
Interest cost		1,741			1,869
Amendments		—			—
Actuarial loss		(5,199	)		4,221
Benefits paid		(1,713	)		(1,669	)
Projected benefit obligation at end of year	$	37,528		$	42,699
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year	$	29,519		$	24,180
Actual return on plan assets		3,820			2,712
Employer contribution		800			4,296
Benefits paid		(1,713	)		(1,669	)
Fair value of plan assets at end of year		32,426			29,519

Funded status at end of year	$	(5,102	)	$	(13,180	)

December 31,	2013			2012
*(in thousands)*
AMOUNTS RECOGNIZED IN THE CONSOLIDATED BALANCE SHEETS CONSIST OF:
Noncurrent assets	$	—		$	—
Current liabilities		—			—
Noncurrent liabilities		(5,102	)		(13,180	)
	$	(5,102	)	$	(13,180	)

December 31,	2013		2012
*(in thousands)*
AMOUNTS (PRE-TAX) RECOGNIZED IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) CONSIST OF:
Net loss (gain)	$	15,369	$	23,129
Prior service cost (credit)		—		—
Net transition obligation (asset)		—		—
	$	15,369	$	23,129

The accumulated benefit obligation for the Retirement Income Plan at December 31, 2013 and 2012 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,	2013			2012
*(in thousands)*
Funded status	$	(5,102	)	$	(13,180	)
SERP liability		(16,864	)		(13,363	)
Long-term pension liability	$	(21,966	)	$	(26,543	)

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. Amounts contributed to the plan totaled $800,000 in 2013 and $4,296,000 in 2012.

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

Years ended December 31,	2013			2012			2011
*(in thousands)*
Service cost for benefits earned during the period	$	—		$	—		$	—
Interest cost on projected benefit obligation		1,741			1,869			1,916
Expected return on plan assets		(2,043	)		(1,846	)		(1,831	)
Amortization of net loss		784			667			463
Net periodic benefit plan cost	$	482		$	690		$	548

The Company recognized pre-tax (increases) decreases to the funded status in accumulated other comprehensive loss of $(7,760,000) in 2013, $2,688,000 in 2012 and $4,800,000 in 2011. There were no previously unrecognized prior service costs as of December 31, 2013, 2012 and 2011. The pre-tax amounts recognized in accumulated other comprehensive loss for the years ended December 31, 2013, 2012 and 2011 are summarized as follows:

*(in thousands)*	2013			2012			2011
Net (gain) loss	$	(6,976	)	$	3,355		$	5,263
Amortization of net loss		(784	)		(667	)		(463	)
Net transition obligation (asset)		—			—			—
Amount recognized in accumulated other comprehensive loss		(7,760	)	$	2,688		$	4,800

The amounts in accumulated other comprehensive loss expected to be recognized as components of net periodic benefit cost in 2014 are as follows:

*(in thousands)*	2014
Amortization of net loss	$	484
Prior service cost (credit)		—
Net transition obligation (asset)		—
Estimated net periodic benefit plan cost	$	484

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

December 31,	2013			2012			2011
Projected Benefit Obligation:
Discount rate		5.20	%		4.16	%		5.00	%
Rate of compensation increase		N/A			N/A			N/A
Net Benefit Cost:
Discount rate		4.16	%		5.00	%		5.49	%
Expected return on plan assets		7.00	%		7.00	%		7.00	%
Rate of compensation increase		N/A			N/A			N/A

The Company’s expected return on assets assumption is derived from a detailed periodic assessment conducted by its management and its investment advisor. 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, 2013 and 2012 by asset category along with the target allocation for 2014 are as follows:

Asset Category	Target Allocation for 2014			Percentage of Plan Assets as of December 31, 2013			Percentage of Plan Assets as of December 31, 2012

Cash and Cash Equivalents		0% - 5	%		0.6	%		0.2	%
Debt Securities – Core Fixed Income		15% - 50	%		25.3	%		20.2	%
Tactical – Fund of Equity and Debt Securities		—			—			15.1	%
Domestic Equity Securities		0% - 30	%		26.6	%		15.2	%
Global Equity Securities		—			—			16.0	%
International Equity Securities		0% - 30	%		31.4	%		15.1	%
Real Estate		0% - 20	%		8.3	%		9.2	%
Real Return		0% - 20	%		7.8	%		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 small-cap companies domiciled domestically and internationally. Fixed-income securities include corporate bonds, mortgage-backed securities, sovereign bonds, and U.S. Treasuries. Other types of investments include real estate 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 but not limited to individual market securities, equity and fixed income funds in which the underlying securities are marketable, and debt funds to achieve this target allocation. The Company expects to contribute approximately $765,000 to the pension plan during fiscal year 2014.

Some of our assets, primarily our private equity and real estate 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, 2013 plan asset reporting, publicly traded asset pricing was used where possible. For assets without readily determinable values, estimates were derived from investment manager statements combined with discussions focusing on underlying fundamentals and significant events. Additionally, 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, 2013 and December 31, 2012. 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.

Fair Value Hierarchy as of December 31, 2013:

*Investments (in thousands)*			Total		Level 1		Level 2		Level 3
Cash and Cash Equivalents	(1	)	$	210	$	210	$	—	$	—
Fixed Income Securities	(2	)		8,201		—		8,201		—
Domestic Equity Securities				8,590		8,590		—		—
Global Equity Securities				—		—		—		—
International Equity Securities	(3	)		10,192		—		10,192		—
Tactical Composite	(4	)		—		—		—		—
Real Estate	(5	)		2,705		—		—		2,705
Real Return	(6	)		2,528		—		2,528		—
			$	32,426	$	8,800	$	20,921	$	2,705

Fair Value Hierarchy as of December 31, 2012:

*Investments (in thousands)*			Total		Level 1		Level 2		Level 3
Cash and Cash Equivalents	(1	)	$	61	$	61	$	—	$	—
Fixed Income Securities	(2	)		5,959		—		5,959		—
Domestic Equity Securities				4,475		4,475		—		—
Global Equity Securities				4,446		4,446		—		—
International Equity Securities	(3	)		4,737		2,205		2,532		—
Tactical Composite	(4	)		4,454		—		4,454		—
Real Estate	(5	)		2,730		—		—		2,730
Real Return	(6	)		2,657		—		2,657		—
			$	29,519	$	11,187	$	15,602	$	2,730

(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.

The following table presents a reconciliation of Level 3 assets held during the year ended December 31, 2013:

*Investments (in thousands)*		Balance at December 31, 2012				Net Realized and Unrealized Gains/(Losses)				Net Purchases, Issuances and Settlements				Net Transfers In to (Out of) Level 3				Balance at December 31, 2013
Real Estate		$	2,730			$	217			$	(242	)		$	—			$	2,705

The following table presents a reconciliation of Level 3 assets held during the year ended December 31, 2012:

*Investments (in thousands)*		Balance at December 31, 2011				Net Realized and Unrealized Gains/(Losses)				Net Purchases, Issuances and Settlements				Net Transfers In to (Out of) Level 3				Balance at December 31, 2012
Real Estate		$	1,350			$	365			$	1,015			$	—			$	2,730

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

*(in thousands)*
2014	$	1,896
2015		1,989
2016		2,189
2017		2,254
2018		2,346
2019-2023		12,614

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 to satisfy the obligations of 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 $47.4 million in variable life insurance policies as of December 31, 2013 and $44.3 million as of December 31, 2012. 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 $13,963,000 as of December 31, 2013 and $11,103,000 as of December 31, 2012. 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 $2,026,000 in 2013, $1,352,000 in 2012, and $(194,000) for 2011. The SERP liability is recorded on the balance sheet in long-term pension liabilities with any change in the fair value of the liabilities recorded as compensation cost within selling, general and administrative expenses 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 $5,451,000 in 2013, $5,088,000 in 2012, and $4,074,000 in 2011.

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, 2013, there were 1,355,431 shares available for grants.

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 the 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 a financing activity in the accompanying consolidated statements of cash flows.

Pre-tax stock-based employee compensation expense was $8,177,000 in 2013 ($5,192,000 after tax), $7,860,000 in 2012 ($4,991,000 after tax) and $8,075,000 in 2011 ($5,128,000 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.

There were no stock options exercised during 2013 and there have been no stock options outstanding since December 31, 2012. The total intrinsic value of stock options exercised was $7,467,000 during 2012 and $11,882,000 during 2011. Tax benefits associated with the exercise of stock options exercised totaled $431,000 during 2012 and $799,000 during 2011 and were credited to capital in excess of par value and are classified as financing cash flows.

Restricted Stock

The Company has granted employees time lapse restricted stock which vest after a stipulated number of years from the grant date, depending on the terms of the issue. Time lapse restricted shares issued 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. The agreement under which the restricted stock is issued provides that shares awarded may not be sold or otherwise transferred until restrictions or, established under the stock plans have lapsed. Upon termination of employment from RPC (other than due to death, disability or retirement on or after age 65), shares with restrictions must be returned to the Company.

The following is a summary of the changes in non-vested restricted shares for the year ended December 31, 2013:

	Shares			Weighted Average Grant- Date Fair Value
Non-vested shares at January 1, 2013		4,494,191		$	8.12
Granted		850,500			13.68
Vested		(1,078,534	)		6.36
Forfeited		(151,357	)		9.72
Non-vested shares at December 31, 2013		4,114,800		$	9.67

The fair value of restricted share 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 $13.68 for 2013, $11.69 for 2012 and $11.59 for 2011. The total fair value of shares vested was $15,471,000 during 2013, $10,695,000 during 2012 and $11,861,000 during 2011. The tax benefit for compensation tax deductions in excess of compensation expense was credited to capital in excess of par value aggregating $3,178,000 for 2013, $2,293,000 for 2012 and $2,572,000 for 2011. The excess tax deductions are classified as a financing activity in the accompanying consolidated statements of cash flows.

Other Information

As of December 31, 2013, total unrecognized compensation cost related to non-vested restricted shares was $34,614,000 which is expected to be recognized over a weighted-average period of 3.2 years. As of December 31, 2013, there was no unrecognized compensation cost related to non-vested stock options.

The Company received cash from options exercised of $544,000 during 2012 and $728,000 during 2011. 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 $377,000 during 2012 and $720,000 during 2011 and have been excluded from the consolidated statements of cash flows.

Note 11: Related Party Transactions

Marine Products Corporation

Other

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.

Summarized financial information concerning RPC’s reportable segments for the years ended December 31, 2013, 2012 and 2011 are shown in the following table:

	Technical Services		Support Services		Corporate			Loss on disposition of assets, net			Total
*(in thousands)*
2013
Revenues	$	1,729,732	$	131,757	$	—		$	—		$	1,861,489
Operating profit (loss)		276,246		26,223		(17,685	)		(9,371	)		275,413
Capital expenditures		167,586		32,250		1,845			—			201,681
Depreciation and amortization		181,026		31,417		685			—			213,128
Identifiable assets		1,113,877		202,243		67,740			—			1,383,860
2012
Revenues	$	1,794,015	$	151,008	$	—		$	—		$	1,945,023
Operating profit (loss)		420,231		45,912		(17,654	)		(6,099	)		442,390
Capital expenditures		277,686		46,053		5,197			—			328,936
Depreciation and amortization		183,762		30,707		430			—			214,899
Identifiable assets		1,128,124		175,611		63,428			—			1,367,163
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

The following summarizes selected information between the United States and all international locations combined for the years ended December 31, 2013, 2012 and 2011. 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,	2013		2012		2011
*(in thousands)*
United States Revenues	$	1,795,592	$	1,870,815	$	1,757,661
International Revenues		65,897		74,208		52,146
	$	1,861,489	$	1,945,023	$	1,809,807

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, 2013 (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 29 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, 2013 and issued a report thereon which is included on page 30 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 2014 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 2014 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 2014 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 2014 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 2014 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, 2013.

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		—		$ —		1,355,431	(1)
Equity compensation plans not approved by securityholders		—		—		—
Total		—		$ —		1,355,431

(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 2014 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 2014 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 2014 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

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

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

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

10.7

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

10.8

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

10.9

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).

10.10

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

10.11

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

Form of Time Lapse Restricted Stock Agreement (incorporated herein by reference to Exhibit 10.1 to the Form 10-Q filed on May 2, 2012).

10.15

Summary of Compensation Arrangements with Non-Employee Directors (incorporated herein by reference to Exhibit 10.18 to the Form 10-K filed on March 1, 2013).

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

10.7		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).

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

10.9		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).

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

10.11		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).

10.12		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).

10.13		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 (incorporated herein by reference to Exhibit 10.16 to the Form 10-K filed on February 29, 2012).

10.14		Form of Time Lapse Restricted Stock Agreement (incorporated herein by reference to Exhibit 10.1 to the Form 10-Q filed on May 2, 2012).

10.15		Summary of Compensation Arrangements with Non-Employee Directors (incorporated herein by reference to Exhibit 10.18 to the Form 10-K filed on March 1, 2013).

10.16		Amendment No. 2 to Credit Agreement and Amendment No. 1 to Subsidiary Guaranty Agreement dated as of January 17, 2014 between RPC, Bank of America, N.A., certain other Lenders party thereto, and the Subsidiary Loan Parties party thereto (incorporated herein by reference to Exhibit 99.1 to the Company’s Form 8-K dated January 17, 2014).

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

95.1		Mine Safety Disclosure

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 28, 2014

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 28, 2014

/s/ Ben M. Palmer
Ben M. Palmer		Chief Financial Officer (Principal Financial and Accounting Officer)		February 28, 2014

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
Gary W. Rollins, Director	Linda H. Graham, Director
Henry B. Tippie, Director	Bill J. Dismuke, Director
James B. Williams, Director	Larry L. Prince, Director

/s/ Richard A. Hubbell
Richard A. Hubbell
Director and as Attorney-in-fact
February 28, 2014

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	29

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting	30

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements	31

Consolidated Balance Sheets as of December 31, 2013 and 2012	32

Consolidated Statements of Operations for the three years ended December 31, 2013	33

Consolidated Statements of Comprehensive Income for the three years ended December 31, 2013	34

Consolidated Statements of Stockholders’ Equity for the three years ended December 31, 2013	35

Consolidated Statements of Cash Flows for the three years ended December 31, 2013	36

Notes to Consolidated Financial Statements	37 - 54

SCHEDULE
Schedule II — Valuation and Qualifying Accounts	60

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, 2013, 2012 and 2011
*(in thousands)*	Balance at Beginning of Period		Charged to Costs and Expenses		Net (Deductions) Recoveries			Balance at End of Period
Year ended December 31, 2013
Allowance for doubtful accounts	$	9,110	$	8,815	$	(4,428	) (1)	$	13,497
Deferred tax asset valuation allowance	$	1,003	$	—	$	(920	) (2)	$	83
Year ended December 31, 2012
Allowance for doubtful accounts	$	8,093	$	1,784	$	(767	) (1)	$	9,110
Deferred tax asset valuation allowance	$	1,295	$	—	$	(292	) (2)	$	1,003
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

(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)
2013
Revenues	$	425,821	$	457,566	$	491,121	$	486,981
Operating profit	$	57,219	$	67,853	$	85,839	$	64,502
Net income	$	35,076	$	40,416	$	53,760	$	37,643
Net income per share — basic (a)	$	0.16	$	0.19	$	0.25	$	0.18
Net income per share — diluted (a)	$	0.16	$	0.19	$	0.25	$	0.17
2012
Revenues	$	502,557	$	500,106	$	472,418	$	469,942
Operating profit	$	130,857	$	119,858	$	102,368	$	89,307
Net income	$	80,755	$	72,260	$	66,040	$	55,381
Net income per share — basic (a)	$	0.37	$	0.34	$	0.31	$	0.26
Net income per share — diluted (a)	$	0.37	$	0.33	$	0.30	$	0.26

(a)	The sum of the income 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.