Overview

The following discussion should be read in conjunction with "Selected Financial Data," and the Consolidated Financial Statements included elsewhere in this document. See also "Forward-Looking Statements" on page 2.

RPC, Inc. ("RPC") provides a broad range of specialized oilfield services primarily to independent and major oilfield companies engaged in exploration, production and development of oil and gas properties throughout the United States, including the southwest, mid-continent, Gulf of Mexico, Rocky Mountain and Appalachian regions, and in selected international markets. The Company's revenues and profits are generated by providing equipment and services to customers who operate oil and gas properties and invest capital to drill new wells and enhance production or perform maintenance on existing wells.

Our key business and financial strategies are:

- To focus our management resources on and invest our capital in equipment and geographic markets that we believe will earn high returns on capital, and maintain an appropriate capital structure.

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

- To maintain an 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 natural gas prices which have gradually increased following declines in 2011 and the first two quarters of 2012, but which remain too low to encourage natural gas drilling activity in the U.S. domestic market. In the first quarter of 2013, U.S. natural gas drilling activity was at its lowest level since the second quarter of 1999. Furthermore, U.S. natural gas production reached historical highs during the fourth quarter of 2012, in spite of declining natural gas drilling activity. We believe that further near-term negative impacts of high natural gas production will be minimal, because during the first quarter of 2013 natural gas drilling has declined to less than 25 percent of total U.S. domestic drilling activity. However, we also believe that this condition decreases the possibility that our customers' natural gas-directed drilling activities will increase significantly in the near term. The price of oil did not fluctuate significantly during 2012, but has remained high enough to encourage our customers to continue conducting oil-directed drilling activities. During the first quarter of 2013, the price of oil has increased compared to the fourth quarter of 2012. The consistently high price of oil over the past two years and the price increase during the first quarter of 2013 have positive implications for RPC's activity levels in 2013. RPC has operations in most of the areas in which drilling activity is directed towards oil, and we increased our presence in these areas during 2012. The average U.S. rig count increased by two percent during 2012. During the first quarter of 2013, the rig count was approximately 12 percent lower than the first quarter of 2012 and three percent lower than the fourth quarter of 2012. The rig count during the first quarter of 2013 is approximately 13 percent lower than the peak rig count attained during the prior U.S. drilling cycle improvement, which occurred during the third quarter of 2008. The U.S. domestic rig count may increase during 2013, but any increases are likely to be modest due to weak natural gas prices and high natural gas production from existing wells.

In addition to the overall rig count, the Company also monitors the number of horizontal and directional wells drilled in the U.S. domestic market, because this type of well is more service-intensive than a vertical oil or gas well, thus requiring more of the Company's services provided for a longer period of time. The number of horizontal and directional wells drilled in the United States increased by approximately five percent in 2012, and was 71 percent of total wells drilled during the year. During the first part of 2013, the percentage of horizontal and directional wells drilled as a percentage of total wells was approximately 75 percent. In addition, the percentage of wells drilled for oil increased during 2012, and we believe that this percentage will increase in 2013 due to the continued high price of oil and the low price and high production levels of natural gas. During 2012, a combination of relatively flat activity levels, a shift towards less service-intensive drilling and completion activities, and a larger U.S. domestic fleet of revenue-producing equipment negatively impacted demand and 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 drilling and completion programs. Such arrangements have been 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 have also positively impacted the Company's financial results, because they increase the utilization of our revenue-producing equipment and allow us to conduct our operations more efficiently. A number of these arrangements expired during 2012 and were not renewed at the same or similar terms due to declining customer activity levels in service-intensive unconventional completion work. We do not expect to enter into additional contractual arrangements with such terms during 2013.

The Company's response to the operating environment during 2012 has been to curtail our purchases of revenue-producing equipment. We have also relocated selected fleets of equipment from areas of declining activity to oilfield basins with higher activity levels. In each of these situations, we had existing operational locations in these oilfield basins, so these relocations were accomplished with minimal inefficiencies. 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 $328.9 million in 2012 compared to $416.4 million in 2011. 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 2012 totalled $1.9 billion, an increase of 7.5 percent compared to 2011. Cost of revenues increased $113.2 million in 2012 compared to the prior year due to the variable nature of many of these expenses and was approximately 57 percent of revenues in 2012 compared to 55 percent of revenues in 2011. Selling, general and administrative expenses as a percentage of revenues increased approximately 0.6 percentage points in 2012 compared to 2011.

Income before income taxes was $442.6 million in 2012 compared to $478.8 million in the prior year. The effective tax rate for 2012 was 38.0 percent compared to 38.1 percent in the prior year. Diluted earnings per share were $1.27 in 2012 compared to $1.35 for the prior year.

Cash flows from operating activities were $559.9 million in 2012 and $386.0 million in 2011, and cash and cash equivalents were $14.2 million at December 31, 2012, an increase of $6.8 million compared to December 31, 2011. As of December 31, 2012, there was $107.0 million in outstanding borrowings under our credit facility.

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. Unconventional activity as a percentage of total oilfield activity has grown steadily over the past several years and was 71 percent of total wells drilled during 2012. Early in the first quarter of 2013, unconventional drilling represented 75 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. Although the price of natural gas began to recover during the third and fourth quarters of 2012 and the first quarter of 2013, its price remains too low to encourage drilling in the service-intensive natural gas resource shale plays in the U.S. domestic market. 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 2012, the average price of benchmark natural gas liquids was 31.4 percent lower than in the prior year, and it declined an additional 16.0 percent early in the first quarter of 2013. These trends have negative implications for our near-term activity levels, since the recent decline in domestic drilling activity is due to declines in natural gas-directed drilling. On the other hand, the average price of oil remained high during 2012, and has risen early in the first quarter of 2013. The high price of oil should continue to have a positive impact on our customers' activity levels and our financial results, since there are a number of significant U.S. domestic shale resource plays which produce oil and petroleum liquids, and RPC has operational locations and revenue-producing equipment in these locations.

The effect of these trends is evident in the current composition of the U.S. domestic rig count, approximately 75 percent of which was directed towards oil during the first quarter of 2013. We believe that the trend of an increased percentage of oil-directed drilling and a decreased percentage of gas-directed drilling will continue in the near term. We believe that this trend will continue due to continued low prices for natural gas, as well as high production from existing natural gas wells. We do not believe that the overall rig count will increase significantly during 2013 unless the price of natural gas increases significantly.

We continue to monitor the market for our services and the competitive environment in 2013. We are concerned about the continued low price of natural gas and natural gas liquids, and the fact that the high cost of completing wells in many unconventional shale plays will discourage our customers from conducting drilling and completion activities in these areas until these commodity prices improve. We also monitor the competitive environment because the high historical financial returns and favorable long-term outlook for our industry continue have attracted new entrants and encouraged existing service companies to purchase additional revenue-producing equipment. Although these catalysts for increased competitive pressures began to subside during 2012, we believe that there is an excessive service capacity in the U.S. domestic market at the present time, given the current level and composition of drilling and completion activities. Because of these concerns, we anticipate that our equipment purchases will be lower in 2013 than in 2012. 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 structure by industry standards. Based on current industry conditions, we believe that the Company's consolidated revenues will increase moderately in 2013 compared to 2012 and financial performance in the period will also improve moderately.

Results of Operations

Years Ended December 31,                                2012            2011            2010
(in thousands except per share amounts and
industry data)
Consolidated revenues                                $ 1,945,023     $ 1,809,807     $ 1,096,384
Revenues by business segment:
Technical                                            $ 1,794,015     $ 1,663,793     $   979,834
Support                                                  151,008         146,014         116,550

Consolidated operating profit                        $   442,390     $   482,081     $   238,845
Operating profit by business segment:
Technical                                            $   420,231     $   451,259     $   217,144
Support                                                   45,912          51,672          31,086
Corporate expenses                                       (17,654 )       (17,019 )       (13,143 )
(Loss) gain on disposition of assets, net                 (6,099 )        (3,831 )         3,758

Net income                                           $   274,436     $   296,381     $   146,742
Earnings per share - diluted                         $      1.27     $      1.35     $      0.67
Percentage of cost of revenues to revenues                    57 %            55 %            55 %
Percentage of selling, general and administrative
expenses to revenues                                           9 %             8 %            11 %
Percentage of depreciation and amortization
expenses to revenues                                          11 %            10 %            12 %
Effective income tax rate                                   38.0 %          38.1 %          38.2 %
Average U.S. domestic rig count                            1,919           1,877           1,543
Average natural gas price (per thousand cubic feet
(mcf))                                               $      2.73     $      3.95     $      4.34
Average oil price (per barrel)                       $     94.20     $     94.94     $     79.39

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 most service lines partially offset by lower pricing for our services in several 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. At the present time, we believe that our activity levels are affected by both the price of natural gas and the price of oil, since oil-directed activity as a percentage of total U.S. activity has increased significantly during 2012. 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 several of the services within our technical services segment. 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. Our international revenues are impacted by the timing of project initiation and their ultimate duration.

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 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.

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

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

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

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

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

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

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

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

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

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

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