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RES > SEC Filings for RES > Form 10-K on 28-Feb-2014All Recent SEC Filings

Show all filings for RPC INC

Form 10-K for RPC INC


28-Feb-2014

Annual Report


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:
. . .
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