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CAM > SEC Filings for CAM > Form 10-Q on 29-Jul-2013All Recent SEC Filings

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Form 10-Q for CAMERON INTERNATIONAL CORP


29-Jul-2013

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

In addition to the historical data contained herein, this document includes forward-looking statements regarding future market strength, customer spending and order levels, revenues and earnings of the Company, as well as expectations regarding equipment deliveries, margins, profitability, the ability to control and reduce raw material, overhead and operating costs, cash generated from operations, legal fees, costs associated with, or any punitive liability remaining from a number of lawsuits filed against the Company in connection with the Deepwater Horizon matter, capital expenditures and the use of existing cash balances and future anticipated cash flows made in reliance upon the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The Company's actual results may differ materially from those described in any forward-looking statements. Any such statements are based on current expectations of the Company's performance and are subject to a variety of factors, some of which are not under the control of the Company, which can affect the Company's results of operations, liquidity or financial condition. Such factors may include overall demand for, and pricing of, the Company's products; the size and timing of orders; the Company's ability to successfully execute large subsea and drilling projects it has been awarded; the possibility of cancellations of orders in backlog; the Company's ability to convert backlog into revenues on a timely and profitable basis; the impact of acquisitions the Company has made or may make, including the impact of OneSubsea; changes in the price of (and demand for) oil and gas in both domestic and international markets; raw material costs and availability; political and social issues affecting the countries in which the Company does business; fluctuations in currency markets worldwide; and variations in global economic activity. In particular, current and projected oil and gas prices historically have generally directly affected customers' spending levels and their related purchases of the Company's products and services. As a result, changes in oil and gas price expectations may impact the demand for the Company's products and services and the Company's financial results due to changes in cost structure, staffing and spending levels the Company makes in response thereto. See additional factors discussed in "Factors That May Affect Financial Condition and Future Results" contained herein.

Because the information herein is based solely on data currently available, it is subject to change as a result of, among other things, changes in conditions over which the Company has no control or influence, and should not therefore be viewed as assurance regarding the Company's future performance. Additionally, the Company is not obligated to make public disclosure of such changes unless required under applicable disclosure rules and regulations.


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SECOND QUARTER 2013 COMPARED TO SECOND QUARTER 2012

Market Conditions

Information related to drilling activity and certain commodity spot and futures
prices during each quarter and the number of deepwater floaters and semis under
contract at the end of each period follows:

                                              Three Months Ended
                                                   June 30,                  Increase (Decrease)
                                              2013           2012          Amount             %
Drilling activity (average number of
working rigs during period)(1):
United States                                   1,761          1,970           (209 )          (10.6 )%
Canada                                            155            173            (18 )          (10.4 )%
Rest of world                                   1,306          1,229             77              6.3 %
Global average rig count                        3,222          3,372           (150 )           (4.4 )%

Commodity prices (average of daily U.S.
dollar prices per unit during
period)(2):
West Texas Intermediate Cushing, OK
crude spot price per barrel in U.S.
dollars                                    $    94.14      $   93.30     $     0.84              0.9 %
Henry Hub natural gas spot price per
MMBtu in U.S. dollars                      $     4.02      $    2.30     $     1.72             74.8 %

Twelve-month futures strip price (U.S.
dollar amount at period end)(2):
West Texas Intermediate Cushing, OK
crude oil contract (per barrel)            $    93.62      $   87.14     $     6.48              7.4 %
Henry Hub Natural Gas contract (per
MMBtu)                                     $     3.76      $    3.29     $     0.47             14.3 %

Contracted drillships and semi
submersibles by location at
period-end(3):
U.S. Gulf of Mexico                                40             40              -                -
Central and South America                          88             85              3              3.5 %
Northwestern Europe                                47             45              2              4.4 %
West Africa                                        37             34              3              8.8 %
Southeast Asia and Australia                       23             40            (17 )          (42.5 )%
Other                                              45             30             15             50.0 %

(1) Based on average monthly rig count data from Baker Hughes

(2) Source: Bloomberg

(3) Source: ODS-Petrodata Ltd.

The decrease in average worldwide operating rigs during the second quarter of 2013 as compared to the second quarter of 2012 was driven by lower North American natural gas focused drilling activity. Despite the improvement in year over year natural gas pricing, the challenging economics associated with horizontal shale development drilling at current prices continues to constrain the overall rig market. The average number of rigs drilling for gas was down nearly 40% in the United States and almost 7% in Canada in the second quarter of 2013 as compared to the second quarter of 2012.

Crude oil prices (West Texas Intermediate, Cushing, OK) were fairly consistent throughout much of the second quarter of 2013 after reaching a low of $86.68 per barrel in mid-April before closing the period at $96.56 per barrel. On average, crude oil prices were flat during the second quarter of 2013 as compared to the second quarter of 2012. The twelve month futures price for crude oil at June 30, 2013 was $93.62, a 7.4% increase compared to futures prices at June 30, 2012.


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Natural gas (Henry Hub) prices continued to trend upward during the second quarter of 2013 reaching their highest levels since September 2011, at the end of May before closing the quarter at $3.57 per MMBtu. On average, prices during the second quarter of 2013 were up 75% as compared to the same period in 2012.
The 12-month futures strip price for natural gas at June 30, 2013 was $3.76 per MMBtu, 14.3% above the futures price at June 30, 2012.

Outlook

Recent order rates for certain of the Company's products that serve the natural gas focused drilling market have been negatively affected by weak market conditions. The low natural gas futures price strip may continue to have a dampening effect on North American drilling activity and may have a further adverse impact on the Company's North American operations, including its wellhead separation businesses, during the year.

Critical Accounting Policies

Goodwill - The Company reviews the carrying value of goodwill in accordance with accounting rules on impairment of goodwill, which require that the Company estimate the fair value of each of its reporting units annually, or when impairment indicators exist, and compare such amounts to their respective carrying values to determine if an impairment of goodwill is required. The estimated fair value of each reporting unit is determined using discounted future expected cash flow models (level 3 observable inputs) consistent with the accounting guidance for fair value measurements. Certain estimates and judgments are required in the application of the discounted cash flow models, including, but not limited to, estimates of future cash flows and the selection of a discount rate. Generally, this review is conducted during the first quarter of each annual period. The results of the 2013 test indicated that there was no impairment of goodwill. Should the Company's estimate of the fair value of any of its reporting units decline significantly in future periods due to changes in customer demand, market activity levels, interest rates or other factors which would impact future earnings and cash flow or market valuation levels of the Company or any of its reporting units, an impairment of goodwill could be required.

Goodwill at June 30, 2013 was $2.7 billion, nearly 32% of which was allocated to the Company's PCS segment, which includes the majority of the NATCO operations acquired in 2009. The Company's determination of the fair value of its Custom Process Systems (CPS) business within the PCS segment included assumptions for continued long-term improvements to recent results. This business has in the past and continues to experience certain production inefficiencies. While profitability began to improve in late 2012, the Company expects further improvements over time. If the financial performance of the CPS business does not continue to improve, a future evaluation could indicate that an impairment of goodwill might be necessary. Goodwill associated with the CPS business was approximately $572.2 million at June 30, 2013 ($573.0 million at December 31, 2012).

In addition, the formation of OneSubsea™ added $754.0 million of goodwill to the Company's subsea reporting unit for a total reporting unit goodwill balance of $819.4 million at June 30, 2013. Should a future evaluation of the profitability and cash flows of this business fall significantly below current expectations, a future impairment of goodwill may also be necessary for this reporting unit.

Consolidated Results

Net income for the second quarter of 2013 totaled $140.4 million, or $0.57 per diluted share, compared to net income for the second quarter of 2012 of $174.6 million, or $0.70 per diluted share. Included in the second quarter 2013 results were charges of $0.22 per diluted share, primarily associated with:

• formation costs for OneSubsea, which became effective as a separate venture on June 30, 2013 and is described further in Note 2 of the Notes to Consolidated Condensed Financial Statements,

• currency devaluation, severance, restructuring and various other costs,

• foreign currency exchange losses, and

• additional income tax expense related to the formation of OneSubsea.


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The second quarter 2012 results included pre-tax charges of $9.9 million, or $0.04 per share, primarily related to pension settlement and integration costs.

Absent these costs in both periods, diluted earnings per share increased nearly 7% as compared to the second quarter of 2012.

Total revenues for the Company increased $233.7 million, or 11.4%. Almost one-fifth of the increase was due to impact of newly acquired businesses with the remaining increase mainly reflecting higher activity levels in each major product line within the DPS segment.

As a percent of revenues, cost of sales (exclusive of depreciation and amortization) increased from 70.6% during the second quarter of 2012 to 71.0% for the second quarter of 2013, mainly as a result of higher foreign currency exchange losses which increased the ratio by approximately 0.4 percentage points.

Selling and administrative expenses increased $39.3 million, or 13.7%, during the three months ended June 30, 2013 as compared to the three months ended June 30, 2012.

• Selling and administrative expenses were 14.2% of revenues for the second quarter of 2013 as compared to 13.9% for the second quarter of 2012.

• Over 84% of the dollar increase was due to (i) higher employee-related costs largely as a result of increased headcount and travel and (ii) higher facility-related costs, mainly for rent, insurance and maintenance of data processing and communications equipment and systems.

Depreciation and amortization expense totaled $70.1 million for the second quarter of 2013 as compared to $63.6 million during the second quarter of 2012, an increase of $6.5 million. The increase was due mainly to higher depreciation expense as a result of recent increased levels of capital spending and the impact of newly acquired businesses.

Net interest increased $3.3 million, from $22.0 million during the second quarter of 2012 to $25.3 million during the second quarter of 2013, mainly as a result of nearly $1.8 million of additional interest during the full current year quarter on new senior notes issued by the Company in May 2012, as well as a decline in interest earned on the Company's invested cash balances due primarily to lower current-period interest rates.

Other costs totaled $35.6 million for the three months ended June 30, 2013 as compared to $9.9 million for the three months ended June 30, 2012, an increase of $25.7 million. See Note 3 of the Notes to Consolidated Condensed Financial Statements for further information on the nature of these items.

The effective income tax rate for the second quarter of 2013 was 31.8% as compared to 21.7% for the second quarter of 2012. The increase in the tax rate was mainly due to recognition of various foreign taxes and an increase in certain foreign valuation allowances, largely arising as a result of the formation of OneSubsea.


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Segment Results

DPS Segment -
                                             Three Months Ended
                                                  June 30,                 Increase (Decrease)
($ in millions)                              2013          2012             $                %

Revenues                                   $ 1,438.4     $ 1,155.8     $      282.6           24.5 %
Income before income taxes                 $   195.6     $   176.1     $       19.5           11.1 %
Income before income taxes as a percent
of revenues                                     13.6 %        15.2 %            N/A           (1.6 )%

Orders                                     $ 1,502.7     $ 1,617.2     $     (114.5 )         (7.1 )%
Backlog (at period-end)                    $ 8,470.4     $ 5,155.3     $    3,315.1           64.3 %

Revenues

Newly acquired businesses accounted for approximately 20% of the total change in revenues from the second quarter of 2012. Absent this effect, sales were up 20% in each major product line.

• higher manufacturing activity levels associated with new deepwater rig construction projects and awards received in earlier periods for spare drilling stacks resulted in higher drilling equipment revenues,

• increased activity levels in unconventional resource regions of North America, as well as increased international customer demand in the Caspian Sea, the North Sea, the Middle East and in the Asia Pacific region contributed to higher revenues in the surface equipment product line, and

• higher project activity levels in the Asia Pacific region along with higher customer demand for aftermarket parts and services resulted in increased revenues for subsea equipment.

Income before income taxes as a percent of revenues

The decrease in the ratio of income before income taxes as a percent of revenues was due primarily to a 2.2 percentage-point increase in the ratio of cost of sales to revenues as a result of:

• higher foreign currency exchange losses which accounted for approximately a 1.3 percentage-point increase in the ratio, and

• lower margins on major drilling projects and higher costs associated with surface equipment rental activities in North America.

This increase in the ratio was partially offset by the favorable impact of selling and administrative expenses and depreciation and amortization expense which increased at a slower rate than the growth in revenues for the quarter.

Orders

Excluding the impact of newly acquired businesses, total segment orders were down nearly 19% in the second quarter of 2013 as compared to the same period last year. This decline was primarily attributable to:

• a 51% decrease in subsea orders as a result of the lack of major projects awarded in the second quarter of 2013 for new subsea trees, and

• a 21% decrease in orders for drilling equipment due primarily to various large awards received in the second quarter of 2012 for new drilling stacks that did not repeat at the same levels in the second quarter of 2013.


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Partially offsetting these decreases was a 27% increase in orders for surface equipment reflecting higher demand in North America for new and aftermarket rental equipment for use in unconventional resource regions and higher international activity levels, primarily in the North Sea and West Africa.

Backlog (at period-end)

Higher drilling and subsea equipment backlog, primarily resulting from strong
demand within the last twelve months and backlog added from the businesses
contributed by Schlumberger in connection with the formation of OneSubsea,
accounted for approximately 88% of the total increase in DPS segment backlog
from June 30, 2012 to June 30, 2013.

V&M Segment -

                                             Three Months Ended
                                                  June 30,                 Increase (Decrease)
($ in millions)                              2013          2012             $                %

Revenues                                   $   534.3     $   558.3     $     (24.0 )          (4.3 )%
Income before income taxes                 $   108.7     $   111.1     $      (2.4 )          (2.2 )%
Income before income taxes as a percent
of revenues                                     20.3 %        19.9 %           N/A             0.4 %

Orders                                     $   523.8     $   549.8     $     (26.0 )          (4.7 )%
Backlog (at period-end)                    $ 1,063.0     $ 1,144.0     $     (81.0 )          (7.1 )%

Revenues

The slight decrease in segment sales was primarily attributable to a decrease in engineered valves due to the absence of large project shipments when compared to the same period in 2012. This decrease was partially offset by modest volume increases in process and aftermarket sales.

Income before income taxes as a percent of revenues

The increase in the ratio of income before income taxes as a percent of revenues was attributable to:

• a 2.0 percentage-point decrease in the ratio of cost of sales to revenues resulting from a favorable mix change related to project shipments, partially offset by:

• a 1.5 percentage-point increase in the ratio of selling and administrative costs to revenue due to higher employee-related costs.

Orders

Overall, total segment orders were slightly lower when compared to the same period last year. Most of the change was attributable to a 17% and 19% decrease in engineered and process valve orders, respectively, relating to lower project volumes primarily in North America, partially offset by a 21% increase in distributed valve orders on the strength of higher U.S. activity levels.

Backlog (at period-end)

Backlog levels for the V&M segment decreased 7% from June 30, 2012 with
distributed valves accounting for over two-thirds of the decrease as a result of
a decline in Canadian activity levels.

                                       24
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  Table of Contents
PCS Segment -

                                              Three Months Ended
                                                   June 30,                Increase (Decrease)
($ in millions)                               2013          2012             $               %

Revenues                                   $    314.7     $   339.6     $     (24.9 )         (7.3 )%
Income before income taxes                 $     23.2     $    26.9     $      (3.7 )        (13.8 )%
Income before income taxes as a percent
of revenues                                       7.4 %         7.9 %           N/A           (0.5 )%

Orders                                     $    304.4     $   407.0     $    (102.6 )        (25.2 )%
Backlog (at period-end)                    $    963.7     $ 1,154.3     $    (190.6 )        (16.5 )%

Revenues

The decrease in revenues was due primarily to:

• a 17% decrease in sales of centrifugal compression equipment, mainly reflecting lower levels of international shipments of new plant air equipment and engineered units designed for gas processing and air separation applications, and

• an 8% decrease in process systems revenues mainly resulting from lower North American demand for wellhead and midstream processing equipment.

These decreases were partially offset by a 7% increase in sales of reciprocating compression equipment during the second quarter of 2013 due to increased shipments of new Ajax and Superior compressors and higher demand for aftermarket parts and services for upgrade projects.

Income before income taxes as a percent of revenues

The decrease in the ratio of income before income taxes as a percent of revenues was due primarily to the impact of increasing selling and marketing expenses, mainly in the Custom Processing Systems product line, in relation to a 7.3% decrease in segment revenues during the current year quarter (approximately a 2.1 percentage-point decrease in the ratio).

This decrease in the ratio of income before income taxes as a percent of revenues was partially offset by improved margins in the centrifugal and reciprocating compression equipment product lines, which increased the ratio by nearly 1.5 percentage points.

Orders

Over three-fourths of the decrease in orders was due to a 36% decline in awards for process systems as a result of weak North American demand for wellhead and midstream processing equipment and a lower level of awards for new custom process systems caused mainly by project delays and the absence of certain large awards received in the second quarter of 2012 that did not repeat during the second quarter of 2013.

In addition, centrifugal compression equipment orders declined 27% during the second quarter of 2013 primarily due to weaker North and South American demand for gas processing and engineered air equipment as compared to the more robust level of awards received in the second quarter of 2012.

Backlog (at period-end)

Backlog at June 30, 2013 declined from the same period last year in all major product lines, except for new plant air equipment, as a result of weaker order rates in recent periods which have not kept up with shipment and manufacturing activity levels.


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Corporate Segment -

The $30.6 million increase in the loss before income taxes in the Corporate segment during the second quarter of 2013 as compared to the second quarter of 2012 (see Note 10 of the Notes to Consolidated Condensed Financial Statements) was due primarily to $28.4 million of costs incurred in connection with the formation of OneSubsea, which became effective as a separate venture on June 30, 2013, and is described further in Note 2 of the Notes to Consolidated Condensed Financial Statements.

SIX MONTHS ENDED JUNE 30, 2013 COMPARED TO SIX MONTHS ENDED JUNE 30, 2012

Market Conditions

Information related to drilling activity and certain commodity spot and futures
prices during each quarter and the number of deepwater floaters and semis under
contract at the end of each period follows:

                                               Six Months Ended
                                                   June 30,                Increase (Decrease)
                                              2013          2012          Amount             %
Drilling activity (average number of
working rigs during period)(1):
United States                                   1,760         1,981           (221 )         (11.2 )%
Canada                                            346           382            (36 )          (9.4 )%
Rest of world                                   1,290         1,209             81             6.7 %
Global average rig count                        3,396         3,572           (176 )          (4.9 )%

Commodity prices (average of daily U.S.
dollar prices per unit during
period)(2):
West Texas Intermediate Cushing, OK
crude spot price per barrel in U.S.
dollars                                    $    94.22     $   98.11     $    (3.89 )          (4.0 )%
Henry Hub natural gas spot price per
MMBtu in U.S. dollars                      $     3.76     $    2.36     $     1.40            59.3 %

(1) Based on average monthly rig count data from Baker Hughes

(2) Source: Bloomberg

The decrease in average worldwide operating rigs during the first six months of 2013 as compared to the first six months of 2012 was driven by lower North American natural gas focused drilling activity. Despite the improvement in natural gas pricing, the challenging economics associated with horizontal shale development drilling at current prices continues to constrain the overall rig market. The average number of rigs drilling for gas was down nearly 41% in the United States and almost 12% in Canada in the first half of 2013 as compared to the first half of 2012. This impact was partially offset by a slight increase in the average number of North American rigs drilling for oil.

Crude oil prices (West Texas Intermediate, Cushing, OK) were fairly consistent throughout much of the first half of 2013 reaching a high of $98.44 per barrel in mid-June before closing the period at $96.56 per barrel. On average, crude oil prices were slightly lower during the first half of 2013 as compared to the first half of 2012.

Natural gas (Henry Hub) prices continued to trend upward during the six months ended June 30, 2013 reaching their highest levels since September 2011, at the end of May before closing the period at $3.57 per MMBtu. On average, prices during the first half of 2013 were up 59% as compared to the same period in 2012.


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Consolidated Results

Net income for the six months ended June 30, 2013 totaled $288.8 million, or $1.16 per diluted share, compared to net income for the six months ended June 30, 2012 of $308.6 million, or $1.25 per diluted share. Included in the results for the first half of 2013 were charges of $0.31 per diluted share, primarily associated with:

• formation costs for OneSubsea, which became effective as a separate venture on June 30, 2013 and is described further in Note 2 of the Notes to Consolidated Condensed Financial Statements,

• currency devaluation, severance, restructuring and other costs, and

• additional income tax expense related to the formation of OneSubsea.

The results for the first six months of 2012 included pre-tax charges of $8.4 million, or $0.02 per share, primarily related to pension settlement and . . .

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