Baker Hughes Announces Second Quarter Results

- Revenue of $4 billion for the quarter, down 33% year-over-year
- GAAP net loss per diluted share of $0.43 for the quarter, includes adjusting items of $0.29 per diluted share
- Free cash flow for the quarter of $413 million, increased $341 million year-over-year

HOUSTON, July 21, 2015 /PRNewswire/ -- Baker Hughes Incorporated (NYSE: BHI) announced today results for the second quarter of 2015.

Martin Craighead, Baker Hughes Chairman and Chief Executive Officer, commented, "Revenue of $4 billion for the second quarter declined 33% year-over-year, outperforming the 36% drop in the global rig count, despite incremental headwinds from deteriorating pricing and unfavorable currency changes. Even though the severity of the revenue decline has compressed our margins, we have minimized the impact by aggressively reducing costs and rightsizing our operational footprint. These actions have resulted in decremental margins of 35% compared to the prior year, a significant improvement from the prior industry downturn. Furthermore, earnings for the quarter were impacted by an unfavorable tax rate which resulted primarily from a change in the geographic mix of earnings.

"Our focus on revenue growth in markets we expect to be more resilient in this lower commodity environment has led to significant drilling and production chemical wins in Norway, Saudi Arabia, West Africa, and the Gulf of Mexico. With our efforts on cost reductions and targeted growth, we are well positioned to manage through these difficult conditions while generating positive cash flow, reducing working capital, and improving profitability.

"Looking ahead to the second half of 2015, we expect these unfavorable market dynamics to persist. In North America, we don't anticipate activity to increase while commodity prices remain depressed as the seasonal activity rebound in Canada will likely be offset by a decline in the U.S. Internationally, rig counts are projected to continue to decline led by many onshore and shallow water markets.

"While near-term market conditions remain challenging, the world's need for energy will continue to rise and the ability to meet demand will require more complex solutions and advanced technology from oilfield service companies. As such, our strategy of delivering innovative technologies that enable our customers to lower the cost of well construction, optimize well production, and increase ultimate recovery will continue to be an essential differentiator.

"Finally, in regard to the pending merger, I continue to be pleased with the efforts of the teams working on completing regulatory filings and to develop plans for a successful integration."

2015 Second Quarter Results

Revenue for the current quarter was $4 billion, down 33% compared to the second quarter of 2014.

On a GAAP basis, net loss attributable to Baker Hughes for the second quarter was $188 million or $0.43 per diluted share.

The effective tax rate on net loss for the current quarter was 3.7%, compared to 37.2% on net income for the second quarter of 2014. The decrease is driven by an unfavorable change in the geographic mix of earnings and the loss of certain tax benefits.

Adjusted EBITDA (a non-GAAP measure) for the second quarter of 2015 was $459 million, a decrease of $700 million or 60% compared to the second quarter of 2014.

Adjusted net loss (a non-GAAP measure) for the second quarter of 2015 was $62 million or $0.14 per diluted share. Adjusted net loss for the second quarter excludes $169 million before-tax or $126 million after-tax ($0.29 per diluted share) in adjustments. The adjustments include restructuring charges of $76 million before-tax or $59 million after-tax ($0.13 per diluted share); $83 million before-tax or $60 million after-tax ($0.14 per diluted share) for merger and other related costs; $23 million before-tax or $16 million after-tax ($0.04 per diluted share) for inventory adjustments; and ($13) million before-tax or ($9) million after-tax (($0.02) per diluted share) adjustment relating to a litigation settlement.

Free cash flow for the current quarter was $413 million compared to $72 million for the second quarter of 2014. Free cash flow excluding restructuring payments of $195 million would have been $608 million for the quarter.

For the quarter, capital expenditures were $258 million, compared to $424 million in the second quarter of 2014. Depreciation and amortization expense for the second quarter of 2015 was $434 million, compared to $454 million in the prior year quarter.

Excluding merger-related costs of $40 million in the current quarter, corporate costs were $42 million, compared to $73 million in the second quarter of 2014. The reduction in corporate costs is a result of workforce reductions and lower discretionary spend.

North America

North America revenue for the second quarter was $1.5 billion, a decrease of 47% compared to the second quarter of 2014. The drop in revenue is primarily attributable to the reduction in customer spending, which has resulted in a steep decline in onshore and shallow water activity, and an unfavorable pricing environment. The average U.S. and Canadian rig counts were down 51% for the same comparison period. In the Gulf of Mexico, deepwater operations included a favorable mix of completion activity.

North America adjusted operating profit margin (a non-GAAP measure) was (8.5%) for the second quarter, compared to 12% for the same quarter last year. Margins were negatively impacted by the sharp reduction in activity and an increasingly unfavorable pricing environment. Nevertheless, as a result of actions taken to right size the operational footprint and ongoing cost management efforts, decremental margins at 35% were substantially better than in the most recent downturn.

Latin America

Second quarter revenue for Latin America was $439 million, a decrease of $105 million, or 19%, compared to the second quarter of 2014. Revenue declined largely as result of sharp activity reductions in the Andean area, as reflected in a 43% drop in the rig count, and in Venezuela from decreased operations and unfavorable exchange rates.  In Brazil and Mexico, activity reductions were more than offset by offshore share gains.

Adjusted operating profit margin for Latin America in the second quarter was 10.3%, compared to 10.7% for the second quarter of 2014. The impact on margins as result of lower revenue was almost entirely offset by improvements made to the operating cost structure, minimizing year-over-year decremental margins to 12%.

Europe/Africa/Russia Caspian

Revenue was $869 million in Europe/Africa/Russia Caspian, representing a 22% decline compared to the second quarter of 2014. Revenue for the quarter was impacted by approximately $100 million related to the unfavorable change in foreign exchange rates. Activity reductions, unfavorable pricing, and the deconsolidation of a joint venture in North Africa late last year also contributed to the decline. These reductions were slightly offset by share gains in pockets of Africa and Europe.

Adjusted operating profit margins were 6.6% for the second quarter of 2015, compared to 16.5% for the second quarter of 2014. Profitability for the quarter was impacted by approximately $54 million associated with the unfavorable change in foreign exchange rates. Lower activity levels, pricing deterioration, and unfavorable product mix also impacted margins. Workforce reductions and other cost savings were partially offsetting these unfavorable market conditions.

Middle East/Asia Pacific

In the second quarter, revenue was $856 million in Middle East/Asia Pacific, a 22% reduction compared to the second quarter of 2014. The decline in revenue was driven primarily by lower activity throughout Asia Pacific, as reflected in the 12% drop in the rig count, and in Iraq as result of a reduction to our integrated operations, including exiting a large turnkey contract in mid-2014. Revenue was also impacted by unfavorable pricing in certain markets across the region.

Adjusted operating profit margin for the segment was 7%, compared to 14.8% for the second quarter of 2014. The reduction in margins was attributed mainly to lower activity levels and pricing reductions. The current quarter also includes mobilization costs for additional activity in the Middle East. The reduction in margins was slightly offset by improved profitability in Iraq and the benefit of the recent cost-cutting actions.

Industrial Services

Revenue for Industrial Services was $306 million in the second quarter, an 8% decrease compared to the second quarter of 2014. The decrease in revenue was attributed to reduced customer spending across all the industrial businesses, primarily process and pipeline services. Revenue was further impacted by the unfavorable change in foreign exchange rates. These reductions were partially offset by the acquisition of a new specialty pipeline services business in the third quarter of 2014.

Adjusted operating profit margins were 10.5%, compared to 10.2% for the second quarter of 2014. The reduction in profitability associated with lower activity levels was almost entirely offset by savings from recent cost reduction measures.

Outlook

For the remainder of the year, we expect unfavorable market conditions to continue across all segments. North America rig counts are anticipated to remain relatively unchanged. Seasonal increase in activity in Canada is expected to be fully offset by lower activity levels in the U.S. onshore and an unfavorable mix of activity in the Gulf of Mexico. In Latin America, we project the rig count to continue to decline, albeit, at a slower pace. In Europe/Africa/Russia Caspian, the rig count is also expected to decline across most of the region, primarily in onshore and shallow water markets. For Middle East/Asia Pacific, we anticipate the rig count to remain relatively stable as any rig count growth in the Middle East will likely to be offset by rig count declines in Asia Pacific.

Please see Table 1 for a reconciliation of GAAP to non-GAAP financial measures. A reconciliation of net (loss) income attributable to Baker Hughes to Adjusted EBITDA is provided in Table 2. Supplemental segment financial information for revenue, adjusted operating profit (loss) before tax (a non-GAAP measure), and adjusted operating profit before tax margin is provided in Tables 5a and 5b. Decremental margin (a non-GAAP measure) is the decrease of adjusted operating profit (loss) before interest expense and income taxes between two periods, divided by the increase or decrease in revenue between the same two periods (see Tables 5a and 5b). Free cash flow is defined as net cash flows provided by operating activities less disbursements for capital expenditures plus proceeds from disposal of assets.

 

Consolidated Condensed Statements of Income (Loss)




Three Months Ended


June 30,


March 31,

(In millions, except per share amounts)

2015


2014


2015

Revenue

$

3,968



$

5,935



$

4,594


Costs and expenses:






Cost of revenue

3,615



4,745



4,342


Research and engineering

124



159



138


Marketing, general and administrative1

310



338



315


Restructuring charges

76





573


Litigation settlements

(13)



62




Total costs and expenses

4,112



5,304



5,368


Operating (loss) income

(144)



631



(774)


Interest expense, net

(53)



(59)



(54)


(Loss) income before income taxes

(197)



572



(828)


Income taxes

7



(213)



235


Net (loss) income

(190)



359



(593)


Net loss (income) attributable to noncontrolling interests

2



(6)



4


Net (loss) income attributable to Baker Hughes

$

(188)



$

353



$

(589)








Basic (loss) earnings per share attributable to Baker Hughes

$

(0.43)



$

0.81



$

(1.35)


Diluted (loss) earnings per share attributable to Baker Hughes

$

(0.43)



$

0.80



$

(1.35)








Weighted average shares outstanding, basic

438



437



437


Weighted average shares outstanding, diluted

438



440



437








Depreciation and amortization expense

$

434



$

454



$

460


Capital expenditures

$

258



$

424



$

315





1


Marketing, general and administrative expenses include merger related costs of $46 million and $28 million in the three months ended June 30, 2015 and March 31, 2015, respectively.

 

Consolidated Condensed Statements of Income (Loss)



Six Months Ended June 30,

(In millions, except per share amounts)

2015


2014

Revenue

$

8,562



$

11,666


Costs and expenses:




Cost of revenue

7,957



9,465


Research and engineering

262



302


Marketing, general and administrative1

625



654


Restructuring charges

649




Litigation settlements

(13)



62


Total costs and expenses

9,480



10,483


Operating (loss) income

(918)



1,183


Interest expense, net

(107)



(116)


(Loss) income before income taxes

(1,025)



1,067


Income taxes

242



(372)


Net (loss) income

(783)



695


Net loss (income) attributable to noncontrolling interests

6



(14)


Net (loss) income attributable to Baker Hughes

$

(777)



$

681






Basic (loss) earnings per share attributable to Baker Hughes

$

(1.77)



$

1.56


Diluted (loss) earnings per share attributable to Baker Hughes

$

(1.77)



$

1.55






Weighted average shares outstanding, basic

438



438


Weighted average shares outstanding, diluted

438



440






Depreciation and amortization expense

$

894



$

891


Capital expenditures

$

573



$

863





1


Marketing, general and administrative expenses include merger related costs of $74 million in the six months ended June 30, 2015.

 

Consolidated Condensed Balance Sheets



June 30,


December 31,

(In millions)

2015


2014

ASSETS




Current assets:




Cash and cash equivalents

$

1,973



$

1,740


Accounts receivable - less allowance for doubtful accounts (2015 - $322,  2014 - $224)

3,684



5,418


Inventories, net

3,535



4,074


Other current assets

746



813


Total current assets

9,938



12,045


Property, plant and equipment, net

8,366



9,063


Goodwill

6,081



6,081


Intangible assets, net

759



812


Other assets

874



826


Total assets

$

26,018



$

28,827


LIABILITIES AND EQUITY




Current liabilities:




Accounts payable

$

1,785



$

2,807


Short-term debt and current portion of long-term debt

139



220


Accrued employee compensation

634



782


Other accrued liabilities

556



828


Total current liabilities

3,114



4,637


Long-term debt

3,904



3,913


Deferred income taxes and other tax liabilities

410



740


Long-term liabilities

793



807


Equity

17,797



18,730


Total liabilities and equity

$

26,018



$

28,827


 

Consolidated Condensed Statements of Cash Flows



Six Months Ended June 30,

(In millions)

2015


2014

Cash flows from operating activities:




Net (loss) income

$

(783)



$

695


Adjustments to reconcile net (loss) income to net cash flows from operating activities:




Depreciation and amortization

894



891


Other, primarily working capital

726



(890)


Net cash flows provided by operating activities

837



696


Cash flows from investing activities:




Expenditures for capital assets

(573)



(863)


Proceeds from disposal of assets

171



203


Other

(11)



(26)


Net cash flows used in investing activities

(413)



(686)


Cash flows from financing activities:




Net proceeds from issuance of debt

(64)



178


Repurchase of common stock



(400)


Dividends

(148)



(131)


Other

25



108


Net cash flows used in financing activities

(187)



(245)


Effect of foreign exchange rate changes on cash and cash equivalents

(4)



(1)


Increase (decrease) in cash and cash equivalents

233



(236)


Cash and cash equivalents, beginning of period

1,740



1,399


Cash and cash equivalents, end of period

$

1,973



$

1,163


 

Table 1:  Reconciliation of GAAP and Non-GAAP Financial Measures

The following table reconciles net (loss) income attributable to Baker Hughes, which is the directly comparable financial result determined in accordance with Generally Accepted Accounting Principles (GAAP), to adjusted net (loss) income1 (a non-GAAP financial measure).  Adjusted net (loss) income excludes identified items with respect to 2014 and 2015 as disclosed below:


Three Months Ended


June 30,


March 31,


2015


2014


2015

(In millions, except per share amounts)

Net
(Loss)

Income


Diluted
(Loss)
Earnings
Per Share


Net
(Loss)
Income


Diluted
(Loss)
Earnings
Per Share


Net
(Loss)
Income


Diluted
(Loss)

Earnings
Per Share

Net (loss) income attributable to Baker Hughes (GAAP)

$

(188)



$

(0.43)



$

353



$

0.80



$

(589)



$

(1.35)


Identified item:












       Restructuring charges2

59



0.13







415



0.95


       Inventory adjustments3

16



0.04







122



0.28


       Merger and related costs4

60



0.14







20



0.05


       Litigation settlements5

(9)



(0.02)



39



0.09






       Venezuela currency devaluation6





12



0.03






Adjusted net (loss) income (non-GAAP)1

$

(62)



$

(0.14)



$

404



$

0.92



$

(32)



$

(0.07)





1


Adjusted net (loss) income is a non-GAAP measure comprised of net (loss) income attributable to Baker Hughes excluding the impact of certain identified items.  The Company believes that adjusted net (loss) income is useful to investors because it is a consistent measure of the underlying results of the Company's business.  Furthermore, management uses adjusted net (loss) income as a measure of the performance of the Company's operations.

2


Restructuring charges of $76 million before tax ($59 million after-tax) and $573 million before-tax ($415 million after-tax) associated with workforce reductions, facility closures, asset impairments and contract terminations were recorded during the second and first quarters of 2015, respectively.

3


Inventory adjustments of $23 million before-tax ($16 million after-tax) were recorded in the second quarter of 2015 to adjust the carrying value of certain U.S. inventory.  Inventory adjustments of $171 million before-tax ($122 million after-tax) were recorded in the first quarter of 2015 to adjust the carrying value of certain inventory of which $159 million is in the U.S. and $12 million is in Latin America.

4


Merger and related costs of $83 million before-tax ($60 million after-tax) were recorded during the second quarter of 2015, including costs under our retention program and obligations for minimum incentive compensation which, based on meeting eligibility criteria in April, have been treated as merger related expenses. Merger and related costs for the second quarter of 2015 of which $40 million were recorded in Corporate and $43 million in total Operations. Merger and related costs of $28 million before-tax ($20 million after-tax) were recorded in Corporate during the first quarter of 2015.

5


Costs related to litigation settlements for labor claims of $62 million before-tax ($39 million after-tax) were recorded during the second quarter of 2014.  The amount of claims made under the settlement agreement was less than expected and accordingly, the accrual was reduced by $13 million before tax ($9 million after-tax), which was recorded during the second quarter of 2015.

6


Foreign exchange loss of $12 million before and after-tax in Venezuela was recorded in the second quarter of 2014 as a result of changing from the official exchange rate of 6.3 Bolivars Fuertes per U.S. Dollar to the SICAD 2 rate of approximately 50 Bolivars Fuertes per U.S. Dollar.

 

Table 2:  Calculation of EBIT, EBITDA, and Adjusted EBITDA1


Three Months Ended


June 30,


March 31,

(In millions)

2015


2014


2015

Net (loss) income attributable to Baker Hughes

$

(188)



$

353



$

(589)


Net (loss) income attributable to noncontrolling interests

(2)



6



(4)


Income taxes

(7)



213



(235)


(Loss) income before income taxes

(197)



572



(828)


Interest expense, net

53



59



54


(Loss) earnings before interest and taxes (EBIT)

(144)



631



(774)


Depreciation and amortization expense

434



454



460


Earnings (loss) before interest, taxes, depreciation and amortization (EBITDA)

290



1,085



(314)


Adjustments to EBITDA:






Restructuring charges2

76





573


Inventory adjustments3

23





171


Merger and related costs4

83





28


Litigation settlements5

(13)



62




Venezuela currency devaluation6



12




Adjusted EBITDA

$

459



$

1,159



$

458


 


Six Months Ended June 30,

(In millions)

2015


2014

Net (loss) income attributable to Baker Hughes

$

(777)



$

681


Net (loss) income attributable to noncontrolling interests

(6)



14


Income taxes

(242)



372


(Loss) income before income taxes

(1,025)



1,067


Interest expense, net

107



116


(Loss) earnings before interest and taxes (EBIT)

(918)



1,183


Depreciation and amortization expense

894



891


(Loss) earnings before interest, taxes, depreciation and amortization (EBITDA)

(24)



2,074


Adjustments to EBITDA:




Restructuring charges2

649




Inventory adjustments3

194




Merger and related costs4

111




Litigation settlements5

(13)



62


Venezuela currency devaluation6



12


Severance charges7



29


Technology royalty agreement8



29


Adjusted EBITDA

$

917



$

2,206





1


EBIT, EBITDA, and Adjusted EBITDA (as defined in the calculations above) are non-GAAP measures.  Management is providing these measures because it believes that such measures are widely accepted financial indicators used by investors and analysts to analyze and compare companies on the basis of operating performance.

2


Restructuring charges of $76 million before tax ($59 million after-tax) and $573 million before-tax ($415 million after-tax) associated with workforce reductions, facility closures, asset impairments and contract terminations were recorded during the second and first quarters of 2015, respectively.

3


Inventory adjustments of $23 million before-tax ($16 million after-tax) were recorded in the second quarter of 2015 to adjust the carrying value of certain U.S. inventory.  Inventory adjustments of $171 million before-tax ($122 million after-tax) were recorded in the first quarter of 2015 to adjust the carrying value of certain inventory of which $159 million is in the U.S. and $12 million is in Latin America.

4


Merger and related costs of $83 million before-tax ($59 million after-tax) were recorded during the second quarter of 2015, including costs under our retention program and obligations for minimum incentive compensation which, based on meeting eligibility criteria in April, have been treated as merger related expenses. Merger and related costs for the second quarter of 2015 of which $40 million were recorded in Corporate and $43 million in total Operations. Merger and related costs of $28 million before-tax ($20 million after-tax) were recorded in Corporate during the first quarter of 2015.

5


Costs related to litigation settlements for labor claims of $62 million before-tax ($39 million after-tax) were recorded during the second quarter of 2014. The amount of claims made under the settlement agreement was less than expected and accordingly, the accrual was reduced by $13 million before tax ($9 million after-tax), which was recorded during the second quarter of 2015.

6


Foreign exchange loss of $12 million before and after-tax in Venezuela was recorded in the second quarter of 2014 as a result of changing from the official exchange rate of 6.3 Bolivars Fuertes per U.S. Dollar to the SICAD 2 rate of approximately 50 Bolivars Fuertes per U.S. Dollar.

7


Severance charges of $29 million before-tax ($21 million after-tax) were incurred in North America during the first quarter of 2014.

8


Costs related to a technology royalty agreement of $29 million before-tax ($20 million after-tax) were incurred during the first quarter of 2014.

 

Table 3a:  Segment Revenue, Profit (Loss) Before Tax, and Profit Before Tax Margin1


Three Months Ended


June 30,


March 31,

(In millions)

2015


2014


2015

Segment Revenue






North America

$

1,498



$

2,843



$

2,006


Latin America

439



544



493


Europe/Africa/Russia Caspian

869



1,111



895


Middle East/Asia Pacific

856



1,104



916


Industrial Services

306



333



284


Total Operations

$

3,968



$

5,935



$

4,594


Profit (Loss) Before Tax






North America

$

(167)



$

340



$

(209)


Latin America

41



46



33


Europe/Africa/Russia Caspian

47



183



(20)


Middle East/Asia Pacific

51



163



62


Industrial Services

29



34



10


Total Operations

$

1



$

766



$

(124)


Corporate and Other Profit (Loss) Before Tax






Corporate

(82)



(73)



(77)


Interest expense, net

(53)



(59)



(54)


Restructuring charges

(76)





(573)


Litigation settlements

13



(62)




Corporate, net interest and other

(198)



(194)



(704)


Profit (Loss) Before Tax

$

(197)



$

572



$

(828)


Profit Before Tax Margin1






North America

(11%)



12%



(10%)


Latin America

9%



8%



7%


Europe/Africa/Russia Caspian

5%



16%



(2%)


Middle East/Asia Pacific

6%



15%



7%


Industrial Services

9%



10%



4%


Total Operations

—%



13%



(3%)





1


Profit before tax margin is a non-GAAP measure defined as profit (loss) before tax divided by revenue.  Management uses the profit before tax margin because it believes it is a widely accepted financial indicator used by investors and analysts to analyze and compare companies on the basis of operating performance.

 

Table 3b:  Segment Revenue, Profit (Loss) Before Tax, and Profit Before Tax Margin1


Six Months Ended June 30,

(In millions)

2015


2014

Segment Revenue




North America

$

3,504



$

5,619


Latin America

932



1,074


Europe/Africa/Russia Caspian

1,764



2,155


Middle East/Asia Pacific

1,772



2,164


Industrial Services

590



654


Total Operations

$

8,562



$

11,666


Profit (Loss) Before Tax




North America

$

(376)



$

598


Latin America

74



101


Europe/Africa/Russia Caspian

27



330


Middle East/Asia Pacific

113



293


Industrial Services

39



61


Total Operations

$

(123)



$

1,383


Corporate and Other Profit (Loss) Before Tax




Corporate

(159)



(138)


Interest expense, net

(107)



(116)


Restructuring charges

(649)




Litigation settlements

13



(62)


Corporate, net interest and other

(902)



(316)


Profit (Loss) Before Tax

$

(1,025)



$

1,067


Profit Before Tax Margin1




North America

(11%)



11%


Latin America

8%



9%


Europe/Africa/Russia Caspian

2%



15%


Middle East/Asia Pacific

6%



14%


Industrial Services

7%



9%


Total Operations

(1%)



12%





1


Profit before tax margin is a non-GAAP measure defined as profit (loss) before tax divided by revenue.  Management uses the profit before tax margin because it believes it is a widely accepted financial indicator used by investors and analysts to analyze and compare companies on the basis of operating performance.

 

Table 4:  Adjustments to Profit (Loss) Before Tax


Three Months Ended


June 30,


March 31,

(In millions)

20151,2


20143


20151

Adjustments to Profit (Loss) Before Tax






North America

$

40



$



$

159


Latin America

4



12



12


Europe/Africa/Russia Caspian

10






Middle East/Asia Pacific

9






Industrial Services

3






Total Operations

$

66



$

12



$

171


Corporate

40





28


Total

$

106



$

12



$

199


 


Six Months Ended


June 30,

(In millions)

20151,2


20143,4

Adjustments to Profit (Loss) Before Tax




North America

$

199



$

42


Latin America

16



15


Europe/Africa/Russia Caspian

10



6


Middle East/Asia Pacific

9



6


Industrial Services

3



1


Total Operations

$

237



$

70


Corporate

68




Total

$

305



$

70





1


Inventory adjustments of $23 million before-tax were recorded in the second quarter of 2015 to adjust the carrying value of certain U.S. inventory.  Inventory adjustments of $171 million before-tax were recorded in the first quarter of 2015 to adjust the carrying value of certain inventory of which $159 million is in the U.S. and $12 million is in Latin America.

2


Merger and related costs of $83 million before-tax were recorded during the second quarter of 2015, including costs under our retention program and obligations for minimum incentive compensation which, based on meeting eligibility criteria in April, have been treated as merger related expenses. Merger and related costs for the second quarter of 2015 of which $40 million were recorded in Corporate and $43 million in Total Operations. Merger and related costs of $28 million before-tax were recorded in Corporate during the first quarter of 2015.

3


Foreign exchange loss of $12 million before-tax in Venezuela was recorded in the second quarter of 2014 as a result of changing from the official exchange rate of 6.3 Bolivars Fuertes per U.S. Dollar to the SICAD 2 rate of approximately 50 Bolivars Fuertes per U.S. Dollar.

4


Severance charges of $29 million before-tax in North America and costs related to a technology royalty agreement of $29 million before-tax were incurred during the first quarter of 2014. The costs associated with the technology royalty agreement pertain to our global operations and have therefore been allocated to all segments.

 

Table 5a:  Supplemental Segment Financial Information Excluding Certain Identified Items

The following table contains non-GAAP measures of adjusted operating profit (loss) before tax and adjusted operating profit before tax margin, which excludes identified items in Table 4:


Three Months Ended


June 30,


March 31,

(In millions)

2015


2014


2015

Segment Revenue






North America

$

1,498



$

2,843



$

2,006


Latin America

439



544



493


Europe/Africa/Russia Caspian

869



1,111



895


Middle East/Asia Pacific

856



1,104



916


Industrial Services

306



333



284


Total Operations

$

3,968



$

5,935



$

4,594


Adjusted Operating Profit (Loss) Before Tax1






North America

$

(127)



$

340



$

(50)


Latin America

45



58



45


Europe/Africa/Russia Caspian

57



183



(20)


Middle East/Asia Pacific

60



163



62


Industrial Services

32



34



10


Total Operations

$

67



$

778



$

47


Corporate

(42)



(73)



(49)


Total

$

25



$

705



$

(2)


Adjusted Operating Profit Before Tax Margin1






North America

(8%)



12%



(2%)


Latin America

10%



11%



9%


Europe/Africa/Russia Caspian

7%



16%



(2%)


Middle East/Asia Pacific

7%



15%



7%


Industrial Services

10%



10%



4%


Total Operations

2%



13%



1%





1


Adjusted operating profit (loss) before tax is a non-GAAP measure defined as profit (loss) before tax less interest expense and certain identified costs.  Adjusted operating profit before tax margin is a non-GAAP measure defined as adjusted operating profit (loss) before tax divided by revenue.  Management uses each of these measures because it believes they are widely accepted financial indicators used by investors and analysts to analyze and compare companies on the basis of operating performance and that these measures may be used by investors to make informed investment decisions.

 

Table 5b:  Supplemental Segment Financial Information Excluding Certain Identified Items

The following table contains non-GAAP measures of adjusted operating profit (loss) before tax and adjusted operating profit before tax margin, which excludes identified items in Table 4:


Six Months Ended June 30,

(In millions)

2015


2014

Segment Revenue




North America

$

3,504



$

5,619


Latin America

932



1,074


Europe/Africa/Russia Caspian

1,764



2,155


Middle East/Asia Pacific

1,772



2,164


Industrial Services

590



654


Total Operations

$

8,562



$

11,666


Adjusted Operating Profit (Loss) Before Tax1




North America

$

(177)



$

640


Latin America

90



116


Europe/Africa/Russia Caspian

37



336


Middle East/Asia Pacific

122



299


Industrial Services

42



62


Total Operations

$

114



$

1,453


Corporate

(91)



(138)


Total

$

23



$

1,315


Adjusted Operating Profit Before Tax Margin1




North America

(5%)



11%


Latin America

10%



11%


Europe/Africa/Russia Caspian

2%



16%


Middle East/Asia Pacific

7%



14%


Industrial Services

7%



9%


Total Operations

1%



12%





1


Adjusted operating profit (loss) before tax is a non-GAAP measure defined as profit (loss) before tax less interest expense and certain identified costs.  Adjusted operating profit before tax margin is a non-GAAP measure defined as adjusted operating profit (loss) before tax divided by revenue.  Management uses each of these measures because it believes they are widely accepted financial indicators used by investors and analysts to analyze and compare companies on the basis of operating performance and that these measures may be used by investors to make informed investment decisions.

 

Innovations to Earnings

The following section provides operational and technical highlights outlining the successes aligned to our strategy.

Efficient Well Construction

Baker Hughes receives drilling and pressure pumping cementing services contracts for a major operator in the Middle East. The drilling services will be provided on 12 rigs and pressure pumping cementing services on 10 rigs. The Baker Hughes drilling services will include the FASTrak™ logging-while-drilling (LWD) fluid analysis sampling and testing service and the AutoTrak™ Curve rotary steerable systems. For cementing services, Baker Hughes technology will ensure borehole integrity for offshore and land oil and gas fields.

Baker Hughes achieves record for longest extended reach well in United Arab Emirates. The well was drilled to total measured depth of 28,235 ft (8606 m) and a 17,300-ft (5273-m) lateral length. The Baker Hughes drilling system technologies included the AutoTrak X-treme™ system combined with the OnTrak™ integrated measurement-while-drilling and LWD system, the LithoTrak™ service, and the StarTrak™ high-definition advanced LWD imaging system.

Baker Hughes achieves new drilling record in deepwater Nigeria. The Baker Hughes AutoTrak™ G3 rotary steerable system drilled to a total depth of 21,160 ft (6450 m) holding a maximum inclination of 73 degrees in single runs per hole section, which sets a new record for the longest well drilled by any company in Nigeria. The previous total depth was 19,000 ft (5791 m). This well also recorded the first GyroTrak™ gyro-while-drilling deployment in deepwater Nigeria. The TesTrak™ LWD formation-pressure testing service was also deployed taking 21 successful formation pressure tests to a depth of 20,734 ft (6320 m).

Baker Hughes completes records with the Kymera™ hybrid drill bit in Africa. Baker Hughes drilled the longest bit run for a major operator in Tunisia. The Kymera bit drilled 4,839 ft (1475 m) at a rate of penetration (ROP) of 12.36 m/h. Despite limited capabilities such as low flow gallons per minute that would significantly affect the bit performance, Baker Hughes totaled 1 million bit revolutions. Baker Hughes also completed a footage and ROP record on one of the most prominent fields in Algeria. The Kymera bit drilled through interbedded sandstone and clay with dolorite intrusions to 3,707 ft (1130 m) with an average ROP of 6.6 m/hr, replacing six bit runs compared to the offset wells and providing savings to the operator. The previous record was 4.2 m/hrs as an average for the six runs.

Baker Hughes receives drilling services contract for a major operator in the Gulf of Mexico through 2016. The contract includes the AutoTrak™ rotary steerable system and LWD services such as the SoundTrak™ acoustic LWD service, the LithoTrak™ service, the TesTrak™ LWD formation-pressure testing service, and the MagTrak™ advanced magnetic resonance service. Baker Hughes replaces a competitor for this contract. With the operator increasing activity in the Gulf of Mexico, the work provides opportunities for additional contracts with these product lines.

Baker Hughes successfully completes the first hybrid multistage completion system for a shale oil well in Argentina. Baker Hughes completed a 6,500-ft (1981-m) lateral horizontal well providing a hybrid solution that met the field challenges and customer's expectations. This completion design will allow the well to be stimulated by combining the FracPoint™ multistage completion system, and the IN-Tallic™ disintegrating frac balls and casing perforation.

Baker Hughes saves operator time and money with the GaugePro™ Echo digital on-command reamer in the deepwater Gulf of Mexico. The elimination of the rat hole was necessary to safely position the casing on the bottom of the wellbore. A GaugePro Echo reamer was incorporated into the bottomhole assembly. After drilling the section to total depth, the reamer was activated and successfully eliminated 172 ft (52 m) of rat hole. This removed the cleanout run saving the customer 26 hours of operating time. The GaugePro Echo is unique in that it can be activated multiple times in a single run, while providing confirmation that the reamer blades have opened, eliminating risk and uncertainty during reaming operations.

Optimizing Well Production

Baker Hughes receives significant contracts for production chemicals with major customers. One contract will provide chemical services for an operator in Nigeria. Baker Hughes was awarded a five-year, oilfield production chemicals and services contract for both onshore and offshore wells in this West Africa field. An extensive range of solutions will be provided from production optimization, integrity management, and flow assurance product lines. Baker Hughes replaces a competitor that had held the account for 20 years. Another contract includes production chemical treatment for a major operator's gas field in the Republic of Congo. A third contract, also in the Republic of Congo, is for oil and water separation programs at three major operator fields. Baker Hughes will be replacing two competitors.

Baker Hughes secures a contract for production chemicals and services for an operator in the UK. Baker Hughes will design and supply standard production chemicals and services under an eight-year contract, anticipated to start in July 2015.  The contract includes an extension option of four years.

Baker Hughes successfully deploys the FASTrak™ LWD fluid analysis and testing services for the first time in Latin America. The job was in a deviated presalt deepwater well in Santos Basin for a major operator in Brazil. A total of five pretests and one water sample were collected in a low permeability carbonate reservoir section. The sample pumping time was significantly lower compared to a typical wireline reservoir fluids sampling operation. The FASTrak services allowed the operator to obtain critical reservoir information early. It saved the operator 3 days of rig time by avoiding a drillpipe conveyed wireline fluids sampling run and reduced sampling time due to less drilling fluids invasion into the reservoir.

Baker Hughes completes the first rigless deepwater subsea stimulation vessel to vessel transfer for a six-well project in the Gulf of Mexico. The stimulation treatments were blended onboard the Baker Hughes StimFORCE™ Gulf of Mexico stimulation vessel and transferred to a multipurpose support vessel where the wells were treated using the Baker Hughes skid pumps. This successful rigless intervention eliminated the deepwater rig, which allowed the customer to save a significant amount in costs. The successful stimulation treatments increased production by 8,070 BOPD.

Increasing Ultimate Recovery

Baker Hughes continues to provide high-end technologies in Eastern Caspian. Baker Hughes conducted water shut off study for wells in Kazakhstan. The successful results were recognized by the customer and led to services for a multiple array production suite (MAPS) survey of horizontal well aiming to identify water inflow interval and cross flows to perform remedial work using Baker Hughes pressure pumping services. Also in Kazakhstan, Baker Hughes completed the first MAPS run in Chinaryovskoye field that saved the customer 2 days of drilling time. This successful operation is the first step in the production logging campaign aiming to introduce a complex production logging solution with MAPS and the Reservoir Performance Monitor™ platform to the market helping customers have full diagnostic information for their wells including inflow profiles, flow composition, hold ups, and cross flows.

Baker Hughes receives an artificial lift contract for CENtigrade™ ESP production system for the Christina Lake field in Northern Alberta, Canada. The CENtigrade 446°F (230°C) in-fill well system was commercially launched in March and is designed to allow steam-assisted gravity drainage (SAGD) operators to drill smaller, in-fill wells to improve reserves recovery from SAGD fields. The temperature rating of the system allows operators to increase production without sacrificing equipment reliability.

Supplemental Financial Information

Supplemental financial information can be found on the Company's website at: www.bakerhughes.com/investor in the Financial Information section under Quarterly Results.

Additional Information

As previously announced in Baker Hughes' Current Report on Form 8-K filed with the SEC on November 18, 2014, Baker Hughes and Halliburton Company ("Halliburton") have entered into an Agreement and Plan of Merger (the "Merger Agreement"), pursuant to which, subject to the satisfaction or waiver of certain conditions, Baker Hughes will be merged with and into a wholly owned subsidiary of Halliburton (the "Merger").  In connection with this proposed Merger, Halliburton filed with the SEC a registration statement on Form S-4, including Amendments No. 1 and 2 thereto, and a definitive joint proxy statement/prospectus of Baker Hughes and Halliburton and other documents related to the proposed transaction.  The registration statement was declared effective by the SEC on February 17, 2015 and the definitive proxy statement/prospectus was mailed to stockholders of Baker Hughes and Halliburton.

On March 27, 2015, Halliburton's stockholders approved the proposal to issue shares of Halliburton common stock as contemplated by the Merger Agreement.  In addition, Baker Hughes' stockholders adopted the Merger Agreement and thereby approved the proposed combination of the two companies.  The transaction is still subject to regulatory approvals and customary closing conditions, including the termination or expiration of the applicable waiting period under the U.S. Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act"). On July 10, 2015, Baker Hughes and Halliburton entered into a timing agreement with the Antitrust Division of the Department of Justice (the "DOJ") pursuant to which both companies agreed to extend the period of the DOJ's review of the Merger to the later of November 25, 2015 or 90 days after both companies have certified substantial compliance with the DOJ's prior request for additional information under the HSR Act (the "Second Request"). Baker Hughes certified substantial compliance with the Second Request on July 14, 2015, and Halliburton expects to certify substantial compliance with the Second Request by mid-summer of 2015. Baker Hughes and Halliburton are targeting closing the Merger late in 2015. However, the Merger Agreement provides that the closing can be extended into 2016, if necessary.  Baker Hughes cannot predict with certainty when, or if, the pending Merger will be completed because completion of the transaction is subject to conditions beyond the control of Baker Hughes.

Forward-Looking Statements

This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, (each a "forward-looking statement").  The words "anticipate," "believe," "ensure," "expect," "if," "intend," "estimate," "project," "foresee," "forecasts," "predict," "outlook," "aim," "will," "could," "should," "potential," "would," "may," "probable," "likely," and similar expressions, and the negative thereof, are intended to identify forward-looking statements.  There are many risks and uncertainties that could cause actual results to differ materially from our forward-looking statements.  These forward-looking statements are also affected by the risk factors described in the Company's Annual Report on Form 10-K for the year ended December 31, 2014; Baker Hughes' subsequent quarterly report on Form 10-Q for the quarterly period ended March 31, 2015; and those set forth from time-to-time in other filings with the Securities and Exchange Commission ("SEC").  The documents are available through the Company's website at:  www.bakerhughes.com/investor or through the SEC's Electronic Data Gathering and Analysis Retrieval ("EDGAR") system at:  www.sec.gov.  We undertake no obligation to publicly update or revise any forward-looking statement.

Our expectations regarding our business outlook and business plans; the business plans of our customers; oil and natural gas market conditions; cost and availability of resources; economic, legal and regulatory conditions and other matters are only our forecasts regarding these matters.

These forward looking statements, including forecasts, may be substantially different from actual results, which are affected by many risks including the impact of the pending Merger with Halliburton, along with the following risk factors and the timing of any of these risk factors:

Baker Hughes - Halliburton pending Merger - the ability to obtain regulatory approvals for the transaction; the impact of the pending transaction making it more difficult to obtain relationships with customers, employees or suppliers; the inability to retain key personnel; the suspension of our stock repurchase program pursuant to the terms of the Merger Agreement.

Restructuring activities - the ability to successfully implement and adjust the restructuring activities and achieve it's intended results.

Economic and political conditions – the impact of worldwide economic conditions; the effect that declines in credit availability may have on worldwide economic growth and demand for hydrocarbons; the ability of our customers to finance their exploration and development plans; foreign currency exchange fluctuations and changes in the capital markets in locations where we operate; and the impact of government disruptions.

Oil and gas market conditions – the level of petroleum industry exploration, development and production expenditures; the price of, volatility in pricing of, and the demand for crude oil and natural gas; drilling activity; drilling permits for and regulation of the shelf and the deepwater drilling; excess productive capacity; crude and product inventories; LNG supply and demand; seasonal and other adverse weather conditions that affect the demand for energy; severe weather conditions, such as tornadoes and hurricanes, that affect exploration and production activities; Organization of Petroleum Exporting Countries ("OPEC") policy and the adherence by OPEC nations to their OPEC production quotas.

Terrorism and geopolitical risks – war, military action, terrorist activities or extended periods of international conflict, particularly involving any petroleum-producing or consuming regions; labor disruptions, civil unrest or security conditions where we operate; expropriation of assets by governmental action; cybersecurity risks and cyber incidents or attacks; epidemic outbreaks.

Price, market share, contract terms, and customer payments – our ability to obtain market prices for our products and services; the ability of our competitors to capture market share; our ability to retain or increase our market share; changes in our strategic direction; the effect of industry capacity relative to demand for the markets in which we participate; our ability to negotiate acceptable terms and conditions with our customers, especially national oil companies, to successfully execute these contracts, and receive payment in accordance with the terms of our contracts with our customers; our ability to manage warranty claims and improve performance and quality; our ability to effectively manage our commercial agents.

Costs and availability of resources – our ability to manage the costs, availability, distribution and delivery of sufficient raw materials and components (especially steel alloys, chromium, copper, carbide, lead, nickel, titanium, beryllium, barite, synthetic and natural diamonds, sand, gel, chemicals, and electronic components); our ability to manage energy-related costs; our ability to manage compliance-related costs; our ability to recruit, train and retain the skilled and diverse workforce necessary to meet our business needs and manage the associated costs; the effect of manufacturing and subcontracting performance and capacity; the availability of essential electronic components used in our products; the effect of competition, particularly our ability to introduce new technology on a forecasted schedule and at forecasted costs; potential impairment of long-lived assets; unanticipated changes in the levels of our capital expenditures; the need to replace any unanticipated losses in capital assets; labor-related actions, including strikes, slowdowns and facility occupations; our ability to maintain information security.

Litigation and changes in laws or regulatory conditions – the potential for unexpected litigation or proceedings and our ability to obtain adequate insurance on commercially reasonable terms; the legislative, regulatory and business environment in the U.S. and other countries in which we operate; outcome of government and legal proceedings, as well as costs arising from compliance and ongoing or additional investigations in any of the countries where the Company does business; new laws, regulations and policies that could have a significant impact on the future operations and conduct of all businesses; laws, regulations or restrictions on hydraulic fracturing; any restrictions on new or ongoing offshore drilling or permit and operational delays or program reductions as a result of the regulations in the Gulf of Mexico and other areas of the world; changes in export control laws or exchange control laws; the discovery of new environmental remediation sites; changes in environmental regulations; the discharge of hazardous materials or hydrocarbons into the environment; restrictions on doing business in countries subject to sanctions; customs clearance procedures; changes in accounting standards; changes in tax laws or tax rates in the jurisdictions in which we operate; resolution of tax assessments or audits by various tax authorities; and the ability to fully utilize our tax loss carry forwards and tax credits.

Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas industry.  The Company's 49,000 employees today work in more than 80 countries helping customers find, evaluate, drill, produce, transport and process hydrocarbon resources.  For more information about Baker Hughes, visit:  www.bakerhughes.com.

Investor Contact:
Alondra Oteyza, +1.713.439.8822, alondra.oteyza@bakerhughes.com

Media Contact:
Melanie Kania, +1.713.439.8303, melanie.kania@bakerhughes.com

 

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SOURCE Baker Hughes Incorporated