BHI Baker Hughes Incorporated

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2017

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)

Baker Hughes Incorporated

Consolidated Condensed Statements of Income (Loss)

(Unaudited)

	Three Months Ended March 31,
(In millions, except per share amounts)	2017				2016
Revenue:
Sales	$	955			$	1,013
Services	1,307				1,657
Total revenue	2,262				2,670
Costs and expenses:
Cost of sales	775				944
Cost of services	1,113				1,714
Research and engineering	99				102
Marketing, general and administrative	184				207
Impairment and restructuring charges	90				160
Merger and related costs	31				102
Total costs and expenses	2,292				3,229
Operating loss	(30		)		(559		)
Interest expense, net	(35		)		(55		)
Loss before income tax and equity in loss of affiliate	(65		)		(614		)
Equity in loss of affiliate	(18		)		—
Income tax provision	(47		)		(367		)
Net loss	(130		)		(981		)
Net loss attributable to noncontrolling interests	1				—
Net loss attributable to Baker Hughes	$	(129	)		$	(981	)
Basic and diluted loss per share attributable to Baker Hughes	$	(0.30	)		$	(2.22	)
Cash dividends per share	$	0.17			$	0.17

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

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Baker Hughes Incorporated

Consolidated Condensed Statements of Comprehensive Income (Loss)

(Unaudited)

	Three Months Ended March 31,
(In millions)	2017				2016
Net loss	$	(130	)		$	(981	)
Other comprehensive income (loss):
Foreign currency translation adjustments	23				65
Pension and other postretirement benefits, net of tax	(1		)		2
Other comprehensive income (loss)	22				67
Comprehensive loss	(108		)		(914		)
Comprehensive loss attributable to noncontrolling interests	1				—
Comprehensive loss attributable to Baker Hughes	$	(107	)		$	(914	)

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

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Baker Hughes Incorporated

Consolidated Condensed Balance Sheets

(Unaudited)

(In millions)	March 31, 2017				December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	4,222			$	4,572
Accounts receivable - less allowance for doubtful accounts (2017 - $396; 2016 - $509)	2,162				2,251
Inventories, net	1,907				1,809
Other current assets	673				535
Total current assets	8,964				9,167
Property, plant and equipment - less accumulated depreciation (2017 - $6,574; 2016 - $6,567)	4,128				4,271
Goodwill	4,090				4,084
Intangible assets, net	294				318
Other assets	1,200				1,194
Total assets	$	18,676			$	19,034
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,088			$	1,027
Short-term debt and current portion of long-term debt	134				132
Accrued employee compensation	420				566
Income taxes payable	75				78
Other accrued liabilities	413				501
Total current liabilities	2,130				2,304
Long-term debt	2,884				2,886
Deferred income taxes and other tax liabilities	334				328
Liabilities for pensions and other postretirement benefits	626				626
Other liabilities	151				153
Commitments and contingencies
Equity:
Common stock, one dollar par value (shares authorized - 750; issued and outstanding: 2017 - 426; 2016 - 424)	427				425
Capital in excess of par value	6,735				6,708
Retained earnings	6,380				6,583
Accumulated other comprehensive loss	(1,011		)		(1,033		)
Treasury stock	(60		)		(27		)
Baker Hughes stockholders' equity	12,471				12,656
Noncontrolling interests	80				81
Total equity	12,551				12,737
Total liabilities and equity	$	18,676			$	19,034

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

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Baker Hughes Incorporated

Consolidated Condensed Statements of Changes in Equity

(Unaudited)

	Baker Hughes Stockholders' Equity
(In millions, except per share amounts)	Common Stock				Capital in Excess of Par Value				Retained Earnings				Accumulated Other Comprehensive Loss				Treasury Stock				Non-controlling Interests				Total Equity
Balance at December 31, 2016	$	425			$	6,708			$	6,583			$	(1,033	)		$	(27	)		$	81			$	12,737
Comprehensive loss:
Net loss									(129		)										(1		)		(130		)
Other comprehensive income													22												22
Activity related to stock plans	2				2												(33		)						(29		)
Stock-based compensation					29																				29
Cash dividends ($0.17 per share)									(74		)														(74		)
Net activity related to noncontrolling interests					(4		)																(4		)
Balance at March 31, 2017	$	427			$	6,735			$	6,380			$	(1,011	)		$	(60	)		$	80			$	12,551

	Baker Hughes Stockholders' Equity
(In millions, except per share amounts)	Common Stock				Capital in Excess of Par Value				Retained Earnings				Accumulated Other Comprehensive Loss				Treasury Stock				Non-controlling Interests				Total Equity
Balance at December 31, 2015	$	437			$	7,261			$	9,614			$	(1,005	)		$	(9	)		$	84			$	16,382
Comprehensive loss:
Net loss									(981		)														(981		)
Other comprehensive income													67												67
Activity related to stock plans	1				(14		)										(12		)						(25		)
Stock-based compensation					34																				34
Cash dividends ($0.17 per share)									(74		)														(74		)
Net activity related to noncontrolling interests																					(1		)		(1		)
Balance at March 31, 2016	$	438			$	7,281			$	8,559			$	(938	)		$	(21	)		$	83			$	15,402

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

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Baker Hughes Incorporated

Consolidated Condensed Statements of Cash Flows

(Unaudited)

	Three Months Ended March 31,
(In millions)	2017				2016
Cash flows from operating activities:
Net loss	$	(130	)		$	(981	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation and amortization	218				354
Impairment of assets	19				118
Provision for deferred income taxes	12				359
Provision for doubtful accounts	(94		)		48
Other noncash items	(5		)		(3		)
Changes in operating assets and liabilities:
Accounts receivable	107				386
Inventories	(92		)		149
Accounts payable	59				(263		)
Other operating items, net	(257		)		(266		)
Net cash flows used in operating activities	(163		)		(99		)
Cash flows from investing activities:
Expenditures for capital assets	(87		)		(86		)
Proceeds from disposal of assets	76				82
Proceeds from maturities of investment securities	3				202
Purchases of investment securities	(68		)		(137		)
Net cash flows provided by (used in) investing activities	(76		)		61
Cash flows from financing activities:
Net repayments of short-term debt and other borrowings	(6		)		(5		)
Dividends paid	(74		)		(74		)
Other financing items, net	(32		)		(16		)
Net cash flows used in financing activities	(112		)		(95		)
Effect of foreign exchange rate changes on cash and cash equivalents	1				1
Decrease in cash and cash equivalents	(350		)		(132		)
Cash and cash equivalents, beginning of period	4,572				2,324
Cash and cash equivalents, end of period	$	4,222			$	2,192
Supplemental cash flows disclosures:
Income taxes paid, net of refunds	$	67			$	85
Interest paid	$	56			$	70
Supplemental disclosure of noncash investing activities:
Capital expenditures included in accounts payable	$	29			$	32
Receipt of bonds for outstanding accounts receivable	$	84			$	—

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Baker Hughes Incorporated ("Baker Hughes," "Company," "we," "our," or "us,") is a leading supplier of oilfield services, products, technology and systems used for drilling, formation evaluation, completion and production, pressure pumping, and reservoir development in the worldwide oil and natural gas industry. We also provide products and services for other businesses including downstream chemicals, and process and pipeline services.

Basis of Presentation

Our unaudited consolidated condensed financial statements included herein have been prepared in accordance with generally accepted accounting principles ("GAAP") in the United States of America ("U.S.") and pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC") for interim financial information. Accordingly, certain information and disclosures normally included in our annual financial statements have been condensed or omitted. These unaudited consolidated condensed financial statements should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2016 . We believe the unaudited consolidated condensed financial statements included herein reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. In the Notes to Unaudited Consolidated Condensed Financial Statements, all dollar and share amounts in tabulations are in millions of dollars and shares, respectively, unless otherwise indicated.

New Accounting Standards Adopted

In November 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2015-17, Balance Sheet Classification of Deferred Taxes . The new standard requires all deferred tax assets and liabilities to be classified as noncurrent in a classified statement of financial position. We adopted this pronouncement prospectively on January 1, 2017, thus prior periods were not adjusted. The impact of adoption was not material to our consolidated condensed balance sheets.

In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting . The simplifications in this standard affect several aspects of the accounting for share-based payment transactions, including the requirement to record all of the tax effects related to share-based payments at settlement (or expiration) through the income statement. We adopted this pronouncement on January 1, 2017. The impact of adoption was not material to our consolidated condensed financial statements and related disclosures.

New Accounting Standards To Be Adopted

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers . The ASU will supersede most of the existing revenue recognition requirements in U.S. GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Company expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires significantly expanded disclosures regarding the qualitative and quantitative information of an entity's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The pronouncement is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.

The standard permits either a full retrospective method of adoption, in which the standard is applied to all the periods presented, or a modified retrospective method of adoption, in which the standard is applied only to the current period with a cumulative-effect adjustment reflected in retained earnings.  We currently intend on adopting the new standard on January 1, 2018, following the modified retrospective method, but will not make a final decision on the adoption method until later in 2017.

We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, that it may have on our financial position and results of operations. In the fourth quarter of 2016, we formed an implementation work

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

team, completed training of the new ASU's revenue recognition model and began policy and contract review. Our approach includes performing a detailed review of contracts representative of our different product lines and comparing historical accounting policies and practices to the new requirements that are in the standard. We engaged external resources to help the Company complete the analysis of potential changes to current accounting practices related to material revenue streams and are substantially complete with the initial assessment. During the remainder of 2017, we will quantify the potential impacts as well as design and implement required process, system and control changes to address the impacts identified in the assessment. We are not currently able to reasonably estimate the impact the revenue recognition will have on our consolidated financial statements and related disclosures.

In February 2016, the FASB issued ASU No. 2016-02, Leases , a new standard on accounting for leases. The ASU introduces a lessee model that brings most leases on the balance sheet. The new standard also aligns many of the underlying principles of the new lessor model with those in the current accounting guidance as well as the FASB's new revenue recognition standard. However, the ASU eliminates the use of bright-line tests in determining lease classification as required in the current guidance. The ASU also requires additional qualitative disclosures along with specific quantitative disclosures to better enable users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The pronouncement is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period, using a modified retrospective approach. Early adoption is permitted.

We are currently evaluating the provisions of ASU 2016-02 and assessing the impact it will have on our consolidated financial statements and related disclosures. In the fourth quarter of 2016, we formed an implementation work team and completed training of the new ASU's lease model with the implementation team. We engaged external resources to complete an initial review of lease agreements representative of the different aspects of our business, to assess the potential changes to current accounting practices as a result of the new requirements that are in the standard.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments. The new standard amends the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments to utilize an expected loss methodology in place of the currently used incurred loss methodology. This pronouncement is effective for annual periods beginning after December 15, 2019, including interim periods within those annual periods. Early adoption will be permitted for annual periods beginning after December 15, 2018. We are currently evaluating the provisions of the pronouncement and assessing the impact, if any, on our consolidated financial statements and related disclosures.

In August 2016, the FASB issued ASU No. 2016-15, Classification of Certain Cash Receipts and Cash Payments . The standard addresses the classification and presentation of eight specific cash flow issues that currently result in diverse practices. This pronouncement is effective for annual reporting periods beginning after December 15, 2017. The amendments in this ASU should be applied using a retrospective approach. We have not completed an evaluation of the impact the pronouncement will have on our consolidated financial statements and related disclosures, but the impact is not expected to be material.

In October 2016, the FASB issued ASU No. 2016-16, Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory . The standard removes the prohibition in ASC 740 against the immediate recognition of the current and deferred income tax effects of intra-entity transfers of assets other than inventory. This pronouncement is effective for annual reporting periods beginning after December 15, 2017. The amendments in this ASU should be applied using a retrospective approach. We have not completed an evaluation of the impact the pronouncement will have on our consolidated financial statements and related disclosures, but the impact is not expected to be material.

In January 2017, the FASB issued ASU No. 2017-04, Simplifying the Test for Goodwill Impairment, which removes the requirement to compare the implied fair value of goodwill with its carrying amount as part of Step two of the goodwill impairment test. As a result, under this ASU, an entity would recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. This pronouncement is effective for

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

impairment tests in fiscal years beginning after December 15, 2019, on a prospective basis. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017.

In March 2017, the FASB issued ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost , which changes the income statement presentation of net periodic benefit cost by requiring separation between the service cost component and all other components. The service cost component is required to be presented as an operating expense with other similar compensation costs arising for services rendered by the pertinent employees during the period. The non-operating components must be presented outside of income from operations. This pronouncement is effective for annual reporting periods beginning after December 15, 2017. Early adoption is permitted. We have not completed an evaluation of the impact the pronouncement will have on our consolidated financial statements and related disclosures, but the impact is not expected to be material.

NOTE 2. GENERAL ELECTRIC TRANSACTION AGREEMENT

On October 30, 2016, Baker Hughes, General Electric Company ("GE"), Bear Newco, Inc. ("Newco"), a Delaware corporation and a direct wholly owned subsidiary of Baker Hughes, and Bear MergerSub, Inc. ("Merger Sub"), a Delaware corporation and a direct wholly owned subsidiary of Newco, entered into a Transaction Agreement and Plan of Merger (the "Transaction Agreement"). The Transaction Agreement was amended on March 27, 2017 pursuant to the Amendment to Transaction Agreement and Plan of Merger (the "Amendment") entered into among Baker Hughes, GE, Newco, Merger Sub, BHI Newco, Inc., a Delaware corporation and wholly owned subsidiary of Baker Hughes ("Newco 2"), and Bear MergerSub 2, Inc., a Delaware corporation and direct wholly owned subsidiary of Newco 2 ("Merger Sub 2"). The Amendment provides that the transactions contemplated by the Transaction Agreement (the "GE Transaction") include (i) the merger of Baker Hughes with Merger Sub 2, with Baker Hughes surviving the merger as a direct wholly owned subsidiary of Newco 2 (the "First Merger"), (ii) the conversion of the surviving corporation of the First Merger into a Delaware limited liability company ("Newco LLC") (the "Conversion"), (iii) the merger of Newco 2 with Newco, with Newco surviving the merger (the "Second Merger" and collectively with the First Merger, the "Mergers") and (iv) the transfer by GE to Newco LLC, following the Mergers and the Conversion, and as originally provided under the Transaction Agreement, of (1) all of the equity interests of the holding companies that will hold directly or indirectly all of the assets and liabilities of GE's oil and gas business ("GE O&G"), including any GE O&G operating subsidiaries, and (2) $7.4 billion in cash in exchange for approximately 62.5% of the membership interests in Newco LLC. Newco will operate as a public company following the closing of the GE Transaction (the "Closing"). Following the Closing, Newco will distribute as a special dividend an amount equal to $17.50 per share to the holders of record of the Newco Class A common stock, which are the former Baker Hughes stockholders.

As originally provided under the Transaction Agreement, immediately following completion of the GE Transaction, the combined business of Baker Hughes and GE O&G will be held by Newco LLC. GE will own approximately 62.5% of Newco LLC and Newco will own approximately 37.5% of Newco LLC through certain wholly owned subsidiaries of Newco, one of which will be the managing member of Newco LLC. GE will hold 100% of the Newco Class B common stock, which will represent approximately 62.5% of the voting power of the outstanding shares of common stock of Newco (calculated on a fully diluted basis) and stockholders of Baker Hughes immediately prior to the Closing will hold 100% of the Newco Class A common stock, which will represent approximately 37.5% of the voting power of the outstanding shares of common stock of Newco. The membership interests in Newco LLC, together with the Newco Class B common stock, will be exchangeable on a 1:1 basis for Newco Class A common stock, subject to certain adjustments. The rights of Newco Class A and Class B common stock will be identical as to voting rights, but unlike the holders of the Class A common stock, GE, as the holder of the Class B common stock, will have no economic rights in Newco, including no right to dividends and no right to any assets in the event of the liquidation of Newco. Effective from and following the Closing, Newco and its subsidiaries will operate under the name "Baker Hughes, a GE Company."

Baker Hughes and GE each made customary representations, warranties and covenants in the Transaction Agreement, including, among others, covenants by each of Baker Hughes and GE to, subject to certain exceptions, conduct its business (in the case of Baker Hughes) or GE O&G (in the case of GE) in the ordinary course during the interim period between the execution of the Transaction Agreement and the Closing. In particular, among other restrictions and subject to certain exceptions, Baker Hughes agreed to generally refrain from acquiring new

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

businesses, incurring new indebtedness, repurchasing shares, issuing new common stock or equity awards (other than equity awards granted to employees, officers and directors materially consistent with historical long-term incentive awards granted), or entering into new material contracts or commitments outside the normal course of business, without the consent of GE, during the period between the execution of the Transaction Agreement and the consummation of the GE Transaction.  With respect to equity awards granted after the Transaction Agreement to officers and employees, such awards will not vest solely as a result of the GE Transaction but will be converted to an equivalent Newco equity award.  However, they will vest entirely if an officer or employee is terminated within one year following the Closing of the GE Transaction.

Baker Hughes is permitted to pay regular quarterly cash dividends to its stockholders between signing and Closing. GE O&G is permitted to pay dividends to GE between signing and Closing; provided that GE O&G is required to have a minimum level of working capital at Closing.

The obligation of the parties to consummate the GE Transaction is subject to customary closing conditions, including, among others, (i) the approval of holders of a majority of the outstanding shares of Baker Hughes common stock; (ii) (A) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; (B) the European Commission issuing a decision under the Council Regulation (EC) No. 139/2004 of January 20, 2004 on the control of concentrations between undertakings (published in the Official Journal of the European Union on January 29, 2004 at L 24/1) declaring the GE Transaction compatible with the common market, or, if the European Commission has adopted any decision under Article 9 of such regulations to refer the GE Transaction in part to any Member State of the European Economic Area, the European Commission issuing a decision declaring the part of the GE Transaction not so referred to that Member State compatible with the common market and every Member State to which part of the Transaction has been referred under Article 9 issuing a decision clearing the GE Transaction; and (C) the expiration or termination of all other applicable waiting and other time periods under certain other regulatory and competition laws; (iii) the absence of legal restraints and prohibitions; (iv) the effectiveness of the registration statement on Form S-4 to be filed by Newco with the Securities and Exchange Commission and the approval of the listing on the New York Stock Exchange of Newco Class A Common Stock to be issued in the GE Transaction; and (v) the completion in all material respects of certain restructuring transactions in connection with the GE Transaction. The obligation of each party to consummate the GE Transaction is also conditioned upon the other party's representations and warranties being true and correct (subject to certain materiality exceptions) and the other party having performed in all material respects its obligations under the Transaction Agreement.

GE is required to take all actions necessary to obtain regulatory approvals (including agreeing to divestitures of certain specified businesses and any businesses of which any such business forms a substantial part (the "Specified Businesses")) unless the assets, businesses or product lines subject to such actions would account for more than $200 million of revenue in 2015. The divestiture of the Specified Businesses will not be taken into account for purposes of calculating the $200 million divestiture limit. Subject to certain exceptions, proceeds of any divestitures would remain with GE O&G and be transferred to Newco LLC following the Closing of the GE Transaction .

Additionally, the Transaction Agreement provides for certain termination rights for each of Baker Hughes and GE, including (i) GE's right to terminate the Transaction Agreement if Baker Hughes' board of directors changes its recommendation that Baker Hughes' stockholders approve the Transaction Agreement; (ii) Baker Hughes' right to terminate the Transaction Agreement, prior to obtaining the approval of its stockholders, to enter into a definitive agreement providing for a superior proposal; and (iii) the right of each party to terminate the Transaction Agreement if the GE Transaction has not been consummated by the "termination date" of January 30, 2018, subject to each party's right to extend the termination date until April 30, 2018, if all closing conditions (other than receipt of certain regulatory approvals) has been satisfied by January 30, 2018.

The Transaction Agreement provides for the payment by Baker Hughes to GE of a termination fee of $750 million if certain events described in the Transaction Agreement occur, including if Baker Hughes' board of directors changes its recommendation that Baker Hughes' stockholders approve the Transaction Agreement.

Baker Hughes is also required to reimburse GE for certain expenses (up to $40 million ) if the Transaction Agreement is terminated because Baker Hughes' stockholders have not approved the Transaction Agreement upon

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

a vote taken thereon , and prior to the Baker Hughes stockholder meeting , a proposal for an alternative transaction was publicly announced and not withdrawn. If, within twelve months after such termination, Baker Hughes enters into an agreement providing for, or consummates, an alternative transaction with a third party, thereby triggering the $750 million termination fee described above, that termination fee will be reduced by the amount of any expenses previously reimbursed.

In the event the Transaction Agreement is terminated by (i) either party as a result of the failure of the GE Transaction to occur on or before the termination date (as it may be extended) due to the failure to achieve certain antitrust-related approvals if all closing conditions (other than receipt of antitrust and other specified regulatory approvals and conditions that by their nature cannot be satisfied until the Closing but subject to such conditions being capable of being satisfied if the Closing date were the date of termination) have been satisfied, (ii) either party as a result of any antitrust-related final, non-appealable order or injunction prohibiting the Closing, or (iii) Baker Hughes, as a result of GE's material breach of its obligations to obtain regulatory approvals such that the antitrust-related condition to closing is incapable of being satisfied, then in each case GE would be required to pay Baker Hughes a termination fee of $1.3 billion .

Baker Hughes and GE expect the GE Transaction to close in mid-2017. However, Baker Hughes cannot predict with certainty when, or if, the GE Transaction will be completed because completion of the GE Transaction is subject to conditions beyond the control of Baker Hughes. Baker Hughes incurred costs of $31 million related to the GE Transaction, which was recorded as Merger and related costs during the first quarter of 2017.

NOTE 3. IMPAIRMENT AND RESTRUCTURING CHARGES

IMPAIRMENT CHARGES

We conduct impairment tests on long-lived assets whenever events or changes in circumstances indicate that the carrying value may not be recoverable based on estimated future cash flows. During the first quarter of 2017, based on current facts and circumstances, we did not identify any indicators of potential impairment for assets still in use that would require further examination. Impairments related to assets removed from service are included in restructuring charges below.

During the first quarter of 2016, as a result of our customers' constrained capital spending budgets driven by deteriorating commodity prices, we performed impairment testing of certain long-lived assets and as a result, we recorded impairment charges of $118 million . Specifically, certain machinery and equipment with an initial total carrying value of $203 million was written down to its estimated fair value, resulting in an impairment charge of $106 million . Additionally, certain intangible assets with an initial total carrying value of $29 million were written down to their estimated fair values, resulting in an impairment charge of $12 million . The majority of the machinery and equipment and intangible assets impaired in the first quarter of 2016 were related to our businesses in Russia Caspian and Asia Pacific. These assets remain in use. The estimated fair values for these assets were determined using discounted future cash flows. The significant Level 3 unobservable inputs used in the determination of the fair value of these assets were the estimated future cash flows and the weighted average cost of capital of 15.0% for Russia Caspian and 13.5% for Asia Pacific.

RESTRUCTURING CHARGES

As a result of the downturn in the oil and natural gas industry, beginning in the first quarter of 2015 through the end of 2016, we took broad actions to reduce costs, simplify our organization, refine and rationalize our operating strategy and adjust our capacity to meet expected levels of activity. We refer to this initiative as the "Global Cost Reduction and Restructuring."

During the first quarter of 2017, we initiated a separate restructuring plan to address specific market challenges in key areas, including offshore North America, North Sea, Africa and Southeast Asia. These actions are primarily related to workforce reductions. We refer to this initiative as the "2017 Oilfield Restructuring."

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

As a result of the two restructuring plans described above, we recorded charges during the three months ended March 31, 2017 and 2016 , as summarized in the table below:

	Three Months Ended				Three Months Ended
Restructuring charges	March 31, 2017				March 31, 2016
Global Cost Reduction and Restructuring	$	21			$	42
2017 Oilfield Restructuring	69				—
Total restructuring charges	$	90			$	42

Global Cost Reduction and Restructuring

As part of our Global Cost Reduction and Restructuring plan, we took actions that included workforce reductions, contract terminations, facility closures and the permanent removal from service and disposal of excess machinery and equipment. Restructuring activities relating to these global cost reductions continued into the first quarter of 2017. However, we do not expect significant restructuring activities under this plan for the remainder of 2017. The composition of total restructuring charges we incurred under this plan in the first quarter of 2017 and 2016 is shown in the following table:

	Three Months Ended				Three Months Ended
	March 31, 2017				March 31, 2016
Workforce reductions	$	3			$	47
Other	18				(5		)
Total restructuring charges	$	21			$	42

During the first three months of 2017 , there were additional workforce reductions resulting in the elimination of approximately 70 additional positions worldwide, bringing the total number of positions eliminated to 26,270 since the first quarter of 2015 as a result of this restructuring activity. We made payments totaling $20 million during the first three months of 2017 , and as of March 31, 2017, we had $42 million of accrued severance. We expect that substantially all of the accrued severance will be paid within 2017.

Also during the first quarter of 2017 , we incurred costs of $18 million primarily related to the termination of facility and equipment lease contracts, and impairment charges resulting from the closing of certain owned facilities primarily within our North America segment. As of March 31, 2017, we had accrued contract termination costs of $80 million , of which substantially all will be paid within 2017.

2017 Oilfield Restructuring

As part of the 2017 Oilfield Restructuring plan, we took actions to reorganize our operating structure in certain countries based on recent changes in market conditions. Accordingly, we recorded a charge of $69 million , primarily related to workforce reductions. The composition of total restructuring charges we incurred under this plan in the first quarter of 2017 is shown in the following table:

	Three Months Ended
	March 31, 2017
Workforce reductions	$	58
Other	11
Total restructuring charges	$	69

The workforce reductions initiated in the first quarter of 2017 will result in the elimination of approximately 850 positions worldwide. As of March 31, 2017, we had $50 million of accrued severance. We expect that substantially all of the accrued severance will be paid within 2017. We do not expect significant restructuring activities under this plan for the remainder of 2017.

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 4. EQUITY METHOD INVESTMENT

We use the equity method to account for investments in companies in which Baker Hughes does not have a controlling financial interest, but over which it exercises significant influence over its operating and financial policies. Our consolidated net income (loss) includes our Company's proportionate share of the net income (loss) of the investee.

In December 2016, we closed the transaction contemplated by the contribution agreement among subsidiaries of Baker Hughes, CSL Capital Management ("CSL") and West Street Energy Partners ("WSEP"), a fund managed by the Merchant Banking Division of Goldman Sachs, to create a North American onshore pressure pumping company, called BJ Services, LLC ("BJ Services"). Under the terms of the agreement, we contributed our wholly-owned North American onshore pressure pumping business, which consists primarily of cementing and hydraulic fracturing services in the U.S. and Canada. This also includes personnel, technology and infrastructure. We received a 46.7% interest in BJ Services, which we recorded as an equity method investment included in Other Assets in our consolidated condensed balance sheet. We retained no other services within the onshore North American pressure pumping business that was contributed to BJ Services.

We will continue to provide customary support services during the transition period. BJ Services has access to certain of Baker Hughes' pressure pumping technology through a licensing agreement. We have representation on the BJ Services board of directors based on our ownership interest.  While there is no formal agreement for strategic collaboration between the Company and BJ Services, the mixed board representation allows the Baker Hughes representatives and the BJ Services executives to identify possible opportunities for the two parties to collaborate.  Through this collaboration, we may access BJ Services' product and service portfolio to provide solutions to customers in the North American onshore market if and when opportunities arise.

Financial information for BJ Services is reported on a one-month lag. The impact of the lag on our consolidated net income (loss) is not expected to be material. BJ Services is taxed as a partnership, therefore, the net loss reflected below does not include income taxes. Summarized unaudited financial information for BJ Services for the two months ended February 28, 2017 is as follows:

Revenue	$	100
Gross profit (loss)	(28		)
Net loss	(39		)
Net loss attributable to Baker Hughes	(18		)

NOTE 5. SEGMENT INFORMATION

We are a supplier of oilfield services, products, technology and systems used in the worldwide oil and natural gas business, referred to as oilfield operations, which are managed through operating segments that are aligned with our geographic regions. We also provide services and products to the downstream chemicals, and process and pipeline services, referred to as Industrial Services.

The performance of our operating segments is evaluated based on operating profit (loss) before tax, which is defined as income (loss) before income taxes and equity in loss of affiliate and before the following: net interest expense, corporate expenses, impairment and restructuring charges, and certain gains and losses not allocated to the operating segments.

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

Summarized financial information is shown in the following tables:

	Three Months Ended								Three Months Ended
	March 31, 2017								March 31, 2016
Segments	Revenue				Operating Profit (Loss) Before Tax				Revenue				Operating Profit (Loss) Before Tax
North America	$	712			$	(23	)		$	819			$	(225	)
Latin America	201				84				277				(66		)
Europe/Africa/Russia Caspian	461				1				611				(19		)
Middle East/Asia Pacific	661				72				718				49
Industrial Services	227				(6		)		245				(4		)
Total Operations	2,262				128				2,670				(265		)
Corporate	—				(37		)		—				(32		)
Interest expense, net	—				(35		)		—				(55		)
Impairment and restructuring charges	—				(90		)		—				(160		)
Merger and related costs	—				(31		)		—				(102		)
Total	$	2,262			$	(65	)		$	2,670			$	(614	)

NOTE 6. INCOME TAXES

For the three months ended March 31, 2017 , total income tax expense was $47 million on a loss before income taxes, including equity in loss of affiliate, of $83 million , resulting in a negative effective tax rate of 56.6% . The negative effective tax rate is due primarily to the geographical mix of earnings and losses, which resulted in taxes in certain jurisdictions, including withholding and deemed profit taxes, exceeding the tax benefit from the losses in other jurisdictions due to valuation allowances provided in most loss jurisdictions.

NOTE 7. EARNINGS PER SHARE

A reconciliation of the number of shares used for the basic and diluted loss per share computations is as follows:

	Three Months Ended March 31,
	2017			2016
Weighted average common shares outstanding for basic and diluted loss per share	429			442
Anti-dilutive shares excluded from diluted loss per share (1)	1			—
Future potentially dilutive shares excluded from diluted loss per share (2)	2			7

(1)	The calculation of diluted loss per share for the three months ended March 31, 2017 excludes shares potentially issuable under stock-based incentive compensation plans and the employee stock purchase plan, as their effect, if included, would have been anti-dilutive.

(2)	Options where the exercise price exceeds the average market price are excluded from the calculation of diluted net loss or earnings per share because their effect would be anti-dilutive.

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 8. INVENTORIES

Inventories, net of reserves of $157 million at March 31, 2017 and $188 million at December 31, 2016 , are comprised of the following:

	March 31, 2017				December 31, 2016
Finished goods	$	1,679			$	1,607
Work in process	123				105
Raw materials	105				97
Total inventories	$	1,907			$	1,809

NOTE 9. INTANGIBLE ASSETS

Intangible assets are comprised of the following:

	March 31, 2017												December 31, 2016
	Gross Carrying Amount				Less: Accumulated Amortization				Net				Gross Carrying Amount				Less: Accumulated Amortization				Net
Technology	$	523			$	275			$	248			$	527			$	267			$	260
Customer relationships	68				33				35				74				31				43
Trade names	19				12				7				90				79				11
Other	18				14				4				17				13				4
Total intangible assets	$	628			$	334			$	294			$	708			$	390			$	318

Intangible assets are generally amortized on a straight-line basis with estimated useful lives ranging from 3 to 30  years. Amortization expense for the three months ended March 31, 2017 was $14 million , as compared to $22 million reported in 2016 for the same period.

Amortization expense of these intangibles over the remainder of 2017 and for each of the subsequent five fiscal years is expected to be as follows:

Year	Estimated Amortization Expense
Remainder of 2017	$	39
2018	48
2019	45
2020	38
2021	32
2022	29

NOTE 10. FINANCIAL INSTRUMENTS

Our financial instruments include cash and cash equivalents, accounts receivable, investments, accounts payable, short and long-term debt and derivative financial instruments. Except for long-term debt, the estimated fair value of our financial instruments at March 31, 2017 and December 31, 2016 approximates their carrying value as reflected in our consolidated condensed balance sheets.

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

The estimated fair value of total debt at March 31, 2017 and December 31, 2016 was $3.35 billion and $3.36 billion , respectively, which differs from the carrying amount of $3.02 billion reported in each period, respectively, in our consolidated condensed balance sheets. The fair value was determined using quoted period-end market prices.

During the first quarter of 2017, we executed an agreement with our primary customer in Ecuador, resulting in an exchange of certain fully reserved outstanding receivables for government-backed bonds.  We recorded the bonds at their estimated fair value of $84 million at the date of exchange, which approximated their fair value as of March 31, 2017.  Estimated fair value for these bonds was determined using discounted cash flows.  The significant Level 3 unobservable input used in the determination of the fair value was the discount rate of 11.6% , which was based on the Ecuador government bond yield.  This investment is classified as available-for-sale and included in Other Current Assets on our consolidated condensed balance sheet.

NOTE 11. EMPLOYEE BENEFIT PLANS

We have both funded and unfunded noncontributory defined benefit pension plans ("Pension Benefits") covering certain employees primarily in the U.S., the United Kingdom, Germany and Canada. We also provide certain postretirement health care benefits ("Other Postretirement Benefits"), through an unfunded plan, to a closed group of U.S. employees who, when they retire, have met certain age and service requirements.

The components of net periodic cost are as follows for the three months ended March 31 :

	U.S. Pension Benefits								Non-U.S. Pension Benefits								Other Postretirement Benefits
	2017				2016				2017				2016				2017				2016
Service cost	$	10			$	13			$	3			$	4			$	1			$	1
Interest cost	7				7				6				7				1				1
Expected return on plan assets	(10		)		(10		)		(9		)		(9		)		—				—
Amortization of prior service credit	—				—				—				—				(2		)		(2		)
Amortization of net actuarial loss	2				3				2				1				—				—
Net periodic cost	$	9			$	13			$	2			$	3			$	—			$	—

NOTE 12. COMMITMENTS AND CONTINGENCIES

LITIGATION

We are subject to a number of lawsuits and claims arising out of the conduct of our business. The ability to predict the ultimate outcome of such matters involves judgments, estimates and inherent uncertainties. We record a liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated, including accruals for self-insured losses which are calculated based on historical claim data, specific loss development factors and other information. A range of total possible losses for all litigation matters cannot be reasonably estimated. Based on a consideration of all relevant facts and circumstances, we do not expect the ultimate outcome of any currently pending lawsuits or claims against us will have a material adverse effect on our financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of these matters.

We insure against risks arising from our business to the extent deemed prudent by our management and to the extent insurance is available, but no assurance can be given that the nature and amount of that insurance will be sufficient to fully indemnify us against liabilities arising out of pending or future legal proceedings or other claims. Most of our insurance policies contain deductibles or self-insured retentions in amounts we deem prudent and for which we are responsible for payment. In determining the amount of self-insurance, it is our policy to self-insure those losses that are predictable, measurable and recurring in nature, such as claims for automobile liability, general liability and workers compensation.

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

During 2014, we received customer notifications related to a possible equipment failure in a natural gas storage system in Northern Germany, which includes certain of our products. We are currently investigating the cause of the possible failure and, if necessary, possible repair and replacement options for our products. Similar products were utilized in other natural gas storage systems for this and other customers. The customer initiated arbitral proceedings against us on June 19, 2015, under the rules of the German Institute of Arbitration e.V. (DIS). On August 3, 2016, the customer amended its claims and now alleges damages of approximately $224 million plus interest at an annual rate of prime + 5% . Hearings before the arbitration panel were held January 16, 2017 through January 23, 2017, and March 20, 2017 through March 21, 2017. In addition, on September 21, 2015, TRIUVA Kapitalverwaltungsgesellschaft mbH filed a lawsuit in the United States District Court for the Southern District of Texas, Houston Division against the Company and Baker Hughes Oilfield Operations, Inc. alleging that the plaintiff is the owner of gas storage caverns in Etzel, Germany in which the Company provided certain equipment in connection with the development of the gas storage caverns. The plaintiff further alleges that the Company supplied equipment that was either defectively designed or failed to warn of risks that the equipment posed, and that these alleged defects caused damage to the plaintiff's property. The plaintiff seeks recovery of alleged compensatory and punitive damages of an unspecified amount, in addition to reasonable attorneys' fees, court costs and pre-judgment and post-judgment interest. The allegations in this lawsuit are related to the claims made in the June 19, 2015 German arbitration referenced above. At this time, we are not able to predict the outcome of these claims or whether either will have any material impact on our financial position, results of operations or cash flows.

On April 30, 2015, a class and collective action lawsuit alleging that we failed to pay a nationwide class of workers overtime in compliance with the Fair Labor Standards Act and North Dakota law was filed titled Williams et al. v. Baker Hughes Oilfield Operations, Inc. in the U.S. District Court for the District of North Dakota.  On February 8, 2016, the Court conditionally certified certain subclasses of employees for collective action treatment. We are evaluating the background facts and at this time cannot predict the outcome of this lawsuit and are not able to reasonably estimate the potential impact, if any, such outcome would have on our financial position, results of operations or cash flows.

On July 31, 2015, Rapid Completions LLC filed a lawsuit in federal court in the Eastern District of Texas against Baker Hughes Incorporated, Baker Hughes Oilfield Operations, Inc., and others claiming infringement of U.S. Patent Nos. 6,907,936; 7,134,505; 7,543,634; 7,861,774; and 8,657,009.  On August 6, 2015, Rapid Completions amended its complaint to allege infringement of U.S. Patent No. 9,074,451.  On September 17, 2015, Rapid Completions and Packers Plus Energy Services Inc., sued Baker Hughes Canada Company in the Canada Federal Court on related Canadian patent 2,412,072. On April 1, 2016, Rapid Completions removed U.S. Patent No. 6,907,936 from its claims in the lawsuit. On April 5, 2016, Rapid Completions filed a second lawsuit in federal court in the Eastern District of Texas against Baker Hughes Incorporated, Baker Hughes Oilfield Operations, Inc. and others claiming infringement of U.S. Patent No. 9,303,501. These patents relate primarily to certain specific downhole completions equipment. The plaintiff has requested a permanent injunction against further alleged infringement, damages in an unspecified amount, supplemental and enhanced damages, and additional relief such as attorney's fees and costs.  During August and September 2016, the United States Patent and Trademark office agreed to institute an inter-partes review of U.S. Patent Nos 7,861,774; 7,134,505; 7,534,634; 6,907,936; 8,657,009; and 9,074,451. Trial on the validity of asserted claims from Canada patent 2,412,072, was completed March 9, 2017, with no decision from the Court at this time. At this time, we are not able to predict the outcome of these claims or whether they will have a material impact on our financial position, results of operations or cash flows.

OTHER

In the normal course of business with customers, vendors and others, we have entered into off-balance sheet arrangements, such as surety bonds for performance, letters of credit and other bank issued guarantees, which totaled approximately $1.1 billion at March 31, 2017 . It is not practicable to estimate the fair value of these financial instruments. None of the off-balance sheet arrangements either has, or is likely to have, a material effect on our financial position, results of operations or cash flows.

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 13. ACCUMULATED OTHER COMPREHENSIVE LOSS

The following tables present the changes in accumulated other comprehensive loss, net of tax:

	Pensions and Other Postretirement Benefits					Foreign Currency Translation Adjustments					Accumulated Other Comprehensive Loss
Balance at December 31, 2016		$	(284	)			$	(749	)			$	(1,033	)
Other comprehensive income (loss) before reclassifications		(3		)			23					20
Amounts reclassified from accumulated other comprehensive loss		2					—					2
Balance at March 31, 2017		$	(285	)			$	(726	)			$	(1,011	)

	Pensions and Other Postretirement Benefits					Foreign Currency Translation Adjustments					Accumulated Other Comprehensive Loss
Balance at December 31, 2015		$	(261	)			$	(744	)			$	(1,005	)
Other comprehensive income before reclassifications		1					65					66
Amounts reclassified from accumulated other comprehensive loss		2					—					2
Deferred taxes		(1		)			—					(1		)
Balance at March 31, 2016		$	(259	)			$	(679	)			$	(938	)

The amounts reclassified from accumulated other comprehensive loss during the three months ended March 31, 2017 and 2016 represent the amortization of prior service credit and net actuarial loss, which are included in the computation of net periodic cost. See Note 11. "Employee Benefit Plans" for additional details. Net periodic cost is recorded in cost of sales and services, research and engineering, and marketing, general and administrative expenses.

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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") should be read in conjunction with the consolidated condensed financial statements and the related notes included in Item 1 thereto, as well as our Annual Report on Form 10-K for the year ended December 31, 2016 (" 2016 Annual Report").

EXECUTIVE SUMMARY

Baker Hughes is a leading supplier of oilfield services, products, technology and systems used in the worldwide oil and natural gas industry, referred to as our oilfield operations. We manage our oilfield operations through four geographic segments consisting of North America, Latin America, Europe/Africa/Russia Caspian ("EARC"), and Middle East/Asia Pacific ("MEAP"). Our Industrial Services businesses are reported in a fifth segment. As of March 31, 2017 , Baker Hughes had approximately 32,000 employees compared to approximately 33,000 employees as of December 31, 2016 .

Within our oilfield operations, the primary driver of our businesses is our customers' capital and operating expenditures dedicated to oil and natural gas exploration, field development and production. The main products and services provided by oilfield operations fall into one of two categories, Drilling and Evaluation or Completion and Production. This classification is based on the two major phases of constructing an oil and/or natural gas well, the drilling phase and the completion phase, and how our products and services are utilized in each phase. We also provide products and services to the downstream chemicals, and process and pipeline services, referred to as Industrial Services.

During the first quarter of 2017, the market remained in a state of transition. In North America, while onshore activity increased faster than many industry observers had expected, the excess capacity in the marketplace prevented a meaningful recovery in price. This steep increase in North America onshore activity led to short-term growing pains as seen in stressed supply chains and varying degrees of cost inflation across the oilfield service sector. Additionally, outside of the North America onshore market, activity declined in many markets, particularly offshore. Despite these challenges, we reported improved operating results year-over-year and sequentially, which is the direct result of our cost reduction efforts and operational restructuring initiated since 2015.

In the first quarter of 2017 , we generated revenue of $2.26 billion , a decrease of $408 million , or 15% , compared to the first quarter of 2016 . All geographic segments experienced revenue declines in the first quarter of 2017 as compared to the first quarter of 2016. In North America, the revenue decline was driven by the divestiture of our onshore pressure pumping business in the fourth quarter of 2016 and reduced activity in the Gulf of Mexico. Outside North America, revenue decreased due primarily to reduced activity, and to a lesser extent, pricing pressures experienced globally over the past year. Loss before income tax and equity in loss of affiliate was $65 million for the first quarter of 2017 , and included impairment and restructuring charges of $90 million and merger and related costs of $31 million . These impairment and restructuring charges were recorded as a result of our continued actions to adjust our operations and cost structure to reflect reduced activity levels. Our operating results for the first quarter of 2017 were benefited by the deconsolidation of the North America onshore pressure pumping business, and by bad debt recoveries in Ecuador as a result of receiving government-backed bonds in exchange for fully reserved outstanding receivables. For the first quarter of 2016 , loss before income tax and equity in loss of affiliate was $614 million , which also included impairment and restructuring charges of $160 million , merger and related costs of $102 million as well as a loss on a firm purchase commitment of $51 million.

General Electric Transaction Agreement

On October 30, 2016, Baker Hughes, GE, Newco and Merger Sub entered into a Transaction Agreement and Plan of Merger, pursuant to which, among other things, GE's oil and gas business and Baker Hughes will be combined and operate under the name "Baker Hughes, a GE Company". The Transaction Agreement was amended on March 27, 2017 pursuant to the Amendment to Transaction Agreement and Plan of Merger (the "Amendment") entered into among Baker Hughes, GE, Newco, Merger Sub, BHI Newco, Inc., a Delaware corporation and wholly owned subsidiary of Baker Hughes ("Newco 2"), and Bear MergerSub 2, Inc., a Delaware corporation and direct wholly owned subsidiary of Newco 2 ("Merger Sub 2"). The GE Transaction is subject to the

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approval of Baker Hughes' stockholders, regulatory approvals and customary closing conditions. Baker Hughes and GE expect the GE Transaction to close in mid-2017. However, Baker Hughes cannot predict with certainty when, or if, the GE Transaction will be completed because completion of the GE Transaction is subject to conditions beyond the control of Baker Hughes. For further information about the transaction, see Note 2. "General Electric Transaction Agreement" of the Notes to Unaudited Consolidated Condensed Financial Statements in Item 1 herein. Newco will operate as a public company.

Outlook

The voluntary oil cuts agreed to in late 2016 by members of the Organization of Petroleum Exporting Countries ("OPEC") and some non-OPEC producers, coupled with the current projections for global oil demand growth point towards a rebalancing of the market in late 2017. However, the significant North America rig count growth over the past couple of quarters, impending production growth, and relatively high inventory levels have added some uncertainty into this equation, limiting upward oil price movement and causing oil prices to remain somewhat volatile. As a result, while we are more optimistic in an oil price and activity recovery than we were last quarter, we remain mindful of a range of external factors and unanswered questions that could slowdown the recovery. The largest single factor is OPEC's pending decision on whether to extend the production cuts that were implemented late last year. Also, geopolitical dynamics, economic growth, fiscal policy and currency fluctuations all remain variables that could impact supply and demand, and by extension, oil prices.

Based on current oil price outlook and existing customer hedges, we expect North America onshore activity to continue to grow and excess service capacity to continue to be absorbed. In the global offshore markets, where customer confidence in commodity prices remains one of the key elements that is required for a sustained industry recovery, we expect activity declines to continue for the rest of the year. Conversely, for the international land market, we expect activity to remain stable, with a few pockets of modest growth. The broader market conditions and customer behavior vary significantly by region and operating environment. However, with our leading products and innovative technologies, we are strongly positioned to capitalize on growth opportunities across all of our product lines and geographic regions.

BUSINESS ENVIRONMENT

We operate in more than 80 countries helping customers find, evaluate, drill, produce, transport and process hydrocarbon resources. Our revenue is predominately generated from the sale of products and services to major, national, and independent oil and natural gas companies worldwide, and is dependent on spending by our customers for oil and natural gas exploration, field development and production. This spending is driven by a number of factors, including our customers' forecasts of future energy demand and supply, their access to resources to develop and produce oil and natural gas, their ability to fund their capital programs, the impact of new government regulations and most importantly, their expectations for oil and natural gas prices as a key driver of their cash flows.

Oil and Natural Gas Prices

Oil and natural gas prices are summarized in the table below as averages of the daily closing prices during each of the periods indicated.

	Three Months Ended March 31,
	2017				2016
Brent oil price ($/Bbl) (1)	$	54.04			$	34.53
WTI oil price ($/Bbl) (2)	51.70				33.41
Natural gas price ($/mmBtu) (3)	2.98				1.96

(1)	Bloomberg Dated Brent ("Brent") Oil Spot Price per Barrel

(2)	Bloomberg West Texas Intermediate ("WTI") Cushing Crude Oil Spot Price per Barrel

(3)	Bloomberg Henry Hub Natural Gas Spot Price per million British Thermal Unit

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In North America, customer spending is highly driven by WTI oil prices, which began the first quarter of 2017 at $52.33/Bbl, and remained in a range between $47.00/Bbl and $54.10/Bbl. Early in the quarter, the oil market showed signs that a balance between supply and demand would be achieved by the end of 2017, which supported a recovery in oil prices. On the demand side, global economic activity remained healthy supporting oil consumption growth. On the supply side, voluntary oil cuts agreed in late 2016 by members of OPEC and some non-OPEC producers, achieved a substantial degree of compliance.

However, at the same time, North American drilling activity and production ramped up in response to the higher oil prices, causing inventories in the United States to build throughout the first quarter. U.S. crude oil production was an estimated 9.1 million Bbl/d in March, the highest level in a year. This growth in the U.S. decreased OPEC market share, adding to the uncertainty about whether its members will extend voluntary supply reductions for the second half of 2017. Additionally, forecasted oil demand growth for 2017 was revised down to 1.4 million Bbl/d compared to 1.6 million Bbl/d in 2016, with some indications of deceleration in Germany and several countries in Asia. These supply uncertainties combined with weaker oil demand growth limited the upward oil price movement, and continued to create volatility in the oil market as evident in the oil price fall experienced at the end of the quarter.

Outside North America, customer spending is most heavily influenced by Brent oil prices, which experienced a similar trend as WTI throughout the quarter, closing at $52.71/Bbl. Brent oil price fluctuations were driven by the same factors as WTI, although the growing U.S. supply has lowered WTI crude oil prices relative to international crude oil prices.

Overall, WTI and Brent oil prices in the first three months of 2017 averaged higher than the prior year period by 55% and 57%, respectively.

In North America, natural gas prices, as measured by the Henry Hub Natural Gas Spot Price, fluctuated between $2.44/mmBtu and $3.42/mmBtu, and averaged $2.98/mmBtu. Compared to the same quarter in the prior year, natural gas prices increased 52%, driven by higher drawdowns this season stemming from lower natural gas production and higher exports. According to the U.S. Department of Energy ("DOE"), working natural gas in storage in the last week of the first quarter of 2017 was 2,051 Bcf, which is 15% higher than the previous five-year (2012-2016) average, but 17%, or 427 Bcf, below the corresponding week in 2016.

Baker Hughes Rig Count

The Baker Hughes rig counts are an important business barometer for the drilling industry and its suppliers. When drilling rigs are active they consume products and services produced by the oil service industry. Rig count trends are driven by the exploration and development spending by oil and natural gas companies, which in turn is influenced by current and future price expectations for oil and natural gas. The counts may reflect the relative strength and stability of energy prices and overall market activity; however, these counts should not be solely relied on as other specific and pervasive conditions may exist that affect overall energy prices and market activity.

Baker Hughes has been providing rig counts to the public since 1944. We gather all relevant data through our field service personnel, who obtain the necessary data from routine visits to the various rigs, customers, contractors and other outside sources as necessary. We base the classification of a well as either oil or natural gas primarily upon filings made by operators in the relevant jurisdiction. This data is then compiled and distributed to various wire services and trade associations and is published on our website. We believe the counting process and resulting data is reliable; however, it is subject to our ability to obtain accurate and timely information. Rig counts are compiled weekly for the U.S. and Canada and monthly for all international rigs. Published international rig counts do not include rigs drilling in certain locations, such as Russia, the Caspian region, Iran and onshore China because this information is not readily available.

Rigs in the U.S. and Canada are counted as active if, on the day the count is taken, the well being drilled has been started but drilling has not been completed and the well is anticipated to be of sufficient depth to be a potential consumer of our drill bits. In international areas, rigs are counted on a weekly basis and deemed active if drilling activities occurred during the majority of the week. The weekly results are then averaged for the month and published accordingly. The rig count does not include rigs that are in transit from one location to another, rigging up,

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being used in non-drilling activities including production testing, completion and workover, and are not expected to be significant consumers of drill bits.

The rig counts are summarized in the table below as averages for each of the periods indicated.

	Three Months Ended March 31,
	2017		2016		% Change
U.S. - land and inland waters	722		535		35	%
U.S. - offshore	21		26		(19	%)
Canada	295		165		79	%
North America	1,038		726		43	%
Latin America	180		233		(23	%)
North Sea	26		30		(13	%)
Continental Europe	74		74		—	%
Africa	79		91		(13	%)
Middle East	383		403		(5	%)
Asia Pacific	197		186		6	%
Outside North America	939		1,017		(8	%)
Worldwide	1,977		1,743		13	%

The rig count in North America increased 43% in the first quarter of 2017 compared to the same period last year, as a consequence of increased spending from our customers in response to the upward price movement experienced early in the quarter. Following the OPEC production cut agreements and the subsequent oil price stability, many North American producers ramped up drilling programs and materially increased spending. Oil directed rigs in the United States have increased to about 32% above their levels last year. Natural gas drilling activity in the United States has also grown by about 31% since the first quarter of 2016 as lower production and higher exports reduced natural gas inventory levels. In Canada, both oil and gas drilling activity has meaningfully increased with the higher commodity prices.

Outside North America, the rig count in the first quarter of 2017 decreased 8% compared to the same period a year ago. In Latin America, the rig count declined 23% as a consequence of customer spending reductions throughout the entire region, but most notably in Mexico, Brazil, Venezuela, and Argentina, which were partially offset by an activity pickup in Colombia. In Europe, the rig count in the North Sea decreased 13% , primarily due to a reduction in offshore drilling activity in Norway, and in Continental Europe the rig count remained flat year over year. In Africa, the rig count decreased 13% primarily due to reduced drilling activity across the region, mainly in Angola and Algeria. The rig count decreased 5% in the Middle East due to lower drilling activity in Oman, Egypt, Iraq, and Saudi Arabia partially offset by increased drilling activity in Kuwait. In Asia Pacific, the rig count increased by 6% as a result of increased drilling activity in India, Australia, and Indonesia, which were partially offset by reduced activity in offshore China.

RESULTS OF OPERATIONS

The discussions below relating to significant line items from our unaudited consolidated condensed statements of income (loss) are based on available information and represent our analysis of significant changes or events that impact the comparability of reported amounts. Where appropriate, we have identified specific events and changes that affect comparability or trends and, where reasonably practicable, have quantified the impact of such items. In addition, the discussions below for revenue and cost of revenue are on a total basis as the business drivers for product sales and services are similar. All dollar amounts in tabulations in this section are in millions of dollars, unless otherwise stated.

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Revenue and Operating Profit (Loss) Before Tax

Revenue and operating profit (loss) before tax for each of our five operating segments is provided below. The performance of our operating segments is evaluated based on operating profit (loss) before tax, which is defined as income (loss) before income taxes and equity in loss of affiliate and before the following: net interest expense, corporate expenses, impairment and restructuring charges, and certain gains and losses not allocated to the operating segments.

	Three Months Ended March 31,								$ Change				% Change
	2017				2016
Revenue:
North America	$	712			$	819			$	(107	)		(13	%)
Latin America	201				277				(76		)		(27	%)
Europe/Africa/Russia Caspian	461				611				(150		)		(25	%)
Middle East/Asia Pacific	661				718				(57		)		(8	%)
Industrial Services	227				245				(18		)		(7	%)
Total	$	2,262			$	2,670			$	(408	)		(15	%)

	Three Months Ended March 31,								$ Change				% Change
	2017				2016
Operating Profit (Loss) Before Tax:
North America	$	(23	)		$	(225	)		$	202			90	%
Latin America	84				(66		)		150				227	%
Europe/Africa/Russia Caspian	1				(19		)		20				105	%
Middle East/Asia Pacific	72				49				23				47	%
Industrial Services	(6		)		(4		)		(2		)		(50	%)
Total Operations	128				(265		)		393				148	%
Corporate	(37		)		(32		)		(5		)		16	%
Interest expense, net	(35		)		(55		)		20				(36	%)
Impairment and restructuring charges	(90		)		(160		)		70				(44	%)
Merger and related costs	(31		)		(102		)		71				(70	%)
Loss Before Income Taxes and Equity in Loss of Affiliate	$	(65	)		$	(614	)		$	549			89	%

First Quarter of 2017 Compared to the First Quarter of 2016

North America

North America revenue decreased $107 million , or 13% , in the first quarter of 2017 compared to the first quarter of 2016 . The decline in revenue is primarily the result of the divestiture of our North America onshore pressure pumping business. Revenue from this business was $81 million in the first quarter of 2016. Additionally, revenue decreased as a result of the steep reduction in offshore activity in the Gulf of Mexico. These reductions were partially offset by increased onshore activity primarily in our drilling services, artificial lift and drill bits product lines. Although the North American rig count increased 43% in the first quarter of 2017, compared to the same period a year ago, excess capacity in the marketplace has prevented any meaningful pricing recovery. Additionally, our upstream chemicals product line, which represents a significant portion of the sales mix of our products and services in North America, is not highly correlated to changes in rig count.

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North America operating loss before tax was $23 million in the first quarter of 2017 compared to a loss of $225 million in the first quarter of 2016 . Despite the reduction in revenue, results from operations were benefited by $89 million due to the deconsolidation of the North America onshore pressure pumping business. Additionally, other actions taken to restructure our North American operations and the reduction of depreciation and amortization expense from asset impairments drove improvements in our operating results. While we have experienced increased activity in certain product lines, operating results were negatively impacted by the limited price recovery experienced in the market to date. The first quarter of 2016 included a loss on a firm purchase commitment of $51 million that did not repeat in 2017.

Latin America

Latin America revenue decreased $76 million , or 27% , in the first quarter of 2017 compared to the first quarter of 2016 primarily driven by reduced activity, as evident in the 23% drop in the rig count, and to a lesser extent lower pricing. Mexico experienced the largest decline in revenue in line with the decline in the rig count of 54%. To a lesser extent, our business in the Andean and Brazil also declined across almost all product lines.

Latin America operating profit before tax was $84 million in the first quarter of 2017 compared to an operating loss before tax of $66 million in the first quarter of 2016 . The increase in profitability is primarily due to an $84 million benefit in the first quarter of 2017 from bad debt recoveries in Ecuador from the receipt of government-backed bonds in exchange for fully reserved outstanding receivables, compared to $42 million of bad debt expense in the first quarter of 2016. Also, reduced operating costs resulting from our efforts to structurally realign the segment to reflect current and expected near-term activity levels contributed to the improvement. These events more than offset the impact to profitability from the reduction in revenue.

Europe/Africa/Russia Caspian

EARC revenue decreased $150 million , or 25% , in the first quarter of 2017 compared to the first quarter of 2016 . The decrease in revenue can be attributed to activity reductions, and to a lesser extent price deterioration, across all markets and the majority of our product lines. In particular, our drilling services and completions product lines in West Africa, and our drilling services product line in the North Sea experienced the sharpest declines. These reductions were partially offset by moderate growth in Russia, particularly in our drilling and evaluation product lines and our artificial lift business.

EARC operating profit before tax was $1 million in the first quarter of 2017 compared to an operating loss before tax of $19 million in the first quarter of 2016 . The impact from the decline in revenue was more than offset by the benefit of implemented cost reduction measures, and lower depreciation and amortization expense from asset impairments.

Middle East/Asia Pacific

MEAP revenue decreased $57 million or 8% in the first quarter of 2017 compared to the first quarter of 2016 . The decrease in revenue was largely due to reduced activity across most product lines in Iraq, Australia, South East Asia and Oman, and pricing pressure across the region, especially in Asia Pacific. In particular, we experienced the largest declines in Iraq as our integrated projects came to an end in 2016, and in our drilling services and completions business in Australia. These declines were partially offset by activity growth across most of our product lines in Saudi Arabia and in our drilling services product line in China.

MEAP operating profit before tax was $72 million in the first quarter of 2017 compared to $49 million in the first quarter of 2016 . The increase in profitability is driven primarily by the operating cost reductions and lower depreciation and amortization expense from asset impairments, which more than offset the impact from lower activity and price deterioration.

Industrial Servi ces

For Industrial Services, revenue decreased $18 million and profitability decreased $2 million in the first quarter of 2017 compared to the first quarter of 2016 due to project completions and activity reductions resulting from

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reduced spending and delayed projects by our customers, including several major pipeline construction and maintenance projects. Revenue and profitability were also negatively impacted by price deterioration in the market. The impact on profitability from decreased activity and price deterioration was lessened by cost reduction efforts taken in 2016.

Costs and Expenses

The table below details certain unaudited consolidated condensed statement of income (loss) data and as a percentage of revenue.

	Three Months Ended March 31,
	2017							2016
	$				%			$				%
Revenue	$	2,262			100	%		$	2,670			100	%
Cost of revenue	1,888				83.5	%		2,658				99.6	%
Research and engineering	99				4.4	%		102				3.8	%
Marketing, general and administrative	184				8.1	%		207				7.8	%
Impairment and restructuring charges	90				4.0	%		160				6.0	%
Merger and related costs	31				1.4	%		102				3.8	%

Cost of Revenue

Cost of revenue as a percentage of revenue was 83.5% and 99.6% for the three months ended March 31, 2017 and 2016 , respectively. The decrease in cost of revenue as a percentage of revenue is due mainly to the benefit of implemented cost reduction measures and lower depreciation and amortization from asset impairments. Additionally, cost of revenue for the three months ended March 31, 2017 was favorably impacted by bad debt recoveries of $94 million, primarily the result of receiving $84 million of government-backed bonds in exchange for certain fully reserved outstanding receivables in Ecuador. During the three months ended March 31, 2016, cost of revenue for the first three months of 2016 was negatively impacted by bad debt expense totaling $47 million, and a charge for the loss on a firm purchase commitment of $51 million that was recorded in cost of service.

Marketing, General and Administrative

Marketing, general and administrative ("MG&A") expenses declined by $23 million for the three months ended March 31, 2017 , compared to the same period a year ago. The decline in MG&A expenses is primarily a result of workforce reductions, lower spending, and reduced foreign exchange losses.

Impairment and Restructuring Charges

During the three months ended March 31, 2017, we recorded restructuring charges of $90 million . These restructuring charges consisted of $61 million for workforce reduction costs, and $29 million for contract termination costs and asset impairments related to facility closures and removal of excess machinery and equipment. Total cash paid during 2017 related to workforce reductions and contract terminations was $46 million .

During the three months ended March 31, 2016, we recorded restructuring charges of $42 million consisting primarily of workforce reduction costs. In addition to our restructuring activities, in response to the downturn in the energy market and its impact on our business outlook, we determined that the carrying amount of certain of our long-lived assets exceeded their respective fair values; therefore, we recorded an impairment charge of $118 million.

For further discussion of these charges, see Note 3. "Impairment and Restructuring Charges" of the Notes to Unaudited Consolidated Condensed Financial Statements in Item 1 of Part 1 herein.

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Merger and Related Costs

We incurred merger and related costs of $31 million related to the GE Transaction and $102 million related to the terminated merger with Halliburton for the three months ended March 31, 2017 and 2016, respectively, including costs under our retention programs. Costs related to the terminated merger with Halliburton also include obligations for minimum incentive compensation costs which, based on meeting eligibility criteria, were treated as merger and related expenses.

Income Taxes

For the three months ended March 31, 2017 , total income tax expense was $47 million on a loss before income taxes, including equity in loss of affiliate, of $83 million , resulting in a negative effective tax rate of 56.6% . The negative effective tax rate is due primarily to the geographical mix of earnings and losses, which resulted in taxes in certain jurisdictions, including withholding and deemed profit taxes, exceeding the tax benefit from the losses in other jurisdictions due to valuation allowances provided in most loss jurisdictions.

As a result of the geographic mix of earnings and losses, and other discrete tax items, our tax rate has been and will continue to be volatile until the market stabilizes.

LIQUIDITY AND CAPITAL RESOURCES

Our objective in financing our business is to maintain sufficient liquidity, adequate financial resources and financial flexibility in order to fund the requirements of our business. At March 31, 2017 , we had cash and cash equivalents of $4.22 billion compared to $4.57 billion of cash and cash equivalents held at December 31, 2016 .

At March 31, 2017 , approximately $3.13 billion of our cash and cash equivalents was held by foreign subsidiaries compared to approximately $2.92 billion at December 31, 2016 . A substantial portion of the cash held by foreign subsidiaries at March 31, 2017 was reinvested in our international operations as our intent is to use this cash to, among other things, fund the operations of our foreign subsidiaries. If we decide at a later date to repatriate those funds to the U.S., we may be required to provide taxes on certain of those funds based on applicable U.S. tax rates net of foreign tax credits. We have a committed revolving credit facility ("credit facility") with commercial banks and a related commercial paper program under which the maximum combined borrowing at any time under both the credit facility and the commercial paper program is $2.5 billion. At March 31, 2017 , we had no commercial paper outstanding; therefore, the amount available for borrowing under the credit facility as of March 31, 2017 was $2.5 billion. During the three months ended March 31, 2017 , we used cash to fund a variety of activities including certain working capital needs and restructuring costs, capital expenditures, and the payment of dividends. We believe that cash on hand, cash flows generated from operations and the available credit facility, including the issuance of commercial paper, will provide sufficient liquidity to manage our global cash needs.

Cash Flows

Cash flows provided by (used in) each type of activity were as follows for the three months ended March 31 :

(In millions)	2017				2016
Operating activities	$	(163	)		$	(99	)
Investing activities	(76		)		61
Financing activities	(112		)		(95		)

Operating Activities

Cash flows from operating activities used cash of $163 million in the three months ended March 31, 2017 , due to other operating items that used cash of $257 million primarily for employee compensation payments related to annual bonuses and severance. These cash outflows were partially offset by changes in the components of our working capital (receivables, inventories and accounts payable) as a result of lower activity that provided cash of $74 million.

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Investing Activities

Our principal recurring investing activity is the funding of capital expenditures to ensure that we have the appropriate levels and types of machinery and equipment in place to generate revenue from operations. Expenditures for capital assets totaled $87 million in the three months ended March 31, 2017 .

Proceeds from the disposal of assets were $76 million in the three months ended March 31, 2017 , which related primarily to equipment that was lost-in-hole, and to a lesser extent, property, machinery and equipment no longer used in operations that was sold throughout the period.

We purchased short-term and long-term investment securities totaling $68 million in the three months ended March 31, 2017 .

Financing Activities

We had net repayments of short-term debt and other borrowings of $6 million in the three months ended March 31, 2017 . Total debt outstanding was $3.02 billion at March 31, 2017 and December 31, 2016 , respectively. The total debt-to-capital (defined as total debt plus equity) ratio was 0.19 at March 31, 2017 and at December 31, 2016 . We paid dividends of $74 million in the three months ended March 31, 2017 .

We had no stock repurchases in the three months ended March 31, 2017 under our previously announced purchase program. We had authorization remaining to repurchase approximately $1.24 billion in common stock at March 31, 2017 . Under the Transaction Agreement with GE entered into on October 30, 2016 as described in Note 2. "General Electric Transaction Agreement" of the Notes to Unaudited Consolidated Condensed Financial Statements in Item 8 herein, we have generally agreed not to repurchase any shares of common stock or increase the quarterly dividend while the transaction is pending.

Available Credit Facility

We have a committed revolving credit facility with commercial banks and a related commercial paper program under which the maximum combined borrowing at any time under both the credit facility and the commercial paper program is $2.5 billion. The credit facility matures in July 2021 and contains certain covenants, which, among other things, require the maintenance of a total debt-to-total capitalization ratio, restrict certain merger transactions or the sale of all or substantially all of our assets or a significant subsidiary and limit the amount of subsidiary indebtedness. Upon the occurrence of certain events of default, our obligations under the credit facility may be accelerated. Such events of default include payment defaults to lenders under the credit facility, covenant defaults and other customary defaults.

We were in compliance with all of the credit facility's covenants, and there were no direct borrowings under the credit facility during the quarter ended March 31, 2017 . Under the commercial paper program, we may issue from time to time up to $2.5 billion in commercial paper with maturity of no more than 270 days. The amount available to borrow under the credit facility is reduced by the amount of any commercial paper outstanding. At March 31, 2017 , we had no outstanding borrowings under the commercial paper program.

If market conditions were to change and our revenue was reduced significantly or operating costs were to increase, our cash flows and liquidity could be reduced. Additionally, it could cause the rating agencies to lower our credit rating. There are no ratings triggers that would accelerate the maturity of any borrowings under our committed credit facility. However, a downgrade in our credit ratings could increase the cost of borrowings under the credit facility and could also limit or preclude our ability to issue commercial paper. Should this occur, we would seek alternative sources of funding, including borrowing under the credit facility.

We believe our current credit ratings would allow us to obtain interim financing over and above our existing credit facility for any currently unforeseen significant needs.

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Cash Requirements

For 2017 , we believe cash on hand, cash flows from operating activities and the available credit facility will provide us with sufficient capital resources and liquidity to manage our working capital needs, meet contractual obligations, fund capital expenditures and dividends, and support the development of our short-term and long-term operating strategies. If necessary, we may issue commercial paper or other short-term debt to fund cash needs in the U.S. in excess of the cash generated in the U.S.

Our capital expenditures can be adjusted and managed by us to match market demand and activity levels. In light of the current market conditions, capital expenditures in 2017 will be made as appropriate at a rate that we estimate would equal $450 million to $500 million on an annualized basis. The expenditures are expected to be used primarily for normal, recurring items necessary to support our business. We also anticipate making income tax payments in the range of $225 million to $275 million in 2017 .

During the three months ended March 31, 2017 , we contributed approximately $55 million to our defined benefit, defined contribution and other postretirement plans. We expect to make additional contributions in the range of $150 million to $160 million for the remainder of 2017.

We anticipate paying dividends in the range of $140 million to $160 million in the first half of 2017 prior to the expected Closing of the GE Transaction.

FORWARD-LOOKING STATEMENTS

MD&A and certain statements in the Notes to Unaudited Consolidated Condensed Financial Statements, includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act (each a "forward-looking statement"). The words "anticipate," "believe," "ensure," "expect," "if," "intend," "estimate," "probable," "project," "forecasts," "predict," "outlook," "aim," "will," "could," "should," "would," "potential," "may," "likely" and similar expressions, and the negative thereof, are intended to identify forward-looking statements. Our forward-looking statements are based on assumptions that we believe to be reasonable but that may not prove to be accurate. The statements do not include the potential impact of future transactions, such as an acquisition, disposition, merger, joint venture or other transactions that could occur, including the pending GE Transaction. We undertake no obligation to publicly update or revise any forward-looking statement. Our expectations regarding our business outlook, including changes in revenue, pricing, capital spending, profitability, tax rates, strategies for our operations, the impact of any common stock or debt repurchases or exchanges, oil and natural gas market conditions, the business plans of our customers, market share and contract terms, costs and availability of resources, legal, economic and regulatory conditions, and environmental matters are only our forecasts regarding these matters.

All of our forward-looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in "Part II, Item 1A. Risk Factors" section contained herein, as well as the risk factors described in our 2016 Annual Report, this filing and those set forth from time to time in our filings with the SEC. These documents are available through our website or through the SEC's Electronic Data Gathering and Analysis Retrieval ("EDGAR") system at http://www.sec.gov . In light of such risks and uncertainties, we caution you not to place undue reliance on these forward-looking statements. These forward-looking statements speak only as of the date of this quarterly report, or if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities law.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the three months ended March 31, 2017 , does not differ materially from that discussed under Part II, Item 7(a), "Quantitative and Qualitative Disclosures About Market Risk," in our 2016 Annual Report on Form 10-K.

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this Quarterly Report, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act of 1934, as amended (the "Exchange Act"). This evaluation was carried out under the supervision and with the participation of our management, including our principal executive officer and principal financial officer. Based on this evaluation, these officers have concluded that, as of March 31, 2017 , our disclosure controls and procedures, as defined by Rule 13a-15(e) of the Exchange Act, are effective at a reasonable assurance level. There has been no change in our internal controls over financial reporting during the quarter ended March 31, 2017 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Disclosure controls and procedures are our controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act, such as this Quarterly Report, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

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PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See discussion of legal proceedings in Note 12 of the Notes to Unaudited Consolidated Condensed Financial Statements in this Quarterly Report, Item 3 of Part I of our 2016 Annual Report and Note 15 of the Notes to Consolidated Financial Statements included in Item 8 of our 2016 Annual Report.

ITEM 1A. RISK FACTORS

As of the date of this filing, the Company and its operations continue to be subject to the risk factors previously disclosed in our "Risk Factors" contained in the 2016 Annual Report.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table contains information about our purchases of equity securities during the three months ended March 31, 2017 .

Period	Total Number of Shares Purchased (1)			Average Price Paid  Per Share (1)				Total Number of Shares Purchased as Part of a Publicly Announced Program (2)		Maximum Dollar Value of Shares that May Yet Be Purchased Under the Program (3)
January 1-31, 2017	487,595			$	62.54			—		$	1,237,161,230
February 1-28, 2017	845			$	59.96			—		$	1,237,161,230
March 1-31, 2017	—			$	—			—		$	1,237,161,230
Total	488,440			$	62.54			—

(1)	Represents shares purchased from employees to satisfy the tax withholding obligations in connection with the vesting of restricted stock awards and restricted stock units.

(2)	There were no repurchases during the first quarter of 2017 under our previously announced purchase program.

(3)

Under the transaction agreement with General Electric, as described in Note 2. "General Electric Transaction Agreement" of the Notes to the Consolidated Condensed Financial Statements, we have agreed to not repurchase any shares of our common stock other than in connection with shares repurchased from employees to satisfy the tax withholding obligations in connection with the vesting of equity awards.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Our barite mining operations, in support of our drilling fluids products and services business, are subject to regulation by the federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Quarterly Report.

ITEM 5. OTHER INFORMATION

In December 2016, we closed the transaction contemplated by the contribution agreement among subsidiaries of Baker Hughes, CSL Capital Management ("CSL") and West Street Energy Partners ("WSEP"), a fund managed by the Merchant Banking Division of Goldman Sachs, to create a North American onshore pressure pumping company, called BJ Services, LLC ("BJ Services"). Under the terms of the agreement, we contributed our wholly-owned North American onshore pressure pumping business, which consists primarily of cementing and hydraulic

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fracturing services in the U.S. and Canada. This also includes personnel, technology and infrastructure. We received a 46.7% interest in BJ Services, which we recorded as an equity method investment included in Other Assets in our consolidated condensed balance sheet. We retained no other services within the onshore North American pressure pumping business that was contributed to BJ Services.

We will continue to provide customary support services during the transition period. BJ Services has access to certain of Baker Hughes' pressure pumping technology through a licensing agreement. We have representation on the BJ Services board of directors based on our ownership interest.  While there is no formal agreement for strategic collaboration between the Company and BJ Services, the mixed board representation allows the Baker Hughes representatives and the BJ Services executives to identify possible opportunities for the two parties to collaborate.  Through this collaboration, we may access BJ Services' product and service portfolio to provide solutions to customers in the North American onshore market if and when opportunities arise.

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ITEM 6. EXHIBITS

Each exhibit identified below is filed as a part of this report. Exhibits designated with an "*" are filed as an exhibit to this Quarterly Report on Form 10-Q and Exhibits designated with an "**" are furnished as an exhibit to this Quarterly Report on Form 10-Q. Exhibits designated with an "+" are identified as management contracts or compensatory plans or arrangements.

2.1		Amendment dated as of March 27, 2017, to the Transaction Agreement and Plan of Merger, dated as of October 30, 2016, entered into among General Electric Company, Baker Hughes Incorporated, Bear Newco, Inc., Bear MergerSub, Inc., BHI Newco, Inc. and Bear MergerSub 2, Inc. (filed as Exhibit 2.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on March 31, 2017).
3.1		Certificate of Amendment dated April 22, 2010 and the Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2010).
3.2		Restated Bylaws of Baker Hughes Incorporated effective as of January 26, 2017 (filed as Exhibit 3.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 31, 2017).
4.1		Certificate of Amendment dated April 22, 2010 and the Restated Certificate of Incorporate (filed as Exhibit 3.1 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2010).
4.2		Restated Bylaws of Baker Hughes Incorporated effective as of January 26, 2017 (filed as Exhibit 3.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 31, 2017).
10.1 +		Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and Conditions for officers with a three-year cliff vest pursuant to the 2002 Director & Officer Long-Term Incentive Plan (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 31, 2017).
10.2 +		Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and Conditions for officers with a three-year graded vest pursuant to the 2002 Director & Officer Long-Term Incentive Plan (filed as Exhibit 10.2 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 31, 2017).
10.3 +		Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and Conditions for officers with a three-year performance-based vest pursuant to the 2002 Director & Officer Long-Term Incentive Plan (filed as Exhibit 10.3 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 31, 2017).
10.4 +		Performance Goals for Performance-Based Restricted Stock Unit Awards pursuant to the 2002 Director & Officer Long-Term Incentive Plan (filed as Exhibit 10.4 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 31, 2017).
31.1**		Certification of Martin S. Craighead, Chairman and Chief Executive Officer, furnished pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.
31.2**		Certification of Kimberly A. Ross, Chief Financial Officer, furnished pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.
32**		Statement of Martin S. Craighead, Chairman and Chief Executive Officer, and Kimberly A. Ross, Chief Financial Officer, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.
95*		Mine Safety Disclosure.
101.INS*		XBRL Instance Document
101.SCH*		XBRL Schema Document
101.CAL*		XBRL Calculation Linkbase Document
101.LAB*		XBRL Label Linkbase Document
101.PRE*		XBRL Presentation Linkbase Document
101.DEF*		XBRL Definition Linkbase Document

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		BAKER HUGHES INCORPORATED (Registrant)
Date:	April 28, 2017	By:	/s/ KIMBERLY A. ROSS
		Kimberly A. Ross
		Senior Vice President and Chief Financial Officer
Date:	April 28, 2017	By:	/s/ KELLY C. JANZEN
		Kelly C. Janzen
		Vice President, Controller and Chief Accounting Officer

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