10-Q
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549

FORM 10-Q
 
ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2016

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

For the transition period from _____to_____

Commission file number: 001-07964


NOBLE ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware
 
73-0785597
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. employer identification number)
1001 Noble Energy Way
 
 
Houston, Texas
 
77070
(Address of principal executive offices)
 
(Zip Code)
(281) 872-3100
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes ý    No o 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes ý    No o
 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller
reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company”
in Rule 12b-2 of the Exchange Act. 
Large accelerated filer x
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
 
 
(Do not check if a smaller reporting company)
 
 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o    No ý
 
As of March 31, 2016, there were 429,592,264 shares of the registrant’s common stock,
par value $0.01 per share, outstanding.




Table of Contents
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Part II. Other Information  
 
 
Item 1.  Legal Proceedings 
 
 
Item 1A.  Risk Factors 
 
 
 
 
 
 
 
 
 
 
Item 6.  Exhibits 
 
 
 
 


2

Table of Contents

Part I. Financial Information
Item 1. Financial Statements
Noble Energy, Inc.
Consolidated Statements of Operations
(millions, except per share amounts)
(unaudited)
 
Three Months Ended
March 31,
 
2016
 
2015
Revenues
 
 
 
Oil, Gas and NGL Sales
$
705

 
$
749

Income from Equity Method Investees
19

 
18

Total
724

 
767

Costs and Expenses
 
 
 
Production Expense
272

 
254

Exploration Expense
163

 
65

Depreciation, Depletion and Amortization
617

 
454

General and Administrative
91

 
94

Other Operating (Income) Expense, Net
3

 
34

Total
1,146

 
901

Operating Loss
(422
)
 
(134
)
Other (Income) Expense
 
 
 
Gain on Commodity Derivative Instruments
(44
)
 
(150
)
Interest, Net of Amount Capitalized
79

 
57

Other Non-Operating (Income) Expense, Net
(4
)
 
1

Total
31

 
(92
)
Loss Before Income Taxes
(453
)
 
(42
)
Income Tax Benefit
(166
)
 
(20
)
Net Loss
$
(287
)
 
$
(22
)
 
 
 
 
Loss Per Share, Basic
$
(0.67
)
 
$
(0.06
)
Loss Per Share, Diluted
$
(0.67
)
 
$
(0.06
)
 
 
 
 
Weighted Average Number of Shares Outstanding
 
 
 
   Basic
429

 
370

   Diluted
429

 
370


The accompanying notes are an integral part of these financial statements.

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Table of Contents

Noble Energy, Inc.
Consolidated Statements of Comprehensive Loss
(millions)
(unaudited)

 
 
Three Months Ended
March 31,
 
2016
 
2015
Net Loss
$
(287
)
 
$
(22
)
Other Items of Comprehensive Loss
 
 
 
Net Change in Mutual Fund Investment

 
(11
)
Less Tax Benefit

 
3

Net Change in Pension and Other

 
1

Other Comprehensive Loss

 
(7
)
Comprehensive Loss
$
(287
)
 
$
(29
)

The accompanying notes are an integral part of these financial statements.


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Table of Contents

Noble Energy, Inc.
Consolidated Balance Sheets
(millions)
(unaudited)

 
March 31,
2016
 
December 31,
2015
ASSETS
 
 
 
Current Assets
 
 
 
Cash and Cash Equivalents
$
953

 
$
1,028

Accounts Receivable, Net
531

 
450

Commodity Derivative Assets, Current
454

 
582

Other Current Assets
154

 
216

Total Current Assets
2,092

 
2,276

Property, Plant and Equipment
 

 
 

Oil and Gas Properties (Successful Efforts Method of Accounting)
31,209

 
31,220

Property, Plant and Equipment, Other
892

 
858

Total Property, Plant and Equipment, Gross
32,101

 
32,078

Accumulated Depreciation, Depletion and Amortization
(11,394
)
 
(10,778
)
Total Property, Plant and Equipment, Net
20,707

 
21,300

Other Noncurrent Assets
614

 
620

Total Assets
$
23,413

 
$
24,196

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current Liabilities
 

 
 

Accounts Payable - Trade
$
1,005

 
$
1,128

Other Current Liabilities
601

 
677

Total Current Liabilities
1,606

 
1,805

Long-Term Debt
7,882

 
7,976

Deferred Income Taxes, Noncurrent
2,640

 
2,826

Other Noncurrent Liabilities
1,233

 
1,219

Total Liabilities
13,361

 
13,826

Commitments and Contingencies

 


Shareholders’ Equity
 

 
 

Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized, None Issued

 

Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 471 Million and 470 Million Shares Issued, respectively
5

 
5

Additional Paid in Capital
6,378

 
6,360

Accumulated Other Comprehensive Loss
(33
)
 
(33
)
Treasury Stock, at Cost; 38 Million Shares
(696
)
 
(688
)
Retained Earnings
4,398

 
4,726

Total Shareholders’ Equity
10,052

 
10,370

Total Liabilities and Shareholders’ Equity
$
23,413

 
$
24,196


The accompanying notes are an integral part of these financial statements.


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Table of Contents

Noble Energy, Inc.
Consolidated Statements of Cash Flows
(millions)
(unaudited)
 
Three Months Ended
March 31,
 
2016
 
2015
Cash Flows From Operating Activities
 
 
 
Net Loss
$
(287
)
 
$
(22
)
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
 

 
 

Depreciation, Depletion and Amortization
617

 
454

Asset Impairments

 
27

Dry Hole Cost
93

 
20

Gain on Extinguishment of Debt
(80
)
 

Loss on Asset Due to Terminated Contract
42

 

Deferred Income Tax Benefit
(186
)
 
(30
)
Loss from Equity Method Investees, Net of Dividends
(3
)
 
(18
)
Gain on Commodity Derivative Instruments
(44
)
 
(150
)
Net Cash Received in Settlement of Commodity Derivative Instruments
178

 
210

Stock Based Compensation
20

 
21

Other Adjustments for Noncash Items Included in Income
37

 
11

Changes in Operating Assets and Liabilities


 
 

(Increase) Decrease in Accounts Receivable
(38
)
 
107

Decrease in Accounts Payable
(24
)
 
(71
)
(Decrease) Increase in Current Income Taxes Payable
(16
)
 
3

Other Current Assets and Liabilities, Net
(64
)
 
(51
)
Other Operating Assets and Liabilities, Net
6

 
30

Net Cash Provided by Operating Activities
251

 
541

Cash Flows From Investing Activities
 

 
 

Additions to Property, Plant and Equipment
(496
)
 
(1,111
)
Additions to Equity Method Investments
(6
)
 
(44
)
Proceeds from Divestitures and Other
238

 
119

Net Cash Used in Investing Activities
(264
)
 
(1,036
)
Cash Flows From Financing Activities
 

 
 

Dividends Paid, Common Stock
(41
)
 
(64
)
Proceeds from Issuance of Shares of Common Stock to Public, Net of Offering Costs

 
1,112

Proceeds from Term Loan Facility
1,400

 

Repayment of Senior Notes
(1,383
)
 

Repayment of Capital Lease Obligation
(13
)
 
(19
)
Other
(25
)
 
(8
)
Net Cash (Used in) Provided by Financing Activities
(62
)
 
1,021

(Decrease) Increase in Cash and Cash Equivalents
(75
)
 
526

Cash and Cash Equivalents at Beginning of Period
1,028

 
1,183

Cash and Cash Equivalents at End of Period
$
953

 
$
1,709

 The accompanying notes are an integral part of these financial statements.

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Table of Contents


Noble Energy, Inc.
Consolidated Statements of Shareholders' Equity
(millions)
(unaudited)

 
Common
Stock
 
Additional
Paid in
Capital
 
Accumulated Other
Comprehensive
Loss
 
Treasury
Stock at
Cost
 
Retained
Earnings
 
Total
Shareholders'
Equity
December 31, 2015
$
5

 
$
6,360

 
$
(33
)
 
$
(688
)
 
$
4,726

 
$
10,370

Net Loss

 

 

 

 
(287
)
 
(287
)
Stock-based Compensation

 
19

 

 

 

 
19

Dividends (10 cents per share)

 

 

 

 
(41
)
 
(41
)
Other

 
(1
)
 

 
(8
)
 

 
(9
)
March 31, 2016
$
5

 
$
6,378

 
$
(33
)
 
$
(696
)
 
$
4,398

 
$
10,052

 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2014
$
4

 
$
3,624

 
$
(90
)
 
$
(671
)
 
$
7,458

 
$
10,325

Net Loss

 

 

 

 
(22
)
 
(22
)
Stock-based Compensation

 
21

 

 

 

 
21

Dividends (18 cents per share)

 

 

 

 
(64
)
 
(64
)
Issuance of Shares of Common Stock to Public, Net of Offering Costs

 
1,112

 

 



 
1,112

Other

 
4

 
(7
)
 
(12
)
 

 
(15
)
March 31, 2015
$
4

 
$
4,761

 
$
(97
)
 
$
(683
)
 
$
7,372

 
$
11,357


The accompanying notes are an integral part of these financial statements.

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Table of Contents
Noble Energy, Inc.
Notes to Consolidated Financial Statements


Note 1.  Organization and Nature of Operations
Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our core operating areas are onshore US (DJ Basin, Marcellus Shale, Eagle Ford Shale, and Permian Basin), deepwater Gulf of Mexico, offshore Eastern Mediterranean and offshore West Africa.


Note 2.  Basis of Presentation
Presentation   The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US (US GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. The accompanying consolidated financial statements at March 31, 2016 and December 31, 2015 and for the three months ended March 31, 2016 and 2015 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and shareholders’ equity for such periods. Certain prior-period amounts have been reclassified to conform to the current-period presentation. Operating results for the three months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016.
These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2015.
Consolidation   Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries.  In addition, we use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence. All significant intercompany balances and transactions have been eliminated upon consolidation.
Estimates   The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.
Issuance of Phantom Units On February 1, 2016, we issued cash-settled awards to certain employees under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan in lieu of a portion of restricted stock and stock options. We issued approximately one million awards (phantom units; nomenclature used in accounting literature), a portion of which are subject to the achievement of specific performance goals. These phantom units, once vested, are settled in cash. The phantom units represent a hypothetical interest in the Company and are equivalent in value to the phantom unit value. The phantom unit value is the lesser of the fair market value of a share of common stock of the Company as of the vesting date or four times the fair market value of a share of common stock of the Company as of the grant date, which was $31.65. The Company recognizes the value of our cash-settled awards utilizing the liability method as defined under Accounting Standards Codification Topic 718, Compensation - Stock Compensation. The fair value of liability awards is remeasured at each reporting date, based on the fair market value of a share of common stock of the Company as of the reporting date, through the settlement date with the change in fair value recognized as compensation expense over that period. As of March 31, 2016, the fair value remeasurement had a de minimis impact on our consolidated statement of operations and balance sheet. See Note 7. Fair Value Measurements and Disclosures.
Recently Issued Accounting Standards In March 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-09 (ASU 2016-09): Compensation - Stock Compensation, to reduce complexity and enhance several aspects of accounting and disclosure for share-based payment transactions, including the accounting for income taxes, award forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The ASU will be effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. Certain aspects of this guidance will require retrospective application while other aspects are to be applied prospectively. We are currently evaluating the effect that the guidance will have on our consolidated financial statements and related disclosures.
In March 2016, the FASB issued Accounting Standards Update No. 2016-07 (ASU 2016-07): Investments - Equity Method and Joint Ventures, to eliminate retroactive application of equity method accounting when an investment becomes qualified for equity method accounting as a result of an increase in the level of ownership interest or degree of influence. The ASU will be effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. We are currently evaluating the effect, if any, that the guidance will have on our consolidated financial statements and related disclosures.

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Table of Contents
Noble Energy, Inc.
Notes to Consolidated Financial Statements

In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The guidance requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by leases with terms of more than 12 months. This ASU also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. While we are currently evaluating the provisions of this guidance to determine the effects it will have on our consolidated financial statements and related disclosures, we believe it is likely to have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities.
In July 2015, the FASB issued Accounting Standards Update No. 2015-11 (ASU 2015-11): Simplifying the Measurement of Inventory, effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We follow the average cost method and are currently evaluating the provisions of ASU 2015-11 and assessing the impact, if any, it may have on our financial position and results of operations.
In February 2015, the FASB issued Accounting Standards Update No. 2015-02 (ASU 2015-02): Consolidation - Amendments to the Consolidation Analysis, which changes the guidance as to whether an entity is a variable interest entity (VIE) or a voting interest entity and how related parties are considered in the VIE model. As of March 31, 2016, we have adopted the provisions of ASU 2015-02, which did not impact our consolidated financial statements.
In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers. In summary, the core principle of Topic 606 is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. The standard will be effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 to clarify principal versus agent considerations. We are continuing to evaluate the provisions of ASU 2014-09 and have not yet determined the full impact it may have on our financial position and results of operations. At a minimum, we expect we will be required to change from the entitlements method used for certain domestic natural gas sales to the sales method of accounting.

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Table of Contents
Noble Energy, Inc.
Notes to Consolidated Financial Statements

Statements of Operations Information   Other statements of operations information is as follows:
 
Three Months Ended
March 31,
(millions)
2016
 
2015
Production Expense
 
 
 
Lease Operating Expense
$
161

 
$
157

Production and Ad Valorem Taxes (1)
4

 
32

Transportation and Gathering Expense (2)
107

 
65

Total
$
272

 
$
254

Other Operating (Income) Expense, Net
 
 
 
Loss on Asset Due to Terminated Contract (3)
$
42

 
$

Marketing and Processing Expense, Net (4)
22

 
6

Asset Impairments (5)

 
27

Gain on Extinguishment of Debt (6)
(80
)
 

Other, Net
19

 
1

Total
$
3

 
$
34

Other Non-Operating (Income) Expense, Net
 
 
 
Deferred Compensation Expense (7)

 
$
2

Other (Income) Expense, Net
(4
)
 
(1
)
Total
$
(4
)
 
$
1


(1) 
The reduction in production and ad valorem taxes is primarily due to the accrual of a $28 million onshore US severance tax receivable during first quarter 2016.
(2) 
Certain of our revenue received from purchasers was historically presented with deductions for transportation, gathering, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense and prior year amounts have been reclassified to conform to the current presentation.
(3) 
Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. See Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold and Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Exploration Program Update.
(4) 
In 2016, amount includes $16 million of expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.
(5) 
Impairments during 2015 were related to facility costs at South Raton (Deepwater Gulf of Mexico) and increases in expected field abandonment cost for the Noa and Pinnacles fields (Eastern Mediterranean).
(6) 
Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 6. Debt.
(7) 
Amounts represent decreases in the fair value of shares of our common stock held in a rabbi trust.


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Table of Contents
Noble Energy, Inc.
Notes to Consolidated Financial Statements

Balance Sheet Information   Other balance sheet information is as follows:
(millions)
March 31,
2016
 
December 31,
2015
Accounts Receivable, Net
 
 
 
Commodity Sales
$
308

 
$
298

Joint Interest Billings
51

 
20

Proceeds Receivable (1)
40

 

Severance Tax Refund (2)
28

 

Other
128

 
151

Allowance for Doubtful Accounts
(24
)
 
(19
)
Total
$
531

 
$
450

Other Current Assets
 

 
 

Inventories, Materials and Supplies
$
90

 
$
92

Inventories, Crude Oil
27

 
23

Assets Held for Sale (3)

 
67

Prepaid Expenses and Other Current Assets
37

 
34

Total
$
154

 
$
216

Other Noncurrent Assets
 

 
 

Investments in Unconsolidated Subsidiaries
$
461

 
$
453

Mutual Fund Investments
77

 
90

Commodity Derivative Assets
6

 
10

Other Assets
70

 
67

Total
$
614

 
$
620

Other Current Liabilities
 

 
 

Production and Ad Valorem Taxes
$
162

 
$
166

Income Taxes Payable
71

 
86

Asset Retirement Obligations
128

 
128

Interest Payable
94

 
83

Current Portion of Capital Lease Obligations
54

 
53

Other
92

 
161

Total
$
601

 
$
677

Other Noncurrent Liabilities
 

 
 

Deferred Compensation Liabilities
$
214

 
$
217

Asset Retirement Obligations
872

 
861

Production and Ad Valorem Taxes
76

 
68

Other
71

 
73

Total
$
1,233

 
$
1,219

(1) Amount relates to proceeds to be received from our farm-out of 35% interest in Block 12 offshore Cyprus. See Note 4. Divestitures.
(2) Amount relates to the accrual of a $28 million onshore US severance tax receivable.
(3) Assets held for sale at December 31, 2015 included our Karish and Tanin natural gas discoveries, offshore Israel. The sale closed first quarter 2016. See Note 4. Divestitures.

Note 3. Rosetta Merger

On July 20, 2015, Noble Energy completed the merger of Rosetta Resources Inc. (Rosetta) into a subsidiary of Noble Energy (Rosetta Merger). The results of Rosetta's operations since the merger date are included in our consolidated statements of operations. The merger was effected through the issuance of approximately 41 million shares of Noble Energy common stock in exchange for all outstanding shares of Rosetta common stock using a ratio of 0.542 of a share of Noble Energy common stock for each share of Rosetta common stock and the assumption of Rosetta's liabilities, including approximately $2 billion fair value of outstanding debt. The merger added two new onshore US shale positions to our portfolio including approximately 50,000 net acres in the Eagle Ford Shale and 54,000 net acres in the Permian Basin (45,000 acres in the Delaware Basin and 9,000 acres in the Midland Basin). In connection with the Rosetta Merger, we incurred merger-related costs in 2015 of approximately $81 million, including (i) $66 million of severance, consulting, investment, advisory, legal and other merger-related fees, and (ii) $15 million of noncash share-based compensation expense, all of which were expensed and were included in Other Operating (Income) Expense, Net.

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Noble Energy, Inc.
Notes to Consolidated Financial Statements

Allocation of Purchase Price The merger has been accounted for as a business combination, using the acquisition method. The following table represents the preliminary allocation of the total purchase price of Rosetta to the assets acquired and the liabilities assumed based on the fair value at the merger date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, valuation of pre-merger contingencies, final assessment of deferred taxes based upon the underlying tax basis of Rosetta's assets and liabilities, and final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the merger date, in line with the acquisition method of accounting, during which time the value of the assets and liabilities may be revised as appropriate.
The following table sets forth our preliminary purchase price allocation which was based on fair values of assets acquired and liabilities assumed at the merger date, July 20, 2015, with the excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill:
 
(in millions, except stock price)
Shares of Noble Energy common stock issued to Rosetta shareholders
41

Noble Energy common stock price on July 20, 2015
$
36.97

Fair value of common stock issued
$
1,518

Plus: fair value of Rosetta's restricted stock awards and performance awards assumed
10

Plus: Rosetta stock options assumed
1

Total purchase price
1,529

Plus: liabilities assumed by Noble Energy
 
Accounts Payable
100

Current Liabilities
37

Long Term Deferred Tax Liability
8

Long-Term Debt
1,992

Other Long Term Liabilities
23

Asset Retirement Obligation
27

Total purchase price plus liabilities assumed
$
3,716

 
 
Fair Value of Rosetta Assets
 
Cash and Equivalents
$
61

Other Current Assets
76

Derivative Instruments
209

Oil and Gas Properties
 
Proved Reserves
1,613

Undeveloped Leaseholds
1,355

Gathering & Processing Assets
207

Asset Retirement Obligation
27

Other Property Plant and Equipment
5

Goodwill
163

Total Asset Value
$
3,716

The fair value measurements of derivative instruments assumed were determined based on published forward commodity price curves as of the date of the merger and represent Level 2 inputs. Derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. The fair value measurements of long-term debt were estimated based on published market prices and represent Level 1 inputs.
The fair value measurements of crude oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change.
The results of operations attributable to Rosetta are included in our consolidated statements of operations beginning on July 21, 2015. Revenues of $87 million and pre-tax net loss of $31 million from Rosetta were generated during first quarter 2016.

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Table of Contents
Noble Energy, Inc.
Notes to Consolidated Financial Statements

Proforma Financial Information The following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Rosetta and gives effect to the merger as if it had occurred on January 1, 2015. The below information reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) adjustments to conform Rosetta's historical policy of accounting for its crude oil and natural gas properties from the full cost method to the successful efforts method of accounting, (ii) depletion of Rosetta's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments. The pro forma results of operations do not include any cost savings or other synergies that may result from the Rosetta Merger or any estimated costs that have been or will be incurred by us to integrate the Rosetta assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Rosetta Merger taken place on January 1, 2015; furthermore, the financial information is not intended to be a projection of future results.
 
Three Months Ended
March 31,
(in millions, except per share amounts)
2016 (1)
2015
Revenues
$
724

$
894

Net Loss
$
(287
)
$
(27
)
 
 
 
Loss per share
 
 
Basic
$
(0.67
)
$
(0.07
)
Diluted
$
(0.67
)
$
(0.07
)
(1) 
No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.

Note 4. Divestitures
Offshore Israel Assets In November 2015, we executed an agreement to divest our 47% interest in the Alon A and Alon C offshore Israel licenses, which include the Karish and Tanin fields, for a total transaction value of $73 million. These assets were held for sale as of December 31, 2015, and the transaction closed in January 2016.
Cyprus Project (Offshore Cyprus) During fourth quarter 2015, we entered into a farm-out agreement with a partner for a 35% interest in Block 12, which includes the Aphrodite natural gas discovery, for $171 million. In first quarter 2016, we received proceeds of $131 million related to the farm-out agreement and expect to receive the remaining consideration of $40 million, subject to post-close adjustments, in 2017. The proceeds were applied to the Cyprus project asset with no gain or loss recognized.
Onshore US Properties During first quarter 2016, we sold certain onshore US crude oil and natural gas properties, generating net proceeds of $20 million. Proceeds were primarily applied to the DJ Basin depletable field, with no recognition of gain or loss.
During first quarter 2015, we sold certain onshore US crude oil and natural gas properties, generating net proceeds of $119 million. Proceeds were primarily applied to the DJ Basin depletable field, with no recognition of gain or loss.
Subsequent Event On May 2, 2016, we entered into a purchase and sale agreement for the divestiture of certain producing and undeveloped crude oil and natural gas interests in approximately 33,100 net acres in Weld County, Colorado for $505 million, subject to customary closing adjustments.  The divestiture is expected to close during 2016, with an effective date of April 1, 2016; however, there can be no assurance that the transaction contemplated by the agreement will be consummated.

Note 5.  Derivative Instruments and Hedging Activities
Objective and Strategies for Using Derivative Instruments   We are exposed to fluctuations in crude oil and natural gas prices. In order to mitigate the effect of commodity price volatility and enhance the predictability of cash flows relating to the marketing of our global crude oil and domestic natural gas, we enter into crude oil and natural gas price hedging arrangements.
While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices. See Note 7. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments.

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Table of Contents
Noble Energy, Inc.
Notes to Consolidated Financial Statements

Unsettled Commodity Derivative Instruments   As of March 31, 2016, the following crude oil derivative contracts were outstanding:
 
 
 
 
Swaps
 
Collars
Settlement
Period
Type of Contract
Index
Bbls Per
Day
Weighted
Average
Fixed
Price
 
Weighted
Average
 Short Put
 Price
Weighted
Average
Floor
Price
Weighted
Average
 Ceiling
Price
2Q16 (1)
Swaps
NYMEX WTI
5,000

$
54.16

 
$

$

$

2H16 (1)
Call Option (2)
NYMEX WTI
5,000


 


54.16

2H16 (1)
Swaps
NYMEX WTI
4,000

47.34

 



2H16 (1)
Two-Way Collars
NYMEX WTI
6,000


 

35.00

49.82

2016
Swaps
NYMEX WTI
12,000

74.47

 



2016
    Swaps (3)
(4) 
6,000

90.28





2016
Two-Way Collars
NYMEX WTI
1,000


 

60.00

70.00

2016
Three-Way Collars
NYMEX WTI
6,000


 
61.00

72.50

86.37

2016
Swaps
Dated Brent
9,000

97.96

 



2016
Three-Way Collars
Dated Brent
8,000


 
72.50

86.25

101.79

1H17 (1)
Swaps
NYMEX WTI
3,000
60.12

 



1H17 (1)
Two-Way Collars
NYMEX WTI
2,000

 

40.00

50.44

1H17 (1)
Swaps
Dated Brent
3,000
62.80

 



2H17 (1)
Call Option (2)
NYMEX WTI
3,000

 


60.12

2H17 (1)
Swaptions (5)
Dated Brent
3,000

 


62.80

2017
Two-Way Collars
NYMEX WTI
7,000

 

40.00

53.29

2017
Call Option (2)
 NYMEX WTI
3,000

 


57.00

2017
Swaptions (5)
NYMEX WTI
4,000


 


47.34

(1) 
We have entered into NYMEX WTI swap contracts for portions of 2016 and 2017 resulting in the difference in hedge volumes for the full year.
(2) 
We have entered into crude oil derivative enhanced swaps with strike prices that are above the market value as of trade commencement. To effect the enhanced swap structure, we sold call options to the applicable counterparty to receive the above market terms.
(3) 
Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger.
(4) 
The index for these derivative instruments is NYMEX WTI and Argus LLS indices.
(5) 
We have entered into certain derivative contracts (swaptions), which give counterparties the option to extend for an additional 6-month or 12-month period. Options covering a notional volume of 3,000 Bbls/d are exercisable on June 30, 2017. If the counterparties exercise all such options, the notional volume of our existing Dated Brent derivative contracts will increase by 3,000 Bbls/d at a weighted average price of $62.80 per Bbl for each month during the period July 1, 2017 through December 31, 2017. Options covering a notional volume of 4,000 Bbls/d are exercisable on December 30, 2016. If the counterparties exercise all such options, the notional volume of our existing NYMEX WTI derivative contracts will increase by 4,000 Bbls/d at a weighted average price of $47.34 per Bbl for each month during the period July 1, 2017 through December 31, 2017.


14

Table of Contents
Noble Energy, Inc.
Notes to Consolidated Financial Statements

As of March 31, 2016, the following natural gas derivative contracts were outstanding:
 
 
 
 
Swaps
 
Collars
Settlement
Period
Type of Contract
Index
MMBtu
Per Day
Weighted
Average
Fixed
Price
 
Weighted
Average
Short Put
 Price
Weighted
Average
Floor
Price
Weighted
Average
Ceiling
Price
2H16
Swaps
NYMEX HH
30,000

$
2.77

 
$

$

$

2016
Swaps
NYMEX HH
40,000

3.60

 



2016
Two-Way Collars
NYMEX HH
30,000


 

3.00

3.50

2016
Three-Way Collars
NYMEX HH
90,000


 
2.83

3.42

3.90

2016
Swaps (1)
(2) 
30,000

4.04

 



2016
Two-Way Collars (1)
(2) 
30,000


 

3.50

5.60

2017
Swaptions (3)
NYMEX HH
60,000

 


3.14

(1) 
Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger.
(2) 
The index for these derivative instruments includes a combination of Houston Ship Channel and Tennessee Zone 0 indices.
(3) 
We have entered into certain natural gas derivative contracts (swaptions), which give counterparties the option to extend for an additional 12-month period. Options covering a notional volume of 60,000 MMBtu/d are exercisable on December 22 and 23, 2016. If the counterparties exercise all such options, the notional volume of our existing natural gas derivative contracts will increase by 60,000 MMBtu/d at a weighted average price of $3.14 per MMBtu for each month during the period January 1, 2017 through December 31, 2017.
Fair Value Amounts and (Gain) Loss on Commodity Derivative Instruments   The fair values of commodity derivative instruments in our consolidated balance sheets were as follows:
Fair Value of Derivative Instruments
 
Asset Derivative Instruments
 
Liability Derivative Instruments
 
March 31,
2016
 
December 31,
2015
 
March 31,
2016
 
December 31,
2015
(millions)
Balance Sheet Location
 
Fair
Value
 
Balance Sheet Location
 
Fair
 Value
 
Balance Sheet Location
 
Fair
Value
 
Balance Sheet Location
 
Fair
Value
Commodity Derivative Instruments
Current Assets
 
$
454

 
Current Assets
 
$
582

 
Current Liabilities
 
$
2

 
Current Liabilities
 
$

 
Noncurrent Assets
 
6

 
Noncurrent Assets
 
10

 
Noncurrent Liabilities
 
1

 
Noncurrent Liabilities
 

Total
 
 
$
460

 
 
 
$
592

 
 
 
$
3

 
 
 
$



15

Table of Contents
Noble Energy, Inc.
Notes to Consolidated Financial Statements

The effect of commodity derivative instruments on our consolidated statements of operations was as follows:
 
Three Months Ended
March 31,
(millions)
2016
 
2015
Cash Received in Settlement of Commodity Derivative Instruments
 
 
 
  Crude Oil
$
(156
)
 
$
(185
)
  Natural Gas
(22
)
 
(25
)
Total Cash Received in Settlement of Commodity Derivative Instruments
(178
)
 
(210
)
Non-cash Portion of Loss on Commodity Derivative Instruments
 
 
 
   Crude Oil
127

 
55

   Natural Gas
7

 
5

Total Non-cash Portion of Loss on Commodity Derivative Instruments
134

 
60

Gain on Commodity Derivative Instruments
 
 
 
   Crude Oil
(29
)
 
(130
)
   Natural Gas
(15
)
 
(20
)
Total Gain on Commodity Derivative Instruments
$
(44
)
 
$
(150
)
Note 6. Debt
Debt consists of the following:
 
March 31,
2016
 
December 31,
2015
(millions, except percentages)
Debt
 
Interest Rate
 
Debt
 
Interest Rate
Revolving Credit Facility, due August 27, 2020
$

 
%
 
$

 
%
Capital Lease and Other Obligations
390

 
%
 
403

 
%
Term Loan Facility, due January 6, 2019
1,400

 
1.69
%
 

 
%
8.25% Senior Notes, due March 1, 2019
1,000

 
8.25
%
 
1,000

 
8.25
%
5.625% Senior Notes, due May 1, 2021
379

 
5.625
%
 
693

 
5.63
%
4.15% Senior Notes, due December 15, 2021
1,000

 
4.15
%
 
1,000

 
4.15
%
5.875% Senior Notes, due June 1, 2022
18

 
5.875
%
 
597

 
5.88
%
7.25% Senior Notes, due October 15, 2023
100

 
7.25
%
 
100

 
7.25
%
5.875% Senior Notes, due June 1, 2024
8

 
5.875
%
 
499

 
5.88
%
3.90% Senior Notes, due November 15, 2024
650

 
3.90
%
 
650

 
3.90
%
8.00% Senior Notes, due April 1, 2027
250

 
8.00
%
 
250

 
8.00
%
6.00% Senior Notes, due March 1, 2041
850

 
6.00
%
 
850

 
6.00
%
5.25% Senior Notes, due November 15, 2043
1,000

 
5.25
%
 
1,000

 
5.25
%
5.05% Senior Notes, due November 15, 2044
850

 
5.05
%
 
850

 
5.05
%
7.25% Senior Debentures, due August 1, 2097
84

 
7.25
%
 
84

 
7.25
%
Total
7,979

 
 
 
7,976

 
 

Unamortized Discount
(24
)
 
 

 
(24
)
 
 

Unamortized Premium
19

 
 
 
113

 
 
Unamortized Debt Issuance Costs
(38
)
 
 
 
(36
)
 
 
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs
7,936

 
 

 
8,029

 
 

Less Amounts Due Within One Year
 

 
 

 
 

 
 

Capital Lease Obligations
(54
)
 
 

 
(53
)
 
 

Long-Term Debt Due After One Year
$
7,882

 
 

 
$
7,976

 
 

Revolving Credit Facility Our Credit Agreement, as amended, provides for a $4.0 billion unsecured revolving credit facility (Revolving Credit Facility), which is available for general corporate purposes. The Revolving Credit Facility (i) provides for facility fee rates that range from 10 basis points to 25 basis points per year depending upon our credit rating, (ii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 90 basis points to 150 basis points depending upon our credit rating, and (iii) includes a sub-limit for letters of credit up to an aggregate amount of $500 million ($450 million of which is committed as of March 31, 2016).

16

Table of Contents
Noble Energy, Inc.
Notes to Consolidated Financial Statements

Term Loan Agreement and Completed Tender Offers On January 6, 2016, we entered into a term loan agreement (Term Loan Facility) with Citibank, N.A., as administrative agent, Mizuho Bank, Ltd., as syndication agent, and certain other financial institutions party thereto, which provides for a three-year term loan facility for a principal amount of $1.4 billion. Provisions of the Term Loan Facility are consistent with those in the Revolving Credit Facility. Borrowings under the Term Loan Facility may be prepaid prior to maturity without premium. The Term Loan Facility will accrue interest, at our option, at either (a) a base rate equal to the highest of (i) the rate announced by Citibank, N.A., as its prime rate, (ii) the Federal Funds Rate plus 0.5%, and (iii) a London interbank offered rate plus 1.0%, plus a margin that ranges from 10 basis points to 75 basis points depending upon our credit rating, or (b) a London interbank offered rate, plus a margin that ranges from 100 basis points to 175 basis points depending upon our credit rating. The interest rate for our Term Loan Facility is 1.69% as of March 31, 2016.
In connection with the Term Loan Facility, we launched cash tender offers for the 5.875% Senior Notes due June 1, 2024, 5.875% Senior Notes due June 1, 2022 and 5.625% Senior Notes due May 1, 2021, all of which were assumed in the Rosetta Merger. The borrowings under the Term Loan Facility were used solely to fund the tender offers. Approximately $1.38 billion of notes were validly tendered and accepted by us, with a corresponding amount borrowed under the new Term Loan Facility. As a result, we recognized a gain of $80 million which is reflected in other operating (income) expense, net in our consolidated statements of operations.
See Note 7. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.

Note 7.  Fair Value Measurements and Disclosures  
Assets and Liabilities Measured at Fair Value on a Recurring Basis 
Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values: 
Cash, Cash Equivalents, Accounts Receivable and Accounts Payable   The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. 
Mutual Fund Investments   Our mutual fund investments consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. The fair values are based on quoted market prices for identical assets.
Commodity Derivative Instruments   Our commodity derivative instruments may include variable to fixed price commodity swaps, two-way collars, three-way collars, swaptions and enhanced swaps. We estimate the fair values of these instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold and the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 5. Derivative Instruments and Hedging Activities
Deferred Compensation Liability   The value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust. See Mutual Fund Investments above. 
Phantom Units The fair value of phantom unit awards is measured based on the fair market value of our common stock on the date of grant. We recognize the value of these awards utilizing the liability method whereby these liability awards are remeasured at each reporting date, based on the fair market value of a share of common stock of the Company as of the reporting date, through the settlement date with the change in fair value recognized as compensation expense over that period. See Note 2. Basis of Presentation.

17

Table of Contents
Noble Energy, Inc.
Notes to Consolidated Financial Statements

Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows: 
 
Fair Value Measurements Using
 
 
 
 
 
Quoted Prices in 
Active Markets
(Level 1) (1)
 
Significant Other
Observable Inputs
(Level 2) (2)
 
Significant
Unobservable
Inputs (Level 3) (3)
 
Adjustment (4)
 
Fair Value Measurement
(millions)
 
 
 
 
 
 
 
 
 
March 31, 2016
 
 
 
 
 
 
 
 
 
Financial Assets
 
 
 
 
 
 
 
 
 
Mutual Fund Investments
$
77

 
$

 
$

 
$

 
$
77

Commodity Derivative Instruments

 
472

 

 
(12
)
 
460

Financial Liabilities
 

 
 

 
 

 
 

 
 

Commodity Derivative Instruments

 
(15
)
 

 
12

 
(3
)
Portion of Deferred Compensation Liability Measured at Fair Value
(96
)
 

 

 

 
(96
)
Portion of Stock Based Compensation Liability Measured at Fair Value
(1
)
 

 

 

 
(1
)
December 31, 2015
 
 
 
 
 
 
 

 
 

Financial Assets
 

 
 

 
 

 
 

 
 

Mutual Fund Investments
$
90

 
$

 
$

 
$

 
$
90

Commodity Derivative Instruments

 
600

 

 
(8
)
 
592

Financial Liabilities
 

 
 

 
 

 
 

 
 

Commodity Derivative Instruments

 
(8
)
 

 
8

 

Portion of Deferred Compensation Liability Measured at Fair Value
(98
)
 

 

 

 
(98
)
 
(1) 
Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value.
(2) 
Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.
(3) 
Level 3 measurements are fair value measurements which use unobservable inputs.
(4) 
Amount represents the impact of netting provisions within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are measured at fair value on a nonrecurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:
Asset Impairments Information about impaired assets is as follows:
 
Fair Value Measurements Using
 
 
 
 
 
Quoted Prices in 
Active Markets
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant
Unobservable
Inputs (Level 3)
 
Net Book Value (1)
 
Total Pre-tax (Non-cash) Impairment Loss
(millions)
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2016
 
 
 
 
 
 
 
 
Impaired Oil and Gas Properties
$

 
$

 
$

 
$

 
$

Three Months Ended March 31, 2015
 
 
 
 
 
 
 
 
Impaired Oil and Gas Properties

 

 

 
27

 
27

(1) Amount represents net book value at the date of assessment.

18

Table of Contents
Noble Energy, Inc.
Notes to Consolidated Financial Statements

The fair value of impaired crude oil and natural gas properties was determined as of the date of the assessment using a discounted cash flow model based on management’s expectations of future production prior to abandonment date, commodity prices based on NYMEX WTI, NYMEX Henry Hub, and Brent futures price curves as of the date of the estimate, estimated operating and abandonment costs, and a risk-adjusted discount rate. First quarter 2015 impairments were due primarily to increases in asset carrying values associated with increases in estimated abandonment costs.
Additional Fair Value Disclosures
Debt   The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public, fixed-rate debt to be a Level 1 measurement on the fair value hierarchy.
Our Term Loan Facility is variable-rate, non-public debt. The fair value is estimated based on significant other observable inputs. As such, we consider the fair value of our Term Loan Facility to be a Level 2 measurement on the fair value hierarchy. See Note 6. Debt.
Fair value information regarding our debt is as follows:
 
March 31,
2016
 
December 31,
2015
(millions)
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Long-Term Debt, Net (1)
$
7,546

 
$
7,334

 
$
7,626

 
$
7,105

(1) 
Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations.
Note 8.  Capitalized Exploratory Well Costs and Undeveloped Leasehold
Capitalized Exploratory Well Costs We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. On a quarterly basis, we review the status of suspended exploratory well costs and assess the development of these projects. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost.
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period:
(millions)
Three Months Ended March 31, 2016
Capitalized Exploratory Well Costs, Beginning of Period
$
1,353

Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves
22

Divestitures (1)
(143
)
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves
(2
)
Capitalized Exploratory Well Costs Charged to Expense (2)
(56
)
Capitalized Exploratory Well Costs, End of Period
$
1,174

(1) Represents our farm-out of a 35% interest in Block 12 offshore Cyprus to a new partner.
(2) Includes $42 million relating to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance.

The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced, and the number of projects that have been capitalized for a period greater than one year: 
(millions)
March 31,
2016
 
December 31,
2015
Exploratory Well Costs Capitalized for a Period of One Year or Less
$
63

 
$
95

Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling
1,111

 
1,258

Balance at End of Period
$
1,174

 
$
1,353

Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling
14

 
14

 

19

Table of Contents
Noble Energy, Inc.
Notes to Consolidated Financial Statements

The following table includes exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of March 31, 2016:
 
 
 
 
(millions)
Total by Project
 
Progress
Country/Project:
 
 
 
Deepwater Gulf of Mexico
 
 
 
Troubadour
49

 
Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure.
Katmai
93

 
Commenced drilling of an appraisal well in April 2016 to test the resource potential of this 2014 crude oil discovery.
Offshore Equatorial Guinea (Blocks I and O)
 

 
 
Diega (Block I) and Carmen (Block O)
235

 
Evaluating regional development scenarios for this 2008 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks I and O and are interpreting and evaluating the acquired seismic data.

Carla (Block O)
180

 
Evaluating regional development scenarios for this 2011 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks I and O and are interpreting and evaluating the acquired seismic data.
Yolanda/Felicita
66

 
Evaluating regional development plans for these 2007/2008 condensate and natural gas discoveries. Natural gas development teams are working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options and finalize data exchange agreements between the two countries.
Offshore Cameroon
 

 
 
YoYo
52

 
Working with the government to assess commercialization of this 2007 condensate and natural gas discovery. A natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options and finalize a data exchange agreement between the two countries. Our 50% working interest partner has given notice to us and the Cameroon government of their intention to exit this acreage position. Once the assignment process is finalized, we will hold 100% operating working interest. We have begun efforts to market this additional working interest.
Offshore Israel
 

 
 
Leviathan
194

 
We are engaged in natural gas marketing activities for both export and domestic Israeli customers. We have submitted a Plan of Development to the Government of Israel and continue to pursue financing arrangements to support development. The Natural Gas Framework was enacted in 2015 and subsequently affirmed by the Israeli Supreme Court, with the exception of the stability provisions. The Court concluded that the Government of Israel should provide stability assurances and provisions through an alternate legal mechanism and provided the Government up to one year to resolve this matter. In first quarter 2016, Israel's National Planning Commission approved the platform location and gas interconnect.
Leviathan-1 Deep
82

 
Well did not reach the target interval; developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases. We are working on potential well design and placement. See also Leviathan, above, for discussion of Natural Gas Framework.

20

Table of Contents
Noble Energy, Inc.
Notes to Consolidated Financial Statements

Dalit
28

 
Submitted a development plan to the government to develop this 2009 natural gas discovery as a tie-in to existing infrastructure.
Dolphin 1
26

 
Reviewing regional development scenarios for this 2011 natural gas discovery, including a potential tieback to Leviathan. We have applied to the government for a commerciality ruling and our license has been extended to second quarter 2016.
Offshore Cyprus
 
 
 
Cyprus
84

 
We continue to work with the Government of Cyprus to obtain approval of the development plan and the subsequent issuance of an Exploitation License. Receiving an Exploitation License will enable us and our partners to perform the necessary engineering and design studies and progress the project to final investment decision. During fourth quarter 2015, we farmed-out a 35% working interest.
Other
 

 
 
Individual Projects Less than $20 million
22

 
Continuing to assess and evaluate wells.
Total
$
1,111

 
 
Undeveloped Leasehold Costs As of March 31, 2016, we had capitalized undeveloped leasehold costs of $2.3 billion, of which approximately $2 billion relates to our core operating areas onshore US and is included in our quarterly impairment testing for these areas. In addition, we have capitalized undeveloped leasehold of $57 million relating to international operations,and $255 million relating to deepwater Gulf of Mexico.
Significant undeveloped leases, primarily in deepwater Gulf of Mexico, are individually assessed for impairment. While none of our undeveloped leases were impaired as of March 31, 2016, if, based upon a change in exploration plans, availability of capital and suitable rig and drilling equipment, resource potential, changing regulations and/or other factors, an impairment is indicated, a valuation allowance will be provided. Costs of individually insignificant leases are combined and amortized over their lease term. Expense associated with either impairment or amortization of undeveloped leases is included in exploration expense in our consolidated statement of operations.

Note 9.  Asset Retirement Obligations
Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows:
 
Three Months Ended
March 31,
(millions)
2016
 
2015
Asset Retirement Obligations, Beginning Balance
$
989

 
$
751

Liabilities Incurred
2

 
10

Liabilities Settled
(8
)
 
(8
)
Revision of Estimate
5

 
24

Accretion Expense (1)
12

 
10

Asset Retirement Obligations, Ending Balance
$
1,000

 
$
787

(1) Accretion expense is included in DD&A expense in the consolidated statements of operations.
For the three months ended March 31, 2016 Liabilities incurred were due to new wells and facilities for onshore US. Liabilities settled primarily related to onshore US property abandonments.
Revisions of estimates relate to changes in cost estimates of $5 million for Equatorial Guinea.
For the three months ended March 31, 2015 Liabilities incurred were due to new wells and facilities and included $4 million for onshore US and $6 million for deepwater Gulf of Mexico. Liabilities settled in 2015 relate primarily to non-core US properties classified as held for sale.
Revisions in estimate for 2015 relate to changes in cost estimates for Eastern Mediterranean.

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Noble Energy, Inc.
Notes to Consolidated Financial Statements

Note 10.  Loss Per Share
Basic loss per share of common stock is computed using the weighted average number of shares of common stock outstanding during each period. The following table summarizes the calculation of basic and diluted loss per share:
 
Three Months Ended
March 31,
(millions, except per share amounts)
2016
 
2015
Net Loss
$
(287
)
 
$
(22
)
 
 
 
 
Weighted Average Number of Shares Outstanding, Basic (1)
429

 
370

Weighted Average Number of Shares Outstanding, Diluted(2)
429

 
370

Loss Per Share, Basic
$
(0.67
)
 
$
(0.06
)
Loss Per Share, Diluted
(0.67
)
 
(0.06
)
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above
15

 
9

(1) 
The weighted average number of shares outstanding includes the weighted average shares of common stock issued in connection with the underwritten public offering of 24.15 million shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately 41 million shares for all outstanding shares of Rosetta common stock on July 20, 2015.
(2) 
For the three months ended March 31, 2016 and March 31, 2015, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted loss per share as Noble Energy incurred a net loss. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted loss per share would be anti-dilutive.


Note 11.  Income Taxes
The income tax benefit consists of the following:
 
Three Months Ended
March 31,
(millions)
2016
 
2015
Current
$
20

 
$
10

Deferred
(186
)
 
(30
)
Total Income Tax Benefit
$
(166
)
 
$
(20
)
Effective Tax Rate
36.6
%
 
47.6
%

Accumulated Undistributed Earnings of Foreign Subsidiaries As of December 31, 2015, we no longer consider our foreign subsidiaries’ undistributed earnings to be indefinitely reinvested outside the United States and, accordingly, recorded additional deferred income taxes, net of estimated foreign tax credits.
Effective Tax Rate (ETR) Our ETR decreased first quarter 2016 as compared with first quarter 2015. This is primarily due to a higher income tax benefit as compared with the change in the components of the overall net loss from period to period, which is impacted by certain income items with different tax rates.
Also, during first quarter 2016, the change in our permanent reinvestment assumption, noted above, resulted in additional deferred income tax expense (net of estimated foreign tax credits) being recorded on certain income items, including income from equity method investees and increased earnings in our foreign jurisdictions with rates that vary from the US statutory rate. This additional deferred income tax expense had the result of offsetting our income tax benefit to a greater extent in first quarter 2016 thereby driving the ETR lower than it would have been if additional deferred taxes had not been recorded.
In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2012, Equatorial Guinea – 2010 and Israel – 2011.

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Noble Energy, Inc.
Notes to Consolidated Financial Statements

Note 12.  Segment Information  
We have operations throughout the world and manage our global operations by country. The following information is grouped into four components that are all in the business of crude oil and natural gas exploration, development, production, and acquisition: the United States; West Africa (Equatorial Guinea, Cameroon, Gabon and Sierra Leone (which we exited in second quarter 2015); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes the North Sea, Falkland Islands, Suriname, Nicaragua (which we exited in first quarter 2015) and new ventures.
(millions)
Consolidated
 
United
States
 
West
Africa
 
Eastern
Mediterranean
 
Other Int'l &
Corporate
Three Months Ended March 31, 2016
 
 
 
 
 
 
 
 
 
Revenues from Third Parties
$
705

 
$
489

 
$
90

 
$
126

 
$

Income from Equity Method Investees
19

 
16

 
3

 

 

Total Revenues
724

 
505

 
93

 
126

 

DD&A
617

 
530

 
55

 
20

 
12

Gain on Commodity Derivative Instruments
(44
)
 
(37
)
 
(7
)
 

 

Income (Loss) Before Income Taxes
(453
)
 
(292
)
 
9

 
84

 
(254
)
Three Months Ended March 31, 2015
 

 
 

 
 

 
 

 
 

Revenues from Third Parties
$
749

 
$
487

 
$
138

 
$
120

 
$
4

Income from Equity Method Investees
18

 
11

 
7

 

 

Total Revenues
767

 
498

 
145

 
120

 
4

DD&A
454

 
357

 
77

 
15

 
5

Asset Impairments
27

 
3

 

 
24

 

Gain on Commodity Derivative Instruments
(150
)
 
(105
)
 
(45
)
 

 

Income (Loss) Before Income Taxes
(42
)
 
(1
)
 
74

 
51

 
(166
)
March 31, 2016
 

 
 

 
 

 
 

 
 

Total Assets
$
23,413

 
$
18,387

 
$
2,233

 
$
2,459

 
$
334

December 31, 2015
 

 
 

 
 

 
 

 
 

Total Assets
24,196

 
18,831

 
2,299

 
2,677

 
389



Note 13.  Commitments and Contingencies  
CONSOL Carried Cost Obligation In accordance with our Marcellus Shale joint venture arrangement with a subsidiary of CONSOL Energy Inc. (CONSOL), we agreed to fund one-third of CONSOL's 50% working interest share of future drilling and completion costs, capped at $400 million each year (CONSOL Carried Cost Obligation). The remaining obligation totaled approximately $1.6 billion at March 31, 2016.
The CONSOL Carried Cost Obligation is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and remain suspended until average Henry Hub natural gas prices equal or exceed $4.00 per MMBtu for three consecutive months. Due to low natural gas prices, the CONSOL Carried Cost Obligation was suspended from the end of 2011 until February 28, 2014. We began funding a portion of CONSOL's working interest share of certain drilling and completion costs as of March 1, 2014; however, the funding was suspended again in November 2014 due to lower natural gas prices. Based on the March 31, 2016 NYMEX Henry Hub natural gas price curve, we expect that the CONSOL Carried Cost Obligation will be suspended for the next 12 months.
Delivery and Firm Transportation Commitments We have commitments to deliver approximately 437 Bcf of natural gas produced onshore US (primarily in the Marcellus Shale) and have also entered into various long-term gathering, processing and transportation contracts for some of our onshore US crude oil and natural gas production (in the Marcellus Shale, DJ Basin and Eagle Ford Shale).
We enter into long-term contracts to provide production flow assurance in over-supplied markets and/or markets with limited infrastructure. This strategy provides for optimization of transportation and processing costs. As properties are undergoing development activities, we may experience temporary delivery or transportation shortfalls until production volumes grow to meet or exceed the minimum volume commitments. During first quarter 2016, we incurred expense of approximately $16 million related to deficiencies and/or unutilized commitments. We expect to continue to incur deficiency and/or unutilized costs in the near-term as development activities continue. Should commodity prices continue to decline or if we are unable to continue to develop our properties as planned, or certain wells become uneconomic and are shut-in, we could incur additional shortfalls in delivering or transporting the minimum volumes and we could be required to make payments in the event that these commitments are not otherwise offset.
Legal Proceedings  We are involved in various legal proceedings in the ordinary course of business.  These proceedings are subject to the uncertainties inherent in any litigation.  We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Air Matter In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency, US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream crude oil and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was entered by the Court on June 2, 2015.   
The Consent Decree, which alleges violations of the Colorado Air Pollution Prevention and Control Act and Colorado’s federal approved State Implementation Plan, specifically Colorado Air Quality Control Commission Regulation Number 7, requires us to perform certain injunctive relief activities to complete mitigation projects and supplemental environmental projects (SEP), and pay a civil penalty. Costs associated with the settlement consist of $4.95 million in civil penalties which were paid in 2015. Mitigation costs of $4.5 million and SEP costs of $4 million are being expended in accordance with schedules established in the Consent Decree. Costs associated with the injunctive relief are not yet precisely quantifiable as they will be determined in accordance with the outcome of evaluations on the adequate design, operation, and maintenance of certain aspects of tank systems to handle potential peak instantaneous vapor flow rates between now and mid-2017.
Compliance with the Consent Decree could result in the temporary shut in or permanent plugging and abandonment of certain wells and associated tank batteries. The Consent Decree sets forth a detailed compliance schedule with deadlines for achievement of milestones through early 2019. The Consent Decree contains additional obligations for ongoing inspection and monitoring beyond that which is required under existing Colorado regulations.  Inspection and monitoring findings may influence decisions to temporarily shut in or permanently plug and abandon wells and associated tank batteries.     
We have concluded that the penalties, injunctive relief, and mitigation expenditures that resulted from this settlement did not have, and based on currently available information will not have, a material adverse effect on our financial position, results of operations or cash flows. 
Colorado Air Compliance Order on Consent  In December 2015, we received a proposed Compliance Order on Consent (COC) from the Colorado Department of Public Health and Environment's Air Pollution Control Division to resolve allegations of noncompliance associated with certain engines subject to various General Permit 02 conditions and/or individual permit conditions as well as certain emission control devices subject to various individual permit conditions. The COC, which provided for an opportunity to further discuss the offer of settlement, has not yet been executed. At present, the revised COC seeks completion of compliance testing, modification of certain permits, submission of a notice and payment of a reduced penalty of $223,475, of which up to 80% may be mitigated by pursuing a SEP or SEPs. Given the inherent uncertainty in administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time. However, we believe that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our financial position, results of operations or cash flows.


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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) is intended to provide a narrative about our business from the perspective of our management. We use common industry terms, such as thousand barrels of oil equivalent per day (MBoe/d) and million cubic feet equivalent per day (MMcfe/d), to discuss production and sales volumes. Our MD&A is presented in the following major sections:

 
The preceding consolidated financial statements, including the notes thereto, contain detailed information that should be read in conjunction with our MD&A.
 
EXECUTIVE OVERVIEW
We are a globally diversified explorer and producer of crude oil, natural gas and natural gas liquids. We aim to achieve sustainable growth in value and cash flow through the development of a high-quality and diverse, worldwide portfolio of assets with investment flexibility between onshore unconventional developments and offshore exploration leading to major development projects. Our portfolio is further diversified through US and international projects and production mix among crude oil, natural gas, and NGLs. Our core operating areas include onshore US, primarily the DJ Basin, Marcellus Shale, Eagle Ford Shale and Permian Basin; offshore US Gulf of Mexico; West Africa; and Eastern Mediterranean. In these areas we believe we have a strategic competitive advantage and will generate attractive returns throughout oil and gas business cycles.
Our portfolio is further complimented through the pursuit of certain exploration opportunities as we seek to establish potential new core areas, such as Suriname, Falkland Islands and Gabon. We may also conclude that an exploration area is not commercially viable and, therefore, may exit locations, such as we did in 2015 with Nevada, Sierra Leone and Nicaragua.
The following discussion highlights significant operating and financial results. This discussion includes operating results associated with our Rosetta Merger, which closed in third quarter of 2015, and should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2015, which includes disclosures regarding our critical accounting policies as part of “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
First Quarter 2016 Significant Operating Highlights Included:
maintained cost reduction efforts in capital, lease operating expense and general and administrative areas and continued to pursue further reductions to align spending with operational cash flows in the current commodity price environment (see Cost Reduction Efforts, below);
continued progression of the Natural Gas Framework (Framework) in Israel;
set a first quarter record 266 million MMcf/d, net, of natural gas in Israel, reflecting enhanced dispatch of natural gas to fuel power generation;
averaged 416 MBoe/d total sales volumes;
recorded first full quarter sales volumes for Big Bend and Dantzler combined of 19 MBoe/d, net, in deepwater Gulf of Mexico;
improved and enhanced well completion designs in the DJ Basin leading to capital efficiencies;
initiated production on our first two Briscoe Ranch wells in the Eagle Ford Shale and first two Delaware Basin wells in the Permian Basin;
installed the Alba B3 compression platform and initiated hook-up and commissioning activities; and
entered into a purchase and sale agreement on May 2, 2016, subsequent to quarter-end, for the divestiture of certain producing and undeveloped crude oil and natural gas interests in approximately 33,500 net acres in Weld County, Colorado for $505 million. See Item 1. Financial Statements – Note 4. Divestitures.
First Quarter 2016 Financial Results Included:
net loss of $287 million, as compared with net loss of $22 million for first quarter 2015;
net gain on commodity derivative instruments of $44 million as compared with net gain on commodity derivative instruments of $150 million for first quarter 2015;
reduced unit costs by 23% in lease operating expense and 27% in general and administrative expense as compared to first quarter 2015;
dry hole expense of $95 million related to the Silvergate exploration well in deepwater Gulf of Mexico;

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other expense of $42 million related to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance;
diluted loss per share of $0.67, as compared with diluted loss per share of $0.06 for first quarter 2015;
cash flow provided by operating activities of $251 million, as compared with $541 million for first quarter 2015;
cash proceeds from non-core divestitures and other of $238 million, as compared with $119 million for first quarter 2015;
capital expenditures of $374 million, as compared with $919 million for first quarter 2015; and
entered into the $1.4 billion Term Loan Facility and utilized borrowings under the Term Loan Facility to tender $1.38 billion of senior notes assumed in the Rosetta Merger resulting in a gain of $80 million.
Quarter-End Key Financial Metrics Included:
ending cash balance of $953 million, as compared with $1.0 billion at December 31, 2015;
total liquidity of approximately $5.0 billion at March 31, 2016, as compared with $5.0 billion at December 31, 2015; and
ratio of debt-to-book capital of 44% at March 31, 2016, as compared with 43% at December 31, 2015
Impact of Current Commodity Prices on our Business 
The upstream oil and gas business is cyclical and we are currently operating in a period of low commodity prices. Commodity prices began declining sharply during fourth quarter 2014 and continued to decline throughout 2015. Thus far in 2016, crude oil prices have remained volatile ranging below $30.00 per barrel to upwards of $43.00 per barrel. Current commodity prices continue to negatively impact our revenues, profitability, and cash flows. In response to the commodity price environment, we have reduced our 2016 capital spending program to less than $1.5 billion, approximately 50% lower than 2015 and approximately 70% lower than 2014. See Operating Outlook – 2016 Capital Investment Program, below.
Positioning for the Future 
We have taken steps to sustain our business in the volatile and low commodity price environment that has evolved. We have adopted a comprehensive effort to spend within cash flow and maintain our strong balance sheet. To this end, we plan to defer certain activity to protect our liquidity position and have adopted a 2016 capital program more closely aligned with expected cash flow. In addition, we adjusted the quarterly dividend to 10 cents per common share in first and second quarter 2016, representing a reduction of 8 cents, or 44%, from 2015 quarterly dividends which aligns the dividend yield with historical levels and further enhances our liquidity. We also intend to reduce leverage in this environment and have engaged in debt refinancing activities in first quarter 2016. The dividend reduction and debt refinancing are expected to provide approximately $200 million annually in support of balance sheet management efforts. 
We believe we have positioned the Company for sustainability, operational efficiency, and long-term success throughout the oil and gas business cycle. However, if the industry downturn continues for an extended period, or becomes more severe, we could experience additional material negative impacts on our revenues, profitability, cash flows, liquidity and proved reserves, and in response, we may consider additional reductions in our capital program or dividends, and further asset sales and/or additional organizational changes. Our production and our stock price could decline further as a result of these potential developments.
Cost Reduction Efforts
For 2016, we continue to focus on maintaining our strong safety culture, driving operational efficiencies and productivity and reducing our cost structure. Cost reduction initiatives, including both operational enhancements and new pricing arrangements with suppliers, have resulted in total lease operating expense and general and administrative expense being flat as compared to first quarter 2015 while sales volumes increased nearly 100 MBoe/d. Our global portfolio provides significant optionality, allowing us to reduce our capital spending by nearly 60% for the first three months of 2016, as compared to the same period of 2015. As the majority of our onshore US assets are held by production, the investment and financial flexibility of our portfolio allows us to defer certain activity to protect our liquidity position.
Sales Volumes
On a BOE basis, total sales volumes were 31% higher for first quarter 2016 as compared with first quarter 2015, and our mix of sales volumes was 45% global liquids, 19% international natural gas, and 36% US natural gas. On a BOE basis and excluding the impact of the Rosetta Merger, total sales volumes were 12% higher for first quarter 2016 as compared with first quarter 2015, and our mix of sales volumes was 42% global liquids, 36% US natural gas and 22% international natural gas. See Results of Operations – Revenues, below.
Commodity Price Changes
Crude oil prices are driven by global crude oil supply and demand factors. During 2014, crude oil became oversupplied as production from non-OPEC producers increased, primarily driven by US crude oil production growth from tight formations and the de-bottlenecking of transportation infrastructure, while global crude oil demand growth was muted on lower global economic growth, especially in Europe, coupled with slower growth in China.

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The outlook for crude oil prices during 2016 depends primarily on supply and demand dynamics and global security concerns in crude oil-producing nations. In April 2016, OPEC and other major oil producers convened to discuss efforts to reduce the oversupply and re-balance the market, but failed to reach an agreement to limit crude oil production. On the demand side, recent projections have reduced anticipated global crude oil demand growth for 2016 and Chinese economic indicators have weakened, which continue to exacerbate the current oversupply situation and resulting soft pricing environment.
Longer term, we expect supply and demand to re-balance. If prices remain at lower levels, we expect producers will reduce investment which will, over time, reduce production, helping to balance supply and demand in the crude oil market.
We plan for commodity price cyclicality in our business and believe we are well positioned to withstand current and future commodity price volatility due to the following:
we have a high-quality, globally diversified portfolio of assets, the majority of which are held by production and provide investment flexibility;
we have achieved sustainable cost reductions impacting both operating expenses and capital expenditures, including a substantially reduced capital investment program which allows us to respond to changing commodity price conditions in 2016, thereby positively impacting operating cash flows;
we are well hedged for 2016, and partially hedged for 2017;
we have a strong balance sheet with a ratio of debt-to-book capital of 44% at March 31, 2016; and
we have robust liquidity of approximately $5.0 billion at March 31, 2016 and ability to access capital markets.
Major Development Project Updates
We continue to advance our major development projects, which we expect to deliver incremental production over the next several years. Updates on major development projects are as follows:
Sanctioned Ongoing Development Projects
A "sanctioned" development project is one for which a final investment decision has been made.
DJ Basin (Onshore US)   During the quarter, we operated three drilling rigs (reducing to two rigs in February), drilled 24 wells and commenced production on 36 wells. We continued to improve and enhance our completion designs and were able to deliver higher production at lower capital and lease operating expense costs than first quarter of 2015.
Marcellus Shale (Onshore US)   Currently, we have no operated or non-operated rigs running in the Marcellus Shale. For 2016, we and CONSOL have agreed to operate within cash flow and have agreed to a plan which will focus on well completions. As such, our allocated capital to be invested in the Marcellus Shale will be limited to the completion of certain previously-drilled wells primarily located in non-operated dry gas areas. During the quarter, we commenced production on eight operated wells and our joint venture partner commenced production on 17 wells.
Eagle Ford Shale and Permian Basin (Onshore US) During the quarter, we operated one drilling rig, drilled two horizontal wells and commenced production on eight wells in the Eagle Ford Shale. In the Permian Basin, we operated one drilling rig, drilled two horizontal wells and commenced production on our first two horizontal wells.
Gunflint (Deepwater Gulf of Mexico)  Development is on track for the Gunflint (31% operated working interest) crude oil discovery, utilizing a two-well subsea tieback to the Gulfstar One spar. Topsides modifications and facilities upgrades are in the process of being completed, and we are targeting first production for mid-2016.
Alba Field (Offshore Equatorial Guinea) The Alba B3 compression platform was successfully installed in first quarter 2016. Hook-up and commissioning activities are underway and are expected to be completed in mid-year 2016, with first production from the compression project expected in third quarter 2016.
Tamar Southwest We continue to work with the Government of Israel to obtain regulatory approval of our development plan, which is intended to utilize current Tamar infrastructure. To ensure project continuity, we have petitioned the Israeli courts to expedite the needed approvals. Timely development of Tamar Southwest is important to maintain well capacity and reliability for our overall Tamar project. See Update on Israel Natural Gas Regulatory Framework, below.
Unsanctioned Development Projects
Tamar Expansion Project (Offshore Israel) We have engaged in the planning phase for an expansion project which would expand Tamar field deliverability to approximately 2.1 Bcf/d, a quantity that would allow for regional export. Expansion would include a third flow line component and additional producing wells. Timing of project sanction depends on satisfactory resolution of regulatory matters as well as progression of marketing efforts. See Update on Israel Natural Gas Regulatory Framework, below.
Leviathan Project (Offshore Israel)   The marketing and development of natural gas is intended to serve both domestic demand and regional export. We have been engaged in natural gas marketing activities and executed our first natural gas sales and

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purchase agreement in early 2016. We also submitted a Plan of Development to the Government of Israel. However, timing of project sanction depends on satisfactory resolution of regulatory matters that we and our partners face in developing our offshore assets. Project financing will also be required. See Update on Israel Natural Gas Regulatory Framework, below.
Cyprus Project (Offshore Cyprus)  During fourth quarter 2015, we entered into a farm-out agreement with a partner for a 35% interest in Block 12, which includes the Aphrodite natural gas discovery, for $171 million. In first quarter 2016, we received proceeds of $131 million related to the farm-out agreement and expect to receive the remaining consideration of $40 million, subject to post-close adjustments, in 2017. The proceeds were applied to the Cyprus project asset with no gain or loss recognized. We will continue to operate with a 35% interest. Also, as part of the farm-out process, we negotiated a waiver of our remaining exploration well obligation.
During 2015, we submitted a Declaration of Commerciality and a Development Plan to the Government of Cyprus. We continue to work with the Government of Cyprus to obtain approval of the development plan and the issuance of an Exploitation License for the Aphrodite field. Receiving an Exploitation License, in conjunction with securing markets for Aphrodite gas, will allow us and our partners to perform the necessary front-end engineering design (FEED) studies and progress the project to final investment decision. In preparation for FEED, we and our partners are currently performing preliminary engineering and design (pre-FEED) for the potential development of Aphrodite field that, as currently planned, would deliver natural gas to potential customers in Cyprus and Egypt.
See Item 1. Financial Statements – Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold.
Exploration Program Update
Our 2016 exploration budget has been substantially reduced compared to prior years, but provides flexibility to respond to commodity price changes. While we expect to conduct limited exploratory activities in the current year, our core areas provide for exploration opportunities and we have increased our evaluation of new venture opportunities in both US and international locations.
We do not always encounter hydrocarbons through our drilling activities. In addition, we may find hydrocarbons but subsequently reach a decision, through additional analysis or appraisal drilling, that a development project is not economically or operationally viable. In the event we conclude that one of our exploratory wells did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs would be recorded as dry hole expense. 
Additionally, we may not be able to conduct exploration activities prior to lease expirations. As a result, in a future period, dry hole cost and/or leasehold abandonment expense could be significant. See Item 1. Financial Statements – Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold and Operating Outlook – Potential for Future Impairment, Dry Hole or Lease Abandonment Expense, below.
Updates on significant exploration activities are as follows:
Deepwater Gulf of Mexico In first quarter 2016, drilling operations were completed at our Silvergate exploration well in deepwater Gulf of Mexico. The well did not encounter commercial hydrocarbons and has been plugged and abandoned. In first quarter 2016, we recorded dry hole expense of $95 million associated with this well. Our exploration and appraisal program for 2016 also includes an appraisal well (38% operated working interest) at our Katmai discovery made during third quarter 2014 (Green Canyon Block 40, 50% operated working interest) to test the remaining resource potential and further define potential development scenarios.
Offshore West Africa We are interpreting and evaluating recently acquired 3D seismic data across Equatorial Guinea Blocks I and O which will aid in advancing exploration and development opportunities, including the Diega/Carmen and Carla discoveries.
Offshore Cameroon  We have an interest in approximately 167,800 gross undeveloped acres offshore Cameroon in our YoYo mining concession (50% operating working interest). Petronas holds the other 50% operating working interest and has given notice to us and the Cameroon government of their intention to exit this acreage position. Once the assignment process is finalized, we will hold 100% operating working interest in the YoYo mining concession. We have begun efforts to market this additional working interest. The YoYo-1 exploratory well was drilled in 2007, discovering natural gas and condensate. We are working with the government of Cameroon to evaluate natural gas development options and are negotiating with the Cameroon government to convert the YoYo mining concession to a production sharing contract. We have completed reprocessing of 3D seismic data over our YoYo mining concession and are currently evaluating the data. In April 2016, we gave notice to the Cameroon government of our intention to exit our acreage position in the Tilapia block (46.67% operating working interest) which covered an area of approximately 900,000 gross acres.
Offshore Eastern Mediterranean See Update on Israel Natural Gas Regulatory Framework, below.

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Offshore Falkland Islands In 2015, we experienced material operational issues with a drilling rig while drilling the Humpback well. The same drilling rig was scheduled to drill another prospect but due to significant safety and operational concerns, the drilling contract was terminated in first quarter 2016. We have been and will continue to work closely with our partners and the Falkland Islands Government to evaluate a path forward that includes retaining flexibility for any possible prospects. In first quarter 2016, we expensed $42 million of capitalized rig costs relating to pre-drill activities. These costs are reflected in Other Non-Operating (Income) Expense, Net in the consolidated statements of operations.
Offshore Suriname  The initial phase of exploration on Block 54 requires acquisition of a 3D seismic survey, which has been completed and is currently being processed.  Evaluation of the seismic survey will determine if a commitment to a subsequent exploration phase to drill an exploration well is warranted.
Offshore Gabon We are the operator of Block F15 (60% working interest), an undeveloped, deep water area. Our exploration commitment includes a 3D seismic obligation which is currently being acquired.
Update on Israel Natural Gas Regulatory Framework
We have been progressing plans to develop the Leviathan field and expand the currently producing Tamar field. Historically we have had to address certain fiscal, antitrust and other regulatory challenges in Israel. These challenges were addressed with the enactment of a comprehensive regulatory natural gas framework (Natural Gas Framework) by the Government of Israel in 2015. The Natural Gas Framework provides clarity on numerous matters concerning resource development which we will rely upon to support a final investment decision and upon which we can develop our resources while ensuring economic benefits to the state of Israel and its citizens. Among other items, the Natural Gas Framework provides for the following:
the timely approval of asset development permits and plans and export permits;
benchmarking future domestic contract pricing for an interim period until market competition is established, whereby such contracts are indexed to existing domestic and export contracts;
resolution of antitrust and competition concerns, whereby we recently divested our Karish and Tanin discoveries and will reduce our ownership in Tamar to 25% within six years;
the de-linking of Tamar export timing from Leviathan, enabling Tamar expansion to move forward; and
support for investment and industry growth through stabilization assurance.
The Natural Gas Framework also enables marketing of Leviathan natural gas to Israeli customers for the first time. The development of Leviathan will substantially expand our capacity to deliver natural gas to Israel and the region, as well as provide a second source of domestic natural gas supply and redundancy of infrastructure for the people of Israel.
Since its enactment, the Natural Gas Framework (Framework) has been subject to ongoing legal challenges. The Israel Supreme Court held hearings in February 2016 to consider the challenges, including the Government of Israel’s enactment of Section 52 of the Restrictive Trade Practices Act and constitutional aspects of the stability undertakings. Execution of Section 52 resolves and provides exemption from claims of the Anti-trust Authority with respect to the Leviathan joint venture partners' acquisition of petroleum rights in the underlying permits.
The Court subsequently affirmed the Framework, including the anti-trust exemption, the Framework’s price transparency and export provisions. However, the Court did not approve the stability provisions. 
Regarding the stability provisions, the Court concluded that the Government of Israel should provide stability assurances and provisions through an alternate legal mechanism and provided the Government up to one year to resolve this matter. The Government continues to evaluate a number of alternatives to provide for this stability clause and instill investment confidence. Stable fiscal and contract terms and the regulatory Framework are required to support long-term investment in such major energy infrastructure. We cannot predict the outcome of this process, the impact on timing of sanction or start-up of production of the Leviathan project.
Pending Master Limited Partnership
On October 22, 2015, Noble Midstream Partners LP (Noble Midstream), a wholly owned subsidiary of Noble Energy, filed a registration statement on Form S-1 with the U.S. Securities and Exchange Commission (SEC) relating to a proposed master limited partnership. On April 1, 2016, Noble Midstream filed an amendment to the Form S-1. Under the proposed structure, Noble Midstream will own, operate and develop our DJ Basin crude oil, natural gas and water-related midstream infrastructure, and Noble Energy will own the general partner of Noble Midstream and retain a majority of limited partnership interests in the proposed master limited partnership. As of the date of this report, the registration statement is not effective. The completion of the proposed offering is subject to numerous conditions, including capital market conditions, and we can provide no assurance that it will be successfully completed.
Non-Core Divestiture Program
We periodically divest non-core, non-strategic assets. During first quarter 2016, we continued our non-core asset divestiture program with the sale of certain smaller onshore US property packages resulting in net proceeds of $20 million. Divestitures of

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non-core properties allow us to allocate capital and other resources to high-value and high-growth areas and enhances our balance sheet strength. We continue to evaluate divestment opportunities of certain non-core onshore properties located in the Rocky Mountain and Bowdoin (north central Montana) areas. As of March 31, 2016, the net book value of these non-core assets totaled $86 million, of which $65 million was related to our Bowdoin assets located in north central Montana.
See Item 1. Financial Statements – Note 4. Divestitures and Operating Outlook - Potential for Future Impairment, Dry Hole or Lease Abandonment Expense, below.
Update on Regulations
US Offshore Regulatory Developments On April 14, 2016, the BSEE issued a final rule establishing updated standards for blowout prevention systems and other well controls for offshore oil and gas activities conducted in US federal waters, including the Gulf of Mexico. Although the final rule incorporates some of the changes recommended by the oil and gas industry, it imposes a number of new requirements relating to well design, well control, casing, cementing, real-time well monitoring and subsea containment. For example, the new rule requires double sets of shear rams on all deepwater blowout preventers (BOPs), periodic inspections of BOPs and outside audits of equipment, and real-time well monitoring requirements. The new rule will likely increase the costs associated with well design, drilling and completion operations.
On March 17, 2016, the BOEM proposed a new air quality monitoring rule that would significantly broaden the scope of air emissions that operators in US federal waters, including the Gulf of Mexico, must measure, monitor and control. Among other things, the proposed rule would expand the types of emissions that must be measured, require operators to measure emissions more frequently, and increase the scope of facilities that must be monitored. If adopted as proposed, the new rule would likely increase the cost associated with our activities in the Gulf of Mexico.
Colorado Crude Oil and Natural Gas Regulation In 2014, by executive order, Colorado Governor Hickenlooper created a 21-member Oil and Gas Task Force (Task Force) made up of representatives of local governments, civic entities, environmental organizations and industry for the purpose of making recommendations regarding oil and gas development in communities. After 18-months, the Task Force, which included a representative from Noble Energy, concluded its activities on February 27, 2015. Nine recommendations were sent to the governor, seven of which were unanimously supported. These recommendations have all been adopted by legislation or regulation. The Colorado Oil and Gas Conservation Commission recently completed work on new rules which govern the siting of large oil and gas operations in urban areas and require greater coordination of drilling operations with local governments. These new rules took effect in March 2016 and there is strong public support for them to be implemented.
Recently the state of Colorado approved for signature gathering four ballot measures which would impact oil and gas operations. Measure 40 would grant local communities self-governance and the opportunity to ban certain businesses from operating in their jurisdictions. Measure 63 would establish a constitutional right to a healthy environment and provide local governments the obligation to protect the environment. Measure 75 would grant local governments control over oil and gas development, notwithstanding state law. Measure 78 would require that all new oil and gas facilities be located 2,500 feet from occupied structures and an expansive list of landscape features called ‘areas of special concern.’ Measure 78 would significantly impact future oil and gas operations and has strong opposition from the oil and gas industry, the governor and the business community.
All of these measures are available for signature gathering and the proponents have until August 8, 2016 to gather 98,492 signatures to qualify for the November 2016 ballot.
In addition to the above, we will continue to monitor proposed and new regulations and legislation in all our operating jurisdictions to assess the potential impact on our company. Concurrently, we are engaged in extensive public education and outreach efforts with the goal of engaging and educating the general public and communities about the energy, economic and environmental benefits of safe and responsible crude oil and natural gas development.
Recently Issued Accounting Standards
See Item 1. Financial Statements – Note 2. Basis of Presentation.
OPERATING OUTLOOK
2016 Production   We have adopted a comprehensive effort to spend within cash flow, manage the Company's balance sheet and position ourselves for future growth. To this end, we plan to defer certain activities to protect our liquidity position and adopted a 2016 capital program more closely aligned with expected cash flow. Therefore, our total crude oil, natural gas and NGL production for 2016 may not grow at a rate consistent with prior years and potentially could decline. Production may be impacted by factors including:
commodity prices which, if subject to further decline, could result in current production becoming uneconomic;
overall level and timing of capital expenditures which, as discussed below and dependent upon our drilling success, will impact near-term production volumes;

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timing of start-up of the Gunflint project (deepwater Gulf of Mexico) and Alba compression project (offshore Equatorial Guinea);
Israeli demand for electricity, which is impacted by unseasonable weather and conversion of the Israeli electricity portfolio from coal to natural gas;
Israeli industrial demand for natural gas;
variations in West Africa crude oil and condensate sales volumes due to potential Aseng FPSO downtime and timing of liftings, and variations in natural gas sales volumes related to potential downtime at the methanol, LPG and/or LNG plants;
natural field decline in the onshore US, deepwater Gulf of Mexico and offshore Equatorial Guinea;
potential weather-related volume curtailments due to hurricanes in the deepwater Gulf of Mexico, or winter storms and flooding impacting onshore US operations;
reliability of support equipment and facilities and/or potential pipeline and processing facility capacity constraints which may cause restrictions or interruptions in production and/or mid-stream processing;
timing and completion of planned maintenance, including turnarounds, of processing facilities serving our DJ Basin assets;
potential shut-in of US producing properties if storage capacity becomes unavailable;
potential drilling and/or completion permit delays due to future regulatory changes; and
potential purchases of producing properties or divestments of non-core operating assets.
2016 Capital Investment Program Given the current commodity price environment, we have designed a substantially reduced and flexible capital investment program that is part of our comprehensive effort to spend within cash flow and manage the Company's balance sheet. Our updated 2016 capital investment program will accommodate an investment level of less than $1.5 billion, or approximately 50% lower than our 2015 program. The program allocates two-thirds of total investment to core onshore US assets and the remaining one-third to offshore development and exploration.
See Liquidity and Capital Resources – Financing Activities.
Potential for Future Dry Hole Cost, Lease Abandonment Expense or Property Impairments
Exploration Activities Our exploratory drilling program seeks to provide long-term growth from existing and potential new core areas. In the event we conclude that an exploratory well did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense. For example, in first quarter 2016, we recorded dry hole costs of $95 million associated with our Silvergate exploratory well. The well did not encounter commercial hydrocarbons and has been plugged and abandoned. See Item 1. Financial Statements - Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold.
Additionally, we may not conduct exploration activities prior to lease expirations. For example, in the deepwater Gulf of Mexico, we continue to mature our prospect portfolio. However, regulations have become more stringent due to the Deepwater Horizon incident in 2010. In some instances, specifically engineered blowout preventers, rigs, and completion equipment may be required for high pressure environments. Regulatory requirements or lack of readily available equipment could prevent us from engaging in future exploration activities during our current lease terms. In addition, the current commodity price environment may render certain prospects economically less attractive and we may not conduct exploration activities before lease expiration.
We currently have capitalized undeveloped leasehold cost of approximately $255 million related to deepwater Gulf of Mexico prospects that have not yet been drilled. These leases will expire over the years 2016 - 2024. While none of our undeveloped leases were impaired as of March 31, 2016, changes in exploration plans, availability of capital and suitable rig and drilling equipment, resource potential, changing regulations and/or other factors, could result in future impairment. In the deepwater Gulf of Mexico, some leases may become impaired if production is not established, we do not take action to extend the terms of the leases, or the leases become uneconomic due to low commodity prices, costs of complying with new regulations, or other factors.
As a result of our exploration activities, future exploration expense, including leasehold expense, could be significant. See Results of Operations - Oil and Gas Exploration Expense, below. See also Item 1A. Risk Factors.
Producing Properties In 2016, commodity prices, including WTI, Brent and HH, have continued to trade in a low range and remain volatile. A further decline in future crude oil, natural gas or NGL prices could result in some of our properties becoming uneconomic, resulting in additional impairment charges, decrease in proved reserves and/or shut-in of currently producing wells.
In addition, in certain onshore US areas, transportation bottlenecks caused by oversupply and/or lack of infrastructure can reduce the amount of production reaching premium markets, resulting in less favorable basis differentials, or differences between WTI and HH pricing and the average prices we actually receive. A widening of these basis differentials could also reduce cash flows and result in property impairment charges.

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The cash flow model that we use to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future crude oil and natural gas production along with operating and development costs, market outlook on forward commodity prices, and interest rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward commodity prices, or widening of basis differentials, alone could result in an impairment.
In addition, well decommissioning programs, especially in deepwater or remote locations, are often complex and expensive. It may be difficult to estimate timing of actual abandonment activities, which are subject to regulatory approval and the availability of rigs and services. It may be difficult to estimate costs as rigs and services become more expensive in periods of higher demand. Therefore, our ARO estimates may change, sometimes significantly, and could result in asset impairment.
Divestments We are currently marketing certain non-core onshore US properties. If properties are reclassified as assets held for sale in the future, they will be valued at the lower of net bo