NBL-2013.03.31-10Q FILE COPY
Table of Contents

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, 2013

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)
100 Glenborough Drive, Suite 100
 
 
Houston, Texas
 
77067
(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 April 8, 2013, there were 179,314,474 shares of the registrant’s common stock,
par value $0.01 per share, outstanding.



Table of Contents

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,
 
2013
 
2012
Revenues
 
 
 
Oil, Gas and NGL Sales
$
1,083

 
$
1,037

Income from Equity Method Investees
60

 
51

Total
1,143

 
1,088

Costs and Expenses
 
 
 
Production Expense
187

 
163

Exploration Expense
61

 
60

Depreciation, Depletion and Amortization
366

 
294

General and Administrative
112

 
97

Other Operating (Income) Expense, Net
(8
)
 
12

Total
718

 
626

Operating Income
425

 
462

Other (Income) Expense
 
 
 
Loss on Commodity Derivative Instruments
72

 
96

Interest, Net of Amount Capitalized
25

 
32

Other Non-Operating (Income) Expense, Net
10

 
(1
)
Total
107

 
127

Income from Continuing Operations Before Income Taxes
318

 
335

Income Tax Provision
86

 
86

Income from Continuing Operations
232

 
249

Discontinued Operations, Net of Tax
29

 
14

Net Income
$
261

 
$
263

 
 
 
 
Earnings Per Share, Basic


 


Income from Continuing Operations
$
1.29

 
$
1.40

Discontinued Operations, Net of Tax
0.17

 
0.08

Net Income
$
1.46

 
$
1.48

Earnings Per Share, Diluted
 
 
 
Income from Continuing Operations
$
1.28

 
$
1.39

Discontinued Operations, Net of Tax
0.17

 
0.08

Net Income
$
1.45

 
$
1.47

 
 
 
 
Weighted Average Number of Shares Outstanding
 
 
 
   Basic
179

 
177

   Diluted
181

 
180


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

3

Table of Contents

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

 
 
Three Months Ended
March 31,
 
2013
 
2012
Net Income
$
261

 
$
263

Other Items of Comprehensive Income
 
 
 
Net Change in Pension and Other
6

 
3

      Less Tax Benefit
(2
)
 
(1
)
Other Comprehensive Income
4

 
2

Comprehensive Income
$
265

 
$
265


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


4

Table of Contents

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

 
March 31,
2013
 
December 31,
2012
ASSETS
 
 
 
Current Assets
 
 
 
Cash and Cash Equivalents
$
1,305

 
$
1,387

Accounts Receivable, Net
776

 
964

Other Current Assets
370

 
420

Total Current Assets
2,451

 
2,771

Property, Plant and Equipment
 

 
 

Oil and Gas Properties (Successful Efforts Method of Accounting)
20,015

 
19,496

Property, Plant and Equipment, Other
346

 
344

Total Property, Plant and Equipment, Gross
20,361

 
19,840

Accumulated Depreciation, Depletion and Amortization
(6,366
)
 
(6,289
)
Total Property, Plant and Equipment, Net
13,995

 
13,551

Goodwill
632

 
635

Other Noncurrent Assets
632

 
597

Total Assets
$
17,710

 
$
17,554

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current Liabilities
 

 
 

Accounts Payable - Trade
$
1,388

 
$
1,508

Other Current Liabilities
986

 
1,024

Total Current Liabilities
2,374

 
2,532

Long-Term Debt
3,723

 
3,736

Deferred Income Taxes, Noncurrent
2,249

 
2,218

Other Noncurrent Liabilities
850

 
810

Total Liabilities
9,196

 
9,296

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; 500 Million Shares Authorized; 199 Million and 198 Million Shares Issued, respectively
2

 
2

Additional Paid in Capital
3,353

 
3,304

Accumulated Other Comprehensive Loss
(109
)
 
(113
)
Treasury Stock, at Cost; 19 Million Shares
(662
)
 
(648
)
Retained Earnings
5,930

 
5,713

Total Shareholders’ Equity
8,514

 
8,258

Total Liabilities and Shareholders’ Equity
$
17,710

 
$
17,554


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


5

Table of Contents

Noble Energy, Inc.
Consolidated Statements of Cash Flows
(millions)
(unaudited)

 
Three Months Ended
March 31,
 
2013
 
2012
Cash Flows From Operating Activities
 
 
 
Net Income
$
261

 
$
263

Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
 

 
 

Depreciation, Depletion and Amortization
367

 
312

Deferred Income Taxes
52

 
32

Dividends (Income) from Equity Method Investees, Net
(35
)
 
(29
)
Unrealized Loss on Commodity Derivative Instruments
79

 
73

Gain on Divestitures
(53
)
 

Stock Based Compensation
18

 
16

Other Adjustments for Noncash Items Included in Income
25

 
15

Changes in Operating Assets and Liabilities
 
 
 

Increase in Accounts Receivable
(56
)
 
(135
)
(Increase) Decrease in Other Current Assets
20

 
(5
)
Increase in Accounts Payable
82

 
190

Decrease in Other Current Liabilities
(48
)
 
(26
)
Other Operating Assets and Liabilities, Net
(7
)
 
35

Net Cash Provided by Operating Activities
705

 
741

Cash Flows From Investing Activities
 

 
 

Additions to Property, Plant and Equipment
(806
)
 
(1,018
)
Additions to Equity Method Investments
(20
)
 
(14
)
Proceeds from Divestitures
76

 

Other
2

 

Net Cash Used in Investing Activities
(748
)
 
(1,032
)
Cash Flows From Financing Activities
 

 
 

Exercise of Stock Options
22

 
27

Excess Tax Benefits from Stock-Based Awards
9

 
12

Dividends Paid, Common Stock
(44
)
 
(39
)
Purchase of Treasury Stock
(14
)
 
(13
)
Repayment of Capital Lease Obligation
(12
)
 
(8
)
Net Cash Used In Financing Activities
(39
)
 
(21
)
Decrease in Cash and Cash Equivalents
(82
)
 
(312
)
Cash and Cash Equivalents at Beginning of Period
1,387

 
1,455

Cash and Cash Equivalents at End of Period
$
1,305

 
$
1,143

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


6

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, 2012
$
2

 
$
3,304

 
$
(113
)
 
$
(648
)
 
$
5,713

 
$
8,258

Net Income

 

 

 

 
261

 
261

Stock-based Compensation

 
18

 

 

 

 
18

Exercise of Stock Options

 
22

 

 

 

 
22

Tax Benefits Related to Exercise of Stock Options

 
9

 

 

 

 
9

Dividends (25 cents per share)

 

 

 

 
(44
)
 
(44
)
Changes in Treasury Stock, Net

 

 

 
(14
)
 

 
(14
)
Net Change in Pension and Other

 

 
4

 

 

 
4

March 31, 2013
$
2

 
$
3,353

 
$
(109
)
 
$
(662
)
 
$
5,930

 
$
8,514

 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2011
$
656

 
$
2,497

 
$
(100
)
 
$
(638
)
 
$
4,850

 
$
7,265

Net Income

 

 

 

 
263

 
263

Stock-based Compensation

 
16

 

 

 

 
16

Exercise of Stock Options
2

 
25

 

 

 

 
27

Tax Benefits Related to Exercise of Stock Options

 
12

 

 

 

 
12

Dividends (22 cents per share)

 

 

 

 
(39
)
 
(39
)
Changes in Treasury Stock, Net

 

 

 
(13
)
 

 
(13
)
Net Change in Pension and Other
1

 
(1
)
 
2

 

 

 
2

March 31, 2012
$
659

 
$
2,549

 
$
(98
)
 
$
(651
)
 
$
5,074

 
$
7,533


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

7

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, primarily in the DJ Basin and Marcellus Shale, in the 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, 2013 and December 31, 2012 and for the three months ended March 31, 2013 and 2012 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. Operating results for the three months ended March 31, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013. Certain reclassifications of amounts previously reported have been made to reflect the operations of our North Sea geographical segment as discontinued, as well as to conform to current year presentations. See Note 3. Divestitures.

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, 2012.
 
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.
 

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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,
 
2013
 
2012
(millions)
 
 
 
Production Expense
 
 
 
Lease Operating Expense
$
117

 
$
105

Production and Ad Valorem Taxes
43

 
38

Transportation and Gathering Expense
27

 
20

Total
$
187

 
$
163

Other Operating (Income) Expense, Net
 
 
 
Gain on Divestitures (1)
(15
)
 

Other, Net
7

 
12

Total
$
(8
)
 
$
12

Other Non-Operating (Income) Expense, Net
 
 
 
Deferred Compensation Expense (2)
$
10

 
$
3

Other (Income) Expense, Net

 
(4
)
Total
$
10

 
$
(1
)
 
(1) 
See Note 3. Divestitures.
(2) 
Amounts represent increases in the fair value of shares of our common stock held in a rabbi trust.

 

9

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

Balance Sheet Information   Other balance sheet information is as follows:
 
March 31,
2013
 
December 31,
2012
(millions)
 
 
 
Accounts Receivable, Net
 
 
 
Commodity Sales
$
266

 
$
349

Joint Interest Billings
395

 
486

Other
125

 
139

Allowance for Doubtful Accounts
(10
)
 
(10
)
Total
$
776

 
$
964

Other Current Assets
 

 
 

Inventories, Current
$
97

 
$
90

Commodity Derivative Assets
36

 
63

Deferred Income Taxes, Net
83

 
106

Probable Insurance Claims (1)
17

 
45

Assets Held for Sale (2)
63

 
45

Prepaid Expenses and Other Current Assets
74

 
71

Total
$
370

 
$
420

Other Noncurrent Assets
 

 
 

Equity Method Investments
$
423

 
$
367

Mutual Fund Investments
109

 
103

Commodity Derivative Assets
13

 
21

Other Assets, Noncurrent
87

 
106

Total
$
632

 
$
597

Other Current Liabilities
 

 
 

Production and Ad Valorem Taxes
$
107

 
$
113

Commodity Derivative Liabilities
44

 
7

Income Taxes Payable
202

 
203

Asset Retirement Obligations
69

 
69

Interest Payable
40

 
55

CONSOL Installment Payment (3)
325

 
324

Current Portion of FPSO Lease Obligation
49

 
48

Liabilities Associated with Assets Held for Sale (2)
14

 
12

Other
136

 
193

Total
$
986

 
$
1,024

Other Noncurrent Liabilities
 

 
 

Deferred Compensation Liabilities
$
247

 
$
229

Asset Retirement Obligations
330

 
333

Accrued Benefit Costs
118

 
116

Commodity Derivative Liabilities
9

 
3

Other
146

 
129

Total
$
850

 
$
810

 
(1) 
Amounts represent the costs incurred to date of the Leviathan-2 appraisal well and expected well abandonment costs in excess of the insurance deductible less insurance proceeds received to date.
(2) 
Assets held for sale consist primarily of North Sea and onshore US oil and gas properties. Liabilities associated with assets held for sale consist primarily of asset retirement obligations related to these assets. See Note 3. Divestitures.
(3) 
See Note 5. Debt.


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

Note 3. Divestitures
 
North Sea Properties During the first quarter of 2013, we closed the sale of our 13% non-operated working interest in the Cook field located in the UK sector of the North Sea. The sale resulted in a $37 million gain based on net sale proceeds of $38 million for the field.
We continue to market our remaining North Sea properties. As of March 31, 2013, all the properties remaining in our North Sea geographical segment are included in assets held for sale in our consolidated balance sheet. Our consolidated statements of operations have been reclassified for all periods presented to reflect the operations of our North Sea geographical segment as discontinued. Upon reclassification as held for sale, depreciation, depletion, and amortization (DD&A) ceased. Our long-term debt is recorded at the consolidated level; therefore no interest expense has been allocated to discontinued operations.
Summarized results of discontinued operations are as follows:
 
Three Months Ended
March 31,
 
2013
 
2012
(millions)
 
 
 
Oil and Gas Sales
$
10

 
$
75

Income (Loss) Before Income Taxes
(1
)
 
39

Income Tax Expense
7

 
25

Operating Income (Loss), Net of Tax
(8
)
 
14

Gain on Sale, Net of Tax
37

 

Discontinued Operations, Net of Tax
$
29

 
$
14

Sale of Onshore US Properties During the first quarter of 2013, we closed the sales of certain crude oil and natural gas properties in the Gulf Coast area with an effective date of November 1, 2012. The information regarding the assets sold is as follows:
 
Three Months Ended
March 31,
 
2013
(millions)
 
Sale Proceeds
$
55

Less
 
     Net Book Value of Assets Sold
(28
)
     Goodwill Allocated to Assets Sold
(3
)
     Asset Retirement Obligations Associated with Assets Sold
5

     Other Closing Adjustments (1)
(14
)
Gain on Divestitures
$
15


(1) Other closing adjustments also include adjustments related to onshore US property sales completed during 2012.

Note 4.  Derivative Instruments and Hedging Activities
 
Objective and Strategies for Using Derivative Instruments   We are exposed to fluctuations in crude oil and natural gas prices on the majority of our worldwide production. In order to mitigate the effect of commodity price volatility and enhance the predictability of cash flows relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. The derivative instruments we use include variable to fixed price commodity swaps, two-way and three-way collars and put options.

During the first quarter of 2013, we restructured our hedge portfolio to better align hedge benchmark prices with our realized crude oil sales prices. We terminated certain of our crude oil swaps and three way collars while entering into new hedging

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

instruments including crude oil swaps and put options. As a result of this restructuring, we recognized a de minimis gain on hedge terminations.

We also may enter into forward contracts to hedge anticipated exposure to interest rate risk associated with public debt financing.
 
While these instruments mitigate the cash flow risk of future reductions in commodity prices or increases in interest rates, they may also curtail benefits from future increases in commodity prices or decreases in interest rates.
 
See Note 6. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments.
 

Unsettled Derivative Instruments   As of March 31, 2013, we had entered into the following crude oil derivative instruments: 
 
 
 
 
Swaps
 
Options
 
Collars
Settlement
Period
Type of Contract
Index
Bbls Per
Day
Weighted
Average
Fixed
Price
 
Put Option Premium
 
Weighted
Average
 Short Put
 Price
Weighted
Average
Floor
Price
Weighted
Average
 Ceiling
Price
Instruments Entered Into as of March 31, 2013
 
 
 
 
 
 
 
 
2013
Swaps
NYMEX WTI  (1)
9,000
$
90.16

 
$

 
$

$

$

2013
Swaps
Dated Brent
3,000
98.03

 

 



2013
Two-Way Collars
NYMEX WTI
5,000

 

 

95.00

115.00

2013
Three-Way Collars
NYMEX WTI
7,000

 

 
63.57

83.57

109.04

2013
Three-Way Collars
Dated Brent
13,000

 

 
81.15

100.75

124.68

2013
Put Options (2)
NYMEX WTI
11,000

 
5.97

 

97.60


2014
Swaps
NYMEX WTI
32,000
92.62

 

 



2014
Swaps
Dated Brent
10,000
103.33

 

 



2014
Three-Way Collars
NYMEX WTI
9,000

 

 
75.89

90.89

100.44

2014
Three-Way Collars
Dated Brent
5,000

 

 
84.00

97.20

129.70

2015
Swaps
NYMEX WTI
5,000
88.02

 

 



2015
Swaps
Dated Brent
5,000
99.04

 

 



2015
Three-Way Collars
NYMEX WTI
10,000

 

 
68.50

88.50

92.87

2015
Three-Way Collars
Dated Brent
5,000

 

 
75.00

95.00

112.53

 
(1) 
West Texas Intermediate
(2) 
For put options, we typically pay a premium to the counterparty in exchange for the sale of the instrument. If the index price is below the floor price of the put option, we receive the difference between the floor price and the index price multiplied by the contract volumes less the option premium. If the index price settles at or above the floor price of the put option, we pay only the option premium.


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

As of March 31, 2013, we had entered into the following natural gas derivative instruments:
 
 
 
 
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
Instruments Entered Into as of March 31, 2013
 
 
 
 
 
 
2013
Swaps
  NYMEX HH (1)
60,000
$
4.58

 
$

$

$

2013
Two-Way Collars
NYMEX HH
40,000

 

3.25

5.14

2013
Three-Way Collars
NYMEX HH
100,000

 
3.88

4.75

5.63

2014
Swaps
NYMEX HH
60,000
4.24

 



2014
Three-Way Collars
NYMEX HH
160,000

 
2.64

3.64

5.02

2015
Swaps
NYMEX HH
30,000
4.25

 



2015
Three-Way Collars
NYMEX HH
100,000

 
3.50

4.25

5.01

 
(1) 
Henry Hub

Fair Value Amounts and Gains and Losses on Derivative Instruments   The fair values of derivative instruments in our consolidated balance sheets were as follows: 
Fair Value of Derivative Instruments
 
Asset Derivative Instruments
 
Liability Derivative Instruments
 
March 31,
2013
 
December 31,
2012
 
March 31,
2013
 
December 31,
2012
 
Balance
Sheet
Location
 
Fair
Value
 
Balance Sheet Location
 
Fair
 Value
 
Balance Sheet Location
 
Fair
Value
 
Balance Sheet Location
 
Fair
Value
(millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Derivative Instruments
Current
Assets
 
$
36

 
Current Assets
 
$
63

 
Current Liabilities (1)
 
$
44

 
Current Liabilities
 
$
7

 
Noncurrent Assets
 
13

 
Noncurrent Assets
 
21

 
Noncurrent Liabilities
 
9

 
Noncurrent Liabilities
 
3

Total
 
 
$
49

 
 
 
$
84

 
 
 
$
53

 
 
 
$
10


 (1) Includes $18 million of deferred put option premium.

The effect of derivative instruments on our consolidated statements of operations was as follows: 
 
Three Months Ended
March 31,
 
2013
 
2012
(millions)
 
 
 
Realized Mark-to-Market (Gain) Loss
 
 
 
  Crude Oil
$
8

 
$
34

  Natural Gas
(15
)
 
(11
)
Total Realized Mark-to-Market (Gain) Loss
(7
)
 
23

Unrealized Mark-to-Market (Gain) Loss
 
 
 
  Crude Oil
41

 
92

  Natural Gas
38

 
(19
)
Total Unrealized Mark-to-Market Loss
79

 
73

Total Loss on Commodity Derivative Instruments
$
72

 
$
96

 

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

Accumulated other comprehensive loss (AOCL) at March 31, 2013 included deferred losses of $25 million, net of tax, related to interest rate derivative instruments. This amount will be reclassified to earnings as an adjustment to interest expense over the terms of our senior notes due April 2014 and March 2041.  Approximately $2 million of deferred losses (net of tax) will be reclassified to earnings during the next 12 months and will be recorded as an increase in interest expense.
 
Note 5. Debt

Our debt consists of the following:
 
March 31,
2013
 
 
December 31,
2012
 
 
Debt
 
Interest Rate
 
 
Debt
 
Interest Rate
 
(millions, except percentages)
 
 
 
 
 
 
 
 
 
Credit Facility, due October 14, 2016 (1)
$

 

 
 
$

 

 
CONSOL Installment Payment, due September 30, 2013
328

 
1.79
%
(2) 
 
328

 
1.79
%
(2) 
FPSO Lease Obligation
299

 

 
 
311

 

 
5¼% Senior Notes, due April 15, 2014
200

 
5.25
%
 
 
200

 
5.25
%
 
8¼% Senior Notes, due March 1, 2019
1,000

 
8.25
%
 
 
1,000

 
8.25
%
 
4.15% Senior Notes, due December 15, 2021
1,000

 
4.15
%
 
 
1,000

 
4.15
%
 
7¼% Senior Notes, due October 15, 2023
100

 
7.25
%
 
 
100

 
7.25
%
 
8% Senior Notes, due April 1, 2027
250

 
8.00
%
 
 
250

 
8.00
%
 
6% Senior Notes, due March 1, 2041
850

 
6.00
%
 
 
850

 
6.00
%
 
7¼% Senior Debentures, due August 1, 2097
84

 
7.25
%
 
 
84

 
7.25
%
 
Total
4,111

 
 
 
 
4,123

 
 

 
Unamortized Discount
(14
)
 
 

 
 
(15
)
 
 

 
Total Debt, Net of Discount
4,097

 
 

 
 
4,108

 
 

 
Less Amounts Due Within One Year
 

 
 

 
 
 

 
 

 
Current portion of CONSOL Installment Payment, net of discount
(325
)
 
 

 
 
(324
)
 
 

 
FPSO Lease Obligation
(49
)
 
 

 
 
(48
)
 
 

 
Long-Term Debt Due After One Year
$
3,723

 
 

 
 
$
3,736

 
 

 

(1) 
Our Credit Agreement provides for a $4.0 billion unsecured revolving Credit Facility. The Credit Facility is available for general corporate purposes.
(2) 
Imputed rate based on the prevailing market rates for similar debt instruments at the date of assessment.
 
See Note 6. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.

Note 6.  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, which primarily include assets held in a rabbi trust, 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.
 

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Noble Energy, Inc.
Notes to Consolidated Financial Statements

Commodity Derivative Instruments   Our commodity derivative instruments consist of variable to fixed price commodity swaps, two-way and three-way collars, and put options. We estimate the fair values of these instruments based on 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 (for three-way collars) and the contract floors and ceilings (for two-way and three-way collars) using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 4. 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.
 
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, 2013
 
 
 
 
 
 
 
 
 
Financial Assets
 
 
 
 
 
 
 
 
 
Mutual Fund Investments
$
109

 
$

 
$

 
$

 
$
109

Commodity Derivative Instruments

 
62

 

 
(13
)
 
49

Financial Liabilities
 

 
 

 
 

 
 

 
 

Commodity Derivative Instruments

 
(66
)
 

 
13

 
(53
)
Portion of Deferred Compensation Liability Measured at Fair Value
(174
)
 

 

 

 
(174
)
December 31, 2012
 
 
 
 
 
 
 

 
 

Financial Assets
 

 
 

 
 

 
 

 
 

Mutual Fund Investments
$
103

 
$

 
$

 
$

 
$
103

Commodity Derivative Instruments

 
113

 

 
(29
)
 
84

Financial Liabilities
 

 
 

 
 

 
 

 
 

Commodity Derivative Instruments

 
(39
)
 

 
29

 
(10
)
Portion of Deferred Compensation Liability Measured at Fair Value
(160
)
 

 

 

 
(160
)
 
(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 clauses within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty.

15

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Noble Energy, Inc.
Notes to Consolidated Financial Statements


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. The carrying amount of the CONSOL installment payment approximates fair value because it is discounted at the prevailing market rate for similar debt instruments. As such, we consider the fair value of our CONSOL installment payment to be a Level 2 measurement on the fair value hierarchy. See Note 5. Debt. Fair value information regarding our debt is as follows: 
 
March 31,
2013
 
December 31,
2012
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
(millions)
 
 
 
 
 
 
 
Total Debt, Net of Unamortized Discount (1)
$
3,798

 
$
4,539

 
$
3,797

 
$
4,570

 
(1) 
Excludes Aseng FPSO lease obligation. No floating rate debt was outstanding at March 31, 2013 or December 31, 2012.

Note 7.  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. If a well is deemed to be noncommercial, the well costs are immediately 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: 
 
Three Months Ended March 31, 2013
(millions)
 
Capitalized Exploratory Well Costs, Beginning of Period
$
900

Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves
178

Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves
(8
)
Capitalized Exploratory Well Costs, End of Period
$
1,070


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: 
 
March 31,
2013
 
December 31,
2012
(millions)
 
 
 
Exploratory Well Costs Capitalized for a Period of One Year or Less
$
453

 
$
355

Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling
617

 
545

Balance at End of Period
$
1,070

 
$
900

Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling
13

 
14

 

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

The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of March 31, 2013:
 
 
 
Suspended Since
 
Total
 
2012
 
2011
 
2010 & Prior
(millions)
 
 
 
 
 
 
 
Country/Project:
 
 
 
 
 
 
 
Offshore Equatorial Guinea
 
 
 
 
 
 
 
Carla
$
12

 
$

 
$
12

 
$

Diega
106

 
1

 
46

 
59

Felicita
36

 
1

 
2

 
33

Yolanda
18

 

 
1

 
17

Offshore Cameroon
 

 
 

 
 

 
 

YoYo
47

 
2

 
5

 
40

Offshore Israel
 

 
 

 
 

 
 

Leviathan
113

 
5

 
67

 
41

Leviathan-1 Deep
55

 
27

 
28

 

Tanin 1
33

 
2

 
31

 

Dolphin 1
22

 

 
22

 

Dalit
22

 

 

 
22

Offshore Cyprus
 
 
 
 
 
 
 
Cyprus A-1
64

 
7

 
57

 

Deepwater Gulf of Mexico
 

 
 

 
 

 
 

Gunflint
77

 
23

 

 
54

Other
 

 
 

 
 

 
 

Projects of $10 million or less each
12

 
3

 

 
9

Total
$
617

 
$
71

 
$
271

 
$
275


Carla/Diega Carla is a 2011 crude oil discovery on Block O, Diega (formerly Carmen) is a 2008 condensate and crude oil discovery on Blocks O and I. We are continuing our appraisal program for our Carla discovery. During first quarter of 2013, we spud the Carla I-7 well and continue to review the drilling results of the Carla O-7 well. Further appraisal drilling of Diega is planned for the second half of 2013. We are currently evaluating regional development scenarios for these two discoveries, which includes possible sanctioning of Carla during 2013.
Felicita/Yolanda Felicita is a 2008 condensate and natural gas discovery on Block O. Yolanda is a 2008 condensate and natural gas discovery on Block I. We are currently evaluating regional natural gas development options for these discoveries.
YoYo   YoYo is a 2007 natural gas and condensate discovery. During 2011 we acquired and processed additional 3D seismic information and are continuing evaluations for future drilling potential. We are also working with the government of Cameroon to assess gas commercialization options.
Leviathan   Leviathan is a 2010 natural gas discovery. During 2012, we continued to evaluate the discovery with the successful drilling of both the Leviathan-3 and Leviathan-4 appraisal wells. We have project and commercial teams in place and are in the process of screening multiple development concepts. In 2012, we announced that the partners in the Leviathan Project had agreed in principle on a proposal to sell a 30% working interest in the Leviathan licenses to Woodside Energy Ltd. (Woodside).
Leviathan-1 Deep In January 2012, we returned to the Leviathan-1 well and began drilling toward two deeper intervals in order to evaluate them for the existence of crude oil (Leviathan-1 Deep). We are continuing our evaluation of Leviathan-1 Deep and will integrate the data from the Leviathan-1 Deep well into our model to update our analysis and design a drilling plan specifically to test the deep oil concept. We have secured a drillship with the capabilities necessary to reach the target objective. The drillship is scheduled to arrive in the Eastern Mediterranean at the end of 2013, and we plan to begin drilling an exploratory well shortly after its arrival.
Tanin 1 Tanin 1 is a 2011 natural gas discovery located in the Alon A block, offshore Israel. We and our partners are currently reviewing alternatives for the development of reserves from this asset.

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

Dolphin 1 Dolphin 1 is a 2011 natural gas discovery located in the Hanna license, southwest of the Tamar gas field. We and our partners are currently reviewing alternatives for the development of reserves from this asset.
Dalit   Dalit is a 2009 natural gas discovery. We and our partners are working on a development plan which would include tie-in to the Tamar platform and have submitted a development plan to the Israeli government.
Cyprus During the fourth quarter of 2011, we drilled a successful natural gas exploration well (A-1) in Block 12. We submitted an appraisal plan to the Cyprus government and are reviewing locations for appraisal drilling activities. We plan to drill the A-2 appraisal well during the second half of 2013.
Gunflint   Gunflint (Mississippi Canyon Block 948) is a 2008 crude oil discovery. In July 2012, we drilled a successful Gunflint appraisal well. We have commenced drilling the second Gunflint appraisal well and continue to proceed towards sanctioning a scalable development project in the second half of 2013. First production from Gunflint is targeted for 2015 if we utilize a subsea tieback to an existing host facility or 2017 if a standalone facility is required.
Note 8.  Asset Retirement Obligations
Asset retirement obligation (ARO) consists 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,
 
2013
 
2012
(millions)
 
 
 
Asset Retirement Obligations, Beginning Balance
$
402

 
$
377

Liabilities Incurred
1

 
6

Liabilities Settled
(10
)
 
(2
)
Revision of Estimate
(1
)
 
3

Accretion Expense (1)
7

 
7

Asset Retirement Obligations, Ending Balance
$
399

 
$
391

(1) Accretion expense is included in DD&A expense in the consolidated statements of operations.
Liabilities settled in 2013 relate primarily to onshore US properties sold. See Note 3. Divestitures.
Note 9.  Earnings Per Share
Basic earnings per share of common stock is computed using the weighted average number of shares of common stock outstanding during each period. The diluted earnings per share of common stock include the effect of outstanding stock options, shares of restricted stock, or shares of our common stock held in a rabbi trust (when dilutive). The following table summarizes the calculation of basic and diluted earnings per share:
 
Three Months Ended
March 31,
 
2013
 
2012
(millions, except per share amounts)
 
 
 
Income from Continuing Operations
$
232

 
$
249

 
 
 
 
Weighted Average Number of Shares Outstanding, Basic
179

 
177

Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock and Shares of Common Stock in Rabbi Trust
2

 
3

Weighted Average Number of Shares Outstanding, Diluted
181

 
180

Earnings from Continuing Operations Per Share, Basic
$
1.29

 
$
1.40

Earnings from Continuing Operations Per Share, Diluted
1.28

 
1.39

Number of antidilutive stock options, shares of restricted stock and shares of common stock in rabbi trust excluded from calculation above
3

 
2



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

Common Stock Split   On April 22, 2013, Noble Energy’s Board of Directors approved a two-for-one split of its common stock to be effected in the form of a stock dividend. The stock dividend will be distributed on May 28, 2013 to shareholders of record as of May 14, 2013. Pro forma earnings per share and common shares outstanding, giving retrospective effect to the stock split, is as follows:
 
Three Months Ended March 31,
 
2013
 
2012
 
As Reported
 
Pro Forma
 
As Reported
 
Pro Forma
(millions, except per share amounts)
 
 
 
 
 
 
 
Earnings Per Share, Basic
 
 
 
 
 
 
 
Income from Continuing Operations
$
1.29

 
$
0.65

 
$
1.40

 
$
0.70

Discontinued Operations, Net of Tax
0.17

 
0.08

 
0.08

 
0.04

Net Income
$
1.46

 
$
0.73

 
$
1.48

 
$
0.74

Earnings Per Share, Diluted
 
 
 
 
 
 
 
Income from Continuing Operations
$
1.28

 
$
0.64

 
$
1.39

 
$
0.69

Discontinued Operations, Net of Tax
0.17

 
0.08

 
0.08

 
0.04

Net Income
$
1.45

 
$
0.72

 
$
1.47

 
$
0.73

 
 
 
 
 
 
 
 
Weighted Avg Number of Shares Outstanding
 
 
 
 
 
 
 
Basic
179

 
358

 
177

 
355

Diluted
181

 
362

 
180

 
359


Note 10.  Income Taxes
The income tax provision relating to continuing operations consists of the following: 
 
Three Months Ended
March 31,
 
2013
 
2012
(millions)
 
 
 
Current
$
36

 
$
44

Deferred
50

 
42

Total Income Tax Provision
$
86

 
$
86

Effective Tax Rate
27.1
%
 
25.8
%

Our effective tax rate for the first three months of 2013 increased as compared with the first three months of 2012. This increase is primarily due to a tax contingency recognized during the first quarter of 2013.
In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2008, Equatorial Guinea – 2007, Israel – 2008 and China –2010.
See Note 3. Divestitures for income taxes related to discontinued operations.

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


Note 11.  Segment Information
 
We have operations throughout the world and manage our 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, Sierra Leone and Senegal/Guinea-Bissau, which we exited in the third quarter of 2012); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes China, Falkland Islands, Nicaragua and new ventures. As of March 31, 2013, our remaining North Sea assets were reclassified to assets held for sale, and prior year amounts have been reclassified to exclude the North Sea geographical segment. See Note 3. Divestitures.
 
Consolidated
 
United
States
 
West
Africa
 
Eastern
Mediterranean
 
Other Int'l &
Corporate
(millions)
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2013
 
 
 
 
 
 
 
 
 
Revenues from Third Parties
$
1,083

 
$
716

 
$
273

 
$
51

 
$
43

Income from Equity Method Investees
60

 

 
60

 

 

Total Revenues
1,143

 
716

 
333

 
51

 
43

DD&A
366

 
266

 
54

 
28

 
18

Loss on Commodity Derivative Instruments (1)
72

 
49

 
23

 

 

Income (Loss) from Continuing Operations Before Income Taxes
318

 
243

 
231

 
15

 
(171
)
Three Months Ended March 31, 2012
 

 
 

 
 

 
 

 
 

Revenues from Third Parties
$
1,037

 
$
554

 
$
383

 
$
44

 
$
56

Income from Equity Method Investees
51

 

 
51

 

 

Total Revenues
1,088

 
554

 
434

 
44

 
56

DD&A
294

 
198

 
73

 
5

 
18

Gain (Loss) on Commodity Derivative Instruments (1)
96

 
(9
)
 
105

 

 

Income (Loss) from Continuing Operations Before Income Taxes
335

 
193

 
227

 
32

 
(117
)
March 31, 2013
 

 
 

 
 

 
 

 
 

Total Assets
$
17,667

 
$
11,398

 
$
3,183

 
$
2,631

 
$
455

December 31, 2012
 

 
 

 
 

 
 

 
 

Total Assets
17,509

 
11,199

 
3,063

 
2,572

 
675

(1) See Note 4. Derivative Instruments and Hedging Activities.

Note 12.  Commitments and Contingencies
 
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.

West Virginia Matter  In March 2013, we received seven Notices of Violation (NOV) and two Administrative Orders (Orders) from the West Virginia Department of Environmental Protection Office of Oil and Gas (OOG) regarding the unintentional discharge of a mixture of freshwater and produced water that occurred on or about the evening of February 22, 2013 from one of our permitted water storage facilities in Marshall County, West Virginia. At this time, the OOG has not established a proposed penalty for these NOVs or Orders. Given the 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.

Colorado Matter On April 16, 2013, we received a proposed Early Settlement Agreement (ESA) from Colorado Department of Public Health and Environment's Air Pollution Control Division to resolve allegations of noncompliance with our 2011 Ozone and Non-Ozone season spreadsheet submissions pursuant to Air Quality Control Commission Regulation 7. The ESA, which provides for an opportunity to further discuss the offer of settlement, has not yet been executed. At present, the ESA seeks payment of a reduced penalty of $112,000. 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.


20

Table of Contents

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.  Our MD&A is presented in the following major sections:

Executive Overview;
Operating Outlook;
Results of Operations; and
Liquidity and Capital Resources.
 
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 worldwide producer of crude oil and natural gas. We aim to achieve sustainable growth in value and cash flow through exploration success and the development of a high-quality, diversified, growing portfolio of assets that is balanced between US and international projects, while maintaining a strong balance sheet and ample liquidity levels. We primarily focus on organic growth from exploration and development drilling and augment that with a periodic, opportunistic new business development (mergers and acquisition) capability. We manage the portfolio for superior returns and to ensure geographic portfolio diversification, with periodic divestments of non-core assets. We focus on basins or plays where we have strategic competitive advantage and which we believe generate superior returns.
Our core operating areas are the onshore US (DJ Basin and Marcellus Shale), deepwater Gulf of Mexico, offshore West Africa and offshore Eastern Mediterranean.
Our major development projects typically offer long life, sustained cash flows after investment and attractive financial returns. We maintain a diversified portfolio between US and international assets and strive to maintain a balanced geographic and political risk profile. We also maintain a geographical diversity of production mix among crude oil, US natural gas, and international natural gas.
Our financial results for the first quarter of 2013 included:
net income of $261 million (including $232 million from continuing operations), as compared with $263 million (including $249 million from continuing operations) for first quarter 2012;
loss on commodity derivative instruments of $72 million (including unrealized mark-to-market loss of $79 million) as compared with a loss on commodity derivative instruments of $96 million (including unrealized mark-to-market loss of $73 million) for first quarter 2012;
diluted earnings per share of $1.45, as compared with $1.47 for first quarter 2012;
cash flow provided by operating activities of $705 million, as compared with $741 million for first quarter 2012;
ending cash balance of $1.3 billion, as compared with $1.4 billion at December 31, 2012;
capital spending, on a cash basis, of $806 million as compared with $1.0 billion for first quarter 2012; and
ratio of debt-to-book capital of 33%, unchanged from December 31, 2012
Key highlights for the first quarter of 2013 included:
first production established at Tamar, offshore Israel;
record net sales volumes of 92 MBoe/d from the DJ Basin with 45 MBoe/d from the horizontal program;
drilled extended reach lateral well of 9,978 feet in the DJ Basin, the longest in Colorado history;
signed sales agreements on three non-core divestment packages with expected proceeds exceeding $105 million; and
successful appraisal well at Leviathan, offshore Israel.

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Table of Contents

Tamar Startup
Initial sales from Tamar commenced on March 31, 2013. Just over four years from discovery, the Tamar project is fully operational and delivering significant volumes of natural gas to Israel and represents the first of two major projects targeted for completion in 2013. The natural gas flows from the field through the longest subsea tieback in the world, more than 90 miles to the Tamar platform and then to the Ashdod onshore terminal. Tamar was successfully brought online during the first quarter and currently all five of the subsea wells are producing at stable rates. Each of the five subsea wells is capable of flowing 250 MMcf/d of natural gas. The development is designed to deliver natural gas rates up to one Bcf/d. Volumes will likely reach this maximum capacity during the peak summer demand in the third quarter this year. Tamar is a technological and commercial milestone and will make a significant contribution to our continuing production growth. Sales commenced under a temporary permit and we are working with the government to obtain a final permit as soon as practicable. Our largest purchaser, the Israel Electric Corporation Ltd., recently exercised its option to increase sales over the 15-year contract period from approximately 2.7 Tcf (approximately 1.0 Tcf net) to approximately 3.5 Tcf (approximately 1.3 Tcf net).
Exploration Program Update
We continue to evaluate and build upon our significant exploration inventory in the onshore US, deepwater Gulf of Mexico, offshore West Africa, offshore Eastern Mediterranean and other new venture locations.
We continually evaluate our exploration inventory to provide additional growth opportunities and potential new core areas. In addition, each of our existing core areas has significant remaining exploration upside. We continue to leverage existing activities to improve our exploratory programs in these core areas.
We were in the process of drilling and/or evaluating significant exploratory wells at March 31, 2013 (See Item 1. Financial Statements – Note 7. Capitalized Exploratory Well Costs), and we expect to continue an active exploratory drilling program in the future.
We devote significant capital to our exploration program; approximately 19% of our $3.9 billion capital investment program in 2013 is dedicated to exploration and associated appraisal activities, including leasehold acquisitions. However, 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 project is not economically or operationally viable.
As discussed below, we are currently conducting, or planning to conduct, exploratory drilling activities in previously unexplored areas as well as appraisal activities at several of our discoveries. 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 charged to expense.  Additionally, we may not conduct exploration activities prior to lease expirations. As a result, in a future period, dry hole cost and leasehold impairment charges could be significant.
Updates of our significant exploration activities are as follows: 
Deepwater Gulf of Mexico We hold significant exploration potential in the deepwater Gulf of Mexico. During the first quarter of 2013, we participated in the Central Gulf of Mexico Lease Sale 227 and were high bidder on five deepwater blocks. During the second half of 2013, we plan to drill the Troubadour exploration well (Mississippi Canyon Block 699), an offset to our Big Bend discovery, and spud an additional exploration prospect.
Karish (Offshore Israel) We spud our first exploratory well on the Karish prospect in the Alon C license. Karish is expected to reach total depth in the second quarter of 2013.
Offshore Nicaragua We continue to evaluate our undeveloped acreage and currently plan to spud our first exploration well (Paraiso), targeting an oil play, in the third quarter of 2013. During the first quarter of 2013, we began hosting potential partners in our Houston data room in anticipation of a working interest farmout by the time we spud Paraiso.
Offshore Falkland Islands In March 2013, we assumed operatorship from Falkland Oil and Gas Limited (FOGL) of the Northern Area License and will assume operatorship of the Southern Area License no later than March 2014. We continue to acquire 3D seismic over the Southern Area License as part of the exploration program.
Major Development Project Updates
During the first quarter of 2013, we successfully brought the Tamar project online as we continue to advance our major development projects, many of which have resulted from our exploration success. We expect these projects to deliver significant growth in production over the next several years. Updates on our significant development projects are as follows:
Sanctioned Development Projects
Horizontal Niobrara (Onshore US)   We have increased our horizontal drilling activity by targeting the Niobrara formation in the Wattenberg area, resulting in a significant positive impact on our current production volumes. We expect to drill over 300 horizontal

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wells during 2013 and we continue to move into areas of higher liquids content. We spud 56 horizontal wells during the first quarter of 2013, including ten extended-reach lateral wells.
We continue to expand our horizontal Niobrara development activities into northern Colorado, where recent results indicate recoveries comparable to those in the Wattenberg area. We plan to spud over 60 wells during 2013 as we work to delineate our remaining acreage position in northern Colorado.
Marcellus Shale (Onshore US)   We continue developing the field with longer lateral wells, enhanced completion design and optimal well placements. We have drilled to total depth 15 wet gas wells thus far in 2013.
Although we have reduced drilling in the dry gas area due to the current natural gas price environment, the dry gas portion of the program continues to deliver economically attractive returns due to strong production performance, high net revenue interests, and access to market. The CONSOL Carried Cost Obligation is currently suspended due to low natural gas prices. See Liquidity and Capital Resources - Contractual Obligations below.
Alen (Blocks O and I, Offshore Equatorial Guinea) The production and injection wells have been completed and platform and subsea installations continue on schedule. First production is expected to commence in the third quarter of 2013 at 18 MBbl/d, net. Alen will be our second major project to be completed in 2013.
Unsanctioned Development Projects
Gunflint (Deepwater Gulf of Mexico)  We have commenced drilling the second Gunflint appraisal well and continue to proceed towards sanctioning a scalable development project in the second half of 2013. First production from Gunflint is targeted for 2015 if we utilize a subsea tieback to an existing host facility or 2017 if a standalone facility is required.
Big Bend (Deepwater Gulf of Mexico) We anticipate sanctioning a development plan for Big Bend during 2013 with first production targeted in late 2015 or early 2016.
Leviathan (Offshore Israel)   The Leviathan #4 appraisal well was drilled to total depth and encountered 454 net feet of natural gas pay in multiple intervals, the thickest net pay of any well drilled to date at Leviathan. The results have enhanced our understanding of the reservoir and we continue our evaluation of multiple development concepts.
We continue working with Woodside Energy Ltd. towards reaching a definitive agreement to sell a 30% working interest in the Leviathan licenses. Each of the current Leviathan partners is expected to participate as a seller to Woodside. We expect to convey a 9.66% working interest, reducing our working interest to 30%, and continue as upstream operator.
Carla and Diega (Offshore Equatorial Guinea) We continue our appraisal program for our Carla discovery where we are reviewing drilling results of the Carla O-7 and have spud the Carla I-7 during the first quarter of 2013. Further appraisal drilling of Diega is planned for the second half of 2013.
Non-Core Divestiture Program
Our non-core divestiture program is designed to generate organizational and operational efficiencies as well as cash for use in our capital investment program. Divestitures of non-core properties allow us to allocate capital and employee resources to high-value and high-growth areas.  Further, proceeds from divestitures will provide additional flexibility in the implementation of our international and deepwater Gulf of Mexico exploration and development programs and our horizontal drilling activities in the DJ Basin and Marcellus Shale.
During the first quarter of 2013, we closed the sale of our 13% non-operated working interest in the Cook field located in the UK sector of the North Sea. The sale resulted in a $37 million gain based on total net sale proceeds of $38 million for the field. We also closed the sale of certain crude oil and natural gas properties in the Gulf Coast area for total sale proceeds of $55 million. We continue to market packages of non-core onshore US properties and our remaining North Sea properties. See Item 1. Financial Statements – Note 3. Divestitures.
On occasion we will withdraw from all operations in a country. The reasons for withdrawing from a country vary. It may be based on a decision to allocate resources to other projects, or result from government action such as the Ecuadorian government's termination of our Block 3 PSC in 2010. Some exploration programs simply do not result in the discovery of a commercial quantity of reserves. Withdrawing from a country usually involves two parallel processes: concluding exploration and production operations; and winding up local business activities. Winding up local business activities may involve completing outstanding tax audits and filing final tax returns, resolving employment related matters, settling claims and dissolving local entities such as subsidiaries or branches.
We are currently planning to withdraw from the United Kingdom and the Dutch North Sea and are winding up local business activities in Ecuador and Argentina. At this time, we do not believe that any of the activities associated with these areas will have a material effect on our financial position, results of operations or cash flows.

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Sales Volumes
On a BOE basis, total sales volumes from continuing operations were 4% higher for the first quarter of 2013 as compared with the first quarter of 2012, and our mix of sales volumes was 48% global liquids, 24% international natural gas, and 28% US natural gas. Onshore US sales volume increases were due to our horizontal drilling programs in the DJ Basin and the Marcellus Shale. In the deepwater Gulf of Mexico, South Raton was offline for an extended period during the quarter due to mechanical issues and Swordfish production was impacted by a temporary loss of power. Also, we had lower sales volumes from Alba, offshore Equatorial Guinea, due to fewer liftings in first quarter of 2013. See Results of Operations – Revenues below.
Commodity Price Changes and Hedging
US natural gas prices began to increase during the quarter; US average realized natural gas prices for the first quarter of 2013 increased 26% as compared with the first quarter of 2012. Total consolidated average realized crude oil prices for the first quarter of 2013 decreased 8% as compared with the first quarter of 2012.
We have hedged approximately 45% of our expected global crude oil production and 44% of our expected domestic natural gas production for the remainder of 2013. See Item 1. Financial Statements – Note 4. Derivative Instruments and Hedging Activities.
OPERATING OUTLOOK
2013 Production   Our expected crude oil, natural gas and NGL production for 2013 may be impacted by several factors including:
overall level and timing of capital expenditures which, as discussed below and dependent upon our drilling success, are expected to maintain our near-term production volumes;
timing of ramp up of the Tamar field and other major development projects completion and initial production, including Alen, offshore Equatorial Guinea, which is scheduled to begin producing in the third quarter of 2013;
ongoing development activity in the Wattenberg area and horizontal drilling in the Niobrara formation in the DJ Basin;
pace of increase of development activity in both wet gas and dry gas areas of the Marcellus Shale;
divestments of non-core operating assets;
natural field decline in the deepwater Gulf of Mexico and Mid-Continent areas of our US operations, the Mari-B, Noa and Pinnacles fields offshore Israel, and Alba and Aseng fields offshore Equatorial Guinea;
variations in sales volumes of natural gas from the Alba field in Equatorial Guinea related to potential downtime at the methanol, LPG and/or LNG plants;
Israeli demand for electricity which affects demand for natural gas as fuel for power generation, market growth, and production rates from Tamar, Mari-B, Noa and Pinnacles fields, offshore Israel;
variations in West Africa sales volumes due to potential FPSO downtime and timing of liftings;
potential hurricane-related volume curtailments in the deepwater Gulf of Mexico;
potential winter storm-related volume curtailments in the Rocky Mountain and/or Marcellus Shale areas of our US operations;
third party facilities reliability in the Wattenberg and/or Rocky Mountain areas of our US properties which may cause restrictions or interruptions in mid-stream processing facilities;
potential pipeline and processing facility capacity constraints in the Rocky Mountain and/or Marcellus Shale areas of our US operations;
potential drilling and/or hydraulic fracturing permit delays due to future regulatory changes;
potential purchases of producing properties; and
potential shut-in of US producing properties if storage capacity becomes unavailable.
2013 Capital Investment Program Our total capital investment program for 2013 is estimated at $3.9 billion. The capital investment program allocates approximately 60% to onshore US, 6% for deepwater Gulf of Mexico, 10% to the Eastern Mediterranean, 15% to West Africa and 9% to corporate and other. Exploration and appraisal activity within these geographic areas is expected to receive 19% of total capital.
The 2013 capital investment program will exceed operating cash flows and is expected to be funded from cash flows from operations, cash on hand, and borrowings under our revolving credit facility and/or other financing such as an issuance of long-term debt. Funding may also be provided by proceeds from divestment of non-core assets. See Liquidity and Capital Resources – Financing Activities below.

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We will evaluate the level of capital spending and remain flexible throughout the year based on the following factors, among others: 
commodity prices, including price realizations on specific crude oil and natural gas production including the impact of NGLs;
cash flows from operations;
operating and development costs and possible inflationary pressures;
permitting activity in the deepwater Gulf of Mexico;
drilling results;
CONSOL Carried Cost Obligation (See Liquidity and Capital Resources - Contractual Obligations);
property acquisitions and divestitures;
increase in exploration activities in new areas, including offshore Sierra Leone, Nicaragua and the Falkland Islands;
availability of financing;
potential legislative or regulatory changes regarding the use of hydraulic fracturing;
potential changes in the fiscal regimes of the US and other countries in which we operate; and
impact of new laws and regulations, including implementation of the Dodd-Frank Wall Street Reform and Consumer Protection Act, which has resulted in significant derivatives regulations and disclosure requirements, on our business practices.
Potential for Asset Impairments
Commodity prices remain volatile. A decline in future NYMEX crude oil or natural gas prices could result in impairment charges. The cash flow model that we use to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production, market outlook on forward commodity prices, operating and development costs, and interest rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward crude oil or natural gas prices alone could result in impairment.
Additionally, we are currently marketing certain non-core onshore US properties. If the properties are reclassified as assets held for sale, they will be valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less costs to sell.
Occasionally, well mechanical problems arise, which can reduce production and potentially result in reductions in proved reserves estimates. For example, our South Raton development in the deepwater Gulf of Mexico is currently experiencing mechanical issues and we are conducting remediation efforts. South Raton had a net book value of approximately $115 million at March 31, 2013.
Hydraulic Fracturing Update
The practice of hydraulic fracturing in shale formations is the subject of significant focus among some environmentalists, local, state, and federal policy makers, and the general public.
Although hydraulic fracturing is regulated primarily at the state level, local governments and the federal government are increasingly active on the matter. For example, the Federal Bureau of Land Management is presently developing new regulations related to hydraulic fracturing processes on federal lands. Additionally, in 2012 the City of Longmont, Colorado voted to ban hydraulic fracturing activities within city limits. And, in March 2013, the Fort Collins, Colorado, City Council also voted to ban hydraulic fracturing activities within city limits. The State of Colorado, through the Colorado Oil and Gas Conservation Commission, and with oil and gas industry support, has opposed such bans.
Our current activities are focused outside these jurisdictions, primarily in Weld County, Colorado. The local initiatives referenced above represent a focused effort by those who oppose oil and gas development to impact public policy decisions and direction. Therefore, they remain a concern for us because their efforts could lead to statewide initiatives related to hydraulic fracturing.
An outright ban on hydraulic fracturing or a significant increase in local regulation in the State of Colorado would have a negative impact on us, and it would also significantly impact the State of Colorado via a reduction in private investment, employment opportunities, and state and local government revenues. We continue to monitor new and proposed legislation and regulations to assess the potential impact on our operations. We are currently evaluating the possible impact any proposed rules, such as those described above, could have on our business. Certain federal, state or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could potentially result in substantial incremental operating, capital and compliance costs as well as delay our ability to develop oil and gas reserves.
Update on Israel's Natural Gas Economy
The Israeli Antitrust Commissioner (Commissioner) has been actively engaged to encourage competition in developing Israel's natural gas resources. The Commissioner ruled that all domestic natural gas sales contracts are subject to review and approval

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of the antitrust authority and has intervened in the terms of long term contracts with certain consumers. In addition, we are in discussions with the antitrust authority relating to an alleged restrictive arrangement with respect to the acquisition agreement of the Leviathan licenses. The Commissioner has also publicly expressed concerns regarding ownership concentration in exploration blocks and development projects and its potential impacts on a competitive domestic natural gas price environment and end user electricity costs. Commissioner decisions and actions to increase competition could result in our being required to divest certain assets, reduce or relinquish revenue interests, and implement equity marketing of production.
In addition, the government is in the process of finalizing an export policy. We are monitoring current policy-making activities to assess the possible impact, positive or negative, of any resulting laws or regulations on our business.
Certain changes in Israel's fiscal and/or regulatory regimes occurring as a result of Antitrust Commission rulings or government policy on exports could delay or reduce the profitability of our Tamar and/or Leviathan development projects and render future exploration and development projects uneconomic. Our dependency on the Israeli government to make decisions to reduce these uncertainties may have an impact on the expected timing of our developments.