form10q.htm


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

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

For the quarterly period ended March 31, 2012

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
 
Graphic
 
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 x    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 x    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 x
 
As of April 6, 2012, there were 177,787,421 shares of the registrant’s common stock,
par value $3.33 1/3 per share, outstanding.
 


 
 

 
 
Table of Contents
 
Part I. Financial Information 3
   
Item 1. Financial Statements  3
   
Consolidated Statements of Operations
   
Consolidated Statements of Comprehensive Income
   
Consolidated Balance Sheets   
   
Consolidated Statements of Cash Flows    
   
Consolidated Statements of Shareholders' Equity
   
Notes to Consolidated Financial Statements 
   
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations 19 
   
Item 3.  Quantitative and Qualitative Disclosures About Market Risk    35 
   
Item 4.  Controls and Procedures 36 
   
Part II. Other Information   36 
   
Item 1.  Legal Proceedings  36 
   
Item 1A.  Risk Factors  36 
   
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 37 
   
Item 3. Defaults Upon Senior Securities     37 
   
Item 4. Mine Safety Disclosures   37 
   
Item 5.  Other Information 37 
   
Item 6.  Exhibits  37 
   
Signatures 37 
   
Index to Exhibits   38 
 

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,
 
   
2012
   
2011
 
Revenues
           
Oil, Gas and NGL Sales
  $ 1,112     $ 830  
Income from Equity Method Investees
    53       48  
Other Revenues
    -       21  
Total
    1,165       899  
Costs and Expenses
               
Production Expense
    179       142  
Exploration Expense
    63       70  
Depreciation, Depletion and Amortization
    312       221  
General and Administrative
    98       83  
Other Operating (Income) Expense, Net
    12       36  
Total
    664       552  
Operating Income
    501       347  
Other (Income) Expense
               
Loss on Commodity Derivative Instruments
    96       286  
Interest, Net of Amount Capitalized
    32       16  
Other Non-Operating (Income) Expense, Net
    (1 )     8  
Total
    127       310  
Income Before Income Taxes
    374       37  
Income Tax Provision
    111       23  
Net Income
  $ 263     $ 14  
                 
Earnings Per Share, Basic
  $ 1.48     $ 0.08  
Earnings Per Share, Diluted
    1.47       0.08  
                 
Weighted Average Number of Shares Outstanding, Basic
    177       176  
Weighted Average Number of Shares Outstanding, Diluted
    180       178  

The accompanying notes are an integral part of these financial statements.
 
 
Noble Energy, Inc.
Consolidated Statements of Comprehensive Income
(in millions)
(unaudited)
 
   
Three Months Ended
March 31,
 
   
2012
   
2011
 
Net Income
  $ 263     $ 14  
Other Items of Comprehensive Income (Loss)
               
Interest Rate Cash Flow Hedges
               
Unrealized Change in Fair Value
    -       23  
Less Tax Provision
    -       (8 )
Net Change in Other
    2       2  
Other Comprehensive Income
    2       17  
Comprehensive Income
  $ 265     $ 31  

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

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

   
March 31,
   
December 31,
 
   
2012
   
2011
 
ASSETS
 
Current Assets
           
Cash and Cash Equivalents
  $ 1,143     $ 1,455  
Accounts Receivable, Net
    919       783  
Other Current Assets
    330       180  
Total Current Assets
    2,392       2,418  
Property, Plant and Equipment
               
Oil and Gas Properties (Successful Efforts Method of Accounting)
    18,527       17,703  
Property, Plant and Equipment, Other
    317       294  
Total Property, Plant and Equipment, Gross
    18,844       17,997  
Accumulated Depreciation, Depletion and Amortization
    (5,460 )     (5,215 )
Total Property, Plant and Equipment, Net
    13,384       12,782  
Goodwill
    696       696  
Other Noncurrent Assets
    592       548  
Total Assets
  $ 17,064     $ 16,444  
                 
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
Current Liabilities
               
Accounts Payable - Trade
  $ 1,457     $ 1,343  
Other Current Liabilities
    951       925  
Total Current Liabilities
    2,408       2,268  
Long-Term Debt
    4,088       4,100  
Deferred Income Taxes, Noncurrent
    2,216       2,059  
Other Noncurrent Liabilities
    819       752  
Total Liabilities
    9,531       9,179  
                 
Commitments and Contingencies
               
                 
Shareholders’ Equity
               
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized, None Issued
    -       -  
Common Stock - Par Value $3.33 1/3 per share; 250 Million Shares Authorized; 198 Million and 197 Million Shares Issued, Respectively
    659       656  
Additional Paid in Capital
    2,549       2,497  
Accumulated Other Comprehensive Loss
    (98 )     (100 )
Treasury Stock, at Cost; 19 Million Shares
    (651 )     (638 )
Retained Earnings
    5,074       4,850  
Total Shareholders’ Equity
    7,533       7,265  
Total Liabilities and Shareholders’ Equity
  $ 17,064     $ 16,444  

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

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

 
 
Three Months Ended
March 31,
 
 
 
2012
   
2011
 
Cash Flows From Operating Activities
 
 
   
 
 
Net Income
  $ 263     $ 14  
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
               
Depreciation, Depletion and Amortization
    312       221  
Dry Hole Cost
    1       22  
Deferred Income Taxes
    32       11  
Dividends (Income) from Equity Method Investees, Net
    (29 )     (23 )
Unrealized Loss on Commodity Derivative Instruments
    73       303  
Other Adjustments for Noncash Items Included in Income
    30       36  
Changes in Operating Assets and Liabilities
               
(Increase) in Accounts Receivable
    (135 )     (9 )
(Increase) in Other Current Assets
    (5 )     (17 )
Increase in Accounts Payable
    190       28  
Increase (Decrease) in Current Income Taxes Payable
    5       (71 )
(Decrease) in Other Current Liabilities
    (26 )     (54 )
Other Operating Assets and Liabilities, Net
    30       23  
Net Cash Provided by Operating Activities
    741       484  
                 
Cash Flows From Investing Activities
               
Additions to Property, Plant and Equipment
    (1,018 )     (578 )
Additions to Equity Method Investments
    (14 )     -  
Proceeds from Divestitures
    -       3  
Net Cash Used in Investing Activities
    (1,032 )     (575 )
                 
Cash Flows From Financing Activities
               
Exercise of Stock Options
    27       23  
Excess Tax Benefits from Stock-Based Awards
    12       8  
Dividends Paid, Common Stock
    (39 )     (32 )
Purchase of Treasury Stock
    (13 )     (16 )
Proceeds from Credit Facilities
    -       120  
Repayment of Credit Facilities
    -       (470 )
Proceeds from Issuance of Senior Long-Term Debt, Net
    -       836  
Settlement of Interest Rate Derivative Instrument
    -       (40 )
Repayment of Capital Lease Obligation
    (8 )     -  
Net Cash Provided By (Used In) Financing Activities
    (21 )     429  
Increase (Decrease) in Cash and Cash Equivalents
    (312 )     338  
Cash and Cash Equivalents at Beginning of Period
    1,455       1,081  
Cash and Cash Equivalents at End of Period
  $ 1,143     $ 1,419  
 
The accompanying notes are an integral part of these financial statements.
 
 
Noble Energy, Inc.
Consolidated Statements of Shareholders' Equity
(millions)
 (unaudited)

   
Common
Stock
   
Additional
Paid in
Capital
   
Acumulated Other
Comprehensive
Loss
   
Treasury
Stock at
Cost
   
Retained
Earnings
   
Total
Shareholders'
Equity
 
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  
Restricted Stock Awards, Net
    1       (1 )     -       -       -       -  
Dividends (22 cents per share)
    -       -       -       -       (39 )     (39 )
Changes in Treasury Stock, Net
    -       -       -       (13 )     -       (13 )
Net Change in Other
    -       -       2       -       -       2  
March 31, 2012
  $ 659     $ 2,549     $ (98 )   $ (651 )   $ 5,074     $ 7,533  
                                                 
December 31, 2010
  $ 651     $ 2,385     $ (104 )   $ (624 )   $ 4,540     $ 6,848  
Net Income
    -       -       -       -       14       14  
Stock-based Compensation
    -       14       -       -       -       14  
Exercise of Stock Options
    2       21       -       -       -       23  
Tax Benefits Related to Exercise of Stock Options
    -       8       -       -       -       8  
Restricted Stock Awards, Net
    1       (1 )     -       -       -       -  
Dividends (18 cents per share)
    -       -       -       -       (32 )     (32 )
Changes in Treasury Stock, Net
    -       -       -       (16 )     -       (16 )
Interest Rate Cash Flow Hedges
                                               
Unrealized Change in Fair Value
    -       -       15       -       -       15  
Net Change in Other
    -       -       2       -       -       2  
March 31, 2011
  $ 654     $ 2,427     $ (87 )   $ (640 )   $ 4,522     $ 6,876  

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

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 U.S., 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, 2012 and December 31, 2011 and for the three months ended March 31, 2012 and 2011 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, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012. Certain reclassifications of amounts previously reported have been made to conform to current year presentations. 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, 2011.
 
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.
 
Statements of Operations Information   Other statements of operations information is as follows:
 
   
Three Months Ended
March 31,
 
 
 
2012
   
2011
 
(millions)
           
Other Revenues (1)
  $ -     $ 21  
Production Expense
               
Lease Operating Expense
  $ 118     $ 92  
Production and Ad Valorem Taxes
    38       32  
Transportation and Gathering Expense
    23       18  
Total
  $ 179     $ 142  
Other Operating (Income) Expense, Net
               
Deepwater Gulf of Mexico Moratorium Expense (2)
  $ -     $ 18  
Electricity Generation Expense (1)
    -       17  
Other, Net
    12       1  
Total
  $ 12     $ 36  
Other Non-Operating (Income) Expense, Net
               
Deferred Compensation Expense (3)
  $ 3     $ 10  
Interest Income
    -       (3 )
Other (Income) Expense, Net
    (4 )     1  
Total
  $ (1 )   $ 8  
 
(1)
Other revenues for first quarter 2011 consist of electricity sales from the Machala power plant located in Machala, Ecuador. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including depreciation and changes in the allowance for doubtful accounts. In May 2011, we transferred our assets in Ecuador to the Ecuadorian government.
 
(2)
Amount relates to rig stand-by expense incurred prior to receiving a permit to resume drilling activities in the deepwater Gulf of Mexico in 2011. 
 
(3)
Amounts represent increases in the fair value of shares of our common stock held in a rabbi trust.
 
 
Noble Energy, Inc.
Notes to Consolidated Financial Statements
 
Balance Sheet Information   Other balance sheet information is as follows:
   
March 31,
   
December 31,
 
 
 
2012
   
2011
 
(millions)
           
Accounts Receivable, Net
           
Commodity Sales
  $ 467     $ 356  
Joint Interest Billings
    344       313  
Other
    117       123  
Allowance for Doubtful Accounts
    (9 )     (9 )
Total
  $ 919     $ 783  
Other Current Assets
               
Inventories, Current
  $ 77     $ 78  
Commodity Derivative Assets, Current
    17       10  
Deferred Income Taxes, Net, Current (1)
    159       41  
Probable Insurance Claims (2)
    22       15  
Prepaid Expenses and Other Current Assets, Current
    55       36  
Total
  $ 330     $ 180  
Other Noncurrent Assets
               
Equity Method Investments
  $ 376     $ 329  
Mutual Fund Investments
    108       99  
Commodity Derivative Assets, Noncurrent
    22       37  
Other Assets, Noncurrent
    86       83  
Total
  $ 592     $ 548  
Other Current Liabilities
               
Production and Ad Valorem Taxes
  $ 123     $ 121  
Commodity Derivative Liabilities, Current
    119       76  
Income Taxes Payable
    131       127  
Asset Retirement Obligations, Current
    41       33  
Interest Payable
    41       56  
CONSOL Installment Payment (3)
    325       324  
Current Portion of FPSO Lease Obligation
    48       45  
Other
    123       143  
Total
  $ 951     $ 925  
Other Noncurrent Liabilities
               
Deferred Compensation Liabilities, Noncurrent
  $ 237     $ 222  
Asset Retirement Obligations, Noncurrent
    350       344  
Accrued Benefit Costs, Noncurrent
    90       88  
Commodity Derivative Liabilities, Noncurrent
    29       7  
Other
    113       91  
Total
  $ 819     $ 752  
 
 (1)
Increase from December 31, 2011 is due to reclassification of deferred income tax assets from long-term to short-term as certain foreign entities are estimated to begin utilizing net operating loss carryforwards in 2012 and 2013.
 
 (2)
Amounts represent the costs incurred to date of the Leviathan-2 appraisal well in excess of the insurance deductible and insurance proceeds received to date.
 
 (3)
See Note 3. Acquisitions and Note 4. Debt.
 
Changes in Shareholders’ Equity   On April 24, 2012, our shareholders voted to approve an amendment to the Company’s Certificate of Incorporation to (i) increase the number of authorized shares of our common stock from 250 million to 500 million shares and (ii) reduce the par value of the Company’s common stock from $3.33 1/3 per share to $0.01 per share.
 
 
Noble Energy, Inc.
Notes to Consolidated Financial Statements
 
Recently Issued Accounting Standards Updates   In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2011-04: Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (ASU 2011-04). ASU 2011-04 clarifies application of fair value measurement and disclosure requirements and is effective for annual and interim periods beginning after December 15, 2011. As of March 31, 2012, we have adopted the provisions of ASU 2011-04, which did not impact our consolidated financial statements. The only impact was to our fair value disclosures.
 
In December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities (ASU 2011-11). ASU 2011-11 requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 is effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on our financial position and results of operations.
 
Note 3.   Acquisitions
 
Marcellus Shale Joint Venture   On September 30, 2011, we closed an agreement with a subsidiary of CONSOL Energy Inc. (CONSOL) for the development of Marcellus Shale properties in southwest Pennsylvania and northwest West Virginia. Under the agreement, we acquired a 50% interest in approximately 628,000 net undeveloped acres, certain producing properties, and existing infrastructure, such as pipeline and gathering facilities, for approximately $1.3 billion, including post-closing adjustments. We and CONSOL also formed CONE Gathering LLC (CONE) to own and operate the existing and future infrastructure. We have paid a total of $596 million as of March 31, 2012, and, other than post-closing adjustments, the remainder will be paid in two annual installments. See Note 4. Debt.
 
As part of the joint venture transaction, 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, up to approximately $2.1 billion (CONSOL Carried Cost Obligation), which is expected to be paid out over approximately eight years or more. 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 will remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. The CONSOL Carried Cost Obligation is currently suspended due to low natural gas prices.
 
As a result of the transaction, we recorded the following:

 
 
March 31,
 
 
 
2012
 
(millions)
     
Unproved Oil and Gas Properties
  $ 853  
Proved Oil and Gas Properties
    386  
Investment in CONE Gathering LLC
    69  
Total Assets Acquired (1)
  $ 1,308  

(1) Total reflects impact of $17 million imputed discount on CONSOL installment payments.
 
We used an income approach to estimate the fair value of the proved oil and gas properties as of the acquisition date. We utilized a discounted cash flow model which took into account the following inputs to arrive at estimates of future net cash flows:
 
 
estimated quantities of crude oil and natural gas reserves prepared by our qualified petroleum engineers;
 
 
management’s estimates of future commodity prices based on NYMEX Henry Hub natural gas futures prices and adjusted for estimated location and quality differentials;
 
 
estimated future production rates based on our experience with similar properties which we operate; and
 
 
estimated timing and amounts of future operating and development costs based on our experience with similar properties which we operate.
 
We discounted the resulting future net cash flows using a market-based weighted average cost of capital rate determined appropriate at the acquisition date. The fair value of the proved producing properties is considered a Level 3 fair value measurement.
 
Certain data necessary to complete the final purchase price allocation for proved oil and gas properties is not yet available, and includes, but is not limited to, final appraisals of assets acquired and liabilities assumed. We expect to complete the final purchase price allocation during the 12-month period following the acquisition date, during which time the preliminary allocation may be revised.
 
 
Noble Energy, Inc.
Notes to Consolidated Financial Statements
 
Note 4. Debt
 
Our debt consists of the following:
 
   
March 31,
   
December 31,
 
 
 
2012
   
2011
 
 
 
Debt
   
Interest Rate
   
Debt
   
Interest Rate
 
(millions, except percentages)
                       
Credit Facility, due October 14, 2016 (1)
  $ -       -     $ -       -  
CONSOL Installment Payments, due September 30, 2012 and 2013
    656       1.76 % (2)     656       1.76 % (2)
FPSO Lease Obligation
    344       -       355       -  
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
    4,484               4,495          
Unamortized Discount
    (23 )             (26 )        
Total Debt, Net of Discount
    4,461               4,469          
Less Amounts Due Within One Year
                               
CONSOL Installment Payment, due September 30, 2012, net of discount
    (325 )             (324 )        
FPSO Lease Obligation
    (48 )             (45 )        
Long-Term Debt Due After One Year
  $ 4,088             $ 4,100          
 
(1)  Our Credit Agreement provides for a $3.0 billion unsecured five-year revolving credit facility. The Credit Facility is available for general corporate purposes.
 
(2) Imputed rate.
 
See Note 6. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our debt.
 
Note 5.  Derivative Instruments and Hedging Activities
 
Objective and Strategies for Using Derivative Instruments   In order to mitigate the effect of commodity price uncertainty 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 basis swaps.
 
The fixed price swap, two-way collar, and basis swap contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed strike price or floor price. We would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price or ceiling price. The amount payable by us, if the floating price is above the fixed or ceiling price, is the product of the notional quantity per calculation period and the excess of the floating price over the fixed or ceiling price in respect of each calculation period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional quantity per calculation period and the excess of the fixed or floor price over the floating price in respect of each calculation period.
 
A three-way collar consists of a two-way collar contract combined with a put option contract sold by us with a strike price below the floor price of the two-way collar.  We receive price protection at the purchased put option floor price of the two-way collar if commodity prices are above the sold put option strike price. If commodity prices fall below the sold put option strike price, we receive the cash market price plus the delta between the two put option strike prices. This type of instrument allows us to capture more value in a rising commodity price environment, but limits our benefits in a downward commodity price environment.
 
We also may enter into forward contracts to hedge anticipated exposure to interest rate risk associated with public debt financing.
 
 
Noble Energy, Inc.
Notes to Consolidated Financial Statements
 
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.
 
Counterparty Credit Risk   Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with a diversified group of highly rated major banks or market participants, and we monitor and manage our level of financial exposure. Our commodity derivative contracts are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election.
 
We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices or higher interest rates, and could incur a loss.
 
Interest Rate Derivative Instrument   In January 2010, we entered into an interest rate forward starting swap to effectively fix the cash flows related to interest payments on our anticipated March 2011 debt issuance. During first quarter 2011, the fair value of the swap increased and we recognized a gain of $23 million, net of tax, in AOCL. On February 15, 2011 we settled the interest rate swap, which had a net liability position of $40 million at the time of settlement. Approximately $26 million, net of tax, was recorded in accumulated other comprehensive loss (AOCL) and is being reclassified to interest expense over the term of the notes. The ineffective portion of the interest rate swap was de minimis.
 
Unsettled Derivative Instruments   As of March 31, 2012, we had entered into the following crude oil derivative instruments:
 
             
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
 
Instruments Entered Into as of March 31, 2012
                         
2012
Swaps
NYMEX WTI  (1)
    5,000     $ 91.84     $ -     $ -     $ -  
2012
Swaps
Dated Brent
    8,000       89.06       -       -       -  
2012
Three-Way Collars
 NYMEX WTI
    23,000       -       61.09       83.04       101.66  
2012
Three-Way Collars
 Dated Brent
    3,000       -       70.00       95.83       105.00  
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
    5,000       -       65.00       85.00       113.63  
2013
Three-Way Collars
 Dated Brent
    26,000       -       82.88       100.86       127.32  
2014
Swaps
Dated Brent
    3,000       107.15       -       -       -  
2014
Three-Way Collars
 Dated Brent
    10,000       -       85.00       98.50       129.24  
 
(1)
West Texas Intermediate
 
As of March 31, 2012, 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, 2012
                             
2012
Swaps
NYMEX HH (1)
    30,000     $ 5.10     $ -     $ -     $ -  
2012
Two-Way Collars
NYMEX HH
    40,000       -       -       3.25       5.14  
2012
Three-Way Collars
NYMEX HH
    110,000       -       4.44       5.25       6.66  
2013
Swaps
NYMEX HH
    30,000       5.25       -       -       -  
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  
 
(1)
Henry Hub
 
 
Noble Energy, Inc.
Notes to Consolidated Financial Statements
 
As of March 31, 2012, we had entered into the following natural gas basis swaps:
 
Settlement
Period
Index
Index Less Differential
 
MMBtu Per Day
   
Weighted Average
Differential
 
2012
IFERC CIG (1)
 NYMEX HH
    150,000     $ (0.52 )

(1)
Colorado Interstate Gas – Northern System
 
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,
 
December 31,
 
March 31,
 
December 31,
 
   
2012
 
2011
 
2012
 
2011
 
 
 
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
  $ 17  
Current Assets
  $ 10  
Current Liabilities
  $ 119  
Current Liabilities
  $ 76  
   
Noncurrent Assets
    22  
Noncurrent Assets
    37  
Noncurrent Liabilities
    29  
Noncurrent Liabilities
    7  
Total
 
 
  $ 39  
 
  $ 47  
 
  $ 148  
 
  $ 83  
 
The effect of derivative instruments on our consolidated statements of operations was as follows:
 
 
 
Three Months Ended
March 31,
 
 
 
2012
   
2011
 
(millions)
           
Realized Mark-to-Market (Gain) Loss
  $ 23     $ (17 )
Unrealized Mark-to-Market Loss
    73       303  
Total Loss on Commodity Derivative Instruments
  $ 96     $ 286  
 
AOCL at March 31, 2012 included deferred losses of $26 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 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.
 
Commodity Derivative Instruments   Our commodity derivative instruments consist of variable to fixed price commodity swaps, two-way and three-way collars, and basis swaps. 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 5. Derivative Instruments and Hedging Activities.
 
 
Noble Energy, Inc.
Notes to Consolidated Financial Statements
 
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, 2012
 
 
   
 
   
 
   
 
   
 
 
Financial Assets
 
 
   
 
   
 
   
 
   
 
 
Mutual Fund Investments
  $ 108     $ -     $  -     $ -     $ 108  
Commodity Derivative Instruments
    -       105       -       (66 )     39  
Financial Liabilities
                                       
Commodity Derivative Instruments
    -       (214 )     -       66       (148 )
Portion of Deferred Compensation
                                       
Liability Measured at Fair Value
    (172 )     -       -       -       (172 )
December 31, 2011
 
 
                 
Financial Assets
                                       
Mutual Fund Investments
  $ 99     $ -     $ -     $ -     $ 99  
Commodity Derivative Instruments
    -       99       -       (52 )     47  
Financial Liabilities
                                       
Commodity Derivative Instruments
    -       (135 )     -       52       (83 )
Portion of Deferred Compensation Liability
                                       
Measured at Fair Value
    (162 )     -       -       -       (162 )
 
(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 master netting agreements that allow us to net cash settle asset and liability positions with the same counterparty.
 
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 amounts of floating-rate debt approximate fair value because the interest rate paid on such debt was set for periods of three months or less. The carrying amounts of the CONSOL installment payments approximate fair value because they have been discounted at the prevailing market rates for similar instruments. As such, we consider the fair value of our floating-rate debt and CONSOL installment payments to be level 2 measurements on the fair value hierarchy. See Note 4. Debt. Fair value information regarding our debt is as follows:
 
   
March 31,
   
December 31,
 
 
 
2012
   
2011
 
 
 
Carrying Amount
   
Fair Value
   
Carrying Amount
   
Fair Value
 
(millions)
                       
Long-Term Debt, Net of Unamortized Discount (1)
  $ 4,117     $ 4,606     $ 4,114     $ 4,733  
 
(1)
Excludes Aseng FPSO lease obligation. No floating rate debt was outstanding at March 31, 2012 or December 31, 2011. See Note 4. Debt.
 
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.
 
 
Noble Energy, Inc.
Notes to Consolidated Financial Statements
 
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, 2012
 
(millions)
       
Capitalized Exploratory Well Costs, Beginning of Period
  $
696
 
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves
   
        93
 
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves
   
           -
 
Capitalized Exploratory Well Costs Charged to Expense
   
           -
 
Capitalized Exploratory Well Costs, End of Period
 
$
789
 
 
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,
   
December 31,
 
 
 
2012
   
2011
 
(millions)
 
 
       
Exploratory Well Costs Capitalized for a Period of One Year or Less
  $ 345     $ 318  
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling
    444       378  
Balance at End of Period
  $ 789     $ 696  
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling
    10       9  
 
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, 2012:

 
 
 
   
Suspended Since
 
 
 
Total
   
2011
   
2010
   
2009 &
Prior
 
(millions)
 
 
   
 
   
 
   
 
 
Country/Project
 
 
   
 
   
 
   
 
 
Offshore Equatorial Guinea
 
 
   
 
   
 
   
 
 
Blocks O and I
  $ 114     $ 2     $ 6     $ 106  
Offshore Cameroon
                               
YoYo
    41       1       2       38  
Offshore Israel
                               
Leviathan
    86       45       41       -  
Dalit
    22       -       1       21  
Deepwater Gulf of Mexico
                               
Gunflint
    70       11       3       56  
Deep Blue
    75       2       54       19  
North Sea
                               
Selkirk
    22       -       1       21  
Other
                               
3 projects of $10 million or less each
    14       6       8       -  
Total
  $ 444     $ 67     $ 116     $ 261  

Blocks O and I   Blocks O and I are crude oil, natural gas and natural gas condensate discoveries.  During the second quarter of 2011, we drilled the successful Diega appraisal well which encountered both crude oil and natural gas. We have drilled two sidetracks, each of which encountered hydrocarbons. We are currently finalizing our appraisal of Diega and are evaluating regional development scenarios.
 
YoYo   YoYo is a 2007 natural gas and condensate discovery. During 2011 we acquired and processed additional 3-D seismic information and are continuing evaluations for future drilling potential.
 
Leviathan   Leviathan is a 2010 natural gas discovery. We are continuing to evaluate the discovery with the successful drilling of the Leviathan-3 appraisal well. We will require an additional one or two appraisal wells to further define Leviathan’s natural gas areal extent in order to determine the best development option including subsea tieback to existing shallow water platform, semi-submersible platform, FPSO, or LNG. 
 
In January 2012, we resumed drilling at the Leviathan-1 well in order to evaluate two additional intervals for the existence of crude oil. Results from these deeper tests are expected during the second quarter of 2012.
 
 
Noble Energy, Inc.
Notes to Consolidated Financial Statements
 
Dalit   Dalit is a 2009 natural gas discovery. We are currently working with our partners on a cost-effective development plan.
 
Gunflint   Gunflint (Mississippi Canyon Block 948) is a 2008 crude oil discovery. We are currently drilling the first of up to three appraisal wells that we anticipate drilling to fully evaluate the extent of the reservoir. We are also reviewing host platform options including subsea tieback to an existing third-party host and construction of a new facility.
 
Deep Blue   Deep Blue (Green Canyon Block 723) was a significant test well which began drilling in 2009. When the Deepwater Moratorium was announced in May 2010, we were required to suspend side track drilling activities. We resumed drilling activities and found additional hydrocarbons in high quality reservoirs in 2011. We have completed the analysis of the data obtained from the side track well and are working with our existing and potential new partners regarding their participation in an appraisal well.
 
Selkirk   The Selkirk project is located in the UK sector of the North Sea. Capitalized costs to date primarily consist of the cost of drilling an exploratory well. We are currently working with our partners on a cost-effective development plan, including selection of a host facility.
 
Note 8.  Asset Retirement Obligations
 
Asset retirement obligations consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in asset retirement obligations were as follows:
 
 
 
Three Months Ended
March 31,
 
 
 
2012
   
2011
 
(millions)
           
Asset Retirement Obligations, Beginning Balance
  $ 377     $ 253  
Liabilities Incurred
    6       1  
Liabilities Settled
    (2 )     (9 )
Revision of Estimate
    3       4  
Accretion Expense
    7       5  
Asset Retirement Obligations, Ending Balance
  $ 391     $ 254  

Liabilities settled in 2011 related primarily to Deepwater Gulf of Mexico and Gulf of Mexico shelf properties.
 
Accretion expense is included in depreciation, depletion and amortization (DD&A) expense in the consolidated statements of operations.
 
Note 9.  Basic and Diluted 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,
 
 
 
2012
   
2011
 
(millions, except per share amounts)
       
 
 
Net Income
  $ 263     $ 14  
                 
Weighted Average Number of Shares Outstanding, Basic
    177       176  
Incremental Shares From Assumed Conversion of Dilutive Stock Options and Restricted Stock
    3       2  
Weighted Average Number of Shares Outstanding, Diluted
    180       178  
Earnings Per Share, Basic
  $ 1.48     $ 0.08  
Earnings Per Share, Diluted
    1.47       0.08  
                 
 Number of antidilutive stock options, shares of restricted stock and shares of common stock in rabbi trust excluded from calculation above
    2       2  

 
Noble Energy, Inc.
Notes to Consolidated Financial Statements
 
Note 10.  Income Taxes
 
The income tax provision consists of the following:
 
   
Three Months Ended
March 31,
 
 
 
2012
   
2011
 
(millions)
           
Current
  $ 79     $ 12  
Deferred
    32       11  
Total Income Tax Provision
  $ 111     $ 23  
Effective Tax Rate
    30 %     62 %

Our effective tax rate decreased for the first quarter of 2012 as compared with the first quarter of 2011. During the first quarter of 2011, we increased the valuation allowance against our deferred tax asset for foreign tax credits by $11 million resulting in a corresponding increase in income tax expense, which was primarily responsible for the difference in the quarterly effective tax rates.
 
Years Remaining Open to Examination   In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2008, Equatorial Guinea – 2007, Israel – 2008, UK – 2010, the Netherlands – 2009, and China – 2006.
 
Note 11.  Segment Information
 
We have operations throughout the world and manage our operations by country. The following information is grouped into five components that are all primarily in the business of crude oil and natural gas exploration, development, and acquisition: the United States; West Africa (Equatorial Guinea, Cameroon, Senegal/Guinea-Bissau); Eastern Mediterranean (Israel and Cyprus); the North Sea (UK and the Netherlands); and Other International and Corporate. Other International includes China, Ecuador (in first quarter 2011), and new ventures.
 
 
 
Consolidated
   
United
States
   
West
Africa
   
Eastern
Mediter-
ranean
   
North
Sea
   
Other Int'l
and
Corporate
 
(millions)
       
 
   
 
   
 
   
 
   
 
 
Three Months Ended March 31, 2012
                                   
Revenues from Third Parties
  $ 1,112     $ 554     $ 383     $ 44     $ 75     $ 56  
Income from Equity Method Investees
    53       2       51       -       -       -  
Total Revenues
    1,165       556       434       44       75       56  
DD&A
    312       198       73       5       18       18  
(Gain) Loss on Commodity Derivative Instruments
    96       (9 )     105       -       -       -  
Income (Loss) Before Income Taxes
    374       193       227       32       40       (118 )
Three Months Ended March 31, 2011
                                               
Revenues from Third Parties
  $ 851     $ 505     $ 130     $ 52     $ 114     $ 50  
Income from Equity Method Investees
    48       -       48       -       -       -  
Total Revenues
    899       505       178       52       114       50  
DD&A
    221       167       10       4       28       12  
Loss on Commodity Derivative Instruments
    286       192       94       -       -       -  
Income (Loss)  Before Income Taxes
    37       (37 )     74       39       68       (107 )
                                                 
March 31, 2012
                                               
Goodwill
  $ 696     $ 696     $ -     $ -     $ -     $ -  
Total Assets
    17,064       11,220       2,948       2,107       458       331  
December 31, 2011
                                               
Goodwill
    696       696       -       -       -       -  
Total Assets
    16,444       11,201       2,728       1,751       544       220  
 
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.
 
 
Noble Energy, Inc.
Notes to Consolidated Financial Statements
 
During 2011, we received two Notices of Alleged Violation (NOAV) from the Colorado Oil and Gas Conservation Commission (COGCC) regarding the reporting of the presence of hydrogen sulfide to the COGCC and local government designee within certain areas of our Piceance Basin and Grover field operations. At this time, the COGCC has not established a proposed penalty for either NOAV.  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.
 
 
Item 2. 
 
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 leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our strategy is to achieve growth in value and cash flows through the continued expansion of a high quality portfolio of producing assets that is balanced and diversified among US and international projects, crude oil and natural gas, and near, medium and long-term opportunities.
 
Our financial results for first quarter 2012 included:
 
 
net income of $263 million, as compared with $14 million for first quarter 2011;
 
loss on commodity derivative instruments of $96 million (including unrealized mark-to-market loss of $73 million) as compared with a loss on commodity derivative instruments of $286 million (including unrealized mark-to-market loss of $303 million) for first quarter 2011;
 
diluted earnings per share of $1.47, as compared with $0.08 for first quarter 2011;
 
cash flow provided by operating activities of $741 million, as compared with $484 million for first quarter 2011;
 
ending cash balance of $1.1 billion, as compared with $1.5 billion at December 31, 2011;
 
capital spending, on a cash basis, of $1 billion, as compared with $578 million for first quarter of 2011; and
 
ratio of debt-to-book capital of 37% as compared with 38% at December 31, 2011. 
 
Operational events for first quarter 2012 included:   
 
Overall
 
 
record total sales volume of 243 MBoe/d, up 10 MBoe/d over the fourth quarter of 2011; and
 
liquids represent 47% of total sales volumes, up from 40% in the fourth quarter of 2011;
 
United States
 
 
horizontal production from the DJ Basin averaged 18 MBoe/d net, or 25% of the total DJ Basin volumes;
 
expanded the Northern Colorado acreage position by 48,000 net acres to 230,000 net acres, where recent Company horizontal Niobrara results indicate recoveries comparable to Wattenberg; and
 
assumed operatorship in the wet gas area of the Marcellus Shale joint venture acreage;
 
International
 
 
gross daily crude oil production from the Aseng field, offshore Equatorial Guinea, achieved 60 MBbl/d;
 
signed a natural gas sales contract with Israel Electric Corporation Limited for 2.7 Tcf of natural gas; and
 
announced the Tanin discovery offshore Israel.
 

Exploration Program Update
 
We have significant remaining exploration potential in the onshore US, deepwater Gulf of Mexico, offshore West Africa, offshore Eastern Mediterranean and other international areas where we hold acreage positions. Significant exploratory wells were in progress at March 31, 2012, such as Deep Blue and the deep crude oil test at Leviathan-1 (See Item 1. Financial Statements – Note 7. Capitalized Exploratory Well Costs), and we expect to continue an active exploratory drilling program during the remainder of 2012. We do not always find proved reserves 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. We are currently conducting, or planning to conduct, appraisal activities at several of our discoveries. In the event we conclude that one of our discoveries is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense.  As a result, in a future period, dry hole cost could be significant.
 
Updates of our significant exploration activities are as follows:
 
DJ Basin (Onshore US) We continue to acquire 3-D seismic information and appraise our acreage in Northern Colorado and Wyoming.
 
Deep Blue (Deepwater Gulf of Mexico)   We have completed the analysis of the data obtained from the side track well and are working with our existing and potential new partners regarding their participation in an appraisal well.
 
Leviathan (Offshore Israel)   In late 2010, we announced a significant natural gas discovery at the Leviathan-1 well in the Levant Basin. Additionally, we will require one or two appraisal wells to further define Leviathan’s natural gas areal extent in order to determine the best development option. See Major Development Projects Update – Leviathan below.
 
In January 2012, we returned to drilling at the Leviathan-1 well, which was suspended during 2011, in order to evaluate additional intervals for the existence of crude oil. Although the geological likelihood of success is low, the drilling results, which are expected in the second quarter of 2012, will yield valuable information about this new basin.
 
Tanin 1 (Offshore Israel)   In February 2012 we announced a natural gas discovery at the Tanin prospect, approximately 13 miles northwest of the Tamar field.
 
Additionally, we have acquired approximately 330,000 net acres in the state of Nevada.  We are currently planning 3-D seismic testing in 2012 and exploration drilling in 2013.
 
Major Development Projects Update
 
During the first quarter of 2012, we continued to advance our major development projects, which we expect to deliver significant growth over the next several years. Updates on our significant development projects are as follows:
 
Horizontal Niobrara (Onshore US)   We have increased our horizontal drilling activity targeting the Niobrara formation, completing 30 horizontal wells during the quarter. We recently added another horizontal drilling rig to our program and are currently running six horizontal drilling rigs.
 
Marcellus Shale (Onshore US)   During the first quarter of 2012, we took over operatorship of our first rig in the wet gas area of the Marcellus Shale, bringing the total rig count operating in the joint venture properties to seven. We drilled five horizontal wells reaching target depth during the quarter. By the end of the year, we expect to operate three rigs in the wet gas area while our partner CONSOL expects to operate two rigs in the dry gas area.
 
Galapagos (Deepwater Gulf of Mexico)   Installation of topside equipment at the host facility and subsea tiebacks for Santa Cruz, Isabela and Santiago have been completed and we are working with the host platform operator to perform final commissioning work. We expect production to commence in the second quarter of 2012.
 
Gunflint (Deepwater Gulf of Mexico)   We are currently drilling an appraisal well at Gunflint.  We currently anticipate drilling up to two additional appraisal wells to fully evaluate the extent of the reservoir. We are also reviewing host platform options, including subsea tieback to an existing third-party host and construction of a new facility, which will likely lead to sanctioning of a development project.
 
Alen (Offshore Equatorial Guinea)   All sub-sea trees have been installed and sub-sea fabrication is underway. The production and injection wells are also on schedule and first production is expected to commence in the fourth quarter of 2013.
 
Diega (Offshore Equatorial Guinea)   We are currently finalizing our appraisal of Diega and are evaluating regional development scenarios.
 
Carla (Offshore Equatorial Guinea)   In late 2011, we drilled the Carla well, a successful oil appraisal well in Block O, offshore Equatorial Guinea. We are evaluating drilling results from our Carla discovery well and reviewing development options and formulating a development plan for these areas.
 
Tamar (Offshore Israel)  Tamar development drilling and platform fabrication are ongoing. Pipeline installation is essentially complete, and the project remains on schedule for commissioning beginning in late 2012 and first sales in the second quarter of 2013. We also finalized several natural gas sales and purchase agreements during the quarter. See Israel Delivery Commitments below.
 
Noa/Pinnacles (Offshore Israel)   The Noa field is being developed as a subsea tieback to the Mari-B platform. Two development wells have been drilled, FEED (front end engineering and design) work has been completed, and installation and fabrication are progressing on schedule. In addition to Noa, we drilled the Pinnacles-1 well and are currently in the process of completing and tying the well back to the Mari-B platform. Noa and Pinnacles will help meet Israeli natural gas demands until the Tamar field begins producing. We expect production from both Noa and Pinnacles to commence in the third quarter of 2012. See Israel Delivery Commitments below.
 
 
Leviathan (Offshore Israel)   We have project and commercial teams in place and are considering our natural gas commercialization options. Due to the size of the field, economic viability depends on the ability to export via pipeline or LNG. Engineering design and planning work are currently underway for a potential first phase of development; however, we have not yet sanctioned a development project.
 
Block 12 (Offshore Cyprus) We are in the process of evaluating our commercialization options, including LNG, for the Block 12 natural gas discovery.
 
Northern Region Transportation Curtailments
 
The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. Although we have some contractual control over the transportation of our production through firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions, mechanical or other reasons. In addition, continued drilling activity in concentrated areas, such as the DJ Basin and Marcellus Shale, can result in production growth outstripping available transportation and gathering capacity.
 
Due to both scheduled and unscheduled curtailments of third party pipeline services for significant equipment repairs and upgrades, we expect our Wattenberg area production to be impacted for the second quarter of 2012.
 
Recent Developments in the Marcellus Shale
 
Well Impact Fee    During the first quarter of 2012, the Pennsylvania legislature enacted an annual well impact fee which will be used by local governments, counties and state agencies to support the infrastructure and regulatory framework necessary to sustain effective development of natural gas resources in the Marcellus Shale. The well impact fee is a variable rate based on natural gas prices and the year a well is drilled. Due to the early stage of our Marcellus Shale development activities, the fee did not have a significant impact on our results of operations for the first quarter of 2012.
 
Butler v. Powers    On September 7, 2011, an intermediate appellate court (Superior Court) in Pennsylvania issued an opinion in Butler v. Powers regarding the interpretation of a deed. As a result, traditional views of how ownership of shale gas is determined in that state have been called into question. The issue raised by the case is whether shale gas is different from other natural gas and should be considered part of mineral rights, rather than oil and gas rights, because shale gas is contained inside non-porous shale rock. An appeal of the decision was subsequently filed with the Pennsylvania Supreme Court. The Pennsylvania Supreme Court recently announced its decision to hear the appeal. Written arguments in the case are due by May 15, 2012.
 
At this time, no case law or interpretation of existing law has changed, nor has there been an indication that either the Superior Court or the Pennsylvania Supreme Court will seek to change existing law. Based upon our initial review, we believe that any adverse decision in the pending case would have minimal adverse impact upon the assets acquired from CONSOL and our Marcellus Shale joint venture operations.
 
Recent Developments Onshore US
 
Researchers from the U.S. Geological Survey recently reported that they have observed an increase in seismic activity in the Midcontinent region and have indicated that the seismic activity may be attributable to injection wells that handle wastewater from oil and gas drilling activities. The researchers cite a series of examples for which an uptick in seismic activity is observed in areas where the disposal of wastewater through deep-well injection increased significantly. Regulators in Ohio and Arkansas are also looking at a possible connection between minor seismic events and disposal of wastewater in injection wells.
 
Minor and imperceptible seismic activity is extremely common in areas of oil and gas development. Historically, such activity has rarely caused damage. In addition, there are safeguards in place to reduce the likelihood of seismic activity caused by oil and gas drilling activities, including the disposal of wastewater. For example, we study the seismicity of the areas where we operate and design plans for each well based on our understanding of the specific geology.  Steps taken to prevent seismic events include limiting increases in well pressure by reducing either the volume of wastewater pumped into the wells or the rate at which it is pumped. We also comply with requirements for injection well construction, operation, and closure set by the Underground Injection Control (UIC) Program, which was established under the provisions of the Safe Drinking Water Act of 1974.
 
Recent Developments Offshore France
 
We and our partner have applied to the French government for an extension of our offshore exploratory license until November 2015.  The French government has thus far not responded officially to this application, even though the regulatory period for reply has passed. The current political climate is not favorable to our application, and we are unable to predict the ultimate outcome. Regardless of the final result, any curtailment of exploration activities offshore France would have no material impact on our financial position or results of operations.
 
 
Recent Developments in West Africa
 
We currently have an interest in the AGC Profond block covering 2.4 million gross (724,000 net) undeveloped acres offshore Senegal/Guinea-Bissau. On March 26, 2012, a new president of Senegal was elected in a peaceful, democratic election. Conversely, on April 13, 2012, the interim government of Guinea-Bissau was deposed by military forces. The military and the opposition subsequently agreed to form a transitional council, but have not announced specific plans. We will continue to monitor these developments, and we currently cannot predict the impact these events may have on our future exploration plans in this area.
 
Israel Delivery Commitments
 
During 2011, due to multiple interruptions in imported gas supplies from Egypt, Mari-B natural gas volumes were delivered at very high rates to support Israel’s growing natural gas and power demands. As a result, we experienced accelerated depletion of the Mari-B field. In January 2012, we announced a cut back in production at Mari-B, which is nearing the end of its expected production life, to prudently manage the reservoir. We are currently working closely with our Israeli customers to manage demand from the Mari-B field and continue production from it while wells from Noa and Pinnacles are drilled, completed and tied back to the Mari-B platform. We expect production to commence from Noa and Pinnacles during the third quarter of 2012 and the Tamar field during the second quarter of 2013.
 
On March 14, 2012, we and our Tamar partners entered into a Gas Sale and Purchase Agreement (GSPA) with the Israel Electric Corporation Limited (IEC). Under the terms of the GSPA, we have agreed to sell approximately 2.7 Tcf of natural gas produced from the Tamar field to IEC over an approximate 15-year period. At IEC’s option, this amount can be increased to 3.5 Tcf, under certain conditions. The term of the GSPA begins upon commissioning of the Tamar project. The sales price is based on an initial base price and will be subject to an inflation adjustment. The GSPA is attached as Exhibit 10.1 to this Quarterly Report on Form 10-Q.
 
As of April 15, 2012, we and our partners have also signed GSPAs with other Israeli customers, including independent power, cogeneration and manufacturing companies, to supply approximately 1.3 Tcf of natural gas over a 16 to 17 year period beginning in late 2013. These contracts provide for an initial base price, subject to an inflation adjustment, and some of the contracts provide for increases or decreases in total quantities. We continue to negotiate additional GSPAs with other potential customers.
 
Sales Volumes
 
On a BOE basis, total sales volumes were 13% higher for the first quarter of 2012 as compared with the first quarter of 2011, and our mix of sales volumes was 47% global liquids, 23% international natural gas, and 30% US natural gas. US sales volumes increased due to continued acceleration of our horizontal drilling programs in Wattenberg along with our Marcellus Shale program, which began at the end of the third quarter of 2011. International crude oil sales volumes were higher in Equatorial Guinea due to the commencement of crude oil production at Aseng in the fourth quarter of 2011. Israel natural gas sales volumes were lower as we have reduced the rate of production from the Mari-B field in order to manage the reservoir. See Israel Delivery Commitments above and Results of Operations – Revenues below.
 
Commodity Price Changes and Hedging
 
Total consolidated average realized crude oil prices for the first three months of 2012 increased 14% as compared with the first three months of 2011. The increase was driven by the continued global economic recovery and continued threats to the global oil supply system.
 
US natural gas prices remain weak. Average realized natural gas prices for the first three months of 2012 decreased 36% as compared with the first three months of 2011 primarily due to abundant supply and above average levels of natural gas in storage. As long as US natural gas development activity continues at, or near, the current level and there is no significant increase in demand, production growth will continue to outstrip growth in transportation and storage capacity, likely resulting in downward pressure on natural gas prices (See Potential for Future Asset Impairments below).
 
We have hedged approximately 41% of our expected global crude oil production and 39% of our expected domestic natural gas production for the remainder of 2012. See Item 1. Financial Statements – Note 5. Derivative Instruments and Hedging Activities.

OPERATING OUTLOOK
 
Our expected crude oil, natural gas and NGL production for 2012 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 major development project completion and initial production;
 
ongoing development activity in the Wattenberg area and horizontal drilling in the Niobrara formation in the DJ Basin;
 
ramp-up of development activity in the Marcellus Shale;
 
natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas of our US operations, in the North Sea and the Mari-B field in Israel, where we reduced production to manage the reservoir (See Israel Delivery Commitments, above);
 
variations in sales volumes of natural gas from the Alba field in Equatorial Guinea related to scheduled field maintenance and potential downtime at the methanol, LPG and/or LNG plants;