10-Q
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2015
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 001-07964
NOBLE ENERGY, INC.
(Exact name of registrant as specified in its charter)
|
| | |
Delaware | | 73-0785597 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. employer identification number) |
1001 Noble Energy Way | | |
Houston, Texas | | 77070 |
(Address of principal executive offices) | | (Zip Code) |
(281) 872-3100 (Registrant’s telephone number, including area code) |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes ý No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes ý No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller
reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company”
in Rule 12b-2 of the Exchange Act.
|
| | | |
Large accelerated filer x | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o |
| | (Do not check if a smaller reporting company) | |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No ý
As of September 30, 2015, there were 428,554,158 shares of the registrant’s common stock,
par value $0.01 per share, outstanding.
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 September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
Revenues | | | | | | | |
Oil, Gas and NGL Sales | $ | 765 |
| | $ | 1,228 |
| | $ | 2,227 |
| | $ | 3,893 |
|
Income from Equity Method Investees | 36 |
| | 41 |
| | 60 |
| | 138 |
|
Total | 801 |
| | 1,269 |
| | 2,287 |
| | 4,031 |
|
Costs and Expenses | |
| | |
| | | | |
Production Expense | 235 |
| | 216 |
| | 693 |
| | 689 |
|
Exploration Expense | 203 |
| | 217 |
| | 308 |
| | 350 |
|
Depreciation, Depletion and Amortization | 539 |
| | 460 |
| | 1,444 |
| | 1,297 |
|
General and Administrative | 109 |
| | 132 |
| | 308 |
| | 399 |
|
Asset Impairments | — |
| | 33 |
| | 43 |
| | 164 |
|
Other Operating (Income) Expense, Net | 182 |
| | (19 | ) | | 252 |
| | (31 | ) |
Total | 1,268 |
| | 1,039 |
| | 3,048 |
| | 2,868 |
|
Operating Income (Loss) | (467 | ) | | 230 |
| | (761 | ) | | 1,163 |
|
Other (Income) Expense | |
| | |
| | | | |
Gain on Commodity Derivative Instruments | (267 | ) | | (385 | ) | | (331 | ) | | (74 | ) |
Interest, Net of Amount Capitalized | 71 |
| | 52 |
| | 183 |
| | 151 |
|
Other Non-Operating (Income) Expense, Net | (12 | ) | | (13 | ) | | (20 | ) | | 1 |
|
Total | (208 | ) | | (346 | ) | | (168 | ) | | 78 |
|
Income (Loss) Before Income Taxes | (259 | ) | | 576 |
| | (593 | ) | | 1,085 |
|
Income Tax (Benefit) Provision | 24 |
| | 157 |
| | (180 | ) | | 274 |
|
Net Income (Loss) | $ | (283 | ) | | $ | 419 |
| | $ | (413 | ) | | $ | 811 |
|
| | | | | | | |
Earnings (Loss) Per Share, Basic | $ | (0.67 | ) | | $ | 1.16 |
| | $ | (1.05 | ) | | $ | 2.25 |
|
Earnings (Loss) Per Share, Diluted | $ | (0.67 | ) | | $ | 1.12 |
| | $ | (1.05 | ) | | $ | 2.21 |
|
| | | | | | | |
Weighted Average Number of Shares Outstanding | | | | | | | |
Basic | 420 |
| | 362 |
| | 392 |
| | 361 |
|
Diluted | 420 |
| | 367 |
| | 392 |
| | 367 |
|
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Statements of Comprehensive Income
(millions)
(unaudited)
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
Net Income (Loss) | $ | (283 | ) | | $ | 419 |
| | $ | (413 | ) | | $ | 811 |
|
Other Items of Comprehensive Income | | | | | | | |
Net Change in Mutual Fund Investment | — |
| | — |
| | (11 | ) | | — |
|
Less Tax Benefit | — |
| | — |
| | 3 |
| | — |
|
Net Change in Pension and Other | 69 |
| | 6 |
| | 94 |
| | 16 |
|
Less Tax Expense | (23 | ) | | (2 | ) | | (33 | ) | | (6 | ) |
Other Comprehensive Income | 46 |
| | 4 |
| | 53 |
| | 10 |
|
Comprehensive Income (Loss) | $ | (237 | ) | | $ | 423 |
| | $ | (360 | ) | | $ | 821 |
|
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Balance Sheets
(millions)
(unaudited)
|
| | | | | | | |
| September 30, 2015 | | December 31, 2014 |
ASSETS | | | |
Current Assets | | | |
Cash and Cash Equivalents | $ | 1,028 |
| | $ | 1,183 |
|
Accounts Receivable, Net | 571 |
| | 857 |
|
Commodity Derivative Assets, Current | 650 |
| | 710 |
|
Other Current Assets | 281 |
| | 325 |
|
Total Current Assets | 2,530 |
| | 3,075 |
|
Property, Plant and Equipment | |
| | |
|
Oil and Gas Properties (Successful Efforts Method of Accounting) | 30,456 |
| | 25,599 |
|
Property, Plant and Equipment, Other | 830 |
| | 630 |
|
Total Property, Plant and Equipment, Gross | 31,286 |
| | 26,229 |
|
Accumulated Depreciation, Depletion and Amortization | (9,537 | ) | | (8,086 | ) |
Total Property, Plant and Equipment, Net | 21,749 |
| | 18,143 |
|
Goodwill | 945 |
| | 620 |
|
Other Noncurrent Assets | 741 |
| | 715 |
|
Total Assets | $ | 25,965 |
| | $ | 22,553 |
|
LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
Current Liabilities | |
| | |
|
Accounts Payable - Trade | $ | 1,297 |
| | $ | 1,578 |
|
Other Current Liabilities | 795 |
| | 944 |
|
Total Current Liabilities | 2,092 |
| | 2,522 |
|
Long-Term Debt | 8,033 |
| | 6,103 |
|
Deferred Income Taxes, Noncurrent | 2,286 |
| | 2,516 |
|
Other Noncurrent Liabilities | 1,104 |
| | 1,087 |
|
Total Liabilities | 13,515 |
| | 12,228 |
|
Commitments and Contingencies |
| |
|
|
Shareholders’ Equity | |
| | |
|
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized, None Issued | — |
| | — |
|
Common Stock - Par Value $0.01 per share; 1 Billion and 500 Million Shares Authorized, respectively; 469 Million and 402 Million Shares Issued, respectively | 5 |
| | 4 |
|
Additional Paid in Capital | 6,342 |
| | 3,624 |
|
Accumulated Other Comprehensive Loss | (37 | ) | | (90 | ) |
Treasury Stock, at Cost; 38 Million Shares | (691 | ) | | (671 | ) |
Retained Earnings | 6,831 |
| | 7,458 |
|
Total Shareholders’ Equity | 12,450 |
| | 10,325 |
|
Total Liabilities and Shareholders’ Equity | $ | 25,965 |
| | $ | 22,553 |
|
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Statements of Cash Flows
(millions)
(unaudited)
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2015 | | 2014 |
Cash Flows From Operating Activities | | | |
Net Income (Loss) | $ | (413 | ) | | $ | 811 |
|
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities | |
| | |
|
Depreciation, Depletion and Amortization | 1,444 |
| | 1,297 |
|
Asset Impairments | 43 |
| | 164 |
|
Dry Hole Cost | 154 |
| | 163 |
|
Deferred Income Tax (Benefit) Expense | (244 | ) | | 61 |
|
Income (Loss) from Equity Method Investees, Net of Dividends | (4 | ) | | 53 |
|
(Gain) Loss on Commodity Derivative Instruments | (331 | ) | | (74 | ) |
Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments | 683 |
| | (95 | ) |
Gain on Divestitures | — |
| | (72 | ) |
Stock Based Compensation | 69 |
| | 67 |
|
Non-cash Pension Termination Expense | 81 |
| | — |
|
Other Adjustments for Noncash Items Included in Income | 78 |
| | 42 |
|
Changes in Operating Assets and Liabilities | | | |
|
Decrease in Accounts Receivable | 370 |
| | 166 |
|
(Decrease) Increase in Accounts Payable | (248 | ) | | 103 |
|
(Decrease) in Current Income Taxes Payable | (118 | ) | | 21 |
|
Other Current Assets and Liabilities, Net | (28 | ) | | 16 |
|
Other Operating Assets and Liabilities, Net | (50 | ) | | (20 | ) |
Net Cash Provided by Operating Activities | 1,486 |
| | 2,703 |
|
Cash Flows From Investing Activities | |
| | |
|
Additions to Property, Plant and Equipment | (2,519 | ) | | (3,585 | ) |
Rosetta Merger | 61 |
| | — |
|
Additions to Equity Method Investments | (86 | ) | | (58 | ) |
Distribution from Equity Method Investee | — |
| | 156 |
|
Proceeds from Divestitures | 151 |
| | 312 |
|
Net Cash Used in Investing Activities | (2,393 | ) | | (3,175 | ) |
Cash Flows From Financing Activities | |
| | |
|
Exercise of Stock Options | 7 |
| | 45 |
|
Excess Tax Benefits from Stock-Based Awards | 2 |
| | 18 |
|
Dividends Paid, Common Stock | (214 | ) | | (182 | ) |
Purchase of Treasury Stock | (20 | ) | | (15 | ) |
Proceeds from Issuance of Shares of Common Stock to Public, Net of Offering Costs | 1,112 |
| | — |
|
Proceeds from Credit Facility | — |
| | 900 |
|
Repayment of Credit Facility | (74 | ) | | — |
|
Repayment of Senior Notes | (12 | ) | | (200 | ) |
Repayment of Capital Lease Obligation | (49 | ) | | (42 | ) |
Net Cash Provided by Financing Activities | 752 |
| | 524 |
|
Increase (Decrease) in Cash and Cash Equivalents | (155 | ) | | 52 |
|
Cash and Cash Equivalents at Beginning of Period | 1,183 |
| | 1,117 |
|
Cash and Cash Equivalents at End of Period | $ | 1,028 |
| | $ | 1,169 |
|
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 | | Accumulated Other Comprehensive Loss | | Treasury Stock at Cost | | Retained Earnings | | Total Shareholders' Equity |
December 31, 2014 | $ | 4 |
| | $ | 3,624 |
| | $ | (90 | ) | | $ | (671 | ) | | $ | 7,458 |
| | $ | 10,325 |
|
Net Loss | — |
| | — |
| | — |
| | — |
| | (413 | ) | | (413 | ) |
Rosetta Merger | 1 |
| | 1,528 |
| | — |
| | — |
| | — |
| | 1,529 |
|
Stock-based Compensation | — |
| | 69 |
| | — |
| | — |
| | — |
| | 69 |
|
Exercise of Stock Options | — |
| | 7 |
| | — |
| | — |
| | — |
| | 7 |
|
Tax Benefits Related to Exercise of Stock Options | — |
| | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Dividends (54 cents per share) | — |
| | — |
| | — |
| | — |
| | (214 | ) | | (214 | ) |
Changes in Treasury Stock, Net | — |
| | — |
| | — |
| | (20 | ) | | — |
| | (20 | ) |
Issuance of Shares of Common Stock to Public, Net of Offering Costs | — |
| | 1,112 |
| | — |
| | — |
| | — |
| | 1,112 |
|
Net Change in Pension and Other | — |
| | — |
| | 53 |
| | — |
| | — |
| | 53 |
|
September 30, 2015 | $ | 5 |
| | $ | 6,342 |
| | $ | (37 | ) | | $ | (691 | ) | | $ | 6,831 |
| | $ | 12,450 |
|
| | | | | | | | | | | |
December 31, 2013 | $ | 4 |
| | $ | 3,463 |
| | $ | (117 | ) | | $ | (659 | ) | | $ | 6,493 |
| | $ | 9,184 |
|
Net Income | — |
| | — |
| | — |
| | — |
| | 811 |
| | 811 |
|
Stock-based Compensation | — |
| | 67 |
| | — |
| | — |
| | — |
| | 67 |
|
Exercise of Stock Options | — |
| | 45 |
| | — |
| | — |
| | — |
| | 45 |
|
Tax Benefits Related to Exercise of Stock Options | — |
| | 18 |
| | — |
| | — |
| | — |
| | 18 |
|
Dividends (50 cents per share) | — |
| | — |
| | — |
| | — |
| | (182 | ) | | (182 | ) |
Changes in Treasury Stock, Net | — |
| | — |
| | — |
| | (15 | ) | | — |
| | (15 | ) |
Net Change in Pension and Other | — |
| | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
September 30, 2014 | $ | 4 |
| | $ | 3,593 |
| | $ | (107 | ) | | $ | (674 | ) | | $ | 7,122 |
| | $ | 9,938 |
|
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 include onshore US, primarily in the DJ Basin, Eagle Ford Shale, Delaware Basin and Marcellus Shale, 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 September 30, 2015 and December 31, 2014 and for the three and nine months ended September 30, 2015 and 2014 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and shareholders’ equity for such periods. Certain prior-period amounts have been reclassified to conform to the current-period presentation. Operating results for the three and nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015.
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, 2014.
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.
Pension Plan In third quarter 2015, we completed the process of terminating our noncontributory, tax-qualified defined benefit pension plan through the purchase of annuities for the remaining participants. As a result, we expensed all remaining unamortized prior service costs and actuarial losses from accumulated other comprehensive loss (AOCL). For the nine months ended September 30, 2015, we have expensed $88 million related to the termination of the plan. As of September 30, 2015, we have $16 million remaining in AOCL related to our non-qualified defined benefit plan.
Equity Offerings On March 3, 2015, we closed an underwritten public offering of 21 million shares of common stock, par value $0.01 per share, at a price of $47.50 per share. In addition, on March 25, 2015, we completed the issuance of an additional 3.15 million shares of common stock, par value $0.01 per share, in connection with the exercise of the option of the underwriters to purchase additional shares of common stock. The aggregate net proceeds of the offerings were approximately $1.1 billion (after deducting underwriting discounts and commissions and offering expenses). We used approximately $150 million of the net proceeds to repay outstanding indebtedness under our revolving credit facility and the remainder was used for general corporate purposes, including the funding of our capital investment program.
On July 20, 2015, we issued approximately 41 million shares of common stock in exchange for all outstanding shares of Rosetta Resources Inc. (Rosetta) using a ratio of 0.542 of a share of Noble Energy common stock for each share of Rosetta common stock. See Note 3. Rosetta Merger. Increase in Authorized Shares On April 28, 2015, our stockholders approved an amendment to our Certificate of Incorporation to increase the number of authorized shares of our common stock from 500 million to 1 billion.
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.
Update on Core Area – Israel The Israeli government has developed a framework (Framework) to support the development of offshore natural gas reserves and natural gas exports. After a public hearing process, the Framework was approved by the Israeli Cabinet and Knesset. Enactment of the Framework provides that certain antitrust matters will be resolved. Authority resides with the Minister of Economy to provide the stipulated exemption related to these antitrust matters. Legal challenges may still be brought against the Framework in the Israeli courts. We continue to monitor this effort and if necessary, we are prepared to defend our legal rights to our Israel assets to the fullest extent in both Israel and international venues.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Recently Issued Accounting Standards In July 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2015-11 (ASU 2015-11): Simplifying the Measurement of Inventory, effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We follow the average cost method and are currently evaluating the provisions of ASU 2015-11 and assessing the impact, if any, it may have on our financial position and results of operations.
In April 2015, the FASB issued Accounting Standards Update No. 2015-03 (ASU 2015-03): Simplifying the Presentation of Debt Issuance Costs, effective for annual and interim periods beginning after December 15, 2015. ASU 2015-03 requires that all costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of the debt. It is effective retrospectively for all prior periods presented in the financial statements beginning in the first quarter 2016 and is only expected to impact the presentation of our consolidated balance sheet. In August 2015, the FASB issued ASU 2015-15 to specifically address the presentation and subsequent measurement of debt issuance costs related to line-of-credit arrangements. ASU 2015-15 allows entities to defer and present debt issuance costs related to line-of-credit arrangements as an asset and amortize the costs ratably over the term of the line-of-credit arrangement. As of September 30, 2015 and December 31, 2014, we had $49 million and $50 million of capitalized, unamortized debt issuance costs, respectively, included in other long-term assets in our consolidated balance sheet.
In February 2015, the FASB issued Accounting Standards Update No. 2015-02 (ASU 2015-02): Consolidation - Amendments to the Consolidation Analysis, effective for annual and interim periods beginning after December 15, 2015. ASU 2015-02 changes the guidance as to whether an entity is a variable interest entity (VIE) or a voting interest entity and how related parties are considered in the VIE model. We are currently evaluating the provisions of ASU 2015-02 and assessing the impact, if any, it may have on our financial position and results of operations.
In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers, and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the Industry Topics of the Codification. In addition, ASU 2014-09 supersedes the cost guidance in Subtopic 605-35, Revenue Recognition - Construction-Type and Production-Type Contracts, and creates new Subtopic 340-40, Other Assets and Deferred Costs - Contracts with Customers. In summary, the core principle of Topic 606 is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. Initially, the amendments in ASU 2014-09 were effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and early application was not permitted. In August 2015, the FASB agreed to give companies an extra year to comply with the new standard. The standard will be effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We are currently evaluating the provisions of ASU 2014-09 and awaiting implementation guidance to determine the impact, if any, it may have on our financial position and results of operations.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Statements of Operations Information Other statements of operations information is as follows:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(millions) | 2015 | | 2014 | | 2015 | | 2014 |
Production Expense | |
| | |
| | | | |
Lease Operating Expense | $ | 133 |
| | $ | 132 |
| | $ | 419 |
| | $ | 424 |
|
Production and Ad Valorem Taxes | 28 |
| | 44 |
| | 89 |
| | 146 |
|
Transportation and Gathering Expense | 74 |
| | 40 |
| | 185 |
| | 119 |
|
Total | $ | 235 |
| | $ | 216 |
| | $ | 693 |
| | $ | 689 |
|
Other Operating (Income) Expense, Net | |
| | |
| | | | |
Midstream Gathering and Processing (Income) Expense, Net | $ | 4 |
| | $ | 1 |
| | $ | 10 |
| | $ | 8 |
|
Corporate Restructuring Expense (1) | 21 |
| | — |
| | 39 |
| | — |
|
Stacked Drilling Rig Expense (2) | 13 |
| | — |
| | 20 |
| | — |
|
Pension Plan Expense(3) | 67 |
| | — |
| | 88 |
| | — |
|
Rosetta Merger Expenses(4) | 71 |
| | — |
| | 73 |
| | — |
|
Gain on Divestitures | — |
| | (30 | ) | | — |
| | (72 | ) |
Other, Net | 6 |
| | 10 |
| | 22 |
| | 33 |
|
Total | $ | 182 |
| | $ | (19 | ) | | $ | 252 |
| | $ | (31 | ) |
Other Non-Operating (Income) Expense, Net | |
| | |
| | | | |
Deferred Compensation (Income) Expense (5) | $ | (13 | ) | | $ | (12 | ) | | (19 | ) | | $ | — |
|
Other (Income) Expense, Net | 1 |
| | (1 | ) | | (1 | ) | | 1 |
|
Total | $ | (12 | ) | | $ | (13 | ) | | $ | (20 | ) | | $ | 1 |
|
| |
(1) | Amount represents expenses associated with the relocation of our personnel. The expenses primarily include the relocation of our Ardmore, Oklahoma office, as well as the consolidation of our Houston personnel to our corporate headquarters in Houston. |
| |
(2) | Amount represents the day rate cost associated with drilling rigs under contract, but not currently being utilized in our US onshore drilling programs. |
| |
(3) | Amount includes the expensing of the actuarial loss from AOCL related to the termination and re-measurement of our defined benefit pension plan. |
| |
(4) | Amount represents expenses associated with the completion of the Rosetta Merger. See Note 3. Rosetta Merger. |
| |
(5) | Amounts represent decreases 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:
|
| | | | | | | |
(millions) | September 30, 2015 | | December 31, 2014 |
Accounts Receivable, Net | | | |
Commodity Sales | $ | 284 |
| | $ | 405 |
|
Joint Interest Billings | 166 |
| | 297 |
|
Other | 140 |
| | 171 |
|
Allowance for Doubtful Accounts | (19 | ) | | (16 | ) |
Total | $ | 571 |
| | $ | 857 |
|
Other Current Assets | |
| | |
|
Inventories, Materials and Supplies | $ | 116 |
| | $ | 81 |
|
Inventories, Crude Oil | 28 |
| | 24 |
|
Assets Held for Sale (1) | 78 |
| | 180 |
|
Prepaid Expenses and Other Current Assets | 59 |
| | 40 |
|
Total | $ | 281 |
| | $ | 325 |
|
Other Noncurrent Assets | |
| | |
|
Investments in Unconsolidated Subsidiaries | $ | 427 |
| | $ | 325 |
|
Mutual Fund Investments | 106 |
| | 111 |
|
Commodity Derivative Assets | 104 |
| | 180 |
|
Other Assets | 104 |
| | 99 |
|
Total | $ | 741 |
| | $ | 715 |
|
Other Current Liabilities | |
| | |
|
Production and Ad Valorem Taxes | $ | 165 |
| | $ | 110 |
|
Income Taxes Payable | 60 |
| | 180 |
|
Deferred Income Taxes, Current | 86 |
| | 158 |
|
Accrued Benefit Costs, Current | 30 |
| | 125 |
|
Asset Retirement Obligations | 141 |
| | 81 |
|
Interest Payable | 119 |
| | 70 |
|
Current Portion of Capital Lease Obligations | 57 |
| | 68 |
|
Other | 137 |
| | 152 |
|
Total | $ | 795 |
| | $ | 944 |
|
Other Noncurrent Liabilities | |
| | |
|
Deferred Compensation Liabilities | $ | 229 |
| | $ | 218 |
|
Asset Retirement Obligations | 746 |
| | 670 |
|
Accrued Benefit Costs | 17 |
| | 24 |
|
Other | 112 |
| | 175 |
|
Total | $ | 1,104 |
| | $ | 1,087 |
|
(1) Assets held for sale at September 30, 2015 include our Tanin and Karish natural gas discoveries, offshore Israel. See Update on Core Area – Israel, above.
Note 3. Rosetta Merger
On July 20, 2015, Noble Energy completed the merger of Rosetta into a subsidiary of Noble Energy (Rosetta Merger). The results of Rosetta's operations since the merger date are included in our consolidated statement of operations. The merger was effected through the issuance of approximately 41 million shares of Noble Energy common stock in exchange for all outstanding shares of Rosetta using a ratio of 0.542 of a share of Noble Energy common stock for each share of Rosetta common stock and the assumption of Rosetta's liabilities, including approximately $2 billion fair value of outstanding debt. The merger adds two new onshore US shale positions to our portfolio including approximately 50,000 net acres in the Eagle Ford Shale and 54,000 net acres in the Permian (45,000 acres in the Delaware Basin and 9,000 acres in the Midland Basin). In connection with the Rosetta Merger, we incurred merger-related costs of approximately $73 million to date, including (i) $58 million of severance, consulting, investment, advisory, legal and other merger-related fees, and (ii) $15 million of noncash share-based compensation expense, all of which were expensed and are included in Other Operating (Income) Expense, Net.
Allocation of Purchase Price - The merger has been accounted for as a business combination, using the acquisition method. The following table represents the preliminary allocation of the total purchase price of Rosetta to the assets acquired and the
Noble Energy, Inc.
Notes to Consolidated Financial Statements
liabilities assumed based on the fair value at the merger date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, valuation of pre-merger contingencies, final tax returns that provide the underlying tax basis of Rosetta's assets and liabilities, and final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the merger date, in line with the acquisition method of accounting, during which time the value of the assets and liabilities, including any goodwill, may be revised as appropriate.
The following table sets forth our preliminary purchase price allocation:
|
| | | |
| (in millions, except stock price) |
Shares of Noble Energy common stock issued to Rosetta shareholders | 41 |
|
Noble Energy common stock price on July 20, 2015 | $ | 36.97 |
|
Fair value of common stock issued | $ | 1,516 |
|
Plus: fair value of Rosetta's restricted stock awards and performance awards assumed | 11 |
|
Plus: Rosetta stock options assumed | 1 |
|
Total purchase price | 1,528 |
|
Plus: liabilities assumed by Noble Energy | |
Accounts Payable | 96 |
|
Current Liabilities | 37 |
|
Long-Term Debt | 1,992 |
|
Other Long Term Liabilities | 24 |
|
Asset Retirement Obligation | 27 |
|
Total purchase price plus liabilities assumed | $ | 3,704 |
|
| |
Fair Value of Rosetta Assets | |
Cash and Equivalents | $ | 61 |
|
Other Current Assets | 74 |
|
Derivative Instruments | 209 |
|
Oil and Gas Properties: | |
Proved Reserves | 1,541 |
|
Undeveloped Leaseholds | 1,165 |
|
Gathering & Processing Assets | 207 |
|
Asset Retirement | 27 |
|
Other Property Plant & Equipment | 5 |
|
Long Term Deferred Tax Asset
| 86 |
|
Implied Goodwill | 329 |
|
Total Asset Value | $ | 3,704 |
|
The fair value measurements of derivative instruments assumed were determined based on published forward commodity price curves as of the date of the merger and represent Level 2 inputs. Derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. The fair value measurements of long-term debt were estimated based on published market prices and represent Level 1 inputs.
The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The results of operations attributable to Rosetta are included in our consolidated statement of operations beginning on July 21, 2015. Revenues of $81 million and pre-tax net income of $43 million from Rosetta were generated from July 21, 2015 to September 30, 2015.
Proforma Financial Information - The following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Rosetta and gives effect to the merger as if it had occurred on January 1, 2014. The below information reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) Noble Energy's common stock and equity awards issued to convert Rosetta's outstanding shares of common stock and equity awards as of the closing date of the merger, (ii) adjustments to conform Rosetta's historical policy of accounting for its oil and natural gas properties from the full cost method to the successful efforts method of accounting, (iii) depletion of Rosetta's fair-valued proved oil and gas properties, and (iv) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings for the three and nine months ended September 30, 2015 were adjusted to exclude $71 million and $73 million, respectively, of merger-related costs incurred by Noble Energy and $32 million and $37 million, respectively, incurred by Rosetta. The pro forma results of operations do not include any cost savings or other synergies that may result from the Rosetta Merger or any estimated costs that have been or will be incurred by us to integrate the Rosetta assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Rosetta Merger taken place on January 1, 2014; furthermore, the financial information is not intended to be a projection of future results.
|
| | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
(in millions, except per share amounts) | 2015 | 2014 | 2015 | 2014 |
Revenues | $ | 828 |
| $ | 1,557 |
| $ | 2,582 |
| $ | 4,828 |
|
Net income | $ | (202 | ) | $ | 542 |
| $ | (338 | ) | $ | 1,039 |
|
| | | | |
Earnings per share: | | | | |
Basic | $ | (0.44 | ) | $ | 1.37 |
| $ | (0.79 | ) | $ | 2.63 |
|
Diluted | $ | (0.44 | ) | $ | 1.35 |
| $ | (0.79 | ) | $ | 2.59 |
|
Note 4. Divestitures
Onshore US Properties During the first nine months of 2015, we sold certain onshore US crude oil and natural gas properties, generating net proceeds of $151 million. Proceeds were primarily applied to the DJ Basin depletable field, with no recognition of gain or loss, other than a de minimis gain in second quarter 2015.
During the first nine months of 2014, we sold certain non-core onshore US crude oil and natural gas properties. The information regarding the assets sold is as follows: |
| | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
(millions) | 2014 | 2014 |
Sales Proceeds | $ | 16 |
| $ | 126 |
|
Less | | |
Net Book Value of Assets Sold | — |
| (118 | ) |
Goodwill Allocated to Assets Sold | (1 | ) | (7 | ) |
Asset Retirement Obligations Associated with Assets Sold | 14 |
| 34 |
|
Other Closing Adjustments | 1 |
| 2 |
|
Gain on Divestitures | $ | 30 |
| $ | 37 |
|
China Sale On June 30, 2014, we closed the sale of our China assets. We determined the sale of our China assets did not meet the criteria for discontinued operations presentation. The information regarding the China assets sold is as follows: |
| | | |
| Nine Months Ended September 30, |
(millions) | 2014 |
Sales Proceeds | $ | 186 |
|
Less | |
Net Book Value of Assets Sold | (149 | ) |
Other Closing Adjustments | (2 | ) |
Gain on Divestiture | $ | 35 |
|
Note 5. Asset Impairments
Pre-tax (non-cash) asset impairment charges were as follows: |
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(millions) | 2015 | | 2014 | | 2015 | | 2014 |
US Properties, Primarily Shelf and Deepwater Gulf of Mexico | $ | — |
| | $ | 2 |
| | $ | 11 |
| | $ | 56 |
|
Eastern Mediterranean | — |
| | 31 |
| | 32 |
| | 14 |
|
North Sea | — |
| | — |
| | — |
| | 94 |
|
Total | $ | — |
| | $ | 33 |
| | $ | 43 |
| | $ | 164 |
|
Impairments for 2015 are primarily related to revisions in expected field abandonment or other costs at South Raton and Lorien (Deepwater Gulf of Mexico) and the Noa and Pinnacles fields (Eastern Mediterranean).
Impairments for 2014 were primarily related to an increase in expected field abandonment costs and a change in the timing of abandonment activities at the North Sea MacCulloch field.
See Note 2. Basis of Presentation, Note 8. Fair Value Measurements and Disclosures and Note 10. Asset Retirement Obligations.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 6. Derivative Instruments and Hedging Activities
Objective and Strategies for Using Derivative Instruments We are exposed to fluctuations in crude oil and natural gas prices. In order to mitigate the effect of commodity price volatility and enhance the predictability of cash flows relating to the marketing of our global crude oil and domestic natural gas, we enter into crude oil and natural gas price hedging arrangements.
While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices. See Note 8. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments. Unsettled Commodity Derivative Instruments As of September 30, 2015, the following crude oil derivative contracts were outstanding: |
| | | | | | | | | | | | | | | | | | |
| | | | Swaps | | Collars |
Settlement Period | Type of Contract | Index | Bbls Per Day | Weighted Average Fixed Price | | Weighted Average Short Put Price | Weighted Average Floor Price | Weighted Average Ceiling Price |
2015 | Swaps | NYMEX WTI | 27,000 |
| $ | 88.80 |
| | $ | — |
| $ | — |
| $ | — |
|
2015 | Swaps | Dated Brent | 8,000 |
| 100.31 |
| | — |
| — |
| — |
|
2015 | Swaps (1) | (2) | 12,000 |
| 89.81 |
| — |
| — |
| — |
| — |
|
2015 | Two-Way Collars | NYMEX WTI | 5,000 |
| — |
| | — |
| 50.00 |
| 64.94 |
|
2015 | Two-Way Collars (1) | (2) | 8,000 |
| — |
| | — |
| 55.00 |
| 84.80 |
|
2015 | Three-Way Collars | NYMEX WTI | 20,000 |
| — |
| | 70.50 |
| 87.55 |
| 94.41 |
|
2015 | Three-Way Collars | Dated Brent | 13,000 |
| — |
| | 76.92 |
| 96.00 |
| 108.49 |
|
1H16 (4) | Swaps | NYMEX WTI | 15,000 |
| 70.31 |
| | — |
| — |
| — |
|
2H16 (4) | Swaps | NYMEX WTI | 12,000 |
| 74.47 |
| | — |
| — |
| — |
|
2016 | Swaps | Dated Brent | 9,000 |
| 97.96 |
| | — |
| — |
| — |
|
2016 | Swaps (1) | (2) | 6,000 |
| 90.28 |
| — |
| — |
| — |
| — |
|
2016 | Two -Way Collars | NYMEX WTI | 1,000 |
| — |
| | — |
| 60.00 |
| 70.00 |
|
2016 | Three-Way Collars | NYMEX WTI | 6,000 |
| — |
| | 61.00 |
| 72.50 |
| 86.37 |
|
2016 | Three-Way Collars | Dated Brent | 8,000 |
| — |
| | 72.50 |
| 86.25 |
| 101.79 |
|
2H16 (4) | Call (3) | NYMEX WTI | 3,000 |
| — |
| | — |
| — |
| 53.65 |
|
2017 | Call (3) | NYMEX WTI | 3,000 |
| — |
| | — |
| — |
| 57.00 |
|
| |
(1) | Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger. |
| |
(2) | The index for these derivative instruments is NYMEX WTI and Argus LLS indices. |
(3) We have entered into crude oil derivative enhanced swaps with strike prices that are above the market value as of trade commencement. To effect the enhanced swap structure, we sold call options to the applicable counterparty to receive the above market terms.
(4) We have entered into NYMEX WTI swap contracts for 3,000 Bbls per day for the first half of 2016 resulting in the difference in hedge volumes for the full year.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
As of September 30, 2015, the following natural gas derivative contracts were outstanding: |
| | | | | | | | | | | | | | | | | |
| | | | Swaps | | Collars |
Settlement Period | Type of Contract | Index | MMBtu Per Day | Weighted Average Fixed Price | | Weighted Average Short Put Price | Weighted Average Floor Price | Weighted Average Ceiling Price |
2015 | Swaps | NYMEX HH | 140,000 |
| $ | 4.30 |
| | $ | — |
| $ | — |
| $ | — |
|
2015 | Swaps (1) | (2) | 50,000 |
| $ | 4.13 |
| | $ | — |
| $ | — |
| $ | — |
|
2015 | Three-Way Collars | NYMEX HH | 150,000 |
| — |
| | 3.58 |
| 4.25 |
| 5.04 |
|
2015 | Two-Way Collars (1) | (2) | 50,000 |
| — |
| | — |
| 3.60 |
| 5.04 |
|
2016 | Swaps (3) | NYMEX HH | 40,000 |
| 3.60 |
| | — |
| — |
| — |
|
2016 | Swaps (1) | (2) | 30,000 |
| 4.04 |
| | — |
| — |
| — |
|
2016 | Two-Way Collars | NYMEX HH | 30,000 |
| — |
| | — |
| 3.00 |
| 3.50 |
|
2016 | Two-Way Collars (1) | (2) | 30,000 |
| — |
| | — |
| 3.50 |
| 5.60 |
|
2016 | Three-Way Collars | NYMEX HH | 90,000 |
| — |
| | 2.83 |
| 3.42 |
| 3.90 |
|
| |
(1) | Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger. |
| |
(2) | The index for these derivative instruments includes a combination of Houston Ship Channel and Tennessee Zone 0 indices. |
| |
(3) | We have entered into certain natural gas derivative contracts (swaptions), which give counterparties the option to extend for an additional 12-month period. Options covering a notional volume of 30,000 MMBtu/d are exercisable on December 22 and 23, 2016. If the counterparties exercise all such options, the notional volume of our existing natural gas derivative contracts will increase by 30,000 MMBtu/d at an average price of $3.50 per MMBtu for each month during the period January 1, 2017 through December 31, 2017. |
As of September 30, 2015, we had assumed the following natural gas liquid derivative instruments, all of which were assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger. The index for these derivative instruments is the Mont Belvieu index.
|
| | | | | | | | | | | | | | | | | |
| | | | Swaps | | Collars |
Settlement Period | Type of Contract | Index | Gallons Per Day | Weighted Average Fixed Price | | Weighted Average Short Put Price | Weighted Average Floor Price | Weighted Average Ceiling Price |
2015 | Swaps | NGL-Ethane | 104,000 |
| $ | 0.27 |
| | $ | — |
| $ | — |
| $ | — |
|
2015 | Swaps | NGL-Propane | 73,500 |
| 1.03 |
| | — |
| — |
| — |
|
2015 | Swaps | NGL-Isobutane | 25,900 |
| 1.26 |
| | — |
| — |
| — |
|
2015 | Swaps | NGL-Normal Butane | 24,300 |
| 1.25 |
| | — |
| — |
| — |
|
2015 | Swaps | NGL-Pentanes Plus | 24,300 |
| 1.85 |
| | — |
| — |
| — |
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Fair Value Amounts and (Gain) Loss on Commodity Derivative Instruments The fair values of commodity derivative instruments in our consolidated balance sheets were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Derivative Instruments |
| Asset Derivative Instruments | | Liability Derivative Instruments |
| September 30, 2015 | | December 31, 2014 | | September 30, 2015 | | December 31, 2014 |
(millions) | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value |
Commodity Derivative Instruments | Current Assets | | $ | 650 |
| | Current Assets | | $ | 710 |
| | Current Liabilities | | $ | — |
| | Current Liabilities | | $ | — |
|
| Noncurrent Assets | | 104 |
| | Noncurrent Assets | | 180 |
| | Noncurrent Liabilities | | 6 |
| | Noncurrent Liabilities | | — |
|
Total | | | $ | 754 |
| | | | $ | 890 |
| | | | $ | 6 |
| | | | $ | — |
|
The effect of commodity derivative instruments on our consolidated statements of operations was as follows:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(millions) | 2015 | | 2014 | | 2015 | | 2014 |
Cash (Received) Paid in Settlement of Commodity Derivative Instruments | | | | | | | |
Crude Oil | $ | (235 | ) | | $ | 14 |
| | $ | (578 | ) | | $ | 87 |
|
Natural Gas | (42 | ) | | (2 | ) | | (98 | ) | | 8 |
|
NGLs | (7 | ) | | — |
| | (7 | ) | | — |
|
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments | (284 | ) | | 12 |
| | (683 | ) | | 95 |
|
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments | | | | | | | |
Crude Oil | 4 |
| | (374 | ) | | 301 |
| | (155 | ) |
Natural Gas | 3 |
| | (23 | ) | | 41 |
| | (14 | ) |
NGLs | 10 |
| | — |
| | 10 |
| | — |
|
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments | 17 |
| | (397 | ) | | 352 |
| | (169 | ) |
(Gain) Loss on Commodity Derivative Instruments | | | | | | | |
Crude Oil | (231 | ) | | (360 | ) | | (277 | ) | | (68 | ) |
Natural Gas | (39 | ) | | (25 | ) | | (57 | ) | | (6 | ) |
NGLs | 3 |
| | — |
| | 3 |
| | — |
|
Total (Gain) Loss on Commodity Derivative Instruments | $ | (267 | ) | | $ | (385 | ) | | $ | (331 | ) | | $ | (74 | ) |
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 7. Debt
Debt consists of the following: |
| | | | | | | | | | | | | |
| September 30, 2015 | | December 31, 2014 |
(millions, except percentages) | Debt | | Interest Rate | | Debt | | Interest Rate |
Credit Facility, due August 27, 2020 | $ | — |
| | — | % | | $ | — |
| | — | % |
Capital Lease and Other Obligations | 424 |
| | — | % | | 413 |
| | — | % |
8.25% Senior Notes, due March 1, 2019 | 1,000 |
| | 8.25 | % | | 1,000 |
| | 8.25 | % |
5.625% Senior Notes, due May 1, 2021 | 693 |
| | 5.625 | % | | — |
| | — | % |
4.15% Senior Notes, due December 15, 2021 | 1,000 |
| | 4.15 | % | | 1,000 |
| | 4.15 | % |
5.875% Senior Notes, due June 1, 2022 | 597 |
| | 5.875 | % | | — |
| | — | % |
7.25% Senior Notes, due October 15, 2023 | 100 |
| | 7.25 | % | | 100 |
| | 7.25 | % |
5.875% Senior Notes, due June 1, 2024 | 499 |
| | 5.875 | % | | — |
| | — | % |
3.90% Senior Notes, due November 15, 2024 | 650 |
| | 3.90 | % | | 650 |
| | 3.90 | % |
8.00% Senior Notes, due April 1, 2027 | 250 |
| | 8.00 | % | | 250 |
| | 8.00 | % |
6.00% Senior Notes, due March 1, 2041 | 850 |
| | 6.00 | % | | 850 |
| | 6.00 | % |
5.25% Senior Notes, due November 15, 2043 | 1,000 |
| | 5.25 | % | | 1,000 |
| | 5.25 | % |
5.05% Senior Notes, due November 15, 2044 | 850 |
| | 5.05 | % | | 850 |
| | 5.05 | % |
7.25% Senior Debentures, due August 1, 2097 | 84 |
| | 7.25 | % | | 84 |
| | 7.25 | % |
Total | 7,997 |
| | | | 6,197 |
| | |
|
Unamortized Discount | (25 | ) | | |
| | (26 | ) | | |
|
Unamortized Premium | 118 |
| | | | — |
| | |
Total Debt, Net of Unamortized Discount and Premium | 8,090 |
| | |
| | 6,171 |
| | |
|
Less Amounts Due Within One Year | |
| | |
| | |
| | |
|
Capital Lease Obligations | (57 | ) | | |
| | (68 | ) | | |
|
Long-Term Debt Due After One Year | $ | 8,033 |
| | |
| | $ | 6,103 |
| | |
|
Credit Facility Our Credit Agreement provides for a $4.0 billion unsecured revolving credit facility (Credit Facility), which is available for general corporate purposes. The Credit Facility (i) provides for facility fee rates that range from 10 basis points to 25 basis points per year depending upon our credit rating, (ii) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility and (iii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 90 basis points to 150 basis points depending upon our credit rating. On August 27, 2015, we entered into the Second Amendment to Credit Agreement (Second Amendment) with JPMorgan Chase Bank, N.A., as administrative agent, and the other commercial lending institutions party thereto. The Second Amendment extended the maturity date of the Credit Agreement, among other things, from October 3, 2018 to August 27, 2020.
Debt Exchange On July 29, 2015, we completed our debt exchange offers to exchange all validly tendered and accepted senior notes assumed in the Rosetta Merger. We were able to exchange 99.4% of the outstanding Rosetta senior notes, whereby we issued (i) $693 million senior unsecured 5.625% notes due May 1, 2021, (ii) $597 million senior unsecured 5.875% notes due June 1, 2022 and (iii) $499 million senior unsecured 5.875% notes due June 1, 2024.
See Note 8. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.
Note 8. 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 may include variable to fixed price commodity swaps, two-way collars, three-way collars, swaptions and extendable swaps. Commodity derivative contracts were valued by a
Noble Energy, Inc.
Notes to Consolidated Financial Statements
third party provider to estimate the fair values of these instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold and the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 6. 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) | | | | | | | | | |
September 30, 2015 | | | | | | | | | |
Financial Assets | | | | | | | | | |
Mutual Fund Investments | $ | 106 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 106 |
|
Commodity Derivative Instruments | — |
| | 759 |
| | — |
| | (5 | ) | | 754 |
|
Financial Liabilities | |
| | |
| | |
| | |
| | |
|
Commodity Derivative Instruments | — |
| | (11 | ) | | — |
| | 5 |
| | (6 | ) |
Portion of Deferred Compensation Liability Measured at Fair Value | (111 | ) | | — |
| | — |
| | — |
| | (111 | ) |
December 31, 2014 | | | | | | | |
| | |
|
Financial Assets | |
| | |
| | |
| | |
| | |
|
Mutual Fund Investments | $ | 111 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 111 |
|
Commodity Derivative Instruments | — |
| | 890 |
| |
|
| | — |
| | 890 |
|
Financial Liabilities | |
| | |
| | |
| | |
| | |
|
Commodity Derivative Instruments | — |
| | — |
| | — |
| | — |
| | — |
|
Portion of Deferred Compensation Liability Measured at Fair Value | (134 | ) | | — |
| | — |
| | — |
| | (134 | ) |
| |
(1) | Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. |
| |
(2) | Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. |
| |
(3) | Level 3 measurements are fair value measurements which use unobservable inputs. |
| |
(4) | Amount represents the impact of netting provisions within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty. |
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are measured at fair value on a nonrecurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:
Asset Impairments Information about impaired assets is as follows: |
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | | | |
Description | Quoted Prices in Active Markets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Book Value (1) | | Total Pre-tax (Non-cash) Impairment Loss |
millions | | | | | | | | | |
Three Months Ended September 30, 2015 | | | | | | | | |
Impaired Oil and Gas Properties | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Three Months Ended September 30, 2014 | | | | | | | | |
Impaired Oil and Gas Properties | — |
| | — |
| | 9 |
| | 42 |
| | 33 |
|
Nine Months Ended September 30, 2015 | | | | | | | | |
Impaired Oil and Gas Properties | $ | — |
| | $ | — |
| | $ | — |
| | $ | 43 |
| | $ | 43 |
|
Nine Months Ended September 30, 2014 | | | | | | | | |
Impaired Oil and Gas Properties | — |
| | — |
| | 23 |
| | 187 |
| | 164 |
|
(1) Amount represents net book value at the date of assessment.
The fair value of impaired oil and gas properties was determined as of the date of the assessment using a discounted cash flow model based on management’s expectations of future crude oil and natural gas production prior to abandonment date, commodity prices based on NYMEX WTI, NYMEX Henry Hub, and Brent future price curves as of the date of the estimate, estimated operating and abandonment costs, and a risk-adjusted discount rate. Impairments for the first nine months of 2015 were due primarily to increases in asset carrying values associated with increases in estimated field abandonment costs. See Note 5. Asset Impairments. Goodwill As of September 30, 2015, we had allocated $945 million of goodwill to our US reporting unit, including goodwill associated with the Rosetta Merger, which may be revised as we complete our purchase price allocation for that transaction. We assess goodwill for impairment annually during the fourth quarter, or more frequently as circumstances require, at the reporting unit level. At September 30, 2015, we performed a qualitative assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as: macroeconomic conditions; industry and market conditions, including current commodity prices; earnings and cash flows; overall financial performance; segment dispositions and acquisitions; and other relevant entity-specific events. Based upon our qualitative assessment of these circumstances, we concluded that a full impairment test was warranted. Accordingly, we estimated the fair value of our US reporting unit using a combination of the income approach and the market approach. We then estimated the implied fair value of goodwill based upon this valuation analysis. These procedures indicated no impairment at September 30, 2015.
Additional Fair Value Disclosures
Debt The fair value of public, fixed-rate 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.
Fair value information regarding our debt is as follows: |
| | | | | | | | | | | | | | | |
| September 30, 2015 | | December 31, 2014 |
(millions) | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
Total Debt, Net of Unamortized Discount and Premium (1) | $ | 7,666 |
| | $ | 7,497 |
| | $ | 5,758 |
| | $ | 6,179 |
|
| |
(1) | Excludes capital lease obligations. |
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 9. Capitalized Exploratory Well Costs
We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. On a quarterly basis, we review the status of suspended exploratory well costs and assess the development of these projects. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost.
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period: |
| | | |
(millions) | Nine Months Ended September 30, 2015 |
Capitalized Exploratory Well Costs, Beginning of Period | $ | 1,337 |
|
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves | 123 |
|
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves | (24 | ) |
Capitalized Exploratory Well Costs Charged to Expense (1) | (23 | ) |
Capitalized Exploratory Well Costs, End of Period | $ | 1,413 |
|
(1) Relates primarily to onshore US exploration activity.
The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced, and the number of projects that have been capitalized for a period greater than one year:
|
| | | | | | | |
(millions) | September 30, 2015 | | December 31, 2014 |
Exploratory Well Costs Capitalized for a Period of One Year or Less | $ | 154 |
| | $ | 247 |
|
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 1,259 |
| | 1,090 |
|
Balance at End of Period | $ | 1,413 |
| | $ | 1,337 |
|
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 14 |
| | 13 |
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The following table includes exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of September 30, 2015: |
| | | | | |
| | | |
(millions) | Total by Project | | Progress |
Country/Project: | | | |
Onshore US | | | |
Northeast Nevada | $ | 40 |
| | Analyzing results from our first four exploratory vertical wells, and evaluating potential for production tests. |
Deepwater Gulf of Mexico | | | |
Katmai | 80 |
| | Anticipate drilling an appraisal well in 2016 to test the resource potential of this 2014 crude oil discovery. |
Troubadour | 48 |
| | Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure. |
Offshore Equatorial Guinea (Blocks O and I) | |
| | |
Diega/Carmen | 236 |
| | Evaluating regional development scenarios for this 2008 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks O and I and are engaged in processing the newly-acquired seismic data to determine an appropriate development plan. |
Carla | 170 |
| | Evaluating regional development scenarios for this 2011 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks O and I and are engaged in processing the newly-acquired seismic data. |
Felicita/Yolanda | 59 |
| | Evaluating regional development plans for these 2008/2007 condensate and natural gas discoveries. Natural gas development teams are working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options and finalize data exchange agreements between the two countries. |
Offshore Cameroon | |
| | |
YoYo | 49 |
| | Working with the government to assess commercialization of this 2007 condensate and natural gas discovery. A natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options and finalize a data exchange agreement between the two countries. |
Offshore Israel (1) | |
| | |
Leviathan | 190 |
| | During 2014, we received the Leviathan Development and Production Leases, submitted a development plan to the Israeli government, completed substantial engineering and pre-procurement activities and are currently negotiating natural gas marketing contracts in anticipation of the pending enactment of the Framework. |
Leviathan-1 Deep | 81 |
| | Well did not reach the target interval; developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases. We are working on potential well design and placement. |
Noble Energy, Inc.
Notes to Consolidated Financial Statements
|
| | | | | |
Dalit | 29 |
| | Submitted a development plan to the Israeli government to develop this 2009 natural gas discovery as a tie-in to existing infrastructure. |
Dolphin 1 | 26 |
| | Reviewing regional development scenarios for this 2011 natural gas discovery, including a potential tieback to Leviathan. We have applied to the Israeli government for a commerciality ruling. |
Offshore Cyprus | | | |
Cyprus | 210 |
| | Submitted a Declaration of Commerciality and a Preliminary Development Plan for Block 12 with the government of Cyprus. We have received approval of the extension request for our exploration obligation well from the government of Cyprus. |
Other | |
| | |
Individual Projects Less than $20 million | 41 |
| | Continuing to drill and evaluate wells. |
Total | $ | 1,259 |
| | |
(1) We are currently working to resolve antitrust and other regulatory matters with the Israeli government to enable Leviathan and other developments to move forward. See Note 2. Basis of Presentation – Update on Core Area – Israel.
Note 10. Asset Retirement Obligations
Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows: |
| | | | | | | |
| Nine Months Ended September 30, |
(millions) | 2015 | | 2014 |
Asset Retirement Obligations, Beginning Balance | $ | 751 |
| | $ | 586 |
|
Liabilities Incurred | 54 |
| | 38 |
|
Liabilities Settled | (29 | ) | | (77 | ) |
Revision of Estimate | 79 |
| | 123 |
|
Accretion Expense (1) | 32 |
| | 28 |
|
Asset Retirement Obligations, Ending Balance | $ | 887 |
| | $ | 698 |
|
(1) Accretion expense is included in DD&A expense in the consolidated statements of operations.
For the nine months ended September 30, 2015
Liabilities incurred were due to new wells and facilities for onshore US and deepwater Gulf of Mexico as well as liabilities assumed by us in the Rosetta Merger. Liabilities settled relate primarily to non-core, onshore US properties sold.
Revisions of estimates relate to changes in cost estimates and included $43 million for Eastern Mediterranean and $28 million for DJ Basin.
For the nine months ended September 30, 2014
Liabilities incurred were due to new wells and facilities for onshore US, deepwater Gulf of Mexico, and Eastern Mediterranean. Liabilities settled primarily related to onshore US property abandonments and non-core, onshore US assets sold.
Revisions of estimates included $67 million for the North Sea McCulloch field due to an increase in costs and a change in timing. See Note 5. Asset Impairments. Additional revisions of $21 million for DJ Basin, $16 million for Equatorial Guinea, $9 million for Eastern Mediterranean, and $9 million for deepwater Gulf of Mexico were due to changes in cost and timing estimates.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 11. 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 September 30, | | Nine Months Ended September 30, |
(millions, except per share amounts) | 2015 | | 2014 | | 2015 | | 2014 |
Net Income (Loss) | $ | (283 | ) | | $ | 419 |
| | $ | (413 | ) | | $ | 811 |
|
Earnings Adjustment from Assumed Conversion of Dilutive Shares of Common Stock in Rabbi Trust (2) | — |
| | (8 | ) | | — |
| | — |
|
Net Income (Loss) Used for Diluted Earnings Per Share Calculation | $ | (283 | ) | | $ | 411 |
| | $ | (413 | ) | | $ | 811 |
|
| | | | | | | |
Weighted Average Number of Shares Outstanding, Basic (1) | 420 |
| | 362 |
| | 392 |
| | 361 |
|
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust (2) | — |
| | 5 |
| | — |
| | 6 |
|
Weighted Average Number of Shares Outstanding, Diluted | 420 |
| | 367 |
| | 392 |
| | 367 |
|
Earnings (Loss) Per Share, Basic | $ | (0.67 | ) | | $ | 1.16 |
| | $ | (1.05 | ) | | $ | 2.25 |
|
Earnings (Loss) Per Share, Diluted | (0.67 | ) | | 1.12 |
| | (1.05 | ) | | 2.21 |
|
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above | 14 |
| | 2 |
| | 11 |
| | 3 |
|
| |
(1) | The weighted average number of shares outstanding includes the weighted average shares of common stock issued in connection with the underwritten public offering of 24.15 million shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately 41 million shares for all outstanding shares of Rosetta common stock on July 20, 2015. |
| |
(2) | For the three and nine months ended September 30, 2015, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted EPS as Noble Energy incurred losses. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted EPS would be anti-dilutive. Consistent with GAAP, when dilutive, deferred compensation gains or losses, net of tax, are excluded from net income while our common shares held in the rabbi trust are included in the diluted share count. For this reason, the diluted earnings per share calculations for the three months ended September 30, 2014 excluded deferred compensation (gains) losses, net of tax. The deferred compensation loss, net of tax, excluded for the calculation of diluted earnings per share for the nine months ended September 30, 2014 was de minimis. |
Note 12. Income Taxes
The income tax provision relating to continuing operations consists of the following:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(millions) | 2015 | | 2014 | | 2015 | | 2014 |
Current | $ | (45 | ) | | $ | 120 |
| | $ | 64 |
| | $ | 213 |
|
Deferred | 69 |
| | 37 |
| | (244 | ) | | 61 |
|
Total Income Tax (Benefit) Provision | $ | 24 |
| | $ | 157 |
| | $ | (180 | ) | | $ | 274 |
|
Effective Tax Rate | (9.3 | )% | | 27.2 | % | | 30.4 | % | | 25.3 | % |
At the end of each interim period, we apply our best estimate of our effective tax rate (ETR) expected to be applicable for the full year, which can result in interim ETR fluctuations. Our ETR for the three and nine months ended September 30, 2015 varied as compared with the three and nine months ended September 30, 2014 primarily as a result of a tax benefit. In the case of a pre-tax loss, our favorable permanent differences, such as income from equity method investees and increased earnings in our foreign jurisdictions with rates that vary from the US statutory rate, have the effect of increasing the tax benefit which, in turn, increases the ETR.
In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2012, Equatorial Guinea – 2010 and Israel – 2010.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 13. Segment Information
We have operations throughout the world and manage our global operations by country. The following information is grouped into four components that are all in the business of crude oil and natural gas exploration, development, production, and acquisition: the United States; West Africa (Equatorial Guinea, Cameroon, Gabon, and Sierra Leone, (which we have exited); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes the North Sea, China (through June 30, 2014), Falkland Islands, Nicaragua (which we have exited) and new ventures. |
| | | | | | | | | | | | | | | | | | | |
(millions) | Consolidated | | United States | | West Africa | | Eastern Mediterranean | | Other Int'l & Corporate |
Three Months Ended September 30, 2015 | | | | | | | | | |
Revenues from Third Parties | $ | 765 |
| | $ | 492 |
| | $ | 120 |
| | $ | 152 |
| | $ | 1 |
|
Income (Loss) from Equity Method Investees | 36 |
| | 16 |
| | 20 |
| | — |
| | — |
|
Total Revenues | 801 |
| | 508 |
| | 140 |
| | 152 |
| | 1 |
|
DD&A | 539 |
| | 437 |
| | 67 |
| | 22 |
| | 13 |
|
(Gain) Loss on Commodity Derivative Instruments | (267 | ) | | (187 | ) | | (80 | ) | | — |
| | — |
|
Income (Loss) Before Income Taxes | (259 | ) | | (189 | ) | | 98 |
| | 107 |
| | (275 | ) |
Three Months Ended September 30, 2014 | |
| | |
| | |
| | |
| | |
|
Revenues from Third Parties | $ | 1,228 |
| | $ | 819 |
| | $ | 269 |
| | $ | 138 |
| | $ | 2 |
|
Income from Equity Method Investees | 41 |
| | — |
| | 41 |
| | — |
| | — |
|
Total Revenues | 1,269 |
| | 819 |
| | 310 |
| | 138 |
| | 2 |
|
DD&A | 460 |
| | 351 |
| | 70 |
| | 17 |
| | 22 |
|
Gain on Divestitures | (30 | ) | | (30 | ) | | — |
| | — |
| | — |
|
Asset Impairments | 33 |
| | 33 |
| | — |
| | — |
| | — |
|
(Gain) Loss on Commodity Derivative Instruments | (385 | ) | | (252 | ) | | (133 | ) | | — |
| | — |
|
Income (Loss) Before Income Taxes | 576 |
| | 457 |
| | 321 |
| | 90 |
| | (292 | ) |
Nine Months Ended September 30, 2015 | | | | | | | | | |
Revenues from Third Parties | $ | 2,227 |
| | $ | 1,411 |
| | $ | 432 |
| | $ | 378 |
| | $ | 6 |
|
Income from Equity Method Investees | 60 |
| | 35 |
| | 25 |
| | — |
| | — |
|
Total Revenues | 2,287 |
| | 1,446 |
| | 457 |
| | 378 |
| | 6 |
|
DD&A | 1,444 |
| | 1,138 |
| | 223 |
| | 52 |
| | 31 |
|
Asset Impairments | 43 |
| | 11 |
| | — |
| | 32 |
| | — |
|
(Gain) Loss on Commodity Derivative Instruments | (331 | ) | | (231 | ) | | (100 | ) | | — |
| | — |
|
Income (Loss) Before Income Taxes | (593 | ) | | (353 | ) | | 195 |
| | 227 |
| | (662 | ) |
Nine Months Ended September 30, 2014 | |
| | |
| | |
| | |
| | |
|
Revenues from Third Parties | $ | 3,893 |
| | $ | 2,503 |
| | $ | 931 |
| | $ | 363 |
| | $ | 96 |
|
Income from Equity Method Investees | 138 |
| | — |
| | 138 |
| | — |
| | — |
|
Total Revenues | 4,031 |
| | 2,503 |
| | 1,069 |
| | 363 |
| | 96 |
|
DD&A | 1,297 |
| | 970 |
| | 218 |
| | 46 |
| | 63 |
|
Gain on Divestitures | (72 | ) | | (36 | ) | | — |
| | — |
| | (36 | ) |
Asset Impairments | 164 |
| | 56 |
| | — |
| | 14 |
| | 94 |
|
(Gain) Loss on Commodity Derivative Instruments | (74 | ) | | (6 | ) | | (68 | ) | | — |
| | — |
|
Income (Loss) Before Income Taxes | 1,085 |
| | 838 |
| | 786 |
| | 211 |
| | (750 | ) |
September 30, 2015 | |
| | |
| | |
| | |
| | |
|
Total Assets | $ | 25,965 |
| | $ | 20,052 |
| | $ | 2,240 |
| | $ | 2,503 |
| | $ | 1,170 |
|
December 31, 2014 | |
| | |
| | |
| | |
| | |
|
Total Assets | 22,553 |
| | 16,400 |
| | 2,763 |
| | 2,806 |
| | 584 |
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 14. Commitments and Contingencies
CONSOL Carried Cost Obligation In accordance with our Marcellus Shale joint venture arrangement with a subsidiary of CONSOL Energy Inc. (CONSOL), we agreed to fund one-third of CONSOL's 50% working interest share of future drilling and completion costs, capped at $400 million each year (CONSOL Carried Cost Obligation). The remaining obligation totaled approximately $1.6 billion at September 30, 2015.
The CONSOL Carried Cost Obligation is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and remain suspended until average Henry Hub natural gas prices equal or exceed $4.00 per MMBtu for three consecutive months. The CONSOL Carried Cost Obligation is currently suspended due to current natural gas prices. Based on the September 30, 2015 NYMEX Henry Hub natural gas price curve, we expect that the CONSOL Carried Cost Obligation will be suspended for the next 12 months.
Legal Proceedings We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Air Matter In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency, US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream oil and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was entered by the Court on June 2, 2015.
The Consent Decree, which alleges violations of the Colorado Air Pollution Prevention and Control Act and Colorado’s federal approved State Implementation Plan, specifically Colorado Air Quality Control Commission Regulation Number 7, requires us to perform certain injunctive relief activities to complete mitigation projects and supplemental environmental projects (SEP), and pay a civil penalty. Costs associated with the settlement consist of $4.95 million in civil penalties, $4.5 million in mitigation projects, and $4 million in SEPs. Costs associated with the injunctive relief are not yet precisely quantifiable as they will be determined in accordance with the outcome of evaluations on the adequate design, operation, and maintenance of certain aspects of tank systems to handle potential peak instantaneous vapor flow rates between now and mid-2017.
Compliance with the Consent Decree could result in the temporary shut in or permanent plugging and abandonment of certain wells and associated tank batteries. The Consent Decree sets forth a detailed compliance schedule with deadlines for achievement of milestones through early 2019. The Consent Decree contains additional obligations for ongoing inspection and monitoring beyond that which is required under existing Colorado regulations. Inspection and monitoring findings may influence decisions to temporarily shut in or permanently plug and abandon wells and associated tank batteries.
We have concluded that the penalties, injunctive relief, and mitigation expenditures that resulted from this settlement did not have, and based on currently available information will not have, a material adverse effect on our financial position, results of operations or cash flows.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a narrative about our business from the perspective of our management. We use common industry terms, such as thousand barrels of oil equivalent per day (MBoe/d) and million cubic feet equivalent per day (MMcfe/d), to discuss production and sales volumes. Our MD&A is presented in the following major sections:
The preceding consolidated financial statements, including the notes thereto, contain detailed information that should be read in conjunction with our MD&A.
EXECUTIVE OVERVIEW
We are a globally diversified explorer and producer of crude oil, natural gas and natural gas liquids. We aim to achieve sustainable growth in value and cash flow through exploration success and the development of a high-quality, worldwide portfolio of assets with investment flexibility between: onshore unconventional developments and offshore organic exploration leading to major development projects; US and international development projects; and production mix among crude oil, natural gas, and NGLs. Our legacy core operating areas include the DJ Basin and Marcellus Shale (onshore US), deepwater Gulf of Mexico, offshore West Africa, and offshore Eastern Mediterranean, where we have a strategic competitive advantage and which we believe will generate attractive returns. We recently added two new core operating areas in the Eagle Ford Shale and the Permian Basin as a result of our merger with Rosetta. We also seek to enter other potential new core areas and are conducting exploration activities in domestic and international locations such as Northeast Nevada, the Falkland Islands, Cameroon, Suriname and Gabon.
Third Quarter 2015 Significant Operating Highlights Included:
| |
• | completed the Rosetta Merger, resulting in our entry into the Eagle Ford Shale and Permian Basin (see Rosetta Merger, below); |
| |
• | progressed cost reduction efforts in capital, lease operating expense and general and administrative areas and continue to pursue further reductions to align spending with operational cash flows in the current commodity price environment (see Cost Reduction Efforts, below); |
| |
• | achieved substantial progress on the regulatory Framework in Israel (see Update on Core Area – Israel, below); |
| |
• | continued to advance our Cyprus development plan with the government of Cyprus and filed a request for extension of the exploration well obligation, which has been approved; |
| |
• | progressed development of our Gulf of Mexico Big Bend and Dantzler projects, which are anticipated to commence production in fourth quarter 2015; |
| |
• | averaged 379 MBoe/d production volumes and achieved record quarterly production volumes in the DJ Basin, Marcellus Shale and Israel assets; |
| |
• | realized expansion of our and third party midstream capacity in the DJ Basin, which supported significant production growth in that core area; |
| |
• | successfully commenced production from Alba C-21 development well, Equatorial Guinea, ahead of schedule; and |
| |
• | completed the Cheetah exploration well in the Tilapia license offshore Cameroon and Humpback exploration well located in the South Falkland Basin, which resulted in dry hole expenses of $27 million and $108 million, respectively. |
Third Quarter 2015 Financial Results Included:
| |
• | net loss of $283 million, as compared with net income of $419 million for third quarter 2014; |
| |
• | net gain on commodity derivative instruments of $267 million as compared with a net gain on commodity derivative instruments of $385 million for third quarter 2014; |
| |
• | diluted loss per share of $0.67, as compared with diluted earnings per share of $1.12 for third quarter 2014; |
| |
• | cash flow provided by operating activities of $520 million, as compared with $945 million for third quarter 2014; |
| |
• | capital expenditures of $664 million, as compared with $1.3 billion for third quarter 2014; |
| |
• | extension of the maturity date of our Credit Agreement to August 27, 2020; and |
| |
• | repatriation of $412 million from our foreign operations. |
Quarter-End Key Financial Metrics Included:
| |
• | ending cash balance of $1.0 billion, as compared with $1.2 billion at December 31, 2014; |
| |
• | total liquidity of $5.0 billion at September 30, 2015, as compared with $5.2 billion at December 31, 2014; and |
| |
• | ratio of debt-to-book capital of 39% at September 30, 2015, as compared with 38% at December 31, 2014. |
Rosetta Merger
On July 20, 2015, we completed the Rosetta Merger. This merger adds two premier onshore US shale positions to our core operating areas: the Eagle Ford Shale and Permian Basin. Rosetta's liquids-rich asset base included approximately 50,000 net acres in the Eagle Ford and 54,000 net acres in the Permian (45,000 acres in the Delaware Basin and 9,000 acres in the Midland Basin). The Eagle Ford in particular will provide significant near-term growth to our production. Together with the Permian Basin, the Eagle Ford increases our year-end 2014 reserves and production by approximately 20%. We anticipate continuing to improve drilling and well performance in these unconventional plays by applying best practices from our onshore business and by capitalizing on Noble Energy - Rosetta synergies. See Item 1. Financial Statements - Note 3. Rosetta Merger. Cost Reduction Efforts
During the first nine months of 2015, we have focused on maintaining our strong safety culture, driving operational efficiencies and productivity and reducing our cost structure. Cost reduction initiatives, including both operational enhancements and new pricing arrangements with suppliers, have resulted in reduced unit costs of 14% and 32% in lease operating expense and general and administrative expense, respectively, during the first nine months of 2015. Our diverse global portfolio provides significant optionality, allowing us to reduce our capital spending by 36% for the first nine months of 2015, as compared to the same period of 2014. This capital spending reduction, coupled with cost reduction activities, has aligned overall cash expenditures more closely to operating cash flows in the current commodity price environment. The closing of our Ardmore, Oklahoma location and other corporate restructuring activities resulted in corporate restructuring expense of $21 million and stacked rig expense of $13 million during third quarter 2015. See Operating Outlook – 2015 Capital Investment Program below.
Sales Volumes
On a BOE basis, total sales volumes were 25% higher for third quarter 2015 as compared with third quarter 2014, and our mix of sales volumes was 44% global liquids, 23% international natural gas, and 33% US natural gas. On a BOE basis and excluding the impact of the Rosetta Merger, total sales volumes were 12% higher for third quarter 2015 as compared with third quarter 2014, and our mix of sales volumes was 42% global liquids, 26% international natural gas, and 32% US natural gas. See Results of Operations – Revenues, below.
Commodity Price Changes
The upstream oil and gas business is cyclical. During 2014, natural gas prices declined steadily, and, during fourth quarter 2014, a significant decline in crude oil prices occurred. During the first nine months of 2015, global commodity prices have continued to trade in this lower range, or declined further. In addition, location differentials have increased in some regions, such as the Marcellus Shale, resulting in further declines in realized natural gas prices. For third quarter 2015, our consolidated average realized prices decreased 55% for crude oil, 23% for natural gas and 74% for NGLs as compared with third quarter 2014. We are unable to predict future commodity prices and prices are likely to remain volatile.
We plan for commodity price cyclicality in our business and believe we are well positioned to withstand current and future commodity price volatility due to the following:
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• | we have a high-quality, globally diversified portfolio of assets, the majority of which are held by production and provide investment flexibility; |
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• | we have achieved sustainable cost reductions impacting both operating expenses and capital items, positively impacting operating cash flows; |
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• | we are focused on operational efficiencies and projects that can be profitable in this current commodity price environment; |
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• | we have designed a substantially reduced capital investment program which allows us to respond to changing commodity price conditions in 2015 and 2016; |
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• | we are well hedged for the remainder of 2015, with additional hedges into 2016; |
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• | we have a strong balance sheet with a ratio of debt-to-book capital of 39% at September 30, 2015; and |
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• | we have robust liquidity with total liquidity of $5.0 billion at September 30, 2015 and ability to access capital markets. |
Major Development Project Updates
We continue to advance our major development projects, which we expect to deliver incremental production over the next several years. Updates on major development projects are as follows:
Sanctioned Ongoing Development Projects
A "sanctioned" development project is one for which a final investment decision has been made.
DJ Basin (Onshore US) We currently have a position in excess of 400,000 net acres, the majority of which are included within our integrated development plan (IDP) areas. During the quarter, we operated four drilling rigs (reducing to three rigs in September), drilled 39 horizontal wells and commenced production on 58 wells. Third party infrastructure also continued to improve, including the ramp-up of the third-party Lucerne-2 natural gas processing plant. The Lucerne capacity, along with recently-completed compression projects in the region, has resulted in lower line pressures and increased production flow.
Marcellus Shale (Onshore US) During the quarter, we and our joint venture partner averaged one horizontal drilling rigs. We drilled six operated wells and commenced production on 16 operated wells. Our joint venture partner drilled seven wells and commenced production on 12 wells. In response to the current natural gas and NGL pricing environment, we and our partner will continue with limited completion activity during the fourth quarter 2015.
Texas (Onshore US) On July 20, 2015, we completed the Rosetta Merger, adding the Eagle Ford Shale and Permian Basin to our portfolio. In the Eagle Ford, we operated one rig, drilled six wells and commenced production on three wells. In the Permian Basin, we operated one rig and drilled one well before releasing the rig in September 2015. See Note 3. Rosetta Merger. Gunflint (Deepwater Gulf of Mexico) Development is on track for the Gunflint (31% operated working interest) crude oil discovery, utilizing a two-well subsea tieback to the Gulfstar One spar. During third quarter 2015, we successfully drilled a second development well. First production is targeted for mid-2016.
Big Bend and Dantzler (Deepwater Gulf of Mexico) A co-development project is underway for the Big Bend (54% operated working interest) and Dantzler (45% operated working interest) crude oil discoveries, located in the Rio Grande area of the deepwater Gulf of Mexico, which will tie back to the Thunder Hawk semi-submersible production facility. First production for both Big Bend and Dantzler is targeted for fourth quarter 2015.
Alba Field (Offshore Equatorial Guinea) During second quarter 2015, the field operator successfully drilled the C-21 development well and production commenced in third quarter 2015. The multi-year compression project continues as planned with anticipated start-up in mid-2016.
Tamar Southwest We continue to work with the Israeli government to obtain regulatory approval of our development plan for the Tamar Southwest discovery, which is intended to utilize current Tamar infrastructure. We have suspended this project following continued delays in securing regulatory approvals. We have petitioned the Israeli courts to expedite the needed approvals. Timely development of Tamar Southwest is important to maintain well capacity and reliability for our overall Tamar project. See Update on Core Area – Israel, below.
North Sea During third quarter 2015, the operator of the MacCulloch Field completed phase I of the decommissioning program, which included subsea disconnection, cleaning and cutting of risers and demobilization of the floating production, storage and offloading vessel (FPSO). Phase II and III, removal of subsea infrastructure and permanent abandonment of all wells, are ongoing and forecasted for completion by 2020. Also, during this period decommission activities were completed at our non-operated Selkirk and Bligh Wells.
Unsanctioned Development Projects
Tamar Expansion Project (Offshore Israel) We have engaged in the planning phase for an expansion project which would expand Tamar field deliverability to approximately 2.0 Bcf/d. Timing of project sanction depends on satisfactory resolution of antitrust and other regulatory matters. See Update on Core Area – Israel, below.
Leviathan Project (Offshore Israel) In 2014, we submitted the Plan of Development to the Ministry of National Infrastructures, Energy and Water Resources. The development plan is expected to serve both domestic demand and export. Timing of project sanction depends on satisfactory resolution of antitrust and other regulatory matters, including adoption of the Framework intended to address and clarify many of the outstanding regulatory issues we and our partners face in developing our offshore assets, as well as execution of natural gas sales and purchase agreements, which will be subject to, among other conditions, the receipt of regulatory approvals. Project financing will also be required. We are engaged with the governments of the US, Israel, Jordan and Egypt on this project. See Update on Core Area – Israel, below.
Cyprus Project (Offshore Cyprus) During second quarter 2015, we submitted a Declaration of Commerciality and a Preliminary Development Plan for Block 12 (Aphrodite, 70% operated working interest) with the government of Cyprus, with which we continue to work to finalize our development plan. Furthermore, we and our partners are performing pre-FEED work for a potential development that envisions a regional natural gas export project to potential natural gas customers in Cyprus and Egypt. There is also potential for a farm-out arrangement of our working interest. In third quarter 2015, we filed an extension request for our 2015 exploration well obligation with the government of Cyprus. Subsequent to third quarter 2015, we received approval of the extension request to May 2016.
Exploration Program Update
We have numerous exploration opportunities remaining in our core areas and are also engaged in new venture activity in both US and international locations.
We were in the process of drilling and/or evaluating significant exploratory wells at September 30, 2015, and expect to conduct additional exploratory activities.
A portion of our 2015 capital investment program is dedicated to exploration and associated appraisal activities. 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 development project is not economically or operationally viable.
In the event we conclude that one of our exploratory wells did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs would be recorded as dry hole expense.
Additionally, we may not be able to conduct exploration activities prior to lease expirations. As a result, in a future period, dry hole cost and/or leasehold abandonment expense could be significant. See Item 1. Financial Statements – Note 9. Capitalized Exploratory Well Costs and Operating Outlook – Potential for Future Impairment, Dry Hole or Lease Abandonment Expense, below. Updates on significant exploration activities are as follows:
Northeast Nevada We have drilled four exploratory wells to date. To assess commercial viability, additional exploration and appraisal work will be required. In the current commodity price environment, we are assessing our future plans and may consider divestment opportunities.
Deepwater Gulf of Mexico We currently have an inventory of identified prospects, which are a combination of both high impact subsalt prospects and smaller, high value tie-back opportunities. These prospects are subject to an ongoing technical maturation process and may or may not emerge as drillable options. We are preparing an exploration and appraisal program for 2016, which will likely include an exploration well at our Silvergate prospect (Mississippi Canyon 339, 50% operated working interest) and an appraisal well at our Katmai discovery made during third quarter 2014 (Green Canyon Block 40, 50% operated working interest).
Offshore West Africa We are currently processing the results of recently acquired 3D seismic data across Equatorial Guinea Blocks O and I which will aid in advancing other regional exploration and development opportunities, including the Diega/Carmen and Carla discoveries.
In July 2015, we spud the Cheetah exploration prospect on the Tilapia license offshore Cameroon (46.67% working interest) and completed drilling activities in third quarter 2015. The well encountered both crude oil and natural gas shows in multiple non-commercial reservoir sands and was plugged and abandoned. In third quarter 2015, we recorded dry hole costs of $27 million associated with this exploratory well. Results from the well are being integrated into our geologic modeling for the
remaining exploration potential in the Tilapia license. We are also evaluating the results of recent reprocessing of 3D seismic data over our YoYo mining concession.
Offshore Eastern Mediterranean See Update on Core Area – Israel, below.
Offshore Falkland Islands Drilling operations at the Humpback prospect (35% operated working interest), located in the South Falkland Basin, began in June 2015. We completed drilling activities, and after evaluating results, we will plug and abandon this exploratory well as we did not locate commercial quantities of hydrocarbons. As a result, we recorded dry hole costs of $108 million in third quarter 2015. In the North Falkland Basin, we have identified the Rhea prospect (75% operated working interest) as the initial target on the PL001 License and expect to commence drilling late fourth quarter 2015. The PL001 License covers an area of approximately 280,000 gross acres.
An Argentine court has initiated a criminal investigation against Noble Energy and other oil and gas companies regarding their exploration activities offshore Falkland Islands. The court has also issued a preservation order against the relevant companies to preserve assets in the event of any judgment. The investigation is premised on Argentina’s claim that the Falkland Islands are a part of its territory. Argentina does not recognize the United Kingdom’s sovereignty over the Falkland Islands or the Falkland Islanders rights to exploit their natural resources. The Falkland Islands are part of the United Kingdom’s overseas territories and are afforded full self-governance. Our concessions are with the Falkland Islands Government and we do not believe that Argentina has any authority over our operations in the Falkland Islands.
Offshore Suriname In October 2015, we acquired a non-operated 20% working interest in Block 54 offshore Suriname via farm-in from Tullow Oil plc. Tullow is the operator with a 30% interest. The initial phase of exploration on the block requires acquisition of a 3D seismic survey, which has been completed and is currently being processed. Evaluation of the seismic survey will determine if a commitment to a subsequent exploration phase to drill an exploration well is warranted.
Offshore Gabon We are the operator of Block F15 (60% working interest), an undeveloped, ultra-deep water area, covering 670,000 gross acres. The exploration phase is underway and we are planning to conduct a proprietary 3D seismic survey in the first half of 2016.
Update on Core Area – Israel
Noble Energy and its partners have remained committed to providing natural gas to Israeli citizens for over a decade. We have delivered approximately 1.6 Tcf, gross, of natural gas to Israeli customers, including the Israel Electric Corporation (IEC), the largest supplier of electricity in the country.
Since obtaining our first exploration license in 1998, Noble Energy has been the first, and only, oil and natural gas company to successfully explore for significant amounts of hydrocarbons offshore Israel. We are also the first company to construct, operate and produce from a major development project offshore Israel. We have invested significant amounts of capital in exploration and development activities since 1998. Throughout this time, we have focused on partnering with our customers and the Israeli government to provide a reliable fuel source to support affordable energy for the State of Israel’s citizens.
Since our initial discovery at Mari-B in 2000, we and our partners have continued to reinvest for long-term growth, leasing additional acreage and conducting exploration activities offshore Israel, in pursuit of additional resources to meet increasing demand from Israeli consumers and global markets. Our exploration efforts resulted in numerous natural gas discoveries over the past several years. The Tamar and Leviathan discoveries, in particular, are large-scale, high-quality reservoirs of global significance, providing substantial additional resources for the government, citizens of Israel and the region. We developed the Tamar field with a discovery to production cycle time of approximately four years, which is exceptionally fast by historical industry standards for an offshore natural gas project of this magnitude and complexity.
The quantity of discovered natural gas resources at Tamar and Leviathan have positioned Israel to meet domestic needs for decades and to become a significant natural gas exporter. Multiple regional markets exist and Israel’s domestic demand is predicted to continue to grow over the next decade. Eastern Mediterranean export projects are well positioned to supply growing regional and global natural gas demand, which would provide benefits beyond satisfying domestic consumption of natural gas. We are working with potential customers to supply natural gas through a regional pipeline system and/or LNG facilities. Government export royalties and tax revenues related to regional export sales would provide material financial benefit for Israel’s citizens.
In addition to our natural gas discoveries, the Levant Basin also has potential for large scale crude oil discoveries, which may exist at greater depths. We have conducted preliminary exploration activities and have been planning to complete our test of two deeper intervals.
We have been progressing plans to develop the Leviathan field and expand the currently-producing Tamar field. However, the regulatory environment in Israel remains challenging and uncertain. Laws, regulations and guidelines have been modified, sometimes with retroactive impacts, resulting in an unpredictable investment climate. Timing of approval for development plans has been delayed, and consequently our ability to make significant, long-term investment decisions has been impacted.
Since 2011, following the discovery of Leviathan, we have been engaged with the Israeli government, including the Antitrust Commissioner, to reach agreement on various antitrust concerns resulting from our significant resource ownership status. During 2014, we and our partners reached an agreement with the Israeli government to resolve the antitrust concerns (Consent Decree), which included an agreement to divest two of our natural gas discoveries, Tanin and Karish.
Acting in good faith upon the Consent Decree, we engaged in discussions with potential purchasers of the Tanin and Karish discoveries. We believed that the Consent Decree matter had been resolved and had received assurances from the Antitrust Authority that approval was forthcoming. However, on December 23, 2014, the Israeli Antitrust Commissioner (Commissioner) reversed a decision to submit the agreed Consent Decree to the Israeli Antitrust Tribunal for approval.
In response to this situation, in late 2014, the Prime Minister's office established an inter-ministerial working group, led by the head of the National Economic Council, for the purpose of addressing outstanding regulatory concerns and the development of a comprehensive regulatory Framework to achieve certainty and support further investment in natural gas development. We engaged with the Israeli government inter-ministerial working group to support their efforts toward the development of the Framework. The resulting Framework was finalized during third quarter 2015.
Among other items, the Framework provides for the government of Israel to address the following:
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• | The timely approval of asset development permits and plans and export permits; |
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• | Benchmarking future domestic contract pricing for an interim period until market competition is established, whereby such contracts are indexed to existing domestic and export contracts; |
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• | Resolution of antitrust and competition concerns, whereby we would divest Tanin and Karish within 14 months and reduce our ownership in Tamar to 25% within six years; |
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• | The de-linking of Tamar export timing from Leviathan, enabling Tamar expansion to move forward; and |
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• | Support for investment through stabilization assurance. |
After a public hearing process, the Framework was approved by the Israeli Cabinet and Knesset. Enactment of the Framework provides that certain antitrust matters will be resolved. Authority resides with the Minister of Economy to provide the stipulated exemption related to these antitrust matters. Legal challenges may still be brought against the Framework in the Israeli courts. We continue to monitor related progress and if necessary, we are prepared to defend our legal rights to our Israel assets to the fullest extent in both Israel and international venues.
Given the quality of the discovered natural gas resources, the regional demand for natural gas and the significant associated economic benefit to the government, citizens of Israel and the region, we believe it is in the best interest of the Israeli government and citizens that these assets be developed without delay. Although our development plans have been delayed as a result of government actions previously described, we continue to expect that our discoveries will be developed, upon satisfactory resolution of the above matters. Therefore, we believe the risk of loss of our investment is remote as the value of these assets could be realized through ultimate development and/or sale to third parties. In addition, we would pursue any and all remedies for any damages incurred.
As of September 30, 2015, our $2.2 billion investment in Israel includes: approximately $1.4 billion related to the currently-producing Tamar field; approximately $400 million related to the Leviathan natural gas discovery and suspended deep oil test; approximately $300 million related to the Tamar expansion project and previous discoveries which are awaiting sanction of development plans; and $78 million related to the Karish and Tanin discoveries, which are included in assets held for sale. We expect further capital expenditure to be minimized, pending resolution of regulatory matters.
Pending Master Limited Partnership
On October 22, 2015, Noble Midstream Partners LP (Noble Midstream), a wholly owned subsidiary of Noble Energy, filed a registration statement on Form S-1 with the U.S. Securities and Exchange Commission (SEC) relating to a proposed master limited partnership. Under the proposed structure, Noble Midstream will own, operate and develop our DJ Basin crude oil, natural gas and water-related midstream services and Noble Energy will own the general partner of Noble Midstream. We expect to retain a majority of our limited partnership interests in the proposed master limited partnership.
Non-Core Divestiture Program
We periodically divest non-core, non-strategic assets. During the first nine months of 2015, we continued our non-core asset divestiture program with the sale of certain smaller onshore US property packages resulting in net proceeds of $151 million. Divestitures of non-core properties allow us to allocate capital and other resources to high-value and high-growth areas. We continue to evaluate divestment opportunities of certain non-core onshore properties located in the Rocky Mountain and Bowdoin (north central Montana) areas. As of September 30, 2015, the net book value of these non-core assets is $84 million.
Colorado Air Matter
In August 2013, we received an information request from the EPA under Section 114 of the Clean Air Act regarding several tank batteries used in our DJ Basin operations. The information request relates to our compliance with certain regulatory requirements at those locations, including air emissions of volatile organic compounds in a marginal ozone non-attainment area. We responded to the EPA’s information requests between November 2013 and April 2014 and, in April 2015, reached a settlement with the EPA and the State of Colorado regarding potential noncompliance with the Clean Air Act, Colorado's State Implementation Plan, Colorado's Air Pollution Prevention and Control Act and its implementation regulations. See Part II. Other Information – Item 1. Legal Proceedings. Update on Regulations
Hydraulic Fracturing Rules
Although hydraulic fracturing is regulated primarily at the state level, governments and agencies at all levels from federal to municipal have been conducting studies and considering new rules.
On March 26, 2015, the US Interior Department's Bureau of Land Management (BLM) published a final rule regulating hydraulic fracturing on public and Indian lands. The new rules include requirements related to well-bore integrity, wastewater disposal and public disclosure of chemicals. Key components of the rule include:
• provisions for ensuring the protection of groundwater supplies by requiring a validation of well integrity and strong cement barriers between the wellbore and water zones through which the wellbore passes;
• increased transparency by requiring companies to publicly disclose chemicals used in hydraulic fracturing to the BLM through the website FracFocus, within 30 days of completing fracturing operations;
• higher standards for interim storage of recovered waste fluids from hydraulic fracturing to mitigate risks to air, water and wildlife; and
• measures to lower the risk of cross-well contamination with chemicals and fluids used in the fracturing operation, by requiring companies to submit more detailed information on the geology, depth, and location of preexisting wells to afford the BLM an opportunity to better evaluate and manage unique site characteristics.
A number of parties, including the States of Wyoming, Colorado, North Dakota and Utah, have challenged the new rule, and in September 2015, a federal court preliminarily enjoined BLM from enforcing it until their case is decided.
We continue to review the BLM requirements, as well as the status of the court challenges, to determine the impacts, including additional costs and reporting burdens and increased cycle time for permit approval, they may have on our operations on federal land, including our federal units in Nevada.
Nevada Regulations
In September 2014, Nevada state regulators finalized regulations for the use of hydraulic fracturing in crude oil and natural gas development. The regulatory program includes requirements for groundwater baseline sampling and monitoring, water resource and wastewater disposal requirements, chemical disclosure requirements and mandates for extra casing for unconventional wells. We actively participated in the program's development and do not believe it will have a material impact on our activities.
Proposed Offshore Drilling Regulations
On April 13, 2015, the US Department of the Interior announced proposed regulations which include more stringent design requirements and operational procedures for critical well control equipment used in offshore oil and gas operations.
The proposed rule addresses the range of systems and equipment related to well control operations. The measures are intended to improve equipment reliability, building upon enhanced industry standards for blowout preventers and blowout prevention technologies. The rule also covers well design, well control, casing, cementing, real-time well monitoring and subsea containment. We will continue to monitor the development of these new regulations to determine the impacts, including additional costs and reporting burdens, on our deepwater Gulf of Mexico operations.
Endangered Species Act
The US Fish and Wildlife Service (FWS), under the Endangered Species Act (ESA), has regulatory authority over activities that may result in the harming of any endangered or threatened species or its habitat. Some of our operations involving exploration for, and production and sale of, crude oil, natural gas and NGLs are located in areas where such species or habitat may be found. Further, the FWS frequently adds to the list of protected species. In April 2015, for example, the FWS announced that it was listing the northern long-eared bat, as threatened under the ESA, which could have an impact on the
timing of certain of our operations in the Marcellus Shale. In addition and relative to our operations in the Permian Basin, the Lesser Prairie Chicken is not currently listed under the ESA as a result of a federal court vacating the final rule listing the Lesser Prairie Chicken as threatened under the ESA. However, recently, the FWS requested a federal judge in Texas to reverse the ruling. If this occurs, the Lesser Prairie Chicken would be again listed as threatened under the ESA.
Clean Water Rule
In May 2015, the US Environmental Protection Agency (US EPA) and the US Army Corps of Engineers jointly released a final rule that is meant to define more precisely which water bodies are and are not subject to the Clean Water Act (the Clean Water Rule). Among other things, the Clean Water Rule defines the intermittent, ephemeral, and man-altered streams to be protected and specifies when federal jurisdiction may be extended from a covered water to nearby waters. While the agencies have claimed that the new requirements are narrower than existing regulation, the Clean Water Rule has generated substantial controversy. Several court challenges have been filed, a court temporarily had stayed its enforcement, and legislation has been introduced in Congress to require changes. To the extent that the Clean Water Rule requires more detailed studies of site conditions, or results in an expansion of federal jurisdiction over streams and wetlands, our costs may increase, especially with respect to spill prevention, storm water management, and wetlands permitting. We are currently evaluating the impact of the new rule on our operations.
Colorado Task Force
In 2014, by executive order, Colorado Governor Hickenlooper created the Task Force on State and Local Regulation of Oil and Gas Operations (Task Force) for the purpose of recommending policies and legislation. The 21-member Task Force, which included a Noble Energy representative, concluded its activities on February 27, 2015. The Task Force sent nine recommendations to the governor. The recommendations sought to balance land use issues among communities and oil and gas operators and allow reasonable access to private mineral rights. Three recommendations were approved by the legislature and in October 2015 state regulators proposed two rules covering large oil and gas operations in urban areas and coordination of drilling with local governments. We currently are evaluating the proposals.
In addition to the above, we will continue to monitor proposed and new regulations and legislation in all operating jurisdictions to assess the potential impact on our company. Concurrently, we are engaged in extensive public education and outreach efforts with the goal of engaging and educating the general public and communities about the energy, economic and environmental benefits of safe and responsible crude oil and natural gas development.
Federal Air Standards
In October 2015, US EPA announced that it was lowering the primary national ambient air quality standard for ozone from 75 parts per billion to 70 parts per billion. Implementation will take place over several years; however, areas that cannot meet the new standard eventually will need to impose additional requirements on sources of ozone precursors such as volatile organic compounds, which could increase the cost of operating our facilities.
In August 2015, US EPA announced a proposal to further extend its air emission regulations covering new and modified oil and gas operations. Among other things, the proposal would directly limit methane emissions, cover hydraulically fractured oil wells, specify when oil and gas wells should be aggregated into a single source for purposes of air permitting and set guidelines for controlling emissions from existing drilling. We will be monitoring the development of these requirements
Recently Issued Accounting Standards
OPERATING OUTLOOK
2015 Production Our expected crude oil, natural gas and NGL production for 2015 may be impacted by several factors including:
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• | commodity prices which, if subject to further decline, could result in current production becoming uneconomic; |
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• | overall level and timing of capital expenditures which, as discussed below and dependent upon our drilling success, will impact near-term production volumes; |
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• | the reduced level of horizontal drilling activity in our onshore US areas and the decline in our DJ Basin legacy vertical well production; |
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• | timing of start-up of a low pressure line-loop system, performance of gathering and processing infrastructure, capacity constraints of midstream facilities serving those wells, offset by additional capacity from new facilities, and occurrence of other events which impact capacity constraints of midstream facilities serving our DJ Basin wells; |
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• | integration and timing of new wells in the Eagle Ford and Permian as a result of the Rosetta Merger; |
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• | timing of start-up of the Big Bend and Dantzler projects (deepwater Gulf of Mexico); |
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• | Israeli demand for electricity, which affects demand for natural gas as fuel for power generation and industrial market growth, and which is impacted by unseasonable weather; |
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• | variations in West Africa crude oil and condensate sales volumes due to potential Aseng FPSO downtime and timing of liftings, and variations in natural gas sales volumes related to potential downtime at the methanol, LPG and/or LNG plants; |
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• | natural field decline in the deepwater Gulf of Mexico and offshore Equatorial Guinea; |
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• | potential weather-related volume curtailments due to hurricanes in the deepwater Gulf of Mexico, or winter storms and flooding impacting onshore US operations; |
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• | reliability of support equipment and facilities and/or potential pipeline and processing facility capacity constraints which may cause restrictions or interruptions in production and/or mid-stream processing; |
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• | pending Alba and Alen field unitizations in West Africa; |
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• | potential shut-in of US producing properties if storage capacity becomes unavailable; |
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• | potential drilling and/or completion permit delays due to future regulatory changes; and |
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• | potential purchases of producing properties or divestments of non-core operating assets. |
2015 Capital Investment Program Given the current commodity price environment and an industry cost structure that has yet to fully reset to lower revenue levels, we have designed a substantially reduced capital investment program that is appropriate for the current price environment and will be responsive to changing price conditions throughout the remainder of the year. Our 2015 capital program accommodates an investment level of less than $3 billion for our existing assets (including Rosetta), which represents an approximate 40% reduction from 2014. The program initially allocated more than 60% of total investment to core onshore US assets and 35% for global offshore development activities including the deepwater Gulf of Mexico, and approximately 5% for global offshore exploration.
The 2015 capital investment program may be funded from cash flows from operations, cash on hand, proceeds from divestments of non-core assets, borrowings under our Credit Facility and/or other financings. We continue to reduce our capital investment program, while targeting a cash neutral position, whereby the capital investment program is at, or below, operating cash flows. See Liquidity and Capital Resources – Financing Activities. Potential for Future Impairments, Dry Hole or Lease Abandonment Expense
Exploration Activities We have an active exploratory drilling program. In the event we conclude that an exploratory well did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense. For example, during the first nine months of 2015, we recorded dry hole expense of $154 million primarily related to onshore US, offshore Cameroon and Falkland Island exploratory wells. See Item 1. Financial Statements - Note 9. Capitalized Exploratory Well Costs. Additionally, we may not conduct exploration activities prior to lease expirations. For example, in the deepwater Gulf of Mexico, we continue to mature our prospect portfolio. However, regulations have become more stringent due to the Deepwater Horizon incident in 2010. In some instances, specifically engineered blowout preventers, rigs, and completion equipment may be required for high pressure environments. Regulatory requirements or lack of readily available equipment could prevent us from engaging in future exploration activities during our current lease terms. In addition, the current commodity price environment may render certain prospects economically less attractive and we may not conduct exploration activities before lease expiration.
We currently have capitalized undeveloped leasehold cost of approximately $250 million related to deepwater Gulf of Mexico prospects that have not yet been drilled. These leases will expire over the years 2015 - 2024. In third quarter 2015, we wrote off $41 million related to one lease which had previously received a suspension of operations (SOO). The SOO required that we commit to an exploration well by October 31, 2015, which we declined to do, and consequently the lease cost was written off to exploration expense.
Our northeast Nevada exploration prospect includes a 350,000 net acre position (66% fee acreage and remainder federal acreage), prospective for crude oil, which we identified through basin scale reconnaissance and innovative geoscience concepts. We have drilled four exploratory wells to date. To assess commercial viability, additional exploration and appraisal work will be required. In the current commodity price environment, we are assessing our future plans and may consider divestment opportunities. As of September 30, 2015, the net book value of our northeast Nevada assets is $112 million.
Producing Properties Commodity prices remain volatile. A decline in future crude oil, natural gas or NGL prices could result in impairment charges, decrease in proved reserves and/or shut-in of currently producing wells. The cash flow model that we use to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future crude oil and natural gas production along with operating and development costs, market outlook on forward commodity prices, and interest rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward crude oil or natural gas prices alone could result in an impairment.
In third quarter 2015, we assessed proved properties for possible impairment due to current commodity prices. While the estimated undiscounted future cash flows of certain of our properties, including our Aseng and Alen fields in Equatorial Guinea, did not indicate an impairment at September 30, 2015, these properties may become impaired if, for example, commodity prices decline further, operating or development costs increase, or estimated proved reserves are revised downward.
In addition, well decommissioning programs, especially in deepwater or remote locations, are often complex and expensive. It may be difficult to estimate timing of actual abandonment activities, which are subject to regulatory approval and the availability of rigs and services. It may be difficult to estimate costs as rigs and services become more expensive in periods of higher demand. Therefore, our ARO estimates may change, sometimes significantly, and could result in asset impairment.
Divestments We are currently marketing certain non-core onshore US properties. If properties are reclassified as assets held for sale in the future, they will be valued at the lower of net 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. In addition, we would allocate a portion of goodwill to any non-core onshore US property held for sale that constitutes a business, which could potentially decrease any gain or increase any loss recorded on the sale.
In addition, certain assets offshore Israel were classified as held for sale at September 30, 2015. No impairments are indicated at this time. However, failure to achieve acceptable sale terms or delays in closing sales of these properties could result in impairment and/or loss on sale.
Goodwill As of September 30, 2015, we had allocated $945 million of goodwill to our US reporting unit, including goodwill associated with the Rosetta Merger, which may be revised as we complete our purchase price allocation for that transaction. We assess goodwill for impairment annually during the fourth quarter, or more frequently as circumstances require, at the reporting unit level. At September 30, 2015, we performed a qualitative assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as: macroeconomic conditions; industry and market conditions, including current commodity prices; earnings and cash flows; overall financial performance; segment dispositions and acquisitions; and other relevant entity-specific events. Based upon our qualitative assessment of these circumstances, we concluded that a full impairment test was warranted. Accordingly, we estimated the fair value of our US reporting unit using a combination of the income approach and the market approach. We then estimated the implied fair value of goodwill based upon this valuation analysis. These procedures indicated no impairment at September 30, 2015. Further declines in commodity prices and sustained lower valuation for our common stock could indicate a reduction in our estimate of reporting unit fair value which, in turn, could lead to an impairment of reporting unit goodwill. We will continue to monitor events and circumstances which could have a negative impact on our estimates of reporting unit fair value.
RESULTS OF OPERATIONS
Revenues
Revenues were as follows: |
| | | | | | | | | | |
| | | | | (Decrease) from Prior Year |
(millions) | 2015 | | 2014 | |
Three Months Ended September 30, | | | | | |
Oil, Gas and NGL Sales | $ | 765 |
| | $ | 1,228 |
| | (38 | )% |
Income from Equity Method Investees | 36 |
| | 41 |
| | (12 | )% |
Total | $ | 801 |
| | $ | 1,269 |
| | (37 | )% |
| | | | | |
Nine Months Ended September 30, | | | | | |
Oil, Gas and NGL Sales | $ | 2,227 |
| | $ | 3,893 |
| | (43 | )% |
Income from Equity Method Investees | 60 |
| | 138 |
| | (57 | )% |
Total | $ | 2,287 |
| | $ | 4,031 |
| | (43 | )% |
N/M amount is not meaningful.
Changes in revenues are discussed below.
Oil, Gas and NGL Sales
We generally sell crude oil, natural gas, and NGLs under two types of agreements common in our industry. Both types of agreements may include transportation charges. One type of agreement is a netback agreement, under which we sell crude oil and natural gas at the wellhead and receive a price, net of transportation expense incurred by the purchaser. In this case, we record crude oil and natural gas revenue at the net price we received from the purchaser. In the case of NGLs, we may receive a price from the purchaser, which is net of processing costs. In this case, we record NGL revenue at the net price we receive from the purchaser. The second type of agreement is one whereby we pay transportation expense directly. In that case, transportation expense is included within production expense in our consolidated statements of operations.
In addition, commodity prices we receive may be reduced by location basis differentials, which can be significant. As a result of both netback agreements and location basis differentials, our reported sales prices may differ significantly from published commodity price benchmarks for the same period.
Average daily sales volumes and average realized sales prices were as follows: |
| | | | | | | | | | | | | | | | | | | | | | | |
| Sales Volumes | | Average Realized Sales Prices |
| Crude Oil & Condensate (MBbl/d) | | Natural Gas (MMcf/d) | | NGLs (MBbl/d) | | Total (MBoe/d) (1) | | Crude Oil & Condensate (Per Bbl) | | Natural Gas (Per Mcf) | | NGLs (Per Bbl) |
Three Months Ended September 30, 2015 |
United States | 83 |
| | 741 |
| | 49 |
| | 255 |
| | $ | 42.42 |
| | $ | 2.01 |
| | $ | 7.49 |
|
Equatorial Guinea (2) | 27 |
| | 231 |
| | — |
| | 65 |
| | 45.99 |
| | 0.27 |
| | — |
|
Israel | — |
| | 303 |
| | — |
| | 51 |
| | — |
| | 5.39 |
| | — |
|
Other International (3) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total Consolidated Operations | 110 |
| | 1,275 |
| | 49 |
| | 371 |
| | 43.30 |
| | 2.50 |
| | 7.49 |
|
Equity Investees (4) | 2 |
| | — |
| | 6 |
| | 8 |
| | 51.41 |
| | — |
| | 24.86 |
|
Total | 112 |
| | 1,275 |
| | 55 |
| | 379 |
| | $ | 43.44 |
| | $ | 2.50 |
| | $ | 9.24 |
|
Three Months Ended September 30, 2014 |
United States | 67 |
| | 538 |
| | 25 |
| | 182 |
| | $ | 94.21 |
| | $ | 3.41 |
| | $ | 29.53 |
|
Equatorial Guinea (2) | 29 |
| | 233 |
| | — |
| | 68 |
| | 98.63 |
| | 0.27 |
| | — |
|
Israel | — |
| | 262 |
| | — |
| | 44 |
| | — |
| | 5.59 |
| | — |
|
Other International (3) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total Consolidated Operations | 96 |
| | 1,033 |
| | 25 |
| | 294 |
| | 95.55 |
| | 3.26 |
| | 29.53 |
|
Equity Investees (4) | 2 |
| | — |
| | 6 |
| | 8 |
| | 102.02 |
| | — |
| | 62.24 |
|
Total | 98 |
| | 1,033 |
| | 31 |
| | 302 |
| | $ | 95.64 |
| | $ | 3.26 |
| | $ | 35.85 |
|
| | | | | | | | | | | | | |
Nine Months Ended September 30, 2015 |
United States | 73 |
| | 658 |
| | 34 |
| | 217 |
| | $ | 46.02 |
| | $ | 2.20 |
| | $ | 9.78 |
|
Equatorial Guinea (2) | 29 |
| | 221 |
| | — |
| | 66 |
| | 52.15 |
| | 0.27 |
| | — |
|
Israel | — |
| | 254 |
| | — |
| | 43 |
| | — |
| | 5.39 |
| | — |
|
Other International (3) | 1 |
| | — |
| | — |
| | 1 |
| | 55.52 |
| | — |
| | — |
|
Total Consolidated Operations | 103 |
| | 1,133 |
| | 34 |
| | 327 |
| | 47.79 |
| | 2.54 |
| | 9.78 |
|
Equity Investees (4) | 2 |
| | — |
| | 5 |
| | 6 |
| | 51.67 |
| | — |
| | 28.77 |
|
Total | 105 |
| | 1,133 |
| | 39 |
| | 333 |
| | $ | 47.85 |
| | $ | 2.54 |
| | $ | 12.15 |
|
Nine Months Ended September 30, 2014 |
United States | 66 |
| | 497 |
| | 22 |
| | 171 |
| | $ | 96.84 |
| | $ | 4.12 |
| | $ | 35.39 |
|
Equatorial Guinea (2) | 32 |
| | 241 |
| | — |
| | 72 |
| | 104.38 |
| | 0.27 |
| | — |
|
Israel | — |
| | 233 |
| | — |
| | 39 |
| | — |
| | 5.59 |
| | — |
|
Other International (3) | 3 |
| | — |
| | — |
| | 3 |
| | 104.47 |
| | — |
| | — |
|
Total Consolidated Operations | 101 |
| | 971 |
| | 22 |
| | 285 |
| | 99.48 |
| | 3.52 |
| | 35.39 |
|
Equity Investees (4) | 2 |
| | — |
| | 6 |
| | 7 |
| | 105.15 |
| | — |
| | 67.06 |
|
Total | 103 |
| | 971 |
| | 28 |
| | 292 |
| | $ | 99.58 |
| | $ | 3.52 |
| | $ | 47.96 |
|
| |
(1) | Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of crude oil equivalent for both natural gas and NGL are significantly less than the price for a barrel of crude oil. |
| |
(2) | Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant, an LNG plant and a power generation plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting. |
| |
(3) | Other International includes primarily China (through June 30, 2014). North Sea sales volumes for 2014 and 2015 were de minimis, with last production in May 2015. |
| |
(4) | Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. See Income from Equity Method Investees, below. |
An analysis of revenues from sales of crude oil, natural gas and NGLs is as follows: |
| | | | | | | | | | | | | | | |
| Sales Revenues |
(millions) | Crude Oil & Condensate | | Natural Gas | | NGLs | | Total |
Three Months Ended September 30, 2014 | $ | 849 |
| | $ | 310 |
| | $ | 69 |
| | $ | 1,228 |
|
Changes due to | |
| | |
| | |
| | |
|
Increase in Sales Volumes | 118 |
| | 72 |
| | 65 |
| | 255 |
|
Decrease in Sales Prices | (529 | ) | | (89 | ) | | (100 | ) | | (718 | ) |
Three Months Ended September 30, 2015 | $ | 438 |
| | $ | 293 |
| | $ | 34 |
| | $ | 765 |
|
| | | | | | | |
Nine Months Ended September 30, 2014 | $ | 2,748 |
| | $ | 932 |
| | $ | 213 |
| | $ | 3,893 |
|
Changes due to | |
| | | | |
| | |
|
Increase in Sales Volumes | 66 |
| | 156 |
| | 113 |
| | 335 |
|
Decrease in Sales Prices | (1,462 | ) | | (303 | ) | | (236 | ) | | (2,001 | ) |
Nine Months Ended September 30, 2015 | $ | 1,352 |
| | $ | 785 |
| | $ | 90 |
| | $ | 2,227 |
|
Crude Oil and Condensate Sales – Revenues from crude oil and condensate sales decreased during third quarter and first nine months of 2015 as compared with 2014 due to the following:
| |
• | decreases in average realized prices primarily due to the decline in global commodity prices that began in the second half of 2014; and |
| |
• | decreases in sales volumes due to planned downtime and maintenance as well as natural field decline in the deepwater Gulf of Mexico and the Aseng field, offshore Equatorial Guinea. |
partially offset by:
| |
• | higher sales volumes due to continued development in the DJ Basin infrastructure and sales volumes contributed by our acquired Eagle Ford and Permian assets, which contributed 7 MBbl/d and 5 MBbl/d, respectively, in third quarter 2015. |
Natural Gas Sales – Revenues from natural gas sales decreased during third quarter and first nine months of 2015 as compared with 2014 due to the following:
| |
• | decreases in US average realized prices between September and December 2014 with prices declining further in the first nine months of 2015; and |
| |
• | a widening of location basis differentials in the Marcellus Shale due to an oversupply of natural gas in the region; |
partially offset by:
| |
• | higher sales volumes due to record quarterly sales volumes in Israel, continued development in the DJ Basin and Marcellus Shale and sales volumes contributed by our acquired Eagle Ford and Permian assets, which contributed 87 MMcf/d and 6 MMcf/d, respectively, in third quarter 2015. |
NGL Sales – Revenues from NGL sales decreased during third quarter and first nine months of 2015 as compared with 2014 due to the following:
| |
• | decreases in average realized prices primarily driven by oversupply, particularly in the Marcellus Shale: |
partially offset by:
| |
• | sales volumes contributed by our acquired Eagle Ford and Permian assets, which contributed 14 MBbl/d and 1 MBbl/d, respectively, in third quarter 2015. |
Income from Equity Method Investees We have interests in equity method investees that operate midstream assets onshore US and West Africa. Equity method investments are included in other noncurrent assets in our consolidated balance sheets, and our share of earnings is reported as income from equity method investees in our consolidated statements of operations. Within our consolidated statements of cash flows, activity is reflected within cash flows provided by operating activities and cash flows provided by (used in) investing activities.
Income from equity method investees decreased $78 million during the first nine months of 2015 as compared with 2014. Income from AMPCO, our methanol investee, decreased $48 million due to lower sales volumes and additional expenses related to a 45-day plant turnaround during 2015. In addition, average realized methanol prices have declined. Income from Alba Plant, our LPG investee, decreased $64 million due to lower sales volumes and lower realized prices. In addition, feed gas supply to both Alba Plant and AMPCO was interrupted during the drilling of the Alba field C-21 development well during second quarter 2015. Alba field C-21 development well commenced production during third quarter 2015. We recorded income
of $31 million during the first nine months of 2015 from our investments in CONE Gathering LLC and CONE Midstream Partners LP, which completed an initial public offering of limited partner units in September 2014.
Operating Costs and Expenses
Operating costs and expenses were as follows:
|
| | | | | | | | | | |
| | | | | Increase / (Decrease) from Prior Year |
(millions) | 2015 | | 2014 | |
Three Months Ended September 30, | | | | | |
Production Expense | $ | 235 |
| | $ | 216 |
| | 9 | % |
Exploration Expense | 203 |
| | 217 |
| | (6 | )% |
Depreciation, Depletion and Amortization | 539 |
| | 460 |
| | 17 | % |
General and Administrative | 109 |
| | 132 |
| | (17 | )% |
Asset Impairments | — |
| | 33 |
| | (100 | )% |
Other Operating (Income) Expense, Net | 182 |
| | (19 | ) | | N/M |
|
Total | $ | 1,268 |
| | $ | 1,039 |
| | 22 | % |
| | | | | |
Nine Months Ended September 30, | | | | | |
Production Expense | $ | 693 |
| | $ | 689 |
| | 1 | % |
Exploration Expense | 308 |
| | 350 |
| | (12 | )% |
Depreciation, Depletion and Amortization | 1,444 |
| | 1,297 |
| | 11 | % |
General and Administrative | 308 |
| | 399 |
| | (23 | )% |
Asset Impairments | 43 |
| | 164 |
| | (74 | )% |
Other Operating (Income) Expense, Net | 252 |
| | (31 | ) | | N/M |
|
Total | $ | 3,048 |
| | $ | 2,868 |
| | 6 | % |
N/M amount is not meaningful.
Changes in operating costs and expenses are discussed below.
Production Expense Components of production expense were as follows: |
| | | | | | | | | | | | | | | | | | | | | | | |
(millions, except unit rate) | Total per BOE (1) | | Total | | United States | | Equatorial Guinea | | Israel | | Other Int'l, Corporate (2) |
Three Months Ended September 30, 2015 | | | | | | | | | | | |
Lease Operating Expense (3) | $ | 3.89 |
| | $ | 133 |
| | $ | 92 |
| | $ | 26 |
| | $ | 13 |
| | $ | 2 |
|
Production and Ad Valorem Taxes | 0.83 |
| | 28 |
| | 27 |
| | — |
| | — |
| | 1 |
|
Transportation and Gathering Expense | 2.13 |
| | 74 |
| | 74 |
| | — |
| | — |
| | — |
|
Total Production Expense | $ | 6.85 |
| | $ | 235 |
| | $ | 193 |
| | $ | 26 |
| | $ | 13 |
| | $ | 3 |
|
Total Production Expense per BOE | | | $ | 6.85 |
| | $ | 8.22 |
| | $ | 4.30 |
| | $ | 2.78 |
| | N/M |
|
Three Months Ended September 30, 2014 | |
| | |
| | |
| | |
| | |
| | |
|
Lease Operating Expense (3) | $ | 4.88 |
| | $ | 132 |
| | $ | 78 |
| | $ | 34 |
| | $ | 13 |
| | $ | 7 |
|
Production and Ad Valorem Taxes | 1.64 |
| | 44 |
| | 44 |
| | — |
| | — |
| | — |
|
Transportation and Gathering Expense | 1.48 |
| | 40 |
| | 40 |
| | — |
| | — |
| | — |
|
Total Production Expense | $ | 8.00 |
| | $ | 216 |
| | $ | 162 |
| | $ | 34 |
| | $ | 13 |
| | $ | 7 |
|
Total Production Expense per BOE | | | $ | 8.00 |
|
| $ | 9.67 |
|
| $ | 5.45 |
|
| $ | 3.20 |
| | N/M |
|
Nine Months Ended September 30, 2015 | | | | | | | | | | | |
Lease Operating Expense (3) | $ | 4.70 |
| | $ | 419 |
| | $ | 274 |
| | $ | 96 |
| | $ | 38 |
| | $ | 11 |
|
Production and Ad Valorem Taxes | 1.00 |
| | 89 |
| | 88 |
| | — |
| | — |
| | 1 |
|
Transportation and Gathering Expense | 2.09 |
| | 185 |
| | 185 |
| | — |
| | — |
| | — |
|
Total Production Expense | $ | 7.79 |
| | $ | 693 |
| | $ | 547 |
| | $ | 96 |
| | $ | 38 |
| | $ | 12 |
|
Total Production Expense per BOE | | | $ | 7.79 |
| | $ | 9.23 |
| | $ | 5.32 |
| | $ | 3.27 |
| | N/M |
|
Nine Months Ended September 30, 2014 | |
| | |
| | |
| | |
| | |
| | |
|
Lease Operating Expense (3) | $ | 5.45 |
| | $ | 424 |
| | $ | 247 |
| | $ | 101 |
| | $ | 39 |
| | $ | 37 |
|
Production and Ad Valorem Taxes | 1.88 |
| | 146 |
| | 129 |
| | — |
| | — |
| | 17 |
|
Transportation and Gathering Expense | 1.54 |
| | 119 |
| | 118 |
| | — |
| | — |
| | 1 |
|
Total Production Expense | $ | 8.87 |
| | $ | 689 |
| | $ | 494 |
| | $ | 101 |
| | $ | 39 |
| | $ | 55 |
|
Total Production Expense per BOE | | | $ | 8.87 |
| | $ | 10.62 |
| | $ | 5.12 |
| | $ | 3.65 |
| | N/M |
|
N/M amount is not meaningful.
| |
(1) | Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees. |
| |
(2) | Other International, Corporate includes primarily China (through June 30, 2014) and corporate expenditures. |
| |
(3) | Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense. |
For third quarter and the first nine months of 2015, total production expense increased as compared with 2014 due to the following:
| |
• | an increase in lease operating expense and transportation and gathering expense due to higher onshore US production, including the addition of production from our Eagle Ford and Permian assets in third quarter 2015; |
| |
• | an increase in transportation and gathering expense rates due to service contracts with CONE Gathering LLC, our equity method investee; |
partially offset by:
| |
• | focused cost reduction and efficiency initiatives; |
| |
• | decreased lease operating expense due to the sale of our China assets at the end of the second quarter 2014; |
| |
• | decreased production and ad valorem taxes due to lower revenues resulting from the decline in commodity prices in the US as well as the sale of our China assets at the end of the second quarter 2014; and |
| |
• | decreased lease operating expense in Gulf of Mexico due to ceased operations at South Raton and natural field decline. |
While total production expense increased for the respective periods compared to 2014, costs on a per Boe basis declined as a result of increased production, product mix and focus on cost reduction initiatives and operational efficiencies.
Exploration Expense Components of exploration expense were as follows: |
| | | | | | | | | | | | | | | | | | | |
(millions) | Total | | United States | | West Africa (1) | | Eastern Mediter- ranean (2) | | Other Int'l, Corporate (3) |
Three Months Ended September 30, 2015 | | | | | | | | |
Dry Hole Expense | $ | 135 |
| | $ | — |
| | $ | 27 |
| | $ | — |
| | $ | 108 |
|
Seismic | — |
| | — |
| | — |
| | — |
| | — |
|
Staff Expense | 24 |
| | — |
| | — |
| | 2 |
| | 22 |
|
Other(4)
| 44 |
| | 44 |
| | — |
| | — |
| | — |
|
Total Exploration Expense | $ | 203 |
| | $ | 44 |
| | $ | 27 |
| | $ | 2 |
| | $ | 130 |
|
Three Months Ended September 30, 2014 | | |
| | |
| | |
| | |
|
Dry Hole Expense | $ | 161 |
| | $ | 79 |
| | $ | — |
| | $ | — |
| | $ | 82 |
|
Seismic | 22 |
| | 4 |
| | 12 |
| | 1 |
| | 5 |
|
Staff Expense | 22 |
| | 4 |
| | 2 |
| | 4 |
| | 12 |
|
Other | 12 |
| | 12 |
| | — |
| | — |
| | — |
|
Total Exploration Expense | $ | 217 |
| | $ | 99 |
| | $ | 14 |
| | $ | 5 |
| | $ | 99 |
|
| | | | | | | | | |
Nine Months Ended September 30, 2015 | | | | | | | | |
Dry Hole Expense | $ | 154 |
| | $ | 18 |
| | $ | 27 |
| | $ | — |
| | $ | 109 |
|
Seismic | 3 |
| | 2 |
| | — |
| | — |
| | 1 |
|
Staff Expense | 81 |
| | 5 |
| | 2 |
| | 11 |
| | 63 |
|
Other(4)
| 70 |
| | 70 |
| | — |
| | — |
| | — |
|
Total Exploration Expense | $ | 308 |
| | $ | 95 |
| | $ | 29 |
| | $ | 11 |
| | $ | 173 |
|
Nine Months Ended September 30, 2014 | | |
| | |
| | |
| | |
|
Dry Hole Expense | $ | 163 |
| | $ | 81 |
| | $ | — |
| | $ | — |
| | $ | 82 |
|
Seismic | 54 |
| | 19 |
| | 12 |
| | 3 |
| | 20 |
|
Staff Expense | 90 |
| | 22 |
| | 6 |
| | 9 |
| | 53 |
|
Other | 43 |
| | 43 |
| | — |
| | — |
| | — |
|
Total Exploration Expense | $ | 350 |
| | $ | 165 |
| | $ | 18 |
| | $ | 12 |
| | $ | 155 |
|
| |
(1) | West Africa includes Equatorial Guinea, Cameroon, Sierra Leone, and Gabon. |
| |
(2) | Eastern Mediterranean includes Israel and Cyprus. |
| |
(3) | Other International, Corporate includes the Falkland Islands, other new ventures and corporate expenditures. |
| |
(4) | Includes leasehold impairment, including one lease related to deepwater Gulf of Mexico |
Exploration expense for third quarter and first nine months of 2015 included:
| |
• | dry hole cost related to exploratory wells, including onshore US; Cheetah, offshore Cameroon; and Humpback, Falkland Islands; |
| |
• | leasehold impairment, including one lease related to deepwater Gulf of Mexico of $41 million; and |
| |
• | salaries and related expenses for corporate exploration and new ventures personnel. |
Exploration expense for third quarter and first nine months of 2014 included the following:
| |
• | dry hole cost related to the Bright exploratory well, deepwater Gulf of Mexico, the Scotia exploratory well, offshore Falkland Islands, and other miscellaneous charges; |
| |
• | seismic expense related to 3D seismic acquisition in the deepwater Gulf of Mexico, Equatorial Guinea, and Falkland Islands; and |
| |
• | salaries and related expenses for corporate exploration and new ventures personnel. |
Depreciation, Depletion and Amortization DD&A expense was as follows: |
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
DD&A Expense (millions) (1) | $ | 539 |
| | $ | 460 |
| | $ | 1,444 |
| | $ | 1,297 |
|
Unit Rate per BOE (2) | $ | 15.75 |
| | $ | 16.98 |
| | $ | 16.21 |
| | $ | 16.67 |
|
| |
(2) | Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees. |
Total DD&A expense for third quarter and first nine months of 2015 increased as compared with 2014 due to the following:
| |
• | the addition of Eagle Ford and Permian production in third quarter 2015; and |
| |
• | an increase in the DJ Basin and Marcellus Shale due to higher sales volumes; |
partially offset by:
| |
• | a decrease in sales volumes from our deepwater Gulf of Mexico operations; and |
| |
• | a decrease due to the sale of our China assets during 2014. |
The decrease in the unit rate per BOE for the third quarter and first nine months of 2015 as compared with 2014 was due primarily to the change in mix of production. Higher-cost production volumes in the DJ Basin were offset by an increase in lower cost volumes produced at Tamar, offshore Israel as well as lower DD&A rates attributable to the Eagle Ford and Permian production.
Other than the addition of proved reserves resulting from the Rosetta Merger, during the third quarter 2015 there were no significant changes to our proved reserves estimates at December 31, 2014. Estimates of proved reserves significantly affect our DD&A expense. Holding other factors constant, a decline in proved reserves estimates caused by decreases in the 12-month average commodity prices, will result in an increase in DD&A expense in future periods, which would reduce earnings.
General and Administrative Expense General and administrative expense (G&A) was as follows: |
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
G&A Expense (millions) | $ | 109 |
| | $ | 132 |
| | $ | 308 |
| | $ | 399 |
|
Unit Rate per BOE (1) | $ | 3.19 |
| | $ | 4.89 |
| | $ | 3.46 |
| | $ | 5.12 |
|
| |
(1) | Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees. |
G&A expense for third quarter and first nine months of 2015 decreased as compared with 2014 primarily due to cost savings initiatives, including reduced use of contractors and consultants and decreased special projects and other discretionary expenses, and decreases in employee personnel costs.
Asset Impairment Expense Asset impairment expense was as follows: |
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(millions) | 2015 | | 2014 | | 2015 | | 2014 |
Asset Impairments | $ | — |
| | $ | 33 |
| | $ | 43 |
| | $ | 164 |
|
Other Operating (Income) Expense Other operating (income) expense was as follows: |
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(millions) | 2015 | | 2014 | | 2015 | | 2014 |
Midstream Gathering and Processing Expense | $ | 4 |
| | $ | 1 |
| | $ | 10 |
| | $ | 8 |
|
Corporate Restructuring Expense | 21 |
| | — |
| | 39 |
| | — |
|
Stacked Drilling Rig Expense | 13 |
| | — |
| | 20 |
| | — |
|
Pension Plan Expense | 67 |
| | — |
| | 88 |
| | — |
|
Rosetta Merger Expenses | 71 |
| | — |
| | 73 |
| | — |
|
Gain on Divestitures | — |
| | (30 | ) | | — |
| | (72 | ) |
Other, Net | 6 |
| | 10 |
| | 22 |
| | 33 |
|
Total | $ | 182 |
| | $ | (19 | ) | | $ | 252 |
| | $ | (31 | ) |
Other (Income) Expense
Other (income) expense was as follows: |
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(millions) | 2015 | | 2014 | | 2015 | | 2014 |
Gain on Commodity Derivative Instruments | $ | (267 | ) | | $ | (385 | ) | | $ | (331 | ) | | $ | (74 | ) |
Interest, Net of Amount Capitalized | 71 |
| | 52 |
| | 183 |
| | 151 |
|
Other Non-Operating (Income) Expense, Net | (12 | ) | | (13 | ) | | (20 | ) | | 1 |
|
Total | $ | (208 | ) | | $ | (346 | ) | | $ | (168 | ) | | $ | 78 |
|
Gain on Commodity Derivative Instruments Gain on commodity derivative instruments is a result of mark-to-market accounting. Many factors impact a gain or loss on commodity derivative instruments including: increases and decreases in the commodity forward price curves compared to the terms of our executed commodity instruments; increases in notional volumes; and the mix of instruments between NYMEX WTI, Dated Brent and NYMEX Henry Hub commodities. See Item 1. Financial Statements – Note 6. Derivative Instruments and Hedging Activities and Note 8. Fair Value Measurements and Disclosures. Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows: |
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
(millions, except unit rate) | | | | | | | |
Interest Expense, Gross | $ | 110 |
| | $ | 79 |
| | $ | 294 |
| | $ | 238 |
|
Capitalized Interest | (39 | ) | | (27 | ) | | (111 | ) | | (87 | ) |
Interest Expense, Net | $ | 71 |
| | $ | 52 |
| | $ | 183 |
| | $ | 151 |
|
Unit Rate per BOE (1) | $ | 2.08 |
| | $ | 1.93 |
| | $ | 2.05 |
| | $ | 1.94 |
|
(1) Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
The increase in interest expense, gross, for third quarter and first nine months of 2015 as compared with 2014 is due to the senior notes assumed by us in the Rosetta Merger during third quarter 2015 as well as the issuance of new senior debt in November 2014. During the first nine months of 2015, we drew down and repaid amounts under our Credit Facility.
The increase in capitalized interest for third quarter and first nine months of 2015 as compared with 2014 is primarily due to higher work in progress amounts related to major long-term projects in deepwater Gulf of Mexico, offshore West Africa, and offshore Israel, as well as expansion of midstream infrastructure in the DJ Basin.
Income Tax Provision
LIQUIDITY AND CAPITAL RESOURCES
Capital Structure/Financing Strategy
In seeking to effectively fund and monetize our discovered hydrocarbons, we employ a capital structure and financing strategy designed to provide sufficient liquidity throughout the volatile commodity price cycle, including the current downturn in commodity prices. Specifically, we strive to retain the ability to fund long cycle, multi-year, capital intensive development projects throughout a range of scenarios, while also funding a continuing exploration program and maintaining capacity to capitalize periodically on financially attractive mergers and acquisitions opportunities.
We endeavor to maintain an investment grade debt rating in service of these objectives, while delivering competitive returns and a growing dividend. We utilize a commodity price hedging program to reduce the impacts of commodity price volatility and enhance the predictability of cash flows along with a risk and insurance program to protect against disruption to our cash flows and the funding of our business.
We strive to maintain a minimum liquidity level to address volatility and risk. Traditional sources of our liquidity are cash flows from operations, cash on hand, available borrowing capacity under our Credit Facility, and proceeds from sales of non-core properties.
We occasionally access the capital markets to ensure adequate liquidity exists in the form of unutilized capacity under our Credit Facility or to refinance scheduled debt maturities. On March 3, 2015, we closed an underwritten public offering of 21 million shares of common stock, par value $0.01 per share, at a price to the public of $47.50 per share. In addition, on March 25, 2015, we completed the issuance of an additional 3.15 million shares of common stock, par value $0.01 per share, in connection with the exercise of the option of the underwriters to purchase additional shares of common stock. The aggregate net proceeds of the offerings were approximately $1.1 billion (after deducting underwriting discounts and commissions and estimated offering expenses). We used approximately $150 million of the net proceeds to repay outstanding indebtedness under our revolving Credit Facility and the remainder was used for general corporate purposes, including the funding of our capital investment program.
In July 2015, we completed the Rosetta Merger, which complements and expands our current portfolio. The merger was effected through the issuance of approximately 41 million shares of common stock in exchange for all outstanding shares of Rosetta using a ratio of 0.542 of a share of Noble Energy common stock for each share of Rosetta common stock and the assumption of Rosetta's liabilities, including approximately $2 billion fair value of outstanding debt.
As discussed previously, we also intend to reduce our economic interest in our DJ Basin midstream assets through the formation and initial public offering of a master limited partnership. Certain of the net after-tax proceeds from the transaction will be used to make a distribution to Noble Energy.
We also consider repatriations of foreign cash to increase our financial flexibility and fund our capital investment program to the extent such cash is not required to fund foreign investment projects and would not incur material incremental US tax. During third quarter 2015, we repatriated $412 million from our foreign operations. We do not expect to incur material incremental US tax on these repatriations due to foreign tax credit and net operating loss usage.
We also evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending and may consider other sources of funding.
Cash on hand at September 30, 2015 totaled $1.0 billion, which includes both domestic and foreign cash, and there were no amounts outstanding under our Credit Facility. See Item 1. Financial Statements – Note 7. Debt and Credit Facility, below. Driven by the current commodity price environment, and despite a 36% reduction in capital spending versus the same period of 2014, capital expenditures exceeded cash flows from operating activities for the first nine months of 2015. Moving forward, we aim to invest capital at a level aligned with current operating cash flows. Our financial capacity and lack of near-term debt maturities, coupled with our diversified global portfolio, provides us with flexibility in our investment decisions including execution of our major development projects and exploration activity.
To support our investment program, we expect that higher production resulting from our core onshore US development programs, including production from our Texas assets, combined with new production from the Big Bend and Dantzler development projects and increased peak deliverability resulting from the Tamar compression project, presuming no significant deterioration of prices, will result in an increase in cash flows which will be available to meet a portion of future capital commitments in 2016 and subsequent years. See Results of Operations above. We are currently evaluating potential development and/or financing scenarios for our significant natural gas discoveries offshore Eastern Mediterranean. The magnitude of these discoveries presents technical and financial challenges for us due to the large-scale development requirements. Each of these development options, including the development of Leviathan Phase 1, would require a multi-billion dollar investment and require a number of years to complete. We are currently working to resolve antitrust and other regulatory matters with the Israeli government to enable Leviathan and other development to move forward. See Executive Overview – Update on Core Area – Israel, above. Pension Plan In third quarter 2015, we completed the process of terminating our noncontributory, tax-qualified defined benefit pension plan through the purchase of annuities for the remaining participants. As a result, we expensed all remaining unamortized prior service costs and actuarial losses from AOCL. For the nine months ended September 30, 2015, we have expensed $88 million related to the termination of the plan. As of September 30, 2015, we have $16 million remaining in AOCL related to our Restoration Plan.
Available Liquidity Information regarding cash and debt balances is as follows: |
| | | | | | | |
| September 30, | | December 31, |
| 2015 | | 2014 |
(millions, except percentages) | | | |
Cash and Cash Equivalents | $ | 1,028 |
| | $ | 1,183 |
|
Amount Available to be Borrowed Under Credit Facility (1) | 4,000 |
| | 4,000 |
|
Total Liquidity | $ | 5,028 |
| | $ | 5,183 |
|
Total Debt (2) | $ | 7,997 |
| | $ | 6,197 |
|
Total Shareholders' Equity | 12,450 |
| | 10,325 |
|
Ratio of Debt-to-Book Capital (3) | 39 | % | | 38 | % |
| |
(1) | See Credit Facility, below. |
| |
(2) | Total debt includes capital lease obligations and excludes unamortized debt discount/premium. |
| |
(3) | We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized discount, the current portion of long-term debt, and short-term borrowings) divided by the sum of total debt plus shareholders’ equity. |
Cash and Cash Equivalents We had approximately $1.0 billion in cash and cash equivalents at September 30, 2015, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $564 million of this cash is attributable to our foreign subsidiaries and a portion would be subject to US income taxes if repatriated.
Credit Facility In the third quarter 2015, we entered into the Second Amendment to our Credit Agreement which, among other things, extended the maturity date of our Credit Agreement from October 3, 2018 to August 27, 2020. The commitment is $4.0 billion through the maturity date of the Credit Facility. As of September 30, 2015, no amounts were outstanding under the Credit Facility. Borrowings under our Credit Facility subject us to interest rate risk. See Item 1. Financial Statements – Note 7. Debt and Item 3. Quantitative and Qualitative Disclosures About Market Risk. Commodity Derivative Instruments We use various derivative instruments in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations and ensure cash flow for future capital needs. Such instruments may include variable to fixed price commodity swaps, two-way collars, three-way collars and/or extendable swaps.
Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties.
A significant portion of the hedged revenues are attributable to three-way collars. When commodities trade below the strike price of the sold put option contract of the three-way collar, the cash settlements received by us are limited. However, we still receive the cash market price plus the delta between the purchased put option floor price of the two-way collar contract and the sold put option strike price.
We net settle by counterparty based on netting provisions within the master agreements. None of our counterparty agreements contain margin requirements.
Commodity derivative instruments are recorded at fair value in our consolidated balance sheets, and changes in fair value are recorded in earnings in the period in which the change occurs. As of September 30, 2015, the fair value of our commodity derivative assets was $754 million and we had no derivative liabilities (after consideration of netting provisions within our master agreements). In connection with the Rosetta Merger on July 20, 2015, we acquired commodity derivative assets. See Item 1. Financial Statements – Note 3. Rosetta Merger and Note 8. Fair Value Measurements and Disclosures, for a description of the methods we use to estimate the fair values of commodity derivative instruments, and Credit Risk, below. Credit Risk We monitor the creditworthiness of our trade creditors, joint venture partners, hedging counterparties, and financial institutions on an ongoing basis. Some of these entities are not as creditworthy as we are and may experience credit downgrades or liquidity problems. Counterparty credit downgrades or liquidity problems could result in a delay in our receiving proceeds from commodity sales, reimbursement of joint venture costs, and potential delays in our major development projects. We are unable to predict sudden changes in a party's creditworthiness or ability to perform. Even if we do accurately predict such sudden changes, our ability to negate these risks may be limited and we could incur significant financial losses.
In addition, nonoperating partners often must obtain financing for their share of capital cost for development projects. A partner's inability to obtain financing could result in a delay of our joint development projects.
Credit enhancements have been obtained from some parties in the form of parental guarantees, letters of credit or credit insurance; however, not all of our counterparty credit is protected through guarantees or credit support. Nonperformance by a trade creditor, joint venture partner, hedging counterparty or financial institution could result in significant financial losses.
Contractual Obligations
Exploration Commitments The terms of some of our production sharing contracts, licenses or concession agreements require us to conduct certain exploration activities, including drilling one or more exploratory wells or acquiring seismic data, within specific time periods. At September 30, 2015, we have the following commitments:
| |
• | remaining three-well obligation in Nevada; |
| |
• | one-well obligation offshore Cyprus; |
| |
• | two-well obligation offshore Falkland Islands, including the Humpback well which resulted in dry hole expense of $108 million; and |
| |
• | 3D seismic obligation offshore Gabon. |
We have completed the Cheetah exploration well in the Tilapia license offshore Cameroon, which reached the targeted Cretaceous interval. Other than plugging and abandoning this well, we have no other exploration obligations related to offshore Cameroon. See Executive Overview – Exploration Program Update, above. These obligations extend over a period ranging from one to four years. Failure to conduct exploration activities within the prescribed periods could lead to loss of leases or exploration rights.
Ratings Triggers We do not have triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit rating. In addition, there are no existing ratings triggers in any of our commodity hedging agreements that would require the posting of collateral. However, a series of downgrades or other negative rating actions could significantly alter our requirements to post collateral as financial assurance of performance under certain other contractual arrangements such as pipeline transportation contracts, crude oil and natural gas sales contracts, work commitments and certain abandonment obligations. A requirement to post collateral could have a negative impact on our liquidity.
Cash Flows
Cash flow information is as follows: |
| | | | | | | |
| Nine Months Ended September 30, |
| 2015 | | 2014 |
(millions) | | | |
Total Cash Provided By (Used in) | | | |
Operating Activities | $ | 1,486 |
| | $ | 2,703 |
|
Investing Activities | (2,393 | ) | | (3,175 | ) |
Financing Activities | 752 |
| | 524 |
|
Increase (Decrease) in Cash and Cash Equivalents | $ | (155 | ) | | $ | 52 |
|
Operating Activities Net cash provided by operating activities for the first nine months of 2015 decreased significantly as compared with 2014. Significant decreases in average realized commodity prices were partially offset by increases in sales volumes, more favorable settlements of commodity derivatives, and a decrease in general and administrative expense. Working capital changes contributed $74 million of negative operating cash flow in the first nine months of 2015 as compared with a positive impact of $286 million in the first nine months of 2014.
Investing Activities Our investing activities include capital spending on a cash basis for oil and gas properties and investments in unconsolidated subsidiaries accounted for by the equity method. These investing activities may be offset by proceeds from property sales or dispositions, including farm-in arrangements, which may result in reimbursement for capital spending that had occurred in prior periods. Capital spending for property, plant and equipment decreased by $1.1 billion during the first nine months of 2015 as compared with 2014, primarily due to a reduced capital spending program. Investing activities included $86 million in CONE Gathering LLC during the first nine months of 2015 as compared with $58 million in the first nine months of 2014. We received $151 million in proceeds from asset divestitures during the first nine months of 2015, as compared with $312 million during the same period in 2014.
Financing Activities Our financing activities include the issuance or repurchase of our common stock, payment of cash dividends on our common stock, the borrowing of cash and the repayment of borrowings. During the first nine months of 2015, funds were provided by cash proceeds from the issuance of shares of Company common stock to the public ($1.1 billion) and the exercise of stock options ($7 million). We used cash to pay dividends on our common stock ($214 million), make principal payments related to capital lease obligations ($49 million) and repurchase shares of our common stock ($20 million).
In comparison, during the first nine months of 2014, funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($45 million) and net cash proceeds from our Credit Facility ($900 million). We also used cash to
pay dividends on our common stock ($182 million), repay senior notes ($200 million), make principal payments related to capital lease obligations ($42 million) and repurchase shares of our common stock ($15 million).
Investing Activities
Acquisition, Capital and Exploration Expenditures Information for investing activities (on an accrual basis) is as follows: |
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
(millions) | | | | | | | |
Acquisition, Capital and Exploration Expenditures | | | | | | | |
Unproved Property Acquisition (1) | $ | 21 |
| | $ | 42 |
| | $ | 86 |
| | $ | 171 |
|
Exploration | 117 |
| | 191 |
| | 257 |
| | 419 |
|
Development | 458 |
| | 976 |
| | 1,695 |
| | 2,617 |
|
Midstream | 26 |
| | 80 |
| | 123 |
| | 175 |
|
Corporate and Other | 21 |
| | 28 |
| | 78 |
| | 118 |
|
Total | $ | 643 |
| | $ | 1,317 |
| | $ | 2,239 |
| | $ | 3,500 |
|
| | | | | | | |
Other | | | | | | | |
Investment in Equity Method Investee (2) | $ | 21 |
| | $ | 18 |
| | $ | 86 |
| | $ | 58 |
|
Increase in Capital Lease Obligations | $ | 29 |
| | $ | 60 |
| | $ | 60 |
| | $ | 81 |
|
| |
(1) | Unproved property acquisition cost for 2015 includes $37 million in the DJ Basin and $43 million in the Marcellus Shale. Unproved property acquisition cost for 2014 includes $55 million in the DJ Basin, $98 million in the Marcellus Shale, and $16 million in the deepwater Gulf of Mexico. |
| |
(2) | Investment in equity method investee represents primarily contributions to CONE Gathering LLC which owns and operates the natural gas gathering infrastructure associated with our Marcellus Shale joint venture. |
On July 20, 2015, we closed the Rosetta Merger and preliminarily allocated $1.5 billion and $1.2 billion to proved and unproved oil and properties, respectively. See Item 1 Financial Statements – Note 3. Rosetta Merger. Financing Activities
Long-Term Debt Our principal source of liquidity is our Credit Facility that matures August 27, 2020. At September 30, 2015, there were no borrowings outstanding under the Credit Facility, leaving $4.0 billion available for use. We may rely on our Credit Facility to help fund our capital investment program, and may periodically borrow amounts for working capital purposes. In connection with the Rosetta Merger, we assumed additional debt, including senior notes and amounts outstanding under Rosetta's revolving credit facility. On July 21, 2015, we repaid the $70 million of outstanding borrowings under Rosetta's revolving credit facility and terminated this credit facility. See Item 1 Financial Statements – Note 3. Rosetta Merger. Our outstanding fixed-rate debt (excluding capital lease obligations) totaled approximately $7.7 billion at September 30, 2015. The weighted average interest rate on fixed-rate debt was 5.71%, with maturities ranging from March 2019 to August 2097.
Dividends We paid total cash dividends of 54 cents per share of our common stock during the first nine months of 2015 and 50 cents per share during the first nine months of 2014.
On October 20, 2015, the Board of Directors declared a quarterly cash dividend of 18 cents per common share, which will be paid on November 16, 2015 to shareholders of record on November 2, 2015. The amount of future dividends will be determined on a quarterly basis at the discretion of our Board of Directors and will depend on earnings, financial condition, capital requirements and other factors.
Exercise of Stock Options We received cash proceeds from the exercise of stock options of $7 million during the first nine months of 2015 and $45 million during the first nine months of 2014.
Common Stock Repurchases We receive shares of common stock from employees for the payment of withholding taxes due on the vesting of restricted shares issued under stock-based compensation plans. We received 481,229 shares with a value of $20 million during the first nine months of 2015 and 253,094 shares with a value of $15 million during the first nine months of 2014.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Derivative Instruments Held for Non-Trading Purposes We are exposed to market risk in the normal course of business operations, and the volatility of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, we continue to use derivative instruments as a means of managing our exposure to price changes.
At September 30, 2015, we had various open commodity derivative instruments related to crude oil, natural gas and NGL sales. Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our open commodity derivative instruments were in a net asset position with a fair value of $748 million. Based on the September 30, 2015 published commodity futures price curves for the underlying commodities, a hypothetical price increase of $10.00 per Bbl for crude oil would decrease the fair value of our net commodity derivative asset by approximately $149 million. A hypothetical price increase of $0.50 per MMBtu for natural gas would decrease the fair value of our net commodity derivative asset by approximately $39 million. We acquired a small portfolio of NGL hedges in the Rosetta Merger. These derivative contracts expire at the end of 2015 and consist of various Mont Belvieu price indices. We have not entered into any additional hedges for NGLs beyond 2015 and a hypothetical 10% price increase per Bbl for NGLs would decrease the fair value of our net commodity derivative asset by approximately $1 million. Our derivative instruments 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 cash settled at the time of election. See Item 1. Financial Statements – Note 6. Derivative Instruments and Hedging Activities. Interest Rate Risk
Changes in interest rates affect the amount of interest we pay on borrowings under our Credit Facility and the amount of interest we earn on our short-term investments.
At September 30, 2015, we had approximately $7.7 billion (excluding capital lease obligations) of long-term debt outstanding. Of this amount, $7.7 billion was fixed-rate debt with a weighted average interest rate of 5.71%. Although near term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to the risk of earnings or cash flow loss.
There was no variable-rate debt outstanding at September 30, 2015. Variable-rate debt exposes us to the risk of earnings or cash flow loss due to increases in market interest rates. We are also exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances. As of September 30, 2015, our cash and cash equivalents totaled approximately $1.0 billion, approximately 15% of which was invested in money market funds and short-term investments with major financial institutions. A change in the interest rate applicable to our variable-rate debt or our short term investments would have a de minimis impact. We currently have no interest rate derivative instruments outstanding. However, we may enter into interest rate derivative instruments in the future if we determine that it is necessary to invest in such instruments in order to mitigate our interest rate risk.
Foreign Currency Risk
The US dollar is considered the functional currency for each of our international operations. Substantially all of our international crude oil, natural gas and NGL production is sold pursuant to US dollar denominated contracts. Transactions, such as operating costs and administrative expenses that are paid in a foreign currency, are remeasured into US dollars and recorded in the financial statements at prevailing currency exchange rates. Certain monetary assets and liabilities, such as taxes payable in foreign tax jurisdictions, are settled in the foreign local currency. A reduction in the value of the US dollar against currencies of other countries in which we have material operations could result in the use of additional cash to settle operating, administrative, and tax liabilities.
Net transaction gains and losses were de minimis for third quarter of each of 2015 and 2014.
We currently have no foreign currency derivative instruments outstanding. However, we may enter into foreign currency derivative instruments (such as forward contracts, costless collars or swap agreements) in the future if we determine that it is necessary to invest in such instruments in order to mitigate our foreign currency exchange risk.
Disclosure Regarding Forward-Looking Statements
This quarterly report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Forward-looking statements give our current expectations or forecasts of future events. These forward-looking statements include, among others, the following:
| |
• | our ability to successfully and economically explore for and develop crude oil and natural gas resources; |
| |
• | anticipated trends in our business; |
| |
• | our future results of operations; |
| |
• | our liquidity and ability to finance our exploration and development activities; |
| |
• | market conditions in the oil and gas industry; |
| |
• | our ability to make and integrate acquisitions; |
| |
• | the impact of governmental fiscal terms and/or regulation, such as those involving the protection of the environment or marketing of production, as well as other regulations; and |
Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “believe,” “anticipate,” “estimate,” “intend,” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 2014, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our Annual Report on Form 10-K for the year ended December 31, 2014 is available on our website at www.nobleenergyinc.com.
Item 4. Controls and Procedures
Based on the evaluation of our disclosure controls and procedures by our principal executive officer and our principal financial officer, as of the end of the period covered by this quarterly report, each of them has concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)), are effective. There were no changes in internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Part II. Other Information
Item 1. Legal Proceedings
See discussion of legal proceedings in Part I. Financial Information, Item 1. Financial Statements - Note 14. Commitments and Contingencies of this Form 10-Q, which is incorporated by reference into this Part II. Item 1, as well as discussion in Item 3. Legal Proceedings, of our Annual Report on Form 10-K for the year ended December 31, 2014.
Item 1A. Risk Factors
There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2014.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table sets forth, for the periods indicated, our share repurchase activity:
|
| | | | | | | | | | | | |
Period | Total Number of Shares Purchased (1) | | Average Price Paid Per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs |
| | | | | | | (in thousands) |
7/1/2015 - 7/31/2015 | 204,367 |
| | $ | 36.98 |
| | — |
| | — |
|
8/1/2015 - 8/31/2015 | 2,061 |
| | 34.03 |
| | — |
| | — |
|
9/1/2015 - 9/30/2015 | 21,204 |
| | 31.25 |
| | — |
| | — |
|
Total | 227,632 |
| | $ | 36.42 |
| | — |
| | — |
|
| |
(1) | Stock repurchases during the period related to common stock received by us from employees for the payment of withholding taxes due on shares of common stock issued under stock-based compensation plans. |
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
None.
Item 6. Exhibits
The information required by this Part II. Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10-Q and is incorporated by reference into this Part II. Item 6.
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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| | | | NOBLE ENERGY, INC. |
| | | | (Registrant) |
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Date | | November 2, 2015 | | /s/ Kenneth M. Fisher |
| | | | Kenneth M. Fisher Executive Vice President, Chief Financial Officer |
Index to Exhibits
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Exhibit Number | | Exhibit |
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2.1 | | Agreement and Plan of Merger, dated as of May 10, 2015, by and among Noble Energy, Inc., Bluebonnet Merger Sub Inc. and Rosetta Resources Inc., filed as Exhibit 2.1 to the Registrant's Current Report on Form 8-K (Date of Event: May 10, 2015) filed on May 11, 2015 and incorporated herein by reference. |
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3.1 | | Certificate of Incorporation of the Registrant (as amended through April 29, 2015), filed as Exhibit 3.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 and incorporated herein by reference. |
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3.2 | | By-Laws of Noble Energy, Inc. (as amended through October 20, 2015), filed as Exhibit 3.1 to the Registrant's Current Report on Form 8-K (Date of Event: October 20, 2015) filed on October 22, 2015 and incorporated herein by reference. |
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4.1 | | Sixth Supplemental Indenture, dated as of July 29, 2015, to Indenture, dated as of February 27, 2009, between Noble Energy, Inc. and Wells Fargo Bank, National Association, as trustee, relating to the Registrant’s 5.625% Senior Notes due 2021, 5.875% Senior Notes due 2022 and 5.875% Senior Notes due 2044 (including the forms of 2021 Notes, 2022 Notes and 2024 Notes) filed as Exhibit 4.2 to the Registrant’s Current Report on Form 8-K (Date of Event: July 29, 2015) filed July 31, 2015 and incorporated herein by reference.
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10.1 | | Second Amendment to Credit Agreement, dated August 27, 2015, by and among Noble Energy, Inc., NBL International Finance B.V., JPMorgan Chase Bank, N.A., as administrative agent, Citibank N.A., as syndication agent, and Bank of America, N.A., Bank of Tokyo-Mitsubishi UFJ, Ltd., Mizuho Bank, Ltd. and DNB Bank ASA, New York Branch, as documentation agents, and the other commercial lending institutions party thereto filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: August 27, 2015) filed August 31, 2015 and incorporated herein by reference.
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10.2 | | |
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10.3 | | |
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10.4 | | |
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12.1 | | |
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31.1 | | |
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31.2 | | |
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32.1 | | |
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32.2 | | |
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101.INS | | XBRL Instance Document |
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101.SCH | | XBRL Schema Document |
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101.CAL | | XBRL Calculation Linkbase Document |
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101.LAB | | XBRL Label Linkbase Document |
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101.PRE | | XBRL Presentation Linkbase Document |
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101.DEF | | XBRL Definition Linkbase Document |