ConocoPhillips is an international energy company and is considered the third largest US oil company.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
For the quarterly period ended September 30, 2012
or
For the transition period from to
Commission file number: 001-32395
ConocoPhillips
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
281-293-1000
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
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.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The registrant had 1,213,894,641 shares of common stock, $.01 par value, outstanding at September 30, 2012.
CONOCOPHILLIPS
TABLE OF CONTENTS
Part I—Financial Information
Item 1. Financial Statements
Consolidated Income Statement
Consolidated Statement of Comprehensive Income
Consolidated Balance Sheet
Consolidated Statement of Cash Flows
Consolidated Statement of Changes in Equity
Notes to Consolidated Financial Statements
Supplementary Information—Condensed Consolidating Financial Information
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Part II—Other Information
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 6. Exhibits
Signature
PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
Revenues and Other Income
Sales and other operating revenues
Equity in earnings of affiliates
Gain (loss) on dispositions
Other income
Total Revenues and Other Income
Costs and Expenses
Purchased commodities
Production and operating expenses
Selling, general and administrative expenses
Exploration expenses
Depreciation, depletion and amortization
Impairments
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
Foreign currency transaction (gains) losses
Total Costs and Expenses
Income from continuing operations before income taxes
Provision for income taxes
Income From Continuing Operations
Income from discontinued operations
Net income
Less: net income attributable to noncontrolling interests
Net Income Attributable to ConocoPhillips
Net Income Attributable to ConocoPhillips Per Share ofCommon Stock (dollars)
Basic
Continuing operations
Discontinued operations
Net Income Attributable to ConocoPhillips Per Share ofCommon Stock
Diluted
Dividends Paid Per Share of Common Stock (dollars)
Average Common Shares Outstanding (in thousands)
See Notes to Consolidated Financial Statements.
1
Net Income
Other comprehensive income (loss)
Defined benefit plans
Prior service cost arising during the period
Reclassification adjustment for amortization of prior service cost (credit) included in net income
Net change
Net actuarial loss arising during the period
Reclassification adjustment for amortization of prior net losses included in net income
Nonsponsored plans*
Income taxes on defined benefit plans
Defined benefit plans, net of tax
Unrealized holding gain on securities**
Reclassification adjustment for gain included in net income
Income taxes on unrealized holding gain on securities
Unrealized gain (loss) on securities, net of tax
Foreign currency translation adjustments
Reclassification adjustment for loss included in net income
Income taxes on foreign currency translation adjustments
Foreign currency translation adjustments, net of tax
Hedging activities
Income taxes on hedging activities
Hedging activities, net of tax
Other Comprehensive Income (Loss), Net of Tax
Comprehensive Income (Loss)
Less: comprehensive income attributable to noncontrolling interests
Comprehensive Income (Loss) Attributable to ConocoPhillips
*Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates.
**Available-for-sale securities of LUKOIL.
2
Assets
Cash and cash equivalents
Short-term investments*
Restricted cash
Accounts and notes receivable (net of allowance of $12 million in 2012 and $30 million in 2011)
Accounts and notes receivable—related parties
Inventories
Prepaid expenses and other current assets
Total Current Assets
Investments and long-term receivables
Loans and advances—related parties
Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $59,890 million in 2012 and $65,029 million in 2011)
Goodwill
Intangibles
Other assets
Total Assets
Liabilities
Accounts payable
Accounts payable—related parties
Short-term debt
Accrued income and other taxes
Employee benefit obligations
Other accruals
Total Current Liabilities
Long-term debt
Asset retirement obligations and accrued environmental costs
Joint venture acquisition obligation—related party
Deferred income taxes
Other liabilities and deferred credits
Total Liabilities
Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2012—1,757,089,796 shares; 2011—1,749,550,587 shares)
Par value
Capital in excess of par
Treasury stock (at cost: 2012—543,195,155 shares; 2011—463,880,628 shares)
Accumulated other comprehensive income
Unearned employee compensation
Retained earnings
Total Common Stockholders’ Equity
Noncontrolling interests
Total Equity
Total Liabilities and Equity
**Certain amounts have been restated to reflect a prior period adjustment. See Note 16—Accumulated Other Comprehensive Income, in the Notes to
Consolidated Financial Statements.
3
Cash Flows From Operating Activities
Adjustments to reconcile net income to net cash provided by operating activities
Dry hole costs and leasehold impairments
Deferred taxes
Undistributed equity earnings
Other
Working capital adjustments
Decrease (increase) in accounts and notes receivable
Decrease (increase) in inventories
Decrease (increase) in prepaid expenses and other current assets
Increase (decrease) in accounts payable
Increase (decrease) in taxes and other accruals
Net cash provided by continuing operating activities
Net cash provided by discontinued operations
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments
Proceeds from asset dispositions
Net sales (purchases) of short-term investments
Long-term advances/loans—related parties
Collection of advances/loans—related parties
Net cash used in continuing investing activities
Net cash provided by (used in) discontinued operations
Net Cash Used in Investing Activities
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
Special cash distribution from Phillips 66
Change in restricted cash
Issuance of company common stock
Repurchase of company common stock
Dividends paid
Net cash used in continuing financing activities
Net cash used in discontinued operations
Net Cash Used in Financing Activities
Effect of Exchange Rate Changes on Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents
Cash and cash equivalents at beginning of period
Cash and Cash Equivalents at End of Period
4
Par
Value
Capital in
Excess of
Treasury
Stock
Accum. Other
Comprehensive
Income
Unearned
Employee
Compensation
Retained
Earnings
December 31, 2011*
Other comprehensive income
Cash dividends paid
Distributions to noncontrolling interests and other
Distributed under benefit plans
Recognition of unearned compensation
Separation of Downstream business
September 30, 2012
5
Note 1—Basis of Presentation
The interim-period financial information presented in the financial statements included in this report is unaudited and, in the opinion of management, includes all known accruals and adjustments necessary for a fair presentation of the consolidated financial position of ConocoPhillips and its results of operations and cash flows for such periods. All such adjustments are of a normal and recurring nature unless otherwise disclosed. Certain notes and other information have been condensed or omitted from the interim financial statements included in this report. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and notes included in our 2011 Annual Report on Form 10-K.
The results of operations for our refining, marketing and transportation businesses; most of our Midstream segment; our Chemicals segment; and our power generation and certain technology operations included in our Emerging Businesses segment (collectively, our “Downstream business”), have been classified as discontinued operations for all periods presented. See Note 2—Separation of Downstream Business, for additional information. Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements relates to our continuing operations.
Note 2—Separation of Downstream Business
On April 30, 2012, the separation of our Downstream business was completed, creating two independent energy companies: ConocoPhillips and Phillips 66. After the close of the New York Stock Exchange on April 30, 2012, the shareholders of record as of 5:00 p.m. Eastern time on April 16, 2012 (the Record Date), received one share of Phillips 66 common stock for every two ConocoPhillips common shares held as of the Record Date.
In connection with the separation, Phillips 66 distributed approximately $7.8 billion to us in a special cash distribution, primarily using the proceeds from the private placement of $5.8 billion in Senior Notes issued by Phillips 66 in March 2012, as well as a portion of the approximately $3.6 billion in cash transferred to Phillips 66 at separation, consisting of funds received from the $2.0 billion term loan that Phillips 66 entered into immediately prior to the separation, and approximately $1.6 billion of cash held by Phillips 66 subsidiaries. Pursuant to a private letter ruling from the Internal Revenue Service, the principal funds from the special cash distribution will be used solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, within twelve months following the distribution. At September 30, 2012, the remaining balance of the cash distribution was $2,468 million and was included in the “Restricted cash” line on our consolidated balance sheet.
In order to effect the separation and govern our relationship with Phillips 66 after the separation, we entered into a Separation and Distribution Agreement, an Indemnification and Release Agreement, an Intellectual Property Assignment and License Agreement, a Tax Sharing Agreement, an Employee Matters Agreement and a Transition Services Agreement. The Separation and Distribution Agreement governs the separation of the Downstream business, the transfer of assets and other matters related to our relationship with Phillips 66. The Indemnification and Release Agreement provides for cross-indemnities between Phillips 66 and us and established procedures for handling claims subject to indemnification and related matters. The Intellectual Property Assignment and License Agreement governs the allocation of intellectual property rights and assets between Phillips 66 and us.
The Tax Sharing Agreement governs the respective rights, responsibilities and obligations of Phillips 66 and ConocoPhillips with respect to taxes, tax attributes, tax returns, tax proceedings and certain other tax matters. In addition, the Tax Sharing Agreement imposes certain restrictions on Phillips 66 and its subsidiaries (including restrictions on share issuances, business combinations, sales of assets and similar transactions) that
6
are designed to preserve the tax-free status of the distribution and certain related transactions. The Tax Sharing Agreement sets forth the obligations of Phillips 66 and us as to the filing of tax returns, the administration of tax proceedings and assistance and cooperation on tax matters.
The Employee Matters Agreement governs the compensation and employee benefit obligations with respect to the current and former employees and non-employee directors of Phillips 66 and ConocoPhillips, and generally allocates liabilities and responsibilities relating to employee compensation, benefit plans and programs. The Employee Matters Agreement provides that employees of Phillips 66 will no longer participate in benefit plans sponsored or maintained by ConocoPhillips. In addition, the Employee Matters Agreement provides that each of the parties will be responsible for their respective current employees and compensation plans for such current employees, and we will be responsible for all liabilities relating to former employees. The Employee Matters Agreement sets forth the general principles relating to employee matters and also addresses any special circumstances during the transition period. The Employee Matters Agreement also provides that (i) the distribution does not constitute a change in control under existing plans, programs, agreements or arrangements, and (ii) the distribution and the assignment, transfer or continuation of the employment of employees with another entity will not constitute a severance event under the applicable plans, programs, agreements or arrangements.
The Transition Services Agreement sets forth the terms on which we will provide Phillips 66, and Phillips 66 will provide to us, certain services or functions Phillips 66 and ConocoPhillips historically have shared. Transition services include administrative, payroll, human resources, data processing, environmental health and safety, financial audit support, financial transaction support, and other support services, information technology systems and various other corporate services. The agreement provides for the provision of specified transition services, generally for a period of up to 12 months, with a possible extension of 6 months (an aggregate of 18 months), on a cost or a cost-plus basis.
7
The following table presents the carrying value of the major categories of assets and liabilities of Phillips 66, immediately preceding the separation of our Downstream business on April 30, 2012, excluded from our consolidated balance sheet at September 30, 2012:
Millions of
Dollars
Accounts and notes receivable
Total current assets of discontinued operations
Net properties, plants and equipment
Total assets of discontinued operations
Total current liabilities of discontinued operations
Total liabilities of discontinued operations
Sales and other operating revenues and income from discontinued operations were as follows:
Sales and other operating revenues from discontinued operations
Income from discontinued operations before-tax
Income tax expense
Income from discontinued operations after-tax includes transaction, information systems and other costs incurred to effect the separation of $70 million for the nine-month period ended September 30, 2012. No separation costs were incurred during the first nine months of 2011.
8
Prior to the separation, commodity sales to Phillips 66 were $4,973 million for the nine-month period ended September 30, 2012, and $4,012 million and $11,611 million for the three- and nine-month periods ended September 30, 2011. Prior to the separation, commodity purchases from Phillips 66 were $166 million for the nine-month period ended September 30, 2012, and $129 million and $393 million for the three- and nine-month periods ended September 30, 2011. Prior to May 1, 2012, commodity sales and related costs were eliminated in consolidation between ConocoPhillips and Phillips 66. Beginning May 1, 2012, these revenues and costs represent third-party transactions with Phillips 66. Although we expect certain transactions related to the sale and purchase of crude oil, natural gas and products to continue in the future with Phillips 66, the expected continuing cash flows are not considered significant; thus, the operations and cash flows of our former Downstream business are considered to be eliminated from our ongoing operations.
Note 3—Variable Interest Entities (VIEs)
We hold variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. Information on our significant VIEs follows:
Freeport LNG Development, L.P. (Freeport LNG)
We have an agreement with Freeport LNG to participate in a liquefied natural gas (LNG) receiving terminal in Quintana, Texas. We have no ownership in Freeport LNG; however, we own a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which serves as the general partner managing the venture. We entered into a credit agreement with Freeport LNG, whereby we agreed to provide loan financing for the construction of the terminal. We also entered into a long-term agreement with Freeport LNG to use 0.9 billion cubic feet per day of regasification capacity. The terminal became operational in June 2008, and we began making payments under the terminal use agreement. Freeport LNG began making loan repayments in September 2008, and the loan balance outstanding was $579 million at September 30, 2012, and $612 million at December 31, 2011. Freeport LNG is a VIE because Freeport GP holds no equity in Freeport LNG, and the limited partners of Freeport LNG do not have any substantive decision making ability. We performed an analysis of the expected losses and determined we are not the primary beneficiary. This expected loss analysis took into account that the credit support arrangement requires Freeport LNG to maintain sufficient commercial insurance to mitigate any loan losses. The loan to Freeport LNG is accounted for as a financial asset, and our investment in Freeport GP is accounted for as an equity investment.
Australia Pacific LNG (APLNG)
As of the third quarter of 2012, APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. We are not the primary beneficiary of APLNG because we share with Origin Energy and China Petrochemical Corporation (Sinopec) the power to direct the key activities of APLNG that most significantly impact its economic performance, which involve activities related to the production and commercialization of coalbed methane, as well as LNG processing and export marketing. As a result, we do not consolidate APLNG, and it is accounted for as an equity method investment.
No other financial support that was not previously contractually required was provided to APLNG as of the nine months ended September 30, 2012, or is expected to be provided in the future. In addition, unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of APLNG. See Note 6—Investments, Loans and Long-Term Receivables, and Note 12—Guarantees, for additional information.
9
Note 4—Inventories
Inventories consisted of the following:
Crude oil and petroleum products
Materials, supplies and other
Inventories valued on the last-in, first-out (LIFO) basis totaled $332 million and $3,387 million at September 30, 2012, and December 31, 2011, respectively. The estimated excess of current replacement cost over LIFO cost of inventories amounted to approximately $100 million and $8,400 million at September 30, 2012, and December 31, 2011, respectively.
A significant portion of our inventories at December 31, 2011, was related to our Downstream business. See Note 2—Separation of Downstream Business, for additional information.
Note 5—Assets Held for Sale or Sold
In August 2012, we sold our 30 percent interest in Naryanmarneftegaz (NMNG) and certain related assets and recognized a gain of $206 million before-tax, which was included in the “Gain (loss) on dispositions” line on our consolidated income statement. At the time of the disposition, the carrying value of our equity investment in NMNG, which was included in our Other International segment, was $244 million.
Note 6—Investments, Loans and Long-Term Receivables
APLNG
In January 2012, APLNG and Sinopec signed an amendment to their existing LNG sales agreement for the sale and purchase of an additional 3.3 million tonnes of LNG per year through 2035. This agreement, in combination with the execution of an LNG sale and purchase agreement with The Kansai Electric Power Co. Inc., in June 2012 for approximately 1.0 million tonnes of LNG per year through 2035, finalized the marketing of the second train.
In July 2012, we sanctioned the development of the second 4.5-million-tonnes-per-year LNG production train for our APLNG coal seam gas to LNG project. LNG exports from the second train are expected to commence in early 2016 under binding sales agreements to Sinopec and Kansai. Upon sanctioning of the second train in July and in conjunction with the LNG sales agreement, Sinopec subscribed to additional shares in APLNG, which increased its equity interest from 15 percent to 25 percent. As a result, on July 12, 2012, both our ownership interest and Origin’s ownership interest diluted from 42.5 percent to 37.5 percent. We recorded a before- and after-tax loss of $133 million from the dilution in the third quarter of 2012. The book value of our investment in APLNG was reduced by $453 million, and we reduced the foreign currency translation adjustment associated with our investment by $320 million. As of September 30, 2012, the book value of our equity method investment in APLNG was $10,444 million, which included $3,438 million of cumulative translation effects due to a strengthening Australian dollar relative to the U.S. Dollar, and is included in the “Investments and long-term receivables” line on our consolidated balance sheet.
In addition, APLNG executed project financing agreements for an $8.5 billion project finance facility during the third quarter of 2012. The $8.5 billion project finance facility is composed of financing agreements executed by APLNG with the Export-Import Bank of the United States for approximately $2.9 billion,
10
the Export-Import Bank of China for approximately $2.7 billion, and a syndicate of Australian and international commercial banks for approximately $2.9 billion. In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata share of the project finance facility until the project achieves financial completion. See Note 12—Guarantees, for additional information.
As of the third quarter of 2012, APLNG is considered a VIE as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. See Note 3—Variable Interest Entities (VIEs) for additional information.
Loans and Long-Term Receivables
As part of our normal ongoing business operations and consistent with industry practice, we enter into numerous agreements with other parties to pursue business opportunities. Included in such activity are loans made to certain affiliated and non-affiliated companies. Significant loans to affiliated companies at September 30, 2012, included the following:
$579 million in loan financing to Freeport LNG.
$1,092 million in project financing to Qatar Liquefied Gas Company Limited (3) (QG3).
The long-term portion of these loans is included in the “Loans and advances—related parties” line on our consolidated balance sheet, while the short-term portion is in “Accounts and notes receivable—related parties.”
Long-term receivables from non-affiliated companies are included in the “Investments and long-term receivables” line on our consolidated balance sheet, while the short-term portion related to non-affiliate loans is in “Accounts and notes receivable.”
Note 7—Suspended Wells
The capitalized cost of suspended wells at September 30, 2012, was $1,013 million, a decrease of $24 million from $1,037 million at year-end 2011. No suspended wells were charged to dry hole expense during the first nine months of 2012 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2011.
Note 8—Impairments
During the three- and nine-month periods of 2012 and 2011, we recognized before-tax impairment charges within the following segments:
Canada
Europe
Asia Pacific and Middle East
The nine-month period of 2012 included a $213 million property impairment in our Canada segment for the carrying value of capitalized project development costs associated with our Mackenzie Gas Project. Advancement of the project was suspended indefinitely in the first quarter of 2012 due to a continued decline in market conditions and the lack of acceptable commercial terms. We also recorded a $481 million impairment for the undeveloped leasehold costs associated with the project, which was included in the
11
“Exploration expenses” line on our consolidated income statement. In addition, the nine-month period of 2012 included a $78 million impairment in our Europe segment, primarily due to an increase in the asset retirement obligation for the Don Field in the United Kingdom, which has ceased production. See Note 20—Segment Disclosures and Related Information, for additional information on our segments.
Note 9—Debt
We have two commercial paper programs supported by our $7.5 billion revolving credit facility: the ConocoPhillips $6.35 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $1.15 billion commercial paper program, which is used to fund commitments relating to the QG3 Project. Commercial paper maturities are generally limited to 90 days.
At both September 30, 2012, and December 31, 2011, we had no direct outstanding borrowings under our revolving credit facilities, with no letters of credit issued as of September 30, 2012, and $40 million as of December 31, 2011. In addition, under the two commercial paper programs, there was $1,540 million of commercial paper outstanding at September 30, 2012, compared with $1,128 million at December 31, 2011. Since we had $1,540 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.0 billion in borrowing capacity under our revolving credit facilities at September 30, 2012.
At September 30, 2012, we classified $967 million of short-term debt as long-term debt, based on our ability and intent to refinance the obligation on a long-term basis under our revolving credit facilities.
During the first nine months of 2012, the following debt instruments were repaid prior to their maturity:
The $400 million 4.4% Notes due 2013.
$1,100 million of the $1,500 million 4.75% Notes due 2014.
We incurred a before-tax loss on redemption of $79 million, consisting of a make-whole premium and unamortized issuance costs.
Note 10—Joint Venture Acquisition Obligation
We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to FCCL Partnership. Quarterly principal and interest payments of $237 million began in the second quarter of 2007, and will continue until the balance is paid. Of the principal obligation amount, approximately $763 million was short-term and was included in the “Accounts payable—related parties” line on our September 30, 2012, consolidated balance sheet. The principal portion of these payments, which totaled $546 million in the first nine months of 2012, is included in the “Other” line in the financing activities section on our consolidated statement of cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.
12
Note 11—Noncontrolling Interests
Activity attributable to common stockholders’ equity and noncontrolling interests for the first nine months of 2012 and 2011 was as follows:
Common
Stockholders’
Non-
Controlling
Interest
Total
Equity*
Balance at January 1
Dividends
Distributions to noncontrolling interests
Other changes, net**
Balance at September 30
* Certain amounts have been restated to reflect a prior period adjustment. See Note 16—Accumulated Other Comprehensive Income.
**Includes components of other comprehensive income, which are disclosed separately in the Consolidated Statement of Comprehensive Income.
Income from continuing operations and discontinued operations attributable to ConocoPhillips for the three- and nine-month periods of 2012 and 2011 were as follows:
Income from continuing operations
Note 12—Guarantees
At September 30, 2012, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.
13
APLNG Guarantees
At September 30, 2012, we have outstanding multiple guarantees in connection with our 37.5 percent ownership interest in APLNG. The following is a description of the guarantees with values calculated utilizing September 2012 exchange rates:
We have guaranteed APLNG’s performance with regard to a construction contract executed in connection with APLNG’s issuance of the Train 1 and Train 2 Notices to Proceed. Our maximum potential amount of future payments related to this guarantee is approximately $120 million and would become payable if APLNG cancels the applicable construction contract and does not perform with respect to the amounts owed to the contractor.
We have issued a construction completion guarantee related to the third-party project financing secured by APLNG. Our maximum potential amount of future payments under the guarantee is estimated to be $3.2 billion, which could be payable if the full debt financing capacity is utilized and completion of the project is not achieved. Our guarantee of the project financing will be released upon meeting certain completion milestones, which we estimate would occur beginning in 2016. Our maximum exposure at September 30, 2012, is zero based upon our pro-rata share of the facility used at that date. In connection with issuance of the guarantee, we recorded a guarantee liability of $114 million.
In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy in October 2008, we agreed to guarantee an existing obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of 4 to 19 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1.1 billion ($2.6 billion in the event of intentional or reckless breach) and would become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-venturers do not make necessary equity contributions into APLNG.
We have guaranteed the performance of APLNG with regard to certain other contracts executed in connection with the project’s continued development. Our maximum potential amount of future payments related to these guarantees is approximately $110 million and would become payable if APLNG does not perform.
Guarantees of Joint Venture Debt
At September 30, 2012, we had guarantees outstanding for our portion of joint venture debt obligations, which have terms of up to 24 years. The maximum potential amount of future payments under the guarantees is approximately $70 million. Payment would be required if a joint venture defaults on its debt obligations.
Other Guarantees
We have other guarantees with maximum future potential payment amounts totaling approximately $380 million, which consist primarily of a guarantee to fund the short-term cash liquidity deficit of two joint ventures, a guarantee of minimum charter revenue for an LNG vessel, one small construction completion guarantee, guarantees of the lease payment obligations of a joint venture, guarantees of the residual value of leased corporate aircraft, and guarantees of the performance of a business partner or some of its customers. These guarantees generally extend up to 12 years or life of the venture.
Indemnifications
Over the years, we have entered into various agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, environmental liabilities, permits and licenses, employee claims, real estate indemnity against tenant defaults, and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite and the
14
maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications at September 30, 2012, was approximately $70 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the recorded carrying amount were approximately $60 million of environmental accruals for known contamination that are included in the “Asset retirement obligations and accrued environmental costs” line on our consolidated balance sheet. For additional information about environmental liabilities, see Note 13—Contingencies and Commitments. “Asset retirement obligations and accrued environmental costs” line on our consolidated balance sheet.
In connection with the separation of the Downstream business, the Company entered into an Indemnification and Release Agreement with Phillips 66. See Note 2—Separation of Downstream Business, for additional information. This agreement provides for cross-indemnities between Phillips 66 and ConocoPhillips and established procedures for handling claims subject to indemnification and related matters. We evaluated the impact of the indemnifications given and the Phillips 66 indemnifications received as of the separation date and concluded those fair values were immaterial.
Note 13—Contingencies and Commitments
A number of lawsuits involving a variety of claims have been made against ConocoPhillips that arise in the ordinary course of business. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.
Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.
Environmental
We are subject to international, federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.
15
Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit and some of the indemnifications are subject to dollar and time limits.
We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except in respect of sites acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. At September 30, 2012, our balance sheet included a total environmental accrual of $380 million, compared with $922 million at December 31, 2011. A significant portion of our environmental contingencies at December 31, 2011, was related to our Downstream business. See Note 2—Separation of Downstream Business, for additional information. We expect to incur a substantial amount of these expenditures within the next 30 years. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings.
Legal Proceedings
Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, are required.
Other Contingencies
We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at September 30, 2012, we had performance obligations secured by letters of credit of $837 million (issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.
In 2007, we announced we had been unable to reach agreement with respect to our migration to an empresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, in November 2007 we filed a request for international arbitration, with the World Bank’s International Centre for Settlement of Investment Disputes (ICSID). An arbitration hearing was held before an ICSID tribunal during the summer of 2010. We are currently awaiting an interim decision on key legal and factual issues, which we anticipate receiving in the first half of 2013. In a separate commercial arbitration from the Company’s ICSID claim discussed above, on September 17, 2012, an International Chamber of Commerce
16
arbitration tribunal issued a decision in favor of the Company finding PDVSA owes $67 million for pre-expropriation breaches of the Petrozuata project agreements.
In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before ICSID against The Republic of Ecuador, as a result of the newly enacted Windfall Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite a restraining order issued by ICSID, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the illegally seized crude oil. In 2009, Ecuador took over operations in Blocks 7 and 21, fully expropriating our assets. In June 2010, the ICSID tribunal concluded it has jurisdiction to hear the expropriation claim. An arbitration hearing on case merits occurred in March 2011, and we are awaiting a decision. On April 24, 2012, Ecuador filed a revised supplemental counterclaim asserting environmental damages, which we believe are not material. The arbitration process is ongoing.
Note 14—Derivative and Financial Instruments
Derivative Instruments
We use derivative instruments to manage our exposure to cash flow variability from commodity price risk. We occasionally use derivatives to capture market opportunities based on our industry knowledge. Our commodity business primarily consists of natural gas, crude oil, bitumen, LNG and natural gas liquids.
Our derivative instruments are held at fair value on our consolidated balance sheet. Where these balances have the right of setoff, they are presented net. Related cash flows are recorded as operating activities on our consolidated statement of cash flows. On our consolidated income statement, realized and unrealized gains and losses are recognized either on a gross basis if directly related to our physical business or a net basis if held for trading. Gains and losses related to contracts that meet and are designated with the normal purchase normal sale exception are recognized upon settlement. We generally apply this exception to eligible crude contracts. We do not use hedge accounting for our commodity derivatives.
The following table presents the gross fair values of our commodity derivatives, excluding collateral, and the line items where they would appear on our consolidated balance sheet:
17
The gains (losses) from commodity derivatives incurred, and the line items where they appear on our consolidated income statement were:
The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts.
September 30
2012
December 31
2011
Commodity
Crude oil, refined products and natural gas liquids (millions of barrels)
Natural gas and power (billions of cubic feet equivalent)
Fixed price
Basis
Foreign Currency Exchange Derivatives
We have foreign currency exchange rate risk resulting from international operations. Our foreign currency exchange derivative activity primarily consists of transactions designed to mitigate our cash-related and foreign currency exchange rate exposures, such as firm commitments for capital projects or local currency tax payments, dividends, and cash returns from net investments in foreign affiliates. We do not elect hedge accounting on our foreign currency exchange derivatives.
The following table presents the gross fair values of our foreign currency exchange derivatives, excluding collateral, and the line items where they would appear on our consolidated balance sheet:
18
The (gains) losses from foreign currency exchange derivatives incurred, and the line items where they appear on our consolidated income statement were:
We had the following net notional position of outstanding foreign currency exchange derivatives:
Sell U.S. dollar, buy other currencies (2)
Sell euro, buy other currencies (3)
Buy U.S. dollar, sell other currencies (4)
Buy British pound, sell other currencies (5)
Buy euro, sell British pound
(1) Denominated in U.S. dollars (USD), British pound (GBP) and euros (EUR).
(2) Primarily euro, Canadian dollar, Norwegian krone and British pound.
(3) Primarily Norwegian krone and British pound.
(4) Primarily Canadian dollar, euro and Norwegian krone.
(5) Primarily euro and U.S. dollar.
Financial Instruments
We have certain financial instruments on the consolidated balance sheet related to interest bearing time deposits and commercial paper. These held-to-maturity financial instruments are included in “Cash and cash equivalents” on our consolidated balance sheet if the maturities at the time we made the investments were 90 days or less; otherwise, these investments are included in “Short-term investments” on our consolidated balance sheet.
These balances consisted of the following:
Cash
Time Deposits
Remaining maturities from 1 to 90 days
Commercial Paper
19
In conjunction with the separation of our Downstream business, we received a special cash distribution from Phillips 66 of $7,818 million. See Note 2—Separation of Downstream Business, for additional information. At September 30, 2012, the unused amount of the special cash distribution was $2,468 million and is designated as “Restricted cash” on our consolidated balance sheet. At September 30, 2012, the funds in the restricted cash account were invested in U.S. Treasury Bills ($268 million) and money market funds ($2,200 million) with maturities within 90 days from September 30, 2012.
Credit Risk
Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, over-the-counter (OTC) derivative contracts and trade receivables. Our cash equivalents and short-term investments are placed in high-quality commercial paper, money market funds, government debt securities and time deposits with major international banks and financial institutions.
The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins or letters of credit when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because these trades are cleared with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit and performance risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.
Our trade receivables result primarily from our petroleum operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less, and we continually monitor this exposure and the creditworthiness of the counterparties. We do not generally require collateral to limit the exposure to loss; however, we will sometimes use letters of credit, prepayments and master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due us.
Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of credit as collateral.
The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on September 30, 2012, and December 31, 2011, was $142 million and $237 million, respectively. No collateral was posted for September 30, 2012, and $3 million was posted for December 31, 2011. If our credit rating had been lowered one level from its “A” rating (per Standard and Poor’s) on September 30, 2012, we would be required to post no additional collateral to our counterparties. If we had been downgraded below investment grade, we would be required to post $142 million of additional collateral, either with cash or letters of credit.
20
Note 15—Fair Value Measurement
We carry a portion of our assets and liabilities at fair value that are measured at a reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclosed according to the quality of valuation inputs under the following hierarchy:
Level 1: Quoted prices (unadjusted) in an active market for identical assets or liabilities.
Level 2: Inputs other than quoted prices that are directly or indirectly observable.
Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities.
The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities that are initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. There were no material transfers in or out of Level 1.
Recurring Fair Value Measurement
Financial assets and liabilities reported at fair value on a recurring basis primarily include derivative instruments and certain investments to support nonqualified deferred compensation plans. The deferred compensation investments are measured at fair value using unadjusted prices available from national securities exchanges; therefore, these assets are categorized as Level 1 in the fair value hierarchy. Level 1 derivative assets and liabilities primarily represent exchange-traded futures and options that are valued using unadjusted prices available from the underlying exchange. Level 2 derivative assets and liabilities primarily represent OTC swaps, options and forward purchase and sale contracts that are valued using adjusted exchange prices, prices provided by brokers or pricing service companies that are all corroborated by market data. Level 3 derivative assets and liabilities consist of OTC swaps, options and forward purchase and sale contracts that are long term in nature and where a significant portion of fair value is calculated from underlying market data that is not readily available. The derived value uses industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value. As reflected in the table below, Level 3 activity was not material.
The following table summarizes the fair value hierarchy for gross financial assets and liabilities (i.e., unadjusted where the right of setoff exists for commodity derivatives accounted for at fair value on a recurring basis):
Deferred compensation investments
Commodity derivatives
Total assets
Total liabilities
Non-Recurring Fair Value Measurement
There were no significant non-recurring fair value measurements as of September 30, 2012.
21
Reported Fair Value of Financial Instruments
The following are the valuation techniques and methods used to estimate the fair value of financial assets and liabilities reported on the balance sheet:
Cash and cash equivalents, restricted cash and short-term investments: The carrying amount reported on the balance sheet approximates fair value.
Accounts and notes receivable (including long-term and related parties): The carrying amount reported on the balance sheet approximates fair value. The valuation technique and methods used to estimate the fair value of the current portion of fixed-rate related party loans is consistent with Loans and advances—related parties.
Loans and advances—related parties: The carrying amount of floating-rate loans approximates fair value. The fair value of fixed-rate loan activity is measured using market observable data and is categorized as Level 2 in the fair value hierarchy. See Note 6—Investments, Loans and Long-Term Receivables, for additional information.
Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts payable and floating-rate debt reported on the balance sheet approximates fair value. The valuation technique and methods used to estimate the fair value of the current portion of the joint venture acquisition obligation reported in accounts payable is consistent with the methodology below.
Fixed-rate debt: The estimated fair value of fixed-rate debt is measured using prices available from a pricing service that is corroborated by market data; therefore, these liabilities are categorized as Level 2 in the fair value hierarchy.
Joint venture acquisition obligation—related party: Fair value is estimated based on the net present value of the future cash flows as a Level 2 fair value, discounted at September 30, 2012, and December 31, 2011, effective yield rates of 0.76 percent and 1.24 percent, respectively, based on yields of U.S. Treasury securities of similar average duration adjusted for our average credit risk spread and the amortizing nature of the obligation principal. See Note 10—Joint Venture Acquisition Obligation, for additional information.
The following table summarizes the net fair value of financial instruments (i.e., adjusted where the right of setoff exists for commodity derivatives):
Financial assets
Total loans and advances—related parties
Financial liabilities
Total debt, excluding capital leases
Total joint venture acquisition obligation
At September 30, 2012, commodity derivative assets and liabilities appear net of $31 million of obligations to return cash collateral and $50 million of rights to reclaim cash collateral, respectively. At December 31, 2011, commodity derivative assets and liabilities appear net of no obligations to return cash collateral and $244 million of rights to reclaim cash collateral.
22
Note 16—Accumulated Other Comprehensive Income
Accumulated other comprehensive income in the equity section of the balance sheet included:
Defined
Benefit Plans
Net
Unrealized
Gain on
Securities
Foreign
Currency
Translation
Accumulated
* The beginning balance of retained earnings has been restated primarily to reflect certain intercompany loans as permanently invested in 2004 and prior periods, which resulted in a $160 million increase in Foreign Currency Translation and Accumulated Other Comprehensive Income, a $15 million decrease to Total Liabilities, and a $145 million reduction in Retained Earnings. The impact on net income and earnings per share was de minimis for the three- and nine-month periods ended September 30, 2012 and 2011.
There were no items within accumulated other comprehensive income related to noncontrolling interests.
Note 17—Cash Flow Information
Cash Payments
Income taxes
Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased
Short-term investments sold
Note 18—Employee Benefit Plans
In connection with the separation of the Downstream business, ConocoPhillips entered into an Employee Matters Agreement with Phillips 66 (see Note 2—Separation of Downstream Business), which provides that employees of Phillips 66 will no longer participate in benefit plans sponsored or maintained by ConocoPhillips. Upon separation, the ConocoPhillips Pension Plan transferred assets and obligations to the Phillips 66 Pension Plan resulting in a net decrease in sponsored pension plan obligations of $1,127 million. Additionally, as a result of the transfer of unrecognized losses to Phillips 66, deferred income taxes and other comprehensive income decreased $335 million and $570 million, respectively.
23
Pension and Postretirement Plans
Components of Net Periodic Benefit Cost
Three Months Ended September 30
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost
Recognized net actuarial (gain) loss
Net periodic benefit costs
Nine Months Ended September 30
During the first nine months of 2012, we contributed $258 million to our domestic benefit plans and $161 million to our international benefit plans. In 2012, we expect to contribute approximately $410 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $210 million to our international qualified and nonqualified pension and postretirement benefit plans.
During the three months ended September 30, 2012, it became probable that lump-sum benefit payments would exceed the sum of service and interest costs for the plan year for the U.S. qualified pension plan and U.S. non-qualified supplemental retirement plan. As a result, we recognized a proportionate share of prior actuarial losses, or pension settlement expense, of $137 million. In conjunction with the recognition of pension settlement expense, the assets and pension benefit obligation of the qualified pension plan were remeasured. At the measurement date, the net pension liability increased $432 million to $1,283 million, resulting in a corresponding decrease to other comprehensive income. The increase in the liability was primarily due to a reduction of the discount rate used to determine benefit obligations from 4.30% at December 31, 2011 to 3.35% at the measurement date. The assumptions used for rate of compensation increased from 4.25% to 4.75% over the same time period.
In addition, pursuant to the Employee Matters Agreement we made certain adjustments to the exercise price and number of our stock-based compensation awards with the intention of preserving the intrinsic value of the awards prior to the separation. Outstanding options to purchase common shares of ConocoPhillips stock that were exercisable prior to the separation were adjusted so the holders of those options would then hold options to purchase common shares of both ConocoPhillips and Phillips 66 stock. Non-exercisable stock options were converted to those of the entity where the employee is working post-separation. In addition, former employee holders and a specified group of holders of stock options and restricted stock units who retired or terminated employment upon or shortly after the separation, received both adjusted ConocoPhillips awards and Phillips 66 awards. ConocoPhillips restricted stock and performance share units awarded for completed performance periods under the Performance Share Program, as well as restricted stock units held by current or former directors, were adjusted to provide holders one restricted share or restricted stock unit of Phillips 66 for every two restricted shares or restricted stock units of ConocoPhillips. Each employee holder of restricted stock and restricted stock units awarded under all other programs were adjusted to provide holders restricted shares or restricted stock units in the company that employs such employee following the separation. Adjustments to our stock-based compensation awards did not have a material impact on compensation expense.
24
Note 19—Related Party Transactions
Significant transactions with related parties were:
Operating revenues and other income
Purchases
Operating expenses and selling, general and administrative expenses
Net interest expense*
* We paid and/or received interest to/from various affiliates, including FCCL Partnership. See Note 6—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.
Note 20—Segment Disclosures and Related Information
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. We manage our operations through six operating segments, which are defined by geographic region: Alaska, Lower 48 and Latin America, Canada, Europe, Asia Pacific and Middle East, and Other International.
On April 30, 2012, our Downstream business was separated into a stand-alone, publicly traded corporation, Phillips 66, and has been reported as discontinued operations in all periods presented. Our reportable segments changed upon separation, and, as a result, all prior periods presented have been restated. Commodity sales to Phillips 66, which were previously eliminated in consolidation prior to the separation, are now reported as third-party sales. For additional information, see Note 2—Separation of Downstream Business.
Our LUKOIL Investment represents our prior investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We completed the divestiture of our entire interest in LUKOIL in the first quarter of 2011.
Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead, ongoing costs associated with the separation and certain technology activities, net of licensing revenues. Corporate assets include all cash and cash equivalents, short-term investments and restricted cash.
We evaluate performance and allocate resources based on net income attributable to ConocoPhillips. Intersegment sales are at prices that approximate market.
25
Analysis of Results by Operating Segment
Sales and Other Operating Revenues
Alaska
Lower 48 and Latin America
Intersegment eliminations
Other International
LUKOIL Investment
Corporate and Other
Consolidated sales and other operating revenues
Consolidated net income attributable to ConocoPhillips
Consolidated total assets
26
Note 21—Income Taxes
Our effective tax rate from continuing operations for the third quarter of 2012 was 52 percent compared with 59 percent for the third quarter of 2011. The lower rate was due primarily to tax benefits associated with asset dispositions occurring in 2012, partially offset by higher income in higher tax rate jurisdictions in 2012.
Our effective tax rate from continuing operations for the first nine months of 2012 was 53 percent compared with 52 percent for the first nine months of 2011.
For both the third quarter and the first nine months of 2012, the effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.
In the United Kingdom, legislation was enacted on July 17, 2012, restricting corporate tax relief on decommissioning costs to 50 percent, retroactively effective from March 21, 2012. Our third quarter 2012 earnings were reduced by $170 million due to the remeasurement of deferred tax balances as of the effective date.
27
We have various cross guarantees among ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding Company II are indirect, 100 percent owned subsidiaries of ConocoPhillips Company. ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to their publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:
ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).
All other nonguarantor subsidiaries of ConocoPhillips.
The consolidating adjustments necessary to present ConocoPhillips’ results on a consolidated basis.
This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.
28
Gain on dispositions
Other income (loss)
Intercompany revenues
Income (loss) from continuing operations before income taxes
Income (Loss) From Continuing Operations
Net income (loss)
Net Income (Loss) Attributable to ConocoPhillips
Less: net income (loss) attributable to noncontrolling interests
29
30
Investments, loans and long-term receivables*
Liabilities and Stockholders’ Equity
Joint venture acquisition obligation
Other liabilities and deferred credits*
Other common stockholders’ equity
Total Liabilities and Stockholders’ Equity
Short-term investments
31
Net sales of short-term investments
Net cash provided by (used in) discontinued operations operations
Net cash provided by (used in) continuing
operating activities
Net Cash Provided by (Used in) Operating Activities
Net purchases of short-term investments
Net cash provided by (used in) continuing financing activities
Net Cash Provided by (Used in) Financing Activities
32
Management’s Discussion and Analysis is the company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 53.
Due to the separation of our downstream businesses on April 30, 2012, which is reported as discontinued operations, income (loss) from continuing operations is more representative of ConocoPhillips as an independent exploration and production company. The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to income (loss) from continuing operations.
BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW
ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural gas. Headquartered in Houston, Texas, we have operations and activities in 30 countries. At September 30, 2012, we had approximately 16,700 employees worldwide and total assets of $115 billion.
The Separation
On April 30, 2012, we completed the separation of our downstream businesses into an independent, publicly traded company, Phillips 66. Our refining, marketing and transportation businesses, most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations included in our Emerging Businesses segment, were transferred to Phillips 66. Results of operations related to Phillips 66 have been classified as discontinued operations in all periods presented in this Form 10-Q. For additional information, see Note 2—Separation of Downstream Business, in the Notes to Consolidated Financial Statements.
Business Environment
As a newly established, independent E&P company, we are solely focused on exploring for, developing and producing oil and natural gas globally. Our commitment to safety and environmental stewardship, operating excellence and financial responsibility is fundamental to our success. We continue to focus on improving our financial position and increasing shareholder returns through production and margin growth, portfolio optimization and maintaining sector-leading dividend distributions. In order to remain competitive, we must continually develop and replenish a portfolio of projects which offer attractive financial returns on our investment. We continue to evaluate our assets regularly to determine whether they fit our strategic plans or should be sold or otherwise disposed, and, as a result, we remain positioned to complete our $8–$10 billion asset disposition program by the end of 2013. For the first nine months of 2012, we have generated proceeds of approximately $2.1 billion as part of this program, which mainly included the sale of the Vietnam business, the Alba and Statfjord fields in the North Sea and our investment in Naryanmarneftegaz (NMNG) in Russia.
33
Because we participate in a capital-intensive industry, we make significant investments to acquire acreage, explore for new oil and gas fields, develop newly discovered fields and maintain existing fields. In the short-term, we will fund a portion of our capital program through the proceeds from our strategic asset dispositions. In the long-term, we plan to fund our capital program organically by investing in high-return developments which will grow our margins and cash flow. We expect our capital spending will be $15.5 billion to $16 billion in 2012. Over the next five years, we plan to execute a disciplined capital program in order to generate 3 to 5 percent annual production volume and margin growth, primarily from major developments underway in the United States, Canada, the United Kingdom and Norwegian North Sea, Malaysia and Australia.
The most significant factors impacting our profitability and related reinvestment of our operating cash flows into our business are the prices for crude oil and natural gas. The prices for these commodity products are subject to factors external to our company, over which we have no control. These prices are supply- and demand-based and can be very volatile; therefore, our strategy is to maintain a core portfolio of low-risk, high-return projects from legacy assets, coupled with a portfolio which offers growth opportunities, such as unconventional plays, deepwater and arctic drilling and liquefied natural gas (LNG).
The following table depicts the average benchmark prices for West Texas Intermediate (WTI) crude oil, Dated Brent crude oil and U.S. Henry Hub natural gas:
Market Indicators
WTI (per barrel)
Dated Brent (per barrel)
U.S. Henry Hub first of month (per million British thermal units)
Industry crude prices for WTI increased 3 percent in the third quarter of 2012 and increased 1 percent in the first nine months of 2012, compared with the same periods of 2011, while Brent prices decreased 3 percent in the third quarter of 2012 and remained relatively flat in the first nine months of 2012. Global oil prices strengthened during the third quarter of 2012, as global economic concerns eased and geopolitical risks remained high. WTI continued to trade at a discount to Brent, mainly due to high inventory levels and excess crude supply in the U.S. Midcontinent market.
Henry Hub natural gas prices decreased 33 percent in the third quarter of 2012, and decreased 39 percent in the first nine months of 2012, compared with the same periods of 2011. U.S. natural gas prices remained depressed in 2012, due to high inventory levels, which resulted from a warmer-than-normal winter and sustained production from shale plays. Prolonged low U.S. natural gas prices may continue to have an adverse effect on our results of operations. The expansion in shale production has also helped boost supplies of natural gas liquids, resulting in downward pressure on natural gas liquids prices in the United States. As a result, our domestic realized natural gas liquids price declined 26 percent in the first nine months of 2012, compared with the same period of 2011.
34
Key Operating and Financial Highlights
Significant highlights during the third quarter of 2012 included the following:
Achieved quarterly production of 1.525 million barrels of oil equivalent per day.
Continued ramp-up of production in Eagle Ford and Bakken.
Continued growth from Canadian oil sands; successful startup of Christina Lake Phase D.
Advanced major growth projects and drilling programs.
Completed turnarounds at major facilities worldwide, as planned.
Increased exploration activity in conventional and unconventional opportunities globally.
Completed sale of NMNG and dilution of interest in Australia Pacific LNG (APLNG).
Outlook
Production for the fourth quarter of 2012 is expected to be higher than the third quarter of 2012, reflecting completion of turnaround activity and ongoing ramp-up in major North American programs, most notably in the Eagle Ford and Canadian oil sands. Full-year 2012 production is estimated to be 1.57 million to 1.58 million barrels of oil equivalent per day. We anticipate continued progress on our major projects and drilling programs in the fourth quarter of 2012, including the evaluation of drilling results on several exploration prospects.
RESULTS OF OPERATIONS
Unless otherwise indicated, discussion of results for the three- and nine-month periods ended September 30, 2012, is based on a comparison with the corresponding period of 2011.
Consolidated Results
We manage our operations through six operating segments, which are defined by geographic region: Alaska, Lower 48 and Latin America, Canada, Europe, Asia Pacific and Middle East, and Other International. Our LUKOIL Investment represents our prior investment in the ordinary shares of OAO LUKOIL, which was sold in the first quarter of 2011. Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead, costs related to the separation and certain technology activities, net of licensing revenues.
A summary of income (loss) from continuing operations by business segment follows:
35
Earnings for ConocoPhillips increased 21 percent in the third quarter of 2012, while earnings for the nine-month period ended September 30, 2012, decreased 5 percent. The improvement in the third quarter of 2012 primarily resulted from:
Higher gains from asset sales of $336 million after-tax, compared with losses of $267 million after-tax in the third quarter of 2011.
Lower production taxes, mainly as a result of lower production volumes.
These items were partially offset by:
Lower prices.
Lower production volumes.
Pension settlement expense of $82 million after-tax. For additional information, see Note 18—Employee Benefit Plans, in the Notes to Consolidated Financial Statements.
The decrease in earnings for the nine-month period of 2012 was primarily due to:
Significantly lower volumes, largely due to dispositions, reduced production in China and higher planned maintenance.
Higher impairments. Non-cash impairments for the nine-month period of 2012 totaled $550 million after-tax.
Lower natural gas and natural gas liquids prices.
The absence of earnings from LUKOIL due to the divestiture of our interest.
Higher operating and selling, general and administrative (SG&A) expenses, which included the pension settlement expense of $82 million after-tax and separation costs of $80 million after-tax.
Higher gains from asset sales of $1,557 million after-tax, compared with gains of $152 million after-tax in the comparative period of 2011.
Lower production taxes and depreciation, depletion and amortization (DD&A) expenses, mainly as a result of lower volumes.
Higher crude oil and LNG prices.
See the “Segment Results” section for additional information on our segment results.
Income Statement Analysis
Sales and other operating revenues decreased 12 percent in both the third quarter and nine-month period of 2012, mainly due to lower crude oil, natural gas and LNG volumes and lower natural gas and natural gas liquids prices. Higher LNG and crude oil prices partly offset the decrease in the nine-month period of 2012.
Equity in earnings of affiliates for the nine-month period of 2012 increased 24 percent. The increase primarily resulted from:
Improved earnings from Qatar Liquefied Gas Company Limited (3) (QG3), primarily due to higher LNG prices and a $72 million tax-related adjustment, partly offset by lower volumes.
The absence of the $83 million before-tax write-off of our investment associated with the cancellation of the Denali gas pipeline project in the second quarter of 2011.
Higher earnings from FCCL Partnership, mainly as a result of new production from Christina Lake Phases C and D, partly offset by lower bitumen prices.
These increases in equity earnings were partially offset by lower earnings from NMNG, largely due to lower volumes.
36
Gain on dispositions for the third quarter and nine-month period of 2012 increased $378 million and $1,253 million, respectively, compared with corresponding periods in 2011. Gains realized in the third quarter of 2012 were primarily due to the disposition of our equity investment in NMNG and the sale of our interest in Block 39 in Peru, which were partly offset by the loss on further dilution of our equity interest in APLNG from 42.5 percent to 37.5 percent. This is compared with a loss in the third quarter of 2011 as a result of the initial dilution of our equity interest in APLNG from 50 percent to 42.5 percent. Additional gains realized in the nine-month period of 2012 mainly resulted from the disposition of our Vietnam business and the Statfjord and Alba fields located in the North Sea, partially offset by the sale of certain E&P assets located in the Lower 48 and the remaining divestiture of our LUKOIL shares in the nine-month period of 2011.
Purchased commodities decreased 19 percent in both the third quarter and nine-month period of 2012, largely as a result of lower U.S. natural gas prices, partly offset by higher purchased volumes.
Production and operating expenses increased 6 percent in the nine-month period of 2012, mostly due to increased operating expenses in China and major turnaround expenses at our Bayu-Undan Field and Darwin LNG facility.
SG&A expenses increased 128 percent and 50 percent in the third quarter and nine-month period of 2012, respectively, mainly as a result of the pension settlement expense. The nine-month period of 2012 also included costs associated with the separation of Phillips 66.
Exploration expenses decreased 18 percent in the third quarter of 2012 and increased 65 percent in the nine-month period of 2012. The decrease in the third quarter of 2012 was mainly due to lower dry hole costs. The increase in the nine-month period was mostly due to the impairment of undeveloped leasehold costs associated with the Mackenzie Gas Project as a result of the indefinite suspension of the project in the first quarter of 2012.
DD&A decreased 7 percent in the nine-month period of 2012, primarily due to lower production volumes as a result of asset dispositions and lower production in China, partially offset by higher production volumes in the Lower 48.
Impairments increased $296 million in the nine-month period of 2012, largely due to the $213 million impairment of capitalized project development costs associated with the Mackenzie Gas Project in the first quarter of 2012, as well as the $78 million increase in the asset retirement obligation for the Don Field in the United Kingdom, which has ceased production. For additional information, see Note 8—Impairments, in the Notes to Consolidated Financial Statements.
Taxes other than income taxes decreased 25 percent and 10 percent in the third quarter and nine-month period of 2012, respectively, mostly due to lower production taxes as a result of lower crude oil production volumes. Lower crude oil prices also contributed to the decrease in the third quarter of 2012.
Interest and debt expense for the third quarter and nine-month period of 2012 decreased 30 percent and 25 percent, respectively, primarily due to higher capitalized interest on projects and lower interest expense due to lower average debt levels.
See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.
37
Summary Operating Statistics
Average Net Production
Crude oil (MBD)*
Natural gas liquids (MBD)
Bitumen (MBD)
Natural gas (MMCFD)**
Total Production (MBOED)***
Average Sales Prices
Crude oil (per barrel)
Natural gas liquids (per barrel)
Bitumen (per barrel)
Natural gas (per thousand cubic feet)
Exploration Expenses
General administrative; geological and geophysical; and lease rentals
Leasehold impairment
Dry holes
*Thousands of barrels per day.
**Millions of cubic feet per day. Represents quantities available for sale and excludes gas equivalent of natural gas liquids included above.
***Thousands of barrels of oil equivalent per day.
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At September 30, 2012, our operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Libya, Nigeria, Algeria, Qatar and Russia.
Total production averaged 1,525 MBOED in the third quarter of 2012, a decrease of 1 percent compared with the third quarter of 2011. Production for the nine-month period of 2012 averaged 1,569 MBOED, down 4 percent from the corresponding period of 2011. The decreases in both periods of 2012 were mostly due to normal field decline, the impact from dispositions and higher planned and unplanned downtime. These decreases were largely offset by additional production from major projects, mainly from shale plays in the Lower 48 and ramp-up of new phases at FCCL, the resumption of production in Libya following a period of civil unrest in 2011, and increased drilling programs. Reduced production in Bohai Bay, China also contributed to the decrease in the nine-month period of 2012.
38
Segment Results
Income From Continuing Operations (millions of dollars)
Crude oil (MBD)
Natural gas (MMCFD)
Total Production (MBOED)
Crude oil (dollars per barrel)
Natural gas (dollars per thousand cubic feet)
The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. As of September 30, 2012, Alaska contributed 23 percent of our worldwide liquids production and 1 percent of our natural gas production.
Our Alaska operations reported earnings of $535 million in the third quarter of 2012, a 7 percent increase compared with the same period in 2011. Earnings for the nine-month period of 2012 were $1,706 million, a 9 percent increase compared with the same period in 2011. The improvement in earnings in the third quarter of 2012 was largely due to lower production taxes, and to a lesser extent, lower DD&A. These improvements were mostly due to lower crude oil production as a result of major planned turnaround activity in Prudhoe and the Western North Slope in the third quarter of 2012. The impact to earnings from lower crude oil production was more than offset by sales from inventory, which contributed approximately $120 million after-tax to third quarter 2012 earnings. Lower LNG sales volumes partly offset the increase in earnings in the third quarter of 2012. Earnings in the nine-month period of 2012 benefitted from higher crude oil and LNG prices, the absence of the $54 million after-tax impairment of our investment associated with the cancellation of the Denali gas pipeline project in the second quarter of 2011, and lower production taxes and DD&A. These increases were partially offset by lower crude oil production volumes and higher operating expenses.
Production averaged 176 MBOED in the third quarter of 2012, a decrease of 15 percent compared with the third quarter of 2011. Production for the nine-month period of 2012 was 209 MBOED, a 6 percent decrease compared with the corresponding period in 2011. The reductions in both periods of 2012 were mainly due to normal field decline and major planned turnaround activity during the third quarter of 2012, partly offset by lower unplanned downtime.
39
Natural gas liquids (dollars per barrel)
As of September 30, 2012, Lower 48 and Latin America contributed 24 percent of our worldwide liquids production and 35 percent of our natural gas production. The Lower 48 and Latin America segment primarily consists of operations located in the U.S. Lower 48 states. Also included in this segment is our 39 percent equity interest in Phoenix Park Gas Processors Limited, which processes natural gas in Trinidad and markets natural gas liquids in the Atlantic Basin, and the Wingate fractionation plant located in Gallup, New Mexico.
Lower 48 and Latin America operations reported earnings of $182 million in the third quarter of 2012, a 46 percent decrease compared with the same period in 2011. Earnings for the nine-month period of 2012 were $556 million, a 44 percent decrease compared with the same period in 2011. The decreases for both periods of 2012 were primarily the result of substantially lower natural gas and natural gas liquids prices and higher DD&A, partially offset by higher crude oil and natural gas liquids volumes. In addition, third quarter 2012 earnings benefitted from lower dry hole costs and the gain on disposition of our interest in Block 39 in Peru, partially offset by higher undeveloped leasehold impairments. For the nine-month period of 2012, lower gains from asset dispositions, higher operating expenses and lower natural gas volumes also contributed to the decrease in earnings.
Average production in the Lower 48 increased 6 percent in the third quarter and 7 percent in the nine-month period of 2012, while average liquids production increased 21 percent and 26 percent over the same respective periods. The increases in both periods of 2012 were mainly due to new production, primarily from the Eagle Ford, Bakken and Permian areas, and improved drilling and well performance, partially offset by normal field decline, and planned and unplanned downtime.
Peru Blocks 123 and 129
In October 2012, we announced our decision not to pursue further exploration activities in Peru Blocks 123 and 129. This decision to withdraw prior to the next exploration period is part of our strategic plan to optimize our portfolio of assets.
40
Income (Loss) From Continuing Operations (millions of dollars)
Consolidated operations
Equity affiliates
Total bitumen
Bitumen (dollars per barrel)
Our Canadian operations comprise mainly natural gas fields in western Canada and oil sands projects in the Athabasca Region of northeastern Alberta. As of September 30, 2012, Canada contributed 15 percent of our worldwide liquids production and 20 percent of our natural gas production.
Canada operations reported losses of $31 million and $674 million in the third quarter and nine-month period of 2012, respectively, versus earnings of $73 million and $201 million in the corresponding periods of 2011. Earnings in the nine-month period of 2012 included the $520 million after-tax impairment of the Mackenzie Gas Project and associated undeveloped leaseholds. The decreases in both periods of 2012 also reflected lower prices, predominantly natural gas, and higher operating and DD&A expenses from our FCCL venture. These decreases were partly offset by higher bitumen volumes and lower DD&A.
Average production increased 8 percent in the third quarter of 2012 and 4 percent in the nine-month period of 2012. The increases in both periods were largely due to new production from Christina Lake Phases C and D in FCCL. Normal field decline and the impact of asset dispositions were largely offset by additional production from western Canada.
41
The Europe segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, as well as exploration activities in Poland and Greenland. As of September 30, 2012, our Europe operations contributed 16 percent of our worldwide liquids production and 13 percent of our natural gas production.
Earnings for our Europe operations were $132 million in the third quarter of 2012, a 50 percent decrease compared with the same period in 2011. Earnings for the nine-month period of 2012 were $1,190 million, a 6 percent decrease compared with the same period in 2011. Earnings for both periods of 2012 were impacted by $170 million in additional income tax expense, as a result of legislation enacted in the United Kingdom in July 2012, which restricted corporate tax relief on decommissioning costs to 50 percent. The additional tax expense resulted from the revaluation of deferred tax balances. Earnings for both periods of 2011 included $234 million in additional income tax expense, as a result of U.K. tax legislation enacted in July 2011, which increased the U.K. corporate tax rate applicable to upstream activity. This additional tax expense consisted of $106 million for the revaluation of deferred tax liabilities; $75 million to reflect the higher tax rates from the effective date of the legislation, March 24, 2011, through June 30, 2011; and $53 million for the impact of the higher tax rates on third quarter 2011 earnings.
Excluding the impact from the U.K. tax increases, the decrease in earnings in both periods of 2012 was primarily the result of substantially lower volumes. Earnings in the third quarter of 2012 were also impacted by losses on foreign currency transactions and lower crude oil prices, partly offset by lower DD&A. Earnings for the nine-month period of 2012 also benefitted from the $285 million after-tax gain on sale of our interests in the Statfjord and Alba fields, lower DD&A and gains on foreign currency transactions, partly offset by the $30 million after-tax impairment of the non-producing Don Field in the United Kingdom, due to an increase in the asset retirement obligation.
Average production decreased 22 percent in the third quarter and 17 percent in the nine-month period of 2012. The decreases in both periods of 2012 were mostly due to field decline, dispositions and slightly higher unplanned downtime, partly offset by production from new wells in Norway. Third quarter 2012 production was also impacted by slightly higher planned downtime in the United Kingdom.
In December 2011, we entered into an agreement to sell our interests in the MacCulloch and Nicol fields in the United Kingdom. The sales of these interests are expected to close in the fourth quarter of 2012, subject to agreement on final terms.
42
Total crude oil
Total natural gas liquids
Total natural gas
The Asia Pacific and Middle East segment has producing operations in China, Indonesia, Australia, the Timor Sea and Qatar, as well as exploration activities in Malaysia, Bangladesh and Brunei. As of September 30, 2012, Asia Pacific and Middle East contributed 12 percent of our worldwide liquids production and 27 percent of our natural gas production.
Asia Pacific and Middle East operations reported earnings of $683 million in the third quarter of 2012, a 42 percent increase compared with the same period in 2011. Earnings for the nine-month period of 2012 were $3,231 million, a 39 percent increase compared with the same period in 2011. The increase in earnings in both periods of 2012 reflected a $133 million after-tax loss recognized in the third quarter of 2012 due to the further dilution of our equity interest in APLNG from 42.5 percent to 37.5 percent, which was more than offset by the absence of the $279 million after-tax loss on the initial dilution of our interest in APLNG from 50 percent to 42.5 percent in the third quarter of 2011. Also contributing to the improvement in third quarter 2012 earnings were gains on foreign currency transactions, lower dry hole costs, the absence of Bohai Bay expenses incurred in
43
the third quarter of 2011, and lower taxes. These increases were partially offset by lower volumes, primarily as a result of our Vietnam disposition, and higher DD&A. Earnings in the nine-month period of 2012 also benefitted from the $931 million after-tax gain on sale of our Vietnam business, significantly higher LNG prices, lower DD&A, as well as a $72 million tax-related adjustment, largely offset by lower crude oil and LNG volumes and an $89 million after-tax charge related to the Bohai Bay settlement with the China State Oceanic Administration.
Production averaged 306 MBOED in the third quarter of 2012, a decrease of 2 percent compared with the third quarter of 2011. For the nine-month period of 2012, production averaged 293 MBOED, a decrease of 15 percent compared with the same period of 2011. The decrease in the third quarter of 2012 was largely due to the disposition of our Vietnam business, normal field decline and unplanned downtime in Qatar, partly offset by higher production in China. Production in the nine-month period of 2012 was also impacted by dispositions and decline, as well as lower production in China and higher planned downtime at our Bayu-Undan Field and Darwin LNG Facility.
In July 2012, we sanctioned the development of the second 4.5-million-tonnes-per-year LNG production train for our APLNG coal seam gas to LNG project. LNG exports from the second train are expected to commence in early 2016 under binding sales agreements to China Petrochemical Corporation (Sinopec) and The Kansai Electric Power Co. Inc. Upon sanctioning of the second train in July and in conjunction with the LNG sales agreement, Sinopec subscribed to additional shares in APLNG, which increased its equity interest from 15 percent to 25 percent. As a result, on July 12, 2012, both our ownership interest and Origin Energy’s ownership interest diluted from 42.5 percent to 37.5 percent.
APLNG executed project financing agreements for an $8.5 billion project finance facility during the third quarter of 2012 and began drawing on the financing in October 2012. Our reduced ownership interest, coupled with Sinopec’s estimated $2.1 billion injection into APLNG associated with the dilution and APLNG’s successful placement of the $8.5 billion of project financing, will lower our future capital requirements to fund the project. We also plan to evaluate opportunities to further reduce our ownership interest in APLNG.
In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata share of the project finance facility until the project achieves financial completion.
For additional information, see Note 3—Variable Interest Entities (VIEs), Note 6—Investments, Loans and Long-Term Receivables and Note 12—Guarantees, in the Notes to Consolidated Financial Statements.
China—Bohai Bay
At the end of the third quarter of 2012, Peng Lai’s net production was approximately 45 MBOED. We continue to seek approval for the revised overall development plan, while the environmental impact assessment was approved in October 2012. Oil offtake should remain fairly level for the remainder of 2012 under an approved interim operations resumption plan.
44
The Other International segment includes producing operations in Nigeria, Libya, Algeria and Russia, as well as exploration activities in Angola and the Caspian Sea. As of September 30, 2012, Other International contributed 10 percent of our worldwide liquids production and 4 percent of our natural gas production.
Other International operations reported earnings of $567 million in the third quarter of 2012, an increase of $514 million compared with the same period in 2011. Earnings for the nine-month period of 2012 were $634 million, an increase of $383 million compared with the same period in 2011. The increase in both periods of 2012 was primarily the result of the $443 million after-tax gain on disposition of our interest in NMNG. Higher earnings from Libya in both periods of 2012 also contributed to the increase, as a result of the resumption of production following a period of civil unrest in 2011. In addition, lower volumes in Russia in the nine-month period of 2012 were partly offset by lower taxes.
Average production increased 36 percent and 13 percent in the third quarter and nine-month period of 2012, respectively. The increases in both periods of 2012 were mostly due to the resumption of production in Libya, partly offset by field decline in Russia and the disposition of our interest in NMNG.
Nigeria Flooding
Our production operations in Nigeria are currently exposed to severe flooding, and, as a result, our fourth quarter drilling program has been interrupted and production may be impacted. We hold a 20 percent interest in the affected Oil Mining Leases and Kwale Gas Plant. For the first nine months of 2012, our net production from Nigeria averaged 43 MBOED. Future impacts are unknown at this time.
45
This segment represents our former investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We sold our remaining interest in LUKOIL in the first quarter of 2011.
Net interest
Corporate general and administrative expenses
Technology
Separation costs
Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased 23 percent in the third quarter of 2012 and decreased 7 percent in the first nine months of 2012. The increase in the third quarter of 2012 was primarily due to a $68 million after-tax premium on early debt retirement, partly offset by higher capitalized interest on projects and lower interest expense due to lower debt levels. In the nine-month period of 2012, higher capitalized interest on projects and lower interest expense more than offset the premium on early debt retirement and lower interest income.
Corporate general and administrative expenses increased $95 million and $109 million in the third quarter and nine-month period of 2012, mostly due to $82 million after-tax of pension settlement expense. Higher costs related to compensation and benefit plans and corporate contributions also contributed to the increase in the nine-month period of 2012.
Technology includes our investment in new technologies or businesses, net of licensing revenues. Activities are focused on heavy oil and oil sands, unconventional reservoirs, subsurface technology, liquefied natural gas, arctic and deepwater, as well as sustainability technology. Technology earnings decreased by 86 percent in the nine-month period of 2012, mostly as a result of lower licensing revenues.
Separation costs consist of expenses related to the separation of our downstream businesses into a stand-alone, publicly traded company, Phillips 66. Expenses incurred in the third quarter and the nine-month period of 2012 primarily included costs related to compensation and benefit plans.
The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, and other costs not directly associated with an operating segment.
46
“Other” expenses improved $98 million in the third quarter and $83 million in the nine-month period of 2012. Both periods in 2012 mainly benefitted from foreign currency transaction gains, in addition to a $39 million after-tax settlement. In addition, the nine-month period of 2012 benefitted from the absence of various tax-related adjustments in 2011, which was partly offset by higher environmental expenses.
Our Corporate and Other net costs are estimated to be $1.1 billion after-tax for the full-year 2012.
47
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Total debt
Total equity*
Percent of total debt to capital**
Percent of floating-rate debt to total debt***
** Capital includes total debt and total equity.
*** Includes effect of interest rate swaps.
To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from continuing operating activities is the primary source of funding. In addition, during the first nine months of 2012, we received $2,088 million in proceeds from asset sales and $7,818 million from a special cash distribution from Phillips 66, primarily using the proceeds from the $5.8 billion in Senior Notes issued by Phillips 66 in March 2012, as well as a portion of the approximately $3.6 billion in cash transferred to Phillips 66 at separation, consisting of funds received from the $2.0 billion term loan which Phillips 66 entered into immediately prior to the separation, and approximately $1.6 billion of cash held by Phillips 66 subsidiaries. The proceeds from the special cash distribution may be used solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, in each case within twelve months following the distribution. At September 30, 2012, the remaining balance of this cash distribution was $2,468 million and was included in the “Restricted cash” line on our consolidated balance sheet.
During the first nine months of 2012, available cash and restricted cash was used to support our ongoing capital expenditures and investments program, repurchase common stock, pay dividends and repay debt. Total dividends paid on our common stock during the first nine months of 2012 were $2,469 million. During the first nine months of 2012, cash and cash equivalents decreased by $4,512 million to $1,268 million.
In addition to cash flows from operating activities and proceeds from asset sales, we rely on our commercial paper and credit facility programs, and our shelf registration statement to support our short- and long-term liquidity requirements. We believe current cash balances and cash generated by operations, together with access to external sources of funds as described below in the “Significant Sources of Capital” section, will be sufficient to meet our funding requirements in the near- and long-term, including our capital spending program, dividend payments, required debt payments and the funding requirements to FCCL Partnership.
Significant Sources of Capital
Operating Activities
Cash provided by continuing operating activities was $9,846 million for the first nine months of 2012, compared with $11,396 million for the corresponding period of 2011, a 14 percent decrease. The decrease was primarily caused by lower volumes, primarily due to dispositions, and lower natural gas and natural gas liquids prices.
While the stability of our cash flows from operating activities benefits from geographic diversity, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and natural gas liquids. Prices and margins in our industry are typically volatile, and are driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.
48
The level of our production volumes also impacts our cash flows. These production levels are impacted by such factors as acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiency, weather conditions, the addition of proved reserves through exploratory success, and their timely and cost-effective development. While we actively manage these factors, production levels can cause variability in cash flows, although generally this variability has not been as significant as that caused by commodity prices.
Asset Sales
Proceeds from asset sales during the first nine months of 2012 were $2,088 million, primarily from the sale of our Vietnam business, the sale of our equity interest in NMNG and the sale of our interest in the Statfjord and Alba fields in the North Sea. This compares with proceeds of $1,954 million in the first nine months of 2011, which mainly included the sale of our remaining interest in LUKOIL and certain properties located in the Lower 48. We plan to raise up to an additional $8 billion from asset sales by the end of 2013.
Commercial Paper and Credit Facilities
At September 30, 2012, we had a revolving credit facility totaling $7.5 billion expiring in August 2016. Our revolving credit facility may be used as direct bank borrowings, as support for issuances of letters of credit totaling up to $750 million, or as support for our commercial paper programs. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or by any of its consolidated subsidiaries.
Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the London interbank market or at a margin above the overnight federal funds rate or prime rates offered by certain designated banks in the United States. The agreement calls for commitment fees on available but unused amounts. The agreement also contains early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.
Our primary funding source for short-term working capital needs is the ConocoPhillips $6.35 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $1.15 billion commercial paper program, which is used to fund commitments relating to the QG3 Project. At September 30, 2012, and December 31, 2011, we had no direct borrowings under the revolving credit facilities, with no letters of credit issued at September 30, 2012, and $40 million at December 31, 2011. In addition, under the two ConocoPhillips commercial paper programs, $1,540 million of commercial paper was outstanding at September 30, 2012, compared with $1,128 million at December 31, 2011. Since we had $1,540 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.0 billion in borrowing capacity under our revolving credit facilities at September 30, 2012.
Shelf Registration
We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
Off-Balance Sheet Arrangements
As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements.
For information about guarantees, see Note 12—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.
49
Capital Requirements
For information about our capital expenditures and investments, see the “Capital Spending” section.
Our debt balance at September 30, 2012, was $21.1 billion, a decrease of $1.5 billion from the balance at December 31, 2011. During the first nine months of 2012, we repaid bonds totaling $1.5 billion. We incurred a before-tax loss on the redemption of $79 million, consisting of a make-whole premium and unamortized issuance costs. In October 2012, we repaid $897 million of 4.75% notes upon maturity.
We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to FCCL. Quarterly principal and interest payments of $237 million began in the second quarter of 2007, and will continue until the balance is paid. Of the principal obligation amount, approximately $763 million was short-term and was included in the “Accounts payable—related parties” line on our September 30, 2012, consolidated balance sheet. The principal portion of these payments, which totaled $546 million in the first nine months of 2012, is included in the “Other” line in the financing activities section on our consolidated statement of cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.
In July 2012, we announced a dividend of 66 cents per share. The dividend was paid September 4, 2012, to stockholders of record at the close of business on July 23, 2012. Additionally, in October 2012, we announced a dividend of 66 cents per share. The dividend will be paid December 3, 2012, to stockholders of record at the close of business on October 15, 2012.
On December 2, 2011, our Board of Directors authorized the purchase of up to an additional $10 billion of our common stock over the subsequent two years. Since our share repurchase programs began in 2010, share repurchases totaled 300 million shares at a cost of $20.1 billion through September 30, 2012. Future share repurchases will be made opportunistically, contingent upon commodity prices and proceeds from asset dispositions.
Capital Spending
Capital Expenditures and Investments
LUKOIL
United States
International
50
During the first nine months of 2012, capital expenditures and investments supported key exploration and development programs, primarily:
Oil and natural gas exploration and development activities in the Lower 48, including the Eagle Ford and Bakken shale plays, and the Permian Basin.
Exploration leases and wells in deepwater Gulf of Mexico.
Oil sands development and ongoing liquids-focused plays in Canada.
Further development of coalbed methane projects associated with the APLNG joint venture in Australia.
Continued development of new fields offshore Malaysia and ongoing exploration and development activity offshore Indonesia and Australia.
In Europe, development activities in the Ekofisk, Jasmine and Clair Ridge areas, as well as investment in a joint venture in Poland.
The Kashagan Field in the Caspian Sea.
Leasehold acquisitions in Angola.
Contingencies
Legal Matters
Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.
51
We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. For a discussion of the most significant of these environmental laws and regulations, including those with associated remediation obligations, see the “Environmental” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 64, 65 and 66 of our 2011 Annual Report on Form 10-K.
We occasionally receive requests for information or notices of potential liability from the Environmental Protection Agency (EPA) and state environmental agencies alleging that we are a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2011, we reported we had been notified of potential liability under CERCLA and comparable state laws at 74 sites around the United States. As of September 30, 2012, we had resolved 2 sites and transferred 61 sites to Phillips 66, bringing the number of unresolved sites with potential liability to 11.
At September 30, 2012, our balance sheet included a total environmental accrual of $380 million, compared with $922 million at December 31, 2011. A significant portion of our environmental contingencies at December 31, 2011, was transferred to Phillips 66. We expect to incur a substantial amount of these expenditures within the next 30 years.
Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect on our results of operations or financial position as a result of compliance with current environmental laws and regulations.
Climate Change
There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, to the extent enacted, could have a material impact on our results of operations and financial condition. Examples of legislation and precursors for possible regulation that do or could affect our operations include the EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)) and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that trigger regulation of GHGs under the Clean Air Act, may trigger more climate-based claims for damages, and may result in longer agency review time for development projects.
For other examples of legislation or precursors for possible regulation and factors on which the ultimate impact on our financial performance will depend, see the “Climate Change” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 66 and 67 of our 2011 Annual Report on Form 10-K.
52
CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions.
We based the forward-looking statements on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including the following:
Fluctuations in crude oil, bitumen, natural gas, LNG and natural gas liquids prices.
Potential failures or delays in achieving expected reserve or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks and the inherent uncertainties in predicting reserves and reservoir performance.
Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.
Unexpected changes in costs or technical requirements for constructing, modifying or operating facilities for exploration and production projects.
Lack of, or disruptions in, adequate and reliable transportation for our crude oil, natural gas, natural gas liquids, bitumen and LNG.
Inability to timely obtain or maintain permits, including those necessary for drilling and/or development projects, construction of LNG terminals or regasification facilities; comply with government regulations; or make capital expenditures required to maintain compliance.
Failure to complete definitive agreements and feasibility studies for, and to timely complete construction of, announced and future exploration and production and LNG projects.
Potential disruption or interruption of our operations due to accidents, extraordinary weather events, civil unrest, political events, terrorism or cyber attacks.
International monetary conditions and exchange controls.
Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations.
Liability for remedial actions, including removal and reclamation obligations, under environmental regulations.
Liability resulting from litigation.
General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas, LNG or natural gas liquids pricing, regulation or taxation; other political, economic or diplomatic developments; and international monetary fluctuations.
Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules applicable to our business.
Limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets.
Delays in, or our inability to implement, our asset disposition plan.
Inability to obtain economical financing for projects, construction or modification of facilities and general corporate purposes.
The factors generally described in Item 1A—Risk Factors in our 2011 Annual Report on Form 10-K.
53
Information about market risks for the nine months ended September 30, 2012, does not differ materially from that discussed under Item 7A in our 2011 Annual Report on Form 10-K.
We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. As of September 30, 2012, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Executive Vice President, Finance and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Executive Vice President, Finance and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of September 30, 2012.
There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Act, in the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
54
PART II. OTHER INFORMATION
The following is a description of reportable legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the third quarter of 2012 and any material developments with respect to matters previously reported in ConocoPhillips’ 2011 Annual Report on Form 10-K. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings was decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to the U.S. Securities and Exchange Commission (SEC) regulations.
On April 30, 2012, the separation of our Downstream business was completed, creating two independent energy companies: ConocoPhillips and Phillips 66. In connection with the separation, we entered into an Indemnification and Release Agreement which provides for cross-indemnities between Phillips 66 and us and established procedures for handling claims subject to indemnification and related matters, such as legal proceedings. We have included matters where we remain a party to a proceeding relating to Phillips 66, in accordance with SEC regulations. We do not expect any of those matters to result in a net claim against us.
New Matters
On September 19, 2012, the Bay Area Air Quality Management District (District) issued a $213,500 demand to settle fourteen Notices of Violation (NOVs) issued in 2009 and 2010 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery. Phillips 66 is working with the District to resolve this matter.
On October 15, 2012, the District issued a $313,000 demand to settle thirteen NOVs issued in 2010 and 2011 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery. Phillips 66 is working with the District to resolve this matter.
Matters Previously Reported
Phillips 66 was one of several companies who entered Administrative Settlement Agreements (ASAs) with the U.S. Environmental Protection Agency (EPA) to settle allegations it had used invalid Renewable Identification Numbers (RINs) for its 2010 and 2011 fuel program compliance. Under this Agreement, Phillips 66 will pay a maximum of $350,000 in penalties for the use of invalid RINs. Payments are made upon demand from the EPA. To date, $250,000 has been paid and it is anticipated the EPA will demand the final $100,000 in 2013.
Phillips 66 has settled an allegation that it did not immediately notify the EPA of certain releases in 2010 and 2011 at the Phillips 66 Wood River Refinery. The facility will be paying a fine of $25,224 and perform on-site supplemental environmental projects valued at $125,000.
55
You should carefully consider the following risk factor, in addition to the risk factors disclosed in Item 1A of our 2011 Annual Report on Form 10-K.
Our operations present hazards and risks that require significant and continuous oversight.
Our technologies, systems and networks may be subject to cybersecurity breaches. Although we have experienced occasional, actual or attempted breaches of our cybersecurity, none of these breaches has had a material effect on our business, operations or reputation. If our systems for protecting against cybersecurity risks prove to be insufficient, we could be adversely affected by having our business systems compromised, our proprietary information altered, lost or stolen, or our business operations disrupted.
There have been no other material changes from the risk factors disclosed in Item 1A of our 2011 Annual Report on Form 10-K.
Issuer Purchases of Equity Securities
Approximate DollarValue of Shares
that May Yet BePurchased Under thePlans or Programs
July 1-31, 2012
August 1-31, 2012
September 1-30, 2012
56
* Filed herewith.
57
SIGNATURE
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.
October 30, 2012
58