Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

February 21, 2008

 

Capital Resources and Liquidity
Financial Indicators

 

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from operating activities is the primary source of funding. In addition, during 2007 we raised $3,572 million in proceeds from asset dispositions. During 2007, available cash was used to support our ongoing capital expenditures and investments program, repurchase shares of our common stock, repay debt, provide loan financing to certain related parties, pay dividends, and meet the funding requirements related to the business venture with EnCana. During 2007, cash and cash equivalents increased $639 million to $1,456 million.

In addition to cash flows from operating activities and proceeds from asset sales, we also rely on our cash balance, commercial paper and credit facility programs, and our shelf registration statements, to support our short- and long-term liquidity requirements. We anticipate these sources of liquidity will be adequate to meet our funding requirements in the near- and long-term, including our capital spending program, our share repurchase program, dividend payments, required debt payments, and the funding requirements related to the business venture with EnCana. For additional information about the EnCana transaction, see Note 16 — Joint Venture Acquisition Obligation, in the Notes to Consolidated Financial Statements.

Our cash flows from operating activities increased in each of the annual periods from 2005 through 2007. Favorable market conditions played a significant role in the upward trend of our cash flows from operating activities. In addition, cash flows in 2007 benefited from the full year inclusion of the operating activity of Burlington Resources, versus only nine months in 2006. Absent any unusual event during 2008, we expect market conditions will again be the most important factor affecting our 2008 operating cash flows.

 

Significant Sources of Capital
Operating Activities
During 2007, cash of $24,550 million was provided by operating activities, a 14 percent increase over cash from operations of $21,516 million in 2006. Contributing to the increase was a planned inventory reduction in the 2007 period, partially related to the formation of the WRB downstream business venture; the impact of the Burlington Resources acquisition late in the first quarter of 2006; and higher worldwide crude oil prices in 2007. These positive factors were partially offset by the absence of dividends from our Venezuelan operations in 2007.

During 2006, cash flow from operations increased $3,888 million to $21,516 million. The improvement, compared with 2005, reflects higher worldwide crude oil prices and U.S.refining margins, higher distributions from equity affiliates, and the impact of the Burlington Resources acquisition, partially offset by higher interest payments.

While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, natural gas and natural gas liquids, as well as refining and marketing margins. During 2007 and 2006, we benefited from favorable crude oil and natural gas prices, as well as refining margins. The sustainability of these prices and margins is 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.

The level of our production volumes of crude oil, natural gas and natural gas liquids 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 the timely and cost-effective development of those proved reserves. While we actively manage these factors, production levels can cause variability in cash flows, although historically this variability has not been as significant as that experienced with commodity prices.

After adjusting our production rates for the impact of the expropriation of our Venezuelan oil operations in June 2007, our BOE production has increased in each of the past three years. These increases were driven primarily by acquisitions, including our increased ownership interest in LUKOIL during 2005 and 2006, the acquisition of Burlington Resources in 2006 and the business venture with EnCana in 2007. Our adjusted 2007 production was approximately 2.25 million BOE per day, after reductions for the expropriation, our exit from Dubai and the sale of non-core assets. We expect 2008 annual production to be similar to the adjusted 2007 amount. Through 2012, we expect our annual production growth rate to average approximately 2 percent. These projections are tied to projects currently scheduled to begin production or ramp-up in those years and exclude our Canadian Syncrude mining operations.

To maintain or grow our production volumes, we must continue to add to our proved reserve base. Our reserve replacement over the three-year period ending December 31, 2007, was 186 percent. The purchase of reserves in place was a significant factor in replacing our reserves over the past three years, partially offset by the expropriation of our Venezuelan oil assets. Significant purchases during this three-year period included reserves added in 2007 related to the EnCana business venture, the 2006 acquisition of Burlington Resources and the 2005 re-entry into Libya, as well as proved reserves added through our investments in LUKOIL.

We are developing and pursuing projects we anticipate will allow us to add to our reserve base going forward. However, access to additional resources has become increasingly difficult as direct investment is prohibited in some nations, while fiscal and other terms in other countries can make projects uneconomic or unattractive. In addition, political instability, competition from national oil companies, and lack of access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to replace our production over subsequent years.

As discussed in Critical Accounting Estimates, engineering estimates of proved reserves are imprecise, and therefore, each year reserves may be revised upward or downward due to the impact of changes in oil and gas prices or as more technical data becomes available on the reservoirs. In 2007 and 2005, revisions increased our reserves, while in 2006, revisions decreased reserves. It is not possible to reliably predict how revisions will impact reserve quantities in the future. See the “Capital Spending” section for an analysis of proved undeveloped reserves.

In addition, the level and quality of output from our refineries impacts our cash flows. The output at our refineries is impacted by such factors as operating efficiency, maintenance turnarounds, feedstock availability and weather conditions. We actively manage the operations of our refineries and, typically, any variability in their operations has not been as significant to cash flows as that experienced with refining margins.

In 2006, we received approximately $1.1 billion in distributions from two heavy-oil projects in Venezuela. The majority of these distributions represented operating results from previous years. We did not receive an operating distribution related to these projects in 2007. See the “Outlook” section for additional discussion concerning our operations in Venezuela.

 

Asset Sales
Proceeds from asset sales in 2007 were $3,572 million, compared with $545 million in 2006. The increase is mainly due to ongoing asset rationalization efforts related to the program we announced in April 2006 to dispose of assets that no longer fit into our strategic plans or those that could bring more value by being monetized in the near term. Through December 31, 2007, this program had generated proceeds of approximately $3.8 billion since inception. In 2008, we expect to complete the disposition of our retail assets in the United States, Norway, Sweden and Denmark.

 

Commercial Paper and Credit Facilities
In September 2007, we replaced our $5 billion and $2.5 billion revolving credit facilities, with one $7.5 billion revolving credit facility, expiring in September 2012. This facility may be used as direct bank borrowings, as support for the ConocoPhillips $7.5 billion commercial paper program, as support for the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, or as support for issuances of letters of credit totaling up to $750 million. The 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 credit 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.

Our primary funding source for short-term working capital needs is the ConocoPhillips $7.5 billion commercial paper program, a portion of which may be denominated in other currencies (limited to euro 3 billion equivalent). Commercial paper maturities are generally limited to 90 days. The ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program is used to fund commitments relating to the Qatargas 3 project. At December 31, 2007 and 2006, we had no outstanding borrowings under the credit facilities, but $41 million in letters of credit had been issued at both dates. Under both commercial paper programs, there was $725 million of commercial paper outstanding at December 31, 2007, compared with $2,931 million at December 31, 2006. Since we had $725 million of commercial paper outstanding and had issued $41 million of letters of credit, we had access to $6.7 billion in borrowing capacity under our revolving credit facility at December 31, 2007.

At December 31, 2007, Moody’s Investor Service had a rating of “A1” on our senior long-term debt; and Standard and Poors’ Rating Service and Fitch had ratings of “A.” We do not have any ratings triggers on any of our corporate debt that would cause an automatic event of default in the event of a downgrade of our credit rating and thereby impact our access to liquidity. In the event that our credit rating deteriorated to a level that would prohibit us from accessing the commercial paper market, we would still be able to access funds under our $7.5 billion revolving credit facilities.

 

Shelf Registrations
We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) 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.

We also have on file with the SEC a shelf registration statement under which ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding Company II, both wholly owned subsidiaries, could issue an indeterminate amount of senior debt securities, fully and unconditionally guaranteed by ConocoPhillips and ConocoPhillips Company.

 

Minority Interests
At December 31, 2007, we had outstanding $1,173 million of equity in less than wholly owned consolidated subsidiaries held by minority interest owners, including a minority interest of $508 million in Ashford Energy Capital S.A. The remaining minority interest amounts are primarily related to operating joint ventures we control. The largest of these, $648 million, was related to the Darwin LNG project located in northern Australia.

In December 2001, in order to raise funds for general corporate purposes, ConocoPhillips and Cold Spring Finance S.a.r.l. (Cold Spring) formed Ashford Energy Capital S.A. through the contribution of a $1 billion ConocoPhillips subsidiary promissory note and $500 million cash by Cold Spring. Through its initial $500 million investment, Cold Spring is entitled to a cumulative annual preferred return based on three-month LIBOR rates, plus 1.32 percent. The preferred return at December 31, 2007, was 6.55 percent. In 2008, and at each 10-year anniversary thereafter, Cold Spring may elect to remarket their investment in Ashford, and if unsuccessful, could require ConocoPhillips to provide a letter of credit in support of Cold Spring’s investment, or in the event that such letter of credit is not provided, then cause the redemption of their investment in Ashford. Should ConocoPhillips’ credit rating fall below investment grade on a redemption date, Ashford would require a letter of credit to support $475 million of the term loans, as of December 31, 2007, made by Ashford to other ConocoPhillips subsidiaries. If the letter of credit is not obtained within 60 days, Cold Spring could cause Ashford to sell the ConocoPhillips subsidiary notes. At December 31, 2007, Ashford held $2.0 billion of ConocoPhillips subsidiary notes and $29 million in investments unrelated to ConocoPhillips. We report Cold Spring’s investment as a minority interest because it is not mandatorily redeemable and the entity does not have a specified liquidation date. Other than the obligation to make payment on the subsidiary notes described above, Cold Spring does not have recourse to our general credit.

 

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. At December 31, 2007, we were liable for certain contingent obligations under the following contractual arrangements:

• Qatargas 3: Qatargas 3 is an integrated project to produce and liquefy natural gas from Qatar’s North field. We own a 30 percent interest in the project. The other participants in the project are affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent). Our interest is held through a jointly owned company, Qatar Liquefied Gas Company Limited (3), for which we use the equity method of accounting. Qatargas 3 secured project financing of $4 billion in December 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA and commercial bank facilities. Prior to project completion certification, all loans, including the ConocoPhillips loan facilities, are guaranteed by the participants, based on their respective ownership interests. Accordingly, our maximum exposure to this financing structure is $1.2 billion, excluding accrued interest. Upon completion certification, which is expected in 2010, all project loan facilities, including the ConocoPhillips loan facilities, will become non-recourse to the project participants. At December 31, 2007, Qatargas 3 had $2.4 billion outstanding under all the loan facilities, of which ConocoPhillips provided $690 million, and an additional $43 million of accrued interest.
• Rockies Express Pipeline LLC: In June 2006, we issued a guarantee for 24 percent of the $2.0 billion in credit facilities of Rockies Express Pipeline LLC (Rockies Express), which will be used to construct a natural gas pipeline across a portion of the United States. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $480 million, which could become payable if the credit facility is fully utilized and Rockies Express fails to meet its obligations under the credit agreement. At December 31, 2007, Rockies Express had $1,625 million outstanding under the credit facilities, with our 24 percent guarantee equaling $390 million. In addition, we have a 24 percent guarantee on $600 million of Floating Rate Notes due 2009 issued by Rockies Express in September 2007. It is anticipated that construction completion will be achieved in 2009, and refinancing will take place at that time, making the debt non-recourse. For additional information, see Note 7 — Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements.
• Keystone Oil Pipeline: In December 2007, we acquired a 50 percent equity interest in the Keystone Oil Pipeline (Keystone), a joint venture with TransCanada Corporation. Keystone plans to construct a crude oil pipeline originating in Alberta, with delivery points in Illinois and Oklahoma. In connection with certain planning and construction activities, agreements were put in place with third parties to guarantee the payments due under those agreements. Our maximum potential amount of future payments under those agreements are estimated to be $400 million, which could become payable if Keystone fails to meet its obligations under the agreements noted above and the obligation cannot otherwise be mitigated. Payments under the guarantees are contingent upon the partners not making necessary equity contributions into Keystone; therefore, it is considered unlikely that payments would be required. All but $15 million of the guarantees will terminate after construction is completed, currently estimated to be in 2010.

 

For additional information about guarantees, see Note 17 — Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

 

Capital Requirements
For information about our capital expenditures and investments, see the “Capital Spending” section.

Our debt balance at December 31, 2007, was $21.7 billion, a decrease of $5.4 billion during 2007, and our debt-to-capital ratio was 19 percent at year-end 2007. Our debt-to-capital ratio at the end of 2008 will depend on realized commodity prices and margins, the funding of our capital program, and the level of our dividends and share repurchases. Our current debt-to-capital target is 20 percent to 25 percent.

Effective January 15, 2007, we redeemed the 8% Junior Subordinated Deferrable Interest Debentures due 2037, at a premium of $14 million, plus accrued interest. This redemption resulted in the immediate redemption by Phillips 66 Capital II of $350 million of 8% Capital Securities. See Note 15 — Debt, in the Notes to Consolidated Financial Statements, for additional information.

Also, in January 2007, we redeemed our $153 million 7.25% Notes due 2007 upon their maturity. In February 2007, we reduced our Floating Rate Five-Year Term Note due 2011 from $5 billion to $4 billion, with a subsequent reduction in July 2007 to $3 billion. In April 2007, we redeemed our $1 billion Floating Rate Notes due 2007 upon their maturity. In October 2007, we redeemed $300 million of ConocoPhillips Australia Funding Company’s Floating Rate Notes due 2009 at par plus accrued interest.

In May 2007, Polar Tankers Inc., a wholly owned subsidiary, issued $645 million of 5.951% Notes due 2037. The notes are fully and unconditionally guaranteed by ConocoPhillips and ConocoPhillips Company.

In December 2007, we terminated interest rate swaps on $350 million of our 4.75% Notes due 2012. No interest rate swaps remain on any of our debt.

In January 2008, we repaid $1 billion of our Floating Rate Five-Year Term Note due 2011, reducing the balance outstanding to $2 billion. In February 2008, we gave notice to redeem in March 2008 our $300 million 7.125% Debentures due 2028 at 102.7 percent, plus accrued interest.

On January 3, 2007, we closed on a business venture with EnCana. As part of this transaction, we are obligated to contribute $7.5 billion, plus accrued interest, over a ten-year period, beginning in 2007, to the upstream business venture, FCCL Oil Sands Partnership, formed as a result of the transaction. An initial contribution of $188 million was made upon closing in January. 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 $593 million is short-term and is included in the “Accounts payable — related parties” line on our consolidated balance sheet. The principal portion of these payments, which totaled $425 million in 2007, is presented on our consolidated statement of cash flows as an other financing activity. 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 an additional capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

On July 9, 2007, we announced plans to repurchase up to $15 billion of our common stock through the end of 2008. This amount included $2 billion remaining under a previously announced program. During 2007, we repurchased 89.5 million shares of our common stock at a cost of $7.0 billion, including 177,110 shares at a cost of $14 million from a consolidated Burlington Resources grantor trust. We anticipate first-quarter 2008 share repurchases to be $2 billion to $3 billion.

In December 2005, we entered into a credit agreement with Qatargas 3, whereby we will provide loan financing of approximately $1.2 billion for the construction of an LNG train in Qatar. This financing will represent 30 percent of the project’s total debt financing. Through December 31, 2007, we had provided $690 million in loan financing, and an additional $43 million of accrued interest. See the “Off-Balance Sheet Arrangements” section for additional information on Qatargas 3.

In 2004, we finalized our transaction with Freeport LNG Development, L.P. (Freeport LNG) to participate in a proposed LNG receiving terminal in Quintana, Texas. Construction began in early 2005. We do not have an ownership interest in the facility, but we do have a 50 percent interest in the general partnership managing the venture, along with contractual rights to regasification capacity of the terminal. We entered into a credit agreement with Freeport LNG to provide loan financing of approximately $631 million, excluding accrued interest, for the construction of the facility. Through December 31, 2007, we had provided $594 million in loan financing, and an additional $87 million of accrued interest.

In the fall of 2004, ConocoPhillips and LUKOIL agreed to the expansion of the Varandey terminal as part of our investment in the OOO Naryanmarneftegaz (NMNG) joint venture. We have an obligation to provide loan financing to Varandey Terminal Company for 30 percent of the costs of the terminal expansion, but we will have no governance or ownership interest in the terminal. We estimate our total loan obligation for the terminal expansion to be approximately $416 million at current exchange rates, excluding interest to be accrued during construction. This amount will be adjusted as the project’s cost estimate and schedule are updated and the ruble exchange rate fluctuates. Through December 31, 2007, we had provided $331 million in loan financing, and an additional $32 million of accrued interest.

Our loans to Qatargas 3, Freeport LNG and Varandey Terminal Company are included in the “Loans and advances — related parties” line on the balance sheet.

In February 2008, we announced a quarterly dividend of 47 cents per share, representing a 15 percent increase over the previous quarter’s dividend of 41 cents per share. The dividend is payable March 3, 2008, to stockholders of record at the close of business February 25, 2008.

 

Contractual Obligations
The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2007:

 

(a) Includes $688 million of net unamortized premiums and discounts. See Note 15 — Debt, in the Notes to Consolidated Financial Statements, for additional information.

(b) Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. The majority of the purchase obligations are market-based contracts. Includes: (1) our commercial activities of $74,446 million, of which $31,834 million are primarily related to the supply of crude oil to our refineries and the optimization of the supply chain, $10,530 million primarily related to the supply of unfractionated natural gas liquids (NGL) to fractionators, optimization of NGL assets, and for resale to customers, $9,575 million on futures, $8,933 million primarily related to natural gas for resale customers, $7,354 million related to transportation, $4,984 million related to product purchases, $943 million related to power trades, and $293 million related to the purchase side of exchange agreements; (2) $45,744 million of purchase commitments for products, mostly natural gas and NGL, from CPChem over the remaining term of 92 years; and (3) purchase commitments for jointly owned fields and facilities where we are the operator, of which some of the obligations will be reimbursed by our co-venturers in these properties. Does not include: (1) purchase commitments for jointly owned fields and facilities where we are not the operator; and (2) an agreement to purchase up to 165,000 barrels per day of Venezuelan Merey, or equivalent, crude oil for a market price over a remaining 12-year term if a variety of conditions are met.

(c) Represents the remaining amount of contributions, excluding interest, due over a nine-year period to the upstream joint venture formed with EnCana.

(d) Does not include: Pensions — for the 2008 through 2012 time period, we expect to contribute an average of $335 million per year to our qualified and non-qualified pension and postretirement medical plans in the United States and an average of $200 million per year to our non-U.S. plans, which are expected to be in excess of required minimums in many cases. The U.S. five-year average consists of $460 million for 2008 and then approximately $300 million per year for the remaining four years. Our required minimum funding in 2008 is expected to be $110 million in the United States and $120 million outside the United States.

(e) Does not include unrecognized tax benefit of $999 million because the ultimate disposition and timing of any payments to be made with regard to such amounts is not reasonably estimable. Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity.

 

Capital Spending
Capital Expenditures and Investments

 

Our capital spending for the three-year period ending December 31, 2007, totaled $39.0 billion. During the three-year period, 67 percent of total spending went to our E&P segment. In addition to our capital expenditures and investments spending during 2007 and 2006, we also provided loans of approximately $700 million and $800 million, respectively, to certain related parties.

Our capital expenditures and investments budget for 2008 is $14.3 billion. Included in this amount is approximately $700 million in capitalized interest. We plan to direct 77 percent of the capital expenditures and investments budget to E&P and 20 percent to R&M. With the addition of loans to certain affiliated companies and principal contributions related to funding our portion of the EnCana transaction, our total capital program for 2008 is approximately $15.3 billion. See the “Capital Requirements” section, as well as Note 10 — Investments, Loans and Long-Term Receivables and Note 16 — Joint Venture Acquisition Obligation, in the Notes to Consolidated Financial Statements, for additional information.

 

E&P
Capital spending for E&P during the three-year period ending December 31, 2007, totaled $26.1 billion. The expenditures over this period supported key exploration and development projects including:

• Development drilling in the Greater Kuparuk Area, including West Sak; the Greater Prudhoe Bay Area; the Alpine field, including satellite field prospects; exploratory drilling; and the acquisition of acreage in Alaska.
• Oil and natural gas developments in the Lower 48 states, including New Mexico, Texas, Louisiana, Oklahoma, Montana, North Dakota and Colorado.
• The Magnolia development, Ursa and K-2 fields in the deepwater Gulf of Mexico.
• The acquisition of limited-term, fixed-volume overriding royalty interests in Utah and the San Juan Basin related to our natural gas production.
• Investment in the West2East Pipeline LLC (West2East), a company holding a 100 percent interest in Rockies Express Pipeline LLC (Rockies Express).
• Expansion of the Syncrude oil sands project, the development of the Surmont heavy-oil project, capital expenditures related to the EnCana upstream business venture, and development of conventional oil and gas reserves, all in Canada.
• Development of the Corocoro field offshore Venezuela (see Note 13 — Impairments, in the Notes to Consolidated Financial Statements, for additional information).
• The Ekofisk Area growth project and Alvheim project in the Norwegian North Sea.
• The Statfjord Late-Life project straddling the offshore boundary between Norway and the United Kingdom.
• The Britannia satellite and Clair developments in the U.K. North Sea and Atlantic Margin, respectively.
• An integrated project to produce and liquefy natural gas from Qatar’s North field.
• Investments in three fields in Algeria.
• Expenditures related to the terms under which we returned to our former oil and natural gas production operations in the Waha concessions in Libya and continued development of these concessions.
• Ongoing development of onshore oil and natural gas fields in Nigeria and ongoing exploration activities both onshore and on deepwater leases.
• The Kashagan field and satellite prospects in the Caspian Sea, offshore Kazakhstan.
• The acquisition of an interest in OOO Naryanmarneftegaz (NMNG), a joint venture with LUKOIL, and development of the Yuzhno Khylchuyu (YK) field.
• The Bayu-Undan gas recycle and liquefied natural gas development projects in the Timor Sea and northern Australia, respectively.
• The Belanak, Suban, Kerisi, Hiu and Belut projects in Indonesia.
• The Peng Lai 19-3 development in China’s Bohai Bay and additional Bohai Bay appraisal and adjacent field prospects.
• Expenditures to develop the Su Tu Vang field and continued in-field development of the Rang Dong field in Vietnam.

 

Capital expenditures for construction of our Endeavour Class tankers, as well as for an upgrade to the Trans-Alaska Pipeline System pump stations were also included in the E&P segment.

 

2008 Capital Expenditures and Investments Budget
E&P’s 2008 capital expenditures and investments budget is $11.1 billion, 11 percent higher than actual expenditures in 2007. Thirty-nine percent of E&P’s 2008 capital expenditures and investments budget is planned for the United States.

Capital spending for our Alaskan operations is expected to fund Prudhoe Bay, Greater Kuparuk and western North Slope operations, including the Alpine satellite fields, as well as exploration activities. In addition, we anticipate further development spending in our Cook Inlet Area. As a result of increased production taxes enacted by the state of Alaska in the fourth quarter of 2007, we anticipate our 2008 capital expenditures will be less than originally planned, mainly related to reduced project funding on the North Slope of Alaska.

In the Lower 48, capital expenditures will focus primarily on developing natural gas reserves within core areas, including the San Juan Basin of New Mexico and Colorado; the Lobo Trend of south Texas; the Bossier and Cotton Valley Trends of east Texas and north Louisiana; the Barnett Shale Trend of north Texas; the Anadarko Basin of western Oklahoma; and the Piceance Basin in northwest Colorado. We also plan to pursue oil development in the Williston Basin of Montana and North Dakota, as well as oil and gas developments in southern Louisiana and the Permian Basin of West Texas. Offshore capital will be focused mainly on the Ursa development in the Gulf of Mexico. In addition, investments will be made in West2East for Rockies Express.

E&P is directing $6.8 billion of its 2008 capital expenditures and investments budget to international projects. Funds in 2008 will be directed to developing major long-term projects, including the Kashagan project in the Caspian Sea and the YK field in northern Russia, through the NMNG joint venture with LUKOIL; the J-Block fields, the Britannia satellites and the Ekofisk Area in the North Sea; the Bohai Bay project in China; heavy-oil projects in Canada and western Canada natural gas projects; offshore Block B and onshore South Sumatra in Indonesia; fields offshore Malaysia and Vietnam; the Qatargas 3 LNG project in Qatar; and the Waha concessions in Libya.

 

Proved Undeveloped Reserves
The net addition of proved undeveloped reserves accounted for 77 percent, 37 percent and 44 percent of our total net additions in 2007, 2006 and 2005, respectively. During these years, we converted, on average, 16 percent per year of our proved undeveloped reserves to proved developed reserves. Of our 2,921 million total BOE proved undeveloped reserves at December 31, 2007, we estimated that the average annual conversion rate for these reserves for the three-year period ending 2010 will be approximately 18 percent.

Costs incurred for the years ended December 31, 2007, 2006 and 2005, relating to the development of proved undeveloped oil and gas reserves were $6.4 billion, $6.4 billion, and $3.4 billion, respectively. Estimated future development costs relating to the development of proved undeveloped reserves for the years 2008 through 2010 are projected to be $4.5 billion, $3.6 billion, and $2.6 billion, respectively.

Approximately 78 percent of our proved undeveloped reserves at year-end 2007 were associated with 10 major development areas and our investment in LUKOIL. Eight of the major development areas are currently producing and are expected to have proved reserves convert from undeveloped to developed over time as development activities continue and/or production facilities are expanded or upgraded, and include:

• The Ekofisk field in the North Sea.
• The Peng Lai 19-3 field in China.
• Fields in the United States and Canada.
• EnCana business venture projects — Christina Lake and Foster Creek.
• The Surmont heavy-oil project in Canada.

 

The remaining two major projects, Qatargas 3 in Qatar and the Kashagan field in Kazakhstan, will have undeveloped proved reserves convert to developed as these projects begin production.

 

Midstream
Capital spending for Midstream during the three-year period ending December 31, 2007, was primarily related to increasing our ownership interest in DCP Midstream in 2005 from 30.3 percent to 50 percent.

 

R&M
Capital spending for R&M during the three-year period ending December 31, 2007, was primarily for acquiring additional crude oil refining capacity, clean fuels projects to meet new environmental standards, refinery-upgrade projects to improve product yields, the operating integrity of key processing units, as well as for safety projects. In addition, in December 2007, we invested funds to acquire a 50 percent equity interest in the Keystone Oil Pipeline (Keystone), a joint venture to construct a crude oil pipeline from Hardisty, Alberta to U.S. Midwest markets in Illinois and Oklahoma. During this three-year period, R&M capital spending was $6.1 billion, representing 16 percent of our total capital expenditures and investments.

Key projects during the three-year period included:

• Acquisition of the Wilhelmshaven refinery in Germany.
• Debottlenecking of a crude and fluid catalytic cracking unit, and completion of a new sulfur plant at the Ferndale refinery.
• A new ultra-low-sulfur diesel hydrotreater at the Sweeny refinery.
• Revamp of an existing hydrotreater for ultra-low-sulfur diesel and a new hydrogen plant at the Wood River refinery.
• Expansion of existing hydrotreaters for both low-sulfur gasoline and ultra-low-sulfur diesel, with the addition of a new hydrogen plant at the Bayway refinery.
• A new hydrotreater for ultra-low-sulfur diesel and a hydrogen plant at the Ponca City refinery.
• Revamps of existing hydrotreaters for ultra-low-sulfur diesel at the Los Angeles, Trainer and Ferndale refineries.
• A new ultra-low-sulfur diesel hydrotreater and hydrogen plant at the Billings refinery.
• A fluid catalytic cracking gasoline hydrotreater at the Alliance refinery for production of low-sulfur gasoline.
• A sulfur removal technology unit at the Lake Charles refinery for the production of low-sulfur gasoline.
• A new ultra-low-sulfur diesel hydrotreater at the Rodeo facility of our San Francisco refinery.

 

Major construction activities in progress include:

• Expansion of a hydrocracker at the Rodeo facility of our San Francisco refinery.
• Construction of a low-sulfur gasoline project at the Billings refinery.
• U.S. programs aimed at air emission reductions.

 

Internationally, we continued to invest in our ongoing refining and marketing operations to upgrade and increase the profitability of our existing assets, including upgrading the distillate desulfurization capabilities at our Humber refinery in the United Kingdom.

 

2008 Capital Expenditures and Investments Budget
R&M’s 2008 capital budget is $2.8 billion, a 102 percent increase from actual spending in 2007. Domestic spending in 2008 is expected to comprise 74 percent of the R&M budget.

We plan to direct about $1.6 billion of the R&M capital budget to domestic refining, primarily for projects related to sustaining and improving the existing business with a focus on reliability, energy efficiency, capital maintenance and regulatory compliance. Work continues at a number of refineries on projects to increase crude oil capacity, expand conversion capability and increase clean product yield. Our North American transportation and marketing businesses are expected to spend about $800 million, including investments in the Keystone project.

Outside North America, we plan to spend about $400 million, with a focus on projects related to reliability, safety and the environment, as well as an upgrade project at the Wilhelmshaven, Germany, refinery and the advancement of a full-conversion refinery project in Yanbu, Saudi Arabia.

 

LUKOIL Investment
Capital spending in our LUKOIL Investment segment during the three-year period ending December 31, 2007, was for continued purchases of ordinary shares of LUKOIL to increase our ownership interest. However, no additional purchases were made in 2007, and none are expected in 2008.

 

Emerging Businesses
Capital spending for Emerging Businesses during the three-year period ending December 31, 2007, was primarily for an expansion of the Immingham combined heat and power cogeneration plant near the company’s Humber refinery in the United Kingdom. In addition, in October 2007, we purchased a 50 percent interest in Sweeny Cogeneration LP (SCLP). SCLP provides steam and electric power to the Sweeny refinery complex with any excess power sold into the market. We account for this joint venture using the equity method of accounting.

 

Contingencies
Legal and Tax Matters
We accrue for non-income-tax-related contingencies when a loss is probable and the amounts can be reasonably estimated. 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. In the case of income-tax-related contingencies, we adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (FIN 48), effective January 1, 2007. FIN 48 requires 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.

 

Environmental
We are subject to the same numerous international, federal, state, and local environmental laws and regulations, as are other companies in the petroleum exploration and production, refining, and crude oil and refined product marketing and transportation businesses. The most significant of these environmental laws and regulations include, among others, the:

• Federal Clean Air Act, which governs air emissions.
• Federal Clean Water Act, which governs discharges to water bodies.
• Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatened to occur.
• Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage, and disposal of solid waste.
• Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States.
• Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories with local emergency planning committees and responses departments.
• Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells.
• U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages.

 

These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.

Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.

The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States.

For example, the Energy Policy Act of 2005 imposed obligations to provide increasing volumes on a percentage basis of renewable fuels in transportation motor fuels through 2012. These obligations were changed with the enactment of the Energy Independence & Security Act of 2007, which was signed in late December. The new law requires fuel producers and importers to provide approximately 66 percent more renewable fuels in 2008 as compared with amounts set forth in the Energy Policy Act of 2005, with increases in amounts of renewable fuels required through 2022. We are in the process of establishing implementation, operating and capital strategies along with advanced technology development to meet these requirements.

Since 1997 when the Kyoto Protocol called for reductions of certain emissions that contribute to increases in atmospheric greenhouse gas concentrations, there have been a range of national, sub-national and international regulations proposed or implemented focusing on greenhouse gas reduction. These actual or proposed regulations do or will apply in countries where we have interests or may have interests in the future. Regulation in this field continues to evolve and while it is likely to be increasingly widespread and stringent, at this stage it is not possible to accurately estimate either a timetable for implementation or our future compliance costs. The overall long-term fiscal impact from this type of regulation is uncertain. Examples of legislation or precursors for possible regulation include:

• European Emissions Trading Scheme, the program through which many of the European Union member states are implementing the Kyoto Protocol.
• California’s Assembly Bill 32, which requires the California Air Resources Board (CARB) to develop regulations and market mechanisms that will ultimately reduce California’s greenhouse gas emissions by 25 percent by 2020.
• Two regulations issued by the Alberta government in 2007 under the Climate Change and Emissions Act. These regulations require any existing facility with emissions equal to or greater than 100,000 metric tons of carbon dioxide or equivalent per year to reduce the net emissions intensity of that facility by 2 percent per year beginning July 1, 2007, with an ultimate reduction target of 12 percent of baseline emissions.
• The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. ___, 127 S.Ct. 1438 (2007) confirming that the U.S. Environmental Protection Agency (EPA) has the authority to regulate carbon dioxide as an “air pollutant” under the federal Clean Air Act.
  

 

There is growing consensus that some form of regulation will be forthcoming at the federal level in the United States with respect to greenhouse gas emissions (including carbon dioxide) and such regulation could result in the creation of substantial additional costs in the form of taxes or required acquisition or trading of emission allowances. Additionally, with the continuing trend toward stricter standards, greater regulation and more extensive permitting requirements, our capital and operating environmental expenditures are likely to be substantial and may increase in the future. We may experience significant delays in obtaining all required environmental regulatory permits or other approvals that we need to operate or upgrade our existing facilities or construct new facilities. If there is a delay in obtaining any required environmental regulatory approvals or permits, the operation of our facilities may be interrupted or become subject to additional costs.

We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks located at numerous past and present ConocoPhillips-owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require contamination caused by such underground storage tank releases be assessed and remediated to meet applicable standards. In addition to other cleanup standards, many states adopted cleanup criteria for methyl tertiary-butyl ether (MTBE) for both soil and groundwater. Future environmental expenditures associated with the remediation of MTBE-contaminated underground storage tank sites could be substantial.

At RCRA permitted facilities, we are required to assess environmental conditions. If conditions warrant, we may be required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as “Superfund,” the cost of corrective action activities under RCRA corrective action programs typically is borne solely by us. Over the next decade, we anticipate that significant ongoing expenditures for RCRA remediation activities may be required, but such annual expenditures for the near term are not expected to vary significantly from the range of such expenditures we have experienced over the past few years. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.

We, from time to time, receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under 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, 2006, we reported we had been notified of potential liability under CERCLA and comparable state laws at 64 sites around the United States. At December 31, 2007, we had resolved five of these sites and had received nine new notices of potential liability, leaving 68 unresolved sites where we have been notified of potential liability.

For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. 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 site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.

Expensed environmental costs were $1,025 million in 2007 and are expected to be about $1.1 billion in 2008 and 2009. Capitalized environmental costs were $785 million in 2007 and are expected to be about $1.2 billion and $1.1 billion in 2008 and 2009, respectively.

We accrue for remediation activities when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. These accrued liabilities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).

Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA. Considerable uncertainty exists with respect to these costs, and under adverse changes in circumstances, potential liability may exceed amounts accrued as of December 31, 2007.

Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.

At December 31, 2007, our balance sheet included total accrued environmental costs of $1,089 million, compared with $1,062 million at December 31, 2006. We expect to incur a substantial majority 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 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 upon our results of operations or financial position as a result of compliance with environmental laws and regulations.

 

Other
We have deferred tax assets related to certain accrued liabilities, loss carryforwards and credit carryforwards. Valuation allowances have been established to reduce these deferred tax assets to an amount that will, more likely than not, be realized. Uncertainties that may affect the realization of these assets include tax law changes and the future level of product prices and costs. Based on our historical taxable income, our expectations for the future, and available tax-planning strategies, management expects that the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as reductions in future taxable income.

 

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