UNITED STATESSECURITIES AND EXCHANGE COMMISSION
FORM 10-Q
(Mark One)
For the Quarterly Period Ended June 30, 2004
or
Commission File No. 000-30176
Devon Energy Corporation
Registrant’s telephone number, including area code:(405) 235-3611
Former name, former address and former fiscal year, if changed from last report.Not applicable
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 þ Noo
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes þ Noo
The number of shares outstanding of Registrant’s common stock, par value $.10, as of June 30, 2004, was 241,744,000.
[This page intentionally left blank.]
2
DEVON ENERGY CORPORATIONIndex to Form 10-Q Quarterly Reportto the Securities and Exchange Commission
3
DEFINITIONS
As used in this document:
“ AECO” means the price of gas delivered onto the NOVA Gas Transmission Ltd. System.
“ Bbl” or “ Bbls” means barrel or barrels.
“ Bcf” means billion cubic feet.
“ Boe” means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.
“ Brent” means pricing point for selling North Sea crude oil.
“ Btu” means British Thermal units, a measure of heating value.
“ Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.
“ LIBOR” means London Interbank Offered Rate.
“ MBbls” means thousand barrels.
“ MMBbls” means million barrels.
“ MBoe” means thousand Boe.
“ MMBoe” means million Boe.
“ MMBtu” means million Btu.
“ Mcf” means thousand cubic feet.
“ MMcf” means million cubic feet.
“ NGL” or “ NGLs” means natural gas liquids.
“ NYMEX” means New York Mercantile Exchange.
“ Oil” includes crude oil and condensate.
“ Domestic” means the properties of Devon in the onshore continental United States and the offshore Gulf of Mexico.
“ Canada” means the division of Devon encompassing oil and gas properties located in Canada.
“ International” means the division of Devon encompassing oil and gas properties that lie outside the United States and Canada.
4
DEVON ENERGY CORPORATION
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2004 and 2003
(Forming a part of Form 10-Q Quarterly Reportto the Securities and Exchange Commission)
5
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
6
CONSOLIDATED STATEMENTS OF OPERATIONS
7
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
8
CONSOLIDATED STATEMENTS OF CASH FLOWS
9
1. Summary of Significant Accounting Policies
The accompanying consolidated financial statements and notes thereto of Devon Energy Corporation (“ Devon” ) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted. The accompanying consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes thereto included in Devon’s 2003 Annual Report on Form 10-K.
In the opinion of Devon’s management, all adjustments (all of which are normal and recurring) have been made which are necessary to fairly state the consolidated financial position of Devon and its subsidiaries as of June 30, 2004, and the results of their operations and their cash flows for the three-month and six-month periods ended June 30, 2004 and 2003.
2. Business Combinations and Pro Forma Information
Ocean Energy, Inc.
On April 25, 2003, Devon completed its merger with Ocean Energy Inc. (“ Ocean” ). In the transaction, Devon issued 0.414 shares of its common stock for each outstanding share of Ocean common stock (or a total of approximately 74 million shares). Also, Devon assumed approximately $1.8 billion of debt (current and long-term) from Ocean.
Devon acquired Ocean primarily for the significant production, development projects and exploration prospects in both the deepwater Gulf of Mexico and internationally, and the additional producing assets onshore United States and in the shallower shelf regions of the Gulf of Mexico.
10
DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Unaudited)
The calculation of the purchase price and the allocation to assets and liabilities as of April 25, 2003, are shown below.
Pro Forma Information
Set forth in the following table is certain unaudited pro forma financial information for the six-month period ended June 30, 2003. The information for the six-month period ended June 30, 2003, has been prepared assuming the Ocean merger was consummated on January 1, 2003. All pro forma information is based on estimates and assumptions deemed appropriate by Devon. The pro forma information is presented for illustrative purposes only. If the transaction had occurred in the past, Devon’s operating results might have been different from those presented in the following table. The pro forma information should not be relied upon as an indication of the operating results that Devon would have achieved if the transaction had occurred on January 1, 2003. The pro forma information also should not be used as an indication of the future results that Devon will achieve after the transaction.
11
12
3. Debt
New Credit Facility
In April 2004, Devon replaced its existing $1.0 billion of unsecured long-term credit facilities with a $1.5 billion five-year unsecured revolving credit facility (the “ Senior Credit Facility” ). The Senior Credit Facility includes (i) a five-year revolving Canadian subfacility in a maximum amount of U.S. $500 million and (ii) a $1 billion sublimit for the issuance of letters of credit, including letters of credit under the Canadian subfacility.
The Senior Credit Facility matures on April 8, 2009, and all amounts outstanding will be due and payable at that time unless the maturity is extended. Prior to each anniversary subsequent to April 8, 2004, Devon has the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders.
Amounts borrowed under the Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. Devon may also elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $1.9 million that is payable quarterly in arrears.
The agreement governing the Senior Credit Facility contains certain covenants and restrictions, including a maximum allowed debt-to-capitalization ratio of 65% as defined in the agreement.
As of June 30, 2004, there were no borrowings under the Senior Credit Facility. The available capacity under the Senior Credit Facility as of June 30, 2004, net of outstanding letters
13
of credit, was approximately $1.3 billion.
$3 Billion Term Loan Credit Facility
On April 9, 2004, Devon repaid the $635 million outstanding balance under its $3 billion term loan credit facility with cash on hand. As a result of the early repayment, Devon expensed the remaining $16 million of unamortized issuance costs, which is included in interest expense for the three-month and six-month periods ended June 30, 2004.
4. Derivative Instruments and Hedging Activities
Devon recorded in its consolidated statements of operations losses of $11 million and $1 million in the second quarter of 2004 and 2003, respectively, and a loss of $7 million and a gain of $9 million in the six-month periods ended June 30, 2004 and 2003, respectively, for the change in fair value of derivative instruments that do not qualify for hedge accounting treatment, as well as the ineffectiveness of derivatives that do qualify as hedges.
As of June 30, 2004, $364 million of net deferred losses on derivative instruments accumulated in “ accumulated other comprehensive income” are expected to be reclassified to earnings during the next 12 months assuming no change in forward commodity prices from the June 30, 2004 forward prices. Transactions and events expected to occur over the next 12 months that will necessitate reclassifying these derivatives’ losses to earnings are primarily the production and sale of oil and gas, which includes the production hedged under the various derivative instruments. Presently, the maximum term over which Devon has hedged exposures to the variability of cash flows for commodity price risk is 18 months.
During the second quarter of 2004, Devon entered into additional interest rate swaps. Following is a table summarizing all the fixed-to-floating interest rate swaps with the related debt instrument and notional amounts as of June 30, 2004.
14
5. Earnings Per Share
The following table reconciles the net earnings and common shares outstanding used in the calculations of basic and diluted earnings per share for the three-month and six-month periods ended June 30, 2004 and 2003.
15
Certain options to purchase shares of Devon’s common stock have been excluded from the dilution calculations because the options’ exercise price exceeded the average market price of Devon’s common stock during the applicable period. The following information relates to these options.
The excluded options for 2004 expire between April 25, 2005 and June 8, 2012.
16
Had Devon elected the fair value provisions of SFAS No. 123 and recognized compensation expense over the vesting period based on the fair value of the stock options granted as of their grant date, Devon’s pro forma net earnings and pro forma net earnings per share for the three-month and six-month periods ended June 30, 2004 and 2003 would have differed from the amounts actually reported as shown in the following table.
6. Supplemental Cash Flow Information
Cash payments for interest and income taxes in the first six months of 2004 and 2003 are presented below:
In January 2004, 38,000 shares of convertible preferred stock of Ocean, which became a subsidiary of Devon in the Ocean merger, were canceled and converted to 1,098,580 shares of Devon common stock pursuant to an automatic conversion feature of the preferred stock. The automatic conversion feature was triggered when the closing price of Devon common stock equaled or exceeded the forced conversion price of $52.39 for 20 consecutive trading days.
17
7. Retirement Plans
Devon has various non-contributory defined benefit pension plans, including qualified plans (“ Qualified Plans” ) and nonqualified plans (“ Supplemental Plans” ). The Qualified Plans provide retirement benefits for U.S. and Canadian employees meeting certain age and service requirements. The Supplemental Plans provide retirement benefits for certain employees whose benefits under the Qualified Plans are limited by income tax regulations. Devon also has defined benefit postretirement plans (“ Postretirement Plans” ) which provide benefits for substantially all employees. The Postretirement Plans provide medical and, in some cases, life insurance benefits and are, depending on the type of plan, either contributory or non-contributory.
Net Periodic Cost
The following table presents the plans’ net periodic benefit cost for the three-month and six-month periods ended June 30, 2004 and 2003.
In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“ the Act” ) was signed into law. The Act introduces a prescription drug benefit under Medicare (“ Medicare Part D” ) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. While the Act is expected to decrease Devon’s accumulated postretirement benefit obligation (“ APBO” ) for the Postretirement Plans, this decrease is not reflected in the net periodic benefit cost amounts above because Devon has not yet determined whether or not the benefits provided by its Postretirement Plans are actuarially equivalent to Medicare Part D under the Act. Devon will make this determination in the third quarter of 2004 and, at that time, will be required to estimate any effects the subsidy will have on the measurement of the APBO and net periodic benefit cost.
Employer Contributions
Devon previously disclosed in its financial statements for the year ended December 31, 2003, that it expected to contribute $52 million to the Qualified and Supplemental Plans and $8 million to the Postretirement Plans in 2004. These estimated contributions have not changed. As of June 30, 2004, $3 million of contributions have been made to the Qualified and Supplemental Plans and $4 million of contributions have been made to the Postretirement Plans.
18
8. Segment Information
Following is certain financial information regarding Devon’s reporting segments. The revenues reported are all from external customers.
19
20
21
22
9. Commitments and Contingencies
Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals although actual amounts could differ from management’s estimate.
Environmental Matters
Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act (“ CERCLA” ) and similar state statutes. In response to liabilities associated with these activities, accruals have been established when reasonable estimates are possible. Such accruals primarily include estimated costs associated with remediation. Devon has not used discounting in determining its accrued liabilities for environmental remediation, and no material claims for possible recovery from third party insurers or other parties related to environmental costs have been recognized in Devon’s consolidated financial statements. Devon adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates must be adjusted to reflect new information.
Certain of Devon’s subsidiaries acquired in past mergers are involved in matters in which it has been alleged that such subsidiaries are potentially responsible parties (“ PRPs” ) under CERCLA or similar state legislation with respect to various waste disposal areas owned or operated by third parties. As of June 30, 2004, Devon’s consolidated balance sheet included $6 million of non-current accrued liabilities, reflected in “ Other liabilities,” related to these and other environmental remediation liabilities. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the current accruals recognized for such environmental remediation activities. With respect to the sites in which Devon subsidiaries are PRPs, Devon’s conclusion is based in large part on (i) Devon’s participation in consent decrees with both other PRPs and the Environmental Protection Agency, which provide for performing the scope of work required for remediation and contain covenants not to sue as protection to the PRPs, (ii) participation in groups as a de minimis PRP, and (iii) the availability of other defenses to liability. As a result, Devon’s monetary exposure is not expected to be material.
Royalty Matters
Numerous gas producers and related parties, including Devon, have been named in various lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates which resulted in underpayment of royalties in connection with natural gas and natural gas liquids produced and sold from federal and Indian owned or controlled lands. The principal suit in which Devon is a defendant isUnited States ex rel. Wright v. Chevron USA, Inc. et al. (the “ Wrightcase” ). The suit was originally
23
filed in August 1996 in the United States District Court for the Eastern District of Texas, but was consolidated in October 2000 with the other suits for pre-trial proceedings in the United States District Court for the District of Wyoming. On July 10, 2003, the District of Wyoming remanded the Wright case back to the Eastern District of Texas to resume proceedings. Devon believes that it has acted reasonably, has legitimate and strong defenses to all allegations in the suit, and has paid royalties in good faith. Devon does not currently believe that it is subject to material exposure in association with this lawsuit and no liability has been recorded in connection therewith.
Devon is a defendant in certain private royalty owner litigation filed in Wyoming regarding deductibility of certain post production costs from royalties payable by Devon. The plaintiffs in these lawsuits propose to expand them into county or state-wide class actions relating specifically to transportation and related costs associated with Devon’s Wyoming gas production. A significant portion of such production is, or will be, transported through facilities owned by Thunder Creek Gas Services, L.L.C., of which Devon owns a 75% interest. Devon believes that it has acted reasonably and paid royalties in good faith and in accordance with its obligations under its oil and gas leases and applicable law, and Devon does not believe that it is subject to material exposure in association with this litigation.
Tax Treatment of Exchangeable Debentures
In its 1999 merger with PennzEnergy, Devon assumed from PennzEnergy certain debentures with a principal amount totaling $760 million. The debentures are exchangeable at the option of the holders into shares of ChevronTexaco common stock that were also acquired by Devon in the PennzEnergy merger.
The Internal Revenue Service has recently examined the 1998 income tax return of PennzEnergy’s predecessor, and the IRS formally notified Devon in April 2004 that it disagrees with certain tax treatments of the exchangeable debentures and similar exchangeable debentures retired in 1998. The IRS has asserted that 1998’s taxable income was understated by $323 million. This amount consists of the disallowance of a $276 million loss incurred on the retirement of the previous debentures and $47 million of interest deductions.
These adjustments to 1998’s taxable income would result in approximately $65 million of taxes due from Devon if such taxes were paid in 2004. The $65 million of taxes is net of certain tax benefits that are currently available to Devon. Without these benefits, which are likely to be utilized by Devon in the normal course of business during 2004, the additional taxes due on the 1998 taxable income adjustments would approximate $100 million.
Devon does not agree with the IRS positions and will vigorously contest the claim of additional taxes. In June 2004, Devon formally protested the IRS notice and requested a conference with the IRS Appeals Office. It will likely be several months before such a conference will be held. Although the outcome of this matter cannot be predicted with certainty, Devon, after consultation with legal counsel, believes that Devon will likely prevail, and no liability has been recorded for this matter. Even if the IRS were to prevail in this matter, Devon believes that any related increase in its 1998 taxable income would increase its tax basis in the ChevronTexaco common stock, or produce a similar tax benefit, and would therefore result in offsetting tax deductions in future taxable years upon the disposal of the ChevronTexaco
24
common stock. Therefore, while the payment of any such additional taxes would reduce Devon’s operating cash flow in the year of payment, it would not affect Devon’s net earnings for any period, and the operating cash flow effect would reverse in future years.
If the IRS were to ultimately prevail in this matter, any related interest owed by Devon would negatively impact Devon’s operating cash flow and net earnings. However, Devon does not believe that such impact would be material to Devon’s financial condition or results of operations.
At this time, the IRS has only challenged the deductions taken in 1998. It is possible that the IRS will also challenge the interest deductions taken in years subsequent to 1998. The IRS is currently examining Devon’s tax returns for the years 1999 through 2001.
Other Matters
Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon’s knowledge as of the date of this report, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.
10. Drilling Rights
In 2003, the Securities Exchange Commission (“ SEC” ) inquired of the Financial Accounting Standards Board (“ FASB” ) regarding the application of certain provisions of SFAS No. 141, Business Combinations, (“ SFAS No. 141” ) and SFAS No. 142, Goodwill and Other Intangible Assets, (“ SFAS No. 142” ) to oil and gas companies. SFAS Nos. 141 and 142 became effective for transactions subsequent to June 30, 2001. SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method and that acquired intangible assets be disaggregated and reported separately from goodwill. Specifically, the SEC’s inquiry is based on whether costs of contract-based drilling and mineral use rights (“ mineral rights” ) should be recorded and disclosed as intangible assets under the guidance in SFAS Nos. 141 and 142. The current practice for Devon and the industry is to present oil and gas related assets, including mineral rights, as property and equipment (tangible assets) on the balance sheet. Since June 30, 2001, Devon has entered into business combinations with Anderson, Mitchell, and Ocean with an aggregate accounting purchase price of $18.2 billion. The majority of the purchase price has been allocated to oil and gas property.
The FASB created an Emerging Issues Task Force Working Group (“ EITF” ) to research the accounting and disclosure treatment of mineral rights for oil and gas companies. As a result, the EITF added Issue No. 04-2, “ Whether Mineral Rights are Tangible or Intangible Assets,” (“ Issue 04-2” ) and Issue No. 03-S, “ Application of FASB Statement No. 142, Goodwill and Other Intangible Assets to Oil and Gas Companies” (“ Issue 03-S” ) to its inventory of open issues. At the March 17-18, 2004 EITF meeting, the EITF reached a consensus on Issue 04-2 that mineral rights, as defined in Issue 04-2, are tangible assets. To resolve the perceived inconsistency between characterization of mineral rights as tangible assets in this EITF consensus and the characterization of mineral rights as intangible assets in SFAS Nos. 141 and 142, the FASB has prepared an amendment that removes mineral rights for mining entities as examples of intangible assets in SFAS Nos. 141 and 142.
25
Issue 03-S was removed from the EITF agenda in anticipation that the FASB would issue proposed Staff Position (“ FSP” ) No. 142-B, “ Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Producing Entities” . This FSP indicates that SFAS No. 142 does not require oil and gas companies’ mineral rights to be classified as intangible assets. Devon agrees with this proposed FSP.
26
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion addresses material changes in results of operations for the three-month and six-month periods ended June 30, 2004, compared to the three-month and six-month periods ended June 30, 2003, and in financial condition since December 31, 2003. It is presumed that readers have read or have access to Devon’s 2003 Annual Report on Form 10-K which includes disclosures regarding critical accounting policies as part of Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Overview
Net earnings for the second quarter of 2004 were $502 million, or $2.02 per diluted share. This compares to net earnings of $356 million, or $1.62 per diluted share for the second quarter of 2003. Net earnings for the first half of 2004 were $996 million, or $4.02 per diluted share. This compares to net earnings of $792 million, or $4.11 per diluted share for the first half of 2003. The increases in second quarter and first half net earnings were due to increases in both production and prices of oil, natural gas and NGLs partially offset by increases in costs and expenses. The increases in production and expenses are primarily the result of the April 2003 Ocean merger.
Cash flow from operations increased from $1.8 billion in the first half of 2003 to $2.4 billion in the first half of 2004. Cash flow from operations and cash on hand were used to fund $1.7 billion of capital expenditures and retire $971 million in long-term debt during the first half of 2004. At June 30, 2004, Devon had $1.1 billion in cash and cash equivalents.
The 2004 debt retirements included scheduled maturities of $336 million and the April 2004 early repayment of the $635 million outstanding balance under Devon’s $3 billion term loan credit facility. In April 2004, Devon also replaced its $1 billion of unsecured long-term credit facilities with a $1.5 billion five-year unsecured revolving credit facility.
During the first half of 2004, Devon drilled 143 exploration wells, of which 87% were completed as successful, and 878 development wells, of which 97% were completed as successful.
A more complete overview and discussion of full year expectations can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Devon’s 2003 Annual Report on Form 10-K and in Devon’s Current Report on Form 8-K filed May 24, 2004.
27
Results of Operations
Total revenues increased $406 million, or 22%, in the second quarter of 2004, and $973 million, or 28%, in the first half of 2004 compared to the corresponding 2003 periods. These increases resulted from increases in both production and prices of oil, natural gas and NGLs. The increases in production were primarily the result of the April 2003 Ocean merger.
Oil, natural gas and NGL revenues were up $364 million, or 25%, for the second quarter of 2004 compared to the second quarter of 2003, and $948 million, or 35%, for the first half of 2004 compared to the first half of 2003. The three-month and six-month comparisons of production and price changes are shown in the following tables. (Note: Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.)
28
N/M Not meaningful.
29
The average sales prices per unit of production shown in the preceding tables include the effect of Devon’s hedging activities. Following is a comparison of Devon’s average sales prices with and without the effect of hedges for the three-month and six-month periods ended June 30, 2004 and 2003.
Oil Revenues. Oil revenues increased $160 million, or 42%, in the second quarter of 2004. An increase in production of 4 million barrels, or 29%, caused oil revenues to increase by $110 million. The April 2003 Ocean merger accounted for 3 million barrels of increased production. The remaining increase is primarily related to new production from China partially offset by natural declines and production problems in Devon’s domestic properties. Oil revenues increased $50 million due to a $2.62 per barrel increase in Devon’s realized average price of oil.
Oil revenues increased $485 million, or 77%, in the first half of 2004. An increase in production of 16 million barrels, or 67%, caused oil revenues to increase by $426 million. The April 2003 Ocean merger accounted for 14 million barrels of increased production. The remaining increase is primarily related to new production from China partially offset by natural declines and production problems in Devon’s domestic properties. Oil revenues increased $59 million due to a $1.47 per barrel increase in Devon’s realized average price of oil.
Gas Revenues. Gas revenues increased $174 million, or 17%, in the second quarter of 2004. An increase in production of 7 Bcf, or 4%, caused gas revenues to increase by $36 million. The April 2003 Ocean merger accounted for 6 Bcf of increased production. The remaining production increase was primarily related to new drilling and development in the Barnett Shale properties as well as new drilling and development in Canada partially offset by natural declines and production problems in Devon’s other domestic properties. Gas revenues increased $138 million due to a $0.62 per Mcf increase in Devon’s realized average price of gas.
Gas revenues increased $421 million, or 22%, in the first half of 2004. An increase in production of 49 Bcf, or 12%, caused gas revenues to increase by $233 million. The April 2003 Ocean merger accounted for 43 Bcf of increased production. The remaining production increase was primarily related to new drilling and development in the Barnett Shale properties as well as new drilling and development in Canada partially offset by natural declines and production problems in Devon’s other domestic properties. Gas revenues increased $188 million due to a $0.43 per Mcf increase in Devon’s realized average price of gas.
30
NGL Revenues. NGL revenues increased $30 million, or 33%, in the second quarter of 2004. An increase in production of 1 million barrels, or 13%, caused NGL revenues to increase by $12 million. The April 2003 Ocean merger accounted for 0.2 million barrels of the increased production. The remaining production increase was primarily related to new drilling and development in the Barnett Shale and other domestic properties. A $3.01 per barrel increase in Devon’s realized average NGL price in the second quarter of 2004 increased NGL revenues by $18 million.
NGL revenues increased $42 million, or 21%, in the first half of 2004. An increase in production of 2 million barrels, or 16%, caused NGL revenues to increase by $33 million. The April 2003 Ocean merger accounted for 0.6 million barrels of the increased production. The remaining production increase was primarily related to new drilling and development in the Barnett Shale and other domestic properties. A $0.82 per barrel increase in Devon’s realized average NGL price in the first half of 2004 increased NGL revenues by $9 million.
Marketing and Midstream Revenues. Marketing and midstream revenues increased $42 million, or 12%, in the second quarter of 2004. Revenues increased $61 million due to higher overall market prices for natural gas and NGLs. This was partially offset by lower third-party natural gas volumes. This decrease was primarily related to the sale of certain assets in March 2004.
Marketing and midstream revenues increased $25 million, or 3%, in the first half of 2004. Revenues increased $56 million due to higher overall market prices for natural gas and NGLs. This was partially offset by lower third-party natural gas volumes primarily due to the sale of certain assets in March 2004.
Oil, Gas and NGL Production and Operating Expenses. The components of oil, gas and NGL production and operating expenses are set forth in the following tables.
31
Lease operating expenses increased $29 million in the second quarter of 2004. The April 2003 Ocean merger accounted for $13 million of the increase. The historical Devon lease operating expenses increased $10 million primarily due to increases in ad valorem and well workover expenses and increased power, fuel, casualty insurance and repairs and maintenance costs. Also, operating costs related to new production in China caused an increase of $4 million. Additionally, changes in the Canadian-to-U.S. dollar exchange rate, from second quarter 2003 to second quarter 2004, resulted in a $2 million increase in costs.
Lease operating expenses increased $121 million in the first half of 2004. The April 2003 Ocean merger accounted for $72 million of the increase. The historical Devon lease operating expenses increased $28 million primarily due to increases in ad valorem and well workover expenses and increased power, fuel, casualty insurance and repairs and maintenance costs. Also, operating costs related to new production in China caused an increase of $8 million. Additionally, changes in the Canadian-to-U.S. dollar exchange rate, from the first half of 2003 to the first half of 2004, resulted in a $13 million increase in costs.
The increase in lease operating expenses per Boe for the second quarter of 2004 and the first half of 2004 is primarily related to changes in the Canadian-to-U.S. dollar exchange rate as well as increased power, fuel and repairs and maintenance costs. With the continuing strength of commodity prices, more repairs and maintenance costs are performed to either maintain or improve production volumes. The higher prices also resulted in increased power and fuel costs.
Transportation costs increased $3 million in the second quarter of 2004. The April 2003 Ocean merger accounted for $2 million of the increase. The remainder of the increase was due primarily to an increase in gas production and changes in the Canadian-to-U.S. dollar exchange rate which resulted in a $0.4 million increase in costs.
Transportation costs increased $15 million in the first half of 2004. The April 2003 Ocean merger accounted for $12 million of the increase. The remainder of the increase was due primarily to an increase in gas production and changes in the Canadian-to-U.S. dollar exchange rate which resulted in a $2 million increase in costs.
Production taxes increased $20 million in second quarter of 2004 and $35 million in the first half of 2004. The majority of Devon’s production taxes are assessed on its onshore domestic properties. In the U.S., most of the production taxes are based on a fixed percentage of revenues. Therefore, the 18% and 29% increases in domestic oil, gas and NGL revenues in the second quarter of 2004 and the first half of 2004, respectively, were the primary cause of the production tax increases. Also included are production taxes related to new production in China of $3 million and $5 million in the second quarter and first half of 2004, respectively.
Marketing and Midstream Operating Costs and Expenses. Marketing and midstream operating costs and expenses increased $22 million, or 8%, in the second quarter of 2004. Costs and expenses increased $39 million due to an increase in overall prices paid for natural gas. This was partially offset by a decrease in third-party natural gas volumes. This decrease was primarily the result of the sale of certain assets in March 2004.
Marketing and midstream operating costs and expenses decreased $3 million, or 1%, in the first half of 2004. Costs and expenses increased $28 million due to an overall increase in
32
prices paid for natural gas. This was more than offset by a decrease in third-party natural gas volumes. The sale of certain assets in March 2004 contributed to the lower third party volumes.
Depreciation, Depletion and Amortization Expenses (“DD&A”). Oil and gas property related DD&A increased $121 million, or 31%, from $395 million in the second quarter of 2003 to $516 million in the second quarter of 2004. Oil and gas property related DD&A expense increased $44 million due to the 11% increase in combined oil, gas and NGLs production in 2004. Additionally, an increase in the combined U.S., Canadian and international DD&A rate from $7.06 per Boe in 2003 to $8.29 per Boe in 2004 caused oil and gas property related DD&A to increase by $77 million. The increase in the DD&A rate is primarily related to the April 2003 Ocean merger, higher finding and development costs and changes in the Canadian-to-U.S. dollar exchange rate.
Oil and gas property related DD&A increased $391 million, or 59%, from $663 million in the first half of 2003 to $1.1 billion in the first half of 2004. Oil and gas property related DD&A expense increased $172 million due to the 26% increase in combined oil, gas and NGLs production in 2004. Additionally, an increase in the combined U.S., Canadian and international DD&A rate from $6.62 per Boe in 2003 to $8.35 per Boe in 2004 caused oil and gas property related DD&A to increase by $219 million. The increase in the DD&A rate is primarily related to the April 2003 Ocean merger, higher finding and development costs and changes in the Canadian-to-U.S. dollar exchange rate.
General and Administrative Expenses (“G&A”). Devon’s net G&A consists of three primary components. The largest of these components is the gross amount of expenses incurred for personnel costs, office expenses, professional fees and other G&A items. The gross amount of these expenses is partially reduced by two offsetting components. One is the amount of G&A capitalized pursuant to the full-cost method of accounting. The other is the amount of G&A reimbursed by working interest owners of properties for which Devon serves as the operator. These reimbursements are received during both the drilling and operational stages of a property’s life. The gross amount of G&A incurred, less the amounts capitalized and reimbursed, is recorded as net G&A in the consolidated statements of operations. The following table is a summary of G&A expenses by component for the second quarter and first half of 2004 and 2003.
Gross G&A decreased $16 million in the second quarter of 2004 compared to the 2003 quarter. Synergies obtained from the April 2003 Ocean merger reduced gross G&A $12 million. This reduction was partially offset by the inclusion of one more month of Ocean activities in the 2004 quarter compared to the 2003 quarter. Also, the 2003 quarter included $8 million related to costs incurred in the closing of Devon’s office in The Woodlands, Texas. These decreases were partially offset by a $5 million charge recorded in the second quarter of 2004 related to the
33
abandonment of certain Canadian office space. Also, changes in the Canadian-to-U.S. dollar exchange rate, from the second quarter 2003 to second quarter 2004, resulted in a $1 million increase in costs.
Gross G&A increased $41 million in the first half of 2004 compared to the first half of 2003. The April 2003 Ocean merger increased gross expenses $27 million primarily due to the inclusion of an additional four months of Ocean activities in the first half of 2004 compared to the first half of 2003. This was partially offset by the synergies obtained from the merger. Also, higher compensation and benefit costs and the abandonment of certain Canadian office space increased gross G&A $8 million and $5 million, respectively in the first half of 2004. Finally, changes in the Canadian-to-U.S. dollar exchange rate, from the first half of 2003 to the first half of 2004, resulted in a $4 million increase in costs. These increases were partially offset by $8 million related to costs incurred in the closing of Devon’s office in The Woodlands, Texas during the first half of 2003.
The increases in both capitalized G&A and reimbursed G&A in the second quarter and first half of 2004 as compared to the same periods of 2003 were primarily related to the increased activity subsequent to the April 2003 Ocean merger.
Interest Expense. The following schedule includes the components of interest expense for the second quarter and first half of 2004 and 2003.
The average debt balance decreased from $9.1 billion in the second quarter of 2003 to $8.4 billion in the 2004 quarter, causing interest expense to decrease $11 million. The decrease in the average debt balance was due to debt repayments in both the second half of 2003 and in the first half of 2004 partially offset by debt assumed in the April 2003 Ocean merger. The average interest rate on outstanding debt increased from 6.0% in the second quarter of 2003 to 6.1% in the second quarter of 2004, causing interest expense to increase $2 million.
Other items included in interest expense that are not related to the debt balance outstanding were $13 million higher in the second quarter of 2004. Of this increase, $16 million related to the early repayment of the outstanding balance under the $3 billion term loan credit facility in which Devon expensed the remaining unamortized issuance costs in the second quarter of 2004. This increase was offset by an additional $5 million related to the capitalization of interest. The increase in interest capitalized was primarily related to additional unproved properties acquired in the Ocean merger and the nature of those properties. The Ocean properties
34
included significant deepwater Gulf and international exploratory properties and major development projects.
The average debt balance increased from $8.5 billion in the first half of 2003 to $8.8 billion in the first half of 2004, causing interest expense to increase $7 million. The increase in the average debt balance was due to debt assumed in the April 2003 Ocean merger partially offset by debt repayments in both the second half of 2003 and in the first half of 2004. The average interest rate on outstanding debt decreased from 6.1% during the first half of 2003 to 6.0% for the first half of 2004, causing interest expense to decrease $7 million.
Other items included in interest expense that are not related to the debt balance outstanding were $8 million lower in the first half of 2004 as compared to the first half of 2003. Of this decrease, $21 million related to the capitalization of interest. The increase in interest capitalized was primarily related to the additional unproved properties acquired in the Ocean merger. Partially offsetting this amount was $16 million related to the early repayment of the outstanding balance under the $3 billion term loan credit facility, in which Devon expensed the remaining unamortized issuance costs in the second quarter of 2004.
Effects of Changes in Foreign Currency Exchange Rates. Devon’s Canadian subsidiary has certain fixed-rate senior notes which are denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the Canadian dollar while the notes are outstanding increase or decrease the expected amount of Canadian dollars eventually required to repay the notes. In addition, Devon’s Canadian subsidiary has cash and other working capital amounts denominated in U.S. dollars which also fluctuate in value with changes in the exchange rate. Such changes in the Canadian dollar equivalent balance of the debt and working capital balances are required to be included in determining net earnings for the period in which the exchange rate changes. The decreases in the Canadian-to-U.S. dollar exchange rate from $0.7738 at December 31, 2003 and $0.7631 at March 31, 2004 to $0.7460 at June 30, 2004 resulted in a $9 million loss and a $15 million loss in the second quarter and the first half of 2004, respectively. The increases in the Canadian-to-U.S. dollar exchange rate from $0.6331 at December 31, 2002 and $0.6806 at March 31, 2003 to $0.7378 at June 30, 2003 resulted in a $28 million gain and $50 million gain in the second quarter and first half of 2003, respectively.
Income Taxes. During interim periods, income tax expense is based on the estimated effective income tax rate that is expected for the entire fiscal year. The estimated effective tax rate in the second quarter of 2004 was 35% compared to 39% in the second quarter of 2003. The estimated effective tax rate was 36% in the first half of 2004 and the first half of 2003.
The second quarter 2003 rate was higher than the statutory federal tax rate primarily due to the effect of state and foreign income taxes. The second quarter 2004 rate is equal to the statutory federal tax rate and lower than the 2003 rate primarily due to reductions in the statutory Canadian tax rate enacted in the second quarter of 2004 and the fourth quarter of 2003. This benefit was partially offset by the effect of state and foreign income taxes.
Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (“SFAS No. 109”), allows the tax benefit of available tax carryforwards be recorded as an asset to the extent that management assesses the utilization of such carryforwards to be “more likely
35
than not”. Otherwise, SFAS No. 109 requires that a valuation allowance be provided to reduce the recorded tax benefits from such assets.
Included as deferred tax assets at June 30, 2004, were the tax effects of approximately $1.4 billion of tax related carryforwards. The carryforwards include federal net operating loss carryforwards, the majority of which do not begin to expire until 2014, state net operating loss carryforwards which expire primarily between 2004 and 2022, Canadian carryforwards which expire primarily between 2005 and 2009, Azerbaijani carryforwards which have no expiration and minimum tax credit carryforwards which have no expiration.
Devon expects the tax benefits from the net operating loss carryforwards to be utilized between 2004 and 2009. Such expectation is based upon current estimates of taxable income during this period, considering limitations on the annual utilization of these benefits as set forth by tax regulations. Significant changes in such estimates caused by variables such as future oil and gas prices or capital expenditures could alter the timing of the eventual utilization of such carryforwards. There can be no assurance that Devon will generate any specific level of continuing taxable earnings. However, management believes that Devon’s future taxable income will more likely than not be sufficient to utilize substantially all its tax carryforwards prior to their expirations.
Cumulative Effect of Change in Accounting Principle. Effective January 1, 2003, Devon adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, and recorded a cumulative-effect-type adjustment for an increase to net earnings of $16 million net of deferred taxes of $10 million.
Capital Expenditures, Capital Resources and Liquidity
The following discussion of capital expenditures, capital resources and liquidity should be read in conjunction with the consolidated statements of cash flows included in Part 1, Item 1.
Capital Expenditures. On an accrual basis, capital expenditures were $1.4 billion for the first six months of 2004. Of this amount, $1.3 billion was for the acquisition, drilling or development of oil and gas properties.
On a cash basis, capital expenditures, which are reflected in Devon’s statements of cash flow, were $1.7 billion and $1.1 billion for the first six months of 2004 and 2003, respectively. These totals include $1.6 billion and $977 million for the acquisition, drilling or development of oil and gas properties in the first six months of 2004 and 2003, respectively.
Capital Resources and Liquidity. Devon’s primary source of liquidity has historically been net cash provided by operating activities (“operating cash flow”). This source has been supplemented as needed by accessing credit lines and commercial paper markets and issuing equity securities and long-term debt securities.
36
Operating Cash Flow
Net cash provided by operating activities (“operating cash flow”) continued to be a primary source of capital and liquidity in the first half of 2004. Operating cash flow in the first half of 2004 was $2.4 billion, compared to $1.8 billion in the first half of 2003. The increase in operating cash flow in the first half of 2004 was primarily caused by the increase in revenues, partially offset by increased expenses, as discussed earlier in this section.
Devon’s operating cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, natural gas and NGLs produced. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic conditions, weather and other substantially variable factors influence market conditions for these products. These factors are beyond Devon’s control and are difficult to predict.
To mitigate some of the risk inherent in oil and natural gas prices, Devon has utilized price collars to set minimum and maximum prices on a portion of its production. Additionally, Devon has entered into various financial price swap contracts and fixed-price physical delivery contracts to fix the price to be received for a portion of future oil and natural gas production. The table below provides the volumes associated with these various arrangements as of June 30, 2004. The price and volume terms of these arrangements have not changed from those disclosed in Devon’s 2003 Annual Report on Form 10-K.
In addition to the above quantities, Devon also has fixed-price physical delivery contracts for the years 2006 through 2011, covering Canadian natural gas production ranging from 8 Bcf to 14 Bcf per year. Thereafter, Devon also has Canadian gas volumes subject to fixed-price contracts in the years from 2012 through 2016, but the yearly volumes are less than 1 Bcf.
By removing the price volatility from a portion of its oil and natural gas production, Devon has mitigated, but not eliminated, the potential effects of changing prices on its operating cash flow.
It is Devon’s policy to enter only into derivative contracts with investment grade rated counterparties deemed by management as competent and competitive market makers. Devon does not hold or issue derivative instruments for speculative trading purposes.
37
Credit Lines
Another source of liquidity is Devon’s new revolving line of credit (the “Senior Credit Facility”). The Senior Credit Facility includes (i) a five-year revolving Canadian subfacility in a maximum amount of U.S. $500 million and (ii) a $1 billion sublimit for the issuance of letters of credit, including letters of credit under the Canadian subfacility.
The Senior Credit Facility matures on April 8, 2009, and all amounts outstanding will be due and payable at that time unless the maturity is extended. Prior to each anniversary subsequent to April 8, 2004, Devon has the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders
As of June 30, 2004, there were no borrowings under the Senior Credit Facility. The available capacity under the Senior Credit Facility as of June 30, 2004, net of outstanding letters of credit, was approximately $1.3 billion.
The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon to maintain a ratio of total funded debt to total capitalization of no more than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in Devon’s consolidated financial statements. Per the agreement, total funded debt excludes the debentures that are exchangeable into shares of ChevronTexaco Corporation common stock. Also, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling property impairments or goodwill impairments. As of June 30, 2004, Devon was in compliance with this covenant.
Devon’s access to funds from its Senior Credit Facility is not restricted under any “material adverse condition” clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments, or the enforceability of material terms of the credit agreement. While Devon’s Senior Credit Facility includes covenants that require Devon to report a condition or event having a material adverse effect on Devon, the obligation of the banks to fund the Senior Credit Facility is not conditioned on the absence of a material adverse effect.
Devon also has access to short-term credit under its commercial paper program. Total borrowings under the commercial paper program may not exceed $725 million. Also, any borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility on a dollar-for-dollar basis. Commercial paper debt generally has a maturity of between seven to 90 days, although it can have a maturity of up to 365 days. Devon had no commercial paper debt outstanding at June 30, 2004.
38
Financing Cash Flow
Net cash used in financing activities in the first half of 2004 was $836 million compared to $313 million in the first half of 2003. The increase in cash used in financing activities from the first half of 2003 to the first half of 2004 was directly related to the increased debt repayments and common stock dividends, partially offset by an increase in proceeds from the issuance of common stock.
During the first half of 2004, Devon paid $971 million to retire the $211 million 6.75% notes due February 15, 2004 and the $125 million 8.05% notes due June 15, 2004 and to repay the remaining $635 million outstanding on the $3 billion term loan credit facility. During the first half of 2003, Devon repaid $380 million in debt.
Devon’s common stock dividends were $48 million and $16 million in the first half of 2004 and 2003, respectively. Devon also paid $5 million of preferred stock dividends in each of the first halves of 2004 and 2003.
The increase in common stock dividends was primarily related to the 100% increase in the quarterly dividend rate and the increased number of shares outstanding. Effective with the first quarter 2004 dividend payment, Devon increased its quarterly dividend rate from $0.05 per share to $0.10 per share. The increase in shares outstanding was primarily related to the April 2003 Ocean merger.
Devon received $188 million from shares issued for options exercised during the first half of 2004 compared to $38 million received during the first half of 2003.
Impact of Recently Issued Medicare Act Not Yet Adopted
In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Act”) was signed into law. The Act introduces a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. While the Act is expected to decrease Devon’s accumulated postretirement benefit obligation (“APBO”) for the Postretirement Plans, this decrease is not reflected in the net periodic benefit cost amounts above because Devon has not yet determined whether or not the benefits provided by its Postretirement Plans are actuarially equivalent to Medicare Part D under the Act. Devon will make this determination in the third quarter of 2004 and, at that time, will be required to estimate any effects the subsidy will have on the measurement of the APBO and net periodic benefit cost.
Drilling Rights
In 2003, the Securities Exchange Commission (“SEC”) inquired of the Financial Accounting Standards Board (“FASB”) regarding the application of certain provisions of SFAS No. 141, Business Combinations, (“SFAS No. 141”) and SFAS No. 142, Goodwill and Other Intangible Assets, (“SFAS No. 142”) to oil and gas companies. SFAS Nos. 141 and 142 became effective for transactions subsequent to June 30, 2001. SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method and that acquired intangible assets be disaggregated and reported separately from goodwill. Specifically,
39
the SEC’s inquiry is based on whether costs of contract-based drilling and mineral use rights (“mineral rights”) should be recorded and disclosed as intangible assets under the guidance in SFAS Nos. 141 and 142. The current practice for Devon and the industry is to present oil and gas related assets, including mineral rights, as property and equipment (tangible assets) on the balance sheet. Since June 30, 2001, Devon has entered into business combinations with Anderson, Mitchell, and Ocean with an aggregate accounting purchase price of $18.2 billion. The majority of the purchase price has been allocated to oil and gas property.
The FASB created an Emerging Issues Task Force Working Group (“EITF”) to research the accounting and disclosure treatment of mineral rights for oil and gas companies. As a result, the EITF added Issue No. 04-2, “Whether Mineral Rights are Tangible or Intangible Assets,” (“Issue 04-2”) and Issue No. 03-S, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets to Oil and Gas Companies” (“Issue 03-S”) to its inventory of open issues. At the March 17-18, 2004 EITF meeting, the EITF reached a consensus on Issue 04-2 that mineral rights, as defined in Issue 04-2, are tangible assets. To resolve the perceived inconsistency between characterization of mineral rights as tangible assets in this EITF consensus and the characterization of mineral rights as intangible assets in SFAS Nos. 141 and 142, the FASB has prepared an amendment that removes mineral rights for mining entities as examples of intangible assets in SFAS Nos. 141 and 142.
Issue 03-S was removed from the EITF agenda in anticipation that the FASB would issue proposed Staff Position (“FSP”) No. 142-B, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Producing Entities”. This FSP indicates that SFAS No. 142 does not require oil and gas companies’ mineral rights to be classified as intangible assets. Devon agrees with this proposed FSP.
SEC Inquiry Relating to Equatorial Guinea
On August 6, 2004, the United States Securities and Exchange Commission (“SEC”) notified Devon that it was conducting an inquiry into payments made to the government of Equatorial Guinea, or to officials and persons affiliated with officials of the government of Equatorial Guinea. This inquiry follows an investigation and public hearing conducted by the United States Senate Permanent Subcommittee on Investigations, which reviewed the transactions of various foreign governments, including that of Equatorial Guinea, with Riggs Bank. The investigation and hearing also reviewed the operations of those U.S. oil companies having interests in Equatorial Guinea, including Devon. Devon is cooperating with the SEC inquiry.
40
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The information included in “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of Devon’s 2003 Annual Report on Form 10-K is incorporated herein by reference. Such information includes a description of Devon’s potential exposure to market risks, including commodity price risk, interest rate risk and foreign currency risk. As of June 30, 2004, there have been no material changes in Devon’s market risk exposure except as discussed below regarding interest rate risk.
Interest Rate Risk
Devon uses a sensitivity analysis technique to evaluate the hypothetical effect that changes in interest rates may have on the fair value of its interest rate swap instruments. At June 30, 2004, a 10% increase in the underlying interest rates would have decreased the fair value of Devon’s interest rate swaps by $29 million.
Item 4. Controls and Procedures
Disclosure Controls and Procedures
We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our principal executive and financial officers have evaluated our disclosure controls and procedures and have determined that such disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q.
41
Part II. Other Information
Item 1. Legal Proceedings
None
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchase of Equity Securities
Item 3. Defaults Upon Senior Securities
Item 4. Submission of Matters to a Vote of Security Holders
(a) Devon’s Annual Meeting of Stockholders was held in Oklahoma City, Oklahoma at 8:00 a.m., local time, on Tuesday, June 8, 2004.
(b) Proxies for the meeting were solicited pursuant to Regulation 14 under the Securities Exchange Act of 1934, as amended. There was no solicitation in opposition to the nominees for election as Directors as listed in the Proxy Statement for the June 8, 2004 meeting and all nominees were elected.
(c) A total of 211,864,565 shares of Devon’s common stock outstanding and entitled to vote were present at the June 8, 2004 meeting in person or by proxy, representing approximately 88.7% of the total outstanding shares. The matters voted upon were as follows:
1. The election of four Directors to serve on Devon’s Board of Directors until the 2007 Annual Meeting of Stockholders. The vote tabulation with respect to each nominee was as follows:
42
2. Ratification of KPMG LLP as the Company’s Independent Auditors for 2004. The results of the votes were as follows:
3. Stockholder Proposal for a Director Election Vote Threshold. The results of the votes were as follows:
Item 5. Other Information
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits required by Item 601 of Regulation S-K are as follows:
43
(b) Reports on Form 8-K
A Report on Form 8-K was furnished pursuant to Item 12 on May 7, 2004 to announce Devon’s first quarter 2004 results.
A report on Form 8-K was filed pursuant to Item 5 on May 12, 2004 to disclose that Devon had provided a revocable parental guaranty to holders of certain debt securities of its subsidiary, Devon Canada Corporation.
A report on Form 8-K was filed pursuant to Item 5 on May 24, 2004 to update Devon’s 2004 forward-looking estimates.
44
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
45
INDEX TO EXHIBITS
46