ITEM 1. BUSINESS
GENERAL
Devon Energy Corporation, including its subsidiaries, ("Devon" or the "Company") is an independent energy company engaged primarily in oil and gas exploration, development and production, and in the acquisition of producing properties. Through its predecessors, Devon began operations in 1971 as a privately-held company. In 1988 the Company's common stock began trading publicly on the American Stock Exchange under the symbol DVN. In addition, commencing on December 15, 1998, a new class of Devon exchangeable shares began trading on The Toronto Stock Exchange under the symbol NSX. These shares are essentially equivalent to Devon common stock. However, because they are issued by Devon's wholly-owned subsidiary, Northstar Energy Corporation ("Northstar"), they qualify as a domestic Canadian investment for Canadian institutional shareholders. They are exchangeable at any time, on a one-for-one basis, for common shares of Devon.
The principal and administrative offices of Devon are located at 20 North Broadway, Suite 1500, Oklahoma City, OK 73102-8260 (telephone 405/235-3611).
Devon currently owns oil and gas properties concentrated in four operating divisions: the Northern Division, which encompasses properties in the Permian Basin, Rocky Mountains and Mid-Continent; the Southern Division, which encompasses properties in south Texas, the Gulf Coast area and offshore Gulf of Mexico; Canada, which includes properties in the Western Canadian Sedimentary Basin in Alberta and British Columbia; and the International Division, which includes properties in Azerbaijan, Egypt, Qatar, Brazil, Australia and Venezuela. (A detailed description of the significant properties can be found under "Item 2.
ITEM 2. PROPERTIES
Substantially all of Devon's properties consist of interests in developed and undeveloped oil and gas leases and mineral acreage located in the Company's core operating areas. These interests entitle Devon to drill for and produce oil, natural gas and NGLs from specific areas. Devon's interests are mostly in the form of working interests and volumetric production payments, and, to a lesser extent, overriding royalty, foreign government concessions, mineral and net profits interests and other forms of direct and indirect ownership in oil and gas properties.
PROVED RESERVES AND ESTIMATED FUTURE NET REVENUE
"Proved reserves" are those quantities of oil, natural gas and NGLs, which geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are strictly technical judgments and are not knowingly influenced by attitudes of conservatism or optimism. The following table sets forth Devon's estimated proved reserves, the estimated future net revenues therefrom and the 10% Present Value thereof as of December 31, 1999. Approximately 97% of Devon's U.S. proved reserves were estimated by LaRoche Petroleum Consultants, Ltd. and Ryder-Scott Company Petroleum Consultants, independent petroleum consultants. Devon's internal staff of engineers estimated the remainder of the U.S. reserves. All of the year-end 1999 Canadian proved reserves were calculated by the independent petroleum consultants Paddock Lindstrom & Associates Ltd. The international proved reserves, other than Canada as of December 31, 1999, were calculated by the independent petroleum consultants of Ryder-Scott Company Petroleum Consultants. All reserve estimates were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines (as described in the following notes). These estimates correspond with the method used in presenting the `Supplemental Information on Oil and Gas Operations" in Note 16 to Devon's Consolidated Financial Statements included herein, except that federal income taxes attributable to such future net revenues have been disregarded in the presentation below.
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(1) Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods.
(2) Proved undeveloped reserves are proved reserves to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompleting or deepening a well or for new fluid injection facilities.
(3) Gas reserves are converted to MBoe at the rate of six MMcf per MBbl of oil, based upon the approximate relative energy content of natural gas to oil, which rate is not necessarily indicative of the relationship of gas to oil prices. The respective prices of gas and oil are affected by market conditions and other factors in addition to relative energy content.
(4) Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and development costs. The amounts shown do not give effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization.
These amounts were calculated using prices and costs in effect as of December 31, 1999. These prices were not changed except where different prices were fixed and determinable from applicable contracts. These assumptions yield average prices over the life of Devon's properties of $21.96 per Bbl of oil, $1.87 per Mcf of natural gas and $15.74 per Bbl of NGLs. These prices compare to December 31, 1999, benchmark posted prices of $22.75 per Bbl for West Texas Intermediate crude oil and a composite of $2.03 per MMBtu for Texas Gulf Coast spot gas for gas delivered to various Texas Gulf Coast pipelines.
No estimates of Devon's proved reserves have been filed with or included in reports to any federal or foreign governmental authority or agency since the beginning of the last fiscal year except (i) in filings with the SEC and (ii) in filings with the Department of Energy ("DOE"). Reserve estimates filed by Devon with the SEC correspond with the estimates of Devon reserves contained herein. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of Devon's reserves included herein. However, the DOE requires reports to include the interests of all owners in wells that Devon operates and to exclude all interests in wells that Devon does not operate.
The prices used in calculating the estimated future net revenues attributable to proved reserves do not necessarily reflect market prices for oil, gas and NGL production subsequent to December 31, 1999. There can be no assurance that all of the proved reserves will be produced and sold within the periods indicated, that the assumed prices will be realized or that existing contracts will be honored or judicially enforced.
The process of estimating oil, gas and NGLs reserves is complex, requiring significant subjective decisions in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may change substantially over time as a result of, among other things, additional development activity, production history and viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur in the future.
PRODUCTION, REVENUE AND PRICE HISTORY
Certain information concerning oil and natural gas production, prices, revenues (net of all royalties, overriding royalties and other third party interests) and operating expenses for the three years ended December 31, 1999, is set forth in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
WELL STATISTICS
The following table sets forth Devon's producing wells as of December 31, 1999:
(1) Gross wells are the total number of wells in which Devon owns a working interest.
(2) Net refers to gross wells multiplied by Devon's fractional working interests therein.
Devon also held numerous overriding royalty interests in oil and gas wells, a portion of which are convertible to working interests after recovery of certain costs by third parties. After converting to working interests, these overriding royalty interests will be included in Devon's gross and net well count.
UNDEVELOPED ACREAGE
The following table sets forth Devon's developed and undeveloped oil and gas lease and mineral acreage as of December 31, 1999.
(1) Gross acres are the total number of acres in which Devon owns a working interest.
(2) Net refers to gross acres multiplied by Devon's fractional working interests therein.
OPERATION OF PROPERTIES
The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs field personnel and performs other functions. The charges under operating agreements customarily vary with the depth and location of the well being operated.
Devon is the operator of 8,913 of its wells. As operator, Devon receives reimbursement for direct expenses incurred in the performance of its duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged in the area to or by unaffiliated third parties. In presenting its financial data, Devon records the monthly overhead reimbursements as a reduction of general and administrative expense, which is a common industry practice.
SIGNIFICANT PROPERTIES
The following table sets forth proved reserve information on the most significant geographic areas in which Devon's properties are located as of December 31, 1999.
(1) Gas reserves are converted to MBoe at the rate of six MMcf of gas per MBbl of oil, based upon the approximate relative energy content of natural gas to oil, which rate is not necessarily indicative of the relationship of gas to oil prices. The respective prices of gas and oil are affected by market and other factors in addition to relative energy content.
(2) Percentage which MBoe for the basin or region bears to total MBoe for all Proved Reserves.
(3) Determined in accordance with SEC guidelines, except that no effect is given to future income taxes.
(4) Percentages which present value for the basin or region bears to total present value for all Proved Reserves.
(5) Canadian dollars converted to U.S. dollars at the rate of $1 Canadian: $0.6929 U.S.
NORTHERN DIVISION PROPERTIES
PERMIAN BASIN. This region encompasses approximately 66,000 square miles in southeastern New Mexico and west Texas and contains more than 500 major oil and gas fields. Since 1987, several significant acquisitions of properties by Devon in the Permian Basin have established prospective acreage in areas in which leasehold positions could not otherwise be obtained. It is characterized by prolific, long-lived oil and gas production from numerous formations found at a wide variety of depths. Many formations respond to enhanced recovery techniques, such as waterflood projects. In addition, the region is criss-crossed with multiple pipelines with easy access to many oil and gas markets. Acreage held by production from existing wells and large federal exploration units makes leases difficult to obtain. Most of Devon's position here was established through five major transactions.
ROCKY MOUNTAINS. Over a dozen oil and gas producing basins are located in the Rocky Mountain area, stretching from the Canadian border south to New Mexico. The Rocky Mountain area includes Devon's operations in three coalbed methane basins: The San Juan Basin in northwest New Mexico and southern Colorado, the Powder River Basin in Wyoming and the Raton Basin of northeastern New Mexico. Technology pioneered by Devon and a few other companies in the 1980's and 1990's resulted in significant production from coalbeds in the San Juan Basin. Devon is now applying its expertise to the development of coalbed reservoirs in the Powder River and Raton Basins. Over the next few years, Devon anticipates significant growth in its gas production from these two basins as wells are drilled and tied into pipelines.
Devon's largest natural gas reserve position in the Rocky Mountain Region relates to its interests in two federal units in the San Juan Basin. The San Juan Basin is a densely drilled area covering 3,700 square miles.
Devon's coal seam expertise will also play an important role in both the Powder River and Raton Basins. These basins, which are less developed than the San Juan Basin, have become two of the more active domestic onshore exploration areas in the United States. During the next five years, Devon plans to drill several thousand coalbed methane wells in the Powder River and Raton Basins which could, in aggregate, add significant proved natural gas reserves. Peak production for the Powder River Basin is anticipated for 2003, while peak production in the Raton Basin is estimated for 2004 to 2006. Additionally, Devon began initial operation of a 126-mile gas gathering system servicing the Powder River Basin in the third quarter of 1999. When it is fully developed in 2001, this system will have an estimated capacity of 450 million cubic feet of gas per day and will have access to multiple interstate pipelines.
MID-CONTINENT. The Mid-Continent area includes all or portions of the states of Kansas, Oklahoma, Texas, Arkansas, Louisiana, Mississippi and Alabama. The area covers a wide spectrum of geologic formations producing both oil and natural gas. Although the Mid-Continent was the site of some of the earliest oil and gas discoveries in the United States, the area continues to offer exploration potential. New technologies such as 3-D seismic are enabling Devon to study complex geologic environments and identify new exploratory prospects. Nuclear magnetic resonance logging is being applied by Devon in the Carthage-Bethany area of east Texas. Devon acquired its position in Carthage-Bethany in the PennzEnergy merger. Previously bypassed reserves are being discovered in wells in Carthage-Bethany through application of this new reserve evaluation technology.
SOUTHERN DIVISION PROPERTIES
ONSHORE. Devon's Gulf Coast area includes lands in south Texas and south Louisiana. In south Texas, where exploration for oil and gas is accelerating, Devon has 3-D seismic data covering its major acreage positions. This acreage is prospective for production in the Charco Lobo, Middle Wilcox and Frio-Vicksburg formations. The Company's exploration efforts in south Louisiana are focused on natural gas prospects in the lower, mid and upper Miocene age formations. The Gulf Coast area provides ready access to pipelines and production facilities. Natural gas from the Gulf Coast is typically priced at a premium to other U.S. producing areas.
OFFSHORE. The offshore Gulf of Mexico is a prolific producing area that provides approximately 25% of the natural gas produced in the United States. With a substantial infrastructure of platforms and production facilities, Devon is one of the largest operators on the shallow-water "shelf." Producing gas wells on the shelf are known for providing high initial flow rates and quick investment returns. As deep water drilling and production technology improves, operators are moving into the waters beyond the shelf. Technology now exists to drill and produce oil at water depths of 3,000 feet and deeper. The deep water Gulf of Mexico is believed to hold some of North America's largest remaining undiscovered oil and gas reserves. Devon has a substantial inventory of exploration acreage in the deeper Gulf waters.
CANADIAN PROPERTIES
Western Canada is Devon's largest production area. The Western Canadian Sedimentary Basin is a vast geologic feature encompassing portions of British Columbia, Alberta, Saskatchewan and Manitoba. The basin feature forms a wedge-shaped depression that tapers from a maximum thickness of 17,000 feet on the western and southern margins to a zero edge along the northeast. Devon's properties in Canada range from shallow oil and natural gas production in northern Alberta to deep, long-lived gas reservoirs in the Foothills area near the Alberta/British Columbia border. Approximately 2.2 million net acres of undeveloped leasehold in the Western Canadian Sedimentary Basin provide Devon with numerous exploration and development opportunities.
INTERNATIONAL DIVISION PROPERTIES
Most of Devon's proved reserves that lie outside North America are located under the Caspian Sea, offshore Azerbaijan, part of the former Soviet Union. The Caspian Basin is considered to hold some of the world's last known major undeveloped hydrocarbon reserves. Devon holds a 4.8% carried interest in the Azeri-Chirag-Gunashli joint development area. This area is estimated to contain five billion barrels of crude oil. Devon expects significant production from its interest in Azerbaijan to begin sometime between 2005 and 2010. Devon also has international operations in Brazil, Egypt, Qatar and Venezuela. In Egypt, Devon expects to begin producing oil in the second half of 2000 from a 1999 discovery. Although Devon currently produces a modest amount of oil in Venezuela, we do not expect to remain active in that country.
TITLE TO PROPERTIES
Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for current taxes not yet due and, in some instances, other encumbrances. Devon believes that such burdens do not materially detract from the value of such properties or from the respective interests therein or materially interfere with their use in the operation of the business.
As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). Investigations, generally including a title opinion of outside counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Ramco Dispute
In October 1995, subsidiaries of Devon acquired in the PennzEnergy merger filed an action, styled Pennzoil Exploration and Production Company, et al. v. Ramco Energy Limited and Ramco Hazar Energy Limited, in the United States District Court for the Southern District of Texas, Houston Division, against Ramco Hazar Energy Limited, formerly known as Ramco Energy Limited (collectively "Ramco"). The underlying dispute involves Ramco's asserted claim to an interest in the Karabakh prospect, an oil and gas field located in the territorial waters of the Azerbaijan Republic in the Caspian Sea. Since the initiation of the litigation, the operator of the Karabakh prospect determined that the hydrocarbon accumulation tested by three exploratory wells was not commercial. The federal suit sought to compel Ramco to arbitrate certain disputes that have arisen between it and
the Devon plaintiffs pursuant to the Federal Arbitration Act and the Convention on the Recognition and Enforcement of Foreign Arbitral Awards. After the filing of the federal action, the Devon plaintiffs filed an Original Petition for Declaration Relief in the 281st Judicial District Court of Harris County, Texas. The state suit, styled Pennzoil Exploration and Production Company, et al. v. Ramco Energy Limited and Ramco Hazar Energy Limited, which is expressly conditioned upon a determination in the federal suit that the disputes between the Devon plaintiffs and Ramco are not subject to arbitration, seeks a declaration that the Devon plaintiffs have not breached any agreements with Ramco, and do not owe and/or have not breached any fiduciary or other legal duty to Ramco including, without limitation, a duty of good faith and fair dealing. In November 1995, Ramco asserted a counterclaim in the state court action, asserting breach of contract and breach of fiduciary duties. The counterclaim seeks a declaratory judgment granting Ramco a participation interest in the Karabakh prospect, compensatory damages, exemplary damages, attorneys' fees, court costs and other unspecified relief.
The judge in the federal suit granted in part the plaintiffs' motion to compel arbitration and ordered arbitration to be held in New York, New York. The United States Court of Appeals for the Fifth Circuit generally affirmed the ruling of the judge in the federal suit and the Devon plaintiffs initiated arbitration. The parties have been engaged in settlement discussions and the selection of arbitrators has been suspended by agreement of the parties pending the outcome of the settlement discussions.
Royalty Matters
More than 30 oil companies, including Devon as a result of the PennzEnergy merger, are involved in disputes in which it is alleged that the oil companies and related parties have underpaid holders of royalty interests, overriding royalty interests and working interests in connection with the production of crude oil. The proceedings include suits in federal court in Texas, Louisiana, Mississippi and Wyoming (that have been consolidated into one proceeding in Texas) and in state court in Texas, Utah, Alabama and Louisiana. Certain parties to the federal litigation have entered into a global settlement agreement which provides for a conditional nationwide settlement, subject to opt-outs, of the crude oil royalty, overriding royalty and working interest claims of all members of the settlement class, including claims in the federal litigation and in numerous other individual and class action cases pending throughout the United States. The federal court held a fairness hearing April 5, 1999, and the settlement was approved. The Amended Final Judgment was entered September 10, 1999. However, certain entities have appealed their objections to the settlement. Devon is a party to the settlement agreement, which explicitly refutes an admission of liability, but was entered into to avoid expensive and protracted litigation.
Also, pending is a separate suit in federal court in Texas alleging that more than 30 major oil companies, including Devon as a result of the PennzEnergy merger, underpaid royalties to the United States in connection with crude oil produced from United States owned and/or controlled lands since 1986. The claims were filed by private litigants under the federal False Claims Act, and after investigation, the United States served notice of its intent to intervene as to certain defendants. Devon has reached an agreement in principle with the United States and the private litigants to settle the claims made in the case. Devon believes that it has acted reasonably and paid royalties in good faith, but has entered into the settlement agreement, which explicitly refutes an admission of liability, to avoid expensive and protracted litigation. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the liability recognized for such settlement of the royalty matters.
Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon's knowledge as of March 24, 2000, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
MARKET PRICE
Devon's common stock has been traded on the American Stock Exchange (the "AMEX") since September 29, 1988. Prior to September 29, 1988, Devon's common stock was privately held. Commencing on December 15, 1998, a new class of Devon exchangeable shares began trading on The Toronto Stock Exchange ("TSE") under the symbol NSX. These shares are essentially equivalent to Devon common stock. However, because they are issued by Devon's wholly-owned subsidiary, Northstar, they qualify as a domestic Canadian investment for Canadian institutional shareholders. They are exchangeable at any time, on a one-for-one basis, for common shares of Devon at the holder's option.
The following table sets forth the high and low sales prices for Devon common stock and exchangeable shares as reported by the AMEX and TSE for the periods indicated.
* Trading of the exchangeable shares on the TSE commenced on December 15, 1998.
DIVIDENDS
Devon commenced the payment of regular quarterly cash dividends on its common stock on June 30, 1993, in the amount of $0.03 per share. Effective December 31, 1996, Devon increased its quarterly dividend payment to $0.05 per share. Devon anticipates continuing to pay regular quarterly dividends in the foreseeable future. Dividends are also paid on the exchangeable shares at the same rate and on the same dates as dividends paid on the common stock.
On March 15, 2000, there were 13,796 holders of record of Devon common stock and 48 holders of record for the exchangeable shares.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial information (not covered by the independent auditors' reports) should be read in conjunction with "Item 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis addresses changes in Devon's financial condition and results of operations during the three year period of 1997 through 1999. Reference is made to "Item 6. Selected Financial Data" and "Item 8. Financial Statements and Supplementary Data."
OVERVIEW
On August 17, 1999, Devon and PennzEnergy Company ("PennzEnergy") closed their merger that was previously announced on May 20, 1999. In the merger, Devon issued approximately 21.5 million shares of common stock and assumed $1.6 billion of long-term debt and $0.7 billion of other liabilities. The merger added 396 million Boe of reserves, 13 million net acres of undeveloped leasehold and $3.2 billion of assets to Devon's balance sheet. This significantly expanded the scope of Devon's operations and moved Devon into the top ten of all U.S.-based independent oil and gas producers.
The PennzEnergy merger was accounted for under the purchase method of accounting for business combinations. Therefore, Devon's 1999 results do not include any effect of PennzEnergy's operations prior to August 17, 1999.
The PennzEnergy merger was completed less than a year after Devon's merger with Northstar Energy Corporation ("Northstar"). The December 10, 1998, combination of Devon and Northstar (the "Northstar Combination") added 115 million Boe of proved reserves and 1.8 million undeveloped acres, all in Canada. The Northstar Combination was accounted for under the pooling-of-interests method of accounting for business combinations. Accordingly, Devon's results for 1998 and prior years include the results of both Devon and Northstar as if the two had always been combined.
In addition to the two mergers, Devon's exploration, drilling and development efforts have also been significant contributors to Devon's growth over the last three years. Excluding the pooled results of Northstar prior to December 1998, Devon has spent approximately $492 million in its exploration, drilling and development efforts from 1997 through 1999. These costs included drilling 1,154 wells, of which 1,065 were completed as producers.
The impact of the mergers and drilling activities include the following changes from 1997 to 1999. (The following changes are calculated using 1997's results without combining Northstar's results, and the 1999 results include the effects of the added PennzEnergy operations for only the last 4 1/2 months of the year.)
o Combined oil, gas and NGLs production increased 32.3 million Boe, or 160%.
o Combined oil, gas and NGLs revenues increased $409.8 million, or 134%, during a period when the average combined price of oil, gas and NGLs fell by $1.53 per Boe, or 10%.
o Net cash provided by operating activities increased $36.9 million, or 22%. Cash margin increased $210.9 million, or 116%.
o Net earnings increased $19.3 million, or 26%.
o Production and operating expenses per Boe dropped $0.52 per Boe, or 19%.
o Depreciation, depletion and amortization of oil and gas properties per Boe increased $0.58 per Boe, or 14%.
o General and administrative expenses per Boe increased $0.39 per Boe, or 61%. However, Devon expects to eliminate a substantial part of this increase in costs per Boe in 2000 due to the termination at the end of 1999 of certain commitments inherited as part of the PennzEnergy merger.
During 1999, Devon marked its eleventh anniversary as a public company. While Devon has consistently increased production over this eleven-year period, volatility in oil and gas prices has resulted in considerable variability in earnings and cash flows. Prices for oil, natural gas and NGLs are determined primarily by market conditions. Market conditions for these products have been, and will continue to be, influenced by regional and world-wide economic growth, weather and other factors that are beyond Devon's control. Devon's future earnings and cash flows will continue to depend on market conditions.
Like all oil and gas production companies, Devon faces the challenge of natural production decline. As virgin pressures are depleted, oil and gas production from a given well naturally decreases. Thus, an oil and gas production company depletes part of its asset base with each unit of oil or gas it produces. Historically, Devon has been able to overcome this natural decline by adding, through drilling and acquisitions, more reserves than it produces. Devon's future growth, if any, will depend on its ability to continue to add reserves in excess of production.
Because oil and gas prices are influenced by many factors outside of its control, Devon's management has focused its efforts on increasing oil and gas reserves and production and controlling expenses. Over its eleven year history as a public company, Devon has been able to significantly reduce its operating costs per unit of production. Devon's future earnings and cash flows are dependent on its ability to continue to contain operating costs at levels that allow for profitable production of its oil and gas reserves.
RESULTS OF OPERATIONS
Devon's total revenues have risen from $499.7 million in 1997 to $734.5 million in 1999. In each of these three years, oil, gas and NGLs sales accounted for over 90% of total revenues.
Changes in oil, gas and NGLs production, prices and revenues from 1997 to 1999 are shown in the following tables. (Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.)
In addition to the volumes included in the prior tables for domestic and Canadian production, in the last 4 1/2 months of 1999 Devon also produced 424,000 barrels of oil in Venezuela and 23,000 barrels of oil in Azerbaijan. The oil revenues generated by this production were $2.9 million. This production was added by the PennzEnergy merger.
OIL REVENUES 1999 vs. 1998 Oil revenues increased $129.6 million in 1999. Oil revenues increased $87.2 million due to a $5.65 per barrel increase in the average price of oil in 1999. An increase in 1999's production of 3.5 million barrels caused oil revenues to increase by $42.4 million. The PennzEnergy merger added 5.3 million barrels of production during the last 4 1/2 months of 1999. This increase was partially offset by a 1.8 million barrel decline in 1999 production from Devon's other properties. The disposition of certain Canadian producing properties during 1998, the deferral of some oil-oriented projects, natural decline, and the effect of some properties that were shut-in earlier in 1999 due to low prices were the primary reasons for this production decline.
1998 vs. 1997 Oil revenues decreased $64.1 million in 1998. An average price decline of $5.56 per barrel reduced revenues by $66.2 million. This was slightly offset by $2.1 million of revenues added by production gains of 120,000 barrels.
GAS REVENUES 1999 vs. 1998 Gas revenues increased $176.6 million in 1999. A 65.4 Bcf increase in production in 1999 added $102.9 million of gas revenues compared to 1998. A $0.37 per Mcf increase in the average gas price in 1999, contributed $73.7 million of the increase in gas revenues.
The largest contributor to the 1999 production increase was production added by the PennzEnergy merger. The PennzEnergy properties added 55.5 Bcf of production during the 4 1/2 months following the merger. A 6.4 Bcf increase in Devon's Canadian gas production also
contributed to the increase in 1999 gas production. The Canadian gas production increase was primarily the result of two 1998 acquisitions.
Gas production from Devon's historical domestic properties also increased in 1999. This was due to a 3.9 Bcf increase in production from Devon's San Juan Basin coal seam gas properties. These properties produced 23.8 Bcf of gas in 1999 compared to 19.9 Bcf in 1998. This increase was largely the result of a program of mechanical improvements implemented at the Northeast Blanco Unit coal seam gas property during 1998.
1998 vs. 1997 Gas revenues decreased $10.1 million in 1998. An average price decline of $0.23 per Mcf reduced revenues by $30.4 million. This was partially offset by higher production in 1998. A production increase of 11.3 Bcf in 1998 added gas revenues of $20.3 million.
The San Juan Basin coal seam gas properties produced 19.9 Bcf in 1998 compared to 17.6 Bcf in 1997. The majority of the production gains realized in 1998 were the result of improvements at the Northeast Blanco Unit property.
NGLS REVENUES 1999 vs. 1998 NGLs revenues increased $39.7 million in 1999. An increase in 1999's average price of $5.40 per barrel caused NGLs revenues to increase $21.7 million. A production increase of 2.1 million barrels in 1999 caused revenues to increase $18.0 million. Production from the PennzEnergy properties for the last 4 1/2 months of 1999 accounted for 1.7 million barrels of the 1999 increase.
1998 vs. 1997 NGLs revenues decreased $8.2 million in 1998. An average price decline of $4.57 per barrel caused revenues to drop by $8.9 million. This decline was slightly offset by production increases of 48,000 barrels. Such production gains added $0.7 million of revenues in 1998.
OTHER REVENUES 1999 vs. 1998 Other revenues increased $1.1 million in 1999. Other revenues in 1999 included $6.7 million of dividend income in the last 4 1/2 months of the year from the 7.1 million shares of Chevron Corporation common stock acquired by Devon in the PennzEnergy merger. This dividend income, along with increases in 1999's revenues from third-party gas processing activities and interest income, caused other revenues to increase by $9.9 million. These increases were partially offset by $8.8 million of one-time revenues recognized by Northstar in 1998 from terminations of certain management agreements and gas contracts.
1998 vs. 1997 Other revenues decreased $29.7 million in 1998. This decrease was primarily due to Northstar's $29.4 million of gains from asset sales in 1997 which did not recur in 1998.
EXPENSES The details of the changes in pre-tax expenses between 1997 and 1999 are shown in the table below.
- - - - - - - - -------------------- (1) Though per Boe amounts for these expense items may be helpful for profitability trend analysis, these expenses are not directly attributable to production volumes.
PRODUCTION AND OPERATING EXPENSES The details of the changes in production and operating expenses between 1997 and 1999 are shown in the table below.
In addition to the expenses included in the prior tables for domestic and Canadian operations, in the last 4 1/2 months of 1999 Devon also incurred $1.5 million of recurring lease operating expenses on its properties outside North America. These expenses were related to properties added by the PennzEnergy merger.
1999 vs. 1998 Recurring lease operating expenses increased $52.6 million in 1999. Domestic expenses increased $48.9 million in 1999 due to $55.8 million of expenses for the last 4 1/2 months of the year from the PennzEnergy properties. Other than the added costs from the PennzEnergy properties, recurring expenses on Devon's other domestic properties dropped $6.9 million in 1999. Efficiencies achieved in certain of Devon's oil producing properties contributed most of this cost reduction.
The majority of Devon's production taxes are assessed on its onshore domestic properties. In the U.S., most of the production taxes paid are based on a fixed percentage of revenues. Therefore, the 149% increase in domestic oil, gas and NGLs revenues was the primary cause of the 77% increase in domestic production taxes. Production taxes did not increase proportionately to the increase in revenues. This was primarily due to the addition in 1999 of gas revenues from offshore Gulf of Mexico properties acquired in the PennzEnergy merger. Revenues generated from such offshore properties do not incur state production taxes.
1998 vs. 1997 Recurring lease operating expenses increased $10.8 million, or 11%, in 1998. The primary causes of this increase were the addition of wells drilled or acquired during 1998 and the effect of having a full year of operations in 1998 from certain Canadian properties acquired in March 1997.
Recurring expenses increased $0.14 per Boe, or 5%, in 1998. This increase was predominantly caused by a 9% increase in costs per Boe on the domestic properties. The operating expenses of the domestic wells drilled during the year raised the overall average costs per Boe in the U.S.
As previously stated, most of the U.S. production taxes paid are based on a fixed percentage of revenues. Therefore, the 24% drop in 1998 domestic oil, gas and NGLs revenues was the primary cause of the 31% decrease in domestic production taxes.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") Devon's largest recurring non-cash expense is DD&A. DD&A of oil and gas properties is calculated as the percentage of total proved reserve volumes produced during the year, multiplied by the net capitalized investment in those reserves including estimated future development costs (the "depletable base"). Generally, if reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, if the depletable base changes, then the DD&A rate moves in the same direction. The per unit DD&A rate is not affected by production volumes. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes. Oil and gas property DD&A is calculated separately on a country-by-country basis.
1999 vs. 1998 Oil and gas property related DD&A increased $124.8 million, or 104%, in 1999. An increase in the consolidated DD&A rate from $3.32 per Boe in 1998 to $4.65 per Boe in 1999 caused DD&A expense to increase $70.0 million. The 1999 rate of $4.65 per Boe was a
blended rate of before and after the PennzEnergy merger. The consolidated rate going into 2000 was $5.41 per Boe. Oil and gas property related DD&A expense increased $54.8 million due to the 46% increase in oil, gas and NGLs production in 1999.
Non-oil and gas property DD&A increased $5.6 million in 1999 compared to 1998. Depreciation of the non-oil and gas properties acquired in the PennzEnergy merger and depreciation of Devon's new Wyoming gas pipeline and gathering system, accounted for the increase in 1999's expense.
1998 vs. 1997 Oil and gas property related DD&A decreased $45.3 million, or 27%, in 1998. A 32% drop in the consolidated DD&A rate per Boe from $4.86 in 1997 to $3.32 in 1998 reduced 1998's DD&A expense by $55.2 million. This decrease was partially offset by $9.9 million of increased expense caused by the 6% increase in combined oil, gas and NGLs production in 1998. The $625.5 million reduction in the carrying value of Canadian oil and gas properties recorded at the end of 1997 was the primary cause of the drop in the 1998 DD&A rate.
AMORTIZATION OF GOODWILL In connection with the PennzEnergy merger, Devon recorded $338.9 million of goodwill. The goodwill recorded was allocated $302.0 million to domestic properties and $26.9 million to international properties. The goodwill is being amortized using the units-of-production method. Substantially all of the $16.1 million of amortization recognized in 1999 was related to the domestic balance.
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. See following table for a summary of G&A expenses by component.
1999 vs. 1998 Net G&A increased $30.3 million in 1999. Gross G&A increased $43.4 million in 1999. Included in the increase in gross expenses were $36.7 million of expenses related to 4 1/2 months of the PennzEnergy operations. The PennzEnergy amounts included $4.4 million of nonrecurring retention bonuses paid to certain PennzEnergy employees as an inducement to remain with Devon for two months following the merger closing.
G&A was lowered $9.1 million due to an increase in the amount capitalized as part of oil and gas properties. The 1999 amount capitalized included $5.5 million related to the PennzEnergy operations for the last 4 1/2 months of the year. G&A was also reduced by a $4.0 million increase in the amount of reimbursements on operated properties. The 1999 reimbursements received from the PennzEnergy properties were $6.0 million.
1998 vs. 1997 Net G&A decreased $0.8 million in 1998. Gross G&A increased $3.1 million in 1998. However, this increase was more than offset by increases in the amount of G&A capitalized and reimbursed in 1998. G&A was lowered $2.0 million due to an increase in the amount capitalized as part of oil and gas properties. G&A was also reduced by a $1.9 million increase in the amount of reimbursements on operated properties.
NORTHSTAR COMBINATION EXPENSES Approximately $13.1 million of expenses were incurred in 1998 in connection with the Northstar Combination. These expenses consisted primarily of investment bankers' fees, legal fees and costs of printing and distributing the proxy statement to shareholders. The pooling-of-interests method of accounting for business combinations requires such costs to be expensed as opposed to capitalized as costs of the transaction.
INTEREST EXPENSE 1999 vs. 1998 Interest expense increased $44.3 million in 1999. An increase in the average debt balance outstanding from $324.7 million in 1998 to $988.1 million in 1999 caused interest expense to increase by $43.5 million. The average interest rate on outstanding debt decreased slightly from 6.7% in 1998 to 6.6% in 1999. This rate decrease caused interest expense to decrease $0.5 million in 1999. Other items included in interest expense that are not related to the debt balance outstanding, such as facility and agency fees, amortization of costs and other miscellaneous items, were $1.3 million higher in 1999 compared to 1998.
The increase in the average debt balance in 1999 was attributable to the long-term debt assumed in the PennzEnergy merger on August 17, 1999. At that date, Devon assumed $1.6 billion of long-term debt with a weighted average interest rate of 7.2%. In the fourth quarter 1999, Devon retired $350 million of the assumed debt with a portion of the $402 million of net proceeds received from the issuance of 10.3 million shares of Devon common stock.
1998 vs. 1997 Interest expense increased $3.8 million, or 20%, in 1998. The average interest rate increased from 5.4% in 1997 to 6.7% in 1998. The increase in the average rate was primarily due to the fact that Northstar replaced a large portion of its floating-rate debt with longer term, fixed-rate debt early in 1998. The increase in 1998's average rate caused a $4.4 million increase in interest expense. The average debt balance increased from $267.0 million in 1997 to $324.7 million in 1998. This increase in the debt outstanding caused interest expense to increase $3.1 million. The increases caused by higher rates and higher balances outstanding were partially offset by the fact that 1997's interest expense included a $3.3 million "make-whole" payment related to the early retirement of debt. Other items included in interest expense that are not related to the balance of debt outstanding, such as facility and agency fees, amortization of costs and other miscellaneous items, were $0.4 million lower in 1998 compared to 1997.
DEFERRED EFFECT OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATE ON SUBSIDIARY'S LONG-TERM DEBT Prior to January 2000, Northstar had certain fixed rate senior notes which were denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the
Canadian dollar from the dates the notes were issued to the dates of repayment increased or decreased the expected amount of Canadian dollars eventually required to repay the notes. Such changes in the Canadian dollar equivalent balance of the debt are required to be included in determining net earnings for the period in which the exchange rate changes. In mid-January 2000, the U.S. dollar denominated notes were retired prior to maturity with cash on hand and borrowings under Devon's long-term credit facilities.
1999 vs. 1998 The rate of converting Canadian dollars to U.S. dollars increased from $0.6535 at the end of 1998 to $0.6929 at the end of 1999. The balance of Northstar's U.S. dollar denominated notes remained constant at $225 million throughout 1999. The higher conversion rate on the $225 million of debt reduced the Canadian dollar equivalent of debt recorded by Northstar at the end of 1999. Therefore, a $13.2 million reduction to expenses was recorded in 1999.
1998 vs. 1997 The principal balance of Northstar's U.S. dollar denominated notes increased from $135 million at the end of 1997 to $225 million at the end of 1998. The rate of converting Canadian dollars to U.S. dollars decreased from $0.6997 at the end of 1997 to $0.6535 at the end of 1998. The combination of these factors caused $16.1 million to be recorded as an expense in 1998.
DISTRIBUTIONS ON PREFERRED SECURITIES OF SUBSIDIARY TRUST As discussed in Note 9 to the consolidated financial statements included elsewhere herein, Devon, through its affiliate Devon Financing Trust, completed the issuance of $149.5 million of 6.5% Trust Convertible Preferred Securities ("TCP Securities") in July 1996. The TCP Securities had a maturity date of June 15, 2026. However, in October 1999, Devon issued notice to the holders of the TCP Securities that it was exercising its right to redeem such securities on November 30, 1999. Substantially all of the holders of the TCP Securities elected to exercise their conversion rights instead of receiving the redemption cash value. As a result, all but 950 of the 2.99 million units of TCP Securities were exchanged for shares of Devon common stock. As a result, Devon issued approximately 4.9 million shares of common stock for substantially all of the outstanding units of TCP Securities. The redemption price for the 950 units redeemed was approximately $50,000.
1999 vs. 1998 The TCP Securities distributions in 1999 were $6.9 million compared to $9.7 million in 1998. Substantially all of the TCP Securities were exchanged for shares of Devon common stock on November 30, 1999. Therefore, there was no fourth quarter 1999 distribution on the exchanged TCP Securities.
1998 vs. 1997 Distributions on the TCP Securities were $9.7 million in both 1998 and 1997.
REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated "ceiling." The ceiling limitation is the discounted estimated after-tax future net revenues from proved oil and gas properties. The ceiling is imposed separately by country. In calculating future net revenues, current prices and costs are generally held constant indefinitely. The net book value, less deferred tax liabilities, is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less deferred taxes, is written off as an expense.
1998 Reduction. As of September 30, 1998, the carrying value of Devon's domestic properties, less deferred income taxes, exceeded the full cost ceiling by $88 million. Accordingly, a $126.9 million pre-tax reduction of the carrying value of such properties was recorded in the third quarter of 1998. This reduction was partially offset by a related $38.9 million deferred income tax benefit, resulting in an after-tax charge of $88 million.
1997 Reduction. As of December 31, 1997, the carrying value of Northstar's oil and gas properties, less deferred income taxes, exceeded the full cost ceiling by $397.9 million. Accordingly, a $625.5 million pre-tax reduction of the carrying value of such properties was recorded in the fourth quarter of 1997. This reduction was partially offset by a related $227.6 million deferred income tax benefit, resulting in an after-tax charge of $397.9 million.
INCOME TAXES 1999 vs. 1998 Devon's 1999 financial tax rate was 41% of earnings before income tax expense. This rate was higher than the statutory federal tax rate of 35% due to the effect of goodwill amortization that is not deductible for income tax purposes and the effect of Canadian pre-tax earnings being taxed at higher rates than the U.S. rate. The 1998 financial tax benefit rate was 20%. This rate was materially affected by a portion of the $126.9 million reduction of carrying value of oil and gas properties recorded in 1998 that was not deductible for income tax purposes.
1998 vs. 1997 Devon's effective financial income tax benefit rate in 1998 was 20% compared to a benefit rate in 1997 of 37%. The benefit rate in 1998 was lower than in 1997 due to a combination of a smaller pre-tax loss in 1998 and certain 1998 financial expenses that are not deductible for income tax purposes. Approximately $27.2 million of the $126.9 million reduction of carrying value of oil and gas properties related to costs, which are not deductible for income taxes. Also, approximately $5.6 million of the Northstar Combination expenses and $4.0 million of the deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt are not deductible for income tax purposes.
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 "Item 8. Financial Statements and Supplementary Data."
CAPITAL EXPENDITURES Approximately $314.8 million was spent in 1999 for capital expenditures, of which $240.7 million was related to the acquisition, drilling or development of oil and gas properties and $69.3 million was spent on the gas gathering and processing project in Wyoming. These amounts compare to 1998 total expenditures of $375.5 million ($371.3 million of which was related to oil and gas properties) and 1997 total expenditures of $288.0 million ($279.9 million of which was related to oil and gas properties.)
OTHER CASH USES Devon's common stock dividends were $12.7 million, $7.3 million and $6.4 million in 1999, 1998 and 1997, respectively. Devon also paid $3.7 million of preferred stock dividends in the last 4 1/2 months of 1999 following the PennzEnergy merger.
CAPITAL RESOURCES AND LIQUIDITY Net cash provided by operating activities ("operating cash flow") has historically been the primary source of Devon's capital and short-term liquidity. Operating cash flow was $205.6 million, $191.6 million and $253.1 million in 1999, 1998 and 1997, respectively. The trends in operating cash flow during these periods have generally followed those of the various revenue and expense items previously discussed.
In addition to operating cash flow, Devon's credit lines and the private placement of long-term debt have been an important source of capital and liquidity. In 1999, debt repayments exceeded borrowings by $223.9 million. During the years 1998 and 1997, long-term debt borrowings exceeded repayments by $55.3 million and $127.2 million, respectively.
On October 15, 1999, Devon entered into new unsecured long-term credit facilities aggregating $750 million (the "Credit Facilities"). The Credit Facilities include a U.S. facility of $475 million (the "U.S. Facility") and a Canadian facility of $275 million (the "Canadian Facility"). The Credit Facilities replaced Devon's previous facilities that totaled $400 million.
Amounts borrowed under the Credit Facilities bear interest at various fixed rate options that Devon may elect for periods up to six months. Such rates are generally less than the prime rate that is also available at Devon's option. The Credit Facilities provide for an annual facility fee of $0.9 million that is payable quarterly.
The $475 million U.S. Facility consists of a Tranche A facility of $200 million and a Tranche B facility of $275 million. The Tranche A facility matures on October 15, 2004. Devon may borrow funds under the Tranche B facility until October 13, 2000 (the "Tranche B Revolving Period"). Devon may request that the Tranche B Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 30 and 60 days prior to the end of the Tranche B Revolving Period. Debt borrowed under the Tranche B facility matures two years following the end of the Tranche B Revolving Period. At the end of 1999, Devon had $200 million borrowed under the Tranche A facility and none borrowed under the Tranche B facility.
Devon may borrow funds under the $275 million Canadian Facility until October 13, 2000 (the "Canadian Facility Revolving Period"). Devon may request that the Canadian Facility Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 45 and 90 days prior to the end of the Canadian Facility Revolving Period. Debt outstanding as of the end of the Canadian Facility Revolving Period is payable in semi-annual installments of 2.5% each for the following five years, with the final installment due five years and one day following the end of the Canadian Facility Revolving Period. At December 31, 1999, there was $114.3 million borrowed under the Canadian Facility.
Another significant source of liquidity in 1999 was the $402 million received from the sale of approximately 10.3 million shares of Devon's common stock in a public offering. The proceeds were primarily used to retire $350 million of long-term debt in the fourth quarter of 1999. The retired debt, which Devon assumed in the PennzEnergy merger, had an average interest rate of 10% per year.
YEAR 2000 STATUS
Devon's company-wide Year 2000 Project ("the Project") was completed on schedule. The Project addressed the "Year 2000" issue caused by computer programs being written utilizing two digits rather than four to define an applicable year. Total costs related to the Project were approximately $1.3 million, of which $1.0 million related to capital items and $0.3 million to expense items.
During the rollover from December 31, 1999 to January 1, 2000, Devon followed a Year 2000 rollover plan for reporting, documenting and remediating Year 2000 errors. These plans included such tasks as on-site testing and verification of systems at January 1, 2000. Currently, there have been no business-critical failures reported due to Year 2000 errors. However, there were two failures reported for non-critical systems, both of which were remedied by vendor-supplied corrections by January 4, 2000.
Devon will continue to monitor systems for errors due to Year 2000 failures through the processing of leap year related data. Devon does not expect to incur significant operational problems due to the Year 2000 issue. However, if all Year 2000 issues are not properly and timely identified, assessed, remediated and tested, there can be no assurances that the Year 2000 issue will not materially impact Devon's results of operations or adversely affect its relationships with customers, vendors, or others. Additionally, there can be no assurance that the Year 2000 issues of other entities will not have a material impact on Devon's systems or results of operations.
2000 ESTIMATES
The forward-looking statements provided in this discussion are based on management's examination of historical operating trends, the December 31, 1999 reserve reports of independent petroleum engineers and other data in Devon's possession or available from third parties. Devon cautions that its future oil, gas and NGLs production, revenues and expenses are subject to all of the risks and uncertainties normally incident to the exploration for and development and production and sale of oil and gas. These risks include, but are not limited to, price volatility, inflation or lack of availability of goods and services, environmental risks, drilling risks, regulatory changes, the uncertainty inherent in estimating future oil and gas production or reserves, and other risks as outlined below. Also, the financial results of Devon's foreign operations are subject to currency exchange rate risks. Additional risks are discussed below in the context of line items most affected by such risks.
SPECIFIC ASSUMPTIONS AND RISKS RELATED TO PRICE AND PRODUCTION ESTIMATES Prices for oil, natural gas and NGLs are determined primarily by prevailing market conditions. Market conditions for these products are influenced by regional and world-wide economic growth, weather and other substantially variable factors. These factors are beyond Devon's control and are difficult to predict. In addition to volatility in general, Devon's oil, gas and NGLs prices may vary considerably due to differences between regional markets, transportation availability and demand for different grades of oil, gas and NGLs. Over 97% of Devon's revenues are attributable to sales of these three commodities. Consequently, Devon's financial results and resources are highly influenced by this price volatility.
Estimates for Devon's future production of oil, natural gas and NGLs are based on the assumption that market demand and prices for oil and gas will continue at levels that allow for profitable production of these products. There can be no assurance of such stability.
Certain of Devon's individual oil and gas properties, such as the Northeast Blanco Unit in the San Juan Basin, are of a size such that significant declines in production at these properties could have a material impact on the overall financial results.
The production, transportation and marketing of oil, natural gas and NGLs are complex processes which are subject to disruption due to transportation and processing availability, mechanical failure, human error, meteorological events including, but not limited to, hurricanes, and numerous other factors. The following forward-looking statements were prepared assuming demand, curtailment, producibility and general market conditions for Devon's oil, natural gas and NGLs for 2000 will be substantially similar to those of 1999, unless otherwise noted. Given the general limitations expressed herein, Devon's forward-looking statements for 2000 are set forth below. Unless otherwise noted, all of the following dollar amounts are expressed in U.S. dollars. Those amounts related to Canadian operations have been converted to U.S. dollars using the year-end 1999 exchange rate of $0.6929 U.S. dollar to $1.00 Canadian dollar. The actual 2000 exchange rate may vary materially from the year-end 1999 rate used. Such variations could have a material effect on the following Canadian estimates.
GEOGRAPHIC REPORTING AREAS FOR 2000 The following estimates of production, average price differentials and capital expenditures are provided separately for each of Devon's geographic divisions established after the PennzEnergy merger. These divisions are as follows:
o the Southern Division, which operates oil and gas properties located primarily in the onshore South Texas and Gulf Coast areas and offshore in the Gulf of Mexico;
o the Northern Division, which operates all properties located in the United States other than those operated by the Southern Division;
o Canada; and
o International Division, which encompasses all oil and gas properties that lie outside of the United States and Canada.
YEAR 2000 POTENTIAL OPERATING ITEMS
OIL PRODUCTION Devon expects its oil production in 2000 to total between 21.1 million barrels and 23.9 million barrels. Northern Division production is expected to be between 9.8 million barrels and 11.1 million barrels, Southern Division production is expected to be between 5.7 million barrels and 6.5 million barrels, Canadian production is expected to be between 4.3 million barrels and 4.9 million barrels, and International production is expected to be between 1.3 million barrels and 1.4 million barrels.
OIL PRICES Devon expects its 2000 net oil prices per barrel will average from $1.50 to $2.40 above West Texas Intermediate ("WTI") posted prices for its Northern Division production and $0.10 to $0.95 above WTI posted prices for its Southern Division production.
Devon expects to receive a price from $1.25 to $2.25 below WTI posted prices for its Canadian production. This expected range includes an estimated $0.30 per barrel decrease resulting from foreign currency hedges. These hedges, in which Devon will sell $30 million in 2000 at an average Canadian-to-U.S. exchange rate of $0.7265 and buy the same amount of dollars at the floating exchange rate, offset a portion of the exposure to currency fluctuations on those Canadian oil sales that are based on U.S. dollar prices. The $0.30 per barrel decrease is based on the assumption that the year-end 1999 Canadian-to-U.S. conversion rate of $0.6929 remains constant during 2000.
Almost 90% of expected International oil production in 2000 is in Venezuela. Due to the terms of the controlling production sharing contract, the net price Devon records for its Venezuelan oil production is substantially less than WTI posted prices.
GAS PRODUCTION Devon expects its 2000 gas production to total between 269 Bcf and 306 Bcf. It is expected that Northern Division production will be between 115 Bcf and 130 Bcf, and Southern Division production will be between 93 Bcf and 106 Bcf. Canadian production is expected to be between 61 Bcf and 70 Bcf. No significant gas production is expected in 2000 from Devon's International properties.
GAS PRICES - FIXED Through various fixed price contracts or hedging instruments, Devon has fixed the price it will receive in 2000 on a portion of its natural gas production. The Northern Division has fixed volumes of 9.5 Bcf at $1.97 per Mcf, which is a modest amount of total expected Northern Division production. Devon's Canadian operation has fixed volumes of 25.6 Bcf at $1.44 per Mcf, which is a more significant amount of total expected Canadian production.
GAS PRICES - FLOATING For the gas production for which prices have not been fixed, Devon's Northern Division production is expected to average from $0.25 less than Texas Gulf Coast spot averages ("TGC") to $0.05 more than TGC, Southern Division production is expected to average from an amount equal to TGC to $0.30 more than TGC and Canadian production is expected to average from $0.40 to $0.80 less than the New York Mercantile Exchange price.
NGLS PRODUCTION Devon expects its 2000 production of NGLs to total between 6.6 million barrels and 7.6 million barrels. Between 4.7 million barrels and 5.4 million barrels are expected to be produced in the Northern Division, between 1.5 million barrels and 1.7 million barrels are expected to be produced in the Southern Division, and between 0.4 million barrels and 0.5 million barrels are expected to be produced in Canada. No significant NGLs production is expected in 2000 from Devon's International properties.
OTHER REVENUES Devon's other revenues in 2000 are expected to be between $29 million and $33 million. Approximately $18.5 million of 2000's expected other revenues is from dividends on Devon's investment of 7.1 million shares of Chevron Corporation common stock.
PRODUCTION AND OPERATING EXPENSES Devon's production and operating expenses vary in response to several factors. Among the most significant of these factors are additions to or deletions from Devon's property base, changes in production taxes, general changes in the prices
of services and materials that are used in the operation of the properties and the amount of repair and workover activity required.
Oil, gas and NGLs prices will have a direct effect on production taxes to be incurred in 2000. Future prices also could have an effect on whether proposed workover projects are economically feasible. These factors, coupled with the uncertainty of future oil, gas and NGLs prices, increase the uncertainty inherent in estimating future production and operating costs. Given these uncertainties, Devon estimates that year 2000 total production and operating costs will be between $288 million and $318 million.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") The 2000 oil and gas property DD&A rate will depend on various factors. Most notable among such factors are the amount of proved reserves that could be added from drilling or acquisition efforts in 2000 compared to the costs incurred for such efforts, and the revisions to Devon's year-end 1999 reserve estimates that, based on prior experience, are likely to be made during 2000.
Devon's consolidated oil and gas property DD&A rate as of January 1, 2000, was $5.41 per Boe. Assuming a full year 2000 oil and gas property DD&A rate of between $5.25 per Boe and $6.00 per Boe, Devon expects that its consolidated oil and gas property DD&A expense in 2000 will be between $400 million and $460 million.
In addition to its oil and gas property DD&A expense, Devon also expects to record goodwill amortization in 2000 of between $37 million and $41 million. The goodwill was recorded in connection with the PennzEnergy merger. Additionally, Devon expects its 2000 DD&A expense related to non-oil and gas property fixed assets to total between $27 million and $29 million.
GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") Devon's G&A includes the costs of many different goods and services used in support of its business. These goods and services are subject to general price level increases or decreases. In addition, Devon's G&A varies with its level of activity and the related staffing needs as well as with the amount of professional services required during any given period. Should Devon's needs or the prices of the required goods and services differ significantly from current expectations, actual G&A could vary materially from the estimate. Given these limitations, consolidated G&A in 2000 is expected to be between $48 million and $53 million.
INTEREST EXPENSE Future interest rates and oil, natural gas and NGLs prices have a significant effect on Devon's interest expense. Approximately $1.2 billion of Devon's January 21, 2000, long-term debt balance of $1.7 billion bears interest at fixed rates. Such fixed rates remove the uncertainty of future interest rates from some, but not all, of Devon's long-term debt. Also, Devon can only marginally influence the prices, and the resulting cash flow, it will receive in 2000 from sales of oil, gas and NGLs. These factors increase the margin of error inherent in estimating future interest expense. Other factors, which affect interest expense, such as the amount and timing of capital expenditures, are within Devon's control. Given the uncertainty of future interest rates and commodity prices, Devon estimates that the consolidated interest expense in 2000 will be between $103 million and $114 million.
DEFERRED EFFECT OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATE ON SUBSIDIARY'S LONG-TERM DEBT Devon's Canadian subsidiary Northstar had $225 million of U.S. dollar denominated debt that gave rise to this item in prior periods. This debt was retired in January 2000. The Canadian-to-U.S. dollar exchange rate dropped slightly in January prior to the debt retirement. As a result, $2.4 million of expense was recognized in January 2000.
REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES As of December 31, 1999, the full cost ceiling exceeded Devon's carrying value of oil and gas properties, less deferred income taxes. However, such excess could easily be eliminated by declines in oil and/or gas prices between year-end 1999 and the end of any quarter during 2000. The result would be a 2000 reduction of the carrying value of oil and gas properties.
INCOME TAXES Devon expects its consolidated financial income tax rate in 2000 to be between 48% and 57%. These rates are the combined current and deferred tax rates. There are certain items that will have a fixed impact on 2000's income tax expense regardless of the level of pre-tax earnings that are produced. These items include Section 29 tax credits in the U.S., which reduce income taxes based on production levels of certain properties and are not necessarily affected by pre-tax financial earnings. The amount of Section 29 tax credits expected to be used to offset financial income tax expense in 2000 is approximately $4 million. Also, Devon's Canadian subsidiaries are subject to Canada's "large corporation tax" of approximately $2 million, which is based on total capitalization levels, not pre-tax earnings. The financial income tax in 2000 will also be increased by approximately $16 million due to the financial amortization of certain costs, such as goodwill amortization, that are not deductible for income tax purposes. Significant changes in estimated production levels of oil, gas and NGLs, the prices of such products, or any of the various expense items could materially alter the effect of the aforementioned items on 2000's financial income tax rates.
Based on its current expectations of 2000 taxable income, Devon anticipates its current portion of 2000 income taxes will be $36 million to $40 million. However, unanticipated revenue and/or expense fluctuations could easily make these tax estimates inaccurate.
PROPERTY ACQUISITIONS AND DIVESTITURES Though Devon has completed several major property acquisitions in recent years, these transactions are opportunity driven. Thus, Devon does not "budget," nor can it reasonably predict, the timing or size of such possible acquisitions, if any.
During 2000, Devon contemplates the disposition of certain oil and gas properties (the "Disposition Properties"). The Disposition Properties are predominantly properties that are either outside of Devon's core-operating areas or otherwise do not fit Devon's current strategic objectives. Most, but not all, of such properties were acquired in the August 1999 merger with PennzEnergy. The Disposition Properties are located in the U.S., Canada and other International areas. At this time, Devon is in the early stages of the disposition process, and it is impossible to identify when, or if, the dispositions will occur.
The estimates of Devon's 2000 results set forth earlier in this section include the full-year results from the Disposition Properties without any effect given to their potential disposition. The actual effect the dispositions will have on Devon's overall estimates will depend upon the actual timing of the dispositions. The estimated full-year results from the Disposition Properties that are included in the overall 2000 estimates include oil production of between 4.1 million barrels and 4.6
million barrels, gas production of between 2.1 Bcf and 2.3 Bcf and NGLs production of between 0.9 million barrels and 1.0 million barrels and production and operating expenses of between $37.8 million and $41.8 million.
Because Devon is in the early stages of the disposition process, it is difficult to accurately predict the amount of proceeds to be generated from the property dispositions. However, the dispositions are expected to increase Devon's oil and gas property depreciation, depletion and amortization rate by $0.35 per Boe to $0.45 per Boe after all dispositions are completed.
YEAR 2000 POTENTIAL CAPITAL SOURCES, USES AND LIQUIDITY
CAPITAL EXPENDITURES Devon's capital expenditures budget is based on an expected range of future oil, natural gas and NGLs prices as well as the expected costs of the capital additions. Should Devon's price expectations for its future production change significantly, some projects may be accelerated or deferred and, consequently, may increase or decrease total 2000 capital expenditures. In addition, if the actual costs of the budgeted items vary significantly from the anticipated amounts, actual capital expenditures could vary materially from Devon's estimates.
Though Devon has completed several major property acquisitions in recent years, these transactions are opportunity driven. Thus, Devon does not "budget", nor can it reasonably predict, the timing or size of such possible acquisitions, if any.
Devon expects its capital expenditures for the year 2000 will be materially higher than those for 1999. For 1999, Devon's capital expenditures for exploration, drilling and development efforts were $217 million. However, for the year 2000, Devon expects capital expenditures for exploration, drilling and development efforts to total between $480 million and $510 million. These amounts include between $110 million and $130 million for drilling and facilities costs related to reserves classified as proved as of year-end 1999. In addition, these amounts include between $240 million and $260 million for other lower risk/reward projects and between $120 million and $130 million for new, higher risk/reward projects. The following table shows expected drilling and facilities expenditures by major operating division.
EXPLORATION, DRILLING AND PRODUCTION FACILITIES EXPENDITURES ($ IN MILLIONS) ----------------------------------------------------------------------------
In addition to these expenditures for exploration, drilling and development, Devon is participating through a joint venture in the construction of gas gathering and processing systems in the Powder River Basin of Wyoming. Devon expects to spend from $10 million to $20 million as its share of the project in 2000. Devon also expects to capitalize between $25 million and $35 million of G&A expenses in accordance with the full cost method of accounting. Also, Devon expects to spend from $10 million to $20 million for plugging and abandonment costs on some of its oil and gas properties.
OTHER CASH USES Devon's management expects the policy of paying a quarterly dividend to continue. With the current $0.05 per share quarterly dividend rate and 86.1 million shares of common stock outstanding, 2000 dividends on common stock are expected to approximate $17 million. Dividends paid on preferred stock should total $9.7 million in 2000.
CAPITAL RESOURCES AND LIQUIDITY Devon's estimated 2000 cash uses, including its exploration, drilling and development activities, are expected to be funded primarily through a combination of working capital and operating cash flow, with the remainder, if any, funded with borrowings from Devon's credit facilities. The amount of operating cash flow to be generated during 2000 is uncertain due to the factors affecting revenues and expenses as previously cited. However, Devon expects its combined capital resources to be more than adequate to fund its anticipated capital expenditures and other cash uses for 2000. As of January 21, 2000, Devon had $337 million available under its $750 million credit facilities. If significant acquisitions or other unplanned capital requirements arise during the year, Devon could utilize its existing credit facilities and/or seek to establish and utilize other sources of financing.
IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires the recognition of all derivatives as either assets or liabilities in the statement of financial position and measurement of those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as a hedge. The accounting for changes in the fair value of a derivative (that is gains and losses) depends on the intended use of the derivative and whether it qualifies as a hedge. A subsequent pronouncement, SFAS 137, was issued in July, 1999 that delayed the effective date of SFAS 133 until fiscal years beginning after June 15, 2000. Devon plans to adopt the provision of SFAS 133 in the first quarter of the year ending December 31, 2001, and is currently evaluating the effects of this pronouncement.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about Devon's potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices, interest rates and foreign currency exchange rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how Devon views and manages its ongoing market risk exposures. All of Devon's market risk sensitive instruments were entered into for purposes other than trading.
COMMODITY PRICE RISK Devon's major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to its U.S. and Canadian natural gas production. Pricing for oil and gas production has been volatile and unpredictable for several years.
Devon periodically enters into financial hedging activities with respect to a portion of its projected oil and natural gas production through financial price swaps whereby Devon will receive a fixed price for its production and pay a variable market price to the contract counterparty. These financial hedging activities are intended to support oil and natural gas prices at targeted levels and to manage Devon's exposure to oil and gas price fluctuations. Realized gains or losses from the settlement of these financial hedging instruments are recognized in oil and gas sales when the associated production occurs. The gains and losses realized as a result of these hedging activities are substantially offset in the cash market when the hedged commodity is delivered. Devon does not hold or issue derivative instruments for trading purposes.
As of year-end 1999, Devon had financial gas price hedging instruments in place which represented approximately 18 Bcf, 13 Bcf and 3 Bcf of gas production in the years 2000, 2001 and 2002, respectively. The 2000 hedged gas volumes represent approximately 6% of expected 2000 total production. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - 2000 Estimates."
Devon uses a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of its commodity hedging instruments. At December 31, 1999, a 10% increase in the underlying commodities' prices would have reduced the fair value of Devon's commodity hedging instruments by $7.7 million.
In addition to the commodity hedging instruments described above, Devon also manages its exposure to gas price risks by periodically entering into fixed-price gas contracts. All of Devon's existing fixed-price contracts relate to its Canadian gas production. For each of the years of 2000 through 2004, Devon's fixed-price gas contracts cover approximately 17 Bcf, 12 Bcf, 10 Bcf, 6 Bcf and 6 Bcf of production, respectively. Devon also has Canadian gas volumes subject to fixed-price contracts in the years from 2005 through 2016, but the yearly volumes are less than 6 Bcf. The amount of 2000's production covered by fixed-price contracts represents approximately 6% of expected 2000 total production. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - 2000 Estimates."
INTEREST RATE RISK At December 31, 1999, Devon had long-term debt outstanding of $1.79 billion. Of this amount, $1.47 billion, or 82%, bears interest at fixed rates averaging 6.9%. The remaining $0.32 billion of debt outstanding at the end of 1999 bears interest at floating rates which averaged 6.2% at the end of 1999.
In mid-January 2000, Devon utilized $75 million of cash on hand and $150 million of borrowings from its long-term credit facilities, which bear interest at floating rates, to retire $225 million of fixed-rate long-term debt. This fixed-rate debt retired had an average interest rate of 6.8% per year. Also in mid-January 2000, Devon used approximately $50 million of cash on hand to reduce year-end 1999 borrowings under its credit facilities. These early 2000 transactions left Devon with $1.66 billion of total long-term debt, of which $1.25 billion, or 75%, bears interest at fixed rates averaging 6.9%. The remaining $0.41 billion of floating-rate debt borrowed under the credit facilities bears interest, as of January 21, 2000, at an average rate of 6.0%.
The terms of the credit facilities in place allow interest rates to be fixed at Devon's option for periods of between 30 to 180 days. A 10% increase in short-term interest rates on the floating-rate debt outstanding as of January 21, 2000, would equal approximately 60 basis points. Such an increase in interest rates would increase Devon's 2000 interest expense by approximately $2.5 million assuming borrowed amounts remain outstanding.
The above sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments.
FOREIGN CURRENCY RISK Devon's net assets, net earnings and cash flows from its foreign subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the applicable functional currency. Assets and liabilities of the foreign subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period.
Substantially all of Devon's Canadian oil sales are paid in Canadian dollars, but at amounts based on the U.S. dollar price of oil. Therefore, currency fluctuations between the Canadian and U.S. dollars impact the amount of Canadian dollars received by Devon's Canadian subsidiaries for their oil production. To mitigate the effect of volatility in the Canadian-to-U.S. dollar exchange rate on Canadian oil revenues, Devon has existing foreign currency exchange rate swaps. Under such swap agreements, in 2000 Devon will sell $30 million at an average Canadian-to-U.S. exchange rate of $0.7265 and buy the same amount of dollars at the floating exchange rate. The amount of gains or losses realized from such swaps are included as increases or decreases to realized oil sales. At the year-end 1999 exchange rate, these swaps would result in decreases to 2000's annual oil sales of approximately $1.4 million. A further $0.03 decrease in the Canadian-to-U.S. dollar exchange rate in 2000 would result in an additional decrease in oil sales of approximately $1.3 million.
For purposes of the sensitivity analysis described above for changes in the Canadian dollar exchange rate, a change in the rate of $0.03 was used as opposed to a 10% change in the rate. During the last seven years, the Canadian-to-U.S. dollar exchange rate has fluctuated an average of approximately 4% per year, and no year's fluctuation was greater than 7%. The $0.03 change used in the above analysis represents an approximate 4% change in the year-end 1999 rate.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto.
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders Devon Energy Corporation:
We have audited the accompanying consolidated balance sheets of Devon Energy Corporation and subsidiaries as of December 31, 1999, 1998 and 1997, and the related consolidated statements of operations, stockholders' equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the 1998 and 1997 financial statements of Northstar Energy Corporation, a wholly-owned subsidiary, which statements reflect total assets constituting 31% and 32% and total revenues constituting 38% and 37% in 1998 and 1997, respectively, of the related consolidated totals. The 1998 and 1997 financial statements of Northstar Energy Corporation were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Northstar Energy Corporation in 1998 and 1997, is based solely on the reports of the other auditors.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Devon Energy Corporation and subsidiaries as of December 31, 1999, 1998 and 1997, and the results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles.
KPMG LLP
Oklahoma City, Oklahoma February 9, 2000
AUDITORS' REPORT TO THE SHAREHOLDERS
We have audited the consolidated balance sheets of Northstar Energy Corporation (a wholly owned subsidiary of Devon Energy Corporation) as at December 31, 1998 and 1997 and the related consolidated statements of operations and comprehensive income (loss), stockholders' equity and cash flows for the years then ended (not separately included herein). These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards, which are substantially similar to generally accepted auditing standards in the United States. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 1998 and 1997, and the results of its operations and the changes in its cash flow for the years then ended in accordance with generally accepted accounting principles in the United States.
/s/ DELOITTE & TOUCHE LLP ------------------------------------- Deloitte & Touche LLP Chartered Accountants
Calgary, Alberta Canada January 20, 1999
DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
See accompanying notes to consolidated financial statements
DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (IN THOUSANDS)
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Accounting policies used by Devon Energy Corporation and subsidiaries ("Devon") reflect industry practices and conform to generally accepted accounting principles. The more significant of such policies are briefly discussed below.
Basis of Presentation and Principles of Consolidation
Devon is engaged primarily in oil and gas exploration, development and production, and the acquisition of producing properties. Such activities domestically are located primarily in five operating areas: Permian Basin, Mid-Continent, the Rocky Mountains, Gulf Coast onshore and offshore Gulf of Mexico. Devon's Canadian activities are located primarily in the Western Canadian Sedimentary Basin and Devon's international activities -- outside of North America -- are located primarily in Azerbaijan and Venezuela. Devon's share of the assets, liabilities, revenues and expenses of affiliated partnerships and the accounts of its wholly-owned subsidiaries are included in the accompanying consolidated financial statements. All significant intercompany accounts and transactions have been eliminated in consolidation.
Information concerning common stock and per share data assumes the exchange of all Exchangeable Shares issued in connection with the Northstar Combination described in Note 2.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from those estimates.
Inventories
Inventories, which consist primarily of injected gas and tubular goods, parts and supplies, are stated at cost, determined principally by the average cost method, which is not in excess of net realizable value.
Property and Equipment
Devon follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Net capitalized costs are limited to the estimated future net revenues, discounted at 10% per annum, from proved oil, natural gas and natural gas liquids reserves. Such limitations are imposed separately on a country-by-country basis. Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of one barrel of oil to six
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
thousand cubic feet of natural gas. No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves.
Depreciation and amortization of other property and equipment, including leasehold improvements, are provided using the straight-line method based on estimated useful lives from 3 to 39 years.
Marketable Securities and Other Investments
Devon accounts for certain investments in debt and equity securities by following the requirements of Statement of Financial Accounting Standards ("SFAS") No. 115, "Accounting for Certain Investments in Debt and Equity Securities." This standard requires that, except for debt securities classified as "held-to-maturity," investments in debt and equity securities must be reported at fair value. As a result, Devon's investment in Chevron Corporation common stock, which is classified as "available for sale," is reported at fair value, with the tax effected unrealized gain or loss recognized in other comprehensive earnings and reported as a separate component of stockholders' equity. Devon's investments in other short-term securities are also classified as "available for sale."
Goodwill
Goodwill, which represents the excess of purchase price over the fair value of net assets acquired, is amortized by an equivalent unit-of-production method. Devon assesses the recoverability of this intangible asset by determining whether the amortization of the goodwill balance over its remaining life can be recovered through undiscounted future operating cash flows of the acquired properties. The amount of goodwill impairment, if any, is measured based on projected discounted future operating cash flows using a discount rate reflecting Devon's average cost of funds. The assessment of the recoverability of goodwill will be impacted if estimated future operating cash flows are not achieved.
Accumulated amortization of goodwill was $16.1 million at December 31, 1999.
Revenue Recognition and Gas Balancing
Oil and gas revenues are recognized when produced. During the course of normal operations, Devon and other joint interest owners of natural gas reservoirs will take more or less than their respective ownership share of the natural gas volumes produced. These volumetric imbalances are monitored over the lives of the wells' production capability. If an imbalance exists at the time the wells' reserves are depleted, cash settlements are made among the joint interest owners under a variety of arrangements.
Devon follows the sales method of accounting for gas imbalances. A liability is recorded when Devon's excess takes of natural gas volumes exceed its estimated remaining recoverable reserves. No
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
receivables are recorded for those wells where Devon has taken less than its ownership share of gas production.
Hedging Activities
Devon has periodically entered into oil and gas price swaps and foreign exchange rate swaps to manage its exposure to oil and gas price volatility. The foreign exchange rate swaps mitigate the effect of volatility in the Canadian-to-U.S. dollar exchange rate on Canadian oil revenues that are predominantly based on U.S. dollar prices. The hedging instruments are usually placed with counterparties that Devon believes are minimal credit risks. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by Devon.
Devon accounts for its hedging instruments using the deferral method of accounting. Under this method, realized gains and losses from Devon's price risk management activities are recognized in oil and gas revenues when the associated production occurs and the resulting cash flows are reported as cash flows from operating activities. Gains and losses on hedging contracts that are closed before the hedged production occurs are deferred until the production month originally hedged. In the event of a loss of correlation between changes in oil and gas reference prices under a hedging instrument and actual oil and gas prices, a gain or loss is recognized currently to the extent the hedging instrument has not offset changes in actual oil and gas prices.
Stock Options
Devon applies the intrinsic value-based method of accounting prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations, in accounting for its fixed plan stock options. As such, compensation expense would be recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. SFAS No. 123, "Accounting for Stock-Based Compensation," established accounting and disclosure requirements using a fair value-based method of accounting for stock-based employee compensation plans. As allowed by SFAS No. 123, Devon has elected to continue to apply the intrinsic value-based method of accounting described above, and has adopted the disclosure requirements of SFAS No. 123 which are included in Note 10.
Major Purchasers
In 1999, Columbia Energy Services Corporation accounted for 12% of Devon's combined oil, gas and natural gas liquids sales. Also, Aquila Energy Marketing Corporation accounted for 19% and 15% of Devon's combined oil, gas and natural gas liquids sales in 1998 and 1997, respectively.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
Income Taxes
Devon accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases, as well as the future tax consequences attributable to the future utilization of existing tax net operating loss and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. U.S. deferred income taxes have not been provided on Canadian earnings which are being permanently reinvested.
General and Administrative Expenses
General and administrative expenses are reported net of amounts allocated to working interest owners of the oil and gas properties operated by Devon and net of amounts capitalized pursuant to the full cost method of accounting.
Net Earnings Per Common Share
Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if Devon's dilutive outstanding stock options were exercised (calculated using the treasury stock method) or if Devon's Trust Convertible Preferred Securities were converted to common stock. Substantially all of Devon's Trust Convertible Preferred Securities were converted to common stock on November 30, 1999 (see Note 9).
The following table reconciles the net earnings and common shares outstanding used in the calculations of basic and diluted net earnings per share for the year 1999. The diluted loss per share calculations for 1998 and 1997 produce results that are anti-dilutive. (The diluted calculation for 1998 reduced the net loss by $6.0 million and increased the common shares outstanding by 5.5 million shares. The 1997 diluted calculation reduced the net loss by $6.0 million and increased the common shares outstanding by 5.6 million shares.) Therefore, the diluted loss per share amounts for 1998 and 1997 reported in the accompanying consolidated statements of operations are the same as the basic loss per share amounts.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
Options to purchase approximately 2.5 million shares of Devon's common stock, with exercise prices ranging from $36.28 per share to $92.78 per share (with a weighted average price of $52.74 per share), were excluded from the diluted earnings per share calculation for 1999. The excluded options for 1999 expire between April 26, 2000 and September 30, 2009. All options were excluded from the diluted earnings per share calculations for 1998 and 1997.
Comprehensive Earnings (Loss)
Devon adopted SFAS No. 130, "Reporting Comprehensive Income," on January 1, 1998. SFAS No. 130 was effective for fiscal years beginning after December 15, 1997. SFAS No. 130 established standards for reporting and display of comprehensive income and its components. Devon's comprehensive income information is included in the accompanying consolidated statements of stockholders' equity. A summary of accumulated other comprehensive loss as of December 31, 1999, 1998 and 1997, and changes during each of the years then ended, is presented in the following table.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
Foreign Currency Translation Adjustments
The assets and liabilities of certain foreign subsidiaries are prepared in their respective local currencies and translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates, while income and expenses are translated at average rates for the periods presented. Translation adjustments have no effect on net income and are included in accumulated other comprehensive loss.
Dividends
Dividends on Devon's common stock were paid in 1999, 1998 and 1997 at a per share rate of $0.05 per quarter. As adjusted for the Northstar Combination's pooling-of-interests method of accounting, annual dividends per share for 1998 and 1997 were $0.15 and $0.14, respectively.
Statements of Cash Flows
For purposes of the consolidated statements of cash flows, Devon considers all highly liquid investments with original maturities of three months or less to be cash equivalents.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
Commitments and Contingencies
Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
Environmental expenditures are expensed or capitalized in accordance with generally accepted accounting principles. Liabilities for these expenditures are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Reference is made to Note 13 for a discussion of amounts recorded for these liabilities.
Reclassifications
Certain of the 1998 and 1997 amounts in the accompanying consolidated financial statements have been reclassified to conform to the 1999 presentation.
2. BUSINESS COMBINATIONS AND PRO FORMA INFORMATION
PennzEnergy Merger
Devon closed its merger with PennzEnergy Company ("PennzEnergy") on August 17, 1999. The merger was accounted for using the purchase method of accounting for business combinations. Accordingly, the accompanying statement of operations for 1999 includes the effects of PennzEnergy operations since August 17, 1999.
Devon issued approximately 21.5 million shares of its common stock to the former stockholders of PennzEnergy. In addition, Devon assumed long-term debt and other obligations totaling approximately $2.3 billion on August 17, 1999. The calculation of the total purchase price and the preliminary allocation to assets and liabilities as of August 17, 1999, are shown below. Devon intends to sell certain of the assets acquired. Generally, the proceeds from such sales will reduce the gross purchase price allocated to oil and gas properties.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
Additionally, $338.9 million was added as goodwill for deferred taxes created as a result of the merger. Due to the tax-free nature of the merger, Devon's tax basis in the assets acquired and liabilities assumed are the same as PennzEnergy's tax basis. The $338.9 million of deferred taxes recorded represent the deferred tax effect of the differences between the fair values assigned by Devon for financial reporting purposes to the former PennzEnergy assets and liabilities and their bases for income tax purposes.
Estimated proved reserves added in the PennzEnergy merger were 232.7 million barrels of oil, 782.6 billion cubic feet of natural gas and 32.7 million barrels of natural gas liquids. Also, added in the PennzEnergy merger were approximately 13 million net acres of undeveloped leasehold. (The quantities of proved reserves stated in this paragraph are unaudited.)
Wascana Properties Transaction
On December 23, 1998, Devon acquired certain natural gas properties located in northeastern Alberta, Canada, from Wascana Oil and Gas Partnership, a subsidiary of Canadian Occidental Petroleums Ltd. (the "Wascana Properties"). Devon acquired the properties for
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
approximately $57.5 million, which was funded with bank debt under Devon's then existing credit facilities.
Estimated proved reserves of the Wascana Properties as of December 31, 1998, were 71.5 billion cubic feet of natural gas. Approximately $52.2 million of the purchase price was allocated to the proved reserves. The remaining $5.3 million of the purchase price was allocated to approximately 190,000 net undeveloped acres and exclusive rights to associated seismic data. (The quantities of proved reserves stated in this paragraph are unaudited.)
Pro Forma Information
Set forth in the following table is certain unaudited pro forma financial information for the years ended December 31, 1999 and 1998. This information has been prepared assuming the PennzEnergy merger and the Wascana Property transaction were consummated on January 1, 1998, and is based on estimates and assumptions deemed appropriate by Devon. The pro forma information is presented for illustrative purposes only. If the transactions 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 transactions had occurred on January 1, 1998. The pro forma information also should not be used as an indication of the future results that Devon will achieve after the transactions.
The pro forma information includes the effect of Devon's issuance of 10.3 million shares of common stock as if such shares had been issued on January 1, 1998. (See Note 10 for additional information on this issuance of shares of common stock.) The pro forma information assumes that the approximately $402 million of net proceeds from the issuance of common stock was used to retire long-term debt and therefore reduce interest expense.
The following should be considered in connection with the pro forma financial information presented:
o Expected annual cost savings of $50 to $60 million related to the PennzEnergy merger have not been reflected as an adjustment to the historical data in preparing the following pro forma information. These cost savings are expected to result from the consolidation of the corporate headquarters of Devon and PennzEnergy and the elimination of duplicate staff and expenses.
o The 1999 pro forma results include a gain of $46.7 million ($29.8 million after-tax) from PennzEnergy's pre-merger sale of land, timber and mineral rights in Pennsylvania and New York.
o In 1998, PennzEnergy realized pretax gains on the sale and exchange of Chevron Corporation common stock of $203.1 million. This gain is included in the 1998 pro forma financial information presented in the following table. The pro forma
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
financial information does not include the related $207.0 million after-tax extraordinary loss resulting from the early extinguishment of debt. The exclusion of the extraordinary loss from the 1998 pro forma results is required by Securities and Exchange Commission rules and regulations regarding presentation of pro forma results of operations, and is consistent with the pro forma results presented in the PennzEnergy merger proxy statement filed in 1999. If the extraordinary loss were included in the 1998 pro forma results, the 1998 pro forma net loss as presented in the following table would be $301 million, or $3.83 per share.
o The 1998 pro forma results include $24.3 million of nonrecurring general and administrative expenses in connection with the spin-off of Pennzoil-Quaker State Company on December 30, 1998.
o The 1998 pro forma results include a reduction of the carrying value of oil and gas properties incurred by Devon. This reduction, which was due to the full cost ceiling limitation, was $126.9 million ($88.0 million after-tax).
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
Northstar Combination
On June 29, 1998, Devon and Northstar Energy Corporation ("Northstar") announced they had entered into a definitive combination agreement subject to shareholder approval and certain other conditions. The combination of the two companies (the "Northstar Combination") was closed on December 10, 1998. At that date, Northstar became a wholly-owned subsidiary of Devon. Pursuant to the Northstar Combination, Northstar's common shareholders received approximately 16.1 million exchangeable shares (the "Exchangeable Shares") based on an exchange ratio of 0.235 Exchangeable Shares for each Northstar common share outstanding. The Exchangeable Shares were issued by Northstar, but are exchangeable at any time into Devon's common shares on a one-for-one basis. Prior to such exchange, the Exchangeable Shares have rights identical to those of Devon's common shares, including dividend, voting and liquidation rights. Between December 10, 1998 and December 31, 1999, approximately 11.4 million of the originally issued 16.1 million Exchangeable Shares had been exchanged for shares of Devon common stock.
The Northstar Combination was accounted for under the pooling-of-interests method of accounting for business combinations. All operational and financial information contained herein includes the combined amounts for Devon and Northstar for all periods presented.
During the fourth quarter of 1998, Devon recorded a pre-tax charge of $13.1 million ($9.7 million after tax) for direct costs related to the Northstar Combination.
Morrison Transaction
In March 1997, Northstar acquired all the outstanding common shares of Morrison Petroleums Ltd. ("Morrison"), an independent oil and gas producer also located in Alberta, Canada. Northstar acquired the Morrison common shares by issuing common shares of Northstar (the "Morrison Transaction"). The Northstar common shares received by the Morrison shareholders represented approximately 53% of the combined company's outstanding shares. Therefore, this transaction was accounted for as a reverse acquisition under U.S. generally accepted accounting principles. Accordingly, Northstar's results through March 31, 1997, which are combined with Devon's results in the accompanying consolidated financial statements, represent the historical results of Morrison, the "accounting acquirer." Because Northstar was the "legal acquirer," the financial results and other information for periods through March 31, 1997, are referred to as "Northstar's" results and information, even though they represent the historical results of Morrison. For periods subsequent to March 31, 1997, Northstar's results that are combined with Devon's results represent the historical results of Morrison, combined with Northstar's results after valuing Northstar's March 31, 1997, assets and liabilities at fair value, rather than historical book value.
The estimated proved reserves added in the Morrison Transaction were 18.3 million barrels of oil, 213.5 billion cubic feet of natural gas and 2.9 million barrels of natural gas liquids.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
Also added in the Morrison Transaction were approximately 563,000 net acres of undeveloped leasehold. (The quantities of proved reserves stated in this paragraph are unaudited.)
After giving effect to the Northstar Combination exchange ratio of 0.235, approximately 9.8 million Exchangeable Shares are deemed to have been issued in the Morrison Transaction with a total value of approximately $441.6 million. Also, approximately $111.3 million of liabilities were assumed and $128.5 million of additional deferred tax liabilities were recorded due to the tax-free nature of the Morrison Transaction to the Morrison shareholders. Excluding the $128.5 million of additional deferred tax liabilities, the total purchase price was allocated $435.2 million to proved oil and gas reserves, $37.3 million to undeveloped leasehold and $80.4 million to other assets acquired. Including the $128.5 million of deferred tax liabilities, the allocation was $527.9 million to proved oil and gas reserves, $43.5 million to undeveloped leasehold and $110.0 million to other assets.
3. SAN JUAN BASIN TRANSACTION
At the beginning of 1995, Devon entered into a transaction (the "San Juan Basin Transaction") involving a volumetric production payment and repurchase option. The San Juan Basin Transaction allowed Devon to monetize tax credits earned from certain of its coal seam gas production in the San Juan Basin. During 1999, 1998 and 1997, the San Juan Basin Transaction added approximately $7.6 million, $8.4 million and $8.5 million, respectively, to Devon's gas revenues.
Under the terms of the San Juan Basin Transaction, Devon has a repurchase option which it can exercise at anytime. Devon records a portion of the quarterly cash payments received pursuant to the San Juan Basin Transaction as a repurchase liability based upon the estimated eventual repurchase price. Devon has also received cash payments in exchange for agreeing not to exercise its repurchase option for specific periods of time. These payments have also been added to the repurchase liability. As a result, in addition to the cash flow recorded as revenues described in the previous paragraph, Devon also received $16.6 million, $6.8 million and $6.2 million in 1999, 1998 and 1997, respectively, which was added to the repurchase liability. At December 31, 1999, the repurchase liability totaled $37.6 million. This amount is included in other long-term liabilities in Devon's consolidated balance sheet.
The additional gas revenues generated by the San Juan Basin Transaction will continue until December 31, 2002, unless Devon exercises its repurchase option earlier.
4. SUPPLEMENTAL CASH FLOW INFORMATION
Cash payments for interest in 1999, 1998 and 1997 were approximately $63.3 million, $24.5 million and $16.7 million, respectively. Cash payments for federal, state and foreign income taxes in 1999, 1998 and 1997 were approximately $10.8 million, $14.2 million and $26.9 million, respectively.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
The 1999 PennzEnergy merger and the 1997 Morrison Transaction involved non-cash consideration as presented below:
During the fourth quarter of 1999, substantially all of the 6.5% Trust Convertible Preferred Securities were converted to Devon common stock (see Note 9).
5. ACCOUNTS RECEIVABLE
The components of accounts receivable included the following:
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
6. PROPERTY AND EQUIPMENT
Property and equipment included the following:
Depreciation, depletion and amortization of property and equipment consisted of the following components:
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
7. LONG-TERM DEBT AND RELATED EXPENSES
A summary of Devon's long-term debt is as follows:
Maturities of long-term debt as of December 31, 1999, excluding the $37.5 million of premiums, are as follows (in thousands):
(a) A discussion of pro forma debt outstanding is included later in this note.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
Credit Facilities With Banks
On October 15, 1999, Devon entered into new unsecured long-term credit facilities aggregating $750 million (the "Credit Facilities"). The Credit Facilities include a U.S. facility of $475 million (the "U.S. Facility") and a Canadian facility of $275 million (the "Canadian Facility"). The Credit Facilities replaced Devon's previous facilities that totaled $400 million.
The $475 million U.S. Facility consists of a Tranche A facility of $200 million and a Tranche B facility of $275 million. The Tranche A facility matures on October 15, 2004. Devon may borrow funds under the Tranche B facility until October 13, 2000 (the "Tranche B Revolving Period"). Devon may request that the Tranche B Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 30 and 60 days prior to the end of the Tranche B Revolving Period. Debt borrowed under the Tranche B facility matures two years and one day following the end of the Tranche B Revolving Period. At December 31, 1999, there were $200 million in borrowings from the $475 million U.S. Facility, all of which was borrowed under the Tranche A facility.
Devon may borrow funds under the $275 million Canadian Facility until October 13, 2000 (the "Canadian Facility Revolving Period"). Devon may request that the Canadian Facility Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 45 and 90 days prior to the end of the Canadian Facility Revolving Period. Debt outstanding as of the end of the Canadian Facility Revolving Period is payable in semi-annual installments of 2.5% each for the following five years, with the final installment due five years and one day following the end of the Canadian Facility Revolving Period. At December 31, 1999, there was $114.3 million borrowed under the $275 million Canadian facility.
Amounts borrowed under the Credit Facilities bear interest at various fixed rate options that Devon may elect for periods up to six months. Such rates are generally less than the prime rate. Devon may also elect to borrow at the prime rate. The Credit Facilities provide for an annual facility fee of $0.9 million that is payable quarterly. The average interest rate on the $314.3 million of debt outstanding at December 31, 1999, was 5.9%. The average interest rate on bank debt outstanding under the previous facilities at December 31, 1998 and 1997 was 5.9% and 4.8%, respectively.
The agreements governing the Credit Facilities contain certain covenants and restrictions, including a maximum debt-to-capitalization ratio. At December 31, 1999, Devon was in compliance with such covenants and restrictions.
Exchangeable Debentures
The exchangeable debentures consist of $443.8 million of 4.90% debentures and $316.5 million of 4.95% debentures. The exchangeable debentures were issued on August 3, 1998, mature August 15, 2008, and are callable beginning August 15, 2000. The exchangeable
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
debentures are exchangeable at the option of the holders at any time prior to maturity, unless previously redeemed, for shares of Chevron Corporation common stock. In lieu of delivering Chevron Corporation common stock, Devon may, at its option, pay to any holder an amount of cash equal to the market value of the Chevron Corporation common stock to satisfy the exchange request. However, at maturity, the holders will receive an amount at least equal to the face value of the debt outstanding - either in cash or in a combination of cash and Chevron Corporation common stock.
As of December 31, 1999, Devon beneficially owned approximately 7.1 million shares of Chevron Corporation common stock. These shares have been deposited with an exchange agent for possible exchange for the exchangeable debentures. Each $1,000 principal amount of the exchangeable debentures is exchangeable into 9.3283 shares of Chevron Corporation common stock, an exchange rate equivalent to $107 7/32 per share of Chevron stock.
The exchangeable debentures were assumed as part of the PennzEnergy merger. The fair values of the exchangeable debentures were determined as of August 17, 1999, based on market quotations. The fair value approximated the face value of the exchangeable debentures. As a result, no premium or discount was recorded on these exchangeable debentures.
Other Debentures
The 10.25% and 10.125% debentures were assumed as part of the PennzEnergy merger. The fair values of the respective debentures were determined using August 17, 1999, market interest rates. As a result, premiums were recorded on these debentures which lowered their effective interest rates to 8.3% and 8.9% on the $250 million of 10.25% debentures and $200 million of 10.125% debentures, respectively. The premiums are being amortized using the effective interest method.
Senior Notes
Northstar issued the 6.76% notes in a private placement in 1995. The notes were unsecured and were payable in five annual installments of $15 million each beginning in 2001. In mid-January 2000, Devon retired these notes. See the "Pro Forma" section below.
Northstar issued the 6.79% notes in a private placement in 1998. The notes were unsecured and were payable in three annual installments of $50 million each beginning in 2007. Proceeds from these notes were partially used to retire the $60 million of 7.03% notes referred to in the preceding table of long-term debt. In mid-January 2000, Devon retired these notes. See the "Pro Forma" section below.
The agreements governing the Senior Notes contained certain covenants and restrictions specific to Northstar, including maintenance of certain debt-to-capitalization and debt-to-EBITDA ratios and a minimum tangible net worth as well as restrictions on additional
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
borrowings. At December 31, 1999, Northstar was in compliance with such covenants and restrictions.
Pro Forma
In January 2000, Devon used excess cash of $75 million, together with borrowings of $150 million under its Credit Facilities, to retire the $225 million of Senior Notes outstanding as of December 31, 1999. Also in January 2000, Devon used an additional $50 million of excess cash to pay down borrowings under Tranche A of the U.S. Facility. The result of these early 2000 transactions left $414.3 million outstanding under the Credit Facilities. Of this amount, $150 million was borrowed under Tranche A of the U.S. Facility, $75 million was borrowed under Tranche B of the U.S. Facility and $189.3 million was borrowed under the Canadian Facility. The average interest rate on the $414.3 million of pro forma debt outstanding under the Credit Facilities was 5.9%.
Interest Expense
Following are the components of interest expense for the years 1999, 1998 and 1997:
Deferred Effect of Changes in Foreign Currency Exchange Rate on Long-term Debt
The fixed-rate Senior Notes referred to in the first table of this note were payable by Northstar. However, the notes were denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the Canadian dollar from the dates the notes were issued to the dates of repayment increased or decreased the expected amount of Canadian dollars eventually required to repay the notes. Such changes in the Canadian dollar equivalent of the debt were required to be included in determining net earnings for the period in which the exchange rate changed. The rate of conversion of Canadian dollars to U.S. dollars increased in 1999 and declined in 1998 and 1997. Therefore, $13.2 million of reduced expense was recorded in 1999, and $16.1 million and $5.9 million of increased expenses were recorded in 1998 and 1997, respectively.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
8. INCOME TAXES
At December 31, 1999, Devon had the following carryforwards available to reduce future income taxes:
All of the carryforward amounts shown above have been utilized for financial purposes to reduce deferred taxes.
The earnings (loss) before income taxes and the components of income tax expense (benefit) for the years 1999, 1998 and 1997 were as follows:
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
Total income tax expense differed from the amounts computed by applying the U.S. federal income tax rate to earnings (loss) before income taxes as a result of the following:
The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 1999, 1998 and 1997 are presented below:
As shown in the above schedule, Devon has recognized $310.3 million of net deferred tax assets as of December 31, 1999. Such amount consists primarily of $226.3 million of various
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
carryforwards available to offset future income taxes. The carryforwards include federal net operating loss carryforwards, the majority of which do not begin to expire until 2008, state net operating loss carryforwards which expire primarily between 2000 and 2013, Canadian carryforwards which expire primarily between 2000 and 2005, and minimum tax credit carryforwards which have no expiration. The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be "more likely than not." When the future utilization of some portion of the carryforwards is determined not to be "more likely than not," a valuation allowance is provided to reduce the recorded tax benefits from such assets.
Devon expects the tax benefits from the net operating loss carryforwards to be utilized between 2000 and 2006. 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 federal 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 expiration. A $0.1 million valuation allowance has been recorded at December 31, 1999, related to depletion carryforwards acquired in a 1994 merger.
The $21.5 million of deferred tax assets related to production payments is offset by a portion of the deferred tax liability related to the excess financial basis of property and equipment. The income tax accounting for the San Juan Basin Transaction described in Note 3 differs from the financial accounting treatment. For income tax purposes, a gain from the conveyance of the properties was realized, and the present value of the production payments to be received was recorded as a note receivable. For presentation purposes, the $21.5 million represents the tax effect of the difference in accounting for the production payment, less the effect of the taxable gain from the transaction which is being deferred and recognized on the installment basis for income tax purposes.
9. TRUST CONVERTIBLE PREFERRED SECURITIES
On July 10, 1996, Devon, through its affiliate Devon Financing Trust, completed the issuance of $149.5 million of 6.5% trust convertible preferred securities (the "TCP Securities"). Devon Financing Trust issued 2,990,000 shares of the TCP Securities at $50 per share with a maturity date of June 15, 2026. Each TCP Security was convertible at the holder's option into 1.6393 shares of Devon common stock, which equates to a conversion price of $30.50 per share of Devon common stock.
Devon Financing Trust invested the $149.5 million of proceeds in 6.5% convertible junior subordinated debentures issued by Devon (the "Convertible Debentures"). In turn, Devon used the net proceeds from the issuance of the Convertible Debentures to retire debt outstanding under its credit lines.
On October 27, 1999, Devon issued notice to the holders of the TCP Securities that it was
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
exercising its right to redeem such securities on November 30, 1999. Substantially all of the holders of the TCP Securities elected to exercise their conversion rights instead of receiving the redemption cash value. As a result, all but 950 shares of the TCP Securities were converted into approximately 4.9 million shares of Devon common stock. The redemption price for the 950 shares not converted was $52.275 per share, or $50,000 total, which included a 4.55% premium as required under the terms of the TCP Securities.
Devon owned all the common securities of Devon Financing Trust. As such, the accounts of Devon Financing Trust were included in Devon's consolidated financial statements after appropriate eliminations of intercompany balances and transactions. The distributions on the TCP Securities were recorded as a charge to pre-tax earnings on Devon's consolidated statements of operations, and such distributions were deductible by Devon for income tax purposes.
10. STOCKHOLDERS' EQUITY
The authorized capital stock of Devon consists of 400 million shares of common stock, par value $.10 per share (the "Common Stock"), and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors.
Effective August 17, 1999, Devon issued 1.5 million shares of 6.49% cumulative preferred stock, Series A, to holders of PennzEnergy 6.49% cumulative preferred stock, Series A. Dividends on the preferred stock are cumulative from the date of original issue and are payable quarterly, in cash, when declared by the Board of Directors. The preferred stock is redeemable at the option of Devon at any time on or after June 2, 2008, in whole or in part, at a redemption price of $100 per share, plus accrued and unpaid dividends to the redemption date.
In late September and early October 1999, Devon received $402.7 million from the sale of approximately 10.3 million shares of its common stock in a public offering. The price to the public for these shares was $40.50 per share. Net of underwriters' discount and commissions, Devon received $38.98 per share. Devon paid approximately $0.8 million of expenses related to the equity offering, and these costs were recorded as reductions of additional paid-in capital.
As discussed in Note 2, there were approximately 21.5 million shares of Devon common stock issued on August 17, 1999, in connection with the PennzEnergy merger. Also, as discussed in Note 2, there were 16.1 million Exchangeable Shares issued on December 10, 1998, in connection with the Northstar Combination. As of year-end 1999, 11.4 million of the Exchangeable Shares had been exchanged for shares of Devon's common stock. The Exchangeable Shares have rights identical to those of Devon's common stock and are exchangeable at any time into Devon's common stock on a one-for-one basis.
Devon's Board of Directors has designated 1.0 million shares of the preferred stock as Series A Junior Participating Preferred Stock (the "Series A Junior Preferred Stock") in connection with the
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
adoption of the share rights plan described later in this note. At December 31, 1999, there were no shares of Series A Junior Preferred Stock issued or outstanding. The Series A Junior Preferred Stock is entitled to receive cumulative quarterly dividends per share equal to the greater of $10 or 100 times the aggregate per share amount of all dividends (other than stock dividends) declared on Common Stock since the immediately preceding quarterly dividend payment date or, with respect to the first payment date, since the first issuance of Series A Junior Preferred Stock. Holders of the Series A Junior Preferred Stock are entitled to 100 votes per share (subject to adjustment to prevent dilution) on all matters submitted to a vote of the stockholders. The Series A Junior Preferred Stock is neither redeemable nor convertible. The Series A Junior Preferred Stock ranks prior to the Common Stock but junior to all other classes of Preferred Stock.
Stock Option Plans
Devon has outstanding stock options issued to key management and professional employees under three stock option plans adopted in 1988, 1993 and 1997 (the "1988 Plan," the "1993 Plan" and the "1997 Plan"). Options granted under the 1988 Plan and 1993 Plan remain exercisable by the employees owning such options, but no new options will be granted under these plans. At December 31, 1999, there were 189,000 and 740,500 options outstanding under the 1988 Plan and the 1993 Plan, respectively.
On May 21, 1997, Devon's stockholders adopted the 1997 Plan and reserved two million shares of Common Stock for issuance thereunder. On December 9, 1998, Devon's stockholders voted to increase the reserved shares to three million. On August 17, 1999, Devon's stockholders voted to increase the reserved shares to six million.
The exercise price of stock options granted under the 1997 Plan may not be less than the estimated fair market value of the stock at the date of grant, plus 10% if the grantee owns or controls more than 10% of the total voting stock of Devon prior to the grant. Options granted are exercisable during a period established for each grant, which period may not exceed 10 years from the date of grant. Under the 1997 Plan, the grantee must pay the exercise price in cash or in Common Stock, or a combination thereof, at the time that the option is exercised. The 1997 Plan is administered by a committee comprised of non-management members of the Board of Directors. The 1997 Plan expires on April 25, 2007. As of December 31, 1999, there were 2,142,150 options outstanding under the 1997 Plan. There were 3,725,550 options available for future grants as of December 31, 1999.
In addition to the stock options outstanding under the 1988 Plan, 1993 Plan and 1997 Plan, there were 2,081,124 and 226,571 stock options outstanding at the end of 1999 that were assumed as part of the PennzEnergy merger and the Northstar Combination, respectively. PennzEnergy and Northstar had granted these options prior to the PennzEnergy merger and the Northstar Combination. As part of the PennzEnergy merger and the Northstar Combination, the options were assumed by Devon and converted to Devon options at the exchange rate of 0.4475 and 0.235 Devon options for each PennzEnergy and Northstar option, respectively.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
A summary of the status of Devon's stock option plans as of December 31, 1997, 1998 and 1999, and changes during each of the years then ended, is presented below.
The weighted average fair values of options granted during 1999, 1998 and 1997 were $10.23, $10.72 and $10.12, respectively. The fair value of each option grant was estimated for disclosure purposes on the date of grant using the Black-Scholes Option Pricing Model with the following assumptions for 1999, 1998 and 1997, respectively: risk-free interest rates of 6.0%, 4.9% and 6.0%; dividend yields of 0.6%, 0.5% and 0.1%; expected lives of 4, 4 and 4 years; and volatility of the price of the underlying common stock of 34.2%, 33.9% and 30.7%.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
The following table summarizes information about Devon's stock options which were outstanding, and those which were exercisable, as of December 31, 1999:
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 1999, 1998 and 1997 pro forma net earnings (loss) and pro forma net earnings (loss) per share would have differed from the amounts actually reported as shown in the following table. The pro forma amounts shown below do not include the effects of stock options granted prior to January 1, 1995.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
Share Rights Plan
Under Devon's share rights plan, stockholders have one right for each share of Common Stock held. The rights become exercisable and separately transferable ten business days after a) an announcement that a person has acquired, or obtained the right to acquire, 15% or more of the voting shares outstanding, or b) commencement of a tender or exchange offer that could result in a person owning 15% or more of the voting shares outstanding.
Each right entitles its holder (except a holder who is the acquiring person) to purchase either a) 1/100 of a share of Series A Preferred Stock for $75.00, subject to adjustment or b) Devon Common Stock with a value equal to twice the exercise price of the right, subject to adjustment to prevent dilution. In the event of certain merger or asset sale transactions with another party or transactions which would increase the equity ownership of a shareholder who then owned 15% or more of Devon, each Devon right will entitle its holder to purchase securities of the merging or acquiring party with a value equal to twice the exercise price of the right.
The rights, which have no voting power, expire on April 16, 2005. The rights may be redeemed by Devon for $.01 per right until the rights become exercisable.
11. FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair values of Devon's financial instruments at December 31, 1999, 1998 and 1997.
The following methods and assumptions were used to estimate the fair values of the financial instruments in the above table. None of Devon's financial instruments are held for trading purposes. The carrying values of cash and cash equivalents, accounts receivable and accounts payable (including income taxes payable and accrued expenses) included in the accompanying consolidated balance sheets approximated fair value at December 31, 1999, 1998 and 1997.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
Investments - The fair values of investments are primarily based on quoted market prices.
Oil and Gas Price Hedge Agreements - The fair values of the oil and gas price hedges are based on either (a) quotes obtained from the counterparty to the hedge agreement or (b) quotes provided by brokers.
Foreign Exchange Hedge Agreements - The fair values of the foreign exchange agreements are based on quotes obtained from brokers.
Long-term Debt - The fair values of the fixed-rate long-term debt have been estimated based on quotes obtained from brokers or by discounting the principal and interest payments at rates available for debt of similar terms and maturity. The fair values of the floating-rate long-term debt are estimated to approximate the carrying amounts due to the fact that the interest rates paid on such debt are generally set for periods of three months or less.
TCP Securities - The fair values of the TCP Securities are based on quoted market prices provided by brokers.
The following table covers Devon's notional volumes and pricing on open natural gas hedging instruments as of December 31, 1999:
The floating reference prices which Devon will pay the counterparties to the above gas price hedging instruments include several index prices based upon the area of the gas production that is hedged. For the hedged Canadian gas production, these reference prices are primarily based on index prices published by the Alberta Energy Company ("AECO"). For the hedged U.S. production, the reference prices are primarily based on index prices published by "Inside FERC" for the Rocky Mountains and San Juan Basin.
Devon has certain foreign currency hedging instruments that offset a portion of the exposure to currency fluctuations on Canadian oil sales that are based on U.S. dollar prices. Gains and losses recognized on these foreign currency hedging instruments are included as increases or decreases to realized oil sales. As of December 31, 1999, Devon had open foreign currency hedging instruments in which it will sell $30 million in 2000 at
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
average Canadian-to-U.S. dollar exchange rates of $0.7265. A portion of these hedging instruments can be extended an additional year at the option of the counterparty. If such options are exercised, Devon will sell an additional $10 million in 2001 at average Canadian-to-U.S. dollar exchange rates of $0.7102. Under these agreements, Devon will buy the same amount of dollars in each year at the floating exchange rate.
Devon's 1999, 1998 and 1997 consolidated balance sheets include deferred revenues of $0.4 million, $1.0 million and $3.8 million, respectively, for gains realized on the early termination of commodity and foreign currency hedging instruments in prior years. These deferred gains as of the end of 1999 will be recognized as oil and gas sales over periods ranging from ten months to one year as the hedged oil and gas production occurs.
12. RETIREMENT PLANS
Devon has non-contributory defined benefit retirement plans (the "Basic Plans") which include U.S. employees meeting certain age and service requirements. The benefits are based on the employee's years of service and compensation. Devon's funding policy is to contribute annually the maximum amount that can be deducted for federal income tax purposes. Rights to amend or terminate the Basic Plans are retained by Devon.
Devon also has separate defined benefit retirement plans (the "Supplementary Plans") which are non-contributory and include only certain employees whose benefits under the Basic Plans are limited by income tax regulations. The Supplementary Plans' benefits are based on the employee's years of service and compensation. Devon's funding policy for the Supplementary Plans is to fund the benefits as they become payable. Rights to amend or terminate the Supplementary Plans are retained by Devon.
Additionally, Devon assumed responsibility for the PennzEnergy sponsored defined benefit postretirement plans, which are unfunded, and cover substantially all of the former PennzEnergy employees who remained with Devon. Devon did not extend these benefits to other employees. The plans provide medical and life insurance benefits and are, depending on the type of plan, either contributory or non-contributory. The accounting for the health care plan anticipates future cost-sharing changes that are consistent with Devon's expressed intent to increase, where possible, contributions for future retirees. Furthermore, future contributions for both current and future salaried retirees have been limited to 200% of the 1992 retiree premium rates. Retirees will be required to absorb all future cost increases over that limit.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
The following table sets forth the plans' benefit obligations, plan assets, reconciliation of funded status, amounts recognized in the consolidated balance sheets and the actuarial assumptions used as of December 31:
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
The benefit obligation for the defined benefit pension plans with benefit obligations in excess of assets was $8.0 million as of December 31, 1999. No plan assets existed for these plans at December 31, 1999.
Net periodic benefit cost included the following components:
For measurement purposes, a 7% annual rate of increase in the per capita cost of covered health care benefits was assumed in 2000. The rate was assumed to decrease on a pro-rata basis annually to 5% in the year 2002 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. A one percentage-point change in assumed health care cost trend rates would have the following effects:
As a result of the PennzEnergy merger, Devon assumed certain postemployment benefits to former or inactive employees who are not retirees. These benefits include salary continuance, severance and disability health care and life insurance which are accounted for under SFAS No. 112, "Employer's Accounting for Postemployment Benefits." The accrued postemployment benefit liability was approximately $2.5 million at the end of 1999.
Devon has a 401(k) Incentive Savings Plan which covers all domestic employees. At its discretion, Devon may match a certain percentage of the employees' contributions to the plan. The matching percentage is determined annually by the Board of Directors. Devon's matching contributions to the plan were $2.7 million, $1.0 million and $0.5 million for the years ended December 31, 1999, 1998 and 1997, respectively.
Devon has defined contribution plans for its Canadian employees. Devon contributes between 6% and 10% of the employee's base compensation, depending upon the employee's classification. Such contributions are subject to maximum amounts allowed under the Income Tax Act (Canada).
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
Devon also has a savings plan for its Canadian employees. Under the savings plan, Devon contributes an amount equal to 2% of the base salary of each employee. The employees may elect to contribute up to 4% of their salary. If such employee contributions are made, they are matched by additional Devon contributions.
During the years 1999, 1998 and 1997, Devon's combined contributions to the Canadian defined contribution plan and the Canadian savings plan were $1.9 million, $1.8 million and $1.2 million, respectively.
13. 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.
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 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 the PennzEnergy merger 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 December 31, 1999, Devon's consolidated balance sheet included $6.7 million of accrued liabilities, reflected in "Other liabilities," for environmental remediation. 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) the availability of defenses to liability, including the availability of the "petroleum exclusion" under CERCLA and similar state laws, and/or (ii) Devon's current belief that its share of wastes at a particular site is or will be
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
viewed by the Environmental Protection Agency or other PRPs as being de minimis. As a result, Devon's monetary exposure is not expected to be material.
Ramco Dispute
In October 1995, subsidiaries of Devon acquired in the PennzEnergy merger filed an action, styled Pennzoil Exploration and Production Company, et al. v. Ramco Energy Limited and Ramco Hazar Energy Limited, in the United States District Court for the Southern District of Texas, Houston Division, against Ramco Hazar Energy Limited, formerly known as Ramco Energy Limited (collectively "Ramco"). The underlying dispute involves Ramco's asserted claim to an interest in the Karabakh prospect, an oil and gas field located in the territorial waters of the Azerbaijan Republic in the Caspian Sea. Since the initiation of the litigation, the operator of the Karabakh prospect determined that the hydrocarbon accumulation tested by three exploratory wells was not commercial. The federal suit sought to compel Ramco to arbitrate certain disputes that have arisen between it and the Devon plaintiffs pursuant to the Federal Arbitration Act and the Convention on the Recognition and Enforcement of Foreign Arbitral Awards. After the filing of the federal action, the Devon plaintiffs filed an Original Petition for Declaration Relief in the 281st Judicial District Court of Harris County, Texas. The state suit, styled Pennzoil Exploration and Production Company, et al. v. Ramco Energy Limited and Ramco Hazar Energy Limited, which is expressly conditioned upon a determination in the federal suit that the disputes between the Devon plaintiffs and Ramco are not subject to arbitration, seeks a declaration that the Devon plaintiffs have not breached any agreements with Ramco, and do not owe and/or have not breached any fiduciary or other legal duty to Ramco including, without limitation, a duty of good faith and fair dealing. In November 1995, Ramco asserted a counterclaim in the state court action, asserting breach of contract and breach of fiduciary duties. The counterclaim seeks a declaratory judgment granting Ramco a participation interest in the Karabakh prospect, compensatory damages, exemplary damages, attorneys' fees, court costs and other unspecified relief.
The judge in the federal suit granted in part the plaintiffs' motion to compel arbitration and ordered arbitration to be held in New York, New York. The United States Court of Appeals for the Fifth Circuit generally affirmed the ruling of the judge in the federal suit and the Devon plaintiffs initiated arbitration. The parties have been engaged in settlement discussions and the selection of arbitrators has been suspended by agreement of the parties pending the outcome of the settlement discussions.
Royalty Matters
More than 30 oil companies, including Devon as a result of the PennzEnergy merger, are involved in disputes in which it is alleged that the oil companies and related parties have underpaid holders of royalty interests, overriding royalty interests and working interests in connection with the production of crude oil. The proceedings include suits in federal court in Texas, Louisiana, Mississippi and Wyoming (that have been consolidated into one proceeding in Texas) and in state court in Texas, Utah, Alabama and Louisiana. Certain parties to the federal litigation have entered into a global settlement agreement which provides for a conditional nationwide settlement, subject to opt-outs, of
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
the crude oil royalty, overriding royalty and working interest claims of all members of the settlement class, including claims in the federal litigation and in numerous other individual and class action cases pending throughout the United States. The federal court held a fairness hearing April 5, 1999, and the settlement was approved. The Amended Final Judgment was entered September 10, 1999. However, certain entities have appealed their objections to the settlement. Devon is a party to the settlement agreement, which explicitly refutes an admission of liability, but was entered into to avoid expensive and protracted litigation.
Also, pending is a separate suit in federal court in Texas alleging that more than 30 major oil companies, including Devon as a result of the PennzEnergy merger, underpaid royalties to the United States in connection with crude oil produced from United States owned and/or controlled lands since 1986. The claims were filed by private litigants under the federal False Claims Act, and after investigation, the United States served notice of its intent to intervene as to certain defendants. Devon has reached an agreement in principle with the United States and the private litigants to settle the claims made in the case. Devon believes that it has acted reasonably and paid royalties in good faith, but has entered into the settlement agreement, which explicitly refutes an admission of liability, to avoid expensive and protracted litigation. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the liability recognized for such settlement of the royalty matters.
Maersk Rig Contracts
In December 1997, Pennzoil Venezuela Corporation, S.A. ("PVC"), a subsidiary of Devon as a result of the PennzEnergy merger, entered into a contract ("Contract #1") with Maersk Jupiter Drilling, S.A. ("Maersk") for the provision of a rig for drilling services relative to the anticipated drilling program associated with Devon's Block 68/79, Lake Maracaibo, Venezuela. The rig to be provided by Maersk was to be assembled and delivered to the Lake Maracaibo area and placed in service in October 1998. The term of Contract #1 was to October 1, 2001. A companion contract ("Contract #2") with Maersk for a second rig with a similar term for use in conjunction with the Block 70/80 drilling program was also executed by PVC's working interest partner in that Block.
With execution of Contract #1, construction of the rig destined for Block 68/79 proceeded until completion thereof. In October 1998, Maersk advised that it intended to commence mobilization of the rig to Lake Maracaibo. However, during the period of rig construction, changes had occurred in the scope and timing of the drilling program anticipated for Block 68/79, resulting in significant reduction of the need for drilling services originally envisioned in Contract #1. PVC instructed Maersk to cease mobilization and to stack the rig in Brownsville, Texas, where it currently remains.
The rig built for Contract #2 was delivered to Lake Maracaibo where it performed an abbreviated drilling program for both Blocks 68/79 and 70/80. It is currently stacked in Lake Maracaibo.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
While both Contract #1 and #2 provide for early termination, the charge for such termination is established in each contract as the "Contract Standby Rate" which is currently estimated at $42,000 per day, per contract, with certain escalation factors for the balance of the term of each. Representatives of PVC and Maersk are engaged in negotiations relative to termination/settlement of both Contract #1 and Contract #2. As of December 31, 1999, Devon's consolidated balance sheet included accrued liabilities, reflected in "Other liabilities," for the expected cost to terminate/settle both Contract #1 and Contract #2. This liability was recorded at the time of the PennzEnergy merger. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the liability recognized for such termination/settlement of both Contract #1 and Contract #2.
Operating Leases
The following is a schedule by year of future minimum rental payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 1999:
Total rental expense for all operating leases is as follows for the years ended December 31:
14. REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES
Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated "ceiling." The ceiling limitation is the discounted estimated after-tax future net revenues from proved oil and gas properties. The ceiling is imposed separately by country. In calculating future net revenues, current prices and costs are generally held constant indefinitely. The net book value, less deferred tax liabilities, is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less deferred taxes, is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
As of September 30, 1998, the carrying value of Devon's domestic properties, less deferred income taxes, exceeded the full cost ceiling by $88 million. Accordingly, a $126.9 million pre-tax reduction of the carrying value of such properties was recorded in the third quarter of 1998. This reduction was partially offset by a related $38.9 million deferred income tax benefit, resulting in an after-tax charge of $88 million.
As of December 31, 1997, the carrying value of Northstar's Canadian oil and gas properties, less deferred income taxes, exceeded the full cost ceiling by $397.9 million. Accordingly, a $625.5 million pre-tax reduction of the carrying value of such properties was recorded in the fourth quarter of 1997. This reduction was partially offset by a related $227.6 million deferred income tax benefit, resulting in an after-tax charge of $397.9 million.
15. OIL AND GAS OPERATIONS
Costs Incurred
The following tables reflect the costs incurred in oil and gas property acquisition, exploration, and development activities:
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
Pursuant to the full cost method of accounting, Devon capitalizes certain of its general and administrative expenses which are related to property acquisition, exploration and development
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $18.7 million, $9.6 million and $7.5 million in the years 1999, 1998 and 1997, respectively.
Due to the tax-free nature of the PennzEnergy merger, additional deferred tax liabilities of $338.9 million were recorded in 1999 and allocated to goodwill.
During 1997, various uncertainties that existed at year-end 1996 regarding the tax basis and liabilities assumed in the acquisition of Kerr-McGee Corporation's North American onshore oil and gas exploration and production business and properties ("KMG-NAOS") were resolved. This resulted in an additional $5.5 million being allocated in 1997 to the proved properties acquired in the 1996 KMG-NAOS transaction. Of this amount, $3.1 million was for liabilities assumed and $2.4 million was for additional deferred tax liabilities created. This additional $5.5 million is included in the preceding table of costs incurred in 1997. The resolution of the uncertainties also resulted in a reduction of $0.1 million in 1997 to the deferred tax liabilities originally allocated in 1996 to the KMG-NAOS unproved properties.
Due to the tax-free nature of the Morrison Transaction, additional deferred tax liabilities of $128.5 million were recorded in 1997. Of this amount, $92.7 million was allocated to proved oil and gas properties and $6.2 million was allocated to unproved properties. The remaining amount of $29.6 million was allocated to non-oil and gas properties.
Results of Operations for Oil and Gas Producing Activities
The following tables include revenues and expenses associated directly with Devon's oil and gas producing activities. They do not include any allocation of Devon's interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Devon's oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil and gas sales after deducting costs, including depreciation, depletion and amortization and after giving effect to permanent differences.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
16. SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED)
The following supplemental unaudited information regarding the oil and gas activities of Devon is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission and SFAS No. 69, "Disclosures About Oil and Gas Producing Activities."
Quantities of Oil and Gas Reserves
Set forth below is a summary of the changes in the net quantities of crude oil, natural gas and natural gas liquids reserves for each of the three years ended December 31, 1999. Approximately 97%, 93% and 93%, of the respective year-end 1999, 1998 and 1997 domestic proved reserves were calculated by the independent petroleum consultants of LaRoche Petroleum Consultants, Ltd. and, for 1999 only, Ryder-Scott Company Petroleum Consultants. The remaining percentages of domestic reserves are based on Devon's own estimates. All of the year-end 1999 Canadian proved reserves were calculated by the independent petroleum consultants Paddock Lindstrom & Associates. All of the
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
year-end 1998 and 1997 Canadian proved reserves were calculated by the independent petroleum consultants of Paddock Lindstrom & Associates, AMH Group Ltd. and, for 1997 only, John P. Hunter & Associates, Ltd. All of the international proved reserves other than Canada as of December 31, 1999, were calculated by the independent petroleum consultants of Ryder-Scott Company Petroleum Consultants.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
Standardized Measure of Discounted Future Net Cash Flows
The accompanying tables reflect the standardized measure of discounted future net cash flows relating to Devon's interest in proved reserves:
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
F
Future cash inflows are computed by applying year-end prices (averaging $21.96 per barrel of oil, adjusted for transportation and other charges, $1.87 per Mcf of gas and $15.74 per barrel of natural gas liquids at December 31, 1999) to the year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements in existence at year-end.
Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate statutory tax rates to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved. The future income tax expenses give effect to permanent differences and tax credits, but do not reflect the impact of future operations.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
Changes Relating to the Standardized Measure of Discounted Future Net Cash Flows
Principal changes in the standardized measure of discounted future net cash flows attributable to Devon's proved reserves are as follows:
17. SEGMENT INFORMATION
Devon manages its business by country. As such, Devon identifies its segments based on geographic areas. Devon has three segments: its operations in the U.S., its operations in Canada, and its international operations outside of North America. Substantially all of these segments' operations involve oil and gas producing activities. Certain information regarding such activities for each segment is included in Notes 15 and 16.
Following is certain financial information regarding Devon's segments for 1999, 1998 and 1997. The revenues reported are all from external customers.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
17. SEGMENT INFORMATION (CONTINUED)
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
17. SEGMENT INFORMATION (CONTINUED)
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
18. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Following is a summary of the unaudited interim results of operations for the years ended December 31, 1999 and 1998.
The third quarter of 1998 includes a $126.9 million pre-tax reduction of the carrying value of U.S. oil and gas properties. The after-tax effect of this charge was $88 million, or $1.82 per share. The fourth quarter of 1998 includes $13.1 million of costs incurred in connection with the Northstar Combination. The after-tax effect of these expenses was $9.7 million, or $0.20 per share.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information called for by this Item 10 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities and Exchange Act of 1934 not later than April 29, 2000.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information called for by this Item 11 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities and Exchange Act of 1934 not later than April 29, 2000.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information called for by this Item 12 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities and Exchange Act of 1934 not later than April 29, 2000.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information called for by this Item 13 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities and Exchange Act of 1934 not later than April 29, 2000.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS AND SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Consolidated Financial Statements
Reference is made to the Index to Consolidated Financial Statements and Consolidated Financial Statement Schedules appearing at Item 8 on Page 48 of this report.
2. Consolidated Financial Statement Schedules
All financial statement schedules are omitted as they are inapplicable, or the required information has been included in the consolidated financial statements or notes thereto.
3. Exhibits
2.1 Amended and Restated Agreement and Plan of Merger among Registrant, Devon Energy Corporation (Oklahoma) (formerly Devon Energy Corporation, an Oklahoma corporation), Devon Oklahoma Corporation and PennzEnergy Company dated as of May 19, 1999 (incorporated by reference to Exhibit 2.1 to Registrant's Form S-4, File No. 333-82903).
2.2 Amended and Restated Combination Agreement between the Registrant and Northstar Energy Corporation dated as of June 29, 1998 (incorporated by reference to Annex B to Registrant's definitive proxy statement for a special meeting of shareholders, filed November 6, 1998).
3.1 Registrant's Restated Certificate of Incorporation (incorporated by reference to Exhibit 3 to Registrant's Form 8-K filed on August 18, 1999).
3.2 Registrant's Bylaws (incorporated by reference to Exhibit 3.3 to Registrant's Registration Statement on Form S-4, File No. 333-82903 as filed on July 15, 1999).
4.1 Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Registrant's Form 8-K filed on August 18, 1999).
4.2 Rights Agreement dated as of August 17, 1999 between Registrant and BankBoston, N.A. (incorporated by reference to Exhibit 4.2 to Registrant's Form 8-K filed on August 18, 1999).
4.3 Certificate of Designations of Series A Junior Participating Preferred Stock of Registrant (incorporated by reference to Exhibit 4.3 to Registrant's Form 8-K filed on August 18, 1999).
4.4 Certificate of Designations of the 6.49% Cumulative Preferred Stock, Series A of Registrant (incorporated by reference to Exhibit 4.4 to Registrant's Form 8-K filed on August 18, 1999).
4.5 Description of Capital Stock of Registrant (incorporated by reference to Exhibit 4.9 to Registrant's Form 8-K filed on August 18, 1999).
4.6 Indenture dated as of December 15, 1992 between Registrant (as successor by merger to PennzEnergy, as successor to Pennzoil Company) and Texas Commerce Bank National Association, Trustee (incorporated by reference to Exhibit 4(o) to Pennzoil Company's Form 10-K filed on March 10, 1993 (SEC File No. 1-5591)).
4.7 Third Supplemental Indenture dated as of August 3, 1998 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy) and Chase Bank of Texas, National Association, setting forth the terms of the 4.90% Exchangeable Senior Debentures due August 15, 2008 (incorporated by reference to Exhibit 4(g) to PennzEnergy Company's 1998 Form 10-K filed on March 23, 1999).
4.8 Fourth Supplemental Indenture dated as of August 3, 1998 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy) and Chase Bank of Texas, National Association, setting forth the terms of the 4.95% Exchangeable Senior Debentures due August 15, 2008 (incorporated by reference to Exhibit 4(g) to PennzEnergy Company's 1998 Form 10-K filed on March 23, 1999).
4.9 Fifth Supplemental Indenture dated as of August 17, 1999 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy, as successor to Pennzoil Company) and Chase Bank of Texas, National Association (incorporated by reference to Exhibit 4.7 to Registrant's Form 8-K filed on August 18, 1999).
4.10 Indenture dated as of February 15, 1986 among Registrant (as successor by merger to PennzEnergy) and Chase Bank of Texas, National Association (incorporated by reference to Exhibit 4(a) to Pennzoil Company's Form 10-Q filed on July 31, 1986 (SEC File No. 1-5591).
4.11 First Supplemental Indenture dated as of August 17, 1999 to Indenture dated as of February 15, 1986 among Registrant (as successor by merger to PennzEnergy) and Chase Bank of Texas, National Association (incorporated by reference to Exhibit 4.8 to Registrant's Form 8-K filed on August 18, 1999).
4.12 Second Supplemental Indenture dated as of August 17, 1999 to Indenture dated as of July 3, 1996 among the Registrant and The Bank of New York, as Trustee and the First Supplemental Indenture dated as of July 3, 1996 between the Registrant and The Bank of New York, as Trustee, relating to the issuance of 6.5% Trust Convertible Preferred Junior Subordinated Debentures (incorporated by reference to Exhibit 4.6 to Registrant's Form 8-K filed on August 18, 1999).
4.13 Amending Support Agreement dated as of August 17, 1999 between Registrant and Northstar Energy Corporation (incorporated by reference to Exhibit 4.5 to Registrant's Form 8-K filed on August 18, 1999).
4.14 Support Agreement, dated December 10, 1998, between the Registrant and Northstar Energy Corporation (incorporated by reference to Exhibit 4.1 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Form 8-K dated as of December 11, 1998).
4.15 Registration Rights Agreement, dated December 31, 1996, by and between Registrant and Kerr-McGee Corporation
(incorporated by reference to Exhibit 4.4 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Form 8-K filed on January 14, 1997).
4.16 Exchangeable Share Provisions (incorporated by reference to Exhibit 4.2 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Form 8-K filed on December 23, 1998).
4.17 Amended Exchangeable Share Provisions dated as of August 17, 1999.
9.1 Voting and Exchange Trust Agreement, dated December 10, 1998, by and between the Registrant, Northstar Energy Corporation and CIBC Mellon Trust Company (incorporated by reference to Exhibit 9 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Form 8-K filed on December 23, 1998).
9.2 Amending Voting and Exchange Trust Agreement, dated as of August 17, 1999, by and between Registrant, Northstar Energy Corporation and CIBC Mellon Trust Company (incorporated by reference to Exhibit 9 to Registrant's Form 8-K filed on August 18, 1999).
10.1 U.S. Credit Agreement, dated October 15, 1999 among the Registrant, as U.S. Borrower, Bank of America, N.A., as Administrative Agent, Bank of America Securities, LLC, as Lead Arranger, Bank One, Texas, N.A., as Syndication Agent, The Chase Manhattan Bank, as Documentation Agent, First Union National Bank, as Co-Documentation Agent, and Certain Financial Institutions, as Lenders (incorporated by reference to Exhibit 10.1 to Registrant's Form 10-Q filed on November 8, 1999).
10.2 Canadian Credit Agreement dated October 15, 1999, among Northstar Energy Corporation and Devon Energy Corporation, as Canadian Borrowers, Bank of America Canada, as Administrative Agent Bank of America Securities, LLC, as Lead Arranger, BancOne Capital Markets, Inc., as Syndication Agent, The Chase Manhattan Bank, as Documentation Agent, First Union
National Bank, as Co-Documentation Agent, and Certain Financial Institutions, as Lenders (incorporated by reference to Exhibit 10.2 to Registrant's Form 10-Q filed on November 8, 1999).
10.3 Morrison Petroleums Ltd. U.S. $75,000,000 6.76% Senior Notes Due July 19, 2005 Note Agreement dated as of July 19, 1995 (incorporated by reference to Exhibit 10.3 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Form 10-K filed on March 31, 1999.)
10.4 Northstar Energy Corporation U.S. $150,000,000 6.79% Senior Notes Due 2009 Note Agreement dated as of March 2, 1998 (incorporated by reference to Exhibit 10.4 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Form 10-K filed on March 31, 1999).
10.5 Pennzoil Company 1990 Stock Option Plan (incorporated by reference to Exhibit A to Pennzoil Company's definitive proxy material filed on April 26, 1990, (SEC File No. 1-5591).*
10.6 Pennzoil Company 1990 Conditional Stock Award Program (incorporated by reference to Exhibit B to Pennzoil Company's definitive proxy material filed on April 26, 1990, SEC File No. 1-5591).*
10.7 Pennzoil Company 1992 Stock Option Plan (incorporated by reference to Exhibit A to Pennzoil Company definitive proxy material filed on April 13, 1993, SEC File No. 1-5591).*
10.8 Pennzoil Company 1993 Conditional Stock Award Program (incorporated by reference to Exhibit B to Pennzoil Company's definitive proxy material filed on April 13, 1993, SEC File No. 1-5591). *
10.9 Pennzoil Company 1997 Incentive Plan (incorporated by reference to Exhibit A to Pennzoil Company definitive proxy material filed on March 21, 1997, SEC File No. 1-5591).*
10.10 PennzEnergy Company 1998 Incentive Plan (incorporated by reference to Exhibit 4.3 to Pennzoil Company's Form S-8 filed on December 29, 1998 SEC No. 333-69845).*
10.11 Devon Energy Corporation 1988 Stock Option Plan (incorporated by reference to Exhibit 10.4 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Registration Statement on Form S-4 filed on July 15, 1999, SEC File No. 33-23564).*
10.12 Devon Energy Corporation 1993 Stock Option Plan (incorporated by reference to Exhibit A to Devon Energy Corporation (Oklahoma)'s (predecessor to Registrant) Proxy Statement for the 1993 Annual Meeting of Shareholders filed on May 6, 1993).*
10.13 Devon Energy Corporation 1997 Stock Option Plan (incorporated by reference to Exhibit A to Devon Energy Corporation (Oklahoma)'s (predecessor to Registrant) Proxy Statement for the 1997 Annual Meeting of Shareholders filed on April 3, 1997).*
10.14 Employment Agreement between Devon Energy Corporation (Nevada), Registrant and Duke R. Ligon, dated February 7, 1997 (incorporated by reference to Exhibit 10.12 to Devon Energy Corporation (Oklahoma)'s (predecessor to Registrant) Form 10-Q filed on July 22, 1997).*
10.15 Amendment to Supplemental Retirement Income Agreement among Devon Energy Corporation (Nevada), Registrant and John W. Nichols, dated September 30, 1999.*
10.16 Supplemental Retirement Income Agreement among Devon Energy Corporation (Nevada), Registrant and John W. Nichols, dated March 26, 1997 (incorporated by reference to Exhibit 10.13 to Devon Energy Corporation (Oklahoma)'s (predecessor to Registrant) Form 10-Q filed on July 22, 1997).*
10.17 Supplemental Benefit Agreement between Northstar Energy Corporation and John A. Hagg dated February 17, 1999 (incorporated by reference to Exhibit 10.15 to Devon Energy Corporation (Oklahoma)'s (predecessor to Registrant) Annual Report on Form 10-K filed on March 31, 1999).*
10.18 Severance Agreement between Devon Energy Corporation (Nevada), Devon Energy Corporation, Devon Delaware Corporation and J. Larry Nichols, dated May 19, 1999 (incorporated by reference to Exhibit 10.4 to Registrant's Form 10-Q filed on November 8, 1999).*
10.19 Form of Severance Agreement between Devon Energy Corporation (Nevada), Devon Energy Corporation, Devon Delaware Corporation and J. Michael Lacey, Marian J. Moon, Duke R. Ligon, Darryl G. Smette, H. Allen Turner and William T. Vaughn, dated May 19, 1999 (incorporated by reference to Exhibit 10.3 to Registrant's Form 10-Q filed on November 8, 1999).*
10.20 Director's Restricted Stock Award Agreement between Devon Delaware Corporation (predecessor to Registrant) and James L. Pate, dated August 17, 1999.*
10.21 Consulting Agreement between Registrant (as successor by merger to PennzEnergy) and Brent Scowcroft dated May 17, 1999.*
10.22 Sale and Purchase Agreement relating to Registrant's San Juan Basin gas properties (incorporated by reference to Exhibit 10.15 to Devon Energy Corporation (Oklahoma)'s (predecessor to Registrant) Form 10-Q filed on November 9, 1995).
10.23 Second Restatement of and Amendment to Sale and Purchase Agreement relating to Registrant's San Juan Basin gas properties (incorporated by reference to Exhibit 10.16 to Devon Energy Corporation (Oklahoma)'s (predecessor to Registrant) Form 10-Q filed on November 9, 1995).
12 Computation of ratio of earnings to fixed charges
21 Subsidiaries of Registrant
23.1 Consent of LaRoche Petroleum Consultants, Ltd.
23.2 Consent of AMH Group, Ltd.
23.3 Consent of Paddock Lindstrom & Associates Ltd.
23.4 Consent of KPMG LLP
23.5 Consent of Ryder-Scott Company Petroleum Consultants
23.6 Consent of Deloitte & Touche LLP
27 Financial Data Schedule (filed electronically only)
* Compensatory plans or arrangements.
Reports on Form 8-K - A Current Report on Form 8-K dated January 26, 2000, was filed by the Registrant regarding year-end 1999 oil and gas reserves and 2000 forward-looking information.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
DEVON ENERGY CORPORATION
March 28, 2000 By /s/ J. Larry Nichols --------------------------- J. Larry Nichols, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
March 28, 2000 By /s/ James L. Pate ------------------------ James L. Pate Chairman of the Board and Director
March 28, 2000 By /s/ J. Larry Nichols --------------------------- J. Larry Nichols President, Chief Executive Officer and Director
March 28, 2000 By /s/ William T. Vaughn ---------------------------- William T. Vaughn Senior Vice President - Finance
March 28, 2000 By /s/ Danny J. Heatly -------------------------- Danny J. Heatly Vice President - Accounting
March 28, 2000 By /s/ Thomas F. Ferguson ----------------------------- Thomas F. Ferguson, Director
March 28, 2000 By /s/ David M. Gavrin -------------------------- David M. Gavrin, Director
March 28, 2000 By /s/ Michael E. Gellert ----------------------------- Michael E. Gellert, Director
March 28, 2000 By /s/ Moulton Goodrum, Jr. ------------------------------- Moulton Goodrum, Jr., Director
March 28, 2000 By /s/ John A. Hagg ----------------------- John A. Hagg, Director
March 28, 2000 By /s/ Henry R. Hamman -------------------------- Henry R. Hamman, Director
March 28, 2000 By /s/ William J. Johnson ----------------------------- William J. Johnson, Director
March 28, 2000 By /s/ Michael M. Kanovsky ------------------------------ Michael M. Kanovsky, Director
March 28, 2000 By /s/ Robert Mosbacher, Jr. -------------------------------- Robert Mosbacher, Jr., Director
March 28, 2000 By /s/ H. R. Sanders, Jr. ----------------------------- H. R. Sanders, Jr., Director
March 28, 2000 By /s/ Brent Scowcroft Brent Scowcroft, Director
March 28, 2000 By /s/ Robert B. Weaver --------------------------- Robert B. Weaver, Director
INDEX TO EXHIBITS
*Incorporated by reference.