UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-10067
DEVON ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
Oklahoma 73-1474008
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
20 North Broadway, Suite 1500
Oklahoma City, Oklahoma 73102-8260
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code: (405) 235-3611
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
Common Stock, par value $.10 per share American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that
the Registrant was required to file such reports), and (2) has been subject
to such filing requirements for at least the past 90 days.
Yes x No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of Registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. x
The aggregate market value of the voting stock held by non-affiliates
of the Registrant as of February 24, 1998, was $719,015,211. At such
date 32,318,895 shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 1998 annual meeting of stockholders - Part III
<PAGE>
TABLE OF CONTENTS
Page
PART I
Item 1. Business 4
Item 2. Properties 12
Item 3. Legal Proceedings 21
Item 4. Submission of Matters to a Vote of
Security Holders 21
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters 22
Item 6. Selected Financial Data 23
Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations 25
Item 8. Financial Statements and Supplementary Data 43
Item 9. Changes in and Disagreements with
Accountants on Accounting
and Financial Disclosure 86
PART III
Item 10. Directors and Executive Officers of the
Registrant 86
Item 11. Executive Compensation 86
Item 12. Security Ownership of Certain Beneficial
Owners and Management 86
Item 13. Certain Relationships and Related
Transactions 86
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K 86
DEFINITIONS
As used in this document:
"Mcf" means thousand cubic feet
"MMcf" means million cubic feet
"Bcf" means billion cubic feet
"MMBtu" means million British thermal units, a measure of heating value
"Bbl" means barrel
"MBbls" means thousand barrels
"MMBbls" means million barrels
"Boe" means equivalent barrels of oil
"MBoe" means thousand equivalent barrels of oil
"MMBoe" means million equivalent barrels of oil
"Oil" includes crude oil and condensate
"NGLs" means natural gas liquids
<PAGE>
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
THIS REPORT INCLUDES "FORWARD-LOOKING STATEMENTS" WITHIN THE
MEANING OF SECTION 27A OF THE SECURITIES ACT OF 1933, AS AMENDED,
AND SECTION 21E OF THE SECURITIES EXCHANGE ACT OF 1934, AS
AMENDED. ALL STATEMENTS OTHER THAN STATEMENTS OF HISTORICAL FACTS
INCLUDED IN THIS REPORT, INCLUDING, WITHOUT LIMITATION, STATEMENTS
REGARDING THE COMPANY'S FUTURE FINANCIAL POSITION, BUSINESS
STRATEGY, BUDGETS, PROJECTED COSTS AND PLANS AND OBJECTIVES
OF MANAGMENT FOR FUTURE OPERATIONS, ARE FORWARD-LOOKING STATEMENTS.
IN ADDITION, FORWARD-LOOKING STATEMENTS GENERALLY CAN BE IDENTIFIED
BY THE USE OF FORWARD-LOOKING TERMINOLOGY SUCH AS "MAY", "WILL",
"EXPECT", "INTEND", "ESTIMATE", "ANTICIPATE", "BELIEVE", OR "CONTINUE"
OR THE NEGATIVE THEREOF OR VARIATIONS THEREON OR SIMILAR TERMINOLOGY.
ALTHOUGH THE COMPANY BELIEVES THAT THE EXPECTATIONS REFLECTED IN SUCH
FORWARD-LOOKING STATEMENTS ARE REASONABLE, IT CAN GIVE NO ASSURANCE
THAT SUCH EXPECTATIONS WILL PROVE TO HAVE BEEN CORRECT. IMPORTANT
FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THE
COMPANY'S EXPECTATIONS ("CAUTIONARY STATEMENTS") ARE DISCLOSED UNDER
"ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS 1998 ESTIMATES", ITEM 2. "PROPERTIES -
PROVED RESERVES AND ESTIMATED FUTURE NET REVENUES" AND ELSEWHERE
IN THIS REPORT. ALL SUBSEQUENT WRITTEN AND ORAL FORWARD-LOOKING
STATEMENTS ATTRIBUTABLE TO THE COMPANY, OR PERSONS ACTING ON ITS
BEHALF, ARE EXPRESSLY QUALIFIED IN THEIR ENTIRETY BY THE CAUTIONARY
STATEMENTS. THE COMPANY ASSUMES NO DUTY TO UPDATE OR REVISE ITS
FORWARD-LOOKING STATEMENTS BASED ON CHANGES IN INTERNAL ESTIMATES
OR EXPECTATIONS OR OTHERWISE.
<PAGE>
PART I
ITEM 1. BUSINESS
General
Devon Energy Corporation ("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. The principal and administrative offices
of Devon are located at 20 North Broadway, Suite 1500, Oklahoma City,
OK 73102-8260 (telephone 405/2353611).
Devon currently owns interests in approximately 1,700 oil and
gas properties concentrated in five operating areas: the Permian Basin
in southeastern New Mexico and western Texas; the San Juan Basin
in northwestern New Mexico; the Rocky Mountain region in Wyoming;
the Mid-continent region in Oklahoma and the Texas Panhandle;
and the Western Canada Sedimentary Basin in Alberta, Canada.
(A detailed description of the significant properties can be found under
"Item 2. Properties - Significant Properties" beginning on page 17 hereof.)
At December 31, 1997, Devon's estimated proved reserves were 184.0
MMBoe, which were relatively balanced between oil and NGLs (44%) and
natural gas (56%). The present value of pre-tax future net revenues
discounted at 10% per annum assuming essentially unescalated prices
("10% Present Value") of such reserves was $913 million. Devon is one
of the top 20 public independent oil and gas companies in the
United States, as measured by oil and gas reserves.
Strategy
Devon's primary objectives are to build production, cash flow
and earnings per share by: (a) acquiring oil and gas properties,
(b) exploring for new oil and gas reserves and (c) optimizing production
from existing oil and gas properties.
During 1988, Devon expanded its capital base with its first
issuance of common stock to the public. This transaction began a
substantial expansion program, which has continued through the subsequent
nine years. Devon has used a two-pronged growth strategy of
acquiring producing properties and engaging in drilling activities.
In the last five years alone, Devon has consummated 5
significant acquisitions and drilled 873 new wells, 842 of which were
producers. These activities have resulted in net reserve additions
(i.e., extensions, discoveries, purchases and revisions) of 189.5 MMBoe.
Capital costs incurred to complete these activities totaled $736.8
million, for a five-year finding and development cost of $3.89 per Boe.
Net reserve additions divided by production, resulted in an annual
average reserve replacement factor of 320%.
Devon's objective, however, is to increase value per share, not
simply to increase total assets. Reserves have grown from 2.94 Boe per
diluted share at year-end 1992 to 4.91 Boe per diluted share at year-end
1997. During this same five-year period, net debt (long-term debt
minus working capital) has remained relatively low, never exceeding
$1.17 per Boe. In fact, at year-end 1997, the Company had no debt and
had working capital of $0.34 per Boe.
The oil and gas industry is characterized by volatile product
prices. Devon's management believes that by (a) keeping debt levels low,
(b) concentrating its properties in core areas to achieve economies of
scale, (c) acquiring and developing high profit margin properties,
(d) continually disposing of marginal and non-strategic properties and
(e) balancing reserves between oil and gas, Devon's profitability will
be maximized, even during periods of low oil and/or gas prices. In
addition, Devon remains financially flexible to take advantage of
opportunities for mergers, acquisitions, exploration or other growth
opportunities.
Recent Developments
On February 13, 1998, the Company commenced a tender offer
(the "Offer") for any and all of the units of beneficial interest
("Units") of Burlington Resources Coal Seam Gas Royalty Trust
(the "Trust"). The Offer of $8.75 per Unit in cash is not conditioned
on the tender of any minimum or maximum number of Units. The initial
expiration of the Offer is expected to be March 13, 1998.
If all of the Trust's Units are tendered, the transaction would
have a total value of approximately $80 million. Devon anticipates
using its cash on hand and committed credit lines to fund the transaction.
As of February 24, 1998, results of the Offer were not known,
and no estimate could be made as to how many Units of the Trust will be
acquired, if any. Devon intends to hold any Units it acquires
in the Offer for investment purposes. The Trust holds certain
economic interests in the Northeast Blanco Unit ("NEBU") of northwest
New Mexico. Devon is the operator of and owns a significant reserve
position in this property. See "Item 2 Properties. Significant
Properties - San Juan Basin Northeast Blanco Unit."
Drilling Activities
Devon is engaged in numerous drilling activities on
properties presently owned and intends to drill or develop other
properties acquired in the future. The majority of Devon's drilling
operations in 1998 will be concentrated in the Permian Basin, the
Rocky Mountains, the Texas Panhandle and Gulf Coast regions of the U.S.
and in the Western Canada Sedimentary Basin of Alberta, Canada.
The following tables set forth Devon's drilling results for the
past five years.
<TABLE>
<CAPTION>
Development Wells
Gross (1) Net (2)
Productive Dry Total Productive Dry Total
<C> <C> <C> <C> <C> <C> <C>
1993 92 4 96 43.39 1.40 44.79
1994 77 1 78 44.40 0.28 44.68
1995 184 3 187 143.87 0.29 144.16
1996 188 3 191 137.05 0.95 138.00
1997(3) 268 9 277 119.20 4.90 124.10
809 20 829 487.91 7.82 495.73
</TABLE>
<TABLE>
<CAPTION>
Exploratory Wells
Gross (1) Net (2)
Productive Dry Total Productive Dry Total
<C> <C> <C> <C> <C> <C> <C>
1993 4 2 6 2.05 0.49 2.54
1994 2 3 5 0.52 2.37 2.89
1995 9 3 12 2.53 1.18 3.71
1996 2 1 3 1.50 0.08 1.58
1997(3) 16 2 18 6.10 1.50 7.60
33 11 44 12.70 5.62 18.32
(1) Gross wells are the sum of all wells in which
Devon owns an interest.
(2) Net wells are the sum of Devon's working
interests in gross wells.
(3) Included in the 1997 figures are 24 gross
(10.2 net) productive development wells and 2 gross
(1.1 net) productive exploratory wells drilled in
Canada. Devon drilled no dry holes in Canada.
Devon had no Canadian properties prior to December 31, 1996.
</TABLE>
As of December 31, 1997, Devon was participating in the
drilling of 54 gross (17.6 net) wells, which are not included
in the table above. All such wells were being drilled in the
United States. Through February 24, 1998, 15 gross (10.1 net)
wells had been completed as productive. The remaining were still
in process.
Customers
For the years ended December 31, 1997 and December 31, 1996,
one significant purchaser, Aquila Energy Marketing Corporation
("Aquila"), accounted for 46% and 45%, respectively, of Devon's
natural gas sales or 22% and 19%, respectively, of total revenue.
For the year ended December 31, 1995, two significant purchasers,
Aquila and Enron Gas Marketing, Inc. ("Enron"), accounted for 31% and
16%, respectively, of Devon's gas sales or 14% and 7%, respectively,
of total revenue. Aquila and Enron purchase gas from numerous Devon
properties, at variable and market-sensitive prices. Devon does
not consider itself dependent upon any one of these purchasers, since
other purchasers are willing to purchase this same gas production at
competitive prices.
Devon sells its remaining gas production to a variety of
customers including pipelines, utilities, gas marketing firms,
industrial users and local distribution companies. Existing
gathering systems and interstate and intrastate pipelines are used
to consummate gas sales and
deliveries.
The principal customers for Devon's crude oil production are
refiners, remarketers and other companies, some of which have
pipeline facilities near the producing properties. In the event pipeline
facilities are not conveniently available, crude oil is trucked or
barged to storage, refining or pipeline facilities.
Oil and Natural Gas Marketing
Oil Marketing. Devon's oil production is sold under both long -
and short-term agreements at prices negotiated between the parties.
Natural Gas Marketing. A large portion of Devon's natural gas
production is sold at variable or market-sensitive prices. Though exact
percentages vary daily, as of December 31, 1997, approximately 73% of
such natural gas is sold under short-term contracts. The remaining 27%
of Devon's natural gas is marketed under various long-term contracts
(one year or more) which dedicate the natural gas to a purchaser for an
extended period of time, but which still may involve variable and
market-sensitive pricing.
Under both long-term and short-term contracts, typically either
the entire contract (in the case of short-term contracts) or the price
provisions of the contract (in the case of long-term contracts) are
renegotiated from daily intervals up to one year intervals. These
market-sensitive sales are referred to as "spot market" sales. The
spot market has become progressively more competitive in recent years.
As a result, prices on the spot market have been volatile. From time to
time Devon has withheld gas from the market due to low prices.
Physical Delivery Contracts. As of February 24, 1998, Devon had
made firm commitments to sell an average of approximately 30% of its
estimated 1998 coal seam gas production (or approximately 9% of
total estimated 1998 gas production) at a fixed price of approximately
$1.45 per Mcf, which equates to a price of approximately $2.04 per MMBtu.
(The $1.45 per Mcf price includes the effect of adjusting for Btu content
and is net of costs for transportation and removing carbon dioxide. This
price excludes the expected benefit of the San Juan Basin Transaction.
See "Item 2. Properties - Significant Properties - San Juan Basin
San Juan Basin Transaction"). Devon has also made other firm commitments
to sell certain quantities of its 1998 domestic conventional and Canadian
gas production at fixed prices. However, such other commitments are
not material.
If Devon is unable to produce the volumes required to fulfill
its firm commitments, Devon would have to purchase gas on the open
market to satisfy such commitments. During the past five years, Devon
has satisfied all of its firm commitments from its production and
anticipates that it will continue to do so in the future.
Competition
The oil and gas business is highly competitive. Devon encounters
competition by major, integrated and independent oil and gas companies
in acquiring drilling prospects and properties, contracting for drilling
equipment and securing trained personnel. Intense competition occurs
with respect to marketing, particularly of natural gas. Certain
competitors have resources which substantially exceed those of Devon.
Seasonal Nature of Business
Generally, but not always, the demand for natural gas decreases
during the summer months and increases during the winter months. Seasonal
anomalies such as mild winters sometimes lessen this fluctuation.
In addition, pipelines, utilities, local distribution companies and
industrial users utilize natural gas storage facilities and purchase
some of their anticipated winter requirements during the summer.
This can also lessen seasonal demand fluctuations.
Government Regulation
Devon's operations are subject to various levels of government
controls and regulations in the United States and Canada.
United States Regulation
In the United States, legislation affecting the oil and gas industry
has been pervasive and is under constant review for amendment
or expansion. Pursuant to such legislation, numerous federal, state
and local departments and agencies have issued extensive rules and
regulations binding on the oil and gas industry and its individual
members, some of which carry substantial penalties for the failure to
comply. Such laws and regulations have a significant impact on oil and gas
drilling and production activities, increase the cost of doing business and,
consequently, affect profitability. Inasmuch as new legislation affecting
the oil and gas industry is commonplace and existing laws and
regulations are frequently amended or reinterpreted, Devon is unable to
predict the future cost or impact of complying with such laws and
regulations.
Exploration and Production. Devon's United States operations
are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for the
drilling of wells; maintaining bonding requirements in order to drill
or operate wells; submitting and implementing spill prevention plans;
submitting notification relating to the presence, use and release of certain
contaminants incidental to oil and gas operations; and regulating the
location of wells, the method of drilling and casing wells, the use,
transportation, storage and disposal of fluids and materials used in
connection with drilling and production activities, surface usage and
the restoration of properties upon which wells have been drilled,
the plugging and abandoning of wells, and the transporting of production.
Devon's operations are also subject to various conservation matters,
including the regulation of the size of drilling and spacing units
or proration units, the number of wells which may be drilled in a unit,
and the unitization or pooling of oil and gas properties. In this regard,
some states allow the forced pooling or integration of tracts to facilitate
exploration while other states rely on voluntary pooling of lands and
leases, which may make it more difficult to develop oil and gas properties.
In addition, state conservation laws establish maximum rates of production
from oil and gas wells, generally prohibit the venting or flaring of gas,
and impose certain requirements regarding the ratable purchase of
production. The effect of these regulations is to limit the amounts of oil
and gas Devon can produce from its wells and to limit the number of wells
or the locations at which Devon can drill.
Certain of Devon's oil and gas leases, including most of its leases
in the San Juan Basin and many of the Company's leases in southeast
New Mexico and Wyoming, are granted by the federal government and
administered by various federal agencies. Such leases require
compliance with detailed federal regulations and orders which regulate,
among other matters, drilling and operations on lands covered by these
leases, and calculation and disbursement of royalty payments to the
federal government.
Environmental and Occupational Regulations. Various federal,
state and local laws and regulations concerning the discharge of
contaminants into the environment, the generation, storage, transportation
and disposal of contaminants or otherwise relating to the protection of
public health, natural resources, wildlife and the environment, affect
Devon's exploration, development and production operations and the
costs attendant thereto. These laws and regulations increase Devon's
overall operating expenses. Devon maintains levels of insurance customary
in the industry to limit its financial exposure in the event of a
substantial environmental claim resulting from sudden and accidental
discharges of oil, salt water or other harmful substances. However,
100% coverage is not maintained concerning any environmental claim,
and no coverage is maintained with respect to any award of punitive
damages against Devon or any penalty or fine required to be paid by Devon
because of its violation of any federal, state or local law. Devon is
committed to meeting its responsibilities to protect the environment
wherever it operates and anticipates making increased expenditures of both
a capital and expense nature as a result of the increasingly stringent
laws relating to the protection of the environment. Devon's
unreimbursed expenditures in 1997 concerning such matters were
immaterial, but Devon cannot predict with any reasonable degree of
certainty its future exposure concerning such matters.
Devon is also subject to laws and regulations concerning
occupational safety and health. Due to the continued changes in these
laws and regulations, and the judicial construction of same, Devon is
unable to predict with any reasonable degree of certainty its future
costs of complying with these laws and regulations.
In 1992 Devon retained the services of an independent environmental
engineering firm to provide a comprehensive evaluation of Devon's
significant properties and to otherwise advise Devon concerning its
compliance with various environmental laws. In 1993 Devon established
its own internal Environmental Industrial Hygiene and Safety Department
to perform these functions. This department is responsible for instituting
and maintaining an environmental and safety compliance program for Devon.
The program includes field inspections of properties and internal audits of
Devon's compliance procedures.
Canadian Regulation
The oil and gas industry in Canada is subject to extensive
controls and regulations imposed by various levels of government.
It is not expected that any of these controls or regulations will
affect Devon's Canadian operations in a manner materially different
than they would affect other oil and gas companies of similar size.
The North American Free Trade Agreement. The North American Free
Trade Agreement ("NAFTA") which became effective on January 1, 1994,
carries forward most of the material energy terms contained in the
Canada-U.S. Free Trade Agreement. In the context of energy resources,
Canada continues to remain free to determine whether exports to the U.S.
or Mexico will be allowed, provided that any export restrictions
do not: (i) reduce the proportion of energy exported relative to the
supply of the energy resource; (ii) impose an export price higher
than the domestic price; or (iii) disrupt normal channels of supply.
All parties to NAFTA are also prohibited from imposing minimum export
or import price requirements.
Royalties and Incentives. Each province of Canada has legislation
and regulations governing land tenure, royalties, production rates and
taxes, environmental protection and other matters. The royalty regime is
a significant factor in the profitability of oil and natural gas production.
Royalties payable on production from lands other than Crown lands are
determined by negotiations between the parties. Crown royalties
are determined by government regulation and are generally calculated
as a percentage of the value of the gross production with the royalty
rate dependent in part upon prescribed reference prices, well
productivity, geographical location, field discovery date and the
type of quality of the petroleum product produced. From time to time,
the governments of Canada, Alberta and British Columbia have also
established incentive programs such as royalty rate reductions, royalty
holidays and tax credits for the purpose of encouraging oil and natural
gas exploration or enhanced recovery projects. These incentives
generally have the effect of increasing the cash flow to the producer.
Pricing and Marketing. The price of oil and natural gas sold
is determined by negotiation between buyers and sellers. An order
from the National Energy Board ("NEB") is required for oil exports.
Any oil export to be made pursuant to an export contract of longer
than one year, in the case of light crude, and two years, in the case
of heavy crude, duration (up to 25 years) requires an exporter to obtain
an export license form the NEB. The issue of such a license requires
the approval of the Governor in Council. Natural gas exported from
Canada is also subject to similar regulation by the NEB and the government
of Canada. Exporters are free to negotiate prices and other terms
with purchasers, provided that the export contracts in excess of two
years must continue to meet certain criteria prescribed by the NEB and
the government of Canada. The governments of Alberta and British Columbia
also regulate the volume of natural gas which may be removed from those
provinces for consumption elsewhere based on such factors as reserve
availability, transportation arrangements and market considerations.
Environmental Regulation. The oil and natural gas industry is
subject to environmental regulation pursuant to local, provincial
and federal legislation. Environmental legislation provides for
restrictions and prohibitions on releases or emissions of various
substances produced or utilized in association with certain oil and gas
industry operations. In addition, legislation requires that well and
facility sites be abandoned and reclaimed to the satisfaction of
provincial authorities. A breach of such legislation may result in the
imposition of fines and penalties. Devon is committed to meeting
its responsibilities to protect the environment wherever it operates
and anticipates making increased expenditures of both a capital and
expense nature as a result of the increasingly stringent laws relating
to the protection of the environment. Devon's unreimbursed expenditures
in 1997 concerning such matters were immaterial, but Devon cannot
predict with any reasonable degree of certainty its future exposure
concerning such matters.
Investment Canada Act. The Investment Canada Act requires
Government of Canada approval, in certain cases, of the acquisition
of control of a Canadian business by an entity that is not controlled
by Canadians. In certain circumstances, the acquisition of natural
resource properties may be considered to be a transaction requiring
such approval.
Employees
As of December 31, 1997, Devon's staff consisted of 383 fulltime
employees, including 32 professionals in engineering, 16 in geology,
21 in the land department, 9 in oil and gas marketing, 53 in accounting
and data processing, 21 in administration and other support positions.
The Company also engages independent consulting petroleum engineers,
environmental professionals, geologists, geophysicists,
landmen and attorneys on a fee basis.
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 New Mexico, Wyoming, Texas, Oklahoma and Alberta, Canada. 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 production payments, and, to a lesser extent,
overriding royalty, royalty, 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, 1997.
Approximately 92% of Devon's domestic proved reserves were estimated by
LaRoche Petroleum Consultants, Ltd., independent petroleum engineers
("LaRoche"). The remainder of such reserves were estimated by Devon's
internal staff of engineers. All of the Canadian proved reserves were
calculated by the independent petroleum consultants, AMH Group Ltd. ("AMH").
In preparing its estimates, Devon's staff used standard geological and
engineering methods generally accepted by the petroleum industry and in
accordance with SEC guidelines (as described in the notes below).
LaRoche and AMH indicated in their reports that they also used standard
geological and engineering methods generally accepted by the petroleum
industry and in accordance with SEC guidelines. These estimates
correspond with the method used in presenting the supplemental information
on oil and gas operations in note 14 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. Please refer to the supplemental information on oil
and gas operations in note 14 to Devon's consolidated financial statements
(included herein) for a presentation of reserves separated between Canada
and the U.S.
<TABLE>
<CAPTION>
Total Proved Proved
Proved Developed Undeveloped
Reserves Reserves (1) Reserves (2)
<S> <C> <C> <C>
Oil (MBbls) 68,443 60,165 8,278
Gas (MMcf) 616,004 506,374 109,630
NGLs (MBbl) 12,881 12,098 783
MBoe (3) 183,991 156,658 27,333
Pre-tax Future Net Revenue 1,562,022 1,390,359 171,663
($ thousands) (4)
Pre-tax 10% Present Value 913,073 841,036 72,037
($ thousands) (4)
<FN>
(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, 1997. 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 $16.93 per
Bbl of oil, $1.89 per Mcf of natural gas ($1.94
per Mcf including the effect of the San Juan Basin
Transaction), and $12.42 per Bbl of NGLs. These
prices compare to December 31, 1997, benchmark posted
prices of $15.50 per Bbl for West Texas
Intermediate crude oil and a composite of $2.34 per
MMBtu for Texas Gulf Coast spot gas, representing
prices paid for gas delivered to various Texas Gulf
Coast pipelines.
</TABLE>
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 which Devon operates and to exclude all
interests in wells which 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, 1997. 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 NGL
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.
The following table presents the net quantities
of Devon's oil, natural gas and NGL reserves as of the end of
the years indicated. Approximately 95%, 91%, 92%,
94% and 92% of Devon's domestic reserves as of the
years ended December 31, 1993, 1994, 1995, 1996 and
1997, respectively, were estimated by LaRoche. The
balance of the domestic reserves was estimated by
Devon's internal staff of engineers. All of the
Canadian reserves as of the years ended December 31, 1996
and 1997, were estimated by AMH. (Devon had no Canadian reserves
prior to 1996.)
<TABLE>
<CAPTION>
Total Proved Reserves
As of December 31, Oil (MBbls) Gas (MMcf) NGLs(MBbls) Total (Mboe)
<S> <C> <C> <C> <C>
1993 14,897 369,254 1,854 78,293
1994 42,165 347,560 5,442 105,534
1995 44,466 363,846 9,469 114,576
1996 67,481 595,519 12,579 179,313
1997 68,443 616,004 12,881 183,991
</TABLE>
Proved Developed Reserves
<TABLE>
<CAPTION>
As of December 31, Oil (MBbls) Gas (MMcf) NGLs(MBbls) Total (MBoe)
<S> <C> <C> <C> <C>
1993 11,548 355,536 1,751 72,555
1994 18,718 324,302 3,123 75,891
1995 28,703 311,664 6,149 86,796
1996 60,202 570,265 11,212 166,458
1997 60,165 506,374 12,098 156,659
</TABLE>
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, 1997, is set forth in "Item 7.
Management's Discussion and Analysis of Financial
Condition and Results of Operations."
Well Statistics
As of December 31, 1997, Devon held interests in
approximately 1700 properties. The following table depicts Devon's
interests in producing wells located on these properties:
<TABLE>
<CAPTION>
Oil Wells Gas Wells Total Wells
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
<S> <C> <C> <C> <C> <C> <C>
U. S. 8,427 1,230 2,852 703 11,279 1,933
Canada 692 117 234 61 926 178
Total 9,119 1,347 3,086 764 12,205 2,111
<FN>
(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.
</TABLE>
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, 1997.
<TABLE>
<CAPTION>
Developed Undeveloped
Gross(1) Net(2) Gross(1) Net(2)
<S> <C> <C> <C> <C>
Alabama 4,662 2,247 583 261
Arkansas 5,906 589 14,649 3,627
Colorado 6,348 2,581 22,319 9,519
Kansas 20,036 8,693 6,433 713
Louisiana 12,840 5,047 12,680 5,769
Mississippi 8,291 548 4,148 1,206
Montana 16,326 365 11,891 1,779
Nebraska 160 80 6,517 1,377
New Mexico 145,481 61,199 237,695 79,953
North Dakota 9,427 3,506 11,453 2,355
Oklahoma 278,720 85,017 212,230 48,160
South Dakota 6,051 149 162 78
Texas 858,224 228,070 608,034 184,955
Utah 5,305 864 2,200 2,200
Wyoming 195,067 82,078 135,265 76,361
Total U. S. 1,572,844 481,033 1,286,259 418,313
Canada 187,621 76,200 113,663 75,732
Grand Total 1,760,465 557,233 1,399,922 494,045
<FN>
(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.
</TABLE>
Operation of Properties
The day-to-day operations of oil and gas properties is 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 2,133 of its 12,205 wells. These
operated wells account for approximately 57% of Devon's total proved
reserves. 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, 1997.
<TABLE>
<CAPTION>
10% Presents
Value (3) 10% Present
Oil(MBbls) Gas(MMcf) NGLs(MBbl) MBoe(1) MBoe% (2) ($000) Value% (4)
<S> <C> <C> <C> <C> <C> <C> <C>
Permian Basin:
West Texas and
Southeast New Mexico
Grayburg-Jackson
Field 19,296 1,539 1,539 21,864 11.9% $101,060 11.1%
Ozona Field 247 50,476 2,553 11,213 6.1% 51,531 5.6%
Other 22,061 74,068 3,199 37,605 20.4% 191,797 21.0%
Total 41,604 130,718 7,291 70,682 38.4% $344,388 37.7%
San Juan Basin:
Northwest New Mexico
Northeast Blanco
Unit 4 148,699 40 24,827 13.5% $120,881 (5) 13.2%
32-9 Unit 0 80,502 0 13,417 7.3% 60,717 (6) 6.7%
Other 3 280 10 60 0.0% 162 0.0%
Total 7 229,481 50 38,304 20.8% $181,760 19.9%
Rocky Mountains:
Colorado and Wyoming
House Creek 11,656 675 0 11,768 6.4% $43,266 4.7%
Other 5,217 86,570 2,953 22,598 12.3% 106,470 11.7%
Total 16,873 87,245 2,953 34,366 18.7% $149,736 16.4%
Mid-Continent:
Oklahoma and
Texas Panhandle 2,119 112,815 1,778 22,699 12.3% $134,360 14.7%
Canada 7,541 48,180 809 16,380 8.9% $92,625 (7) 10.2%
All Other Properties 299 7,565 0 1,560 0.9% $10,204 1.1%
Grand Total 68,443 616,004 12,881 183,991 100.0% $913,073 100.0%
<FN>
(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) Percentage which present value for the basin or
region bears to total present value for all Proved
Reserves.
(5) Includes $17.6 million of additional value
attributable to the San Juan Basin Transaction
through the year 2002.
(6) Includes $11.1 million of additional value
attributable to the San Juan Basin Transaction
through the year 2002.
(7) Canadian dollars converted to U. S. dollars at
the rate of $1 Canadian: $0.6992 U. S.
</TABLE>
Permian Basin Properties. The Permian Basin is a prolific oil
and gas producing province located in western Texas and southeastern
New Mexico. The area encompasses approximately 66,000 square
miles and contains more than 500 major oil and gas fields. Oil and gas
leases within the Permian Basin are difficult to obtain as much of the most
prospective acreage is "held by production" from existing wells or
tied to large producing units. Since 1987, Devon has made four
significant acquisitions of properties in the Permian Basin. These
acquisitions have enabled Devon to obtain prospective acreage in areas
in which leasehold positions could not otherwise be established.
This large and wellsituated leasehold position continues to provide
Devon with numerous exploration and development opportunities. Devon
has also initiated enhanced oil recovery projects to further expand reserves.
Grayburg-Jackson Field. Devon acquired the Grayburg-Jackson
Field in 1994. The property consists of approximately 8,500 acres
located in the southeastern New Mexico portion of the Permian Basin.
The field produces from an 800-foot thick interval of the Grayburg
and San Andres Formations at depths between 3,000 and 4,000 feet.
The Grayburg-Jackson Field contains approximately onethird of Devon's
proved oil reserves and is Devon's largest Permian Basin property.
Production in this field was established in the 1930's, with most
of the current producing wells drilled since 1970. When Devon acquired
this property in 1994, drilling by previous owners had developed the property
on an average spacing of over 40 acres per well. Additional oil reserves
were recovered from similar properties in the immediate vicinity by infill
drilling to 20 acres per well spacing and subsequent waterflooding. Based
upon analogy to these properties, Devon initiated a $75 million capital
development project in 1994. The project included drilling approximately
185 infill wells, converting selected producing wells to water injection
wells and optimizing the existing waterflood. Devon substantially
completed the infill drilling phase of the project in 1996. The majority
of the field was in the initial phases of water injection by mid-1997.
Completion of the waterflood facilities over the remainder of the field
will require the additional conversion of about 30 producing wells
to injection wells.
At year-end 1997, production averaged approximately 3,000 Boe per
day. Devon anticipates that continued water injection and completion of
the waterflood facilities will further improve oil and gas recoveries.
Ozona Field. The Ozona Field encompasses more than 200,000 acres
in Crockett County, Texas, situated 120 miles southeast of Midland, Texas.
The field produces gas primarily from the Canyon and Strawn Formations at
depths ranging from approximately 6,000 to 9,000 feet. The field has
been developed on 80-acre spacing, with portions now being infill drilled
to 40-acre spacing.
San Juan Basin. Devon's single largest natural gas reserve position
relates to its interests in two federal units in the northwest New Mexico
portion of the San Juan Basin: the 33,000 acre NEBU, in Rio Arriba
and San Juan Counties, and the 22,400 acre 32-9 Unit in San Juan County.
The San Juan Basin, a densely drilled area covering 3,700 square miles
in central and northwestern New Mexico, has been historically considered
the second largest gas producing basin in the United States. Prior to
1990, the Basin's gas production primarily came from conventional sandstone
formations at a depth of about 5,500 feet. However, in the early
1980's, development of the shallower Fruitland coal formation began.
Coal seam gas production has increased total production so significantly
that the San Juan Basin could be considered the largest gas producing basin
in the U.S. Production from the coal seams constitutes almost all of
Devon's reserves in these two units.
Substantially all of Devon's interests in both of these
units are a part of a transaction into which the Company entered
effective January 1, 1995. See " - San Juan Basin Transaction" below.
Northeast Blanco Unit. Approximately 97%, or 144.5 Bcf,
of Devon's proved reserves attributable to NEBU are associated
with the Fruitland coal formation. The potential for gas production
from coal seams varies depending upon the thickness of the coal formation,
the type of coal in place, the depth at which it is found and other factors.
NEBU is located in the central part of the San Juan Basin where each
of the factors is at or near its optimum. NEBU is operated by Devon.
The Company initially began developing its coal seam interest during
1988, eventually drilling 102 wells - the maximum permitted
under existing 320-acre spacing on NEBU's 33,000 acres.
In the near term, Devon is implementing various projects
which have already increased and may continue to increase production
and recoverable reserves. The first of these projects, called "line looping,"
involves laying additional gathering lines to decrease operating pressures.
This project was begun in 1996 and was substantially completed in
October, 1997. Another project involves the installation of additional
compressors at various points in the gathering system and at central
delivery points associated with NEBU. This project was begun in 1997
and will continue in 1998. Additional projects to improve production
through work on individual wells are currently underway. Longer term,
Devon believes that additional wells may be drilled which could improve
production.
Initial results from the portion of the line looping and
compression projects that have been completed through February 24, 1998,
appear favorable. Total daily production from NEBU has increased from
an average of 187 MMcf of gas per day in June 1996 to an average of
209 MMcf of gas per day in January 1998. Devon anticipates that the
installation of additional compression and facilities could increase
production from NEBU another 10 MMcf to 20 MMcf of gas per day.
As part of the San Juan Basin Transaction (discussed in more
detail below), a third party will pay 100% of Devon's share of the
capital necessary to enhance production from the existing NEBU wells.
Devon is entitled to retain 75% of any reserves in excess of those
estimated to be in place at the time of the transaction which are
developed as a result of such capital expenditures.
See " - San Juan Basin Transaction" below.
32-9 Unit. The 32-9 Unit is located approximately eight miles
northwest of NEBU. Geologically and operationally this property is
very similar to NEBU; the coal seams at the 32-9 Unit are about the
same thickness as at NEBU, the type of coal and the depth at which
it is found are similar and the gas content of the coal is estimated to be
approximately the same. However, the 32-9 Unit is located in an area
where the coal does not appear to be as permeable as it is at NEBU.
Thus, the 32-9 Unit wells tend to produce at lower rates but should
produce for a longer period of time than the NEBU wells.
Longer term, Devon believes that additional wells may be drilled
which could improve production. This unit is also being evaluated
for possible mechanical improvements similar to those being implemented at
NEBU.
San Juan Basin Transaction. Effective January 1, 1995, Devon
and an unrelated company entered into a transaction covering
substantially all of Devon's San Juan Basin coal seam properties.
The effect of the transaction is that the price Devon receives for its
coal seam gas production will range between $0.40 and $0.60 per Mcf (subject to
adjustment for inflation) higher than the price the Company would
otherwise receive during the period from 1995 through the year 2002.
For a detailed discussion of this transaction, see note 3 to Devon's
consolidated financial statements included elsewhere herein.
Rocky Mountain Properties. The Rocky Mountain
region includes oil and gas producing basins, which are grouped
together because of their geographic location rather than their geological
characteristics. The area generally encompasses all or portions of
the states of Colorado, Montana, New Mexico, North Dakota, Utah
and Wyoming. Devon's properties are primarily located in the Big Horn and
Powder River Basins in Wyoming.
House Creek Field. The House Creek Field is located in
Campbell County, Wyoming within the prolific Powder River Basin.
Devon acquired its original interest in the field at year-end 1996.
In 1997, the Company purchased additional interests. The field,
which produces oil from the Sussex Sandstone reservoir at depths of 8,200
feet, covers an area thirty miles long and two miles wide. The Field
is divided into two production units. The southern two-thirds of the
field, designated as the House Creek Sussex Unit, is operated by Devon with
a 45.4% working interest. A 12 well infill drilling program was initiated
late in 1997. Based on the success of that program, an additional
60 to 80 wells could be drilled in 1998, effectively reducing well
spacing from 160 to 80 acres per well. The northern third of the field,
designated as the House Creek North Sussex Unit, is operated by a third
party. Devon has a 26.5% working interest in the North Unit.
Additional infill drilling is also underway in the North Unit.
Both portions of the field are currently under waterflood.
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. LEGAL PROCEEDINGS
Devon is involved in various routine legal proceedings incidental
to its business. However, to Devon's knowledge as of February 24, 1998,
there were no material pending legal proceedings to which Devon is a party
or to which any of its property is subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the Company's
security holders during the fourth quarter of the year ended
December 31, 1997.
PART II
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.
The following table sets forth the high and low sales prices for Devon
common stock as reported by the AMEX for the periods indicated.
<TABLE>
<CAPTION>
Consolidated
Average
Daily
High Low Volume
1996:
<S> <C> <C> <C>
Quarter Ended March 31, 1996 25-3/4 19-7/8 44,846
Quarter Ended June 39, 1996 26-1/8 22 39,268
Quarter Ended September 30, 1996 27-1/2 22-3/4 73,678
Quarter Ended December 31, 1996 36-7/8 25-1/4 93,606
1997:
Quarter Ended March 31, 1997 38-7/8 29-1/2 73,079
Quarter Ended June 30, 1997 38-1/2 27-3/8 87,800
Quarter Ended September 30, 1997 45-1/4 36-1/8 6,174
Quarter Ended December 31, 1997 49-1/8 35 69,694
1998:
Quarter Ended March 31, 1998 38-3/8 33 93,914
(through February 24, 1998)
</TABLE>
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.
Total dividends for the years ended December 31, 1994 and 1995 were
$0.12 per share. Effective December 31, 1996, Devon increased its quarterly
dividend payment to $0.05 per share, making the total dividends paid in
1996 $0.14 per share. Total dividends for 1997 were $0.20 per share.
Devon anticipates continuing to pay regular quarterly dividends in the
foreseeable future.
On February 24, 1998, there were 859 Devon Common Stock
shareholders of record.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial information (not covered
by the independent auditors' report) should be read in
conjunction with "Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations," and the
consolidated financial statements and the notes thereto
included in "Item 8. Financial Statements and Supplementary
Data."
<TABLE>
<CAPTION>
Year Ended December 31,
1997 1996 1995 1994 1993
(Thousands, Except Per Share Data and Ratios)
OPERATING RESULTS
<S> <C> <C> <C> <C> <C>
Oil sales $ 133,445 80,142 55,290 38,086 38,395
Gas sales 150,549 68,049 50,732 56,372 54,876
NGL sales 21,754 14,367 6,404 4,908 4,544
Other revenue 7,392 1,459 877 1,407 942
Total revenues $ 313,140 164,017 113,303 100,773 98,757
Lease operating expenses $ 65,655 31,568 27,289 24,521 26,401
Production taxes $ 17,924 10,658 6,832 6,899 6,924
Depreciation, depletion and
amortization $ 85,307 43,361 38,090 34,132 28,409
General and administrative
expenses $ 12,922 9,101 8,419 8,425 7,640
Interest expense $ 274 5,277 7,051 5,439 3,422
Distributions on preferred
securities of subsidiary
trust $ 9,717 4,753 -- -- --
<F1>
Net earnings $ 75,292 34,801 14,502 13,745 20,4861
Net earnings per share:
<F1>
Basic $ 2.34 1.57 0.66 0.64 0.98 1
<F1>
Diluted $ 2.17 1.52 0.65 0.63 0.98 1
Cash dividends per common
share $ 0.20 0.14 0.12 0.12 0.09
Weighted average common
shares outstanding - basic 32,216 22,160 22,074 21,552 20,822
Ratio of earnings to fixed
<F2>
charges 2 12.52 6.76 4.54 4.80 8.24
<CAPTION>
December 31,
1997 1996 1995 1994 1993
(Thousands)
BALANCE SHEET DATA
Total assets $ 846,403 746,251 421,564 351,448 285,553
Long-term debt $ - 8,000 143,000 98,000 80,000
Convertible preferred securities
of subsidiary trust $ 149,500 149,500 -- -- --
Stockholders' equity $ 543,576 472,404 219,041 206,406 172,900
<CAPTION>
Year Ended December 31,
1997 1996 1995 1994 1993
(Thousands, Except Per Unit Data)
CASH FLOW DATA
Net cash provided by
operating activities $ 168,722 86,802 61,276 46,384 63,957
<F4>
<F3>
EBITDA 3,4 216,639 112,689 70,763 60,928 57,792
<F4>
<F5>
Cash margin 4,5 181,445 95,951 59,217 55,074 52,893
PRODUCTION, PRICE AND OTHER DATA
Production:
Oil (MBbls) 7,005 3,816 3,300 2,467 2,337
Gas (MMcf) 69,327 35,714 36,886 39,335 35,598
NGLs (MBbls) 1,626 952 600 501 411
<F6>
MBoe 6 20,185 10,720 10,047 9,524 8,681
Average prices:
Oil (Per Bbl) $19.05 21.00 16.75 15.44 16.43
Gas (Per Mcf) $ 2.17 1.91 1.38 1.43 1.54
NGLs (Per Bbl) $13.38 15.09 10.68 9.79 11.06
<F6>
Per Boe 6 $15.15 15.16 11.19 10.43 11.27
Costs per Boe:
Operating costs $ 4.14 3.94 3.40 3.30 3.84
Depreciation, depletion
and amortization of
oil and gas
properties $ 4.08 3.88 3.65 3.45 3.16
General and administra-
tive expenses $ 0.64 0.85 0.84 0.89 0.88
<F1>
1 Net earnings for 1993 include the cumulative effect of a required change
in the method of accounting for income taxes in 1993 which provided
earnings of $1.3 million, or $0.06 per share.
<F2>
2 For purposes of calculating the ratio of earnings to fixed charges, (i)
earnings consist of earnings before income taxes and cumulative effect
of accounting change, plus fixed charges; and (ii) fixed charges consist
of interest expense, distributions on preferred securities of subsidiary
trust, amortization of costs relating to indebtedness and the preferred
securities of subsidiary trust, and one-third of rental expense
estimated to be attributable to interest.
<F3>
3 EBITDA represents earnings before interest (including distributions on
preferred securities of subsidiary trust), taxes, depreciation,
depletion and amortization.
<F4>
4 EBITDA and cash margin (defined below) are indicators which are commonly
used in the oil and gas industry. They should be used as supplements
to, and not as substitutes for, net earnings and net cash provided by
operating activities determined in accordance with generally accepted
accounting principles in analyzing Devon's results of operations and
liquidity.
For the years ended December 31, 1997, 1996, 1995, 1994, and 1993, net
cash used in investing activities were $131.3 million, $94.8 million,
$110.6 million, $73.4 million and $74.2 million, respectively. For
these same periods, net cash provided (used) by financing activities
were ($4.5) million, $8.5 million, $49.8 million, $15.8 million and
$24.2 million, respectively.
<F5>
5 "Cash margin" equals total revenues less cash expenses. Cash expenses
are all expenses other than the non-cash expenses of depreciation,
depletion and amortization and deferred income tax expense. Cash margin
measures the net cash which is generated by a company's operations
during a given period, without regard to the period such cash is
actually physically received or spent by the company. This margin
ignores the non-operational effect on a company's "net cash provided by
operating activities", as measured by generally accepted accounting
principles, from a company's activities as an operator of oil and gas
wells. Such activities produce net increases or decreases in temporary
cash funds held by the operator which have no effect on net earnings of
the company.
<F6>
6 Gas is converted to Boe or MBoe at the rate of six Mcf of gas per barrel
of oil, based upon the approximate relative energy content of natural
gas and oil, which rate is not necessarily indicative of the
relationship of oil and gas prices. The respective prices of oil, gas
and NGLs are affected by market and other factors in addition to
relative energy content.
</TABLE>
<PAGE>
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 1995 through 1997. Reference
is made to "Item 6. Selected Financial Data" and "Item 8.
Financial Statements and Supplementary Data."
Overview
Devon concluded 1997 financially stronger and larger than
at any previous time in the company s history. Over the last
three years Devon's oil and gas reserves have grown 74% to 184
million barrels of oil equivalent ("MMBoe"). The company s
unused long-term credit lines have increased 64% over the same
period, to $208 million. Total assets have increased 141% to
$846 million. During the same three years Devon reduced its
long-term debt from $98 million to zero and significantly
increased stockholders equity.
Devon s operating performance has also improved by most
measures over the last three years. The 1997 oil and gas
production of 20.2 MMBoe was 112% over that of 1994. The 1997
production increase, coupled with a 45% increase in oil, gas
and NGL prices over 1994 levels, led to revenues and earnings
gains. Net earnings for 1997 climbed 448% over those of 1994,
to $75.3 million. Net cash provided by operating activities
rose from $46.4 million in 1994 to $168.7 million in 1997.
<F1>
The cash margin1 (total revenues less cash expenses) during
these same three years has increased from $55.1 million in
1994 to $181.4 million in 1997.
This growth in operations was driven primarily by the
following events:
Devon acquired Alta Energy Corporation through a $72
million cash and common stock merger in May 1994.
The merger added substantial oil and gas reserves,
production and revenues to Devon's Permian Basin
position.
In 1995, Devon entered into a transaction covering
substantially all of its San Juan Basin coal seam
gas properties (the "San Juan Basin Transaction").
This transaction added approximately $8 million, $10
<F1>
1 "Cash margin" equals Devon's total revenues less cash expenses. Cash
expenses are all expenses other than the non-cash expenses of depreci-
ation, depletion and amortization and deferred income tax expense. Cash
margin is an indicator which is commonly used in the oil and gas
industry. This margin measures the net cash which is generated by a
company's operations during a given period, without regard to the period
such cash is actually physically received or spent by the company. This
margin ignores the non-operational effects on a company's activities as
an operator of oil and gas wells. Such activities produce net increases or
decreases in temporary cash funds held by the operator which have no
effect on net earnings of the company. Cash margin should be used as a
supplement to, and not as a substitute for, net earnings and net
cash provided by operating activities determined in accordance with
generally accepted accounting principles in analyzing Devon's results of
operations and liquidity.
million and $12 million to Devon's annual revenues
in 1997, 1996 and 1995, respectively. See Note 3 to
the consolidated financial statements included
elsewhere in this report for a detailed discussion
of the San Juan Basin Transaction.
On December 31, 1996, Devon acquired all of Kerr-
McGee Corporation's North American onshore oil and
gas exploration and production business and
properties (the "KMG-NAOS Properties") in exchange
for 9,954,000 shares of Devon common stock. This
transaction added approximately 62 million Boe to
Devon's year-end 1996 proved reserves (an increase
of over 50%), as well as 370,000 net undeveloped
acres of leasehold.
Devon has been successful during the last three
years in its drilling efforts. During such period,
Devon has spent approximately $246 million to drill
688 wells, of which 667 were completed as producers.
Prices received from oil, gas and NGL revenues have
risen (though with volatility) 45%, from $10.43 per
Boe in 1994 to $15.15 per Boe in 1997.
The following actions during the last three years
improved Devon s liquidity and financial resources while
reducing its bank debt:
Devon's production and revenue gains have given the
company a substantially larger cash flow and, thus,
capital budget.
Devon's acquisition and drilling efforts during the
last three years have added 120.4 MMBoe of proved
reserves to its asset base. Combined with 1.8 MMBoe
of upward revisions to its reserve estimates,
Devon's total reserve additions of 122.2 MMBoe
during the past three years were 298% of its
production of 41.0 MMBoe.
In July, 1996, Devon, through a newly-formed
affiliate trust, issued $149.5 million of 6.5% Trust
Convertible Preferred Securities (the "TCP
Securities"). Combined with cash flow from
operations, this transaction has eliminated Devon's
long-term debt.
Devon's oil and gas reserve additions, production
gains, revenue increases and equity additions over
the past three years have allowed Devon to increase
its unused lines of credit. Since the end of 1994,
Devon's available long-term credit lines have
increased by $81 million to a total of $208 million
at year-end 1997.
The growth exhibited by Devon over the last three years
extends a nine-year expansion period for the company. This
period began with Devon becoming a public company in 1988.
Through its acquisitions and its drilling and development
efforts, Devon has significantly increased oil and gas
reserves and production over this period.
While Devon has consistently increased production over
this nine-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 decrease. Thus, an oil and gas production
company depletes part of its asset base with each unit of oil
and gas it produces. Historically, Devon has been able to
overcome this natural decline by adding more reserves through
drilling and acquisitions than the company produces. However,
Devon s future growth, if any, will depend on the company s
ability to continue to add reserves in excess of production.
Given the dependence of oil and gas prices on factors
outside of Devon's control, the company s management has
focused its efforts on increasing oil and gas reserves and
production and on controlling expenses. Over its nine year
history as a public company, Devon has been able to
significantly reduce its production and operating costs per
unit of production. However, over the last three years Devon s
per-unit operating costs have increased by 25%. An increase in
the company s oil production as a portion of its total
production and an increase in secondary recovery projects have
contributed to this expense increase. (Secondary recovery
projects are generally more expensive than primary production.
In addition, producing oil is generally more expensive than
producing gas. However, oil also generally produces more
revenue per Boe than gas.) Higher oil, gas and NGL revenues
in 1997 also resulted in higher production taxes, a component
of production and operating expenses. Devon s future earnings
and cash flows are dependent on the company s ability to
continue to contain production and 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 $113.3 million in
1995 to $164.0 million in 1996 and $313.1 million in 1997. In
each of these years, oil, gas and NGL sales accounted for over
97% of total revenues.
Changes in oil, gas and NGL production, prices and
revenues from 1995 to 1997 are shown in the table below.
(Note: Unless otherwise stated, all references in this
discussion to dollar amounts regarding Devon's Canadian
operations are expressed in U.S. dollars.)
<TABLE>
<CAPTION>
Total
Year Ended December 31,
1997 1996
1997 vs 1996 1996 vs 1995 1995
(Absolute Amounts in Thousands)
Production
<S> <C> <C> <C> <C> <C>
Oil (MBbls) 7,005 +84% 3,816 +16% 3,300
Gas (MMcf) 69,327 +94% 35,714 -3% 36,886
NGLs (MBbls) 1,626 +71% 952 +59% 600
Oil, Gas and NGLs (MBoe) 20,185 +88% 10,720 +7% 10,047
Revenues
Per Unit of Production:
Oil (per Bbl) $ 19.05 -9% 21.00 +25% 16.75
Gas (per Mcf) $ 2.17 +14% 1.91 +38% 1.38
NGLs (per Bbl) $ 13.38 -11% 15.09 +41% 10.68
Oil, Gas and NGLs (per Boe) $ 15.15 - 15.16 +35% 11.19
Absolute:
Oil $133,445 +67% 80,142 +45% 55,290
Gas $150,549 +121% 68,049 +34% 50,732
NGLs $ 21,754 +51% 14,367 +124% 6,404
Oil, Gas and NGLs $305,748 +88% 162,558 +45% 112,426
<CAPTION>
Domestic
Year Ended December 31,
1997 1996
1997 vs 1996 1996 vs 1995 1995
(Absolute Amounts in Thousands)
Production
Oil (MBbls) 6,055 +59% 3,816 +16% 3,300
Gas (MMcf) 61,015 +71% 35,714 -3% 36,886
NGLs (MBbls) 1,468 +54% 952 +59% 600
Oil, Gas and NGLs (MBoe) 17,692 +65% 10,720 +7% 10,047
Revenues
Per Unit of Production:
Oil (per Bbl) $ 19.08 -9% 21.00 +25% 16.75
Gas (per Mcf) $ 2.28 +19% 1.91 +38% 1.38
NGLs (per Bbl) $ 13.18 -13% 15.09 +41% 10.68
Oil, Gas and NGLs (per Boe) $ 15.48 +2% 15.16 +35% 11.19
Absolute:
Oil $115,504 +44% 80,142 +45% 55,290
Gas $139,018 +104% 68,049 +34% 50,732
NGLs $ 19,338 +35% 14,367 +124% 6,404
Oil, Gas and NGLs $273,860 +68% 162,558 +45% 112,426
<CAPTION>
Canada
Year Ended December 31,
1997 1996
1997 vs 1996 1996 vs 1995 1995
(Absolute Amounts in Thousands)
Production
Oil (MBbls) 950 N/A - N/A -
Gas (MMcf) 8,312 N/A - N/A -
NGLs (MBbls) 158 N/A - N/A -
Oil, Gas and NGLs (MBoe) 2,493 N/A - N/A -
Revenues
Per Unit of Production:
Oil (per Bbl) $ 18.89 N/A - N/A -
Gas (per Mcf) $ 1.39 N/A - N/A -
NGLs (per Bbl) $ 15.28 N/A - N/A -
Oil, Gas and NGLs (per Boe) $ 12.79 N/A - N/A -
Absolute:
Oil $17,941 N/A - N/A -
Gas $11,531 N/A - N/A -
NGLs $ 2,416 N/A - N/A -
Oil, Gas and NGLs $31,888 N/A - N/A -
</TABLE>
Oil Revenues 1997 vs. 1996 Oil revenues increased by $53.3
million in 1997. Production gains of 3.2 million barrels
added $67.0 million of oil revenues in 1997. This increase
was partially offset by a $13.7 million reduction in oil
revenues caused by a $1.95 per barrel decrease in the average
oil price in 1997.
The KMG-NAOS Properties acquired at the end of 1996 were the
primary contributors to the increased oil production in 1997.
These properties 1997 production totaled 3.1 million barrels.
Approximately 2.1 million barrels of such production were in
the U.S., while 1 million barrels were produced in Canada.
Devon s other domestic properties produced 3.9 million barrels
in 1997. This was an increase of 0.1 million barrels, or 3%,
over the 1996 production of 3.8 million barrels.
1996 vs. 1995 Oil revenues increased by $24.9 million in
1996. An increase in the average price of $4.25 per barrel in
1996 added $16.2 million to revenues. Production gains of
516,000 barrels added the remaining $8.7 million of 1996's
increased oil revenues.
The Grayburg-Jackson Field acquired in 1994 accounted for
the majority of 1996's increased production. This field
produced 1.1 million barrels in 1996, a 37% increase over the
807,000 barrels the field produced in 1995. Production from
Devon's other oil properties increased 9% in 1996, from 2.5
million barrels in 1995 to 2.7 million barrels in 1996.
Gas Revenues 1997 vs. 1996 Gas revenues increased by $82.5
million in 1997. An increase in production of 33.6 Bcf added
$64.0 million to 1997 s gas revenues. An increase of $0.26
per Mcf in the average price added $18.5 million to 1997 s gas
revenues.
The KMG-NAOS Properties were responsible for the majority of
the increased gas production in 1997. These properties
produced 29.8 Bcf in 1997. Approximately 21.5 Bcf of such
production was in the U.S., while 8.3 Bcf was produced in
Canada. Devon s coal seam gas properties produced 17.6 Bcf in
1997 compared to 17.4 Bcf in 1996. Devon s other domestic
properties produced 21.9 Bcf in 1997 compared to 18.3 Bcf in
1996.
Devon s coal seam properties averaged $2.13 per Mcf in 1997
compared to $1.72 per Mcf in 1996. The San Juan Basin
Transaction added $8.4 million to coal seam gas revenues in
1997 compared to $10.3 million in 1996. The San Juan Basin
Transaction increased the average coal seam gas price by $0.48
per Mcf in 1997 and $0.59 per Mcf in 1996.
Devon s domestic conventional gas properties averaged $2.34
per Mcf in 1997 compared to $2.08 per Mcf in 1996.
1996 vs. 1995 Gas revenues increased by $17.3 million in
1996. An increase in the average gas price of $0.53 per Mcf
in 1996 added $18.9 million to 1996's gas revenues. This
increase was partially offset by a $1.6 million reduction in
gas revenues from a drop in gas production of 1.2 Bcf.
Coal seam gas production declined by 16%, from 20.8 Bcf in
1995 to 17.4 Bcf in 1996. However, the average realized coal
seam gas price rose by 30% from $1.32 per Mcf in 1995 to $1.72
per Mcf in 1996. Coal seam gas revenues included $10.3
million in 1996 and $12.8 million in 1995 attributable to the
San Juan Basin Transaction. This transaction increased the
average coal seam gas price by $0.59 per Mcf in 1996 and $0.61
per Mcf in 1995.
Total conventional gas production and revenues for 1996 were
18.3 Bcf and $37.9 million, respectively, versus 16.1 Bcf and
$23.2 million in 1995. Prices for conventional gas averaged
$2.08 per Mcf in 1996 compared to 1995's average of $1.44.
NGL Revenues 1997 vs. 1996 NGL revenues increased by $7.4
million in 1997. An increase in production of 674,000 barrels
added $10.2 million to 1997 s revenues. This increase was
partially offset by a $2.8 million reduction in NGL revenues
caused by a $1.71 per barrel decrease in 1997 s average price.
The majority of the increased NGL production in 1997 was
attributable to the KMG-NAOS Properties. These properties
produced 339,000 barrels in the U.S. and 158,000 barrels in
Canada in 1997.
1996 vs. 1995 NGL revenues increased by $8.0 million in
1996. An increase in average prices of $4.41 per barrel added
$4.2 million to the 1996 NGL revenues. The remaining $3.8
million of increased revenues was attributable to increased
production of 352,000 barrels in 1996.
Additional interests acquired in certain Wyoming properties
in December 1995 and the first half of 1996 accounted for
214,000 barrels of the increased production in 1996. These
Wyoming properties produced 226,000 barrels in 1996 compared
to 12,000 barrels in 1995. Additional drilling in the Sand
Dunes area of the Permian Basin increased production from that
area from 69,000 barrels in 1995 to 95,000 barrels in 1996.
Other Revenues. 1997 vs. 1996 Other revenues increased by
$5.9 million in 1997. Revenues from processing third party
natural gas related to the KMG-NAOS Properties accounted for
$3.3 million of the increase. An increase in interest income
provided another $1.7 million of the increase in 1997 s other
revenues.
1996 vs. 1995 Other revenue increased by $0.6 million in
1996. Increases in gains recognized from the disposal of non-
oil and gas fixed assets and from settlements of gas contract
claims accounted for most of this increase.
Expenses The details of the changes in pre-tax expenses
between 1995 and 1997 are shown in the table below.
<TABLE>
<CAPTION>
Year Ended December 31,
1997 1996
1997 vs 1996 1996 vs 1995 1995
(Absolute Amounts in Thousands)
Absolute:
Production and operating expenses:
<S> <C> <C> <C> <C> <C>
Lease operating expenses $ 65,655 +108% 31,568 +16% 27,289
Production taxes 17,924 +68% 10,658 +56% 6,832
Depreciation, depletion and amortiza-
tion of oil and gas properties 82,413 +98% 41,538 +13% 36,640
Subtotal 165,992 +98% 83,764 +18% 70,761
Depreciation and amortization of
non-oil and gas properties 2,894 +59% 1,823 +26% 1,450
General and administrative expenses 12,922 +42% 9,101 +8% 8,419
Interest expense 274 -95% 5,277 -25% 7,051
Distributions on preferred securities
of subsidiary trust 9,717 +104% 4,753 N/A -
Total $191,799 +83% 104,718 +19% 87,681
Per Boe Produced:
Production and operating expenses:
Lease operating expenses $ 3.25 +10% 2.95 +8% 2.72
Production taxes 0.89 -10% 0.99 +46% 0.68
Depreciation, depletion and amortization
of oil and gas properties 4.08 +5% 3.88 +6% 3.65
Subtotal 8.22 +5% 7.82 +11% 7.05
Depreciation and amortization of non-oil
<F1>
and gas properties (1) 0.15 -12% 0.17 +21% 0.14
<F1>
General and administrative expenses (1) 0.64 -25% 0.85 +1% 0.84
<F1>
Interest expense (1) 0.01 -98% 0.49 -30% 0.70
Distributions on preferred securities of
<F1>
subsidiary trust (1) 0.48 +9% 0.44 N/A -
Total $ 9.50 -3% 9.77 +12% 8.73
<F1>
(1) Though per Boe general and administrative expenses, interest
expense, non-oil and gas property depreciation and distributions
on preferred securities of subsidiary trust may be helpful for
profitability trend analysis, these expenses are not directly
attributable to production volumes. Rather they are an artifact of
corporate structure, capitalization and financing, and non-oil and
gas property fixed assets, respectively.
</TABLE>
Production and Operating Expenses The details of the changes in
production and operating expenses between 1995 and 1997 are shown in the
table below.
<TABLE>
<CAPTION>
Total
Year Ended December 31,
1997 1996
1997 vs 1996 1996 vs 1995 1995
(Absolute Amounts in Thousands)
Absolute:
<S> <C> <C> <C> <C> <C>
Recurring lease operating expenses $61,658 +118% 28,270 +19% 23,842
Well workover expenses 3,997 +21% 3,298 -4% 3,447
Production taxes 17,924 +68% 10,658 +56% 6,832
Total production and operating
expenses $83,579 +98% 42,226 +24% 34,121
Per Boe:
Recurring lease operating expenses $ 3.05 +16% 2.64 +11% 2.37
Well workover expenses 0.20 -35% 0.31 -11% 0.35
Production taxes 0.89 -10% 0.99 +46% 0.68
Total production and operating
expenses $ 4.14 +5% 3.94 +16% 3.40
<CAPTION>
Domestic
Year Ended December 31,
1997 1996
1997 vs 1996 1996 vs 1995 1995
(Absolute Amounts in Thousands)
Absolute:
Recurring lease operating expenses $54,969 +94% 28,270 +19% 23,842
Well workover expenses 3,143 -5% 3,298 -4% 3,447
Production taxes 17,646 +66% 10,658 +56% 6,832
Total production and operating
expenses $75,758 +79% 42,226 +24% 34,121
Per Boe:
Recurring lease operating expenses $ 3.10 +17% 2.64 +11% 2.37
Well workover expenses 0.18 -42% 0.31 -11% 0.35
Production taxes 1.00 +1% 0.99 +46% 0.68
Total production and operating
expenses $ 4.28 +9% 3.94 +16% 3.40
<CAPTION>
Canada
Year Ended December 31,
1997 1996
1997 vs 1996 1996 vs 1995 1995
(Absolute Amounts in Thousands)
Absolute:
Recurring lease operating expenses $ 6,689 N/A - N/A -
Well workover expenses 854 N/A - N/A -
Production taxes 278 N/A - N/A -
Total production and operating
expenses $ 7,821 N/A - N/A -
Per Boe:
Recurring lease operating expenses $ 2.68 N/A - N/A -
Well workover expenses 0.35 N/A - N/A -
Production taxes 0.11 N/A - N/A -
Total production and operating
expenses $ 3.14 N/A - N/A -
</TABLE>
1997 vs. 1996 Recurring lease operating expenses increased by $33.4
million, or 118%, in 1997. The KMG-NAOS Properties accounted for $26.0
million of the increased expenses. Most of the remaining $7.4 million of
1997 s increase was due to wells which were drilled in 1997 and 1996.
Recurring expenses per Boe were up by $0.41 per Boe, or 16%, in 1997.
This increase was caused by the reduction in the coal seam gas properties
share of total production. The recurring operating costs per Boe for the
coal seam gas properties are extremely low ($0.43 per Boe in 1997 and
$0.32 per Boe in 1996). However, as production from these properties
remained relatively flat and production from Devon s other properties
increased in 1997, the coal seam gas properties percentage of overall
production dropped from 27% in 1996 to only 15% in 1997. The result is
that a larger percentage of Devon s production in 1997 was attributable to
its conventional properties, which have a higher operating cost per Boe
than the low-cost coal seam gas properties. The recurring operating costs
per Boe for Devon s conventional properties were $3.50 per Boe in 1997 and
1996. Thus, the coal seam properties' costs rose only $0.11 per Boe in
1997 and the conventional properties' costs remained flat in 1997.
However, since the conventional properties represented a larger percentage
of Devon's total production in 1997 compared to 1996 (85% in 1997 compared
to 73% in 1996), the result was a $0.41 per Boe increase in the overall
rate.
Most taxing authorities collect production taxes on a fixed percentage
of revenue basis. Therefore, as Devon s revenues have increased, so have
production taxes. Production taxes increased 68% from $10.7 million in
1996 to $17.9 million in 1997. This increase was due to the 88% increase
in combined oil, gas and NGL revenues in 1997.
1996 vs. 1995 Recurring lease operating expenses increased by $4.4
million, or 19%, in 1996. Approximately $2.7 million of the increase was
related to the additional interests acquired in the Worland Properties in
December 1995 and the first half of 1996. Recurring lease operating
expenses for the Worland Properties increased from $0.1 million in 1995 to
$2.8 million in 1996 after Devon increased its ownership in such
properties. Most of the remaining $1.7 million increase was due to the
higher number of producing wells in the Grayburg-Jackson Field in 1996
compared to 1995.
Recurring expenses per Boe were up by $0.27, or 11%, in 1996 compared to
1995. As explained above in the 1997 vs. 1996 discussion, the increase in
the percentage of production attributable to conventional properties is
also the cause of the increase in per Boe costs in 1996 compared to 1995.
The recurring costs for the coal seam gas properties averaged $0.32 per
Boe in 1996 and $0.24 per Boe in 1995. The recurring expenses of Devon's
conventional oil and gas properties were $3.50 per Boe in 1996 and 1995.
Thus, the coal seam properties' costs rose only $0.08 per Boe in 1996 and
the conventional properties' costs per Boe remained flat in 1996.
However, since the conventional properties represented a larger percentage
of Devon's total production in 1996 compared to 1995 (73% in 1996 compared
to 65% in 1995), the result was a $0.27 per Boe increase in the overall
rate.
Production taxes increased 56% from $6.8 million in 1995 to $10.7
million in 1996. This increase was primarily due to the 45% increase in
combined oil, gas and NGL revenues.
Production taxes per Boe increased by $0.31 per Boe, or 46%, in 1996.
This was primarily caused by the increase in the average price per Boe
received in 1996.
Depreciation, Depletion and Amortization Devon's largest non-cash
expense is depreciation, depletion and amortization ("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 capitalized costs change, 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.
1997 vs. 1996 Oil and gas property related DD&A increased $40.9
million, or 98%, in 1997. Approximately $36.7 million of this increase
was caused by the 88% increase in combined oil, gas and NGL production in
1997. The remaining $4.2 million of increase was caused by a 5% increase
in the DD&A rate from $3.88 per Boe in 1996 to $4.08 per Boe in 1997.
1996 vs. 1995 Oil and gas property related DD&A increased by $4.9
million, or 13%, in 1996. Approximately $2.5 million of this increase was
caused by a 7% increase in total oil, gas and NGL production in 1996. The
remaining $2.4 million increase was caused by a 6% increase in the DD&A
rate from $3.65 per Boe in 1995 to $3.88 per Boe in 1996.
General and Administrative Expenses ("G&A") 1997 vs. 1996 G&A
increased by $3.8 million, or 42%, in 1997. Employee salaries and related
overhead costs, including insurance and pension expense, increased by $4.9
million. This increase was primarily related to the additional permanent
and temporary personnel added at Devon s Oklahoma City and Calgary offices
as a result of the addition of the KMG-NAOS Properties. The expansion in
personnel also caused office-related costs such as rent, dues, travel,
supplies, telephone, etc., to increase by $1.8 million in 1997.
The higher salary, overhead and office costs were partially offset by an
increase in Devon s overhead reimbursements. As the operator of a
property, Devon receives these reimbursements from the property s working
interest owners. Devon records the reimbursements as reductions to G&A.
Due to the addition of the KMG-NAOS Properties, many of which Devon
operates, Devon s overhead reimbursements increased by $3.7 million in
1997.
1996 vs. 1995 G&A increased by $0.7 million, or 8%, in 1996. Employee
salaries and related benefits were $1.1 million higher in 1996. Legal
expenses and abandoned acquisition expenses were each $0.2 million higher
in 1996. These increases were partially offset by a $0.1 million
reduction in franchise tax expense due to Devon's 1995 change of
incorporation from Delaware to Oklahoma. Also, Devon saw a $0.7 million
increase in G&A reimbursements received from joint interest owners in
Devon-operated properties.
Interest Expense 1997 vs. 1996 Interest expense decreased $5.0
million, or 95%, in 1997. This decrease was caused by a drop in the
average debt balance outstanding from $77.0 million in 1996 to $0.7
million in 1997. Devon issued $149.5 million of 6.5% Trust Convertible
Preferred Securities ( TCP Securities ) in July, 1996. The proceeds from
this issuance, along with cash flow from operations, were used to retire
Devon s long-term bank debt early in 1997. (The TCP Securities are
discussed further below.)
1996 vs. 1995 Interest expense decreased by $1.8 million, or 25%, in
1996. Approximately $1.5 million of the lower interest expense was due to
a lower average debt balance in 1996. The average debt balance dropped
from $97.1 million in 1995 to $77.0 million in 1996. This decrease in
average debt outstanding was primarily the result of the issuance of the
TCP Securities in July 1996.
The remaining $0.3 million of interest expense reduction in 1996
resulted from lower interest rates. The interest rates on the debt
outstanding during 1996 averaged 6.3%, compared to 1995's average rate of
6.5%. The overall interest rate (including the effect of the interest
rate swap discussed below, various fees paid to the banks and the
amortization of certain loan costs) averaged 6.9% in 1996 and 7.3% in
1995.
Devon entered into an interest rate swap agreement in the second quarter
of 1995 and terminated the agreement on July 1, 1996 for a gain of $0.8
million. This gain is being recognized ratably in Devon's operating
results as a reduction to interest expense during the period from July 1,
1996 to June 16, 1998 (the original expiration date of the swap
agreement). Approximately $0.2 million of the gain was included in the
last half of 1996 as a reduction to interest expense. During the time
when the agreement was still in effect, it resulted in $0.1 million of
reduced interest expense in the year 1995 and had no effect on interest
expense for the first six months of 1996.
Distributions on Preferred Securities of Subsidiary Trust 1997 vs. 1996
As mentioned in the above discussion of interest expense, and 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% TCP Securities in a private placement
in July, 1996. The distributions on the TCP Securities accrue at the rate
of 1.625% per quarter. Distributions in 1997 were $9.7 million compared
to $4.8 million in 1996. The 1996 distribution total represented slightly
less than two quarters distributions due to the issuance date occurring
in July.
1996 vs. 1995 The TCP Securities were issued in July, 1996. The 1996
distributions of $4.8 million represented slightly less than two quarters'
distributions due to the issuance date occurring in July.
Income Taxes 1997 vs. 1996 Devon s effective financial tax rate in
1997 was 38% compared to 41% in 1996. Both rates were above the statutory
federal tax rate of 35% due to state income taxes, and certain tax aspects
of the San Juan Basin Transaction and a 1994 merger. Also, the 1997 rate
was affected by certain tax aspects of the KMG-NAOS transaction and by
Canadian income taxes which accrue at rates higher than the U.S. statutory
rate of 35%. (The effective financial income tax rate for Devon's
Canadian operations was 43% in 1997.)
1996 vs. 1995 Devon s effective financial tax rate in 1996 was 41%
compared to 1995 s rate of 43%. Both rates were above the federal
statutory rate of 35% due to the effect of the state taxes, San Juan Basin
Transaction and 1994 merger noted in the above paragraph.
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 $130.5 million of cash was spent in
1997 for capital expenditures, of which $124.6 million was related to the
acquisition, drilling or development of oil and gas properties. Most of
the drilling and development efforts in 1997 centered in the Permian
Basin, which included 174 of the 295 oil and gas wells that Devon drilled
during the year.
Other Cash Uses A $0.03 per common share dividend was paid in each
quarter since Devon paid its initial common stock dividend in the second
quarter of 1993 through the third quarter of 1996. In the fourth quarter
of 1996, the quarterly dividend rate was increased to $0.05 per share.
Quarterly dividends in 1997 were paid at the rate of $0.05 per share.
Capital Resources and Liquidity Net cash provided by operating
activities ("operating cash flow") was the primary source of capital and
short-term liquidity in 1997. Operating cash flow in 1997 totaled $168.7
million, a 94% increase compared to the $86.8 million of operating cash
flow generated in 1996.
In addition to operating cash flow, Devon's credit lines have
historically been an important source of capital and liquidity. However,
1997's increased operating cash flow allowed Devon to fund its 1997
capital expenditures and other cash uses without borrowing against its
credit lines. At the end of 1997, Devon had $208 million of long-term
credit lines, all of which was available for future use. Also, Devon has
a $12.5 million Canadian dollars demand facility for its Canadian
operations. All of this Canadian facility was also available at the end
of 1997 for future use. (See Note 7 to the consolidated financial
statements included elsewhere in this report for a detailed discussion of
Devon's credit lines.)
1998 Estimates
The forward-looking statements provided in this
discussion are based on management's examination of historical
operating trends, the December 31, 1997 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 NGL 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 for
Devon's Canadian operations, obtained in the KMG-NAOS
transaction, 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 NGL prices may
vary considerably due to differences between regional markets
and demand for different grades of oil, gas and NGLs. Over
90% of Devon s revenues are attributable to sales of these
three commodities. Consequently, the company 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 are
sufficiently significant as to have a material impact on the
company s overall financial results. With respect to oil
production, these properties include the West Red Lake Field
and the Grayburg-Jackson Unit, both in southeast New Mexico.
The company s interest in NEBU and the 32-9 Unit can have a
significant effect on overall gas production.
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 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 1998 will be substantially similar to
those of 1997, unless otherwise noted. Given the general
limitations expressed herein, Devon's forward-looking
statements for 1998 are set forth below.
Oil Production and Relative Prices Devon expects its oil
production in 1998 to total between 6.3 million barrels and
7.3 million barrels. Devon expects its net oil prices per
barrel will average from between $0.20 to $0.45 above West
Texas Intermediate posted prices in 1998.
Gas Production and Relative Prices Devon expects its
total gas production in 1998 will be between 67.0 Bcf and 78.5
Bcf. It is expected that coal seam gas production will be
between 19.0 Bcf and 22.2 Bcf. Canadian production in 1998 is
estimated to be between 6.8 Bcf and 8.0 Bcf. Devon expects
production from the remainder of its gas properties to total
between 41.2 Bcf and 48.3 Bcf.
Devon expects its 1998 coal seam average price will be
between $0.25 and $0.55 per Mcf less than Texas Gulf Coast
spot averages. This includes an expected $0.40 to $0.45 per
Mcf from the San Juan Basin Transaction. Devon's Canadian gas
production is expected to average from between $0.80 to $1.05
less than Texas Gulf Coast spot averages. (These Canadian
differentials are expressed in U.S. dollars, using the year-
end 1997 exchange rate of $0.70 U.S. dollar to $1.00 Canadian
dollar.) Devon's remaining gas production is expected to
average $0.05 to $0.25 less than Texas Gulf Coast spot
averages during 1998.
Devon had made firm commitments to sell approximately
12,700 Mcf per day of its coal seam gas production throughout
1998 at a fixed price of approximately $1.45 per Mcf, which
equates to a price of approximately $2.04 per MMBtu. (The
$1.45 per Mcf price includes the effect of adjusting for Btu
content and is net of costs for transportation and removing
carbon dioxide. This price excludes the expected $0.40 to
$0.45 per Mcf benefit from the San Juan Basin Transaction.)
The effect of these fixed price commitments has been included
in the expected differential for coal seam gas discussed in
the above paragraph. Devon has also made other commitments to
sell certain quantities of its 1998 domestic conventional and
Canadian gas production at fixed prices. However, such
commitments to date are not expected to have a material effect
on Devon's 1998 gas price differentials due to the limited
quantities of gas per day involved.
NGL Production Devon expects its production of NGLs in
1998 to total between 1.3 million barrels and 1.5 million
barrels.
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 or
deletions to the company s property base, changes in
production taxes, general changes in the prices of services
and materials that are used in the operation of the company s
properties and the amount of repair and workover activity
required on the company s properties.
Oil, gas and NGL prices will have a direct effect on
production taxes to be incurred in 1998. Future prices could
also have an effect on whether proposed workover projects are
economically feasible. These factors, coupled with the
uncertainty of future oil, gas and NGL prices, increase the
uncertainty inherent in estimating future production and
operating costs. Given these uncertainties, Devon estimates
that 1998's total production and operating costs will be
between $78.0 million and $90.5 million.
Depreciation, Depletion and Amortization The 1998 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 1998 compared to the
costs incurred for such efforts, and the revisions to Devon's
year-end 1997 reserve estimates which will be made during
1998.
The DD&A rate as of the beginning of 1998 was 4.08 per
Boe. Assuming a 1998 rate of between $4.10 per Boe and $4.45
per Boe, 1998 oil and gas property related DD&A expense is
expected to be $85 million to $93 million. Additionally,
Devon expects its non-oil and gas property related DD&A to
total between $3 million and $4 million in 1998.
General and Administrative Expenses Devon s general and
administrative expenses include the costs of many different
goods and services used in support of the company s business.
These goods and services are subject to general price level
increases or decreases. In addition, Devon s G&A expenses vary
with the company s level of activity and the related staffing
needs as well as with the amount of professional services
required during any given period. Should the company s
anticipated needs or the prices of the required goods and
services differ significantly from the company s expectations,
actual G&A expenses could vary materially from the estimate.
Given these limitations, G&A expenses are expected to be
between $13 million and $15 million in 1998.
Interest Expense Devon s management expects to fund
substantially all of its anticipated expenditures during 1998
with working capital and internally generated cash flow.
Should Devon s actual capital expenditures or internally
generated cash flow vary significantly from expectations,
interest expense could differ materially from the following
estimate. Given this limitation, interest expense is expected
to be less than $1 million in 1998.
Distributions on TCP Securities TCP Securities are
convertible into common shares of Devon at the option of the
holder. Any conversions of the TCP Securities would reduce the
amount of required distributions. Assuming all $149.5 million
of TCP Securities are outstanding for the entire year, Devon
will make $9.7 million of distributions in 1998.
Income Taxes Devon expects its financial income tax rate
in 1998 to be between 34% and 38%. Regardless of the level of
pre-tax earnings reported for financial purposes, Devon will
have a minimum of approximately $2.0 million of financial
income tax expense due to various aspects of the 1994 Alta
merger, the San Juan Basin Transaction and the KMG-NAOS
acquisition. Therefore, if the actual amount of 1998 pre-tax
earnings differs materially from what Devon currently expects,
the actual financial income tax rate for 1998 could differ
from the expected rate of 34% to 38%. Also, based on its
current expectations of 1998 taxable income, Devon anticipates
its current portion of 1998 income taxes will be between $12
million and $17 million. However, unanticipated revenue and
earnings fluctuations could easily make these tax estimates
inaccurate.
Capital Expenditures Devon s capital expenditures budget
is based on an expected range of future oil, natural gas and
NGL prices as well as the expected costs of the capital
additions. Should the company s price expectations for its
future production change significantly, the company may
accelerate or defer some projects and, consequently, may
increase or decrease total 1998 capital expenditures. In
addition, if the actual cost of the budgeted items varies
significantly from the amount anticipated, actual capital
expenditures could vary materially from Devon s estimate.
Though Devon has completed several major property
transactions 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.
Given these limitations, Devon expects its 1998 capital
expenditures for drilling and development efforts to total
between $140 million and $160 million, including $8 million to
$12 million in Canada. (Canadian amounts are expressed in
U.S. dollars, using the year-end 1997 exchange rate of $0.70
U.S. dollar to $1.00 Canadian dollar.) Devon expects to spend
$45 million to $60 million in 1998 for drilling, facilities
and waterflood costs related to reserves classified as proved
as of year-end 1997. Devon also plans to spend another $60
million to $70 million on new, higher risk/reward projects.
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 32.3 million
shares of common stock outstanding, 1998 dividends are
expected to approximate $6.5 million.
Capital Resources and Liquidity The estimated future
drilling and development activities are expected to be funded
through a combination of working capital and net cash provided
by operations. The amount of net cash to be provided by
operating activities in 1998 is uncertain due to the factors
affecting revenues and expenses cited above. However, Devon
expects that its capital resources will be more than adequate
to fund its anticipated capital expenditures.
Based on the expected level of 1998's capital
expenditures and net cash provided by operations, Devon does
not expect to rely on its existing credit lines to fund a
material portion of its capital expenditures. However, if
significant acquisitions or other unplanned capital
requirements arise during the year, Devon could utilize its
existing credit lines and/or seek to establish and utilize
other sources of financing. The unused portion of existing
credit lines at the end of 1997 consisted of $208 million of
long-term credit facilities, and a $12.5 million Canadian
dollars demand facility for Devon's Canadian operations. If
so desired, Devon believes that its lenders would increase its
credit lines to at least $450 million to $500 million.
However, the company does not desire nor anticipate a need to
increase its credit lines above their current levels.
Potential Reduction in 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 is compared to the ceiling on a quarterly
and annual basis. Any excess of the net book value above the
ceiling is written off as an expense.
At December 31, 1997, the Company's net book value of oil and
gas properties less deferred taxes was well below the calculated
ceiling. This excess "cushion" was $146 million for the Company's
U.S. properties and $18 million for its Canadian properties. By
March 11, 1998 oil prices had declined significantly from year-end
1997 levels. There had also been a moderate decline in natural gas
prices. Based on these decreases, Devon estimated that its ceiling
value on March 11, 1998 was significantly lower than at year-end
1997. However, the estimated ceiling value was still greater than
the book value of the Company's oil and gas properties less
deferred taxes. Oil or gas price declines after March 11, 1998
could cause the ceiling value to fall below the recorded net book
value. The result would be a reduction in the carrying value
of the Company's oil and gas properties. Should this occur, the
Company also would recognize a corresponding expense.
Impact of Recently Issued Accounting Standards Not Yet
Adopted In June, 1997, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No.
130, Reporting Comprehensive Income. SFAS No. 130 is
effective for fiscal years beginning after December 15, 1997.
SFAS No. 130 establishes standards for reporting and display
of comprehensive income and its components in a set of
financial statements. It requires that all items that are
required to be recognized under accounting standards as
components of comprehensive income be reported in a financial
statement that is displayed with the same prominence as other
financial statements. The only component of comprehensive
income that is not currently included in Devon s consolidated
statements of operations is the currency translation
adjustment reported as part of stockholders equity as of
December 31, 1997. Devon will adopt SFAS No. 130 in 1998.
Also in June, 1997, Statement of Financial Accounting
Standards No. 131, Disclosures about Segments of an
Enterprise and Related Information, was issued. SFAS No. 131
is effective for periods beginning after December 15, 1997.
SFAS No. 131 requires that publicly-traded entities report
financial and descriptive information about reportable
operating segments. Operating segments are components of an
enterprise about which separate financial information is
available that is evaluated regularly by the chief operating
decision maker in deciding how to allocate resources and in
assessing performance. Devon will adopt SFAS No. 131 in 1998.
However, such adoption is not expected to have a material
impact on Devon s current financial disclosures because
Devon s oil and gas operations are expected to be the only
reportable operating segment under SFAS No. 131 s definitions.
In January, 1997, the Securities and Exchange Commission
issued Release #33-7386. This release requires enhanced
description of accounting policies for derivative financial
instruments and derivative commodity instruments in the
footnotes to the financial statements. The release also
requires quantitative and qualitative disclosures outside the
financial statements about market risks inherent in market
risk sensitive instruments including derivative financial
instruments, derivative commodity instruments and other
financial instruments. The requirements regarding accounting
policy descriptions were effective for any fiscal period
ending after June 15, 1997. However, because derivative
financial or commodity instruments have not materially
affected Devon's financial position, cash flows or results of
operations, this part of the release did not affect Devon's
1997 disclosures. The quantitative and qualitative
disclosures set forth in the release will be initially
required in Devon's annual report on Form 10-K for the year
ending December 31, 1998.
Impact of the Year 2000 Issue An issue exists for all
companies that rely on computers as the year 2000 approaches.
This is because historically many computer programs used only
two digits to represent the year in dates. Therefore, without
adequate modifications, many programs will not correctly
identify the year 2000. Devon plans to install a Year 2000
Release of its commercial software during 1998.
In-house modifications that have been previously
made to the commercial software will also be upgraded at that
time to be year 2000 compliant. Devon anticipates that it
will be able to install the new commercial software release,
upgrade its modifications and test the entire system with its
existing internal programming staff. Therefore, future
incremental expenses, if any, incurred to deal with the year
2000 issue are expected to be immaterial to Devon's future
operating results.
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements and Consolidated
Financial Statement Schedules
Page
Independent Auditors' Report 44
Consolidated Financial Statements:
Consolidated Balance Sheets
December 31, 1997, 1996 and 1995 45
Consolidated Statements of Operations
Years Ended December 31, 1997, 1996 and 1995 46
Consolidated Statements of Stockholders' Equity
Years Ended December 31, 1997, 1996 and 1995 47
Consolidated Statements of Cash Flows
Years Ended December 31, 1997, 1996 and 1995 48
Notes to Consolidated Financial Statements
December 31, 1997, 1996 and 1995 49
All financial statement schedules are omitted as they are
inapplicable or the required information is immaterial.
<PAGE>
Independent Auditors' Report
The Board of Directors and Stockholders
Devon Energy Corporation:
We have audited the consolidated financial statements
of Devon Energy Corporation and subsidiaries as listed in the
accompanying index. 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 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 provide a
reasonable basis for our opinion.
In our opinion, 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, 1997, 1996 and 1995, and the
results of their operations and their cash flows for the years
then ended, in conformity with generally accepted accounting
principles.
KPMG Peat Marwick LLP
Oklahoma City, Oklahoma
January 26, 1998
<PAGE>
<TABLE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
<CAPTION>
December 31,
1997 1996 1995
Assets
Current assets:
<S> <C> <C> <C>
Cash and cash equivalents $ 42,064,344 9,401,350 8,897,891
Accounts receivable (Note 5) 47,507,805 29,580,306 14,400,295
Inventories 2,422,822 2,103,486 605,263
Prepaid expenses 799,923 688,752 222,135
Deferred income taxes (Note 8) 434,000 1,600,000 749,000
Total current assets 93,228,894 43,373,894 24,874,584
Property and equipment, at cost, based on
the full cost method of accounting for
oil and gas properties (Note 6) 1,103,320,502 974,805,756 631,437,904
Less accumulated depreciation,
depletion and amortization 365,517,722 281,959,410 239,619,167
737,802,780 692,846,346 391,818,737
Other assets 15,371,368 10,030,560 4,870,796
Total assets $ 846,403,042 746,250,800 421,564,117
Liabilities and stockholders' equity
Current liabilities:
Accounts payable:
Trade 9,628,890 4,861,428 3,868,458
Revenues and royalties due
to others 11,531,296 10,569,960 7,322,418
Income taxes payable 4,901,940 4,705,447 1,364,070
Accrued expenses 4,750,699 3,503,420 3,003,943
Total current liabilities 30,812,825 23,640,255 15,558,889
Revenues and royalties due to others 2,862,794 1,259,129 889,173
Other liabilities (Notes 3 and 11) 18,177,130 10,325,999 8,623,057
Long-term debt (Note 7) - 8,000,000 143,000,000
Deferred income taxes (Note 8) 101,474,000 81,121,000 34,452,000
Company-obligated mandatorily redeemable
convertible preferred securities of
subsidiary trust holding solely 6.5%
convertible junior subordinated debentures
of Devon Energy Corporation (Note 9) 149,500,000 149,500,000 -
Stockholders' equity (Note 10):
Preferred stock of $1.00 par value.
Authorized 3,000,000 shares;
none issued - - -
Common stock of $.10 par value.
Authorized 400,000,000 shares;
issued 32,318,895 in 1997,
32,141,295 in 1996, 22,111,896
in 1995 3,231,890 3,214,130 2,211,190
Additional paid-in capital 392,919,170 388,090,930 167,430,347
Retained earnings 149,946,232 81,099,357 49,399,461
Cumulative currency translation
adjustment (2,520,999) - -
Total stockholders' equity 543,576,293 472,404,417 219,040,998
Commitments and contingencies (Notes 11 and 12)
Total liabilities and
stockholders' equity $ 846,403,042 746,250,800 421,564,117
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
<CAPTION>
Year Ended December 31,
1997 1996 1995
Revenues
<S> <C> <C> <C>
Oil sales $133,445,231 80,142,073 55,289,819
Gas sales 150,548,871 68,049,478 50,732,158
Natural gas liquids sales 21,754,033 14,366,771 6,403,663
Other 7,391,733 1,458,562 877,185
Total revenues 313,139,868 164,016,884 113,302,825
Costs and expenses
Lease operating expenses 65,655,074 31,568,428 27,288,755
Production taxes 17,923,815 10,657,814 6,832,507
Depreciation, depletion and
amortization (Note 6) 85,306,868 43,361,029 38,089,783
General and administrative expenses 12,922,259 9,101,429 8,418,739
Interest expense 273,821 5,276,527 7,051,142
Distributions on preferred securities
of subsidiary trust (Note 9) 9,717,502 4,753,125 -
Total costs and expenses 191,799,339 104,718,352 87,680,926
Earnings before income taxes 121,340,529 59,298,532 25,621,899
Income tax expense (Note 8)
Current 25,202,000 6,709,000 4,495,000
Deferred 20,847,000 17,789,000 6,625,000
Total income tax expense 46,049,000 24,498,000 11,120,000
Net earnings $ 75,291,529 34,800,532 14,501,899
Net earnings per average common
share outstanding (Note 1):
Basic $2.34 1.57 0.66
Diluted $2.17 1.52 0.65
Weighted average common shares
outstanding - basic (Note 1) 32,215,745 22,159,507 22,073,550
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Stockholders' Equity
<CAPTION>
Year Ended December 31,
1997 1996 1995
Common stock
<S> <C> <C> <C>
Balance, beginning of year 3,214,130 2,211,190 2,205,100
Par value of common shares issued 17,760 1,002,940 6,090
Balance, end of year 3,231,890 3,214,130 2,211,190
Additional paid-in capital
Balance, beginning of year 388,090,930 167,430,347 166,654,305
Common shares issued, net
of issuance costs 3,628,240 220,660,583 776,042
Tax benefit related to employee
stock options 1,200,000 - -
Balance, end of year 392,919,170 388,090,930 167,430,347
Retained earnings
Balance, beginning of year 81,099,357 49,399,461 37,546,460
Dividends (6,444,654) (3,100,636) (2,648,898)
Net earnings 75,291,529 34,800,532 14,501,899
Balance, end of year 149,946,232 81,099,357 49,399,461
Cumulative currency translation adjustment
Balance, beginning of year - - -
Net change (2,520,999) - -
Balance, end of year (2,520,999) - -
Total stockholders' equity, end of year $543,576,293 472,404,417 219,040,998
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
<CAPTION>
Year Ended December 31,
1997 1996 1995
Cash flows from operating activities
<S> <C> <C> <C>
Net earnings $ 75,291,529 34,800,532 14,501,899
Adjustments to reconcile net earnings to net
cash provided by operating activities:
Depreciation, depletion and amortization 85,306,868 43,361,029 38,089,783
(Gain) loss on sale of assets (192,278) (3,930) 273,238
Deferred income taxes 20,847,000 17,789,000 6,625,000
Changes in assets and liabilities
net of effects of acquisitions
of businesses (Note 2):
(Increase) decrease in:
Accounts receivable (17,835,233) (15,470,528) 1,213,877
Inventories (344,286) (176,286) (70,937)
Prepaid expenses (116,932) (466,617) 342,236
Other assets (874,496) (1,032,653) 677,238
Increase (decrease) in:
Accounts payable 3,394,868 3,370,474 (430,736)
Income taxes payable 445,493 3,341,377 1,364,070
Accrued expenses 1,078,012 399,477 (221,550)
Revenues and royalties due to others 1,603,665 369,956 (1,793,909)
Long-term other liabilities 117,700 519,978 705,636
Net cash provided by operating
activities 168,721,910 86,801,809 61,275,845
Cash flows from investing activities
Proceeds from sale of property and equipment 1,711,769 4,037,480 9,427,401
Capital expenditures (130,468,542) (98,854,846) (117,593,897)
Payments made for acquisition of business - - (2,391,484)
Increase in other assets (2,583,920) - -
Net cash used in investing
activities (131,340,693) (94,817,366) (110,557,980)
Cash flows from financing activities
Proceeds from borrowings on revolving line
of credit 1,847,750 29,000,000 52,000,000
Principal payments on revolving line of credit (9,843,750) (164,000,000) (7,000,000)
Issuance of common stock, net of issuance costs 3,646,000 577,483 782,132
Issuance of preferred securities of subsidiary
trust, net of issuance costs - 144,665,205 -
Dividends paid on common stock (6,444,654) (3,100,636) (2,648,898)
Increase in long-term other liabilities (Note 3) 6,268,085 1,376,964 6,710,421
Net cash provided (used) by
financing activities (4,526,569) 8,519,016 49,843,655
Effect of exchange rate changes on cash (191,654) - -
Net increase in cash and cash equivalents 32,662,994 503,459 561,520
Cash and cash equivalents at beginning of year 9,401,350 8,897,891 8,336,371
Cash and cash equivalents at end of year $ 42,064,344 9,401,350 8,897,891
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1997, 1996 and 1995
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 are primarily in the
states of New Mexico, Texas, Oklahoma, Wyoming and Louisiana.
Effective December 31, 1996, Devon began operations in
Alberta, Canada. 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.
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 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 for Devon's oil and gas
properties in the United States and Canada. Capitalized costs
are depleted by an equivalent unit-of-production method,
converting gas and natural gas liquids to oil at the ratio of
one barrel ("Bbl") of oil to six thousand cubic
feet ("Mcf") of natural gas and one barrel of oil to 42
gallons of natural gas liquids. 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.
Devon adopted the provisions of SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of," on January 1, 1996.
SFAS No. 121 requires that long-lived assets and certain
identifiable intangibles be reviewed for impairment whenever
events or changes in circumstances indicate that the carrying
amount of an asset may not be recoverable. Due to Devon's use
of the full cost method of accounting for its oil and gas
properties, SFAS No. 121 does not apply to Devon's oil and gas
property assets which comprise approximately 97% of Devon's
net property and equipment. Accordingly, the adoption of SFAS
No. 121 did not have an impact on Devon's financial position
or results of operations in 1996.
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.
Gas Balancing
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 only if Devon's
excess takes of natural gas volumes exceed its estimated
remaining recoverable reserves. No receivables are recorded
for those wells where Devon has taken less than its ownership
share of gas production.
Stock Options
On January 1, 1996, Devon adopted SFAS No. 123,
"Accounting for Stock-Based Compensation," which permits
entities to recognize over the vesting period the fair value
of all stock-based awards on the date of grant.
Alternatively, SFAS No. 123 also allows entities to continue
to apply provisions of APB No. 25, "Accounting for Stock
Issued to Employees," whereby compensation expense is recorded
on the date of grant only if the current market price of the
underlying stock exceeds the exercise price. Companies which
continue to apply the provisions of APB No. 25 are required by
SFAS No. 123 to disclose pro forma net earnings and net
earnings per share for employee stock option grants made in
1995 and future years as if the fair-value-based method
defined in SFAS No. 123 had been applied. Devon has elected
to continue to apply the provisions of APB No. 25, and has
provided the pro forma disclosures required by SFAS No. 123 in
Note 10.
Major Purchasers
During 1997 and 1996, there was one purchaser,
Aquila Energy Marketing Corporation ("Aquila"), who accounted
for over 10% of Devon's gas sales. Aquila accounted for 46% of
Devon's 1997 gas sales and 45% of 1996 gas sales. During
1995, there were two purchasers who accounted for over 10% of
Devon's gas sales. These two purchasers and their respective
share of gas sales were: Aquila - 31%; and Enron Gas
Marketing, Inc. - 16%.
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.
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, net of amounts charged
to affiliated partnerships for administrative and overhead
costs, and net of amounts capitalized pursuant to the full
cost method of accounting.
Net Earnings Per Common Share
In February, 1997, the Financial Accounting
Standards Board issued Statement of Financial Accounting
Standards No. 128, Earnings Per Share. SFAS No. 128 revised
the previous calculation methods and presentations of earnings
per share. The statement required that all prior-period
earnings per share data be restated. Devon adopted SFAS No.
128 in the fourth quarter of 1997 as permitted by the
statement. The effect of adopting SFAS No. 128 was not
material to Devon s prior period earnings per share data. The
previously reported amounts for earnings per share assuming no
dilution (now replaced by "basic earnings per share" under
SFAS No. 128) were not affected for any prior periods.
Restated "diluted" earnings per share were $0.01 per share
less than the previously reported "earnings per share assuming
full dilution" for each of the following periods: the years
1995 and 1994 and the second and third quarters of 1996 (as
disclosed in Note 15).
Under the provisions of SFAS No. 128, 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
outstanding stock options were exercised (calculated using the
treasury stock method) or if Devon s Trust Convertible
Preferred Securities were converted to common stock.
The following tables reconcile the net earnings
and common shares outstanding used in the calculations of
basic and diluted net earnings per share for the years 1997,
1996 and 1995.
<TABLE>
<CAPTION>
Net
Common Earnings
Net Shares Per
Earnings Outstanding Share
Year ended December 31, 1997:
<S> <C> <C> <C>
Basic earnings per share $75,291,529 32,215,745 2.34
Dilutive effect of:
Potential common shares issuable upon
the conversion of Trust Convertible
Preferred securities (the increase in
net earnings is net of income tax expense
of $3,853,000) 6,025,955 4,901,507
Potential common shares issuable upon
the exercise of employee stock options - 408,477
Diluted earnings per share $81,317,484 37,525,729 2.17
Year ended December 31, 1996:
Basic earnings per share 34,800,532 22,159,507 1.57
Dilutive effect of:
Potential common shares issuable upon
the conversion of Trust Convertible
Preferred securities (the increase
in net earnings is net of income tax
expense of $1,837,000) 2,997,779 2,383,793
Potential common shares issuable upon
the exercise of employee stock options - 254,352
Diluted earnings per share $37,798,311 24,797,652 1.52
Year ended December 31, 1995:
Basic earnings per share 14,501,899 22,073,550 0.66
Dilutive effect of potential common
shares issuable upon the exercise
of employee stock options - 130,621
Diluted earnings per share $14,501,899 22,204,171 0.65
</TABLE>
Dividends
Dividends on common stock were paid in 1995 and
the first three quarters of 1996 at a per share rate of $0.03
per quarter. The dividend rate was increased to $0.05 per
share for the fourth quarter of 1996 and all four quarters of
1997.
Fair Value of Financial Instruments
Devon's only financial instruments for which the
fair value differs materially from the carrying value are the
interest rate swap discussed in Note 7 and the Trust
Convertible Preferred Securities discussed in Note 9. The
fair value and the carrying value for all other financial
instruments (cash and equivalents, accounts receivable,
accounts payable and long-term debt) are approximately equal.
Such equality is due to the short-term nature of the current
assets and liabilities and the fact that the interest rates
paid on Devon's long-term debt are set for periods of three
months or less.
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.
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.
In October, 1996, the American Institute of
Certified Public Accountants issued Statement of Position
(SOP) 96-1, "Environmental Remediation Liabilities." SOP 96-1
was adopted by Devon on January 1, 1997. It requires, among
other things, that environmental remediation liabilities be
accrued when the criteria of SFAS No. 5, "Accounting for
Contingencies," have been met. SOP 96-1 also provides
guidance with respect to the measurement of the remediation
liabilities. Such accounting is consistent with Devon's
method of accounting for environmental remediation costs.
Therefore, adoption of SOP 96-1 did not have a material impact
on Devon's financial position or results of operations.
Reclassifications
Certain items in the 1996 and 1995 consolidated
balance sheets and statements of cash flows have been
reclassified to correspond with the 1997 presentation.
2. Acquisitions and Pro Forma Information
On December 31, 1996, Devon acquired all of Kerr-
McGee Corporation's ("Kerr-McGee") North American onshore oil
and gas exploration and production business and properties
(the "KMG-NAOS Properties"). As consideration, Devon issued
9,954,000 shares of its common stock to Kerr-McGee. The
acquisition was made pursuant to an October 17, 1996,
agreement and plan of merger among Devon, Kerr-McGee and
certain of their subsidiaries.
Devon recorded the KMG-NAOS Properties at
approximately $221.6 million. Such value was based on the
value of the shares of Devon common stock issued as determined
pursuant to generally accepted accounting principles. An
additional $30.3 million was allocated to the KMG-NAOS
Properties for the deferred income tax liability created as a
result of the substantially tax-free nature of the transaction
to Kerr-McGee. Excluding the additional deferred tax
liability, the amount recorded for the KMG-NAOS Properties
includes approximately $195.1 million allocated to proved oil
and gas reserves, $29.0 million allocated to undeveloped
leasehold acquired, $0.6 million allocated to inventories and
other assets acquired and $3.1 million allocated to certain
assumed liabilities. Including the additional $30.3 million
of deferred tax liability, $220.0 million was allocated to
proved reserves and $34.4 million to undeveloped leasehold.
Estimated proved reserves associated with the KMG-
NAOS Properties as of December 31, 1996, were 47 million
barrels of oil equivalent ("MMBoe") in the United States and
15 MMBoe in Canada. These reserves were approximately 36% oil
and natural gas liquids and 64% natural gas. Included in the
acquired reserves were certain proved undeveloped reserves,
for which Devon expected to incur approximately $6 million of
future capital costs. The United
States assets acquired are located predominantly in the Rocky
Mountain, Permian Basin and Mid-Continent areas of the
country. All of these areas were already core areas of
Devon's operations. (The quantities of proved reserves and
the estimated development costs stated in this paragraph are
unaudited.)
On December 18, 1995, Devon acquired additional
interests in certain of its Wyoming oil and natural gas
properties and a gas processing plant (the "Worland
Properties") for approximately $50.3 million. The acquisition
was primarily funded with $46.0 million of borrowings from
Devon's credit lines. Approximately $46.3 million of the
purchase price was allocated to proved oil, gas and natural
gas liquids reserves and the plant. The remaining $4.0
million of the purchase price was allocated to undeveloped
leasehold.
Pro Forma Information (Unaudited)
The 1996 acquisition of the KMG-NAOS Properties as
described above was accounted for by the purchase method of
accounting for business combinations. Accordingly, the
accompanying 1996 consolidated statement of operations does
not include any revenues or expenses associated with the KMG-
NAOS Properties. Following are Devon's pro forma results for
1996 assuming the acquisition of the KMG-NAOS Properties
occurred on January 1, 1996:
<TABLE>
<CAPTION>
1996
Revenues
<S> <C>
Oil sales $148,337,000
Gas sales 125,092,000
Natural gas liquids sales 19,081,000
Other 4,674,000
Total revenues 297,184,000
Costs and expenses
Lease operating expenses 58,384,000
Production taxes 20,167,000
Depreciation, depletion and amortization 78,310,000
General and administrative expenses 14,101,000
Interest expense 5,277,000
Distributions on preferred securities
of subsidiary trust 4,753,000
Total costs and expenses 180,992,000
Earnings before income taxes 116,192,000
Income tax expense
Current 14,023,000
Deferred 32,721,000
Total income tax expense 46,744,000
Net earnings $ 69,448,000
Net earnings per average common
share outstanding:
Basic $2.16
Diluted $2.09
Weighted average common shares
outstanding - basic 32,086,310
Production data
Oil (Barrels) 7,241,000
Gas (Mcf) 70,925,000
Natural gas liquids (Barrels) 1,304,000
</TABLE>
The 1995 acquisition of the Worland Properties
described above was accounted for by the purchase method of
accounting for business combinations. Accordingly, the
accompanying consolidated statements of operations do not
include any revenues or expenses related to the Worland
Properties prior to the closing date of December 18, 1995.
Following are Devon's pro forma 1995 results assuming the
acquisition of KMG-NAOS Properties and the Worland Properties
both occurred on January 1, 1995:
<TABLE>
<CAPTION>
1995
Pro Forma Effect of
Devon KMG-NAOS Worland Devon
Historical Properties Properties Pro Forma
<S> <C> <C> <C> <C>
Total revenues $113,303,000 108,279,000 5,349,000 226,931,000
Net earnings $14,502,000 14,335,000 (1,405,000) 27,432,000
Net earnings per share:
Basic $0.66 0.86
Diluted $0.65 0.85
</TABLE>
3. San Juan Basin Transaction
Effective January 1, 1995, Devon and an unrelated
company entered into a transaction covering substantially all
of Devon's San Juan Basin coal seam gas properties (the "San
Juan Basin Transaction"). These coal seam gas properties
represented Devon's largest oil and gas reserve position as of
December 31, 1994. The properties' estimated reserves as of
year-end 1994 were 199.2 billion cubic feet ("Bcf") of natural
gas, or 31% of Devon's 633.2 equivalent Bcf of combined oil
and natural gas reserves. In addition to the cash flow
and earnings impact normally associated with oil and gas
production, these properties also qualify as a "nonconventional
fuel source" under the Internal Revenue Code of 1986.
Consequently, gas produced from these properties through the year
2002 qualifies for Section 29 tax credits, which as of year-end
1997 were equal to approximately $1.05 per million Btu ("MMBtu").
The San Juan Basin Transaction involves
approximately 186.2 Bcf, or 93%, of the year-end 1994 coal
seam gas reserves, and has four major parts associated with
it. First, Devon conveyed to the unrelated party 179 Bcf of
the properties' reserves. However, for financial reporting
purposes, Devon retained all of such reserves and their future
production and cash flow through a volumetric production
payment and a repurchase option. Second, Devon conveyed
outright to the unrelated party 7.2 Bcf of reserves for a
sales price of $5.2 million. The reserves and future cash
flow associated with this conveyance were not retained by
Devon. Third, and the source of the most significant impact
of the transaction, Devon receives payments equal to 75% of
the Section 29 tax credits generated by the properties. And
fourth, Devon retained a 75% reversionary interest in any
reserves in excess of the 186.2 Bcf estimated to exist as of
December 31, 1994. Each of these parts of the San Juan Basin
Transaction, and their effects on Devon's operations, are
described in more detail in the following paragraphs.
The production payment retained by Devon is equal
to 94.05% of the first 143.4 Bcf of gas produced from the
properties, or 134.9 Bcf. As such, Devon continues to record
gas sales and associated production and operating expenses and
reserves associated with the production payment. Production
from the retained production payment is currently estimated to
occur over a period of nine years.
The conveyance of the properties which are not
subject to the retained production payment or the repurchase
option was accounted for as a sale of oil and gas properties.
Accordingly, 7.2 Bcf of gas reserves were removed from total
proved reserves, and the $5.2 million of proceeds reduced the
book value of oil and gas properties. The conveyance to the
third party is limited exclusively to the existing wells
drilled as of January 1, 1995. Wells to be drilled in the
future, if any, are not included in this transaction.
In addition to receiving 94.05% of the properties'
net cash flow through the retained production payment, Devon
receives quarterly payments from the third party equal to 75%
of the value of the Section 29 tax credits which are generated
by production from such properties until the earlier of
December 31, 2002, or until the option to repurchase is
exercised. For the
years ended December 31, 1997, 1996 and 1995, Devon received
$11.4 million, $11.5 million and $13.9 million, respectively,
related to the credits. Of these amounts, $8.5 million, $10.3
million and $12.8 million were recorded as additional gas
sales in 1997, 1996 and 1995, respectively, and $2.9 million,
$1.2 million and $1.1 million were recorded as an addition to
liabilities in 1997, 1996 and 1995, respectively, as discussed
in the following paragraph. Based on the reserves estimated
at December 31, 1997, and an assumed annual inflation factor
of 2%, Devon estimates it will receive total tax credit
payments of approximately $49 million from 1998 through 2002.
Devon has an option to repurchase the properties
at any time. The purchase price of such option is equal to
the fair market value of the properties at the time the option
is exercised, as defined in the transaction agreement, less
the production payment balance. At closing, Devon received
$5.6 million associated with reserves to be produced
subsequent to the term of the production payment. Such amount
is included in long-term "other liabilities" on the
accompanying balance sheet. Since Devon expects to eventually
exercise its option to repurchase the properties, the
liability is being increased over time to reflect the expected
option purchase price. As the purchase price increases, a
portion of the tax credit payments received by Devon is added
to the liability. As stated above, for the years ended
December 31, 1997, 1996 and 1995, $2.9 million, $1.2 million
and $1.1 million, respectively, of the total amount received
for tax credit payments were added to the liability. On
December 31, 1997, Devon exercised its option to reacquire
approximately 20% of the properties for approximately $1.9
million. The
other party to the production payment paid Devon $5.3 million
in 1997 in return for Devon agreeing not to exercise its
option on the remaining 80% of the properties through the end
of 1997. (This agreement does not limit Devon's right to
exercise its option in 1998 or beyond.) The $5.3 million that
Devon received, net of the $1.9 million paid for the partial
repurchase, was added to the repurchase liability in 1997.
The repurchase liability totaled $14.2 million at the end of
1997.
Devon has retained a 75% reversionary interest in
the properties' reserves in excess, if any, of the 186.2 Bcf
of reserves estimated to exist at December 31, 1994. The
terms of the transaction provide that the third party will pay
100% of the capital necessary to develop any such incremental
reserves for its 25% interest in such reserves. Devon's
repurchase option also includes the right to purchase this
incremental 25%. However, the $14.2 million of other
liabilities recorded as of year-end 1997, does not include any
amount related to such reserves.
4. Supplemental Cash Flow Information
Cash payments for interest in 1997, 1996 and 1995
were approximately $0.6 million, $5.5 million and $6.7
million, respectively. Cash payments for federal, state and
foreign income taxes in 1997, 1996 and 1995 were approximately
$25.0 million, $3.4 million and $2.2 million, respectively.
The 1996 acquisition of the KMG-NAOS Properties
involved non-cash consideration as presented below:
<TABLE>
<S> <C>
Value of common stock issued $221,576,040
Liabilities assumed 3,098,691
Deferred tax liability created 30,308,000
Fair value of assets acquired $254,982,731
</TABLE>
5. Accounts Receivable
The components of accounts receivable included the
following:
<TABLE>
<CAPTION>
December 31,
1997 1996 1995
Oil, gas and natural gas liquids
<S> <C> <C> <C>
revenue accruals $32,643,633 24,200,047 11,169,313
Joint interest billings 11,742,554 4,318,764 2,962,037
Other 3,521,618 1,461,495 493,945
47,907,805 29,980,306 14,625,295
Allowance for doubtful accounts (400,000) (400,000) (225,000)
Net accounts receivable $47,507,805 29,580,306 14,400,295
</TABLE>
6. Property and Equipment
Property and equipment included the following:
<TABLE>
<CAPTION>
December 31,
1997 1996 1995
Oil and gas properties:
<S> <C> <C> <C>
Subject to amortization $1,024,624,931 899,827,749 604,227,702
Not subject to amortization:
Acquired in 1997 9,476,111 - -
Acquired in 1996 27,906,918 35,141,800 -
Acquired in 1995 3,916,088 5,034,942 5,635,170
Acquired in 1994 870,664 1,001,291 1,001,427
Acquired in 1993 4,026,995 5,204,995 5,556,977
Acquired in 1992 7,814,255 8,113,899 8,257,985
Accumulated depreciation,
depletion and amortization (361,055,425) (278,923,340) (237,385,785)
Net oil and gas properties 717,580,537 675,401,336 387,293,476
Other property and equipment 24,684,540 20,481,080 6,758,643
Accumulated depreciation and
amortization (4,462,297) (3,036,070) (2,233,382)
Net other property and
equipment 20,222,243 17,445,010 4,525,261
Property and equipment, net of
accumulated depreciation,
depletion and amortization $ 737,802,780 692,846,346 391,818,737
</TABLE>
Depreciation, depletion and amortization expense consisted of the following
components:
<TABLE>
<CAPTION>
Year Ended December 31,
1997 1996 1995
Depreciation, depletion and amortization
<S> <C> <C> <C>
of oil and gas properties $82,413,245 41,537,555 36,639,753
Depreciation and amortization of other
property and equipment 2,328,461 1,337,420 1,045,978
Amortization of other assets 565,162 486,054 404,052
Total expense $85,306,868 43,361,029 38,089,783
</TABLE>
7. Long-term Debt
Devon has long-term lines of credit pursuant to which it can
borrow up to an amount determined by the banks based on their
evaluation of the assets and cash flow (the "Borrowing Base")
of Devon. The established Borrowing Base at December 31, 1997,
was $208 million. Amounts borrowed under the credit lines
bear interest at various fixed rate options which Devon may
elect for periods up to 90 days. Such rates are generally
less than the prime rate. Devon may also elect to borrow at
the prime rate. No amounts were borrowed under the credit
lines at the end of 1997. The average interest rates on the
outstanding debt at the end of 1996 and 1995 were 6.19% and
6.64%, respectively. The loan agreements also provide for a
quarterly facility fee equal to .25% per annum.
Debt borrowed under the credit lines is unsecured. No
principal payments are required until maturity unless the
unpaid balance exceeds the maximum loan amount. The maximum
loan amount is equal to the Borrowing Base until August 31,
2000. Thereafter, the maximum loan amount will be reduced by
8.33% every three months until August 31, 2003. The loan
agreements contain certain covenants and restrictions, among
which are limitations on additional borrowings and annual
sales of properties valued at more than $25 million, and
working capital and net worth maintenance requirements. At
December 31, 1997, Devon was in compliance with such covenants
and restrictions.
Devon also has a demand revolving operating credit facility
with a Canadian bank. This facility is unsecured and is
utilized for general corporate purposes related to Devon's
Canadian operations. The credit line totals $12.5 million
Canadian dollars, and interest is charged at the bank's prime
rate for loans to Canadian customers. Amounts borrowed are
due on demand. However, due to Devon's sources of long-term
debt described above, amounts borrowed pursuant to the
Canadian credit line are expected to be classified as long-
term debt. No amounts were borrowed against the Canadian
credit line at year-end 1997 or 1996.
Devon entered into an interest rate swap agreement in June,
1995, to hedge the impact of interest rate changes on a
portion of its long-term debt. The notional amount of the
swap agreement was $75 million, and the other party to the
agreement was one of Devon's lenders. The swap agreement was
accounted for as a hedge. On July 1, 1996, Devon terminated
the interest rate swap agreement for a gain of $0.8 million.
This gain is being recognized ratably as a reduction to
interest expense during the period from July 1, 1996 to June
16, 1998 (the original expiration date of the agreement).
Approximately $0.4 million of the gain was recognized in 1997,
and $0.2 million was recognized in 1996. The fair value of
the interest rate swap as of December 31, 1995 was a liability
of approximately $1.4 million. The interest rate swap had no
carrying value in the accompanying consolidated financial
statements.
See Note 9 for a description of certain convertible
debentures issued in 1996 to a Devon affiliate.
8. Income Taxes
At December 31, 1997, Devon had the following carryforwards
available to reduce future federal and state income taxes:
<TABLE>
<CAPTION>
Years of Carryforward
Types of Carryforward Expiration Amounts
<S> <C> <C>
Net operating loss - federal 2007 - 2008 $ 7,300,000
Net operating loss - various states 1998 - 2011 $10,200,000
</TABLE>
All of the carryforward amounts shown above have been
utilized for financial purposes to reduce deferred taxes.
The earnings before income taxes and the components of
income tax expense for the years 1997, 1996 and 1995 were as
follows:
<TABLE>
<CAPTION>
Year Ended December 31,
1997 1996 1995
Earnings before income taxes:
<S> <C> <C> <C>
United States $106,905,365 59,298,532 25,621,899
Canada 14,435,164 - -
Total $121,340,529 59,298,532 25,621,899
Current income tax expense:
Federal $18,659,000 6,147,000 4,155,000
State 2,521,000 562,000 340,000
Canada 4,022,000 - -
Total current tax expense 25,202,000 6,709,000 4,495,000
Deferred income tax expense:
Federal 17,025,000 14,185,000 5,463,000
State 1,578,000 3,604,000 1,162,000
Canada 2,244,000 - -
Total deferred tax expense 20,847,000 17,789,000 6,625,000
Total income tax expense $46,049,000 24,498,000 11,120,000
</TABLE>
Total income tax expense differed from the amounts computed
by applying the federal income tax rate to net earnings before
income taxes as a result of the following:
<TABLE>
<CAPTION>
Year Ended December 31,
1997 1996 1995
<S> <C> <C> <C>
Federal statutory tax rate 35% 35% 35%
Nonconventional fuel source credits (1) - (1)
State income taxes 3 5 4
Taxation on foreign operations 1 - -
Effect of San Juan Basin Transaction - 2 4
Other - (1) 1
Effective income tax rate 38% 41% 43%
</TABLE>
The tax effects of temporary differences that gave rise to
significant portions of the deferred tax assets and
liabilities at December 31, 1997, 1996 and 1995 are presented
below:
<TABLE>
<CAPTION>
December 31,
1997 1996 1995
Deferred tax assets:
<S> <C> <C> <C>
Net operating loss carryforwards $ 2,909,000 5,314,000 6,082,000
Statutory depletion carryforwards - 412,000 2,287,000
Investment tax credit carryforwards 19,000 42,000 85,000
Minimum tax credit carryforwards - 5,624,000 5,576,000
Production payments 18,504,000 19,685,000 24,770,000
Other 2,932,000 2,613,000 1,966,000
Total gross deferred tax assets 24,364,000 33,690,000 40,766,000
Less valuation allowance 100,000 100,000 100,000
Net deferred tax assets 24,264,000 33,590,000 40,666,000
Deferred tax liabilities:
Property and equipment, principally due
to differences in depreciation, and
the expensing of intangile drilling
costs for tax purposes (123,783,000) (113,111,000) (74,369,000)
Other (1,521,000) - -
Total deferred tax liabilities (125,304,000) (113,111,000) (74,369,000)
Net deferred tax liability $(101,040,000) (79,521,000) (33,703,000)
</TABLE>
As shown in the above schedule, Devon has recognized $24.3
million of net deferred tax assets as of December 31, 1997.
Such amount consists almost entirely of $2.9 million of
various carryforwards available to offset future income taxes,
and $18.5 million of net tax basis in production payments.
The carryforwards include federal net operating loss
carryforwards, the majority of which do not begin to expire
until 2007, and state net operating loss carryforwards which
expire primarily between 1999 and 2011. 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 1998 and 2001. 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 $100,000 valuation
allowance has been recorded at December 31, 1997, related to
depletion carryforwards acquired in a 1994 merger.
The $18.5 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 which is described in such
note. 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 $18.5 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 newly-formed affiliate
Devon Financing Trust, completed the issuance of $149.5
million of 6.5% trust convertible preferred securities (the
"TCP Securities") in a private placement. Devon Financing
Trust issued 2,990,000 shares of the TCP Securities at $50 per
share. Each TCP Security is 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.
The sole assets of Devon Financing Trust are the Convertible
Debentures. The Convertible Debentures and the related TCP
Securities mature on June 15, 2026. However, Devon and Devon
Financing Trust may redeem the Convertible Debentures and the
TCP Securities, respectively, in whole or in part, on or after
June 18, 1999. For the first twelve months thereafter,
redemptions may be made at 104.55% of the principal amount.
This premium declines proportionally every twelve months until
June 15, 2006, when the redemption
price becomes fixed at 100% of the principal amount. If Devon
redeems any Convertible Debentures prior to the scheduled
maturity date, Devon Financing Trust must redeem TCP
Securities having an aggregate liquidation amount equal to the
aggregate principal amount of Convertible Debentures so
redeemed.
Devon has guaranteed the payments of distributions and other
payments on the TCP Securities only if and to the extent that
Devon Financing Trust has funds available therefor. Such
guarantee, when taken together with Devon's obligations under
the Convertible Debentures and related indenture and
declaration of trust, provide a full and unconditional
guarantee of amounts due on the TCP Securities.
Devon owns all the common securities of Devon Financing
Trust. As such, the accounts of Devon Financing Trust are
included in Devon's consolidated financial statements after
appropriate eliminations of intercompany balances. The
distributions on the TCP Securities are recorded as a charge
to pre-tax earnings on Devon's consolidated statements of
operations, and such distributions are deductible by Devon for
income tax purposes.
Devon estimates that the fair value of the TCP Securities as
of December 31, 1997 and 1996 was approximately $218.8 million
and $196.6 million, respectively, as compared to the book
value of $149.5 million. These fair values were based on
quoted prices at which TCP Securities were purchased and sold
on December 31, 1997 and 1996.
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 three million shares of preferred stock,
par value $1.00 per share (the "Preferred Stock"). 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.
Devon's Board of Directors has designated 150,000 shares of
the Preferred Stock as Series A Junior Participating Preferred
Stock (the "Series A Preferred Stock") in connection with the
adoption of the share rights plan described later in this
note. At December 31, 1997, there were no shares of Series A
Preferred Stock issued or outstanding. The Series A 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
Preferred Stock. Holders of the
Series A 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
Preferred Stock is neither redeemable nor convertible. The
Series A 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, 1997, 12 participants held the 251,100
options outstanding under the 1988 Plan, and 23 participants
held the 806,300 options outstanding under the 1993 Plan.
On May 21, 1997, Devon's stockholders adopted the 1997 Plan
and reserved two million shares of Common Stock for issuance
thereunder. Approximately 30 employees and eight members of
the board of directors were eligible to participate in the
1997 Plan at year-end 1997.
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, 1997, seven
participants (all of whom are non-management members of the
Board of Directors) held the 21,000 options outstanding under
the 1997 Plan. There were 1,979,000 options available for
future grants as of December 31, 1997.
A summary of the status of Devon's stock option plans as of
December 31, 1995, 1996 and 1997, and changes during each of
the years then ended, is presented below:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
Weighted Weighted
Average Average
Number Exercise Number Exercise
Outstanding Price Exercisable Price
<S> <C> <C> <C> <C>
Balance at December 31, 1994 877,900 $18.947 485,000 $17.423
Options granted 219,000 $23.875
Options exercised (60,900) $12.843
Options forfeited (7,100) $20.105
Balance at December 31, 1995 1,028,900 $20.349 688,800 $19.744
Options granted 248,500 $32.358
Options exercised (75,400) $12.909
Balance at December 31, 1996 1,202,000 $23.299 823,500 $21.783
Options granted 54,000 $34.584
Options exercised (177,600) $20.529
Balance at December 31, 1997 1,078,400 $24.320 824,500 $23.257
</TABLE>
The weighted average fair values of options granted
during 1997, 1996 and 1995 were $13.74, $12.97 and $9.89,
respectively. The fair value of each option grant was
estimated for disclosure purposes only on the date of grant
using the Black-Scholes Option Pricing Model with the
following assumptions for 1997, 1996 and 1995, respectively:
risk-free interest rates of 6.3%, 6.3% and 5.5%; dividend
yields of 0.6%, 0.6% and 0.5%; expected lives of five years
for each period; and volatility of the price of the underlying
common stock of 33.8%, 33.9% and 38.1%.
The following table summarizes information about Devon's
stock options which were outstanding, and those which were
exercisable, as of December 31, 1997:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
Weighted Weighted Weighted
Range of Average Average Average
Exercise Number Remaining Exercise Number Exercise
Prices Outstanding Life Price Exercisable Price
<S> <C> <C> <C> <C> <C>
$8-$14 90,800 3.7 years $ 9.677 90,800 $ 9.677
$18-$21 150,300 6.9 years $18.098 120,900 $18.106
$23-$26 539,800 6.8 years $23.799 451,000 $23.826
$32-$37 297,500 9.0 years $32.878 161,800 $33.138
1,078,400 7.2 years $24.320 824,500 $23.257
</TABLE>
Had Devon elected the fair value provisions of SFAS No. 123
and recognized compensation expense based on the fair value of
the stock options granted as of their grant date, Devon's
1997, 1996 and 1995 pro forma net earnings and pro forma net
earnings per share would have differed from the amounts
actually reported as shown in the table below. The pro forma
amounts shown below do not include the effects of stock
options granted prior to January 1, 1995. The pro forma
effects shown below may not be representative of the effects
reported in future years.
<TABLE>
<CAPTION>
Year Ended December 31,
1997 1996 1995
Net earnings:
<S> <C> <C> <C>
As reported $75,291,529 34,800,532 14,501,899
Pro forma $74,564,309 34,016,571 13,540,052
Net earnings per share:
As reported:
Basic $2.34 1.57 0.66
Diluted $2.17 1.52 0.65
Pro forma:
Basic $2.31 1.54 0.61
Diluted $2.15 1.49 0.61
</TABLE>
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. Retirement Plans
Devon has a defined benefit retirement plan (the "Basic
Plan") which is non-contributory and includes 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 Plan are retained by
Devon.
Effective January 1, 1995, Devon has a separate defined
benefit retirement plan (the "Supplementary Plan") which is
non-contributory and includes only certain employees whose
benefits under the Basic Plan are limited by federal income
tax regulations. The Supplementary Plan's benefits are based
on the employee's years of service and compensation. Devon's
funding policy for the Supplementary Plan is to fund the
benefits as they become payable. Rights to amend or terminate
the Supplementary Plan are retained by Devon.
The following table sets forth the aggregate funded status
of the Basic Plan and related amounts recognized in Devon's
balance sheets:
<TABLE>
<CAPTION>
December 31,
1997 1996 1995
Actuarial present value of benefit obligations:
Accumulated benefit obligation:
<S> <C> <C> <C>
Vested $(4,630,000) (3,619,000) (3,500,000)
Nonvested (1,021,000) (741,000) (654,000)
Total $(5,651,000) (4,360,000) (4,154,000)
Projected benefit obligation for service
rendered to date (6,690,000) (5,122,000) (4,782,000)
Plan assets at fair value, primarily investments
in mutual funds 6,036,000 5,022,000 4,227,000
Plan assets less than projected benefit obligation (654,000) (100,000) (555,000)
Unrecognized prior service cost (benefit) (105,000) (131,000) (154,000)
Unrecognized net loss from past experience
different from that assumed, and effects
of changes in assumptions 1,276,000 519,000 921,000
Prepaid pension expense $ 517,000 288,000 212,000
</TABLE>
The following table sets forth the aggregate funded
status of the Supplementary Plan and related amounts
recognized in Devon's balance sheets:
<TABLE>
<CAPTION>
December 31,
1997 1996 1995
Actuarial present value of benefit obligations:
Accumulated benefit obligation:
<S> <C> <C> <C>
Vested $(4,039,000) (1,960,000) (1,658,000)
Nonvested (237,000) (279,000) (255,000)
Total (4,276,000) (2,239,000) (1,913,000)
Projected benefit obligation for service
rendered to date (4,969,000) (2,907,000) (2,245,000)
Plan assets at fair value - - -
Plan assets less than projected benefit
obligation (4,969,000) (2,907,000) (2,245,000)
Unrecognized prior service cost 2,078,000 1,235,000 1,354,000
Unrecognized net loss from past experience
different from that assumed, and effects
of changes in assumptions 1,172,000 446,000 185,000
Accrued pension expense (1,719,000) (1,226,000) (706,000)
Additional minimum liability (2,557,000) (1,013,000) (1,207,000)
Total pension liability $(4,276,000) (2,239,000) (1,913,000)
</TABLE>
The $4.3 million, $2.2 million and $1.9 million
total pension liability of the Supplementary Plan as of
December 31, 1997, 1996 and 1995, respectively, are included
in long-term other liabilities on the accompanying
consolidated balance sheets. The additional minimum
liabilities of $2.6 million, $1.0 million and $1.2 million at
year-end 1997, 1996 and 1995, respectively, are offset by
intangible assets of the same amount. These intangible assets
are included in other assets on the balance sheets.
Net pension expense for Devon's two defined benefit
plans included the following components:
<TABLE>
<CAPTION>
Year Ended December 31,
1997 1996 1995
<S> <C> <C> <C>
Service cost - benefits earned during the period $ 706,000 557,000 362,000
Interest cost on projected benefit obligation 747,000 569,000 446,000
Actual return on plan assets (369,000) (453,000) (536,000)
Net amortization and deferral 177,000 231,000 345,000
Net periodic pension expense $1,261,000 904,000 617,000
</TABLE>
The weighted average discount rate used in determining the
actuarial present value of the projected benefit obligation in
1997, 1996 and 1995 was 7.0%, 7.5% and 7.25%, respectively.
The rate of increase in future compensation levels was 5% for
all three years. The expected long-term rate of return on
assets was 8.5% for all three years.
Devon has a 401(k) Incentive Savings Plan which covers all
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
$451,000, $188,000 and $170,000 for the years ended December
31, 1997, 1996 and 1995, respectively.
12. 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
after consideration of recorded accruals.
The State of New Mexico on December 29, 1995, assessed Devon
and other producers of gas from the San Juan Basin a "natural
gas processors tax." Devon's tax assessment for the years
1990 through 1995 was approximately $0.6 million, and the
state also assessed another $0.3 million of penalties and
interest. All of the assessment relates to nonconventional
gas. Devon paid these assessments in January 1996, as well as
an additional $0.2 million each year for 1997 and 1996 taxes
which were paid monthly throughout such years, so that it
could begin the necessary procedures of applying for a refund.
This tax historically was paid by the owners of natural gas
processing plants, not the gas producers, and was assessed for
the privilege of processing natural gas. While Devon's
nonconventional gas is purified through a plant prior to the
actual sales point, such purification is only for the purpose
of removing CO2. Also, Devon does not own an interest in such
plant. For these and other reasons, Devon does not believe
the assessment of the additional tax and the related penalties
and interest is valid. The State of New Mexico in 1997 denied
Devon's initial refund application made through the normal
administrative processes. Subsequently, in late 1997, Devon
filed a suit asking that the assessments be reversed. At this
time, it is not possible to determine the eventual outcome of
this matter. Devon has not expensed in its financial
statements the taxes, penalties and interest paid, but rather
has recorded the $1.3 million total as a receivable.
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, 1997:
<TABLE>
<CAPTION>
Year ending December 31,
<S> <C>
1998 $ 555,000
1999 402,000
2000 326,000
2001 88,000
2002 40,000
Total minimum lease payments required $1,411,000
</TABLE>
Total rental expense for all operating leases is as follows
for the years ended December 31:
<TABLE>
<S> <C>
1997 $1,130,896
1996 $ 572,177
1995 $ 546,388
</TABLE>
13. Oil and Gas Operations
Costs Incurred
The following tables reflect the costs incurred in oil and
gas property acquisition, exploration, and development
activities:
<TABLE>
<CAPTION>
Total
Year Ended December 31,
1997 1996 1995
Property acquisition costs:
Proved, excluding deferred income
<S> <C> <C> <C>
taxes $10,997,000 199,655,000 47,316,000
Deferred income taxes 2,379,000 22,557,000 -
Total proved, including deferred income taxes $ 13,376,000 222,212,000 47,316,000
Unproved, excluding deferred income taxes $ 8,734,000 29,673,000 4,529,000
Deferred income taxes (100,000) 5,472,000 -
Total unproved, including deferred income taxes 8,634,000 35,145,000 4,529,000
Exploration costs $19,169,000 2,708,000 7,174,000
Development costs $87,394,000 73,468,000 56,253,000
</TABLE>
<TABLE>
<CAPTION>
Domestic
Year Ended December 31,
1997 1996 1995
Property acquisition costs:
Proved, excluding deferred income
<S> <C> <C> <C>
taxes $10,891,000 150,546,000 47,316,000
Deferred income taxes 2,084,000 15,257,000 -
Total proved, including deferred income taxes $12,975,000 165,803,000 47,316,000
Unproved, excluding deferred income taxes $ 7,582,000 26,073,000 4,529,000
Deferred income taxes (100,000) 5,472,000 -
Total unproved, including deferred income taxes 7,482,000 31,545,000 4,529,000
Exploration costs $18,326,000 2,708,000 7,174,000
Development costs $79,943,000 73,468,000 56,253,000
</TABLE>
<TABLE>
<CAPTION>
Canada
Year Ended December 31,
1997 1996 1995
Property acquisition costs:
Proved, excluding deferred income
<S> <C> <C> <C>
taxes $ 106,000 49,109,000 -
Deferred income taxes 295,000 7,300,000 -
Total proved, including deferred income taxes $ 401,000 56,409,000 -
Unproved $ 1,152,000 3,600,000 -
Exploration costs $ 843,000 - -
Development costs $ 7,451,000 - -
</TABLE>
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 activities. Such capitalized expenses, which are
included in the costs shown in the above tables, were $4.1
million, $2.9 million and $2.7 million in the years 1997, 1996
and 1995, respectively.
Due to the substantially tax-free nature of the acquisition
of the KMG-NAOS properties to Kerr-McGee, Devon recorded
additional deferred tax liabilities of $28.0 million in 1996.
As shown in the above 1996 tables, the deferred tax
liabilities caused an additional $22.5 million to be allocated
to proved oil and gas reserves and an additional $5.5 million
to be allocated to unproved properties.
During 1997, various uncertainties that existed at year-end
1996 regarding the tax basis and liabilities assumed in the
KMG-NAOS transaction 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 above 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.
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.
<TABLE>
<CAPTION>
Total
Year Ended December 31,
1997 1996 1995
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales $305,748,000 162,558,000 112,425,000
Production and operating expenses (83,579,000) (42,226,000) (34,121,000)
Depreciation, depletion and amortization (82,413,000) (41,538,000) (36,640,000)
Income tax expense (51,050,000) (27,796,000) (15,536,000)
Results of operations for oil and gas
producing activities $ 88,706,000 50,998,000 26,128,000
Depreciation, depletion and amortization
per equivalent barrel of production $4.08 3.88 3.65
</TABLE>
<TABLE>
<CAPTION>
Domestic
Year Ended December 31,
1997 1996 1995
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales $273,860,000 162,558,000 112,425,000
Production and operating expenses (75,758,000) (42,226,000) (34,121,000)
Depreciation, depletion and amortization (73,091,000) (41,538,000) (36,640,000)
Income tax expense (44,648,000) (27,796,000) (15,536,000)
Results of operations for oil and gas
producing activities $ 80,363,000 50,998,000 26,128,000
Depreciation, depletion and amortization
per equivalent barrel of production $4.13 3.88 3.65
</TABLE>
<TABLE>
<CAPTION>
Canada
Year Ended December 31,
1997 1996 1995
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales $ 31,888,000 - -
Production and operating expenses (7,821,000) - -
Depreciation, depletion and amortization (9,322,000) - -
Income tax expense (6,402,000) - -
Results of operations for oil and gas
producing activities $ 8,343,000 - -
Depreciation, depletion and amortization
per equivalent barrel of production $3.74 - -
</TABLE>
As previously discussed, the above tables 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. Shown below are 1997 domestic and Canadian total
revenues and net earnings, including all revenues and all
costs and expenses, as well as total assets.
<TABLE>
<CAPTION>
Domestic Canada Total
As of or for the Year Ended December 31, 1997:
<S> <C> <C> <C>
Total revenues $278,834,000 34,306,000 313,140,000
Net earnings $ 67,123,000 8,169,000 75,292,000
Total assets $776,134,000 70,269,000 846,403,000
</TABLE>
14. 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 Statement of Financial Accounting
Standards 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, 1997.
Approximately 92%, 94% and 92%, of the respective year-end
1997, 1996 and 1995 domestic proved reserves were calculated
by the independent petroleum consultants of LaRoche Petroleum
Consultants, Ltd. The remaining percentages of domestic
reserves are based on Devon's own estimates. All of the 1997
and 1996 Canadian proved reserves were calculated by the
independent petroleum consultants of AMH Group Ltd.
<TABLE>
<CAPTION>
Total
Natural
Oil Gas Gas Liquids
(Bbls) (Mcf) (Bbls)
<S> <C> <C> <C>
Proved reserves as of December 31, 1994 42,165,000 347,560,000 5,442,000
Revisions of estimates 1,127,000 (7,431,000) 535,000
Extensions and discoveries 2,959,000 9,645,000 472,000
Purchase of reserves 1,852,000 59,585,000 3,665,000
Production (3,300,000) (36,886,000) (600,000)
Sale of reserves (337,000) (8,627,000) (45,000)
Proved reserves as of December 31, 1995 44,466,000 363,846,000 9,469,000
Revisions of estimates 2,365,000 4,359,000 1,096,000
Extensions and discoveries 3,680,000 14,849,000 852,000
Purchase of reserves 21,189,000 249,922,000 2,130,000
Production (3,816,000) (35,714,000) (952,000)
Sale of reserves (403,000) (1,743,000) (16,000)
Proved reserves as of December 31, 1996 67,481,000 595,519,000 12,579,000
Revisions of estimates (1,520,000) (17,173,000) 1,614,000
Extensions and discoveries 8,517,000 106,608,000 301,000
Purchase of reserves 1,126,000 992,000 16,000
Production (7,005,000) (69,327,000) (1,626,000)
Sale of reserves (156,000) (615,000) (3,000)
Proved reserves as of December 1997 68,443,000 616,004,000 12,881,000
Proved developed reserves as of:
December 31, 1994 18,718,000 324,302,000 3,123,000
December 31, 1995 28,703,000 311,664,000 6,149,000
December 31, 1996 60,202,000 570,265,000 11,212,000
December 31, 1997 60,165,000 506,374,000 12,098,000
</TABLE>
<TABLE>
<CAPTION>
Domestic
Natural
Oil Gas Gas Liquids
(Bbls) (Mcf) (Bbls)
<S> <C> <C> <C>
Proved reserves as of December 31, 1994 42,165,000 347,560,000 5,442,000
Revisions of estimates 1,127,000 (7,431,000) 535,000
Extensions and discoveries 2,959,000 9,645,000 472,000
Purchase of reserves 1,852,000 59,585,000 3,665,000
Production (3,300,000) (36,886,000) (600,000)
Sale of reserves (337,000) (8,627,000) (45,000)
Proved reserves as of December 31, 1995 44,466,000 363,846,000 9,469,000
Revisions of estimates 2,365,000 4,359,000 1,096,000
Extensions and discoveries 3,680,000 14,849,000 852,000
Purchase of reserves 13,659,000 209,064,000 1,246,000
Production (3,816,000) (35,714,000) (952,000)
Sale of reserves (403,000) (1,743,000) (16,000)
Proved reserves as of December 31, 1996 59,951,000 554,661,000 11,695,000
Revisions of estimates (1,358,000) (21,124,000) 1,531,000
Extensions and discoveries 7,394,000 94,925,000 301,000
Purchase of reserves 1,126,000 992,000 16,000
Production (6,055,000) (61,015,000) (1,468,000)
Sale of reserves (156,000) (615,000) (3,000)
Proved reserves as of December 31, 1997 60,902,000 567,824,000 12,072,000
Proved developed reserves as of:
December 31, 1994 18,718,000 324,302,000 3,123,000
December 31, 1995 28,703,000 311,664,000 6,149,000
December 31, 1996 52,672,000 529,407,000 10,328,000
December 31, 1997 53,059,000 462,082,000 11,289,000
</TABLE>
<TABLE>
<CAPTION>
Canada
Natural
Oil Gas Gas Liquids
(Bbls) (Mcf) (Bbls)
<S> <C> <C> <C>
Proved reserves as of December 31, 1995 - - -
Revisions of estimates - - -
Extensions and discoveries - - -
Purchase of reserves 7,530,000 40,858,000 884,000
Production - - -
Sale of reserves - - -
Proved reserves as of December 31, 1996 7,530,000 40,858,000 884,000
Revisions of estimates (162,000) 3,951,000 83,000
Extensions and discoveries 1,123,000 11,683,000 -
Purchase of reserves - - -
Production (950,000) (8,312,000) (158,000)
Sale of reserves - - -
Proved reserves as of December 31, 1997 7,541,000 48,180,000 809,000
Proved developed reserves as of
December 31, 1996 7,530,000 40,858,000 884,000
December 31, 1997 7,106,000 44,292,000 809,000
</TABLE>
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:
<TABLE>
<CAPTION>
Total
December 31,
1997 1996 1995
<S> <C> <C> <C>
Future cash inflows $2,516,923,000 3,989,582,000 1,476,418,000
Future costs:
Development (88,292,000) (54,133,000) (52,327,000)
Production (866,609,000) (1,071,913,000) (496,279,000)
Future income tax expense (317,064,000) (785,702,000) (153,431,000)
Future net cash flows 1,244,958,000 2,077,834,000 774,381,000
10% discount to reflect timing of
cash flows (518,105,000) (901,617,000) (328,481,000)
Standardized measure of
discounted future net cash flows $ 726,853,000 1,176,217,000 445,900,000
Discounted future net cash
flows before income taxes $ 913,073,000 1,621,992,000 534,248,000
</TABLE>
<TABLE>
<CAPTION>
Domestic
December 31,
1997 1996 1995
<S> <C> <C> <C>
Future cash inflows $2,304,602,000 3,712,956,000 1,476,418,000
Future costs:
Development (83,350,000) (54,064,000) (52,327,000)
Production (806,130,000) (1,013,750,000) (496,279,000)
Future income tax expense (269,880,000) (713,182,000) (153,431,000)
Future net cash flows 1,145,242,000 1,931,960,000 774,381,000
10% discount to reflect timing of
cash flows (481,263,000) (846,174,000) (328,481,000)
Standardized measure of
discounted future net cash flows $ 663,979,000 1,085,786,000 445,900,000
Discounted future net cash
flows before income taxes $ 820,448,000 1,486,603,000 534,248,000
</TABLE>
<TABLE>
<CAPTION>
Canada
December 31,
1997 1996 1995
<S> <C> <C> <S>
Future cash inflows $212,321,000 276,626,000 -
Future costs:
Development (4,942,000) (69,000) -
Production (60,479,000) (58,163,000) -
Future income tax expense (47,184,000) (72,520,000) -
Future net cash flows 99,716,000 145,874,000 -
10% discount to reflect timing of
cash flows (36,842,000) (55,443,000) -
Standardized measure of
discounted future net cash flows $ 62,874,000 90,431,000 -
Discounted future net cash
flows before income taxes $ 92,625,000 135,389,000 -
</TABLE>
Future cash inflows are computed by applying year-end prices
(averaging $16.93 per barrel of oil, adjusted for
transportation and other charges, $1.89 per Mcf of gas and
$12.42 per barrel of natural gas liquids at December 31, 1997)
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.
In addition to the future gas revenues calculated at $1.89 per
Mcf, Devon's total future gas revenues also include the future
tax credit payments to be received and recorded as gas
revenues pursuant to the San Juan Basin Transaction described
in Note 3. Devon's future total and domestic cash inflows
shown in the tables above include $35.2 million related to
these tax credit payments from 1998 through 2002. This amount
has been calculated using the assumption that the year-end
1997 tax credit rate of $1.05 per MMBtu remains constant.
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 pretax 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.
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:
<TABLE>
<CAPTION>
Year Ended December 31,
1997 1996 1995
<S> <C> <C> <C>
Beginning balance $1,176,217,000 445,900,000 358,206,000
Sales of oil, gas and natural gas
liquids, net of production costs (222,169,000) (120,332,000) (78,304,000)
Net changes in prices and
production costs (723,385,000) 519,456,000 60,498,000
Extensions, discoveries, and improved
recovery, net of future
development costs 52,566,000 42,522,000 22,308,000
Purchase of reserves, net of future
development costs 7,696,000 576,234,000 50,000,000
Development costs incurred during
the period which reduced future
development costs 27,883,000 44,332,000 43,810,000
Revisions of quantity estimates (10,044,000) 40,905,000 7,397,000
Sales of reserves in place (1,395,000) (6,499,000) (7,933,000)
Accretion of discount 162,199,000 53,425,000 39,821,000
Net change in income taxes 259,555,000 (357,427,000) (48,347,000)
Other, primarily changes in timing (2,270,000) (62,299,000) (1,556,000)
Ending balance $ 726,853,000 1,176,217,000 445,900,000
</TABLE>
15. Supplemental Quarterly Financial Information
(Unaudited)
Following is a summary of the unaudited interim results of
operations for the years ended December 31, 1997 and 1996:
<TABLE>
<CAPTION>
1997
First Second Third Fourth Full
Quarter Quarter Quarter Quarter Year
Oil, gas and natural gas liquids
<S> <C> <C> <C> <C> <C>
sales $86,572,042 67,759,826 70,517,534 80,898,733 305,748,135
Total revenues $87,899,646 69,651,782 72,860,503 82,727,937 313,139,868
Net earnings $25,225,546 14,829,990 16,305,960 18,930,033 75,291,529
Net earnings per share:
Basic $0.78 0.46 0.51 0.59 2.34
Diluted $0.71 0.44 0.47 0.54 2.17
</TABLE>
<TABLE>
<CAPTION>
1996
First Second Third Fourth Full
Quarter Quarter Quarter Quarter Year
Oil, gas and natural gas liquids
<S> <C> <C> <C> <C> <C>
sales $33,734,229 36,743,221 39,007,410 53,073,462 162,558,322
Total revenues $34,048,060 37,298,613 39,473,680 53,196,531 164,016,884
Net earnings $ 5,553,926 6,775,388 7,707,673 14,763,545 34,800,532
Net earnings per share:
Basic $0.25 0.31 0.35 0.66 1.57
Diluted $0.25 0.30 0.34 0.59 1.52
</TABLE>
The above amounts for diluted net earnings per share for the
second and third quarters of 1996 have been restated from the
amounts previously reported as "net earnings per share
assuming full dilution" due to the adoption of SFAS No. 128 as
discussed in Note 1.
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
PART III
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 30, 1998.
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 30, 1998.
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 30, 1998.
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 30, 1998.
<PAGE>
PART IV
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 42 of this report.
2. Consolidated Financial Statement Schedules
All financial statement schedules are omitted
as they are inapplicable, or the required
information is immaterial.
3. Exhibits
2.1 Agreement and Plan of Merger among Registrant,
Devon Energy Corporation (Nevada), Kerr-McGee
Corporation, Kerr-McGee North American Onshore
Corporation and Kerr-McGee Canada Onshore Ltd.,
dated October 17, 1996 (incorporated by reference to
Addendum A to Registrant's definitive proxy
statement for a special meeting of shareholders,
filed on November 6, 1996).
3.1 Registrant's Certificate of Incorporation, as amended
(incorporated by reference to Exhibit B to Registrant's
definitive Proxy Statement for its 1995 Annual Meeting
of Shareholders filed on April 21, 1995).
3.2 Registrant's Certificate of Amendment of Certificate of
Incorporation (incorporated by reference to Exhibit 2
to Registrant's Current Report on Form 8-K dated
December 31, 1996).
3.3 Registrant's Bylaws (incorporated by reference to
Exhibit 3.2 to Registrant's Registration Statement
on Form 8-B filed on June 7, 1995).
4.1 Form of Common Stock Certificate (incorporated by
reference to Exhibit 4.1 to Registrant's Registration
Statement on Form 8-B filed on June 7, 1995).
4.2 Rights Agreement between Registrant and The First
National Bank of Boston (incorporated by reference
to Exhibit 4.2 to Registrant's Registration Statement
on Form 8-B filed on June 7, 1995).
4.3 First Amendment to Rights Agreement between Registrant
and The First National Bank of Boston, dated October
16, 1996 (incorporated by reference to Exhibit H-1
to Addendum A to Registrant's definitive proxy
statement for a special meeting of shareholders,
filed on November 6, 1996).
4.4 Second Amendment to Rights Agreement between
Registrant and the First National Bank of Boston,
dated December 31, 1996 (incorporated by reference
to Exhibit 4.2 to Registrant's Current Report on
Form 8-K dated December 31, 1996).
4.5 Certificate of Designations of Series A Junior
Participating Preferred Stock of Registrant
(incorporated by reference to Exhibit 3.3 to
Registrant's Registration Statement on Form 8-B
filed on June 7, 1995).
4.6 Certificate of Trust of Devon Financing Trust
[incorporated by reference to Exhibit 4.5 to
Amendment No. 1 to Registrant's Registration
Statement on Form S-3 (No. 333-00815)].
4.7 Amended and Restated Declaration of Trust of Devon
Financing Trust, dated as of July 3, 1996, by
J. Larry Nichols, H. Allen Turner, William T. Vaughn,
The Bank of New York (Delaware) and The Bank
of New York as Trustees and the Registrant as
Sponsor [incorporated by reference to Exhibit 4.6
to Amendment No. 1 to Registrant's Registration
Statement on Form S-3 (No. 333-00815)].
4.8 Indenture, dated as of July 3, 1996, between the
Registrant and The Bank of New York [incorporated
by reference to Exhibit 4.7 to Amendment No. 1 to
Registrant's Registration Statement on Form S-3
(No. 333-00815)].
4.9 First Supplemental Indenture, dated as of July 3, 1996,
between the Registrant and The Bank of New York
[incorporated by reference to Exhibit 4.8 to
Amendment No. 1 to Registrant's Registration
Statement on Form S-3 (No. 333-00815)].
4.10 Form of 6 1/2% Preferred Convertible Securities
(included as Exhibit A-1 to Exhibit 4.7 above).
4.11 Form of 6 1/2% Convertible Junior Subordinated
Debentures (included as Exhibit B to Exhibit 4.7 above).
4.12 Preferred Securities Guarantee Agreement, dated
July 3, 1996, between Registrant, as Guarantor, and
The Bank of New York, as Preferred Guarantee Trustee
[incorporated by reference to Exhibit 4.11 to
Amendment No. 1 to Registrant's Registration
Statement on Form S-3 (No. 333-00815)].
4.13 Stock Rights and Restrictions Agreement, dated as
of December 31, 1996, between Registrant and
Kerr-McGee Corporation (incorporated by reference
to Exhibit 4.3 to Registrant's Current Report on
Form 8-K dated December 31, 1996).
4.14 Registration Rights Agreement, dated December 31,1996,
by and between Registrant and Kerr-McGee Corporation
(incorporated by reference to Exhibit 4.4 to
Registrant's Current Report on Form 8-K, dated
December 31, 1996).
10.1 Credit Agreement, dated August 30, 1996, among
Devon Energy Corporation (Nevada), as Borrower,
the Registrant and Devon Energy Operating Corporation, as
Guarantors, NationsBank of Texas, N.A., as
Agent, and NationsBank of Texas, N.A., Bank
One, Texas, N.A., Bank of Montreal, and First
Union National Bank of North Carolina, as
Lenders (incorporated by reference to Exhibit
10.1 to Registrant's Quarterly Report on Form
10-Q for the quarter ended September 30,
1996).
10.2 First Amendment to Credit Agreement, dated March 15,
1997, among Devon Energy Corporation (Nevada), as
Borrower, the Registrant, as Guarantor, NationsBank of
Texas, N.A., as Agent and NationsBank of
Texas, N.A., Bank One, Texas, N.A., Bank of
Montreal and First Union National Bank of
North Carolina (incorporated by reference to
Exhibit 10.2 to Registrant's Quarterly Report
on Form 10-Q for the quarter ended March 31, 1997).
10.3 Devon Energy Corporation 1988 Stock Option Plan
[incorporated by reference to Exhibit 10.4 to
Registrant's Registration Statement on Form S-4
(No. 33-23564)].*
10.4 Devon Energy Corporation 1993 Stock Option Plan
(incorporated by reference to Exhibit A to Registrant's
Proxy Statement for the 1993 Annual Meeting of
Shareholders filed on May 6, 1993).*
10.5 Devon Energy Corporation 1997 Stock Option Plan
(incorporated by reference to Exhibit A to Registrant's
Proxy Statement for the 1997 Annual Meeting of the
Shareholders filed on April 3, 1997).*
10.6 Severance Agreement between Devon Energy Corporation
(Nevada), Devon Energy Corporation (Delaware) and Mr.
J. Larry Nichols, dated December 3, 1992 (incorporated
by reference to Exhibit 10.10 to Registrant's
Amendment No. 1 to Annual Report on Form 10-K
for the year ended December 31, 1992).*
10.7 Severance Agreement between Devon Energy Corporation
(Nevada), Devon Energy Corporation (Delaware) and
Mr. J. Michael Lacey, dated December 3, 1992
(incorporated by reference to Exhibit 10.12 to
Registrant's Amendment No. 1 to Annual Report
on Form 10-K for the year ended December 31, 1992).*
10.8 Severance Agreement between Devon Energy Corporation
(Nevada), Devon Energy Corporation (Delaware) and
Mr. H. Allen Turner, dated December 3, 1992
(incorporated by reference to Exhibit 10.13
to Registrant's Amendment No. 1 to Annual Report
on Form 10-K for the year ended December 31, 1992).*
10.9 Severance Agreement between Devon Energy Corporation
(Nevada), Devon Energy Corporation (Delaware) and
Mr. Darryl G. Smette, dated December 3, 1992
(incorporated by reference to Exhibit 10.14 to
Registrant's Amendment No. 1 to Annual Report on
Form 10-K for the year ended December 31, 1992).*
10.10 Severance Agreement between Devon Energy Corporation
(Nevada), Devon Energy Corporation (Delaware) and
Mr. William T. Vaughn, dated December 3, 1992
(incorporated by reference to Exhibit 10.15
to Registrant's Amendment No. 1 to Annual Report
on Form 10-K for the year ended December 31, 1992).*
10.11 Severance Agreement between Devon Energy Corporation
(Nevada), Registrant and Duke R. Ligon, dated
March 26, 1997 (incorporated by reference to Exhibit
10.11 to Registrant's Quarterly Report on
Form 10-Q for the quarter ended June 30, 1997).*
10.12 Employment Agreement between Devon Energy Corporation
(Nevada), Registrant and Duke R. Ligon, dated February
7, 1997 (incorporated by reference to Exhibit 10.12
to Registrant's Quarterly Report on Form 10-Q for
the quarter ended June 30, 1997).*
10.13 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 Registrant's Quarterly
Report on Form 10-Q for the quarter ended June 30, 1997).*
10.14 Sale and Purchase Agreement relating to Registrant's
San Juan Basin gas properties (incorporated by
reference to Exhibit 10.15 to Registrant's Quarterly
Report on Form 10-Q for the quarter ended
September 30, 1995).
10.15 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 Registrant's Quarterly Report on
Form 10-Q for the quarter ended September 30, 1995).
10.16 Registration Rights Agreement, dated July 3, 1996,
by and among the Registrant, Devon Financing Trust
and Morgan Stanley & Co. Incorporated [incorporated
by reference to Exhibit 10.1 to Amendment No. 1 to
Registrant's Registration Statement on Form S-3
(No. 333-00815)].
11 Computation of earnings per share
12 Computation of ratio of earnings to fixed charges
21 Subsidiaries of Registrant (incorporated by
reference to Exhibit 21 to Registrant's
Form 10-K for the year ended December 31, 1996).
23.1 Consent of LaRoche Petroleum Consultants, Ltd.
23.2 Consent of AMH Group, Ltd.
23.3 Consent of KPMG Peat Marwick, LLP
* Compensatory plans or arrangements.
(b) Reports on Form 8-K - No reports on Form 8-K
were filed during the fourth quarter of1997.
A Current Report on Form 8-K dated January 20, 1998,
was filed by the Registrant regarding year-end 1997
reserves, 1997 production and modifications to 1997
forward-looking information. A Current Report on
Form 8-K dated January 27, 1998, was filed by the
Registrant regarding 1998 forward-looking information.
<PAGE>
FORM S-8 UNDERTAKING
For the purposes of complying with the amendments to the
rules governing Form S-8 (effective July 13, 1990) under the
Securities Act of 1933, the undersigned Registrant hereby
undertakes as follows, which undertaking shall be incorporated by
reference to the Registrant's Registration Statement on Form S-8
(No. 33-32378) and Registrant's Registration Statement on Form S-
8 (No. 33-67924).
Insofar as indemnification for liabilities arising
under the Securities Act of 1933 may be permitted to
directors, officers and controlling persons of the
Registrant pursuant to the foregoing provisions, or
otherwise, the Registrant has been advised that in the
opinion of the Securities and Exchange Commission such
indemnification is against public policy as expressed
in the Act and is, therefore, unenforceable. In the
event that a claim for indemnification against such
liabilities (other than the payment by the Registrant
of expenses incurred or paid by a director, officer or
controlling person of the Registrant in the successful
defense of any action, suit or proceeding) is asserted
by such director, officer or controlling person in
connection with the securities being registered, the
Registrant will, unless in the opinion of its counsel
the matter has been settled by controlling precedent,
submit to a court of appropriate jurisdiction the
questions whether such indemnification by it is against
public policy as expressed in the Act and will be
governed by the final adjudication of such issue.
<PAGE>
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 13, 1998 By 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 13, 1998 By John W. Nichols
John W. Nichols
Chairman of the Board and Director
March 13, 1998 By J. Larry Nichols
J. Larry Nichols
President, Chief Executive Officer
and Director
March 13, 1998 By William T. Vaughn
William T. Vaughn
Vice President - Finance
March 13, 1998 By Danny J. Heatly
Danny J. Heatly
Controller
March 13, 1998 By H. R. Sanders, Jr.
H. R. Sanders, Jr.
Director
March 13, 1998 By Luke R. Corbett
Luke R. Corbett, Director
March 13, 1998 By Thomas F. Ferguson
Thomas F. Ferguson, Director
March 13, 1998 By David M. Gavrin
David M. Gavrin, Director
March 13, 1998 By Michael E. Gellert
Michael E. Gellert, Director
March 13, 1998 By Tom J. McDaniel
Tom J. McDaniel, Director
March 13, 1998 By Lawrence H. Towell
Lawrence H. Towell, Director
<PAGE>
INDEX TO EXHIBITS
Page
2.1 Agreement and Plan of Merger and
Reorganization by and among Registrant and
Devon Energy Corporation, a Delaware
corporation, dated as of April 13, 1995 #
2.2 Agreement and Plan of Merger among
Registrant, Devon Energy Corporation
(Nevada), Kerr-McGee Corporation, Kerr-
McGee North American Onshore Corporation
and Kerr-McGee Canada Onshore Ltd., dated
October 17, 1996 #
3.1 Registrant's Certificate of Incorporation,
as amended #
3.2 Registrant's Certificate of Amendment of
Certificate of Incorporation #
3.3 Registrant's Bylaws #
4.1 Form of Common Stock Certificate #
4.2 Rights Agreement between Registrant and The
First National Bank of Boston #
4.3 First Amendment to Rights Agreement between
Registrant and The First National Bank of
Boston dated October 16, 1996 #
4.4 Second Amendment to Rights Agreement
between Registrant and the First National
Bank of Boston, dated December 31, 1996 #
4.5 Certificate of Designations of Series A
Junior Participating Preferred Stock of
Registrant #
4.6 Certificate of Trust of Devon Financing
Trust #
4.7 Amended and Restated Declaration of Trust
of Devon Financing Trust dated as of July
3, 1996, by J. Larry Nichols, H. Allen
Turner, William T. Vaughn, The Bank of New
York (Delaware) and The Bank of New York as
Trustees and the Registrant as Sponsor #
4.8 Indenture dated as of July 3, 1996, between
the Registrant and The Bank of New York #
4.9 First Supplemental Indenture dated as of
July 3, 1996, between the Registrant and
The Bank of New York #
4.10 Form of 6 1/2% Preferred Convertible
Securities (included as Exhibit A-1 to
Exhibit 4.5 above) #
4.11 Form of 6 1/2% Convertible Junior
Subordinated Debentures (included in
Exhibit 4.7 above) #
4.12 Preferred Securities Guarantee Agreement
dated July 3, 1996, between Registrant, as
Guarantor, and The Bank of New York, as
Preferred Guarantee Trustee #
4.13 Stock Rights and Restrictions Agreement
dated as of December 31, 1996, between
Registrant and Kerr-McGee Corporation #
4.14 Registration Rights Agreement, dated
December 31, 1996, by and between
Registrant and Kerr-McGee Corporation #
10.1 Credit Agreement dated August 30, 1996,
among Devon Energy Corporation (Nevada), as
Borrower, the Registrant and Devon Energy
Operating Corporation, as Guarantors,
NationsBank of Texas, N.A., as Agent, and
NationsBank of Texas, N.A., Bank One,
Texas, N.A., Bank of Montreal, and First
Union National Bank of North Carolina, as
Lenders #
10.2 First Amendment to Credit Agreement dated March 15, 1997,
among Devon Energy Corporation (Nevada), as Borrower, the
Registrant, as Guarantor, NationsBank of Texas, N.A., as Agent
and NationsBank of Texas, N.A., Bank One, Texas, N.A., Bank of
Montreal and First Union National Bank of North Carolina #
10.3 Devon Energy Corporation 1988 Stock Option
Plan #
10.4 Devon Energy Corporation 1993 Stock Option
Plan #
10.5 Devon Energy Corporation 1997 Stock Option
Plan #
10.6 Severance Agreement between Devon Energy
Corporation (Nevada), Devon Energy
Corporation (Delaware) and Mr. J. Larry
Nichols, dated December 3, 1992 #
10.7 Severance Agreement between Devon Energy
Corporation (Nevada), Devon Energy
Corporation (Delaware) and Mr. J. Michael
Lacey, dated December 3, 1992 #
10.8 Severance Agreement between Devon Energy
Corporation (Nevada), Devon Energy
Corporation (Delaware) and Mr. H. Allen
Turner, dated December 3, 1992 #
10.9 Severance Agreement between Devon Energy
Corporation (Nevada), Devon Energy
Corporation (Delaware) and Mr. Darryl G.
Smette, dated December 3, 1992 #
10.10 Severance Agreement between Devon Energy
Corporation (Nevada), Devon Energy
Corporation (Delaware) and Mr. William T.
Vaughn, dated December 3, 1992 #
10.11 Severance Agreement between Devon Energy
Corporation (Nevada), Registrant and Duke
R. Ligon, dated March 26, 1997 #
10.12 Employment Agreement between Registrant and
Duke R. Ligon, dated February 7, 1997 #
10.13 Supplemental Retirement Income Agreement
between Devon Energy Corporation (Nevada),
Registrant and John W. Nichols, dated March
26, 1997 #
10.14 Sale and Purchase Agreement relating to
Registrant's San Juan Basin gas properties #
10.15 Second Restatement of and Amendment to Sale
and Purchase Agreement relating to
Registrant's San Juan Basin gas properties #
10.16 Registration Rights Agreement dated July 3,
1996, by and among the Registrant, Devon
Financing Trust and Morgan Stanley & Co.
Incorporated #
11 Computation of earnings per share 99
12 Computation of ratio of earnings to fixed
charges 100
21 Subsidiaries of Registrant #
23.1 Consent of LaRoche Petroleum Consultants,
Ltd. 101
23.2 Consent of AMH Group Ltd. 102
23.3 Consent of KPMG Peat Marwick LLP 103
____________________________________
# Incorporated by reference.
<TABLE>
DEVON ENERGY CORPORATION Exhibit 11
Computation of Earnings Per Share
<CAPTION>
Year Ended December 31,
1997 1996 1995
BASIC EARNINGS PER SHARE
<S> <C> <C> <C>
Net earnings per statement of operations $75,291,529 34,800,532 14,501,899
Weighted average common shares outstanding 32,215,745 22,159,507 22,073,550
Basic earnings per share $2.34 1.57 0.66
DILUTED EARNINGS PER SHARE
Net earnings per statement of operations $75,291,529 34,800,532 14,501,899
Increase in net earnings from assumed conversion
of Trust Convertible Preferred Securities
(net of tax effect) 6,025,955 2,997,779 -
Net earnings, as adjusted $81,317,484 37,798,311 14,501,899
Weighted average common shares outstanding as shown
in basic computation above 32,215,745 22,159,507 22,073,550
Add weighted average of additional shares issued
from assumed conversion of Trust Convertible
Preferred Securities 4,901,507 2,383,793 -
Add fully dilutive effect of outstanding stock options
(as determined using the treasury stock method) 408,477 254,352 -
Weighted average common shares outstanding, as adjusted 37,525,729 24,797,625 22,204,171
Diluted earnings per common share $2.17 1.52 0.65
</TABLE>
<TABLE>
DEVON ENERGY CORPORATION Exhibit 12
Computation of Ratio of Earnings to Fixed Charges
<CAPTION>
Year Ended December 31,
1997 1996 1995
<S> <C> <C> <C>
Earnings before income taxes $121,340,529 59,298,532 25,621,899
Add:
Interest expense 273,821 5,276,527 7,051,142
Distributions on preferred securities of subsidiary 9,717,502 4,753,125 -
Amortization of costs incurred in connection with the
offering of the preferred securities of subsidiary
trust 161,113 82,003 -
Estimated interest factor of operating lease payments 376,965 190,726 182,129
Earnings, as adjusted (A) $131,869,930 69,600,913 32,855,170
Fixed charges:
Interest costs incurred 273,821 5,276,527 7,051,142
Distributions on preferred securities of subsidiary
trust 9,717,502 4,753,125 -
Amortization of costs incurred in connection with
the offering of the preferred securities of
subsidiary trust 161,113 82,003 -
Estimated interest factor of operating lease payments 376,965 190,726 182,129
Total fixed charges (B) $10,529,401 10,302,381 7,233,271
Ratio of earnings to fixed charges (A) / (B) 12.52 6.76 4.54
</TABLE>
<PAGE>
Exhibit 23.1
ENGINEER'S CONSENT
We consent to incorporation by reference in the Registration
Statements (No. 33-32378 and No. 33-67924) on Form S-8 and the
Registration Statement (No. 333-00815) on Form S-3 of Devon
Energy Corporation the reference to our appraisal report for
Devon Energy Corporation as of December 31, 1997, which appears
in the December 31, 1997 annual report on Form 10-K of Devon
Energy Corporation.
WILLIAM E. LAROCHE
LAROCHE PETROLEUM CONSULTANTS, LTD.
March 10, 1998
Exhibit 23.2
ENGINEER'S CONSENT
We consent to incorporation by reference in the Registration
Statements (No. 33-32378 and No. 33-67924) on Form S-8 and the
Registration Statement (No. 333-00815) on Form S-3 of Devon
Energy Corporation the reference to our appraisal report for
Devon Energy Corporation as of December 31, 1997, which appears
in the December 31, 1997 annual report on Form 10-K of Devon
Energy Corporation.
ALLEN ASTON
AMH GROUP, LTD.
March 10, 1998
Exhibit 23.3
INDEPENDENT AUDITORS' CONSENT
The Board of Directors and Stockholders
Devon Energy Corporation:
We consent to incorporation by reference in the Registration
Statements (No. 33-32378 and 33-67924) on Form S-8 and the
Registration Statement (No. 333-00815) on Form S-3 of Devon
Energy Corporation of our report dated January 26, 1998, relating
to the consolidated balance sheets of Devon Energy Corporation
and subsidiaries as of December 31, 1997, 1996 and 1995 and the
related consolidated statements of operations, stockholders'
equity, and cash flows for each of the years then ended, which
report appears in the December 31, 1997 annual report on Form 10-
K of Devon Energy Corporation.
KPMG Peat Marwick LLP
KPMG Peat Marwick LLP
Oklahoma City, Oklahoma
March 10, 1998
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<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 42064344
<SECURITIES> 0
<RECEIVABLES> 47507805
<ALLOWANCES> 0
<INVENTORY> 2422822
<CURRENT-ASSETS> 93228894
<PP&E> 1103320502
<DEPRECIATION> 365517722
<TOTAL-ASSETS> 846403042
<CURRENT-LIABILITIES> 30812825
<BONDS> 0
3231890
0
<COMMON> 0
<OTHER-SE> 540344403
<TOTAL-LIABILITY-AND-EQUITY> 846403042
<SALES> 305748135
<TOTAL-REVENUES> 313139868
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 83578889
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 273821
<INCOME-PRETAX> 121340529
<INCOME-TAX> 46049000
<INCOME-CONTINUING> 75291529
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 75291529
<EPS-PRIMARY> 2.34
<EPS-DILUTED> 2.17
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