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, 1996
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 73102-8260
Oklahoma City, Oklahoma (Zip Code)
(Address of Principal Executive Offices)
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 shares 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, 1997 was
$1,020,619,000. At such date 32,141,295 shares of common stock
were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 1997 annual meeting of stockholders - Part III
<PAGE>
TABLE OF CONTENTS
Page
PART I
Item 1. Business 3
Item 2. Properties 12
Item 3. Legal Proceedings 21
Item 4. Submission of Matters to a Vote of Security Holders 22
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters 22
Item 6. Selected Financial Data 24
Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations 26
Item 8. Financial Statements and Supplementary Data 42
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 82
PART III
Item 10. Directors and Executive Officers of
the Registrant 82
Item 11. Executive Compensation 82
Item 12. Security Ownership of Certain Beneficial
Owners and Management 82
Item 13. Certain Relationships and
Related Transactions 82
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K 83
DEFINITIONS
As used in this document:
"Mcf" means thousand cubic feet
"MMcf" means million cubic feet
"Bcf" means billion cubic feet
"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>
FORWARD LOOKING STATEMENTS
This document contains "forward looking statements" as
defined by the Securities Litigation Reform Act of 1995. These
statements should be read in conjunction with the cautionary
statements included in this document, including those found under
"Item 2. Properties - Proved Reserves and Estimated Future Net
Revenues" and "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations."
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. 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 405/235-3611).
Devon currently owns interests in approximately 2,200 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 16 hereof.)
At December 31, 1996, Devon's estimated proved reserves were
179.3 MMBoe, which were balanced between oil and NGLs (45%) and
natural gas (55%). The present value of pre-tax future net
revenues discounted at 10% per annum assuming unescalated prices
("10% Present Value") of such reserves was $1.6 billion. 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 six
significant acquisitions and drilled 637 new wells, 614 of which
were producers. These activities have resulted in reserve
additions of 196.9 million Boe. Capital costs incurred to
complete these activities totaled $743.2 million, for a five-year
finding and development cost of $3.77 per Boe. Reserve additions
and adjustments, minus production and property sales, resulted in
an annual average reserve replacement factor of 435%.
Devon's objective, however, is to increase value per share,
not simply to increase total assets. Reserves have grown from
3.12 Boe per fully-diluted share at year-end 1991 to 4.84 Boe
per fully-diluted share at year-end 1996. During this same five-
year period, net debt (long-term debt minus working capital) has
remained relatively low, never exceeding $1.17 per Boe, and was
zero at year-end 1996.
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
During 1996 Devon completed two notable transactions which
had a significantly positive impact on the Company's size and
financial strength. These two transactions are discussed below.
Trust Convertible Preferred Offering. On July 3, 1996,
Devon Financing Trust, a Delaware business trust organized by
Devon, closed a $149.5 million private placement of 6-1/2% trust
convertible preferred securities (the "TCP Securities"). The net
proceeds of $144.7 million were used to repay substantially all
of Devon's then outstanding bank debt. This increased Devon's
unused borrowing capacity, which can be used for future
acquisitions and drilling projects.
The TCP Securities, which do not mature until June, 2026,
are convertible at the holders' option into Devon common stock at
a conversion price of $30.50 per common share. The securities
are redeemable at Devon's option beginning on June 18, 1999. See
note 9 to Devon's consolidated financial statements included
herein for a detailed description of the TCP Securities.
Kerr-McGee Transaction. On December 31, 1996, Devon
acquired the North American onshore oil and gas exploration and
production properties and business of Kerr-McGee Corporation (the
"KMG-NAOS Properties") in exchange for 9,954,000 shares of Devon
common stock (the "Kerr-McGee Transaction"). The transaction
increased Devon's year-end 1996 reserves by 62 MMBoe, or
approximately 50%, and tripled the Company's net undeveloped
leasehold inventory to 490,000 net acres. The KMG-NAOS
Properties are concentrated in the Permian Basin, the Rocky
Mountains and the Mid-Continent regions of the United States -
areas in which Devon previously owned significant reserves - and
in the Western Canada Sedimentary Basin of Alberta, Canada, which
is a new producing province for Devon.
After consummation of the Kerr-McGee Transaction, Kerr-McGee
Corporation ("Kerr-McGee") owns 31% (26% on a fully-diluted
basis) of Devon's outstanding common stock. Because of Kerr-
McGee's relatively large ownership position, Devon and Kerr-McGee
entered into two agreements which define and limit their
respective rights and obligations. In addition, Devon's board of
directors amended Devon's share rights plan so that Devon's
existing anti-takeover defenses will remain in force for third
parties and/or certain further transactions with Kerr-McGee.
Each of these arrangements are defined in the Stock Rights and
Restrictions Agreement, the Registration Rights Agreement, the
First Amendment to the Rights Agreement and the Second Amendment
to the Rights Agreement. These documents are included as
exhibits to this Form 10-K.
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 1997 will be concentrated in the Permian
Basin, Rocky Mountains 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
---------- --- ----- ---------- --- -----
<S> <C> <C> <C> <C> <C> <C>
1992 53 2 55 7.84 0.12 7.96
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
--- -- --- ------ ---- ------
594 13 607 376.55 3.04 379.59
</TABLE>
<TABLE>
<CAPTION>
Exploratory Wells
Gross (1) Net (2)
---------------------- ----------------------
Productive Dry Total Productive Dry Total
---------- --- ----- ---------- --- -----
<S> <C> <C> <C> <C> <C> <C>
1992 3 1 4 1.09 0.25 1.34
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
-- -- -- ---- ---- ----
20 10 30 7.69 4.37 12.06
(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.
</TABLE>
As of December 31, 1996, Devon was participating in the
drilling of 30 gross (14.51 net) wells which are not included in
the table above. Through February 24, 1997, six gross (1.30 net)
of these wells were completed as productive and the remaining
wells were still in progress.
Customers
For the year ended December 31, 1996, one significant
purchaser, Aquila Energy Marketing Corporation ("Aquila"),
accounted for 45% of Devon's natural gas sales. 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. For the year ended December
31, 1994, Aquila, Enron and Meridian Oil Trading, Inc. ("MOTI")
accounted for 21%, 19% and 18%, respectively, of Devon's gas
sales. Until September, 1995, MOTI was a significant purchaser of
Devon's coal seam gas production at market-sensitive prices under
the terms of a five-year contract entered into in May, 1990.
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. Virtually all of Devon's natural gas
production is sold at variable, or market-sensitive prices.
Though exact percentages vary daily, approximately 7% of such
natural gas is sold under short-term contracts. The remaining 93%
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 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 90 day
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.
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 have begun to more
effectively utilize natural gas storage facilities by purchasing
some of their anticipated winter requirements during the summer.
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. The
Mineral Lands Leasing Act of 1920 places limitations on the
number of acres of federal lands that may be leased by any entity
or person in any one state. Additionally, the Mineral Lands
Leasing Act of 1920 and related regulations also restrict a
corporation from holding federal onshore oil and gas leases if
stock of such corporation is owned by citizens of foreign
countries which are not deemed reciprocal under such Act.
Reciprocity depends, in large part, on whether the laws of the
foreign jurisdiction discriminate against a United States
citizen's ownership of rights to minerals in such jurisdiction.
The purchase of shares in Devon by citizens of foreign countries
with laws which are not deemed to be reciprocal under such Act
could have an impact on Devon's ownership of federal leases.
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's
unreimbursed expenditures in 1996 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.
No Price Controls on Liquid Hydrocarbons. There are
currently no price controls on crude oil, condensate or NGLs.
Canadian Regulation
Canadian Government Regulation. The oil and gas industry 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. On January 1,
1994, the North American Free Trade Agreement ("NAFTA") among the
governments of Canada, the U.S. and Mexico became effective. The
NAFTA 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
resource exported relative to domestic use, (ii) impose an export
price higher than the domestic price, and (iii) disrupt normal
channels of supply. All three countries are prohibited from
imposing minimum export or import price requirements.
The NAFTA contemplates the reduction of Mexican restrictive
trade practices in the energy sector and prohibits discriminatory
border restrictions and export taxes. The agreement also
contemplates clearer disciplines on regulators to ensure fair
implementation of any regulatory changes and to minimize
disruption of contractual arrangements, which is important for
Canadian natural gas exports.
Royalties and Incentives. In addition to federal
regulation, each producing province has legislation and
regulations which govern land tenure, royalties, production
rates, 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 mineral owner and the lessee. Crown royalties are
determined by government regulation and are generally calculated
as a percentage of the value of the gross production, and the
rate of royalties payable generally depends in part on 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 established incentive programs which have
included royalty rate reductions, royalty holidays and tax
credits for the purpose of encouraging oil and natural gas
exploration or enhanced recovery projects. Regulations made
pursuant to the Alberta Mines and Mineral Act provide various
incentives for exploring and developing oil reserves in Alberta.
In Alberta, the royalty reserved to the Crown in respect of
natural gas production, subject to various incentives, is between
15% and 30%, in the case of new gas, and between 15% and 35%, in
the case of old gas, depending upon a prescribed or corporate
average reference price. Gas produced from qualifying intervals
in eligible gas wells spudded or deepened to a depth below 2,500
meters is subject to a royalty exemption, the amount of which
depends on the depth of the well.
In Alberta, a producer of oil or natural gas is entitled to
a credit against the royalties payable to the Crown by virtue of
the Alberta Royalty Tax Credit ("ARTC") program. The ARTC program
is based on a price sensitive formula, and the ARTC rate varies
between 75%, at prices for oil below $100 per cubic meter, and
25%, at prices above $210 per cubic meter. The ARTC rate is
applied to a maximum of $2,000,000 of Alberta Crown royalties
payable for each producer or associated group of producers. Crown
royalties on production from producing properties acquired from
corporations claiming maximum entitlement to ARTC will generally
not be eligible for ARTC. The rate is established quarterly based
on the average "par price", as determined by the Alberta
Department of Energy for the previous quarterly period.
Oil and natural gas royalty holidays and reductions for
specific wells reduce the amount of Crown royalties paid by Devon
to the provincial governments. The ARTC program provides a rebate
on Crown royalties paid in respect of eligible producing
properties. Both of these incentives increase the net income of
Devon.
Producers of oil and natural gas in British Columbia are
required to pay annual rental payments in respect of Crown leases
and royalties and freehold production taxes in respect of oil and
gas produced from Crown and freehold lands respectively. The
amount payable as a royalty in respect of oil depends on the
vintage of the oil (whether it was produced from a pool
discovered before or after October 31, 1975), the quantity of oil
produced in a month and the value of the oil. Oil produced from
newly discovered pools may be exempt from the payment of a
royalty for the first 36 months of production. The royalty
payable on natural gas is determined by a sliding scale based on
a reference price which is the greater of the amount obtained by
the producer and at prescribed minimum price. Gas produced in
association with oil has a minimum royalty of 8% while the
royalty in respect of other gas may not be less than 15%.
Canadian Environmental Regulation. The oil and natural gas
industry is currently subject to environmental regulation
pursuant to 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. In Alberta, environmental
compliance has been governed by the Environmental Protection and
Enhancement Act (Alberta) (the "EPEA") since September 1, 1993.
In addition to replacing a variety of older statutes which
related to environmental matters, the EPEA also imposes certain
new environmental responsibilities on oil and natural gas
operators in Alberta and in certain instances also imposes
greater penalties for violations. Devon is committed to meeting
its responsibilities to protect the environment wherever it
operates and anticipates making increased, although not material,
expenditures of both a capital and expense nature as a result of
the increasingly stringent laws relating to the protection of the
environment.
Natural Gas Regulations. Natural gas sold within the
Province of Alberta is not subject to regulation. Prices are
negotiated and established based upon prevailing market
conditions. Natural gas sold outside Alberta can only be removed
from the province under a removal permit, issued by the
Government of Alberta. The Government, through the Alberta Energy
and Utilities Board ("AEUB"), will issue a removal permit only
after assessing the reserves from the proposed pools supporting
the application, and to a lesser extent reviewing the pricing
provisions of the sales contract.
Natural gas exported to the United States is subject to
approval by the National Energy Board of the Government of
Canada. Exports can be approved provided that the National Energy
Board is satisfied that Canadian demand will be met from current
and expected supplies and the sale is of net benefit to Canada.
While export prices are determined by negotiation between the
buyer and seller, the National Energy Board monitors the prices.
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 that constitutes an acquisition of control of a
Canadian business requiring Government of Canada approval. The
Act requires notification of the establishment of new unrelated
businesses in Canada by entities not controlled by Canadians, but
does not require Government of Canada approval except when the
new business is related to Canada's cultural heritage or national
identity.
Employees
As of December 31, 1996, Devon's staff consisted of 231 full-
time employees, including 19 professionals in engineering, 8 in
geology, 5 in the land department, 4 in oil and gas marketing, 30
in accounting and data processing, 7 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.
Devon expects to add between 100 and 125 full-time employees
during 1997 as a result of the Kerr-McGee Transaction. (See
"Management's Discussion and Analysis of Financial Condition and
Results of Operations - 1997 Estimates - General and
Administrative Expenses".)
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, 1996. Approximately 94%
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 their
estimates, LaRoche, AMH and 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). 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.
<TABLE>
<CAPTION>
Total Proved Proved
Proved Developed Undeveloped
Reserves Reserves (1) Reserves (2)
<S> <C> <C> <C>
Oil (MBBls) 67,481 60,202 7,279
Gas (MMcf) 595,519 570,265 25,254
NGLs (MBoe) 12,579 11,212 1,367
MBoe (3) 179,313 166,457 12,856
Pre-tax Future Net Revenue
($ thousands)(4) 2,863,536 2,677,459 186,077
Pre-tax 10% Present Value
($ thousands)(4) 1,621,992 1,532,021 89,971
(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
recompletion, deepening or 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 future 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, 1996. 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 $24.52 per Bbl of oil,
$3.35 per Mcf of natural gas ($3.43 per Mcf including the
effect of the San Juan Basin Transaction), and $23.34 per Boe
of NGLs. These prices compare to benchmark prices of $24.25
for West Texas Intermediate crude oil and $3.67 for Texas Gulf
Coast spot gas.
</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 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, 1996. 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 88%, 95%, 91%, 92% and 94% of Devon's
domestic reserves as of the years ended December 31, 1992, 1993,
1994, 1995 and 1996, respectively, were estimated by LaRoche.
The balance of the domestic reserves were estimated by Devon's
internal staff of engineers. All of the 1996 Canadian reserves
were calculated by AMH.
<TABLE>
<CAPTION>
Total Proved Reserves Proved Developed Reserves
------------------------------- -------------------------------
As of Oil(MBbls) Gas(MMcf) NGLs(MBoe) Oil(MBbls) Gas(MMcf) NGLs(MBoe)
December 31, ---------- -------- ---------- ---------- --------- ----------
<S> <C> <C> <C> <C> <C> <C>
1992 16,349 263,598 1,011 13,823 249,154 797
1993 14,897 369,254 1,854 11,548 355,536 1,751
1994 42,165 347,560 5,442 18,718 324,302 3,123
1995 44,466 363,846 9,469 28,703 311,664 6,149
1996 67,481 595,519 12,579 60,202 570,265 11,212
</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 five years ended December 31, 1996, is set forth in "Item
6. Selected Financial Data."
Well Statistics
As of December 31, 1996, Devon had interests in 13,992
producing wells, of which 10,839 gross (1,311 net) were oil wells
and 3,153 gross (760 net) were natural gas wells. 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, 1996.
<TABLE>
<CAPTION>
Developed Undeveloped
------------------- ------------------
Gross(1) Net(2) Gross(1) Net(2)
-------- ------ -------- ------
<S> <C> <C> <C> <C>
Alabama 6,166 2,608 400 78
Arkansas 9,091 1,830 12,184 2,517
Colorado 6,588 3,065 22,368 9,568
Kansas 20,676 8,912 6,160 581
Louisiana 14,981 5,373 14,663 6,990
Mississippi 9,224 575 825 222
Montana 16,486 445 11,891 1,779
Nebraska 160 80 6,517 1,377
New Mexico 157,075 68,882 218,135 69,554
North Dakota 17,157 6,030 6,982 755
Oklahoma 294,069 88,904 190,461 38,356
South Dakota 5,771 152 322 238
Texas 839,851 227,654 600,725 176,096
Utah 5,305 864 600 600
Wyoming 253,146 103,967 160,001 106,432
---------- --------- ------- -------
Total U. S. 1,655,746 519,341 1,252,234 415,143
Canada 187,277 75,637 118,808 75,262
---------- ------- --------- -------
Grand Total 1,843,023 594,978 1,371,042 490,405
========= ======= ========= =======
(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 2,006 of its 13,992 wells. As
operator, Devon receives reimbursement for direct expenses
incurred in the performance of its duties as well as monthly per-
well producing and drilling overhead reimbursement at rates
customarily charged in the area to or by unaffiliated third
parties. In presenting its financial data, Devon records the
monthly overhead reimbursements as a reduction of general and
administrative expense, which is a common industry practice.
Significant Properties
The following table sets forth information on the most
significant geographic areas in which Devon's properties are
located as of December 31, 1996.
<TABLE>
<CAPTION>
10% Present
Value(3)
Oil(MBbls) Gas(MMcf) NGLs(MBoe) 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 22,007 7,983 1,955 25,293 14.1% $193,637 12.0%
Ozona Field 254 64,774 1,725 12,775 7.1% 102,385 6.3%
Other 24,296 80,302 3,128 40,808 22.8% 366,870 22.6%
------ ------ ----- ------ ----- -------- -----
Total 46,557 153,059 6,808 78,876 44.0% $662,892 40.9%
Rocky Mountains:
Colorado and Wyoming
Worland Unit 1,966 56,138 3,797 15,119 8.4% $133,571 8.2%
Other 8,516 49,333 460 17,198 9.6% 169,133 10.5%
------ ------ ----- ------ ----- -------- -----
Total 10,482 105,471 4,257 32,317 18.0% $302,704 18.7%
San Juan Basin:
Northwest New Mexico
Northeast Blanco
Unit 4 108,789 47 18,183 10.1% $180,724(5) 11.1%
32-9 Unit 0 53,727 0 8,955 5.0% 94,384(6) 5.8%
Other 3 511 16 104 0.1% 1,235 0.1%
-- ------- --- ------ ----- -------- -----
Total 7 163,027 63 27,242 15.2% $276,343 17.0%
Mid-Continent:
Oklahoma and
Texas Panhandle 1,982 127,752 538 23,812 13.3% $224,326 13.8%
Canada 7,530 40,858 884 15,223 8.5% $135,389(7) 8.3%
All Other
Properties 923 5,352 29 1,843 1.0% 20,338 1.3%
----- ------ ---- ------ ----- -------- ----
Grand Total 67,481 595,519 12,579 179,313 100.0% $1,621,992 100.0%
====== ======= ====== ======= ====== ========== ======
(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 $24.4 million of additional value attributable to
the San Juan Basin Transaction through the year 2002.
(6) Includes $14.3 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 : $0.7297 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 dedicated
federal exploration 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 well-situated 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 one-
third 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-
acre per well spacing and subsequent waterflooding. Based upon
analogy to these properties, Devon initiated a $65 million
capital development project in 1994. The project includes
drilling approximately 150 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 July, 1996. The majority of the
field should be in the initial phases of full water injection by
mid-1997. Completion of the waterflood facilities over the
remainder of the field will require the additional conversion of
more than 90 producing wells to injection wells, construction of
a second water injection plant and installation of an additional
40 miles of injection pipeline.
At year-end 1996, 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 from the Canyon Formation
at depths of 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. Through year-end 1996, Devon drilled 34 Canyon
wells. Additional significant producing wells and acreage were
obtained in the Kerr-McGee Transaction.
Devon has no Canyon locations currently identified for 1997
drilling. However, it is anticipated that undrilled Canyon
locations will be found on the acreage acquired by Devon in 1996.
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.
Worland Property. The property lies on a 25,000-acre federal
unit in Big Horn and Washakie Counties, Wyoming. In December,
1995, Devon purchased a significant interest in producing and
undeveloped acreage and a natural gas processing plant on this
property. In early 1996, Devon increased its working interest to
98% in the developed leases through several small acquisitions.
These acquisitions also increased Devon's interest in the gas
processing plant to 100% and in the undeveloped oil and gas lease
acreage to approximately 99%. These acquired assets, combined
with the small interest Devon previously owned, had total
estimated proved reserves of 15.1 MMBoe as of year-end 1996.
The Worland property is located in the Big Horn Basin, and
contains three separate fields situated along a major geologic
feature referred to as a draped anticline. Seven separate
horizons have proven productive on the property. The Muddy
Formation and the First, Second, Third and Fourth Members of the
Frontier Formation produce sweet gas from sandstone reservoirs at
depths ranging from 7,100 to 9,000 feet. The underlying
Phosphoria Formation produces oil and sour gas from dolomite
reservoirs encountered at a depth of approximately 10,000 feet.
The Tensleep Formation, the deepest proven reservoir, produces
oil from sandstone at a depth of approximately 10,500 feet.
Initial oil and sour gas production was established at
Worland in the 1940's from the Phosphoria Formation. Sweet gas
production from the overlying Frontier and Muddy reservoirs was
established in the 1960's. Tensleep oil production was
established in the 1970's.
Devon believes that the property contains additional
exploitation opportunities for all the proven reservoirs.
Consequently, a drilling program and a 3-D seismic program have
been initiated to further develop the established reservoirs and
to extend and define their productive limits. Devon also has
begun a program to apply modern completion and stimulation
techniques to selected existing wells. Additionally, Devon plans
to upgrade the existing gas processing plant from 15 MMcf of gas
per day to 20 MMcf per day during the first quarter of 1997.
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 historically been 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 can now arguably 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 96%, or 104.1 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.
The current reserve estimates at NEBU assume that 55% to 65%
of the coal seam gas in place can be economically recovered
through existing wells. In the near term, Devon is implementing a
project which may increase production and recoverable reserves.
This "line looping" project involves laying additional gathering
lines and installing compressors to decrease operating pressure.
It was begun in mid-1996 and should be substantially completed by
late 1997. Initial results from the work completed in 1996 were
favorable, and year-end 1996 reserve estimates were increased
slightly (approximately 2.6 Bcf) to reflect this outcome.
Approximately $2.3 million is expected to be spent in 1997 to
continue this development project. As part of the San Juan Basin
Transaction (discussed in more detail below), a third party will
pay 100% 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.
Over the longer term, drilling infill wells on denser
spacing or utilizing enhanced recovery techniques such as
injecting carbon dioxide or nitrogen into the coal formation to
force additional gas to the producing well bores, may result in
further NEBU reserve and production increases. Devon and other
owners in the San Juan Basin have studied and experimented with
these various options to determine if additional recoveries are
economically feasible. Such development projects, if undertaken,
would likely result in significant additional capital
expenditures; however, the timing of any such projects is
presently unknown. The third party in the San Juan Basin
Transaction is not obligated to pay any capital or entitled to
receive any reserves associated with any new or infill wells
drilled at NEBU.
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. The current reserve estimates
assume that 20% to 30% of the coal seam gas in place can be
economically recovered through the existing wells. 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. There is the
possibility that some infill wells may be drilled to accelerate
production and possibly increase reserves; however, the timing of
such drilling, if it occurs, is unknown. 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 be approximately
$0.55 to $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.
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 production 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, there are no material
pending legal proceedings to which Devon is a party or of which
any of its property is subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
A special meeting of Devon shareholders was held on December
6, 1996. The purpose of the meeting was to consider and vote upon
two issues: (a) the issuance of 9,954,000 shares of Devon common
stock to Kerr-McGee in connection with the Kerr-McGee
Transaction; and (b) an amendment to Devon's certificate of
incorporation to increase the number of authorized shares of
Devon common stock from 120 million shares to 400 million shares.
Out of a total of 22,130,896 shares of common stock
outstanding and entitled to vote, 18,773,628 shares, or 85%, were
represented at the meeting in person or by proxy.
Each of the proposals being voted upon was approved. The
voting results were as follows:
<TABLE>
<CAPTION>
Proposal (a) Proposal (b)
---------------------- -----------------
Shares % (1) Shares % (1)
------ ----- ------ -----
<S> <C> <C> <C> <C>
For 18,508,262 83.6% 17,451,728 78.9%
Against 15,538 0.1% 1,287,950 5.8%
Abstain 32,254 0.2% 33,950 0.2%
Broker Non-Vote 217,574 1.0% -- --
(1) Percent of total shares outstanding and entitled to vote.
</TABLE>
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>
Average
Daily
High Low Volume
------ ------ --------
<S> <C> <C> <C>
1995:
Quarter Ended March 31, 1995 21-3/8 16-3/4 41,268
Quarter Ended June 30, 1995 23-1/4 20 41,437
Quarter Ended September 30, 1995 23-7/8 18 39,462
Quarter Ended December 31, 1995 26 21-1/2 22,333
1996:
Quarter Ended March 31, 1996 25-3/4 19-7/8 44,846
Quarter Ended June 30, 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 31 74,876
(through February 24, 1997)
</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 equal to $0.14 per
share. Devon anticipates continuing to pay regular quarterly
dividends in the foreseeable future.
On February 24, 1997, there were approximately 900 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,
1996 1995 1994 1993 1992
(Thousands, Except Per Share Data)
OPERATING RESULTS
<S> <C> <C> <C> <C> <C> <C>
Oil sales $ 80,142 55,290 38,086 38,395 27,329
Gas sales 68,049 50,732 56,372 54,876 39,973
NGL sales 14,367 6,404 4,908 4,544 1,370
Other revenue 1,459 877 1,407 942 2,892
Total revenues $ 164,017 113,303 100,773 98,757 71,564
Lease operating expenses $ 31,568 27,289 24,521 26,401 18,430
Production taxes $ 10,658 6,832 6,899 6,924 4,600
Depreciation, depletion
and amortization $ 43,361 38,090 34,132 28,409 19,894
General and administra-
tive expenses $ 9,101 8,419 8,425 7,640 6,510
Interest expense $ 5,277 7,051 5,439 3,422 2,644
Distributions on preferred
securities of subsidiary
trust $ 4,753 -- -- -- --
<F1>
Net earnings $ 34,801 14,502 13,745 20,486 1 14,615
Net earnings per share:
<F1>
Assuming no dilution $ 1.57 0.66 0.64 0.98 1 0.94
<F1>
Assuming full dilution $ 1.52 0.66 0.64 0.98 1 0.90
Cash dividends:
Per preferred share $ -- -- -- -- 1.46
Per common share $ 0.14 0.12 0.12 0.09 --
Weighted average common
shares outstanding 22,160 22,074 21,552 20,822 13,802
<F2>
Ratio of earnings to fixed
charges 2 $ 6.76 4.54 4.80 8.24 7.97
BALANCE SHEET DATA
Total assets $ 746,251 421,564 351,448 285,553 225,972
Long-term debt $ 8,000 143,000 98,000 80,000 54,450
Convertible preferred
securities of
subsidiary trust $ 149,500 -- -- -- --
Stockholders' equity $ 472,404 219,041 206,406 172,900 153,267
<PAGE>
<CAPTION>
Year Ended December 31,
1996 1995 1994 1993 1992
CASH FLOW DATA
Net cash provided by
operating activities $ 86,802 61,276 46,384 63,957 30,499
<F4>
<F3>
EBITDA 3,4 112,689 70,763 60,928 57,792 42,024
<F5>
<F4>
Cash margin 4,5 95,951 59,217 55,074 52,893 38,140
PRODUCTION, PRICE AND OTHER DATA
Production:
Oil (MBbls) 3,816 3,300 2,467 2,337 1,446
Gas (MMcf) 35,714 36,886 39,335 35,598 28,374
NGLs (MBbl) 952 600 501 411 112
<F6>
MBoe 6 10,720 10,047 9,524 8,681 6,287
Average prices:
Oil (Per Bbl) $ 21.00 16.75 15.44 16.43 18.89
Gas (Per Mcf) $ 1.91 1.38 1.43 1.54 1.41
NGLs (Per Bbl) $ 15.09 10.68 9.79 11.06 12.28
<F6>
Per Boe 6 $ 15.16 11.19 10.43 11.27 10.92
Costs per Boe:
Operating costs $ 3.94 3.40 3.30 3.84 3.66
DD&A of oil and gas
properties $ 3.88 3.65 3.45 3.16 3.08
General and
administrative
expenses $ 0.85 0.84 0.89 0.88 1.04
<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 Earnings before interest (including distributions on
preferred securities of subsidiary trust), taxes,
depreciation, depletion and amortization. <PAGE>
<F4>
4 EBITDA and cash margin 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, 1996, 1995, 1994, 1993 and
1992, net cash used in investing activities were $94.8
million, $110.6 million, $73.4 million, $74.2 million and
$140.6 million, respectively. For these same periods, net
cash provided by financing activities were $8.5 million,
$49.8 million, $15.8 million, $24.2 million and $107.9
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 1994 through 1996. Reference
is made to "Item 6. Selected Financial Data" and "Item 8.
Financial Statements and Supplementary Data."
Overview
Devon concluded 1996 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 129% to
179 million barrels of oil equivalent ("MMBoe"). The company s
long-term credit lines have increased 63% over the same
period, to $260 million. Total assets have increased 161% to
$746 million. During the same three years Devon reduced its
long-term debt from $80 million to $8 million and
significantly increased stockholders equity.
Devon's operating performance has also improved by most
measures over the last three years. In 1996 oil and gas
production was 23% over that of 1993, to 10.7 MMBoe. The 1996
production increase coupled with a 35% increase in oil, gas
and NGL prices over 1993 levels, led to revenues and earnings gains.
Net earnings for 1996 climbed 70% over those of 1993, to $34.8
million. Net cash provided by operating activities rose from
$46.4 million in 1994 to $61.3 million in 1995 and $86.8
<F1>
million in 1996. The cash margin1 (total revenues less cash
expenses) during these same three years has increased from
$55.1 million in 1994 to $59.2 million in 1995 and $96.0
million in 1996.
This growth in operations was driven primarily by the
following events:
Devon acquired $54 million of coal seam gas
properties in the San Juan Basin in June, 1993.
These properties added to Devon's already
significant coal seam gas properties, production and
revenues in the San Juan Basin.
Devon acquired the properties of Alta Energy
Corporation through a $72 million cash and common
stock merger in May 1994. The oil and gas properties
<F1>
1 "Cash margin" equals Devon's 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 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.
acquired through the merger (the "Alta Merger
Properties") added substantial oil and gas reserves,
production and revenues to Devon's Permian Basin
position.
Devon acquired additional interests in certain of
its Wyoming oil and natural gas properties and a gas
processing plant (the "Worland Properties") for
approximately $57 million from December, 1995
through April, 1996.
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 $10 million to
Devon's annual revenues.
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. Devon has spent
approximately $171 million to drill 476 wells, of
which 462 were completed as producers.
The following actions during the last three years
improved Devon s liquidity and financial resources while
reducing its bank debt:
The issuance of $22 million of additional common
equity capital in 1994 for the 1994 Alta Merger.
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 126.5 MMBoe of proved
reserves to its asset base. Combined with 8.6 MMBoe
of upward revisions to its reserve estimates,
Devon's total reserve additions of 135.1 MMBoe
during the past three years were 446% of its
production of 30.3 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").
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 lines of credit. Since the end of 1993, Devon's
long-term credit lines have increased by $100
million to a total of $260 million at year-end 1996.
The growth exhibited by Devon over the last three years
extends an eight-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 period of time, volatility in oil and gas prices has
resulted in considerable variability in earnings and cash
flows. Prices for oil, natural gas and NGL s are determined
primarily by prevailing 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 be dependent
on market conditions for the company s production.
Like all oil and gas production companies, Devon faces
the challenge of natural decline. As virgin pressures are
depleted, oil and gas production from a given well naturally
decreases. Thus, an oil and gas production company consumes
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.
Because Devon can only marginally influence oil and gas
prices, the company's management has focused its efforts on
increasing oil and gas reserves and production and on
controlling expenses. Over its eight 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 two years Devon's per-unit operating
costs have increased somewhat. 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. (Producing oil is generally more
expensive than producing gas. Also, secondary recovery
projects are generally more expensive than primary
production.) Higher oil and gas prices in 1996 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.
Results of Operations
Devon's total revenues have risen from $100.8 million in
1994 to $113.3 million in 1995 and $164.0 million in 1996. In
each of these years, oil, gas and NGL sales accounted for 99%
of total revenues.
Changes in oil, gas and NGL production, prices and
revenues from 1994 to 1996 are shown in the table below.
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995
1996 vs 1995 1995 vs 1994 1994
Production
<S> <C> <C> <C> <C> <C>
Oil (MBbls) 3,816 +16% 3,300 +34% 2,467
Gas (MMcf) 35,714 -3% 36,886 -6% 39,335
NGLs (MBbls) 952 +59% 600 +20% 501
Oil, Gas and NGLs (MBoe) 10,720 +7% 10,047 +5% 9,524
Revenues
Per Unit of Production:
Oil (per Bbl) $ 21.00 +25% 16.75 +8% 15.44
Gas (per Mcf) $1.91 +38% 1.38 -3% 1.43
NGLs (per Bbl) $ 15.09 +41% 10.68 +9% 9.79
Oil, Gas and NGLs (per Boe) $ 15.16 +35% 11.19 +7% 10.43
Absolute: (Thousands)
Oil $80,142 +45% 55,290 +45% 38,086
Gas $68,049 +34% 50,732 -10% 56,372
NGLs $14,367 +124% 6,404 +30% 4,908
Oil, Gas and NGLs $162,558 +45% 112,426 +13% 99,366
</TABLE>
Oil Revenues 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 the 1994 Alta
Merger accounted for the majority of 1996's increased
production. This field produced 1,108,000 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 2,493,000 barrels in 1995 to 2,708,000
barrels in 1996.
1995 vs. 1994 Oil revenues rose $17.2 million in 1995.
Substantial gains in production added $12.9 million to
revenues in 1995, while higher average prices added the
remaining $4.3 million.
The Grayburg-Jackson Field produced 807,000 barrels in
1995, a 296% increase from the 204,000 barrels which were
produced during Devon's ownership for the last seven months of
1994. Production from Devon's other oil properties increased
10% in 1995, from 2,263,000 barrels in 1994 to 2,493,000
barrels in 1995.
Gas Revenues 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. Total coal seam gas revenues were
$30.1 million in 1996 compared to $27.5 million in 1995. Coal
seam gas revenues include $10.3 million in 1996 and $12.8
million in 1995 attributable to the San Juan Basin
Transaction.
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. The additional interests in the Worland Properties
which were acquired in December 1995 and the first half of
1996 added 2.2 Bcf to 1996's conventional production.
1995 vs. 1994 Gas revenues decreased $5.6 million, or
10%, in 1995, due to a combination of lower production and
prices. Lower production accounted for $3.5 million of the
revenue decrease, while lower gas prices accounted for the
remaining $2.1 million.
Gas revenues in 1995 were down despite the positive
effect of the 1995 San Juan Basin Transaction. Such
transaction boosted 1995's gas revenues by $11.4 million, and
raised the average prices for 1995 coal seam gas and total gas
production by $0.61 and $0.35 per Mcf, respectively. See Note
3 to the consolidated financial statements included elsewhere
in this Form 10-K for a detailed discussion of the San Juan
Basin Transaction.
Coal seam gas production declined by 5%, from 22.0 Bcf in
1994 to 20.8 Bcf in 1995. This decline of 1.2 Bcf was due to
the San Juan Basin Transaction which, among other things,
included the sale of a small portion of Devon's coal seam gas
properties.
The average realized coal seam gas price rose by 13%,
from $1.17 per Mcf in 1994 to $1.32 per Mcf in 1995. The
$0.61 per Mcf increase from the San Juan Basin Transaction
more than offset a $0.46 per Mcf price drop at the wellhead.
Total coal seam gas revenues were $27.5 million in 1995 versus
$25.7 million in 1994. Coal seam gas revenues in 1995
included $14.7 million of wellhead sales and $12.8 million of
revenues attributable to the San Juan Basin Transaction. The
sale of the small portion of Devon's coal seam gas properties
which was part of the San Juan Basin Transaction had the
effect of reducing 1995's coal seam gas revenues by $1.4
million as compared to 1994's revenues. The $12.8 million of
additional gas sales received pursuant to the terms of the San
Juan Basin Transaction, less the $1.4 million of wellhead
sales reduction as a result of the small sale, nets to the
$11.4 million increase in coal seam gas sales from the San
Juan Basin Transaction referred to in the second paragraph
above.
Total conventional gas production and revenues for 1995
were 16.1 Bcf and $23.2 million, respectively, versus 17.4 Bcf
and $30.7 million in 1994. Prices for conventional gas
averaged $1.44 per Mcf in 1995 compared to 1994's average of
$1.76 per Mcf.
Production for a full year from the Alta Merger
Properties, as opposed to only seven months in 1994,
contributed a 0.6 Bcf increase in gas production in 1995.
However, this increase and others from wells drilled in 1994
and 1995 were more than offset by reduced production from
other conventional gas wells. The primary contributors to the
conventional production decline in 1995 were the Ozona field,
miscellaneous property sales and NEBU. High pipeline pressure
and down time for repairs contributed to a 0.6 Bcf reduction
in Ozona production in 1995. Various marginal wells sold in
1994 and 1995 accounted for a 0.6 Bcf reduction in 1995's
conventional production. Out-of-period marketing adjustments
caused the reduction in 1995 conventional gas production at
NEBU.
Although Devon does not have a significant interest in
conventional gas production in NEBU, it had been selling more
than its normal share of production. This created an
"imbalance" between Devon and the wells' other owners. This
imbalance was reversed in 1995 as the other owners sold more
than their normal share of production. Also in 1994, Devon
received nonrecurring payments for inventory gas from NEBU.
In 1995, the amounts of imbalance makeup and lack of inventory
sales led to a 0.5 Bcf reduction in conventional NEBU
production compared to 1994.
NGL Revenues 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 revenues. The
remaining $3.8 million of increased revenues was attributable
to increased production of 352,000 barrels in 1996.
The additional interests acquired in the Worland
Properties in December 1995 and the first half of 1996
accounted for 214,000 barrels of the increased production in
1996. The Worland 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 69,000 barrels in 1995 to 95,000 barrels in 1996.
1995 vs. 1994 NGL revenues increased by $1.5 million in
1995. Higher production contributed $1.0 million of the
increase, while the remaining $0.5 of increased revenues was
attributable to higher average prices in 1995.
The Alta Merger Properties accounted for 52,000 barrels
of the increased production. Such properties produced 84,000
barrels in 1995, compared to 32,000 barrels during the seven
months Devon owned the properties in 1994. Additional
drilling in the Sand Dunes area increased production from
39,000 barrels in 1994 to 69,000 barrels in 1995.
Expenses The details of the changes in pre-tax expenses
between 1994 and 1996 are shown in the table below.
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995
1996 vs 1995 1995 vs 1994 1994
(Absolute Amounts in Thousands)
Absolute:
Production and operating expenses:
<S> <C> <C> <C> <C> <C>
Lease operating expenses $ 31,568 +16% 27,289 +11% 24,521
Production taxes 10,658 +56% 6,832 -1% 6,899
Depreciation, depletion and amortization
attributable to:
Oil and gas production 41,538 +13% 36,640 +11% 32,861
Non-oil and gas properties 1,823 +26% 1,450 +14% 1,271
General and administrative expenses 9,101 +8% 8,419 - 8,425
Interest expense 5,277 -25% 7,051 +30% 5,439
Distributions on preferred securities of
subsidiary trust 4,753 N/A - - -
Total $ 104,718 +19% 87,681 +10% 79,416
<F1>
Per Boe Produced(1):
Production and operating expenses:
Lease operating expenses $2.95 +8% 2.72 +6% 2.57
Production taxes 0.99 +46% 0.68 -7% 0.73
Depreciation, depletion and amortization
attributable to:
Oil and gas production 3.88 +6% 3.65 +6% 3.45
Non-oil and gas properties 0.17 +21% 0.14 +8% 0.13
General and administrative expenses 0.85 +1% 0.84 -6% 0.89
Interest expense 0.49 -30% 0.70 +23% 0.57
Distributions on preferred securities of
subsidiary trust 0.44 N/A - - -
Total $9.77 +12% 8.73 +5% 8.34
<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 1994 and
1996 are shown in the table below.
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995
1996 vs 1995 1995 vs 1994 1994
(Absolute Amounts in Thousands)
Absolute:
<S> <C> <C> <C> <C> <C>
Recurring lease operating expenses $ 28,270 +19% 23,842 +10% 21,583
Well workover expenses 3,298 -4% 3,447 +17% 2,938
Production taxes 10,658 +56% 6,832 -1% 6,899
Total production and operating
expenses $ 42,226 +24% 34,121 +9% 31,420
Per Boe:
Recurring lease operating expenses $ 2.64 +11% 2.37 +4% 2.27
Well workover expenses 0.31 -11% 0.35 +17% 0.30
Production taxes 0.99 +46% 0.68 -7% 0.73
Total production and operating
expenses $ 3.94 +16% 3.40 +3% 3.30
</TABLE>
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. The Alta Merger Properties' recurring lease
operating expenses increased from $3.5 million in 1995 to $4.6
million in 1996. This increase was predominantly 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. This increase was primarily caused by the
reduction in the coal seam gas properties' share of total
production. The recurring operating costs per Boe for these
coal seam gas properties are extremely low ($0.32 per Boe in
1996 and $0.24 per Boe in 1995). However, as production from
these properties declined and production from Devon's other
properties increased in 1996, the coal seam gas properties'
percentage of overall production dropped from 35% in 1995 to
27% in 1996. The result is that more of Devon's production in
1996 was attributable to its conventional oil and gas
properties, which have a higher recurring operating cost per
Boe than the low-cost coal seam gas properties. The recurring
costs per Boe on Devon's conventional properties were $3.50
per Boe in 1996 and 1995. However, since these properties
represented a larger percentage of Devon's total production in
1996 compared to 1995, the result was a $0.27 per Boe increase
in the overall rate.
Production taxes are collected by most taxing authorities on
a fixed percentage of revenue basis. Therefore, as Devon's
revenues have increased, so have production taxes. Production
taxes increased 56% from $6.8 million in 1995 to $10.7 million
in 1996. This increase was due almost exclusively to higher
oil, gas and NGL revenues. Excluding revenues generated from
the San Juan Basin Transaction which are not subject to
production taxes, 1996 oil, gas and NGL revenues increased 53%
compared to 1995.
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. Excluding the effect
on average prices from the San Juan Basin Transaction, Devon's
total revenues per Boe increased by 43% from $9.92 per Boe in
1995 to $14.21 per Boe in 1996.
1995 vs. 1994 Recurring lease operating expenses increased
by $2.2 million, or 10%, in 1995. Approximately $1.6 million
of the increase was related to the Alta Merger Properties.
Costs for these properties increased from $1.9 million in 1994
(for the last seven months of the year during which they were
owned by Devon) to $3.5 million in 1995. However, on a cost
per unit of production basis, the Alta Merger Properties'
recurring lease operating expenses dropped from $4.96 per Boe
in 1994 to $3.16 per Boe in 1995. These per unit costs
compare to the averages for Devon's other properties of $2.15
per Boe in 1994 and $2.28 per Boe in 1995.
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.
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.
1995 vs. 1994 Oil and gas property related DD&A increased
by $3.8 million, or 11%, in 1995. Approximately $2.0 million
of this increase was caused by an increase in the DD&A rate
from $3.45 per Boe in 1994 to $3.65 per Boe in 1995. The
increased DD&A rate was primarily caused by the inclusion of
the Alta Merger Properties for a full year in 1995, compared
to only seven months in 1994. The remaining $1.8 million of
the increase in oil and gas property related DD&A was caused
by the increase in total production in 1995.
General and Administrative Expenses ("G&A") 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 other joint interest owners in Devon-operated
properties.
1995 vs. 1994 G&A was constant between 1995 and 1994.
Employee salaries and related overhead burdens increased by
$0.3 million, legal fees increased by $0.3 million and
abandoned acquisition costs rose by $0.1 million. These
increases were offset by a $0.6 million increase in G&A
reimbursements received from joint interest owners in Devon-
operated properties and a $0.1 million reduction in franchise
taxes. Approximately $0.2 million of the increase in G&A
reimbursements related to a change in the method used to
calculate the reimbursements on certain properties, and such
change was retroactive to the prior two years. The reduction
in franchise taxes resulted from Devon's reincorporation from
Delaware to Oklahoma in June 1995.
Interest Expense 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 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 will be
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.
1995 vs. 1994 Interest expense increased by $1.6 million,
or 30%, in 1995. This increase was due almost exclusively to
higher rates in 1995, which accounted for $1.3 million of the
increased interest expense. The interest rate on the debt
outstanding during 1995 was 6.5%, compared to 1994's rate of
5.2%. The overall interest rate averaged 7.3% in 1995,
compared to the 1994 overall rate of 5.9%.
The remaining $0.3 million of interest expense increase in
1995 was caused by a higher average balance outstanding. The
average debt balance during 1995 was $97.1 million, compared
to 1994's average balance of $92.5 million.
Distributions on Preferred Securities of Subsidiary Trust
1996 vs. 1995 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 newly-formed 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 accrue at the rate of 1.625% per quarter. The
1996 distributions of $4.8 million represented slightly less
than two quarters' distributions due to the issuance date
occurring in July.
Income Taxes 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 statutory federal tax rate of 35%
due to state income taxes, and certain tax aspects of the San
Juan Basin Transaction and the 1994 Alta Merger.
1995 vs 1994 Devon's effective financial tax rate in 1995
was 43%, compared to 1994's rate of 36%. State income taxes
and certain tax aspects of the San Juan Basin Transaction were
the primary factors which increased Devon's financial tax rate
in 1995. The San Juan Basin Transaction also had a
significant effect on the portion of income taxes which are
current versus deferred.
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 $98.9 million of cash
was spent in 1996 for capital expenditures, of which $85.0
million was related to the acquisition, drilling or
development of oil and gas properties. Most of the drilling
and development efforts in 1996 centered in the Permian Basin,
which included 176 of the 194 oil and gas wells which Devon
drilled during 1996. Most of Devon's 1996 non-oil and gas
property related capital expenditures involved the $12.5
million purchase of the office building in which its Oklahoma
City offices are located. This purchase was closed on
December 31, 1996.
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.
Capital Resources and Liquidity Net cash provided by
operating activities ("operating cash flow") was the primary
source of capital and short-term liquidity in 1996. Operating
cash flow in 1996 totaled $86.2 million, a 41% increase
compared to the $61.3 million of operating cash flow generated
in 1995.
In addition to operating cash flow, Devon's credit lines
have been an important source of capital and liquidity. At
year-end 1996, long-term credit lines totaled $260 million, of
which $252 million was available for future use. At the end
of 1996, in connection with the KMG-NAOS acquisition, Devon
also established a demand revolving credit line for its new
Canadian operations. This credit line totals $12.5 million
Canadian dollars, all of which was available at year-end.
(See Note 7 to the consolidated financial statements included
elsewhere in this report for a detailed discussion of the
credit lines.) The use of the proceeds from the TCP
Securities offering in July 1996 to retire long-term debt
increased the amount of Devon's credit lines available for
future borrowings.
Devon's San Juan Basin coal seam gas production is subject
to uncertainties regarding additional royalties and taxes. If
such uncertainties are resolved in 1997, the resolutions are
likely to require the use of operating cash flow, but Devon
does not expect such amount to be material to its overall
liquidity, capital resources or net earnings. For a complete
discussion of these matters, see Note 12 to the consolidated
financial statements contained elsewhere in this report.
1997 Estimates
The forward-looking statements provided in this
discussion are based on management's examination of historical
operating trends, the December 31, 1996 reserve reports of
LaRoche and AMH, data in Devon's files and other data
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 of oil and gas.
These risks include, but are not limited to, environmental
risks, drilling risks, regulatory changes, the uncertainty
inherent in estimating future oil and gas production or
reserves, and other risks as outlined below. The scope of
Devon s operations increased significantly with the KMG-NAOS
transaction. This increases the margin of error inherent in
estimating Devon s 1997 production volumes, prices and
expenses. Also, the financial results for Devon's new
Canadian operations, obtained in the KMG-NAOS transaction, are
subject to currency exchange rate risks.
Assumptions and Risks for 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. 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. Although Devon's
management believes these assumptions to be reasonable, 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
substantive 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 1997 will be substantially similar to
those of 1996, unless otherwise noted. Given the general
limitations expressed herein, Devon's forward-looking
statements for 1997 are set forth below.
Oil Production and Relative Prices Devon expects its oil
production in 1997 to total between 5.9 million barrels and
6.9 million barrels. Devon expects its net oil prices will
average from between $0.05 below to $0.20 above West Texas
Intermediate posted prices in 1997.
Gas Production and Relative Prices Devon expects its
total gas production in 1997 will be between 64.0 Bcf and 75.0
Bcf. It is expected that coal seam gas production will be
16.5 Bcf to 19.5 Bcf. Canadian production in 1997 is
estimated to be between 7.0 Bcf and 8.0 Bcf. Devon expects
production from the remainder of its gas properties to total
between 40.5 Bcf and 47.5 Bcf.
Devon expects its 1997 coal seam average price will be
between $0.25 and $0.55 less than Texas Gulf Coast spot
averages. This includes an expected $0.55 per Mcf from the
San Juan Basin Transaction. Devon's Canadian gas production
is expected to average from between $0.85 to $1.20 less than
Texas Gulf Coast spot prices. (These Canadian differentials
are expressed in U.S. dollars, using the year-end 1996
exchange rate of $0.73 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 prices during 1997.
NGL Production Devon expects its production of NGLs in
1997 to total between 1.1 million barrels and 1.3 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.
The addition of the KMG-NAOS Properties is expected to be
the largest contributor to an increase in recurring lease
operating expenses in 1997. The additional revenues
contributed by these properties should also cause production
taxes to rise. In addition, well workover expenses are
anticipated to increase in 1997.
Oil, gas and NGL prices will have a direct effect on
production taxes to be incurred in 1997. 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
margin of error inherent in estimating future production and
operating costs. Given these uncertainties, Devon estimates
that 1997's total production and operating costs will be
between $75 million and $87 million.
Depreciation, Depletion and Amortization The 1997 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 1997 compared to the
costs incurred for such efforts, and the revisions to Devon's
year-end 1996 reserve estimates which will be made during
1997.
The DD&A rate as of the beginning of 1997 was $3.76 per
Boe. This rate includes the effect of the December 31, 1996,
acquisition of the KMG-NAOS Properties. Conversely, the 1996
yearly rate of $3.88 per Boe did not reflect the effect of
these properties. Assuming a 1997 rate of between $3.80 per
Boe and $4.20 per Boe, 1997 DD&A expense (including
approximately $2.5 million of non-oil and gas property related
DD&A) is expected to be $76 million to $84 million.
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. The addition of the KMG-NAOS
Properties will increase Devon's general level of activity as
well as its staffing requirements during 1997. 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 $12 million and $14 million in 1997.
Interest Expense Devon's management expects to fund
substantially all of its anticipated expenditures during 1997
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 1997.
Distributions on TCP Securities TCP Securities are
convertible into common shares of Devon at the option of the
holder. Should any of the holders of the TCP Securities elect
to convert during 1997, it 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 1997.
Income Taxes Devon expects its financial income tax rate
in 1997 to be between 38% and 42%. Regardless of the level of
pre-tax earnings reported for financial purposes, Devon will
have a minimum of approximately $2.5 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 1997 pre-tax
earnings differs materially from what Devon currently expects,
the actual financial income tax rate for 1997 could fall
outside of the expected rate of 38% to 42%. Also, based on
its current expectations of 1997 taxable income, Devon
anticipates its current portion of 1997 income taxes will be
between $9 million and $13 million. However, revenue and
earnings fluctuations could easily make these tax estimates
obsolete.
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. Thus, Devon would increase
or decrease total 1997 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 at least one major acquisition
in each of the last several 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 1997 capital
expenditures for drilling and development efforts to total
between $120 million and $135 million, including $8 million to
$11 million in Canada. (Canadian amounts are expressed in
U.S. dollars, using the year-end 1996 exchange rate of $0.73
U.S. dollar to $1.00 Canadian dollar.) Devon expects to spend
$50 million to $65 million in 1997 for drilling, facilities
and waterflood costs related to reserves classified as proved
as of year-end 1996. Devon also plans to spend another $15
million to $20 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 32.1 million
shares of common stock outstanding, 1997 dividends are
expected to approximate $6.4 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 1997 is uncertain due to the factors
affecting revenues and expenses cited above. However, Devon
considers its capital resources to be more than adequate to
fund its anticipated capital expenditures.
Based on the expected level of 1997's capital
expenditures and net cash provided by operations, Devon does
not expect to rely on its 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 credit lines. The
unused portion of these credit lines at the end of 1996
consisted of $252 million of long-term credit facilities, and
a $12.5 million (Canadian dollars) demand facility for Devon's
new 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. In fact, to lower its borrowing costs, Devon
may reduce its credit lines in 1997 until a need for
significant capital arises.
Impact of Recently Issued Accounting Standards Not Yet
Adopted In June, 1996, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standard No.
125, "Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities." SFAS No. 125 is
effective for certain transfers and servicing of financial
assets and extinguishment of liabilities occurring after
December 31, 1996. It is effective for other transfers of
financial assets occurring after December 31, 1997. It is to
be applied prospectively. SFAS No. 125 provides accounting
and reporting standards for transfers and servicing of
financial assets and extinguishment of liabilities based on
consistent application of a financial-components approach that
focuses on control. It distinguishes transfers of financial
assets that are sales from transfers that are secured
borrowings. Management of Devon does not expect that adoption
of SFAS No. 125 will have a material impact on Devon's
financial position or results of operations.
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 current method of accounting for
environmental remediation costs. Therefore, adoption of SOP
96-1 will not have a material impact on Devon's financial
position or results of operations.
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements and Consolidated
Financial Statement Schedules
Page
Independent Auditors' Report 43
Consolidated Financial Statements:
Consolidated Balance Sheets
December 31, 1996, 1995 and 1994 44
Consolidated Statements of Operations
Years Ended December 31, 1996, 1995 and 1994 45
Consolidated Statements of Stockholders' Equity
Years Ended December 31, 1996, 1995 and 1994 46
Consolidated Statements of Cash Flows
Years Ended December 31, 1996, 1995 and 1994 47
Notes to Consolidated Financial Statements
December 31, 1996, 1995 and 1994 48
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, 1996, 1995 and 1994, 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
February 7, 1997
<PAGE>
<TABLE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
<CAPTION>
December 31,
1996 1995 1994
Assets
Current assets:
<S> <C> <C> <C>
Cash and cash equivalents $ 9,401,350 8,897,891 8,336,371
Accounts receivable (Note 5) 29,580,306 14,400,295 15,626,799
Inventories 2,103,486 605,263 534,326
Prepaid expenses 688,752 222,135 564,371
Deferred income taxes (Note 8) 1,600,000 749,000 262,000
Total current assets 43,373,894 24,874,584 25,323,867
Property and equipment, at cost, based
on the full cost method of accounting
for oil and gas properties (Note 6) 974,805,756 631,437,904 523,941,141
Less accumulated depreciation,
depletion and amortization 281,959,410 239,619,167 202,634,961
692,846,346 391,818,737 321,306,180
Other assets 10,030,560 4,870,796 4,817,489
Total assets $746,250,800 421,564,117 351,447,536
Liabilities and stockholders' equity
Current liabilities:
Accounts payable:
Trade 4,861,428 3,868,458 6,394,897
Revenues and royalties due
to others 10,569,960 7,322,418 7,398,199
Income taxes payable 4,705,447 1,364,070 -
Accrued expenses 3,503,420 3,003,943 3,225,493
Total current liabilities 23,640,255 15,558,889 17,018,589
Revenues and royalties due to others 1,053,270 816,412 1,383,135
Other liabilities (Notes 3 and 11) 10,325,999 8,623,057 -
Long-term debt (Note 7) 8,000,000 143,000,000 98,000,000
Deferred revenue 205,859 72,761 1,299,947
Deferred income taxes (Note 8) 81,121,000 34,452,000 27,340,000
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 - -
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 32,141,295 in 1996,
22,111,896 in 1995 and
22,050,996 in 1994 3,214,130 2,211,190 2,205,100
Additional paid-in capital 388,090,930 167,430,347 166,654,305
Retained earnings 81,099,357 49,399,461 37,546,460
Total stockholders' equity 472,404,417 219,040,998 206,405,865
Commitments and contingencies
(Notes 11 and 12)
Total liabilities and
stockholders' equity $746,250,800 421,564,117 351,447,536
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
<CAPTION>
Year Ended December 31,
1996 1995 1994
Revenues
<S> <C> <C> <C>
Oil sales $ 80,142,073 55,289,819 38,086,076
Gas sales 68,049,478 50,732,158 56,371,452
Natural gas liquids sales 14,366,771 6,403,663 4,908,126
Other 1,458,562 877,185 1,407,305
Total revenues 164,016,884 113,302,825 100,772,959
Costs and expenses
Lease operating expenses 31,568,428 27,288,755 24,520,757
Production taxes 10,657,814 6,832,507 6,899,743
Depreciation, depletion and
amortization (Note 6) 43,361,029 38,089,783 34,132,150
General and administrative
expenses 9,101,429 8,418,739 8,424,687
Interest expense 5,276,527 7,051,142 5,438,911
Distributions on preferred
securities of subsidiary
trust (Note 9) 4,753,125 - -
Total costs and expenses 104,718,352 87,680,926 79,416,248
Earnings before income taxes 59,298,532 25,621,899 21,356,711
Income tax expense (Note 8)
Current 6,709,000 4,495,000 415,000
Deferred 17,789,000 6,625,000 7,197,000
Total income tax expense 24,498,000 11,120,000 7,612,000
Net earnings $ 34,800,532 14,501,899 13,744,711
Net earnings per average common
share outstanding (Note 1):
Assuming no dilution $1.57 0.66 0.64
Assuming full dilution $1.52 0.66 0.64
Weighted average common shares
outstanding 22,159,507 22,073,550 21,551,581
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,
1996 1995 1994
Common stock
<S> <C> <C> <C>
Balance, beginning of year $ 2,211,190 2,205,100 2,084,232
Par value of common shares issued 1,002,940 6,090 120,868
Balance, end of year 3,214,130 2,211,190 2,205,100
Additional paid-in capital
Balance, beginning of year 167,430,347 166,654,305 144,403,743
Common shares issued, net
of issuance costs 220,660,583 776,042 22,250,562
Balance, end of year 388,090,930 167,430,347 166,654,305
Retained earnings
Balance, beginning of year 49,399,461 37,546,460 26,411,572
Dividends (3,100,636) (2,648,898) (2,609,823)
Net earnings 34,800,532 14,501,899 13,744,711
Balance, end of year 81,099,357 49,399,461 37,546,460
Total stockholders' equity, end of year $472,404,417 219,040,998 206,405,865
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,
1996 1995 1994
Cash flows from operating activities
<S> <C> <C> <C>
Net earnings $ 34,800,532 14,501,899 13,744,711
Adjustments to reconcile net earnings to net
cash provided by operating activities:
Depreciation, depletion and amortization 43,361,029 38,089,783 34,132,150
(Gain) loss on sale of assets (3,930) 273,238 (27,086)
Deferred income taxes 17,789,000 6,625,000 7,197,000
Changes in assets and liabilities net of
effects of acquisitions of businesses
(Note 2):
(Increase) decrease in:
Accounts receivable (15,470,528) 1,213,877 123,388
Inventories (176,286) (70,937) 181,475
Prepaid expenses (466,617) 342,236 712
Other assets (1,032,653) 677,238 (489,648)
Increase (decrease) in:
Accounts payable 3,370,474 (430,736) (8,896,674)
Income taxes payable 3,341,377 1,364,070 (467,962)
Accrued expenses 399,477 (221,550) 997,645
Revenues and royalties due to others 236,858 (566,723) (62,748)
Long-term other liabilities 519,978 705,636 -
Deferred revenue 133,098 (1,227,186) (49,127)
Net cash provided by operating
activities 86,801,809 61,275,845 46,383,836
Cash flows from investing activities
Proceeds from sale of property and equipment 4,037,480 9,427,401 4,649,257
Capital expenditures (98,854,846) (117,593,897) (35,619,968)
Payments made for acquisition of business
(Note 2) - (2,391,484) (42,397,463)
Net cash used in investing
activities (94,817,366) (110,557,980) (73,368,174)
Cash flows from financing activities
Proceeds from borrowings on revolving
line of credit 29,000,000 52,000,000 32,500,000
Principal payments on revolving line of
credit (164,000,000) (7,000,000) (14,500,000)
Issuance of common stock, net of issuance
costs 577,483 782,132 380,244
Issuance of preferred securities of subsidiary
trust, net of issuance costs 144,665,205 - -
Dividends paid on common stock (3,100,636) (2,648,898) (2,609,823)
Increase in long-term other liabilities
(Note 3) 1,376,964 6,710,421 -
Net cash provided by financing
activities 8,519,016 49,843,655 15,770,421
Net increase (decrease) in cash and cash
equivalents 503,459 561,520 (11,213,917)
Cash and cash equivalents at beginning of year 8,897,891 8,336,371 19,550,288
Cash and cash equivalents at end of year $ 9,401,350 8,897,891 8,336,371
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1996, 1995 and 1994
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.
Deferred Revenue
Deferred revenue at the end of 1996 consists
primarily of the unrecognized gain from the termination of an
interest rate swap agreement. In prior years, deferred
revenue included primarily funds received under take-or-pay
provisions of certain gas contracts, which provided for
recovery by the paying party of certain volumes of gas.
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 1996, there was one purchaser, Aquila
Energy Marketing Corporation ("Aquila"), who accounted for
over 10% of Devon's gas sales. Aquila accounted for 45% of
Devon's 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. ("Enron") -
16%. During 1994, there were three purchasers who accounted
for over 10% of Devon's gas sales. These three purchasers and
their respective share of gas sales were: Aquila - 21%;
Enron - 19%; and Meridian Oil Trading, Inc. - 18%.
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 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
Net earnings per common share assuming no dilution
are based upon the weighted average number of shares of common
stock outstanding during the year. Stock options have been
excluded since they would not have had a significant dilutive
effect, and the Trust Convertible Preferred Securities issued
in 1996 are excluded as they are not common stock equivalents.
For 1996, net earnings per common share assuming
full dilution is based upon the adjusted amount of net
earnings and the adjusted number of common shares outstanding
assuming the Trust Convertible Preferred Securities had been
converted to common stock as of their issuance date in July
1996. The fully diluted per share amount in 1996 also
includes the effect of Devon's outstanding stock options as
calculated using the treasury stock method. The 1996 adjusted
net earnings used for the fully diluted calculation was $37.8
million, and the adjusted number of common shares was
24,860,910.
No fully diluted per share amounts are presented
for 1995 and 1994 due to the insignificant dilutive effect of
the stock options outstanding.
Dividends
Dividends on common stock were paid in 1994, 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.
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 will not have a material
impact on Devon's financial position or results of
operations.
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 $28.0 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 $191.7 million allocated to proved oil
and gas reserves, $29.0 million allocated to undeveloped
leasehold acquired and $0.9 million allocated to inventories
and other assets acquired. Including the additional $28.0
million of deferred tax liability, $214.2 million was
allocated to proved reserves and $34.5 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 are approximately 36% oil
and natural gas liquids and 64% natural gas. Included in the
acquired reserves were certain proved undeveloped reserves, for
which Devon expects 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.
On February 18, 1994, Devon and Alta Energy
Corporation ("Alta") entered into an Agreement and Plan of
Merger, as amended on April 13, 1994, whereby Alta was merged
into a wholly-owned subsidiary of Devon (the "Alta Merger").
The Alta Merger was consummated on May 18, 1994, at which date
the separate existence of Alta ceased. Alta's common
stockholders received approximately 1,168,000 shares of Devon
common stock and $1.5 million in cash upon consummation of the
Alta Merger. Subsequently, in February 1995, former Alta
stockholders received an additional cash payment of $2.4
million based upon the post-closing evaluation of the Camille
Adams #1 well in Louisiana. Devon also incurred $41.4 million
of other costs related to the Alta Merger. This included
$31.7 million to acquire Alta's debt from its creditors, $3.0
million to acquire shares of Alta preferred and common stock,
$3.8 million loaned to Alta for operating funds, $1.5 million
to acquire certain net profits interests from Alta creditors,
and $1.4 million for third party costs related to the Alta
Merger.
Devon recorded additional deferred tax liabilities
of $11.5 million due to the substantially tax-free nature of
the Alta Merger to the former Alta stockholders. Excluding
the $11.5 million of additional deferred tax liabilities,
approximately $69.4 million of the total consideration
involved in the Alta Merger was allocated to proved oil and
gas reserves. Including the deferred tax liabilities, $80.9
million was allocated to proved oil and gas reserves. The
Alta Merger was accounted for by the purchase method of
accounting for business combinations. Accordingly, the
accompanying 1994 consolidated statement of operations does
not include any revenue or expenses associated with Alta prior
to the May 18, 1994 closing date.
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:
Assuming no dilution $2.16
Assuming full dilution $2.08
Weighted average common shares outstanding 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 $0.66 0.86
</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 1996 were
equal to approximately $1.02 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 12 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, 1996 and 1995, Devon received $11.5
million and $13.9 million, respectively, related to the
credits. Of these amounts, $10.3 million and $12.8 million
were
recorded as additional gas sales in 1996 and 1995,
respectively, and $1.2 million and $1.1 million were recorded
as an addition to liabilities in 1996 and 1995, respectively,
as discussed in the following paragraph. Based on the
reserves estimated at December 31, 1996, and an assumed annual
inflation factor of 2%, Devon estimates it will receive total
tax credit payments of approximately $58 million from 1997
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 will be increased over time to reflect the option
purchase price. As the purchase price increases, a portion of
the tax credit payments received by Devon will be added to the
liability. As stated above, for the years ended December 31,
1996 and 1995, $1.2 million and $1.1 million, respectively, of
the total amount received for tax credit payments were added
to the liability, which raised the liability balance to $7.9
million as of December 31, 1996.
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 $7.9 million of other
liabilities recorded as of year-end 1996, does not include any
amount related to such reserves.
4. Supplemental Cash Flow Information
Cash payments for interest in 1996, 1995, and 1994
were approximately $5.5 million, $6.7 million and $5.1
million, respectively. Cash payments for federal and state
income taxes in 1996, 1995, and 1994 were approximately $3.4
million, $2.2 million and $1.8 million, respectively.
The 1996 acquisition of the KMG-NAOS Properties
and the 1994 Alta Merger involved cash and non-cash
consideration as presented below:
<TABLE>
<CAPTION>
1996 1994
<S> <C> <C>
Cash payments made $ - 42,915,845
Value of common stock issued 221,576,040 21,991,084
Liabilities assumed - 7,192,671
Deferred tax liability created 28,029,000 11,500,000
Fair value of assets acquired $249,605,040 83,599,600
</TABLE>
The above cash payments of $42.9 million in 1994
include approximately $1.4 million of direct costs paid to
third parties which were capitalized and allocated to
producing oil and gas properties. The cash payments made are
reduced in the accompanying 1994 consolidated statement of
cash flows by $518,382 of cash acquired in the Alta Merger.
5. Accounts Receivable
The components of accounts receivable included the
following:
<TABLE>
<CAPTION>
December 31,
1996 1995 1994
Oil, gas and natural gas liquids
<S> <C> <C> <C>
revenue accruals $24,200,047 11,169,313 10,973,589
Joint interest billings 4,318,764 2,962,037 3,367,493
Income tax refunds due - - 959,085
Other 1,461,495 493,945 551,632
29,980,306 14,625,295 15,851,799
Allowance for doubtful accounts (400,000) (225,000) (225,000)
Net accounts receivable $29,580,306 14,400,295 15,626,799
</TABLE>
6. Property and Equipment
Property and equipment included the following:
<TABLE>
<CAPTION>
December 31,
1996 1995 1994
Oil and gas properties:
<S> <C> <C> <C>
Subject to amortization $899,827,749 604,227,702 503,174,488
Not subject to amortization:
Acquired in 1996 35,141,800 - -
Acquired in 1995 5,034,942 5,635,170 -
Acquired in 1994 1,001,291 1,001,427 1,451,109
Acquired in 1993 5,204,995 5,556,977 5,556,977
Acquired in 1992 8,113,899 8,257,985 8,561,031
Accumulated depreciation, depletion
and amortization (278,923,340) (237,385,785) (200,746,032)
Net oil and gas properties 675,401,336 387,293,476 317,997,573
Other property and equipment 20,481,080 6,758,643 5,197,536
Accumulated depreciation and amortization (3,036,070) (2,233,382) (1,888,929)
Net other property and equipment 17,445,010 4,525,261 3,308,607
Property and equipment, net of
accumulated depreciation,
depletion and amortization $ 692,846,346 391,818,737 321,306,180
</TABLE>
Depreciation, depletion and amortization expense consisted
of the following components:
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995 1994
<S> <C> <C> <C>
Depreciation, depletion and amortization
of oil and gas properties $41,537,555 36,639,753 32,861,174
Depreciation and amortization of other
property and equipment 1,337,420 1,045,978 865,092
Amortization of other assets 486,054 404,052 405,884
Total expense $43,361,029 38,089,783 34,132,150
</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, 1996,
was $260 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. The average interest rates on the outstanding
debt at the end of 1996, 1995 and 1994, were 6.19%, 6.64% and
6.83%, 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,
1999. Thereafter, the maximum loan amount will be reduced by
8.33% every three months until August 31, 2002. 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, 1996, Devon was in compliance with such covenants
and restrictions.
On December 31, 1996, Devon established a demand revolving
operating credit facility with a Canadian bank. This facility
is unsecured and will be utilized for general corporate
purposes related to Devon's new 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
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 $0.2 million of the gain 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, 1996, 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 1998 - 2008 $14,100,000
Net operating loss - various states 1997 - 2010 $10,000,000
Statutory depletion No expiration $ 1,200,000
Minimum tax credit No expiration $ 5,600,000
</TABLE>
All of the carryforward amounts shown above have been
utilized for financial purposes to reduce deferred taxes.
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,
1996 1995 1994
<S> <C> <C> <C>
Federal statutory tax rate 35% 35% 35%
Nonconventional fuel source credits - (1) -
State income taxes 5 4 3
Effect of San Juan Basin Transaction 2 4 -
Other (1) 1 (2)
Effective income tax rate 41% 43% 36%
</TABLE>
The tax effects of temporary differences that gave rise to
significant portions of the deferred tax assets and
liabilities at December 31, 1996, 1995 and 1994 are presented
below:
<TABLE>
<CAPTION>
December 31,
1996 1995 1994
Deferred tax assets:
<S> <C> <C> <C>
Net operating loss carryforwards $ 5,314,000 6,082,000 6,127,000
Statutory depletion carryforwards 412,000 2,287,000 3,087,000
Investment tax credit carryforwards 42,000 85,000 813,000
Minimum tax credit carryforwards 5,624,000 5,576,000 2,195,000
Production payments 19,685,000 24,770,000 -
Other 2,613,000 1,966,000 897,000
Total gross deferred tax assets 33,690,000 40,766,000 13,119,000
Less valuation allowance 100,000 100,000 100,000
Net deferred tax assets 33,590,000 40,666,000 13,019,000
Deferred tax liabilities:
Property and equipment, principally due
to differences in depreciation, and
the expensing of intangible drilling
costs for tax purposes (113,111,000) (74,369,000) (40,097,000)
Net deferred tax liability $ (79,521,000) (33,703,000) (27,078,000)
</TABLE>
As shown in the above schedule, Devon has recognized $33.6
million of net deferred tax assets as of December 31, 1996.
Such amount consists almost entirely of $11.4 million of
various carryforwards available to offset future income taxes,
and $19.7 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 2006, state net operating loss carryforwards which
expire primarily between 1999 and 2003, and the statutory
depletion and minimum tax credit carryforwards which have no
expiration dates. 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 1997 and 1999. 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, 1996, related to
depletion carryforwards acquired in the Alta Merger.
The $19.7 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 $19.7 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, 1996 was approximately $196.6 million, as
compared to the book value of $149.5 million. This fair value
was based on quoted prices at which TCP Securities were
purchased and sold on December 31, 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, 1996, 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 two stock option plans
adopted in 1988 and 1993 ("the 1988 Plan" and "the 1993
Plan"). Options granted under the 1988 Plan remain
exercisable by the employees owning such options, but no new
options will be granted under the 1988 Plan. At December 31,
1996, 15 participants held the 303,400 options outstanding
under the 1988 Plan.
Effective June 7, 1993, Devon adopted the 1993 Plan and
reserved one million shares of Common Stock for issuance
thereunder. Twenty-two employees were eligible to participate
in the 1993 Plan at year-end 1996.
The exercise price of incentive stock options granted under
the 1993 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. The exercise price of
nonqualified options granted under the 1993 Plan may not be
less than 75% of the fair market value of the stock on the
date of 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 1993 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 1993 Plan is administered by a committee
comprised of non-management members of the Board of Directors.
The 1993 Plan expires on April 25, 2003. As of December 31,
1996, 23 participants held the 898,600 options outstanding
under the 1993 Plan. There were 88,700 options available for
future grants as of December 31, 1996.
A summary of the status of Devon's stock option plans as of
December 31, 1994, 1995 and 1996, 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, 1993 482,700 $16.521 300,000 $14.848
Options granted 436,000 $20.736
Options exercised (40,800) $9.355
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
</TABLE>
The weighted average fair values of options granted
during 1996 and 1995 were $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 Binomial Option
Pricing Model with the following assumptions for 1996 and
1995, respectively: risk-free interest rates of 6.3% and 5.5%;
dividend yields of 0.6% and 0.5%; expected lives of 5 and 5
years; and volatility of the price of the underlying common
stock of 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, 1996:
<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
<C> <C> <C> <C> <C> <C>
$8-$14 108,600 4.6 years $9.662 108,600 $9.662
$18-$21 205,700 7.9 years $18.088 146,400 $18.092
$23-$26 644,200 7.7 years $23.784 487,800 $23.816
$32-$33 243,500 10.0 years $32.500 80,700 $32.500
1,202,000 7.9 years $23.299 823,500 $21.783
</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 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,
1996 1995
Net earnings:
<S> <C> <C>
As reported $34,800,532 14,501,899
Pro forma $34,016,571 13,540,052
Net earnings per share:
As reported:
Assuming no dilution $1.57 0.66
Assuming full dilution $1.52 0.66
Pro forma:
Assuming no dilution $1.54 0.61
Assuming full dilution $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,
1996 1995 1994
Actuarial present value of benefit
obligations:
Accumulated benefit obligation:
<S> <C> <C> <C>
Vested $(3,619,000) (3,500,000) (2,648,000)
Nonvested (741,000) (654,000) (282,000)
Total $(4,360,000) (4,154,000) (2,930,000)
Projected benefit obligation for
service rendered to date (5,122,000) (4,782,000) (3,378,000)
Plan assets at fair value, primarily
investments in mutual funds 5,022,000 4,227,000 3,252,000
Plan assets less than projected benefit
obligation (100,000) (555,000) (126,000)
Unrecognized prior service cost (benefit) (131,000) (154,000) (176,000)
Unrecognized net loss from past experience
different from that assumed, and effects
of changes in assumptions 519,000 921,000 225,000
Prepaid (accrued) pension expense $ 288,000 212,000 (77,000)
</TABLE>
The following table sets forth the aggregate funded
status of the Supplementary Plan and related amounts
recognized in Devon's balance sheet as of December 31, 1996
and 1995:
<TABLE>
<CAPTION>
December 31,
1996 1995
Actuarial present value of benefit obligations:
Accumulated benefit obligation:
<S> <C> <C>
Vested $(1,960,000) (1,658,000)
Nonvested (279,000) (255,000)
Total $(2,239,000) (1,913,000)
Projected benefit obligation for service
rendered to date (2,907,000) (2,245,000)
Plan assets at fair value - -
Plan assets less than projected benefit obligation (2,907,000) (2,245,000)
Unrecognized prior service cost 1,235,000 1,354,000
Unrecognized net loss from past experience different
from that assumed, and effects of changes in
assumptions 446,000 185,000
Accrued pension expense (1,226,000) (706,000)
Additional minimum liability (1,013,000) (1,207,000)
Total pension liability $(2,239,000) (1,913,000)
</TABLE>
The $2.2 million and $1.9 million total pension
liability of the Supplementary Plan as of December 31, 1996
and 1995, respectively, are included in long-term other
liabilities on the accompanying consolidated balance sheets.
The additional minimum liabilities of $1.0 million and $1.2
million at year-end 1996 and 1995, respectively, are offset by
intangible assets of $1.0 million in 1996 and $1.2 million in
1995. 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,
1996 1995 1994
<S> <C> <C> <C>
Service cost - benefits earned during the period $ 557,000 362,000 277,000
Interest cost on projected benefit obligation 569,000 446,000 284,000
Actual return on plan assets (453,000) (536,000) (20,000)
Net amortization and deferral 231,000 345,000 (231,000)
Net periodic pension expense $ 904,000 617,000 310,000
</TABLE>
The weighted average discount rate used in determining the
actuarial present value of the projected benefit obligation in
1996, 1995 and 1994 was 7.5%, 7.25% and 8.5%, 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%, 8.5% and 8% in 1996, 1995 and 1994,
respectively.
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
$188,000, $170,000 and $158,000 for the years ended December
31, 1996, 1995 and 1994, 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 majority of Devon's sales of nonconventional gas from
the San Juan Basin are subject to federal royalties
administered and collected by the Minerals Management Service
("MMS"). In determining royalties payable to the MMS, Devon
has followed the industry practice of reducing the gas sales
price for certain permitted costs related to the
transportation of gas produced and CO 2 removal. In 1995, the
MMS issued new policies which would increase Devon's share of
federal royalties for nonconventional gas produced and sold in
the San Juan Basin for the years 1990 through 1996, and for
future years as well. In early 1997, the MMS asserted a claim
for additional royalties. While the specific claim only
covers 17 months of the seven-year period in question, the MMS
has requested Devon to calculate and pay additional royalties
for the entire seven-year period using methods and procedures
consistent with the calculation for the 17 months. Devon has
not determined whether it agrees with the methods and
procedures used by the MMS in its calculations, and Devon
intends to vigorously contest any claim for excessive
additional federal royalties through available administrative
and judicial processes. However, Devon has accrued an
estimate of additional federal royalties related to its share
of gas produced from 1990 through 1996. Devon's management,
in consultation with legal counsel, believes adequate
provision has been made for any additional federal royalties
due and related interest. The amount accrued represents
Devon's best estimate based on Devon's interpretation of the
new policies issued and all other related information
available to Devon. It is possible that a different
interpretation of the policies and related facts could result
in an assessment higher than what Devon has accrued. However,
Devon's management does not believe that the amount of
possible assessments above that already accrued would be
material.
In a matter unrelated to the MMS issue discussed above, 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 for 1996 taxes which were paid monthly
throughout the year, 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 CO 2. 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. If the amount paid is not refunded through the normal
administrative processes available, Devon intends to file 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 $1.1 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, 1996:
<TABLE>
<CAPTION>
Year ending December 31,
<C> <C>
1997 $233,000
1998 183,000
1999 138,000
2000 123,000
Total minimum lease payments required $677,000
</TABLE>
Total rental expense for all operating leases is as follows
for the years ended December 31:
<TABLE>
<C> <C>
1996 $572,177
1995 $546,388
1994 $521,769
</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,
1996 1995 1994
Property acquisition costs:
Proved, excluding deferred income
<S> <C> <C> <C>
taxes $199,655,000 47,316,000 70,376,000
Deferred income taxes 22,557,000 - 11,500,000
Total proved, including deferred income taxes $222,212,000 47,316,000 81,876,000
Unproved, excluding deferred income taxes $29,673,000 4,529,000 1,797,000
Deferred income taxes 5,472,000 - -
Total unproved, including deferred income taxes 35,145,000 4,529,000 1,797,000
Exploration costs $ 2,708,000 7,174,000 5,194,000
Development costs $ 73,468,000 56,253,000 26,268,000
<CAPTION>
Domestic
Year Ended December 31,
1996 1995 1994
Property acquisition costs:
Proved, excluding deferred income
taxes $150,546,000 47,316,000 70,376,000
Deferred income taxes 15,257,000 - 11,500,000
Total proved, including deferred income taxes $165,803,000 47,316,000 81,876,000
Unproved, excluding deferred income taxes $26,073,000 4,529,000 1,797,000
Deferred income taxes 5,472,000 - -
Total unproved, including deferred income taxes 31,545,000 4,529,000 1,797,000
Exploration costs $ 2,708,000 7,174,000 5,194,000
Development costs $ 73,468,000 56,253,000 26,268,000
<CAPTION>
Canada
Year Ended December 31,
1996 1995 1994
Property acquisition costs:
Proved, excluding deferred income
taxes $ 49,109,000 - -
Deferred income taxes 7,300,000 - -
Total proved, including deferred income taxes $ 56,409,000 - -
Unproved $ 3,600,000 - -
Exploration costs $ - - -
Development costs $ - - -
</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 $2.9
million, $2.7 million and $2.3 million in the years 1996, 1995
and 1994, respectively.
Due to the substantially tax-free nature of the acquisition
of the KMG-NAOS properties to Kerr-McGee, and of the 1994 Alta
Merger to the former Alta stockholders, Devon recorded
additional deferred tax liabilities of $28.0 million related
to the KMG-NAOS acquisition and $11.5 million related to the
Alta Merger. As shown in the above tables, the deferred tax
liabilities caused an additional $22.5 million and $11.5
million to be allocated to proved oil and gas reserves in 1996
and 1994, respectively, and an additional $5.5 million to be
allocated to unproved properties in 1996.
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. For the three year period
ended December 31, 1996, Devon had no oil and gas producing
activities outside the United States.
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995 1994
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales $162,558,000 112,425,000 99,366,000
Production and operating expenses (42,226,000) (34,121,000) (31,421,000)
Depreciation, depletion and amortization (41,538,000) (36,640,000) (32,861,000)
Income tax expense (27,796,000) (15,536,000) (12,411,000)
Results of operations for oil and gas
producing activities $ 50,998,000 26,128,000 22,673,000
Depreciation, depletion and amortization
per equivalent barrel of production $3.88 3.65 3.45
</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, 1996.
Approximately 94%, 92% and 91%, of the respective year-end
1996, 1995 and 1994 domestic proved reserves were calculated
by the independent petroleum consultants LaRoche Petroleum
Consultants, Ltd. The remaining percentages of domestic
reserves are based on Devon's own estimates. All of
the 1996 Canadian proved reserves were calculated by
the independent petroleum consultants AMH Group Ltd.
<TABLE>
<CAPTION>
Total
Natural
Oil Gas Gas Liquids
(Bbls) (Mcf) (Bbls)
<S> <C> <C> <C>
Proved reserves as of December 31, 1993 14,897,000 369,254,000 1,854,000
Revisions of estimates 3,157,000 (5,540,000) 1,733,000
Extensions and discoveries 2,008,000 13,206,000 183,000
Purchase of reserves 25,201,000 13,492,000 2,181,000
Production (2,467,000) (39,335,000) (501,000)
Sale of reserves (631,000) (3,517,000) (8,000)
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
Proved developed reserves as of:
December 31, 1993 11,548,000 355,536,000 1,751,000
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
<CAPTION>
Domestic
Natural
Oil Gas Gas Liquids
(Bbls) (Mcf) (Bbls)
Proved reserves as of December 31, 1993 14,897,000 369,254,000 1,854,000
Revisions of estimates 3,157,000 (5,540,000) 1,733,000
Extensions and discoveries 2,008,000 13,206,000 183,000
Purchase of reserves 25,201,000 13,492,000 2,181,000
Production (2,467,000) (39,335,000) (501,000)
Sale of reserves (631,000) (3,517,000) (8,000)
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
Proved developed reserves as of:
December 31, 1993 11,548,000 355,536,000 1,751,000
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
<CAPTION>
Canada
Natural
Oil Gas Gas Liquids
(Bbls) (Mcf) (Bbls)
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
Proved developed reserves as of
December 31, 1996 7,530,000 40,858,000 884,000
</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,
1996 1995 1994
<S> <C> <C> <C>
Future cash inflows $ 3,989,582,000 1,476,418,000 1,186,845,000
Future costs:
Development (54,133,000) (52,327,000) (75,115,000)
Production (1,071,913,000) (496,279,000) (400,676,000)
Future income tax expense (785,702,000) (153,431,000) (71,427,000)
Future net cash flows 2,077,834,000 774,381,000 639,627,000
10% discount to reflect timing
of cash flows (901,617,000) (328,481,000) (281,421,000)
Standardized measure of
discounted future net
cash flows $ 1,176,217,000 445,900,000 358,206,000
Discounted future net cash
flows before income
taxes $ 1,621,992,000 534,248,000 398,206,000
<CAPTION>
Domestic
December 31,
1996 1995 1994
Future cash inflows $ 3,712,956,000 1,476,418,000 1,186,845,000
Future costs:
Development (54,064,000) (52,327,000) (75,115,000)
Production (1,013,750,000) (496,279,000) (400,676,000)
Future income tax expense (713,182,000) (153,431,000) (71,427,000)
Future net cash flows 1,931,960,000 774,381,000 639,627,000
10% discount to reflect timing of
cash flows (846,174,000) (328,481,000) (281,421,000)
Standardized measure of
discounted future net
cash flows $ 1,085,786,000 445,900,000 358,206,000
Discounted future net cash
flows before income
taxes $ 1,486,603,000 534,248,000 398,206,000
<CAPTION>
Canada
December 31,
1996 1995 1994
Future cash inflows $276,626,000 - -
Future costs:
Development (69,000) - -
Production (58,163,000) - -
Future income tax expense (72,520,000) - -
Future net cash flows 145,874,000 - -
10% discount to reflect timing of
cash flows (55,443,000) - -
Standardized measure of
discounted future net
cash flows $ 90,431,000 - -
Discounted future net cash
flows before income taxes $135,389,000 - -
</TABLE>
Future cash inflows are computed by applying year-end prices
(averaging $24.52 per barrel of oil, adjusted for
transportation and other charges, $3.35 per Mcf of gas and
$23.34 per barrel of natural gas liquids at December 31, 1996)
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 $3.35 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 $48.7 million related to
these tax credit payments from 1997 through 2002. This amount
has been calculated using the assumption that the year-end
1996 tax credit rate of $1.02 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. Prior to the San
Juan Basin Transaction as described in Note 3, the future
income tax expenses estimated at December 31, 1994 were reduced
by the estimated future Section 29 tax credits to be generated by the
San Juan Basin coal seam gas properties. It was estimated at
year-end 1994 that undiscounted amounts of approximately $113
million of Section 29 tax credits could be generated in future
years to Devon's interest. However, because of limitations on
the amount of Section 29 tax credits which can actually be
utilized for income tax purposes, the undiscounted amounts
included as reductions to future income tax expense for
purposes of calculating the standardized measure of discounted
future net cash flows were only $41 million at year-end 1994.
As a result of the San Juan Basin Transaction, substantially
all of the value of the Section 29 tax credits at year-end
1996 and 1995 is now included in "future cash inflows,"
instead of a reduction to income tax expense, in Devon's
standardized measure of discounted future net cash flows.
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,
1996 1995 1994
<S> <C> <C> <C>
Beginning balance $445,900,000 358,206,000 343,550,000
Sales of oil, gas and natural gas
liquids, net of production costs (120,332,000) (78,304,000) (67,945,000)
Net changes in prices and
production costs 519,456,000 60,498,000 (107,210,000)
Extensions, discoveries, and improved
recovery, net of future
development costs 42,522,000 22,308,000 14,629,000
Purchase of reserves, net of future
development costs 576,234,000 50,000,000 133,103,000
Development costs incurred during
the period which reduced future
development costs 44,332,000 43,810,000 16,519,000
Revisions of quantity estimates 40,905,000 7,397,000 26,167,000
Sales of reserves in place (6,499,000) (7,933,000) (5,281,000)
Accretion of discount 53,425,000 39,821,000 38,047,000
Net change in income taxes (357,427,000) (48,347,000) (3,080,000)
Other, primarily changes in timing (62,299,000) (1,556,000) (30,293,000)
Ending balance $ 1,176,217,000 445,900,000 358,206,000
</TABLE>
15. Supplemental Quarterly Financial Information (Unaudited)
Following is a summary of the unaudited interim results of
operations for the years ended December 31, 1996 and 1995:
<TABLE>
<CAPTION>
1996
First Second Third Fourth
Quarter Quarter Quarter Quarter Total
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:
Assuming no dilution $0.25 0.31 0.35 0.66 1.57
Assuming full dilution $0.25 0.31 0.35 0.59 1.52
<CAPTION>
<F1>
1995 - Actual Reported Results (a)
First Second Third Fourth
Quarter Quarter Quarter Quarter Total
Oil, gas and natural gas liquids
sales $23,519,568 25,331,966 33,589,019 29,985,087 112,425,640
Total revenues $23,762,327 25,650,334 33,770,864 30,119,300 113,302,825
Net earnings $ 1,026,802 2,444,422 6,645,531 4,385,144 14,501,899
Net earnings per share $0.05 0.11 0.30 0.20 0.66
<CAPTION>
<F1>
1995 - Adjusted Results (a)
First Second Third Fourth
Quarter Quarter Quarter Quarter Total
Oil, gas and natural gas liquids
sales $26,478,770 28,293,715 27,668,068 29,985,087 112,425,640
Total revenues $26,796,579 28,612,083 27,774,863 30,119,300 113,302,825
Net earnings $ 2,864,127 4,181,531 3,071,097 4,385,144 14,501,899
Net earnings per share $0.13 0.19 0.14 0.20 0.66
<F1>
(a) The San Juan Basin Transaction described in Note 3 was
effective January 1, 1995. However, it was initially subject
to a material contingency, and thus the transaction's impact
on Devon's statement of operations was deferred pending the
contingency's resolution. When the contingency was favorably
resolved, the cumulative nine-month effect of the transaction
was recorded in the third quarter. The second table above
includes the 1995 quarterly results as reported, including the
six-month out-of-period effect on the third quarter. The
third table above presents the 1995 quarterly results as they
would have been reported had the contingency not existed and
had the San Juan Basin Transaction's effect on earnings been
reported from the inception of the transaction on January 1,
1995.
</TABLE>
<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, 1997.
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, 1997.
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, 1997.
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, 1997.
<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
and Reorganization by and among Registrant
and Devon Energy Corporation, a Delaware
corporation, dated as of April 13, 1995
(incorporated by reference to Exhibit A to
Registrant's definitive Proxy Statement for
its 1995 Annual Meeting of Shareholders filed
on April 21, 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 (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 4.5 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
[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 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)].*
10.3 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).*
10.4 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).*
10.5 Severance Agreement between
Devon Energy Corporation (Nevada), Devon
Energy Corporation (Delaware) and Mr. H. R.
Sanders, Jr., dated December 3, 1992
(incorporated by reference to Exhibit 10.11
to Registrant's Amendment No. 1 to Annual
Report on Form 10-K for the year ended
December 31, 1992).*
10.6 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).*
10.7 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).*
10.8 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).*
10.9 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).*
10.10 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).
10.11 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).
10.12 Purchase and Sale
Agreement between Union Oil Company of
California and Devon Energy Corporation
(Nevada) (incorporated by reference to
Exhibit 2 to Registrant's Current Report on
Form 8-K dated December 18, 1995).
10.13 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
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 of 1996. A
Current Report on Form 8-K dated January 14, 1997, was
filed by the Registrant regarding the December 31,
1996, acquisition of the KMG-NAOS Properties.
<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 6, 1997 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 6, 1997 By John W. Nichols
John W. Nichols
Chairman of the Board and Director
March 6, 1997 By J. Larry Nichols
J. Larry Nichols
President, Chief Executive Officer and Director
March 6, 1997 By H. R. Sanders, Jr.
H. R. Sanders, Jr.
Executive Vice President and Director
March 6, 1997 By William T. Vaughn
William T. Vaughn
Vice President - Finance
March 6, 1997 By Danny J. Heatly
Danny J. Heatly
Controller
<PAGE>
March 6, 1997 By Luke R. Corbett
Luke R. Corbett, Director
March 6, 1997 By Thomas F. Ferguson
Thomas F. Ferguson, Director
March 6, 1997 By David M. Gavrin
David M. Gavrin, Director
March 6, 1997 By Michael E. Gellert
Michael E. Gellert, Director
March 6, 1997 By Tom J. McDaniel
Tom J. McDaniel, Director
March 6, 1997 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 Devon Energy Corporation 1988 Stock Option
Plan #
10.3 Devon Energy Corporation 1993 Stock Option
Plan #
10.4 Severance Agreement between Devon Energy
Corporation (Nevada), Devon Energy
Corporation (Delaware) and Mr. J. Larry
Nichols, dated December 3, 1992 #
10.5 Severance Agreement between Devon Energy
Corporation (Nevada), Devon Energy
Corporation (Delaware) and Mr. H. R.
Sanders, Jr., dated December 3, 1992 #
10.6 Severance Agreement between Devon Energy
Corporation (Nevada), Devon Energy
Corporation (Delaware) and Mr. J. Michael
Lacey, dated December 3, 1992 #
10.7 Severance Agreement between Devon Energy
Corporation (Nevada), Devon Energy
Corporation (Delaware) and Mr. H. Allen
Turner, dated December 3, 1992 #
10.8 Severance Agreement between Devon Energy
Corporation (Nevada), Devon Energy
Corporation (Delaware) and Mr. Darryl G.
Smette, dated December 3, 1992 #
10.9 Severance Agreement between Devon Energy
Corporation (Nevada), Devon Energy
Corporation (Delaware) and Mr. William T.
Vaughn, dated December 3, 1992 #
10.10 Sale and Purchase Agreement relating to
Registrant's San Juan Basin gas properties #
10.11 Second Restatement of and Amendment to Sale
and Purchase Agreement relating to
Registrant's San Juan Basin gas properties #
10.12 Purchase and Sale Agreement between Union
Oil Company of California and Devon Energy
Corporation (Nevada) #
10.13 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 93
12 Computation of ratio of earnings to fixed
charges 94
21 Subsidiaries of Registrant 95
23.1 Consent of LaRoche Petroleum Consultants,
Ltd. 96
23.2 Consent of AMH Group Ltd. 97
23.3 Consent of KPMG Peat Marwick LLP 98
____________________________________
# Incorporated by reference.
<PAGE>
EXHIBIT 11
<TABLE>
<CAPTION>
DEVON ENERGY CORPORATION
Computation of Earnings Per Share
Year Ended December 31,
----------------------------
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
PRIMARY EARNINGS PER SHARE
Computation for Statement of Operations
Net earnings per statement of operations $34,800,532 14,501,899 13,744,711
=========== ========== ==========
Weighted average common shares
outstanding 22,159,507 22,073,550 21,551,581
========== ========== ==========
Primary earnings per share $1.57 0.66 0.64
===== ==== ====
Additional Primary Computation (A)
Net earnings per statement of operations $34,800,532 14,501,899 13,744,711
=========== ========== ==========
Adjustment to weighted average
common shares outstanding:
Weighted average as shown above
in primary computation 22,159,507 22,073,550 21,551,581
Add dilutive effect of outstanding
stock options (as determined using
the treasury stock method) 191,298 127,640 117,799
--------- ---------- ----------
Weighted average common shares
outstanding, as adjusted 22,350,805 22,201,190 21,669,380
========== ========== ==========
Net earnings per common share,
as adjusted $1.56 0.65 0.63
===== ==== ====
FULLY DILUTED EARNINGS PER SHARE (A)
Net earnings per statement of operations $34,800,532 14,501,899 13,744,711
Increase in net earnings from assumed conversion
of Trust Convertible Preferred Securities
(net of tax effect) 2,997,779 - -
----------- ---------- ----------
Net earnings, as adjusted $37,798,311 14,501,899 13,744,711
=========== ========== ==========
Weighted average common shares
outstanding as shown in primary
computation above 22,159,507 22,073,550 21,551,581
Add fully dilutive effect of
outstanding stock options
(as determined using the
treasury stock method) 317,610 181,446 118,211
Add weighted average of additional
shares issued from assumed
conversion of Trust Convertible
Preferred Securities 2,383,793 - -
--------- --------- -------
Weighted average common shares
outstanding, as adjusted 24,860,910 22,254,996 21,669,792
========== ========== ==========
Fully diluted earnings
per common share $1.52 0.65 0.63
===== ==== ====
(A) The additional primary computations for all three years
and the fully diluted computations for 1995 and 1994 are
submitted in accordance with Regulation S-K item
601(b)(11) although not required by footnote 2 to
paragraph 14 of APB Opinion No. 15 because they result in
dilution of less than 3%.
</TABLE>
EXHIBIT 12
<TABLE>
<CAPTION>
DEVON ENERGY CORPORATION
Computation of Ratio of Earnings to Fixed Charges
Year Ended December 31,
-----------------------------
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Earnings before income taxes $59,298,532 25,621,899 21,356,711
Add:
Interest expense 5,276,527 7,051,142 5,438,911
Distributions on preferred
securities of subsidiary trust 4,753,125 - -
Amortization of costs incurred
in connection with the
offering of the preferred
securities of subsidiary trust 82,003 - -
Estimated interest factor of
operating lease payments 190,726 182,129 173,923
-------- -------- --------
Earnings, as adjusted (A) $69,600,913 32,855,170 26,969,545
=========== ========== ==========
Fixed charges:
Interest costs incurred 5,276,527 7,051,142 5,438,911
Distributions on preferred
securities of subsidiary
trust 4,753,125 - -
Amortization of costs incurred
in connection with the offering
of the preferred securities of
subsidiary trust 82,003 - -
Estimated interest factor of
operating lease payments 190,726 182,129 173,923
-------- -------- --------
Total fixed charges (B) $10,302,381 7,233,271 5,612,834
=========== ========= =========
Ratio of earnings to fixed
charges (A)/(B) 6.76 4.54 4.80
==== ==== ====
</TABLE>
EXHIBIT 21
DEVON ENERGY CORPORATION
Subsidiaries of Registrant
The Registrant has the following significant subsidiaries:
Name of Subsidiary Jurisdiction of Incorporation
- ------------------ -----------------------------
Devon Energy Corporation (Nevada) Nevada
Devon Energy Canada Corporation Alberta, Canada
Devon Marketing Corporation Nevada
Devon Production Corporation Nevada
Devon Oil & Gas Company Nevada
Catclaw Pipeline, Inc. Oklahoma
DBC, Inc. Oklahoma
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, 1996, which appears
in the December 31, 1996 annual report on Form 10-K of Devon
Energy Corporation.
LAROCHE PETROLEUM CONSULTANTS, LTD.
LAROCHE PETROLEUM CONSULTANTS, LTD.
March 6, 1997
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, 1996, which appears
in the December 31, 1996 annual report on Form 10-K of Devon
Energy Corporation.
AMH GROUP LTD.
AMH GROUP LTD.
March 6, 1997
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 February 7, 1997, relating
to the consolidated balance sheets of Devon Energy Corporation
and subsidiaries as of December 31, 1996, 1995 and 1994 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, 1996 annual report on Form 10-
K of Devon Energy Corporation.
KPMG Peat Marwick LLP
KPMG Peat Marwick LLP
Oklahoma City, Oklahoma
March 5, 1997
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