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, 1995
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 (I.R.S. Employer
of Identification No.)
Incorporation or Organization)
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 share American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the Registrant was required to file such reports), and (2) has
been subject to such filing requirements for at least the past 90 days.
Yes x No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of Registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. x
The aggregate market value of the voting stock held by non-affiliates
of the Registrant as of February 28, 1996 was $459,567,965. At such date
22,111,896 shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 1996 annual meeting of stockholders - Part III
Page 1 of 81 total pages <PAGE>
<PAGE>
TABLE OF CONTENTS
Page
PART I
Item 1. Business . . . . . . . . . . . . . . . . . . 3
Item 2. Properties . . . . . . . . . . . . . . . . . 10
Item 3. Legal Proceedings . . . . . . . . . . . . . . 20
Item 4. Submission of Matters to a Vote of Security Holders 20
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters . . . . . . . . . . 20
Item 6. Selected Financial Data . . . . . . . . . . . 22
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . .24
Item 8. Financial Statements and Supplementary Data . 37
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . . 71
PART III
Item 10. Directors and Executive Officers of the Registrant 71
Item 11. Executive Compensation . . . . . . . . . . . 71
Item 12. Security Ownership of Certain Beneficial Owners and
Management . . . . . . . . . . . . . . . . . . . . . . 71
Item 13. Certain Relationships and Related Transactions 71
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K . . . . . . . . . . . . . . 72
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.
Unless otherwise specifically identified, forward looking
statements are identified by an asterisk (*) preceeding and
following each such statement. Foward looking 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 - Capital
Expenditures, Capital Resources and Liquidity - 1996
Estimates."
PART I
ITEM 1. BUSINESS
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's oil and gas properties are its primary assets and the source
of its cash flow and earnings. Devon owns interests in 900 producing oil
and gas properties in ten states. At December 31, 1995, Devon's estimated
proved reserves were 363.8 Bcf of natural gas, 44.5 MMBbls of oil and 9.5
MMBoe of NGLs, or 114.6 MMBoe in total. Ninety-eight percent of such
reserves are located in New Mexico, Wyoming, Texas, Oklahoma and Louisiana.
During 1988, Devon expanded its capital base with its first issuance
of common stock to the public and began a substantial expansion program.
Devon has utilized a two-pronged strategy of acquiring producing properties
and engaging primarily in development drilling and limited exploration
activities. During the eight years ended December 31, 1995, Devon has
drilled 605 new wells, 581 of which were producers, and consummated 15
significant acquisitions. During this same period, total capital costs
incurred (including acquisition and drilling costs) aggregated $535.0
million. Reserve additions were 538.1 Bcf of gas, 58.2 MMBbls of oil and
11.2 MMBoe of NGLs. These additions, minus production and property sales,
resulted in reserves increasing by a factor of fourteen during the
eight-year period.
Devon's single largest reserve position relates to its interests in
two federal units in northwest New Mexico: the Northeast Blanco Unit
("NEBU") and the San Juan 32-9 Unit Fruitland Coal Participating Area (the
"32-9 Unit"). These "state-of-the-art" projects produce natural gas from a
nonconventional source: the Fruitland Coal formation. With NEBU, the 32-9
Unit and certain minor properties, Devon's property holdings in the San
Juan Basin account for 29.4 MMBoe, or 26%, of Devon's total proved
reserves. Devon's interest in coal seam production is part of a
transaction the Company entered into effective January 1, 1995.
See "- 1995 Transactions - San Juan Basin Transaction" below.
Devon's second largest reserve position is related to its 100%
working interest in the Grayburg-Jackson field in the southeast New Mexico
portion of the Permian Basin. Devon is in the second year of an extensive
infill drilling program and waterflood project expected to be completed in
1997. *Total development costs for both the infill drilling and the
waterflood projects are estimated to be approximately $60 million, $5.8
million of which was spent in 1994 and $30.1 million of which was spent in
1995.* As of December 31, 1995, the Grayburg-Jackson Field accounted for
26.4 MMBoe, or 23%, of Devon's total proved reserves. Approximately 52% of
total proved reserves for this field are classified as proved undeveloped
and are associated with the infill/waterflood program.
Devon also owns other significant interests in the Permian Basin of
western Texas and southeastern New Mexico. These interests are in a number
of different fields in the Basin, none of which, individually, accounts for
more than 5% of total reserves. However, these holdings are highly
concentrated in a relatively small geographic area and possess many
operational and geologic similarities. Since 1987, Devon has made four
separate acquisitions of properties in the Permian Basin. With these
acquisitions, Devon gained significant developed and undeveloped leasehold
acreage. The multi-objective nature (several potential producing zones) of
the Permian Basin will continue to provide Devon with exploration and
development opportunities which could further expand its reserves. As of
year-end 1995, the Permian Basin properties other than the Grayburg-Jackson
Field accounted for 28% of Devon's total proved reserves.
1995 Transactions
Worland Acquisition - In December, 1995, Devon completed the
acquisition of a group of oil and natural gas properties and a gas
processing plant located in north-central Wyoming (the "Worland Property").
Combined with the small interest Devon previously owned, this property is
now Devon's third largest, accounting for about 14% of the Company's total
proved reserves.
The properties acquired in 1995 were purchased from a major oil
company for $50.3 million. All of the properties are located on a 25,000-
acre federal unit in Big Horn and Washakie Counties, Wyoming. Of the $50.3
million total purchase price, $46.3 million was allocated to 38 producing
wells, 16 proved undeveloped locations and a natural gas processing plant.
The acquired assets had total estimated proved reserves of 15.3 MMBoe as of
year-end 1995. The remaining $4 million purchase price was allocated to
undeveloped leases on the unit. *Devon expects to invest an additional $9
million in 1996 to further develop the property, including drilling
additional wells and upgrading the gas processing plant.*
In early 1996 Devon increased its interest in the Worland Property
through several smaller acquisitions totaling $7 million. After these
smaller acquisitions, the Company now owns an approximate 98% working
interest in the proved properties and 100% of the gas processing plant and
15,500 acres of undeveloped leases. Because the Worland Field has many
potentially productive producing zones, the acreage will provide the
Company with many exploration and development opportunities which could
increase reserves.
<PAGE>
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, i.e., NEBU and the 32-9
Unit, (the "San Juan Basin Transaction"). *The effect of the transaction
is that the price the Company receives for its coal seam gas production has
increased by $0.61 per Mcf from 1995 through the year 2002. Based on
current estimates of coal seam gas production, the San Juan Basin
Transaction will result in approximately $11 million of additional gas
revenues in 1996 and a total of $71 million over the life of the
transaction (including $12.8 million received in 1995).* See "Item 2.
Properties. Significant Properties - San Juan Basin - San Juan Basin
Transaction" for a more detailed description of this transaction.
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 1996 will be
concentrated in the Permian Basin, Rockies and Gulf Coast regions of the
U.S.
The following tables set forth Devon's drilling results for 1988
through 1995.
<TABLE>
<CAPTION>
Development Wells
Gross (1) Net (2)
Productive Dry Total Productive Dry Total
---------- --- ----- ---------- --- -----
<C> <C> <C> <C> <C> <C> <C>
1988 23 0 23 4.13 0 4.13
1989 32 1 33 7.02 0.01 7.03
1990 80 0 80 19.37 0 19.37
1991 22 1 23 1.62 0.11 1.73
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
--- --- --- ------ ---- ------
563 12 575 271.64 2.21 273.85
(1) A gross well is a well in which Devon owns an interest.
(2) Net wells are the sum of Devon's working interests in gross wells.
</TABLE>
<TABLE>
<CAPTION>
Exploratory Wells
Gross (1) Net (2)
Productive Dry Total Productive Dry Total
---------- --- ----- ---------- --- -----
<C> <C> <C> <C> <C> <C> <C>
1988 0 1 1 0 0.32 0.32
1989 0 1 1 0 0.69 0.69
1990 0 1 1 0 0.20 0.20
1991 0 0 0 0 0 0
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
-- -- -- ---- ---- -----
18 12 30 6.19 5.50 11.69
(1) A gross well is a well 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, 1995, Devon was participating in the drilling of
16 gross (11.29 net) development wells which are not included in the table
above. Through February 28, 1996, 11 gross (10.7 net) of these wells were
completed as productive and the remaining wells were still in progress.
Customers
For the year ended December 31, 1995, two significant purchasers,
Aquila Energy Marketing Corporation ("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. For the year ended December 31, 1993, there was one
significant purchaser, MOTI, which accounted for approximately 39% of
Devon's gas sales. Until September, 1995, MOTI was a significant purchaser
of Devon's NEBU coal seam gas production at a market-sensitive price under
the terms of a five-year contract entered into in May, 1990. Aquila and
Enron purchase gas from numerous Devon properties, including NEBU and the
32-9 Unit. These purchases are primarily made 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 Gas Marketing
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 9% of such natural gas is sold under
short-term contracts. The remaining 91% 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.
Oil Marketing. Devon's oil production is sold under both long- and
short-term agreements at prices in the range of field prices as posted by
certain crude purchasers. Approximately 2% of Devon's 1995 oil production
was purchased by its wholly-owned subsidiary, Devon Marketing Corporation,
which also purchases oil from third parties and resells the purchased oil
under contracts to refiners and others.
Competition
The oil and gas business is highly competitive. Devon encounters
competition by major integrated and independent oil and gas companies in
acquiring properties and drilling prospects, 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 capacity
by purchasing some of the winter load in the summer.
Government Regulation
The oil and gas industry is extensively regulated by federal, state
and local authorities. 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.
<PAGE>
Exploration and Production. Devon's 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
at NEBU, the 32-9 Unit, the Worland Property and many of the Company's
leases in southeast New Mexico, including the Grayburg-Jackson Field, 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 deleterious substances. However, 100% coverage is not maintained
concerning any environmental claim, and no coverage is maintained with
<PAGE>
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 1995 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 the 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.
Employees
As of December 31, 1995, Devon's staff consisted of 203 full-time
employees, including 15 professionals in engineering, 6 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. In addition,
through its affiliate, Blackwood & Nichols Co. A Limited Partnership, Devon
employs 21 people, including 3 operations engineers. The Company also
engages independent consulting petroleum engineers, environmental
professionals, geologists, geophysicists, landmen and attorneys on a fee
basis.
ITEM 2. PROPERTIES
Substantially all of Devon's properties consist of interests in
developed and undeveloped oil and gas leases located in New Mexico,
Wyoming, Texas, Oklahoma and Louisiana. These interests entitle Devon to
drill for and produce oil, natural gas and NGLs from a specific area.
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 present value thereof, discounted at 10% per annum ("10% Present
<PAGE>
Value"), as of December 31, 1995. Approximately 92% of Devon's proved
reserves were estimated by LaRoche & Associates, independent petroleum
engineers ("LaRoche"). The remainder of such reserves were estimated by
Devon's internal staff of engineers. In preparing their estimates, both
LaRoche 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 13 to Devon's consolidated financial statements
included herein, except that federal income taxes otherwise attributable to
such future net revenues have been disregarded in the presentation below.
<TABLE>
<CAPTION>
Total Proved Proved
Proved Developed Undeveloped
Reserves Reserves <F1> Reserves <F2>
<S> <C> <C> <C>
Oil (MBBls) . . . . . . . . . . . . . . 44,466 28,703 15,763
Gas (MMcf) . . . . . . . . . . . . . . 363,846 311,664 52,182
NGLs (MBoe) . . . . . . . . . . . . . . 9,469 6,149 3,320
MBoe <F3> . . . . . . . . . . . . . . . 114,576 86,797 27,779
Pre-tax Future Net Revenue
($ thousands)<F4> 927,812 667,994 259,818
Pre-tax 10% Present Value
($ thousands)<F4> 534,248 411,400 122,848
<PAGE>
<FN>
<F1> Proved developed reserves are proved reserves that are expected to
be recovered from existing wells with existing equipment and
operating methods.
<F2> 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.
<F3> 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 and other factors in addition to
relative energy content.
<F4> 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, 1995. 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
$18.11 per Bbl of oil, $1.35 per Mcf of natural gas ($1.51
per Mcf including the effect of the San Juan Basin
Transaction), and $12.73 per Boe of NGLs. These prices
compare to benchmark prices of $18.00 for West Texas
Intermediate crude oil and $2.10 for Texas Gulf Coast spot
gas.
</FN>
</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, 1995. 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. Devon's total proved reserves for the years
ended December 31, 1988 through 1991 were estimated by
LaRoche. Approximately 88%, 95%, 91% and 92% of Devon's
reserves as of the years ended December 31, 1992, 1993, 1994
and 1995, respectively, were estimated by LaRoche. The balance
of the reserves were estimated by Devon's internal staff of
engineers.
<PAGE>
<TABLE>
<CAPTION>
Total Proved Reserves Proved Developed Reserves
------------------------------------- ------------------------------------
As of December 31, Oil (MBbls) Gas (MMcf) NGLs (MBoe) Oil(MBbls) Gas (MMcf) NGLs(MBoe)
<S> <C> <C> <C> <C> <C> <C>
1988 5,590 98,388 - <F1> 4,203 65,503 - (1)
1989 4,800 149,761 - <F1> 3,688 82,086 - (1)
1990 4,058 169,473 - <F1> 3,456 163,364 - (1)
1991 3,798 191,642 - <F1> 3,179 191,360 - (1)
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
<FN>
<F1> Minor quantities of NGLs are included in oil reserves.
</FN>
</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, 1995, is set
forth in "Item 6. Selected Financial Data."
Well Statistics
As of December 31, 1995, Devon had interests in 4,024
producing wells, of which 2,903 gross (793 net) were oil wells
and 1,121 gross (430 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.
Leasehold
The following table sets forth Devon's developed and
undeveloped oil and gas lease acreage as of December 31, 1995.
<PAGE>
<TABLE>
<CAPTION>
Developed Undeveloped
---------------------- ----------------------
Gross<F1> Net<F2> Gross<F1> Net<F2>
<S> <C> <C> <C> <C>
Arkansas 40 40 0 0
California 0 0 5,098 199
Colorado 1,279 121 8,382 5,725
Kansas 1,665 901 160 7
Louisiana 10,214 4,537 18,059 8,952
Montana 0 0 3,828 1,312
New Mexico 90,293 50,154 56,532 39,400
North Dakota 0 0 2,715 817
Oklahoma 68,789 32,271 24,992 11,176
Texas 145,582 76,274 111,014 70,369
Utah 277 134 680 453
West Virginia 4,991 3,737 609 144
Wyoming 43,437 36,392 33,855 23,530
------- ------- ------- -------
366,567 204,561 265,924 162,084
<FN>
<F1> Gross acres are the total number of acres in which Devon owns a
working interest.
<F2> Net refers to gross acres multiplied by Devon's fractional
working interests therein.
</FN>
</TABLE>
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,
1995.
<PAGE>
<TABLE>
<CAPTION>
10% Present
Value <F3> 10% Present
Oil(MBbls) Gas(MMcf) NGLs(MBoe) MBoe<F1> MBoe%<F2> ($000) Value% <F4>
<S> <C> <C> <C> <C> <C> <C> <C>
San Juan Basin:
Northwest New Mexico
Northeast Blanco Unit 5 119,035 25 19,869 17.3% $ 75,531<F5> 14.2%
32-9 Unit 0 56,741 0 9,457 8.3% 38,667<F6> 7.2%
Other 5 292 0 54 0 216 0
-- ------- -- ------ ----- -------- -----
Total 10 176,068 25 29,380 25.6% $114,414 21.4%
Permian Basin:
West Texas and
Southeast New Mexico
Grayburg-Jackson Field 23,250 7,916 1,853 26,422 23.1% $157,922 29.6%
Other 16,312 75,597 3,018 31,930 27.9% 161,184 30.1%
------ ------ ----- ------ ----- -------- -----
Total 39,562 83,513 4,871 58,352 51.0% $319,106 59.7%
Rocky Mountains:
Colorado and Wyoming
Worland Unit 1,913 62,563 3,707 16,047 14.0% $ 51,559 9.7%
Other 1,348 3,278 362 2,256 2.0% 9,113 1.7%
----- ------ ----- ------ ----- -------- -----
Total 3,261 65,841 4,069 18,303 16.0% $ 60,672 11.4%
Mid-Continent:
Oklahoma and
Texas Panhandle 1,009 30,479 480 6,569 5.7% $ 30,608 5.7%
All Other Properties 624 7,945 24 1,972 1.7% 9,448 1.8%
------ ------- ----- ------- ------ -------- ------
Grand Total 44,466 363,846 9,469 114,576 100.0% $534,248 100.0%
<FN>
<F1> 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.
<F2> Percentage which MBoe for the basin or region bears to total MBoe for
all Proved Reserves.
<F3> Determined in accordance with SEC guidelines, except that no effect
is given to future income taxes.
<F4> Percentage which present value for the basin or region bears to total
present value for all Proved Reserves.
<F5> Includes $28.1 million of additional value attributable to San Juan
Basin Transaction through the year 2002.
<F6> Includes $16.3 million of additional value attributable to San Juan
Basin Transaction through the year 2002.
</FN>
</TABLE>
<PAGE>
San Juan Basin. Devon's single largest 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 114.6 Bcf,
of Devon's proved reserves attributable to NEBU are associated
with the Fruitland coal seam formation. The potential for coal
seam gas production 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 through a Devon affiliate,
Blackwood & Nichols Co. A Limited Partnership. 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.
By late 1990, the first NEBU coal seam wells were
connected to pipelines and began producing. Additional wells
were connected each year until project completion in late
1993. Production increased each year through 1994. The
following table shows Devon's net production from NEBU:
Year Gas Production
---- --------------
1990 1.0 Bcf
1991 8.7 Bcf
1992 17.5 Bcf
1993 18.2 Bcf
1994 18.7 Bcf
1995 16.2 Bcf
--------
Total 80.3 Bcf
<PAGE>
As the table above illustrates, NEBU production declined
slightly, as expected, in 1995. About 1.2 Bcf of the reduction
is due to the San Juan Basin Transaction described below. The
remainder of the reduced production is due to natural decline.
*It is likely that production will decrease to 13 to 15 Bcf in
1996 and continue a modest decline thereafter unless
additional development or new technology is applied to the
property.*
The current reserve estimates at NEBU assume that 55% to
65% of the coal seam gas in place can be economically
recovered through the existing wells. *Additional production
and recoverable reserves might be realized by continued
reduction in operating pressure through compression and
pipeline optimization, by use of subsurface pumping equipment
to remove water, by drilling additional wells, or by using
enhanced recovery techniques, such as injecting carbon dioxide
or nitrogen into the coal formation, to force additional gas
to the producing well bores.* Devon and other owners in the
San Juan Basin are studying and experimenting with these
various options to determine if additional recoveries are
economically feasible. *If such development projects were to
be undertaken by Devon, it would likely result in significant
additional capital expenditures and gas reserves.* (As part
of the San Juan Basin Transaction, Devon will be entitled to
75% of any reserves in excess of those estimated to be in
place at the time of the transaction. The third party will
pay 100% of the capital necessary to develop any such
incremental reserves for its 25% interest in such reserves.
See " - San Juan Basin Transaction" below.)
32-9 Unit. The 32-9 Unit, operated by Meridian Oil
Production, Inc., 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, 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, if the State of
New Mexico allows drilling on 160-acre spacing rather than the
existing 320-acre spacing.* This unit is also being evaluated
for possible improved recovery projects similar to those being
studied at NEBU.
Although now largely complete, development of the 32-9
Unit began later and has proceeded more slowly than the
development of NEBU. Production from the 32-9 Unit did not
commence until March of 1992. Consequently, Devon believes the
32-9 Unit has not yet reached its peak production rate.
<PAGE>
Devon also owns an interest in five wells on leases
located immediately adjacent to the 32-9 Unit. These wells
will not be committed to the 32-9 Unit. Unless otherwise
indicated, all references herein to the 32-9 Unit include both
the 33 wells expected to be included in the Unit and the five
wells outside the Unit. Devon does not own any interest or
reserves in the deeper, conventional sandstone reservoirs at
the 32-9 Unit.
San Juan Basin Gas Price. The sales price for Devon's
San Juan Basin coal seam gas production is a combination of
the net wellhead price, plus additional revenue attributable
to the San Juan Basin Transaction. The average net wellhead
price for San Juan Basin coal seam production sold during 1995
(before the benefit of the San Juan Basin Transaction) was
$0.71 per Mcf. This net realization is relatively low compared
to conventional gas produced in other areas of the U.S. This
occurred for two reasons:
First, during most of 1995, demand for natural gas in
California (the primary market for San Juan Basin gas) was
weak, causing San Juan Basin gas to sell at a larger discount
than gas that could be delivered to higher demand areas of the
U.S. *Devon believes that this supply/demand imbalance will
persist throughout 1996, but should dissipate in future
years.*
Second, the price for coal seam gas production was less
than that for Devon's conventional gas in the San Juan Basin
because (i) a relatively large portion (about 10%) of the
produced gas is carbon dioxide which is removed, (ii) a fee
must be paid to remove carbon dioxide and transport the gas
from the field to transmission lines that carry the gas to
market and (iii) a portion of the produced gas is used to fuel
compressors and other field equipment. This is a permanent
circumstance that will always affect the price of coal seam
gas production from the San Juan Basin.
Offsetting the deductions from the wellhead price is an
additional $0.61 per Mcf from the San Juan Basin Transaction.
This increase, added to the net wellhead price of $0.71 per
Mcf, resulted in a San Juan Basin coalseam gas price of $1.32
per Mcf in 1995. See " - San Juan Basin Transaction" below.
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 $0.61
per Mcf higher than the price the Company would otherwise
receive from 1995 through the year 2002.*
The transaction is based on the fact that Devon's coal
seam gas production qualifies as a "nonconventional fuel
source" under Internal Revenue Service regulations.
Consequently, gas produced from these properties through the
year 2002 is eligible for the Section 29 Credit, which was
equal to $1.01 per million Btu ("MMBtu") as of December 31,
<PAGE>
1995. The transaction consists of four major elements.
First, Devon conveyed about 179 Bcf, or 90%, of its year-end
1994 coal seam gas reserves to the unrelated party. However,
for financial reporting purposes Devon retained all of these
reserves and their future production and cash flow through a
volumetric production payment and 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. (However, Devon has an option to reacquire
these reserves at their fair market value at the time the
option is exercised.) Third, the unrelated party pays Devon
an amount equal to 75% of the value of the Section 29 tax
credits generated by the properties. Fourth, Devon retained a
75% reversionary interest in any reserves in excess of the
186.2 Bcf estimated to exist as of the date of the
transaction. The transaction is described in more detail in
note 3 to Devon's consolidated financial statements included
elsewhere herein.
Permian Basin Properties. The Permian Basin covers
approximately 66,000 square miles of western Texas and
southeastern New Mexico. The area has more than 500 major
fields which are grouped under the general designation of
Permian Basin. Permian Basin acreage is largely "held by
production" from existing wells, meaning that new leasehold
positions are not readily attainable. Since 1987, Devon has
made four separate acquisitions of properties in the Permian
Basin. These acquisitions, especially the July, 1992
acquisition of certain Permian Basin properties, enabled Devon
to obtain prospective acreage in areas in which leasehold
positions could not otherwise be purchased. *The
multi-objective nature (several potential producing zones) of
the Permian Basin and Devon's large leasehold position there
will continue to provide Devon with exploration and
development opportunities. Enhanced oil recovery projects are
also possible which could further expand Devon's reserves.*
Grayburg-Jackson Field. This field, which was acquired
in the Alta Merger in May, 1994, is located in Eddy County, in
the far southeastern New Mexico portion of the Permian Basin.
It is the Company's single largest property in the Permian
Basin, accounting for 23% of total oil and gas reserves. Its
location within 35 miles of 26 other Devon properties makes it
an ideal strategic fit for the Company's Permian Basin
holdings.
Production from this field currently comes from the
Grayburg-San Andres-Premier zones over a 400-foot interval to
depths up to 4,000 feet. Although some of the oldest wells in
the Field date back to the 1940's and 1950's, most of the
currently producing wells were drilled in the early 1970's.
Additional drilling over the years by previous owners left the
field developed to an average of 40-acre spacing per well when
Devon acquired it. However, similar properties in the
immediate vicinity have been drilled on 20-acre spacing and
successfully waterflooded. Based upon this information, in
1994 Devon initiated a $60 million capital development project
<PAGE>
which includes drilling about 150 wells over a two- to three-
year period, converting producing wells to water injection
wells and instituting a waterflood. As of year-end 1995, the
project was about 50% completed.
From May through year-end 1994, the first seven months
Devon owned the field, production from the Grayburg-Jackson
Field was 234 MBoe. This was approximately 3% of Devon's total
1994 production. For 1995, production increased to 920 MBoe
as additional drilling was completed and Devon owned the field
for the full year. *For 1996 production is expected to again
increase as development continues.* Currently about 50% of
the Grayburg-Jackson Field reserves are classified as "proved
developed." The remaining reserves are considered "proved
undeveloped."
Worland Property. In December, 1995 Devon completed the
acquisition of properties from a major oil company for
approximately $50.3 million. All of the properties are
located on a 25,000-acre federal unit in Big Horn and Washakie
Counties, Wyoming. Of the $50.3 million purchase price, $46.3
million was allocated to 38 producing wells, 16 proved
undeveloped locations and a natural gas processing plant.
These acquired assets, combined with the small interest Devon
previously owned, had total estimated proved reserves of 16.0
MMBoe as of year-end 1995. The remaining $4 million purchase
price was allocated to undeveloped leasehold on the unit,
which constitutes about 60%, or 15,500 acres, of the total
acreage acquired.
*In 1996 Devon expects to invest an additional $9 million
to begin the exploitation of this property. Projects
scheduled for 1996 include drilling development wells,
optimization of the existing gas processing plant and
gathering system, additional stimulation of existing wells and
drilling wells to extend the productive limits of this
property.*
In early 1996 Devon increased its working interest in the
proved property to 98% through several smaller acquisitions
totaling $7 million. These acquisitions also increased the
Company's interest in the gas processing plant and undeveloped
leases to 100%.
The property consists of three separate fields located
along a major geologic structure. It is the single largest
gas producing feature in the Bighorn Basin. Seven separate
horizons produce on the structure: the First, Second, Third
and Fourth Frontier sandstones, the Muddy sandstone, the
Phosphoria dolomite and the Tensleep sandstone, ranging in
depths from 7,450 to 10,500 feet. The first production from
this property was from the Phosphoria oil reservoir in the
1940s. Shallow gas production was established in the 1960s.
The Tensleep, immediately below the Phosphoria zone, was
developed in the 1970s. The original owner dedicated all gas
production from the property, which they believed to be only a
minor by-product of the oil production, under a long-term
contract for $0.30 or less per Mcf. Because of this contract,
<PAGE>
full development of the gas reservoirs was not economically
feasible until the price was renegotiated by the original
owner in 1988.
Devon believes the major potential of this property is
from the application of modern technology. Three-D seismic
and new well completion techniques such as massive acid-
fracturing, are proving successful in other parts of the
Bighorn Basin and throughout the Rocky Mountain region, and
may enhance reserves and recoveries at the Worland Property as
well. In addition, both the Tensleep and Phosphoria are
possible candidate zones for horizontal drilling technology.
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 1,372 of its 4,024 wells. As
operator, Devon receives reimbursement of 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.
Title to Properties
Title to properties is subject to (i) royalty, overriding
royalty, carried, net profits, working and other similar
interests, (ii) contractual arrangements customary in the oil
and gas industry, (iii) liens for current taxes not yet due
and (iv) 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
No matters were submitted to a vote of the Company's
security holders during the fourth quarter of the year ended
December 31, 1995.
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.
Average
Daily
High Low Volume
1994:
Quarter Ended March 31, 1994 22-7/8 17-1/2 55,131
Quarter Ended June 30, 1994 26-1/2 17-1/4 37,547
Quarter Ended September 30, 1994 23-1/4 19-3/4 26,344
Quarter Ended December 31, 1994 22-1/4 16 34,110
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 21-1/4 45,322
(through February 28, 1996)
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. *Devon anticipates continuing to pay regular quarterly dividends in
the foreseeable future.*
On February 27, 1996, there were approximately 1,200 Devon Common
Stock shareholders of record.
<PAGE>
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,
1995 1994 1993 1992 1991
(Thousands, Except Per Share Data)
OPERATING RESULTS
<S> <C> <C> <C> <C> <C>
Oil sales $ 55,290 38,086 38,395 27,329 9,436
Gas sales 50,732 56,372 54,876 39,973 19,091
NGL sales 6,404 4,908 4,544 1,370 --
Other revenue 877 1,407 942 2,892 1,815
Total revenues $113,303 100,773 98,757 71,564 30,342
Lease operating expenses $ 27,289 24,521 26,401 18,430 8,689
Gross production taxes $ 6,832 6,899 6,924 4,600 1,912
Depreciation, depletion and amortization $ 38,090 34,132 28,409 19,894 7,844
General and administrative expenses $ 8,419 8,425 7,640 6,510 5,832
Interest expense $ 7,051 5,439 3,422 2,644 2,209
Reduction of carrying value of oil and
gas properties $ -- -- -- -- 25,000
<F1>
Net earnings (loss) $ 14,502 13,745 20,486 1 14,615 (15,024)
Net earnings (loss) per share:
<F1>
Assuming no dilution $ 0.66 0.64 0.98 1 0.94 (1.99)
<F1>
Assuming full dilution $ 0.66 0.64 0.98 1 0.90 (1.99)
Cash dividends:
Per preferred share $ -- -- -- 1.46 1.94
Per common share $ 0.12 0.12 0.09 -- --
Weighted average common shares
outstanding 22,074 21,552 20,822 13,802 8,687
BALANCE SHEET DATA
Total assets $421,564 351,448 285,553 225,972 102,107
Long-term debt $143,000 98,000 80,000 54,450 32,000
Stockholders' equity $219,041 206,406 172,900 153,267 53,015
PRODUCTION/PRICE DATA
Production:
Oil (MBbls) 3,300 2,467 2,337 1,446 484
Gas (MMcf) 36,886 39,335 35,598 28,374 15,398
NGLs (MBoe) 600 501 411 112 --
<F2>
MBoe 2 10,047 9,524 8,681 6,287 3,050
Average prices:
Oil (Per Bbl) $ 16.75 15.44 16.43 18.89 19.49
Gas (Per Mcf) $ 1.38 1.43 1.54 1.41 1.24
NGLs (Per Boe) $ 10.68 9.79 11.06 12.28 --
<F2>
Per Boe 2 $ 11.19 10.43 11.27 10.92 9.35
<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 Gas and NGLs are converted to Boe or MBoe at the rate of six Mcf of gas
per barrel of oil and 42 gallons of NGLs per barrel of oil, based upon
the approximate relative energy content of natural gas, oil and NGLs,
which rate is not necessarily indicative of the relationship of oil, gas
and NGL 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 1993 through 1995. Reference is made
to "Item 6. Selected Financial Data" and "Item 8. Financial
Statements and Supplementary Data."
Overview
Many of the major trends for Devon have been positive in
recent history. During the last three years:
the company's major assets, oil and gas reserves, have
grown 87% to 115 million barrels of oil equivalent
("MMBoe"),
annual oil and gas production has risen 60% (from that
of 1992) to 10 MMBoe,
total revenues for 1995 were 58% higher than those of
1992, and
cash margins (total revenues less cash expenses) have
expanded to the $50 million to $60 million range.
However, non-cash expenses, such as higher depreciation,
depletion and amortization and volatile oil and gas prices,
have produced more variable results in net earnings. Net
earnings were down in 1994 compared to 1993, but up in 1995.
Even so, the net earnings of $14.5 million (1995), $13.7
million (1994), $19.2 million (1993) and $14.6 million (1992)
were all substantially above the previous best year in Devon's
history of $4.4 million in 1981.
Devon's liquidity and financial condition also have been
strong during the last three years compared to historical
levels. After the February 1996 annual review by its banks,
Devon's credit lines have increased 117% since 1992 to $260
million. Of this, $110 million was unused as of the end of
February 1996. Net cash provided by operating activities has
been $61.3 million, $46.4 million and $64.0 million the last
three years, compared to an average of $14 million for the
years 1988 through 1992.
Devon has taken several actions in recent years to achieve
its growth in operations and financial condition:
Devon acquired a substantial suite of properties
primarily located in the Permian Basin in July, 1992.
This $130 million acquisition caused significant
improvement in both oil and gas production and in
revenues from the second half of 1992 onward.
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 and production in the San Juan Basin. <PAGE>
Devon acquired the properties of Alta Energy
Corporation through a $72 million merger in May, 1994.
The oil and gas properties acquired through the merger
(the "Merger Properties") have added substantial oil
and gas reserves, production and revenues to Devon's
Permian Basin position.
Devon acquired certain Wyoming oil and natural gas
properties and a gas processing plant (the "Worland
Properties") for approximately $50 million in December,
1995.
In 1995, Devon entered into a transaction covering
substantially all of its San Juan Basin coal seam gas
properties (the "San Juan Basin Transaction"). In
1995, this transaction boosted Devon's revenues by
$11.4 million. This transaction also added $44 million
to Devon's pre-tax discounted present value of year-end
oil and gas reserves.
Devon has been successful during the last three years
in its drilling efforts. Devon has spent almost $125
million to drill 384 wells, of which 368 were completed
as producers. Most of these efforts have been centered
around the 1992 Permian Basin acquisition and the 1994
Merger. These properties, along with the Worland
Properties, are expected to account for some 60% of
Devon's 1996 drilling and development budget of $70
million to $80 million.
Devon's acquisition and drilling efforts during the
last three years have added 74.5 MMBoe of proved
reserves to its asset base. Combined with 13.7 MMBoe
of upward revisions to its reserve estimates, Devon's
total reserve additions of 88.2 MMBoe during the past
three years were 312% of its production of 28.3 MMBoe.
Devon has sought to control its well operating expenses
in part by selling marginal and non-strategic
properties. Though the absolute dollar amount of well
operating expenses increased by almost 50% since 1992
as Devon expanded its production and operations,
Devon's sales of approximately 2,900 wells during the
period helped to lower the expenses per unit of
production by 7%. The combination of expanding its
significant properties and selling the minor ones has
increased Devon's economies of scale and overall
efficiency.
Devon's reserve additions over the past three years
have also increased capital resources via increases in
Devon's lines of credit. Since the end of 1992, and
including the banks' annual review completed in
February, 1996, Devon's credit lines have increased by
$140 million to a total of $260 million. Though total
debt has increased, the unused portion of Devon's
credit lines has increased some $50 million.
Results of Operations
Changes in oil, gas and NGL production, prices and revenues
from 1993 to 1995 are shown in the table below.
<TABLE>
<CAPTION>
Ended December 31,
1995 1994
1995 vs 1994 1994 vs 1993 1993
Production
<S> <C> <C> <C> <C> <C>
Oil (MBbls) . . . . . . . . . . . . 3,300 +34% 2,467 +6% 2,337
Gas (MMcf) . . . . . . . . . . . . 36,886 -6% 39,335 +10% 35,598
NGLs (MBoe) . . . . . . . . . . . . 600 +20% 501 +22% 411
Oil, Gas and NGLs (MBoe) . . . . . . . 10,047 +5% 9,524 +10% 8,681
Revenues
Per Unit of Production:
Oil (per Bbl) . . . . . . . . . . . .$ 16.75 +8% 15.44 -6% 16.43
Gas (per Mcf) . . . . . . . . . . . .$ 1.38 -3% 1.43 -7% 1.54
NGLs (per Boe) . . . . . . . . . . .$ 10.68 +9% 9.79 -11% 11.06
Oil, Gas and NGLs (per Boe) . . . . .$ 11.19 +7% 10.43 -7% 11.27
Absolute
(Thousands)
Oil . . . . . . . . . . . . . . . . $ 55,290 +45% 38,086 -1% 38,395
Gas . . . . . . . . . . . . . . . . $ 50,732 -10% 56,372 +3% 54,876
NGLs . . . . . . . . . . . . . . . $ 6,404 +30% 4,908 +8% 4,544
Oil, Gas and NGLs . . . . . . . . . $112,426 +13% 99,366 +2% 97,815
</TABLE>
Oil Revenues 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 Merger Properties produced 843,000 barrels in 1995, a 239%
increase from the 249,000 barrels which were produced during Devon's
ownership for the last seven months of 1994. Production from Devon's other
oil properties increased 11% in 1995, from 2,218,000 barrels in 1994 to
2,457,000 barrels in 1995.
1994 vs. 1993 Oil revenues were essentially unchanged from 1993 to
1994. A 130,000 barrel boost in production added $2.1 million to oil
revenues. Unfortunately, a decrease in oil prices subtracted $2.4 million.
The Merger Properties added 249,000 barrels of additional production
during the last seven months of 1994, while Devon's other properties
accounted for a net decrease of approximately 119,000 barrels in 1994 due
to the effect of property sales in 1993. Devon sold various minor,
marginally profitable or non-strategic properties throughout 1993. These
properties produced approximately 173,000 barrels of oil in 1993.
Gas Revenues 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 Merger Properties 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 areas where
conventional production declined in 1995 were the Ozona field and NEBU.
High pipeline pressure and down time for repairs contributed to a 0.6 Bcf
reduction in Ozona production in 1995. Although Devon does not have a
significant interest in conventional gas production in NEBU, it has been
receiving more than its normal share of production through gas balancing
and also received nonrecurring payments for inventory gas in 1994. In
1995, the amounts of imbalance makeup and inventory sales declined, thus
leading to a 0.5 Bcf reduction in conventional NEBU production compared to
1994. Also, various marginal wells sold during 1994 and 1995 accounted for
a 0.6 Bcf reduction in conventional production in 1995.
1994 vs. 1993 Gas revenues increased $1.5 million, or 3%, in 1994,
as a 7% drop in prices dampened the effect of a 10% increase in production.
Gas production increases boosted gas revenues by $5.8 million. Lower gas
prices reduced gas revenues by $4.3 million.
Approximately 2.2 Bcf of the production increase was attributable to
coal seam gas production from NEBU and the 32-9 Unit Properties. NEBU
production increased from 18.2 Bcf in 1993 to 18.7 Bcf in 1994. Production
from the 32-9 Unit Properties increased from 1.6 Bcf in 1993 to 3.3 Bcf in
1994 due to the fact that such properties were acquired by Devon in the
middle of 1993, and therefore contributed only six months of production to
Devon's 1993 totals.
Total coal seam gas production and revenues for 1994 were 21.9 Bcf
and $25.7 million, respectively, versus 19.8 Bcf and $27.7 million for
1993. Prices for coal seam gas averaged $1.17 for 1994 versus $1.40 in
1993. The price per Mcf for coal seam gas is less than Devon's
conventional gas (i.e., gas produced from other than coal formations)
primarily due to the former's low Btu content and the costs of
transportation and removing carbon dioxide. These adjustments have been
taken into account in calculating the coal seam sales prices referred to in
this discussion. Beginning in 1995, as discussed above, the San Juan Basin
Transaction increased the coal seam price to a level much closer to Devon's
conventional gas prices.
Total conventional gas production and revenues for 1994 were 17.4 Bcf
and $30.7 million, respectively, versus 15.8 Bcf and $29.2 million in 1993.
Prices for conventional gas averaged $1.76 per Mcf compared to $1.84 per
Mcf in 1993.
Approximately 0.6 Bcf of conventional gas production was added during
1994 from the Merger Properties. Also, approximately 1.5 Bcf of additional
1994 production was contributed by the Ozona field and related properties
in the Permian Basin. The Ozona properties were part of the Permian Basin
Properties acquired in July 1992. However, prior to September 1993,
substantially all of the gas produced from such properties was used to
satisfy a recoupment obligation created by the prior owner of the
properties. Therefore, Devon only began recognizing production and gas
revenues from these properties in September 1993. More importantly,
production from the Ozona properties more than doubled due to Devon's
drilling efforts in this field.
Approximately 0.9 Bcf of gas was produced in 1993 from properties
which were sold during 1993. Therefore, these properties contributed no
production in 1994. Also, gas production declined 0.2 Bcf in 1994 due to
properties which were sold in 1994 and therefore did not produce for a full
year as they did in 1993.
NGL Revenues 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 Merger Properties accounted for 52,000 Boe of the increased
production. Such properties produced 84,000 Boe in 1995, compared to
32,000 Boe during the seven months Devon owned the properties in 1994.
1994 vs. 1993 A 90,000 Boe increase in NGL production raised
revenues by $1.0 million. A decrease in prices subtracted $0.6 million.
Approximately 32,000 Boe of production was added during 1994 from the
Merger Properties. The remaining increase was primarily attributable to
Devon's drilling efforts in 1993 and 1994.
Expenses The details of the changes in pre-tax expenses between 1993
and 1995 are shown in the table below.
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1994
1995 vs 1994 1994 vs 1993 1993
(Absolute Amounts in Thousands)
<F1>
Absolute(1):
Production and operating expenses:
<S> <C> <C> <C> <C> <C>
Lease operating expenses . . . . . . $27,289 +11% 24,521 -7% 26,401
Production taxes . . . . . . . . . . 6,832 -1% 6,899 - 6,924
Depreciation, depletion and amortization
attributable to:
Oil and gas production . . . . . . . 36,640 +11% 32,861 +20% 27,420
Non-oil and gas properties . . . . . 1,450 +14% 1,271 +29% 989
General and administrative expenses . . 8,419 - 8,425 +10% 7,640
Interest expense . . . . . . . . . . . 7,051 +30% 5,439 +59% 3,422
Total . . . . . . . . . . . . $87,681 +10% 79,416 +9% 72,796
<F1>
Per Boe(1):
Production and operations expenses:
Lease operating expenses . . . . . . $ 2.72 +6% 2.57 -15% 3.04
Production taxes . . . . . . . . . . 0.68 -7% 0.73 -9% 0.80
Depreciation, depletion and amortization
attributable to:
Oil and gas production . . . . . . . 3.65 +6% 3.45 +9% 3.16
Non-oil and gas properties . . . . . 0.14 +8% 0.13 +18% 0.11
General and administrative expenses . . 0.84 -6% 0.89 +1% 0.88
Interest expense . . . . . . . . . . . 0.70 +23% 0.57 +43% 0.40
Total . . . . . . . . . . . . $ 8.73 +5% 8.34 -1% 8.39
<F1>
(1) Though per unit general and administrative expenses, interest
expense and non-oil and gas property depreciation 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 1993 and 1995 are shown in the
table below.
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1994
1995 vs 1994 1994 vs 1993 1993
(Absolute Amounts in Thousands)
Absolute:
<S> <C> <C> <C> <C> <C>
Recurring lease operating expenses . . $23,842 +10% 21,583 -3% 22,317
Well workover expenses . . . . . . . . 3,447 +17% 2,938 -28% 4,084
Production taxes . . . . . . . . . . . 6,832 -1% 6,899 - 6,924
Total production and operating
expenses $34,121 +9% 31,420 -6% 33,325
Per Boe:
Recurring lease operating expenses . . $ 2.37 +4% 2.27 -12% 2.57
Well workover expenses . . . . . . . . 0.35 +17% 0.30 -36% 0.47
Production taxes . . . . . . . . . . . 0.68 -7% 0.73 -9% 0.80
Total production and operating
expenses $ 3.40 +3% 3.30 -14% 3.84
</TABLE>
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 Merger Properties, whose costs 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 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.
1994 vs. 1993 Recurring lease operating expenses dropped by $0.7
million, or 3%, in 1994. The positive effect from the sale of over 2,000
wells in 1993 was partially offset by additional expenses related to the
Merger Properties. The Merger Properties are primarily oil producing
properties, which are traditionally more expensive to operate than gas
producing properties. For the year 1994, the Merger Properties incurred
$1.9 million of recurring lease operating expenses, or $4.96 per Boe,
compared to $19.7 million of such costs, or $2.15 per Boe, incurred on
Devon's other properties.
Workover expenses dropped by $1.1 million, or 28%, in 1994. Most of the
reduction occurred in certain Permian Basin properties acquired in 1992. A
substantial number of workover projects were completed on such properties
in 1993 as Devon became more familiar with these properties following the
acquisition. The need for workovers on these properties declined in 1994.
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.
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 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.
1994 vs. 1993 Oil and gas property related DD&A increased $5.4 million,
or 20%, in 1994. Approximately 50% of this increase was related to the
increase in combined oil, gas and NGL production in 1994. The other half
of the increased expense was due to an increase in the DD&A rate from $3.16
per Boe in 1993 to $3.45 per Boe in 1994. The addition of the Merger
Properties in 1994 was the primary cause for the increased DD&A rate. The
DD&A rate for the seven months following the addition of the Merger
Properties was $3.60 per Boe.
General and Administrative Expenses ("G&A") 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.
1994 vs. 1993 G&A increased approximately $0.8 million, or 10%, in
1994. Employee salaries and related overhead burdens such as health
insurance, payroll taxes and pension expenses rose by $1.4 million, or 16%.
These increases were partially offset by a $0.3 million reduction in
abandoned acquisition costs and a $0.3 million increase in overhead
reimbursements received from joint interest owners in Devon-operated
properties.
Interest Expense 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
(including the effect of various fees paid to the banks and the
amortization of certain loan costs) 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.
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 principal amount of the swap agreement is $75 million, and the
other party to the agreement is one of the lenders of Devon's credit lines
(the "Lender"). The agreement terminates on June 16, 1998, unless the
Lender exercises its right to extend the termination date to June 16, 2000.
The terms of the agreement provide for quarterly payments either to or from
Devon, determined by whether the three month London Interbank Offered Rate
("LIBOR") in effect at the beginning of each quarterly calculation period
is greater or less than 5.6%. The calculation periods begin on the
sixteenth day of each March, June, September and December during the term
of the agreement. If, on the date of the beginning of the quarterly
calculation period, the three month LIBOR exceeds 5.6%, the Lender will owe
Devon the quarterly amount of the excess rate applied to the $75 million
principal. Alternately, if the three month LIBOR on the applicable
quarterly date is less than 5.6%, Devon will owe the Lender.
The swap agreement is accounted for as a hedge, with the amount which is
either due to or from Devon recorded as a reduction or increase in interest
expense. The three month LIBOR exceeded 5.6% at the beginning of each of
the three quarterly calculation periods in 1995. Therefore, Devon
recognized $0.1 million as a reduction to interest expense in 1995.
The swap agreement does not alter or affect any terms or conditions of
Devon's credit lines.
1994 vs. 1993 Interest expense increased $2.0 million, or 59%, in 1994.
The average long-term debt balance outstanding rose from $66.6 million
during 1993 to $92.5 million during 1994. The borrowings used to fund a
portion of the cash used in the Merger, along with the effect of borrowing
$50.0 million at mid-year 1993 to acquire the 32-9 Unit Properties,
accounted for the increased average debt during 1994. The interest rate on
the debt outstanding increased from 4.2% in 1993 to 5.2% in 1994. The
overall interest rate rose from 5.1% in 1993 to 5.9% in 1994.
Income Taxes 1995 vs 1994 Devon's effective financial tax rate in
1995 was 43%, compared to the statutory federal rate of 35%. State income
taxes and certain tax aspects of the San Juan Basin Transaction were the
primary factors which increased Devon's financial tax rate. The San Juan
Basin Transaction also had a significant effect on the portion of income
taxes which are current versus deferred.
1994 vs. 1993 Devon's effective financial tax rate in 1994 was 36%
compared to the statutory federal rate of 35%. The effective financial
rate rose above the federal statutory rate primarily due to the effect of
state income taxes.
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 $117.6 million of cash was spent in
1995 for capital expenditures, of which $114.9 million was related to the
acquisition, drilling or development of oil and gas properties. Included
in this total is $50.4 million spent in December to acquire the Worland
Properties, including $0.1 million of third party costs which were
capitalized as part of the transaction. Most of the drilling and
development efforts in 1995 centered in the Permian Basin, which included
183 of the 199 wells which Devon drilled during 1995. Included in the
Permian Basin activity was approximately $30.1 million spent in the
Grayburg-Jackson Field acquired in the May 1994 Merger. Devon completed 88
infill wells in the Grayburg-Jackson Field, and an additional 9 such wells
were in various stages of drilling or completion as of year-end 1995.
Devon also began the initial stages of a waterflood program on this field.
*Drilling of an additional 40 infill wells is expected to commence in 1996,
along with the completion of the waterflood program.*
Other Cash Uses A $0.03 per common share dividend has been paid in each
quarter since Devon paid its initial common stock dividend in the second
quarter of 1993. This quarterly rate translates to a cash demand of $2.7
million annually. *Management expects the policy of paying a quarterly
dividend to continue.*
Capital Resources and Liquidity Net cash provided by operating
activities ("operating cash flow") was the primary source of capital and
short-term liquidity in 1995. Operating cash flow in 1995 totaled $61.3
million, a 32% increase compared to the $46.4 million of operating cash
flow generated in 1994.
In addition to operating cash flow, Devon's credit lines have been an
important source of capital and liquidity. At year-end 1995, these credit
lines totaled $205 million. Devon's December 31, 1995 borrowings from
these credit lines were $143 million, leaving $62 million of credit
available for future use. In 1996, the banks revised the credit line
upward from $205 million to $260 million. (See Note 7 to the consolidated
financial statements included elsewhere in this report for a detailed
discussion of the credit lines.)
Devon's San Juan Basin coal seam gas production is subject to
uncertainties regarding additional royalties and taxes. If such
uncertainties are resolved in 1996, they 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 11 to the consolidated
financial statements contained elsewhere in this report.
1996 Estimates
The forward-looking statements provided in this discussion are based on
management's examination of historical operating trends, the December 31,
1995 reserve report of LaRoche, data in Devon's files and other data
available from third parties. The forward-looking statements were prepared
assuming demand, curtailment, producibility and general market conditions
for Devon's oil, natural gas and NGLs for 1996 will be substantially
similar to those of 1995, unless otherwise noted. Devon cautions that its
future oil and gas production 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 and the uncertainty inherent in
estimating future oil and gas production or reserves.
Given the limitations expressed in the above paragraph, Devon's forward-
looking statements for 1996 are set forth below.
Oil Revenues Devon expects its oil production in 1996 to total between
3.7 million barrels and 4.3 million barrels. Devon expects its net oil
prices will average from between $0.10 below to $0.10 above West Texas
Intermediate posted prices in 1996.
Gas Revenues Devon expects its total gas production in 1996 will be
between 34.6 and 40.3 Bcf. It is expected that coal seam gas production
will be 17.1 Bcf to 19.9 Bcf in 1996. Devon expects production from its
conventional gas properties to total between 17.5 Bcf and 20.4 Bcf in 1996.
Included in the 1996 conventional gas production estimates are 3.1 Bcf to
3.6 Bcf of estimated production from the Worland Properties which were
acquired in mid-December 1995.
The incremental $0.61 per Mcf added to coal seam gas prices by the San
Juan Basin Transaction should offset a substantial portion of the negative
price effect from the low BTU content and the transportation and carbon
dioxide removal costs previously discussed. Therefore, Devon expects its
1996 coal seam average price will be between $0.15 and $0.65 less than
Texas Gulf Coast spot averages. Devon's conventional gas is expected to
average $0.15 to $0.25 per Mcf less than Texas Gulf Coast spot prices
during 1996. This conventional gas price differential is larger than in
the last two years due to the inclusion of the Worland Properties in 1996.
Gas production sold from the Worland Properties is expected to average
$0.55 to $0.65 per Mcf less than Texas Gulf Coast spot prices during 1996.
From December of 1995 through February of 1996, the prices for Texas
Gulf Coast and "Henry Hub" gas have been radically higher than those for
virtually all other major basins in the U.S. Therefore, the basin
differentials quoted above should be regarded as particularly volatile.
The differentials quoted above are based more on historical levels than
those of the last three or four months.
NGL Revenues Devon expects its production of NGLs in 1996 to total
between 800,000 Boe and 950,000 Boe. Included in these estimates are
240,000 Boe to 280,000 Boe estimated to be produced in 1996 from the
Worland Properties.
Production and Operating Expenses The addition of the Worland
Properties and the higher number of wells producing at the Grayburg-Jackson
Field should be the primary contributors to an expected increase in
recurring lease operating expenses in 1996, and the resulting higher
revenues should cause gross production taxes to also rise. Also, well
workover expenses are anticipated to increase in 1996. Future oil, gas and
NGL prices have a direct effect on gross production taxes to be incurred in
1996. Future prices could also have an effect on whether proposed workover
projects are economically feasible. These factors contribute to the margin
of error inherent in estimating future production and operating costs.
Given these uncertainties, Devon estimates that 1996's total production and
operating costs will be between $39 million and $45 million, or between
$3.50 per Boe and $4.00 per Boe.
Depreciation, Depletion and Amortization The 1996 DD&A rate will depend
on numerous factors which cannot be reasonably predicted at this time.
Most notable among such factors are the amount of proved reserves which
will be added from drilling efforts in 1996 compared to the costs incurred
for such efforts, and the revisions to Devon's year-end 1995 reserve
estimates which will be made during 1996. Assuming a 1996 rate constant
with 1995's rate of $3.65 per Boe, and the estimated range from a 3%
increase to a 19% increase in total oil, gas and NGL production discussed
earlier in this section, 1996 DD&A expense (including non-oil and gas
property related DD&A) is expected to increase to approximately $39 million
to $45 million.
General and Administrative Expenses G&A is expected to be between $8.8
million and $9.4 million in 1996.
Interest Expense Future oil, gas and NGL prices and interest rates have
a significant effect on Devon's interest expense. The interest rate swap
entered into in 1995 removes the uncertainty of future interest rates from
a portion, but not all of, Devon's long-term debt. Also, Devon can only
marginally influence the prices it will receive in 1996 from sales of oil,
gas and NGL. These factors increase the margin of error inherent in
estimating future interest expense. Other factors which affect interest
expense, such as the amount and timing of capital expenditures, are within
Devon's control. Given the uncertainty of future prices and interest rates
and their ultimate effect, Devon estimates that it will incur between $9
million and $11 million of interest expense in 1996.
Income Taxes Devon expects its financial income tax rate in 1996 to be
between 41% and 46%. Regardless of the level of pre-tax earnings reported
for financial purposes, approximately $2 million of Devon's financial
income tax expense is "fixed" due to various aspects of the 1994 Merger and
the San Juan Basin Transaction. Therefore, if the actual amount of 1996
pre-tax earnings differs materially from what Devon currently expects such
amount to be, the actual financial income tax rate for 1996 could fall
outside of the expected rate of 41% to 46%. Also, based on Devon's current
expectations of 1996 taxable income, which are largely dependent on 1996
oil and gas prices, Devon anticipates its current portion of 1996 income
taxes will be between $3 million and $5 million.
Capital Expenditures Devon expects its 1996 capital expenditures for
drilling and development efforts will total between $70 and $80 million,
including low risk development projects of approximately $21 million for
the Grayburg-Jackson Field activities described above, and approximately $9
million on the Worland Properties. Devon also plans to spend another $20
million to $25 million on new, higher risk/reward projects in the Gulf
Coast and Permian Basin areas. Devon has not given effect to any possible
success associated with this $20 million to $25 million in its oil and gas
reserve or production estimates.
In addition to these 1996 capital estimates, Devon also expects to incur
an additional $6 million to $9 million in 1997 on certain of its proved
undeveloped properties, with approximately half of such amount attributable
to the Worland Properties.
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.
The estimated future drilling and development activities are expected to
be funded through a combination of working capital, cash flow from
operations and borrowings from its credit lines. Devon considers these
capital resources, which are discussed in detail below, to be more than
adequate to fund these anticipated costs.
The above estimates of future capital expenditures could be
significantly affected by dramatic swings in oil and gas prices,
unanticipated delays in the initiation or completion of the projects,
changes in governmental regulations which may affect permissible
development, and possible acquisitions or mergers.
Capital Resources and Liquidity The above forward-looking statements
generally estimate increases in 1996 for combined oil, gas and NGL
production, and in those expenses which affect operating cash flow.
However, the amount of net cash to be provided by operating activities in
1996 is uncertain due to the significant effect of future oil and gas
prices. It is known, however, that such cash flow will continue to be the
primary source of capital and liquidity in 1996. Operating cash flow,
along with working capital and available credit, are more than adequate to
meet known capital requirements for 1996.
Impact of Recently Issued Accounting Standards In 1995, the Financial
Accounting Standards Board issued Statement of Financial Accounting
Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of," and Statement of Financial
Accounting Standards No. 123, "Accounting for Stock-Based Compensation."
Both of these statements are effective beginning in 1996. With regard to
oil and gas companies, Statement No. 121 will have a more significant
impact on those companies following the successful efforts method of
accounting, as Statement No. 121 revises the "ceiling test" for such
companies. Statement No. 121 does not affect the ceiling test for
companies such as Devon who follow the full cost method of accounting.
Therefore, such statement is not expected to have a material impact on
Devon's future operations.
With regard to Devon's stock options granted, no accounting is made
until such time as the options are exercised. At that time, the proceeds
are added to stockholders' equity, and no expense is recognized. Statement
No. 123 provides companies with the option of expensing the "fair value" of
stock options granted. Devon will not change its current accounting method
regarding stock options, and therefore Statement No. 123 will not impact
Devon's future operating results.
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements and Consolidated
Financial Statement Schedules
Page
Independent Auditors' Report
Consolidated Financial Statements:
Consolidated Balance Sheets
December 31, 1995, 1994 and 1993
Consolidated Statements of Operations
Years Ended December 31, 1995, 1994 and 1993
Consolidated Statements of Stockholders' Equity
Years Ended December 31, 1995, 1994 and 1993
Consolidated Statements of Cash Flows
Years Ended December 31, 1995, 1994 and 1993
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
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, 1995, 1994 and 1993, and the
results of their operations and their cash flows for the years
then ended, in conformity with generally accepted accounting
principles.
As discussed in notes 1 and 8 to the consolidated
financial statements, the Company changed its method of
accounting for income taxes in 1993 to adopt the provisions of
Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes."
KPMG Peat Marwick LLP
Oklahoma City, Oklahoma
February 12, 1996
<PAGE>
<TABLE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
<CAPTION>
December 31,
1995 1994 1993
Assets
Current assets:
<S> <C> <C> <C>
Cash and cash equivalents $ 8,897,891 8,336,371 19,550,288
Accounts receivable (Note 5) 14,400,295 15,626,799 15,356,653
Inventories 605,263 534,326 715,801
Prepaid expenses 222,135 564,371 543,166
Deferred income taxes (Note 8) 749,000 262,000 262,000
Total current assets 24,874,584 25,323,867 36,427,908
Property and equipment, at cost, based on
the full cost method of accounting for oil
and gas properties (Note 6) 631,437,904 523,941,141 414,073,372
Less accumulated depreciation,
depletion and amortization 239,619,167 202,634,961 169,384,351
391,818,737 321,306,180 244,689,021
Other assets 4,870,796 4,817,489 4,435,916
Total assets $421,564,117 351,447,536 285,552,845
Liabilities and stockholders' equity
Current liabilities:
Accounts payable:
Trade 3,868,458 6,394,897 3,883,775
Revenues and royalties
due to others 7,322,418 7,398,199 14,679,455
Income taxes payable 1,364,070 - 467,962
Accrued expenses 3,003,943 3,225,493 2,256,583
Total current liabilities 15,558,889 17,018,589 21,287,775
Revenues and royalties due to others 816,412 1,383,135 1,445,883
Other liabilities (Notes 3 and 10) 8,623,057 - -
Long-term debt (Note 7) 143,000,000 98,000,000 80,000,000
Deferred revenue 72,761 1,299,947 1,276,640
Deferred income taxes (Note 8) 34,452,000 27,340,000 8,643,000
Stockholders' equity (Note 9):
Preferred stock of $1.00 par value.
Authorized 3,000,000 shares;
none issued - - -
Common stock of $.10 par value.
Authorized 120,000,000 shares;
issued 22,111,896 in 1995,
22,050,996 in 1994,
and 20,842,318 in 1993 2,211,190 2,205,100 2,084,232
Additional paid-in capital 167,430,347 166,654,305 144,403,743
Retained earnings 49,399,461 37,546,460 26,411,572
Total stockholders' equity 219,040,998 206,405,865 172,899,547
Commitments and contingencies (Notes 10
and 11)
Total liabilities and
stockholders' equity $421,564,117 351,447,536 285,552,845
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
<CAPTION>
Year Ended December 31,
1995 1994 1993
Revenues
<S> <C> <C> <C>
Oil sales $ 55,289,819 38,086,076 38,395,305
Gas sales 50,732,158 56,371,452 54,875,796
Natural gas liquids sales 6,403,663 4,908,126 4,543,625
Other 877,185 1,407,305 942,195
Total revenues 113,302,825 100,772,959 98,756,921
Costs and expenses
Lease operating expenses 27,288,755 24,520,757 26,401,597
Gross production taxes 6,832,507 6,899,743 6,923,535
Depreciation, depletion and
amortization (Note 6) 38,089,783 34,132,150 28,409,065
General and administrative expenses 8,418,739 8,424,687 7,640,210
Interest expense 7,051,142 5,438,911 3,421,742
Total costs and expenses 87,680,926 79,416,248 72,796,149
Earnings before income taxes and
cumulative effect of change in
accounting principle 25,621,899 21,356,711 25,960,772
Income tax expense (Note 8):
Current 4,495,000 415,000 1,477,000
Deferred 6,625,000 7,197,000 5,298,000
Total income tax expense 11,120,000 7,612,000 6,775,000
Earnings before cumulative effect
of change in accounting principle 14,501,899 13,744,711 19,185,772
Cumulative effect of change in accounting
principle (Note 8) - - 1,300,000
Net earnings $ 14,501,899 13,744,711 20,485,772
Net earnings per average common
share outstanding (Note 1):
Before cumulative effect of
change in accounting principle $0.66 0.64 0.92
Cumulative effect of change in
accounting principle - - 0.06
Net earnings $0.66 0.64 0.98
Weighted average common shares outstanding 22,073,550 21,551,581 20,822,029
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,
1995 1994 1993
Common stock
<S> <C> <C> <C>
Balance, beginning of year $ 2,205,100 2,084,232 2,073,298
Par value of common shares issued 6,090 120,868 10,934
Balance, end of year 2,211,190 2,205,100 2,084,232
Additional paid-in capital
Balance, beginning of year 166,654,305 144,403,743 143,392,520
Common shares issued, net
of issuance costs 776,042 22,250,562 1,011,223
Balance, end of year 167,430,347 166,654,305 144,403,743
Retained earnings
Balance, beginning of year 37,546,460 26,411,572 7,801,189
Dividends (2,648,898) (2,609,823) (1,875,389)
Net earnings 14,501,899 13,744,711 20,485,772
Balance, end of year 49,399,461 37,546,460 26,411,572
Total stockholders' equity, end of year $219,040,998 206,405,865 172,899,547
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
1995 1994 1993
<S> <C> <C> <C>
Cash flows from operating activities:
Net earnings $ 14,501,899 13,744,711 20,485,772
Adjustments to reconcile net earnings to net
cash provided by operating activities:
Depreciation, depletion and amortization 38,089,783 34,132,150 28,409,065
(Gain) loss on sale of assets 273,238 (27,086) 34,832
Deferred income taxes 6,625,000 7,197,000 5,298,000
Cumulative effect of change in accounting
principle - - (1,300,000)
Changes in assets and liabilities net of effects
of acquisitions of businesses (Note 2):
(Increase) decrease in:
Accounts receivable 1,213,877 123,388 2,102,329
Inventories (70,937) 181,475 (194,151)
Prepaid expenses 342,236 712 (127,430)
Other assets 677,238 (489,648) (1,136,282)
Increase (decrease) in:
Accounts payable (430,736) (8,896,674) 9,816,309
Income taxes payable 1,364,070 (467,962) (718,038)
Accrued expenses (221,550) 997,645 1,201,933
Revenues and royalties due to others (566,723) (62,748) (69,763)
Long-term other liabilities 705,636 - -
Deferred revenue (1,227,186) (49,127) 154,234
Net cash provided by operating activities 61,275,845 46,383,836 63,956,810
Cash flows from investing activities:
Proceeds from sale of property and equipment 9,427,401 4,649,257 11,350,912
Capital expenditures (117,593,897) (35,619,968) (85,565,098)
Payments made for acquisition of business (Note 2) (2,391,484) (42,397,463) -
Net cash used in investing activities (110,557,980) (73,368,174) (74,214,186)
Cash flows from financing activities:
Proceeds from borrowings on revolving line of
credit 52,000,000 32,500,000 60,000,000
Principal payments on revolving line of credit (7,000,000) (14,500,000) (34,900,000)
Issuance of common stock, net of issuance costs 782,132 380,244 1,022,157
Dividends paid on common stock (2,648,898) (2,609,823) (1,875,389)
Increase in long-term other liabilities (Note 3) 6,710,421 - -
Net cash provided by financing activities 49,843,655 15,770,421 24,246,768
Net increase (decrease) in cash and cash equivalents 561,520 (11,213,917) 13,989,392
Cash and cash equivalents at beginning of year 8,336,371 19,550,288 5,560,896
Cash and cash equivalents at end of year $ 8,897,891 8,336,371 19,550,288
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
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 a successor to several previous entities
dating back to 1971. Devon's common stock trades on the American
Stock Exchange under the symbol "DVN." 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.
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
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
1. Summary of Significant Accounting Policies
(Continued)
Property and Equipment (Continued)
at 10% per annum, from proved oil, natural gas and natural gas
liquids reserves. Such 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.
Depreciation and amortization of other property
and equipment, including leasehold improvements, is provided
using the straight-line method based on estimated useful lives
from 3 to 20 years.
Deferred Revenue
Deferred revenue includes funds received under
take-or-pay provisions of certain gas contracts, which provide
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
No accounting is made with respect to incentive
stock options until such time as they are exercised, at which
time the proceeds are added to stockholders' equity.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
1. Summary of Significant Accounting Policies
(Continued)
Major Purchasers
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 Energy Marketing Corporation ("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. ("MOTI") - 18%. During 1993, MOTI accounted for
39% of Devon's gas sales.
Income Taxes
Statement of Financial Accounting Standards No.
109, "Accounting for Income Taxes" ("Statement 109") was
issued in February 1992. Under Statement 109's asset and
liability method, 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. Under
Statement 109, 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.
Devon adopted Statement 109 effective January 1,
1993, and has reported a benefit of $1.3 million in 1993 as a
cumulative effect of a change in accounting principle.
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 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.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
1. Summary of Significant Accounting Policies
(Continued)
Dividends
Beginning with the second quarter of 1993,
dividends on common stock were paid in 1993, 1994 and 1995 at
a per share rate of $0.03 per quarter.
Fair Value of Financial Instruments
Devon's only financial instrument for which the
fair value differs materially from the carrying value is the
interest rate swap discussed in Note 7. 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 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.
2. Acquisitions and Pro Forma Information
On December 18, 1995, Devon acquired certain
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 estimated reserve quantities acquired were
1.8 million barrels of oil, 59 billion cubic feet of natural
gas and 3.7 million barrels of oil equivalent of natural gas
liquids. Included in these reserves are certain proved
undeveloped reserves, for which Devon expects to incur
approximately $11.8 million of future capital costs.
Approximately $4.0 million of the purchase price was allocated
to undeveloped leasehold. (The quantities of proved reserves
and the estimated future development costs stated in this
paragraph are unaudited.)
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 "Merger"). The
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 Merger.
Subsequently, in February 1995, former Alta stockholders
received an additional cash payment of $2.4 million based upon
the evaluation of the Camille Adams #1 well in Louisiana which
Alta completed during the first half of 1994. Devon also
incurred $41.4 million of other costs related to the Merger.
This included $31.7 million to
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
2. Acquisitions and Pro Forma Information (Continued)
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 Merger.
Devon recorded additional deferred tax liabilities
of $11.5 million due to the substantially tax-free nature of
the 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 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.
On June 28, 1993, Devon acquired certain coal seam
natural gas properties in the San Juan Basin of New Mexico
("the Acquired San Juan Basin Properties") for approximately
$53.3 million. Approximately $48.3 million of the purchase
price was attributable to proved coal seam natural gas
reserves. The remaining $5 million of the purchase price was
allocated to unproved reserves associated with infill drilling
and development rights. The acquisition was primarily funded
with $50 million of borrowings from Devon's credit lines. The
acquisition was accounted for by the purchase method of
accounting for business combinations. Accordingly, the
accompanying 1993 consolidated statement of operations does
not include any revenues or expenses associated with the
Acquired San Juan Basin Properties prior to July 1, 1993.
Pro Forma Information (Unaudited)
The 1995 acquisition of the Worland Properties as
described above was accounted for by the purchase method of
accounting for business combinations. Accordingly, the
accompanying 1995 consolidated statement of operations does
not include any revenues or expenses associated with the
Worland Properties prior to the closing date of December 18,
1995. Following are Devon's pro forma results for 1995
assuming the acquisition occurred at the beginning of 1995:
<TABLE>
<CAPTION>
1995
<S> <C>
Total revenues $118,652,000
Net earnings $13,097,000
Net earnings per share $0.59
</TABLE>
The 1994 Merger 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 Alta prior to the closing date of May 18,
1994. Following are Devon's pro forma 1994 results assuming
the acquisition of the Worland Properties and the Merger both
occurred on January 1, 1994:
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
2. Acquisitions and Pro Forma Information (Continued)
Pro Forma Information (Unaudited) (Continued)
<TABLE>
<CAPTION>
1994
Pro Forma Effect of
Devon Worland Devon
Historical Merger Properties Pro Forma
<S> <C> <C> <C> <C>
Total revenues $100,773,000 4,329,000 6,297,000 111,399,000
Net earnings $13,745,000 (329,000) (387,000) 13,029,000
Net earnings per share $0.64 (0.03) (.02) 0.59
</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 Internal Revenue Service
regulations. Consequently, gas produced from these properties
through the year 2002 qualifies for Section 29 tax credits,
which as of year-end 1995 were equal to approximately $1.01
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.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
3. San Juan Basin Transaction (Continued)
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 will continue 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 year ended December 31, 1995, Devon
received $13.9 million related to the credits. Of this
amount, $12.8 million was recorded as additional gas sales,
and $1.1 million was recorded as an addition to liabilities as
discussed in the following paragraph. *Based on the reserves
estimated at December 31, 1995, and an assumed annual
inflation factor of 2%, Devon estimates it will receive total
tax credit payments of approximately $68 million from 1996
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 year ended December 31,
1995, $1.1 million of the total amount received for tax credit
payments was added to the liability, which raised the
liability balance to $6.7 million.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
3. San Juan Basin Transaction (Continued)
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 $6.7 million of other
liabilities recorded as of year-end 1995, does not include any
amount related to such reserves.
4. Supplemental Cash Flow Information
Cash payments for interest in 1995, 1994, and 1993
were approximately $6.7 million, $5.1 million and $3.3
million, respectively. Cash payments for federal and state
income taxes in 1995, 1994, and 1993 were approximately $2.2
million, $1.8 million and $2.3 million, respectively.
The Merger with Alta in 1994 involved cash and
non-cash consideration as presented below:
<TABLE>
<CAPTION>
1994
<S> <C>
Cash payments made $42,915,845
Value of common stock issued 21,991,084
Liabilities assumed 7,192,671
Deferred tax liability created 11,500,000
Fair value of assets acquired $83,599,600
</TABLE>
The above cash payments of $42.9 million 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 Merger.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
5. Accounts Receivable
The components of accounts receivable included the
following:
<TABLE>
<CAPTION>
December 31,
1995 1994 1993
Oil, gas and natural gas liquids
<S> <C> <C> <C>
revenue accruals $11,169,313 10,973,589 11,981,969
Joint interest billings 2,962,037 3,367,493 2,995,440
Income tax refunds due - 959,085 -
Other 493,945 551,632 629,244
14,625,295 15,851,799 15,606,653
Allowance for doubtful accounts (225,000) (225,000) (250,000)
Net accounts receivable $14,400,295 15,626,799 15,356,653
</TABLE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
6. Property and Equipment
<TABLE>
Property and equipment included the following:
<CAPTION>
December 31,
1995 1994 1993
Oil and gas properties:
<S> <C> <C> <C>
Subject to amortization $ 604,227,702 503,174,488 394,845,195
Not subject to amortization:
Acquired in 1995 5,635,170 - -
Acquired in 1994 1,001,427 1,451,109 -
Acquired in 1993 5,556,977 5,556,977 5,993,090
Acquired in 1992 8,257,985 8,561,031 8,650,308
Accumulated depreciation,
depletion and amortization (237,385,785) (200,746,032) (167,884,858)
Net oil and gas
properties 387,293,476 317,997,573 241,603,735
Other property and equipment:
Computers, office equipment,
furniture and leasehold
improvements 5,168,817 4,047,183 3,645,091
Automotive equipment 1,201,084 786,338 646,247
Other 388,742 364,015 293,441
6,758,643 5,197,536 4,584,779
Accumulated depreciation and
amortization (2,233,382) (1,888,929) (1,499,493)
Net other property and
equipment 4,525,261 3,308,607 3,085,286
Property and equipment, net of
accumulated depreciation,
depletion and amortization $ 391,818,737 321,306,180 244,689,021
</TABLE>
<TABLE>
Depreciation, depletion and amortization expense consisted
of the following components:
<CAPTION>
Year Ended December 31,
1995 1994 1993
<S> <C> <C> <C>
Depreciation, depletion and
amortization of oil and gas
properties $36,639,753 32,861,174 27,419,640
Depreciation and amortization of
other property and equipment 1,045,978 865,092 808,770
Amortization of other assets 404,052 405,884 180,655
Total expense $38,089,783 34,132,150 28,409,065
</TABLE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
7. Long-term Debt
Devon has 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, 1995, was $205
million. In 1996, the banks revised the Borrowing Base upward
to $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 plus up to .75% depending on the percentage of the
Borrowing Base that is borrowed. The average interest rates
on the outstanding debt at the end of 1995, 1994 and 1993,
were 6.64%, 6.83% and 4.16%, respectively. The loan
agreements also provide for a quarterly commitment fee equal
to .375% per annum.
Debt borrowed under the credit lines is unsecured. No
principal payments are required until maturity unless the
unpaid balance exceeds the Borrowing Base. As of December 31,
1995, $140 million of the outstanding balance matures on March
31, 1998, and the remaining $3 million matures on May 1, 1997.
The loan agreements contain certain covenants and
restrictions, among which are limitations on additional
borrowings and sales of properties valued at more than $10
million, working capital and net worth maintenance
requirements and a minimum debt to net worth ratio. At
December 31, 1995, Devon was in compliance with such covenants
and restrictions.
Assuming the Borrowing Base is not reduced below the current
loan balance outstanding and the maturity dates of the loans
are not extended, the debt outstanding at the end of 1995 is
scheduled to be payable as follows:
<TABLE>
<CAPTION>
Year ending December 31,
<S> <C>
1996 $ -
1997 3,000,000
1998 140,000,000
$143,000,000
</TABLE>
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 principal amount of the
swap agreement is $75 million, and the other party to the
agreement is one of the lenders of Devon's
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
7. Long-term Debt (Continued)
credit lines (the "Lender"). The agreement terminates on June
16, 1998, unless the Lender exercises its right to extend the
termination date to June 16, 2000. The terms of the agreement
provide for quarterly payments either to or from Devon,
determined by whether the three month London Interbank Offered
Rate ("LIBOR") in effect at the beginning of each quarterly
calculation period is greater or less than 5.6%. The
calculation periods begin on the sixteenth day of each March,
June, September and December during the term of the agreement.
If, on the date of the beginning of the quarterly calculation
period, the three month LIBOR exceeds 5.6%, the Lender will
owe Devon the quarterly amount of the excess rate applied to
the $75 million principal. Alternately, if the three month
LIBOR on the applicable quarterly date is less than 5.6%,
Devon will owe the Lender.
The swap agreement is accounted for as a hedge, with the
amount which is either due to or from Devon recorded as a
reduction or increase in interest expense. The three month
LIBOR exceeded 5.6% at the beginning of each of the three
quarterly calculation periods in 1995. Therefore, Devon
recognized $0.1 million as a reduction to interest expense in
1995. 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 has no carrying value in the accompanying
consolidated financial statements.
The swap agreement does not alter or affect any terms or
conditions of Devon's credit lines.
8. Income Taxes
At December 31, 1995, 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 1996-2008 $15,400,000
Net operating loss - various states 1996-2010 $18,100,000
Statutory depletion N/A $ 6,500,000
Minimum tax credit N/A $ 5,600,000
Investment tax credit 1996-1999 $ 100,000
</TABLE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
8. Income Taxes (Continued)
All of the carryforward amounts shown above have been
utilized for financial purposes to reduce deferred taxes.
Substantially all of the federal net operating loss
carryforwards shown above were acquired in the 1994 Merger.
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,
1995 1994 1993
<S> <C> <C> <C>
Federal statutory tax rate 35% 35% 35%
Nonconventional fuel source credits (1) - (6)
Alternative minimum tax (credit) - - (2)
State income taxes 4 3 1
Effect of San Juan Basin Transaction 4 - -
Other 1 (2) (2)
Effective income tax rate 43% 36% 26%
</TABLE>
As discussed in Note 1, Devon adopted Statement 109 as of
January 1, 1993. The $1.3 million cumulative benefit of this
change is reported separately in the 1993 consolidated
statement of operations.
The tax effects of temporary differences that gave rise to
significant portions of the deferred tax assets and
liabilities at December 31, 1995, 1994 and 1993, as provided
for under Statement 109, are presented below:
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
8. Income Taxes (Continued)
<TABLE>
<CAPTION>
December 31,
1995 1994 1993
Deferred tax assets:
<S> <C> <C> <C>
Net operating loss carryforwards $ 6,082,000 6,127,000 1,609,000
Statutory depletion carryforwards 2,287,000 3,087,000 2,606,000
Investment tax credit carryforwards 85,000 813,000 894,000
Minimum tax credit carryforwards 5,576,000 2,195,000 1,860,000
Production payments 24,770,000 - -
Other 1,966,000 897,000 629,000
Total gross deferred tax assets 40,766,000 13,119,000 7,598,000
Less valuation allowance 100,000 100,000 -
Net deferred tax assets 40,666,000 13,019,000 7,598,000
Deferred tax liabilities:
Property and equipment, principally due
to differences in depreciation, and
the expensing of intangible drilling
costs for tax purposes (74,369,000) (40,097,000) (15,979,000)
Net deferred tax liability $(33,703,000) (27,078,000) (8,381,000)
</TABLE>
As shown in the above schedule, Devon has recognized $40.7
million of net deferred tax assets as of December 31, 1995.
Such amount consists almost entirely of $14 million of various
carryforwards available to offset future income taxes, and
$24.8 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, investment tax credit
carryforwards which expire between 1996 and 1999, and the
statutory depletion and minimum tax credit carryforwards which
have no expiration dates. Statement 109 requires that the tax
benefit of carryforwards be 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", Statement 109 requires that a
valuation allowance be 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 1996 and 2002. 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
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
8. Income Taxes (Continued)
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, 1995, related to
depletion carryforwards acquired in the Merger.
The $24.8 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 recognized, and the present value of the
production payments to be received was recorded as a note
receivable. For presentation purposes, the $24.8 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. Stockholders' Equity
The authorized capital stock of Devon consists of 120
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, 1995, 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.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
9. Stockholders' Equity (Continued)
Stock Option Plans
Prior to 1993, Devon had outstanding stock options issued to
certain of its employees under two stock option plans adopted
in 1987 and 1988 ("the 1987 Plan" and "the 1988 Plan").
During 1993, all remaining options outstanding under the 1987
Plan were exercised. Also during 1993, the 1988 Plan was
cancelled. 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,
1995, 14 participants held the 368,600 options outstanding
under the 1988 Plan.
Effective June 7, 1993, Devon adopted the Devon Energy
Corporation 1993 Stock Option Plan ("the 1993 Plan") and
reserved one million shares of Common Stock for issuance
thereunder to key management and professional employees.
Eighteen such employees were eligible to participate in the
1993 Plan at year-end 1995.
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,
1995, 18 participants held the 660,300 options outstanding
under the 1993 Plan. There were 337,200 options available for
future grants as of December 31, 1995.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
9. Stockholders' Equity (Continued)
Stock Option Plans (Continued)
A summary of the status of Devon's stock option plans as of
December 31, 1993, 1994 and 1995, 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, 1992 377,537 $10.146
Options granted 214,500 $24.087
Options exercised (109,337) $ 9.349
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
</TABLE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
9. Stockholders' Equity (Continued)
Stock Option Plans (Continued)
The following table summarizes information about Devon's
stock options which were outstanding, and those which were
exercisable, as of December 31, 1995:
<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 to $14 168,600 5.3 years $10.001 154,600 $10.148
$18 to $21 210,800 8.9 years $18.088 121,600 $18.089
$23 to $25 649,500 8.7 years $23.770 412,600 $23.827
$8 to $25 1,028,900 8.2 years $20.349 688,800 $19.744
</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.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
10. Retirement Plans
Devon has a defined benefit retirement plan (the "Basic
Plan") which is non-contributory and includes substantially
all 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,
1995 1994 1993
Actuarial present value of benefit
obligations:
Accumulated benefit obligation:
<S> <C> <C> <C>
Vested $(3,500,000) (2,648,000) (2,737,000)
Nonvested (654,000) (282,000) (394,000)
Total $(4,154,000) (2,930,000) (3,131,000)
Projected benefit obligation for
service rendered to date (4,782,000) (3,378,000) (3,624,000)
Plan assets at fair value, primarily
investments in corporate obligation
and equity mutual funds 4,227,000 3,252,000 2,917,000
Plan assets less than projected benefit
obligation (555,000) (126,000) (707,000)
Unrecognized prior service cost
(benefit) (154,000) (176,000) (123,000)
Unrecognized net loss from past experience
different from that assumed, and effects
of changes in assumptions 921,000 225,000 683,000
Unrecognized net transitional asset - - (35,000)
Prepaid (accrued) pension expense $ 212,000 (77,000) (182,000)
</TABLE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
10. Retirement Plans (Continued)
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, 1995:
<TABLE>
<CAPTION>
December 31,
1995
Actuarial present value of benefit obligations:
Accumulated benefit obligation:
<S> <C>
Vested $(1,658,000)
Nonvested (255,000)
Total $(1,913,000)
Projected benefit obligation for service rendered
to date (2,245,000)
Plan assets at fair value -
Projected benefit obligation in excess of plan assets (2,245,000)
Unrecognized prior service cost 1,354,000
Unrecognized net loss from past experience different
from that assumed, and effects of changes in
assumptions 185,000
Accrued pension expense (706,000)
Additional minimum liability (1,207,000)
Total pension liability $(1,913,000)
</TABLE>
The $1.9 million total pension liability of the
Supplementary Plan is included in long-term other liabilities
on the accompanying consolidated balance sheet. The $1.2
million additional minimum liability is offset by a $1.2
million intangible asset included in other assets on the
balance sheet.
Net pension expense for Devon's two defined benefit
plans included the following components:
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1994 1993
<S> <C> <C> <C>
Service cost - benefits earned during the period $ 362,000 277,000 183,000
Interest cost on projected benefit obligation 446,000 284,000 247,000
Actual return on plan assets (536,000) (20,000) (254,000)
Net amortization and deferral 345,000 (231,000) 101,000
Net periodic pension expense $ 617,000 310,000 277,000
</TABLE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
10. Retirement Plans (Continued)
The weighted average discount rate used in determining the
actuarial present value of the projected benefit obligation in
1995, 1994 and 1993 was 7.25%, 8.5% and 7.25%, respectively.
The rate of increase in future compensation levels was 5% for
all three years. The expected long-term rate of return on
assets was 8.50% in 1995 and 8% in 1994 and 1993.
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
$170,000, $158,000 and $147,000 for the years ended December
31, 1995, 1994 and 1993, respectively.
11. 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 1995, and for
future years as well. While the MMS has not asserted a claim
for additional royalties, and while Devon intends to
vigorously contest any claim for excessive additional federal
royalties through available administrative and judicial
processes, Devon has accrued an estimate of additional federal
royalties related to its share of gas produced from 1990
through 1995. 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 of the amount
likely to be assessed by the MMS 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.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
11. Commitments and Contingencies (Continued)
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 the assessment in January 1996 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. However, Devon's management
and legal counsel believe that it is reasonably possible that
the amount paid to the State of New Mexico will be refunded.
Pending further developments on this matter, Devon will not
expense in its financial statements the taxes, penalties and
interest paid, but rather will record such amounts as
receivables.
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, 1995:
<TABLE>
<CAPTION>
Year ending December 31,
<C> <C>
1996 $543,000
1997 136,000
1998 83,000
1999 39,000
2000 26,000
Total minimum lease payments required $827,000
</TABLE>
Total rental expense for all operating leases is as follows
for the years ended December 31:
<TABLE>
<S> <C>
1995 $546,388
1994 $521,769
1993 $487,554
</TABLE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
12. Oil and Gas Operations
Costs Incurred
The following table reflects the costs incurred in oil and
gas property acquisition, exploration, and development
activities:
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1994 1993
Property acquisition costs:
Proved, excluding deferred income
<S> <C> <C> <C>
taxes $47,316,000 70,376,000 49,790,000
Deferred income taxes - 11,500,000 -
Total proved, including deferred income
taxes $47,316,000 81,876,000 49,790,000
Unproved $ 4,529,000 1,797,000 6,444,000
Exploration costs $ 7,174,000 5,194,000 4,115,000
Development costs $56,253,000 26,268,000 25,748,000
</TABLE>
Pursuant to the full cost method of accounting, Devon
capitalizes certain of its general and administrative expenses
which are related to property acquisition, exploration and
development activities. Such capitalized expenses, which are
included in the costs shown in the above table, were $2.7
million, $2.3 million and $2.2 million in the years 1995, 1994
and 1993, respectively.
Due to the substantially tax-free nature of the 1994 Merger
to the former Alta stockholders, Devon recorded additional
deferred tax liabilities of $11.5 million as of the effective
date of the Merger. The deferred tax liabilities caused an
additional $11.5 million to be allocated to proved oil and gas
reserves in 1994 as shown in the above schedule.
Results of Operations for Oil and Gas Producing Activities
The following table includes revenues and expenses
associated directly with Devon's oil and gas producing
activities. It does not include any allocation of Devon's
interest costs or general corporate overhead and, therefore,
is not necessarily indicative of the contribution to net
earnings of Devon's oil and gas operations. Income tax
expense has been calculated by applying statutory income tax
rates to oil and gas sales after deducting costs, including
depreciation, depletion and amortization and after giving
effect to permanent differences:
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
12. Oil and Gas Operations (Continued)
Costs Incurred (Continued)
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1994 1993
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales $112,425,000 99,366,000 97,815,000
Production and operating expenses (34,121,000) (31,421,000) (33,325,000)
Depreciation, depletion and amortization (36,640,000) (32,861,000) (27,420,000)
Income tax expense (15,536,000) (12,411,000) (12,844,000)
Results of operations for oil and gas
producing activities $ 26,128,000 22,673,000 24,226,000
Depreciation, depletion and amortization
per equivalent barrel of production $3.65 3.45 3.16
</TABLE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
13. 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, 1995,
as estimated by Devon's independent petroleum consultants
LaRoche & Associates, and Devon's own petroleum engineers.
Approximately 92%, 91%, and 95% of the respective year-end
1995, 1994 and 1993 proved reserves were calculated by LaRoche
& Associates. The remaining percentage of reserves are based
on Devon's own estimates. Natural gas liquids are denominated
in barrels of oil equivalent ("Boe") and are converted to Boe
using the ratio of 42 gallons to one barrel. All of Devon's
reserves are located within the United States.
<TABLE>
<CAPTION>
Natural
Oil Gas Gas Liquids
(Bbls) (Mcf) (Boe)
<S> <C> <C> <C>
Proved reserves as of December 31, 1992 16,349,000 263,598,000 1,011,000
Revisions of estimates (995,000) 54,536,000 1,227,000
Extensions and discoveries 3,543,000 20,759,000 80,000
Purchase of reserves 363,000 75,168,000 20,000
Production (2,337,000) (35,598,000) (411,000)
Sale of reserves (2,026,000) (9,209,000) (73,000)
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
Proved developed reserves as of:
December 31, 1992 13,823,000 249,154,000 797,000
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
</TABLE>
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
13. Supplemental Information on Oil and Gas Operations
(Unaudited) (Continued)
Standardized Measure of Discounted Future Net Cash Flows
The accompanying table reflects the standardized measure of
discounted future net cash flows relating to Devon's interest
in proved reserves:
<TABLE>
<CAPTION>
December 31,
1995 1994 1993
<S> <C> <C> <C>
Future cash inflows $1,476,418,000 1,186,845,000 913,931,000
Future costs:
Development (52,327,000) (75,115,000) (23,713,000)
Production (496,279,000) (400,676,000) (256,658,000)
Future income tax expense (153,431,000) (71,427,000) (61,480,000)
Future net cash flows 774,381,000 639,627,000 572,080,000
10% discount to reflect timing of
cash flows (328,481,000) (281,421,000) (228,530,000)
Standardized measure of discounted
future net cash flows $ 445,900,000 358,206,000 343,550,000
Discounted future net cash
flows before income taxes $ 534,248,000 398,206,000 380,471,000
</TABLE>
Future cash inflows are computed by applying year-end prices
(averaging $18.11 per barrel of oil, adjusted for
transportation and other charges, $1.35 per Mcf of gas and
$12.73 per Boe of natural gas liquids at December 31, 1995) to
the year-end quantities of proved reserves, except in those
instances where fixed and determinable price changes are
provided by contractual arrangements in existence at year-end.
In addition to the future gas revenues calculated at $1.35 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 cash inflows shown in the table
above include $58.2 million related to these tax credit
payments from 1996 through 2002. This amount has been
calculated using the assumption that the year-end 1995 tax
credit rate of $1.01 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
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
13. Supplemental Information on Oil and Gas Operations
(Unaudited) (Continued)
Standardized Measure of Discounted Future Net Cash Flows
(Continued)
Transaction as described in Note 3, the future income tax
expenses estimated at December 31, 1994 and 1993 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 and 1993 that undiscounted amounts
of approximately $113 million and $137 million, respectively,
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 and $39 million at
year-end 1994 and 1993, respectively. As a result of the San
Juan Basin Transaction, substantially all of the value of the
Section 29 tax credits at year-end 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,
1995 1994 1993
<S> <C> <C> <C>
Beginning balance $358,206,000 343,550,000 286,693,000
Sales of oil, gas and natural gas
liquids, net of production costs (78,304,000) (67,945,000) (64,490,000)
Net changes in prices and
production costs 60,498,000 (107,210,000) 1,479,000
Extensions, discoveries, and improved
recovery, net of future
development costs 22,308,000 14,629,000 26,999,000
Purchase of reserves, net of future
development costs 50,000,000 133,103,000 59,594,000
Development costs incurred during
the period which reduced future
development costs 43,810,000 16,519,000 11,580,000
Revisions of quantity estimates 7,397,000 26,167,000 47,798,000
Sales of reserves in place (7,933,000) (5,281,000) (18,170,000)
Accretion of discount 39,821,000 38,047,000 31,457,000
Net change in income taxes (48,347,000) (3,080,000) (9,048,000)
Other, primarily changes in timing (1,556,000) (30,293,000) (30,342,000)
Ending balance $445,900,000 358,206,000 343,550,000
</TABLE>
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1995, 1994 and 1993
14. Supplemental Quarterly Financial Information (Unaudited)
Following is a summary of the unaudited interim results of
operations for the years ended December 31, 1995 and 1994:
<TABLE>
<CAPTION>
<F1>
1995 - Actual Reported Results (a)
First Second Third Fourth
Quarter Quarter Quarter Quarter Total
Oil, gas and natural gas
<S> <C> <C> <C> <C> <C>
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
</TABLE>
<TABLE>
<CAPTION>
<F1>
1995 - Adjusted Results (a)
First Second Third Fourth
Quarter Quarter Quarter Quarter Total
Oil, gas and natural gas
<S> <C> <C> <C> <C> <C>
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 4,385,114 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 first table above
includes the 1995 quarterly results as reported, including the six-month
out-of-period effect on the third quarter. The second table above presents
the 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>
<TABLE>
<CAPTION>
1994
First Second Third Fourth
Quarter Quarter Quarter Quarter Total
Oil, gas and natural gas
<S> <C> <C> <C> <C> <C>
liquids sales $25,778,304 24,953,045 25,054,238 23,580,067 99,365,654
Total revenues $26,144,281 25,519,353 25,298,970 23,810,355 100,772,959
Net earnings $ 4,876,974 4,053,853 3,055,972 1,757,912 13,744,711
Net earnings per share $0.23 0.19 0.14 0.08 0.64
</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 29,
1996.
ITEM 11. EXECUTIVE COMPENSATION
The information called for by this Item 11 is incorporated
herein by reference to the definitive Proxy Statement to be filed by the
Company pursuant to Regulation 14A of the General Rules and Regulations
under the Securities and Exchange Act of 1934 not later than April 29,
1996.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information called for by this Item 12 is incorporated
herein by reference to the definitive Proxy Statement to be filed by the
Company pursuant to Regulation 14A of the General Rules and Regulations
under the Securities and Exchange Act of 1934 not later than April 29,
1996.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information called for by this Item 13 is incorporated
herein by reference to the definitive Proxy Statement to be filed by the
Company pursuant to Regulation 14A of the General Rules and Regulations
under the Securities and Exchange Act of 1934 not later than April 29,
1996.<PAGE>
<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 40 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 by and among Devon
Energy Corporation, Devon Acquisition Corp. and Alta
Energy Corporation dated February 18, 1994
[incorporated by reference to Exhibit 2.1 to
Registrant's Registration Statement on Form S-4 (No.
33-76524)].
2.3 - Amendment to Agreement and Plan of Merger by and
among Devon Energy Corporation, Devon Acquisition Corp.
and Alta Energy Corporation dated April 13, 1994
[incorporated by reference to Exhibit 2.2 to Amendment
No. 1 to Registrant's Registration Statement on Form S-
4 (No. 33-76524)].
3.1 - Registrant's Certificate of Incorporation
(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 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).<PAGE>
4.3 - 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).
10.1 - Credit Agreement dated October 7, 1994, 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, 1994).
10.2 - First Amendment, dated January 27, 1995, to
Credit Agreement 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 10.2 to
Registrant's Annual Report on Form 10-K for the year
ended December 31, 1994).
10.3 - Devon Energy Corporation 1988 Stock Option Plan
[incorporated by reference to Exhibit 10.4 to
Registrant's Registration Statement on Form S-4 (No.
33-23564)].#
10.4 - Devon Energy Corporation 1993 Stock Option Plan
(incorporated by reference to Exhibit A to Registrant's
Proxy Statement for the 1993 Annual Meeting of
Shareholders filed on May 6, 1993).#
10.5 - Severance Agreement between Devon Energy
Corporation (Nevada), Registrant 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).#
10.6 - Severance Agreement between Devon Energy
Corporation (Nevada), Registrant 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).#
10.7 - Severance Agreement between Devon Energy
Corporation (Nevada), Registrant and Mr. J. Michael
Lacey, dated December 3, 1992 (incorporated by
reference to Exhibit 10.12 to Registrant's Amendment
No. 1 to Annual Report on Form 10-K for the year ended
December 31, 1992).#
10.8 - Severance Agreement between Devon Energy
Corporation (Nevada), Registrant and Mr. H. Allen
Turner, dated December 3, 1992 (incorporated by
reference to Exhibit 10.13 to Registrant's Amendment
No. 1 to Annual Report on Form 10-K for the year ended
December 31, 1992).#
10.9 - Severance Agreement between Devon Energy
Corporation (Nevada), Registrant and Mr. Darryl G.
Smette, dated December 3, 1992 (incorporated by
reference to Exhibit 10.14 to Registrant's Amendment
No. 1 to Annual Report on Form 10-K for the year ended
December 31, 1992).#
10.10 - Severance Agreement between Devon Energy
Corporation (Nevada), Registrant and Mr. William T.
Vaughn, dated December 3, 1992 (incorporated by
reference to Exhibit 10.15 to Registrant's Amendment
No. 1 to Annual Report on Form 10-K for the year ended
December 31, 1992).#
10.11 - Stock Purchase Agreement dated January 14,
1994, between GSS Investments Corp. [a wholly-owned
subsidiary of Registrant] and Princor Growth Fund, Inc.
(incorporated by reference to Exhibit 3 to Amendment
No. 2 to Registrant's Schedule 13D dated as of January
7, 1994).
10.12 - Stock Purchase Agreement dated January 14,
1994, between Registrant and Andrew P. Carstensen, Jr.
(incorporated by reference to Exhibit 4 to Amendment
No. 2 to Registrant's Schedule 13D dated as of January
7, 1994).
10.13 - 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).
10.14 - 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).
10.15 - 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)
11 - Computation of earnings per share
21 - Subsidiaries of Registrant (incorporated by
reference to Exhibit 21 to Registrant's Registration
Statement on Form 8-B filed on June 7, 1995).
23.1 - Consent of LaRoche & Associates
23.2 - Consent of KPMG Peat Marwick LLP
# Compensatory plans or arrangements.
(b) Reports on Form 8-K - A Current Report on Form 8-K dated
December 18, 1995, was filed by the Registrant regarding the
acquisition of certain Wyoming oil and natural gas properties
and a gas processing plant for approximately $50.3 million.
<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 4, 1996 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 4, 1996 By John W. Nichols
John W. Nichols
Chairman of the Board and Director
March 4, 1996 By J. Larry Nichols
J. Larry Nichols
President, Chief Executive Officer and Director
March 4, 1996 By H. R. Sanders, Jr.
H. R. Sanders, Jr.
Executive Vice President and Director
March 4, 1996 By William T. Vaughn
William T. Vaughn
Vice President - Finance
March 4, 1996 By Danny J. Heatly
Danny J. Heatly
Controller
March 4, 1996 By Thomas F. Ferguson
Thomas F. Ferguson, Director
March, 4 1996 By David M. Gavrin
David M. Gavrin, Director
March 4, 1996 By Michael E. Gellert
Michael E. Gellert, Director
<PAGE>
Exhibit 11
<TABLE>
<CAPTION>
DEVON ENERGY CORPORATION
Computation of Earnings Per Share
Year Ended December 31,
------------------------------
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
PRIMARY EARNINGS PER SHARE
Computation for Statement of Operations
Net earnings per statement of operations $14,501,899 13,744,711 20,485,772
Weighted average common shares outstanding 22,073,550 21,551,581 20,822,029
Primary earnings per share $0.66 0.64 0.98
Additional Primary Computation (A)
Net earnings per statement of operations $14,501,899 13,744,711 20,485,772
Adjustment to weighted average common shares outstanding:
Weighted average as shown above in primary computation 22,073,550 21,551,581 20,822,029
Add dilutive effect of outstanding stock options
(as determined using the treasury stock method) 127,640 117,799 142,137
Weighted average common shares outstanding, as adjusted 22,201,190 21,669,380 20,964,166
Net earnings per common share, as adjusted $0.65 0.63 0.98
FULLY DILUTED EARNINGS PER SHARE (A)
Net earnings per statement of operations $14,501,899 13,744,711 20,485,772
Weighted average common shares outstanding as shown
in primary computation above 22,073,550 21,551,581 20,822,029
Add fully dilutive effect of outstanding stock options
(as determined using the treasury stock method) 181,446 118,211 143,415
Weighted average common shares outstanding, as adjusted 22,254,996 21,669,792 20,965,444
Fully diluted earnings per common share $0.65 0.63 0.98
(A) These calculations 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 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, 1995,
which appears in the December 31, 1995 annual report on Form 10-K of Devon
Energy Corporation.
William E. LaRoche
LAROCHE & ASSOCIATES
March 4, 1996
Exhibit 23.2
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 12, 1996,
relating to the consolidated balance sheets of Devon Energy
Corporation and subsidiaries as of December 31, 1995, 1994 and
1993 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, 1995
annual report on Form 10-K of Devon Energy Corporation.
Our report refers to a change in 1993 in the method of
accounting for income taxes to adopt the provisions of
Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes."
KPMG Peat Marwick LLP
KPMG Peat Marwick LLP
Oklahoma City, Oklahoma
March 4, 1996
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<CASH> 8897891
<SECURITIES> 0
<RECEIVABLES> 14400295
<ALLOWANCES> 0
<INVENTORY> 605263
<CURRENT-ASSETS> 24874584
<PP&E> 631437904
<DEPRECIATION> 239619167
<TOTAL-ASSETS> 421564117
<CURRENT-LIABILITIES> 15558889
<BONDS> 143000000
<COMMON> 2211190
0
0
<OTHER-SE> 216829808
<TOTAL-LIABILITY-AND-EQUITY> 421564117
<SALES> 112425640
<TOTAL-REVENUES> 113302825
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 34121262
<LOSS-PROVISION> 0
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