SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event report): February 8, 1999
DEVON ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
OKLAHOMA 1-10067 73-1474008
(State or Other Jurisdiction of (Commission File Number) (IRS Employer
Incorporation or Organization) Identification Number)
20 NORTH BROADWAY, SUITE 1500, OKLAHOMA CITY, OK 73102
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code: (405) 235-3611
Page 1 of 8 pages
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Item 5. Other Events
1999 Estimates
The forward-looking statements provided in this
discussion are based on Devon Energy Corporation's ("Devon")
management's examination of historical operating trends, the
December 31, 1998 reserve reports of independent petroleum
engineers and other data in Devon's possession or available
from third parties. Devon cautions that its future oil, gas
and natural gas liquids ("NGLs") production, revenues and
expenses are subject to all of the risks and uncertainties
normally incident to the exploration for and development and
production and sale of oil and gas. These risks include,
but are not limited to, price volatility, inflation or lack
of availability of goods and services, environmental risks,
drilling risks, regulatory changes, the uncertainty inherent
in estimating future oil and gas production or reserves, and
other risks as outlined below. Also, the financial results
of Devon's Canadian operations are subject to currency
exchange rate risks. Additional risks are discussed below
in the context of line items most affected by such risks.
Specific Assumptions and Risks Related to Price and
Production Estimates Prices for oil, natural gas and NGLs
are determined primarily by prevailing market conditions.
Market conditions for these products are influenced by
regional and world-wide economic growth, weather and other
substantially variable factors. These factors are beyond
Devon's control and are difficult to predict. In addition
to volatility in general, Devon's oil, gas and NGLs prices
may vary considerably due to differences between regional
markets and demand for different grades of oil, gas and
NGLs. Over 90% of Devon's revenues are attributable to
sales of these three commodities. Consequently, Devon's
financial results and resources are highly influenced by
this price volatility.
Estimates for Devon's future production of oil, natural
gas and NGLs are based on the assumption that market demand
and prices for oil and gas will continue at levels that
allow for profitable production of these products. There
can be no assurance of such stability.
Certain of Devon's individual oil and gas properties
are sufficiently significant as to have a material impact on
the overall financial results. With respect to oil
production, these properties include the West Red Lake Field
and the Grayburg-Jackson Unit, both in southeast New Mexico,
and the Gilby and Halkirk areas in Alberta. Devon's
interest in the Northeast Blanco Unit ("NEBU") and the 32-9
Unit, both in the San Juan Basin, and the Coleman and
Hamburg areas in Alberta can have a significant effect on
overall gas production.
The production, transportation and marketing of oil,
natural gas and NGLs are complex processes which are subject
to disruption due to transportation and processing
availability, mechanical failure, human error,
meteorological events and numerous other factors. The
following forward-looking statements were prepared assuming
demand, curtailment, producibility and general market
conditions for Devon's oil, natural gas and NGLs for 1999
will be substantially similar to those of 1998, unless
otherwise noted. Given the general limitations expressed
herein, Devon's forward-looking statements for 1999 are set
forth below. Unless otherwise noted, all of the following
dollar amounts are expressed in U.S. dollars. Those amounts
related to Canadian operations have been converted to U.S.
dollars using the year-end 1998 exchange rate of $0.6535
U.S. dollar to $1.00 Canadian dollar. The actual 1999
exchange rate may vary materially from the year-end 1998
rate used. Such variations could have a material effect on
the following Canadian estimates.
Definitions The following discussion includes
references to various abbreviations relating to volumetric
production terms. The definitions of these abbreviations
are as follows:
"Bcf" means billion cubic feet.
"Boe" means equivalent barrels of oil, calculated by
converting six Mcf of gas to one barrel of oil.
"Mcf" means thousand cubic feet.
"MMBtu" means million British thermal units, a measure
of heating value.
"MMcf" means million cubic feet.
Oil Production Devon expects its oil production in
1999 to total between 8.8 million barrels and 10.3 million
barrels. Domestic production is expected to be between 4.6
million barrels and 5.4 million barrels, and Canadian
production is expected to be between 4.2 million barrels and
4.9 million barrels.
Oil Prices Devon expects its 1999 net oil prices per
barrel will average between $0.25 to $0.55 above West Texas
Intermediate ("WTI") posted prices for its domestic
production. Approximately 180,000 barrels of Canadian oil
production in the first quarter have been fixed at a price
of approximately $17.80 per barrel. For the remainder of
1999's Canadian oil production, Devon expects to receive a
price between $1.75 and $2.25 below WTI posted prices.
The above expected range of the Canadian differentials
from WTI prices, as well as the $17.80 per barrel fixed
price for 180,000 barrels of first quarter production,
include an estimated $1.25 per barrel decrease resulting
from foreign currency hedges. These hedges, in which Devon
will sell $60 million in 1999 at an average Canadian-to-U.S.
exchange rate of $0.726, offset a portion of the exposure to
currency fluctuations on those Canadian oil sales that are
based on U.S. prices. The $1.25 per barrel decrease is
based on the assumption that the year-end 1998 Canadian-to-
U.S. conversion rate of $0.6535 remains constant during
1999.
Gas Production Devon expects its 1999 gas production
to total between 122 Bcf and 143 Bcf. It is expected that
San Juan Basin coal seam gas production will be between 19
Bcf and 23 Bcf, and all other domestic production will be
between 41 Bcf and 47 Bcf. Canadian production is expected
to be between 62 Bcf and 73 Bcf.
Gas Prices - Fixed Through various fixed price
contracts or hedging instruments, Devon has fixed the price
it will receive in 1999 on a portion of its natural gas
production. The table below includes the 1999 volumes and
the respective prices that have been fixed.
<TABLE>
<CAPTION>
Volumes Price Per
Area (MMcf) Mcf
<S> <C> <C>
San Juan Basin 13,100 $1.82
Rocky Mountains 7,600 $1.93
Other U.S. 1,500 $2.05
Total U.S. 22,200 $1.87
Canada 40,700 $1.33
</TABLE>
The above price for the San Juan Basin gas includes
approximately $0.41 per Mcf from the 1995 transaction
covering the majority of Devon's San Juan Basin coal seam
gas properties (the "San Juan Basin Transaction.") Also,
the above San Juan Basin price is net of approximately $0.63
per Mcf for transportation costs and quality adjustments.
Gas Prices - Floating For the gas production for which
prices have not been fixed, Devon expects its 1999 San Juan
Basin coal seam average price will be between $0.25 and
$0.55 per Mcf less than Texas Gulf Coast spot averages
("TGC"). This includes the additional $0.41 per Mcf from
the San Juan Basin Transaction and the $0.63 per Mcf
reduction for transportation and quality adjustments, both
referred to in the previous paragraph. Devon's other
domestic production is expected to average $0.05 to $0.20
less than TGC, and the Canadian production is expected to
average $0.80 to $0.95 less than the New York Mercantile
Exchange price ("NYMEX").
NGLs Production Devon expects its production of 1999
NGLs to total between 1.7 million barrels and 2.0 million
barrels. Between 1.3 million barrels and 1.5 million
barrels are expected to be produced domestically, and
between 0.4 million barrels and 0.5 million barrels are
expected to be produced in Canada.
Other Revenues Devon's other revenues in 1999 are
expected to be between $6.0 million and $7.5 million.
Domestic other revenues are expected to be $2.0 million to
$2.5 million and Canadian other revenues are expected to be
$4.0 million to $5.0 million. The majority of these other
revenues are expected to be produced from third party gas
processing activities.
Production and Operating Expenses Devon's production
and operating expenses vary in response to several factors.
Among the most significant of these factors are additions or
deletions to Devon's property base, changes in production
taxes, general changes in the prices of services and
materials that are used in the operation of the properties
and the amount of repair and workover activity required.
Oil, gas and NGLs prices will have a direct effect on
production taxes to be incurred in 1999. Future prices
could also have an effect on whether proposed workover
projects are economically feasible. These factors, coupled
with the uncertainty of future oil, gas and NGLs prices,
increase the uncertainty inherent in estimating future
production and operating costs. Given these uncertainties,
Devon estimates that 1999's total production and operating
costs will be between $116 million and $135 million. The
U.S. portion of such estimate is between $73 million and $84
million, while the Canadian costs are expected to total
between $43 million and $51 million.
Depreciation, Depletion and Amortization ("DD&A") The
1999 DD&A rate will depend on various factors. Most notable
among such factors are the amount of proved reserves that
could be added from drilling or acquisition efforts in 1999
compared to the costs incurred for such efforts, and the
revisions to Devon's year-end 1998 reserve estimates that
will be made during 1999.
Devon expects that its consolidated DD&A expense in
1999 will be between $122 million and $151 million. The
DD&A rates as of the beginning of 1999 were $3.92 per Boe
for domestic properties and $3.19 per Boe for Canadian
properties. Assuming a 1999 domestic rate of between $4.15
per Boe and $4.40 per Boe, 1999 oil and gas property related
DD&A expense is expected to be between $66 million and $81
million for the U.S. properties. Assuming a 1999 Canadian
rate of between $3.40 per Boe and $3.65 per Boe, 1999 oil
and gas property related DD&A expense is expected to be
between $51 million and $64 million for the Canadian
properties.
Additionally, Devon expects its 1999 non-oil and gas
property related DD&A to total between $3.9 million and $4.5
million in the U.S. and between $1.0 million and $1.3
million in Canada.
General and Administrative Expenses ("G&A") Devon's
G&A includes the costs of many different goods and services
used in support of its business. These goods and services
are subject to general price level increases or decreases.
In addition, Devon's G&A varies with its level of activity
and the related staffing needs as well as with the amount of
professional services required during any given period.
Should Devon's needs or the prices of the required goods and
services differ significantly from current expectations,
actual G&A could vary materially from the estimate. Given
these limitations, consolidated G&A in 1999 is expected to
be between $22.5 million and $26.0 million. Domestic G&A is
expected to be between $10.5 million and $12.0 million, and
Canadian G&A is expected to be between $12.0 million and
$14.0 million.
Interest Expense Future interest rates and oil,
natural gas and NGLs prices have a significant effect on
Devon's interest expense. The fixed-rate provisions on $225
million of existing long-term debt removes the uncertainty
of future interest rates from some, but not all, of Devon's
long-term debt. Also, Devon can only marginally influence
the prices it will receive in 1999 from sales of oil, gas
and NGLs. These factors increase the margin of error
inherent in estimating future interest expense. Other
factors which affect interest expense, such as the amount
and timing of capital expenditures, are within Devon's
control. Given the uncertainty of future interest rates and
commodity prices, Devon estimates that the consolidated
interest expense in 1999 will be between $28 million and $32
million. Domestic interest expense is expected to be
between $4 million and $5 million, and Canadian interest
expense is expected to be between $24 million and $27
million.
Deferred Effect of Changes in Foreign Currency Exchange
Rate on Subsidiary's Long-term Debt Assuming that there are
no changes during 1999 in the existing principal balance of
Devon's Canadian subsidiary's $225 million of long-term debt
which is denominated in U.S. dollars, the only factor
influencing the potential 1999 deferred effect is the
foreign currency rate between the U.S. dollar and the
Canadian dollar. For every $0.01 change in the exchange
rate from the year-end 1998 rate of $0.6535, Devon's
Canadian subsidiary will record a deferred effect (either
revenue or expense) of approximately $5 million Canadian
dollars. The resulting revenue or expense in U.S. dollars
from such fluctuations would depend on the currency rate
during the applicable period.
Distributions on TCP Securities Devon's 6.5% Trust
Convertible Preferred Securities (the "TCP Securities") are
convertible into common shares of Devon at the option of the
holder. Beginning in June 1999, Devon can redeem the TCP
Securities for cash at 104.55% of face value if the
redemption occurs in 1999, and thereafter at premiums that
decline ratably to 100% in 2006. If Devon were to offer to
redeem the TCP Securities, the holders could decide instead
to convert the TCP Securities into Devon common stock.
Assuming all $149.5 million of TCP Securities are
outstanding for the entire year, Devon will make $9.7
million of distributions in 1999.
Reduction of Carrying Value of Oil and Gas Properties
As of December 31, 1998, the full cost ceiling exceeded
Devon's carrying value of oil and gas properties, less
deferred income taxes. This full cost "cushion" was
approximately $15 million for the domestic properties and
$43 million for the Canadian properties. However, these
cushion amounts could easily be eliminated by declines in
oil and/or gas prices between year-end 1998 and the end of
any quarter during 1999. The result would be a 1999
reduction of the carrying value of oil and gas properties.
Income Taxes Devon expects its consolidated financial
income tax rate in 1999 to be between 35% and 45%. These
rates are the combined current and deferred tax rates.
There are certain items, both in the U.S. and Canada, that
will have a fixed impact on 1999's income tax expense
regardless of the level of pre-tax earnings that are
produced. These items include Section 29 tax credits in the
U.S., which reduce income taxes based on production levels
of certain properties and are not necessarily affected by
pre-tax financial earnings. The amount of Section 29 tax
credits expected to be used to offset financial income tax
expense in 1999 is approximately $4 million. Also, Devon's
Canadian subsidiary is subject to Canada's "large
corporation tax" of approximately $2 million which is based
on total capitalization levels, not pre-tax earnings. The Canadian
financial income tax in 1999 will also be increased by
approximately $1 million due to the financial amortization
of certain costs that are not deductible for income tax
purposes. Significant changes in estimated production
levels of oil, gas and NGLs, the prices of such products, or
any of the various expense items could materially alter the
effect of the aforementioned items on 1999's financial
income tax rates.
Based on its current expectations of 1999 taxable
income, Devon anticipates its current portion of 1999 income
taxes will be $3 million to $8 million in the U.S. and $2
million to $3 million in Canada. However, unanticipated
revenue and/or expense fluctuations could easily make these
tax estimates inaccurate.
Capital Expenditures Devon's capital expenditures
budget is based on an expected range of future oil, natural
gas and NGLs prices as well as the expected costs of the
capital additions. Should Devon's price expectations for
its future production change significantly, some projects
may be accelerated or deferred and, consequently, may
increase or decrease total 1999 capital expenditures. In
addition, if the actual costs of the budgeted items vary
significantly from the anticipated amounts, actual capital
expenditures could vary materially from Devon's estimates.
Though Devon has completed several major property
transactions in recent years, these transactions are
opportunity driven. Thus, Devon does not "budget", nor can
it reasonably predict, the timing or size of such possible
acquisitions, if any.
Given these limitations, Devon expects its 1999 capital
expenditures for drilling and development efforts to total
between $145 million and $175 million. These amounts
include between $75 million and $90 million in the U.S. and
between $70 million and $85 million in Canada. Devon
expects to spend $20 million to $25 million in the U.S. and
$15 million to $20 million in Canada for drilling and
facilities costs related to reserves classified as proved as
of year-end 1998. Devon also plans to spend another $35
million to $45 million in the U.S. and $40 million to $50
million in Canada on new, higher risk/reward projects.
In addition to the above expenditures for drilling and
development, Devon expects to participate in the
construction of an extensive gas gathering system and
processing project in the Powder River Basin of Wyoming.
The extent to which outside parties will participate in the
project has not yet been determined. Depending on the final
level of participation of those parties, Devon expects to
spend between $60 million to $80 million as its share of the
project in 1999.
Other Cash Uses Devon's management expects the policy
of paying a quarterly dividend to continue. With the
current $0.05 per share quarterly dividend rate and 48.4
million shares of common stock outstanding, 1999 dividends
are expected to approximate $10 million.
Capital Resources and Liquidity The estimated future
drilling and development activities are expected to be
funded primarily through a combination of working capital
and operating cash flow, with the remainder funded with
borrowings from Devon's credit facilities. As of December
31, 1998, Devon had $219.7 million available under its $400
million credit facilities. The amount of operating cash
flow to be generated during 1999 is uncertain due to the
factors affecting revenues and expenses as previously cited.
However, Devon expects its combined capital resources to be
more than adequate to fund its anticipated capital
expenditures for 1999. If significant acquisitions or other
unplanned capital requirements arise during the year, Devon
could utilize its existing credit facilities and/or seek to
establish and utilize other sources of financing.
SIGNATURES
Pursuant to the requirements of the Securities and
Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned hereto
duly authorized.
DEVON ENERGY CORPORATION
By: /s/ Danny J. Heatly
Controller
Date: February 8, 1999
