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): January 26, 2000
DEVON ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
DELAWARE 001-30176 73-1567067
(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 12 pages
<PAGE>
Item 5. Other Events
Definitions
The following discussion includes references to various
abbreviations relating to volumetric production terms and
other defined terms. These definitions 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.
"MBbls" means thousand barrels.
"MBoe" means thousand Boe.
"MMbbls" means million barrels.
"Mcf" means thousand cubic feet.
"MMcf" means million cubic feet.
"NGLs" means natural gas liquids.
"Oil" includes crude oil and condensate.
"Southern Division" means the division of the
company operating oil and gas properties located primarily
in the onshore South Texas and Gulf Coast areas and offshore
in the Gulf of Mexico.
"Northern Division" means the division of the
company operating all properties located in the United
States other than those operated by the Southern Division.
"International" means all of the company's oil and
gas properties that lie outside the United States and
Canada.
Year End 1999 Reserve Quantities
Following are summaries of the changes in the net
quantities of Devon's crude oil, natural gas and NGLs proved
reserves for 1999.
<TABLE>
<CAPTION>
Consolidated
Oil Gas NGLs Total
(MBbls) (MMcf) (MBbls) (MBoe)
As of December 31, 1998:
<S> <C> <C> <C> <C>
Proved developed 73,846 1,052,647 15,081 264,368
Proved undeveloped 9,611 146,247 998 34,984
Total proved 83,457 1,198,894 16,079 299,352
Production (15,416) (198,457) (4,022) (52,514)
Discoveries and extensions 1,309 136,957 2,042 26,177
Divestitures (4,372) (53,456) (142) (13,423)
Acquisitions 235,512 821,547 32,795 405,232
Revisions 3,427 (8,958) 3,065 4,999
Net increase 220,460 697,633 33,738 370,470
As of December 31, 1999:
Proved developed 171,249 1,751,385 47,502 510,649
Proved undeveloped 132,668 145,142 2,315 159,173
Total proved 303,917 1,896,527 49,817 669,822
<CAPTION>
Northern Division
Oil Gas NGLs Total
(MBbls) (MMcf) (MBbls) (MBoe)
As of December 31, 1998:
Proved developed 40,542 464,046 10,575 128,458
Proved undeveloped 3,820 127,923 917 26,058
Total proved 44,362 591,969 11,492 154,516
Production (7,083) (85,665) (2,766) (24,127)
Discoveries and extensions 935 81,470 1,563 16,076
Divestitures (8) (7,648) (4) (1,287)
Acquisitions 74,494 453,764 27,002 177,123
Revisions 6,291 30,600 3,335 14,726
Net increase 74,629 472,521 29,130 182,513
As of December 31, 1999:
Proved developed 104,554 960,753 38,739 303,419
Proved undeveloped 14,437 103,737 1,882 33,609
Total proved 118,991 1,064,490 40,622 337,028
<CAPTION>
Souhern Division
Oil Gas NGLs Total
(MBbls) (MMcf) (MBbls) (MBoe)
As of December 31, 1998:
Proved developed 89 5,018 2 927
Proved undeveloped - - - -
Total proved 89 5,018 2 927
Production (2,708) (39,231) (556) (9,803)
Discoveries and extensions 155 2,789 31 651
Divestitures (2,481) (136) - (2,504)
Acquisitions 31,514 349,670 5,707 95,499
Revisions (36) 1,486 (2) 210
Net increase 26,444 314,578 5,180 84,054
As of December 31, 1999:
Proved developed 23,613 285,378 4,898 76,074
Proved undeveloped 2,920 34,218 285 8,908
Total proved 26,533 319,596 5,182 84,981
<CAPTION>
Canada
Oil Gas NGLs Total
(MBbls) (MMcf) (MBbls) (MBoe)
As of December 31, 1998:
Proved developed 33,215 583,583 4,504 134,983
Proved undeveloped 5,791 18,324 81 8,926
Total proved 39,006 601,907 4,585 143,909
Production (5,178) (73,561) (700) (18,138)
Discoveries and extensions 219 52,698 448 9,450
Divestitures (1,883) (45,672) (138) (9,633)
Acquisitions 2,796 11,890 86 4,864
Revisions (2,828) (41,044) (268) (9,937)
Net increase (6,874) (95,689) (572) (23,394)
As of December 31, 1999:
Proved developed 29,268 501,376 3,865 116,696
Proved undeveloped 2,864 4,842 148 3,819
Total proved 32,132 506,218 4,013 120,515
<CAPTION>
International
Oil Gas NGLs Total
(MBbls) (MMcf) (MBbls) (MBoe)
As of December 31, 1998:
Proved developed - - - -
Proved undeveloped - - - -
Total proved - - - -
Production (447) - - (447)
Discoveries and extensions - - - -
Divestitures - - - -
Acquisitions 126,708 6,223 - 127,745
Revisions - - - -
Net increase 126,261 6,223 - 127,298
As of December 31, 1999:
Proved developed 13,814 3,878 - 14,460
Proved undeveloped 112,447 2,345 - 112,838
Total proved 126,261 6,223 - 127,298
</TABLE>
2000 Estimates
The forward-looking statements provided in this
discussion are based on management's examination of
historical operating trends, the December 31, 1999 reserve
reports of independent petroleum engineers and other data in
Devon's possession or available from third parties. Devon
cautions that its future oil, gas and NGLs production,
revenues and expenses are subject to all of the risks and
uncertainties normally incident to the exploration for and
development and production and sale of oil and gas. These
risks include, but are not limited to, price volatility,
inflation or lack of availability of goods and services,
environmental risks, drilling risks, regulatory changes, the
uncertainty inherent in estimating future oil and gas
production or reserves, and other risks as outlined below.
Also, the financial results of Devon's foreign operations
are subject to currency exchange rate risks. Additional
risks are discussed below in the context of line items most
affected by such risks.
Specific Assumptions and Risks Related to Price and
Production Estimates Prices for oil, natural gas and NGLs
are determined primarily by prevailing market conditions.
Market conditions for these products are influenced by
regional and world-wide economic growth, weather and other
substantially variable factors. These factors are beyond
Devon's control and are difficult to predict. In addition
to volatility in general, Devon's oil, gas and NGLs prices
may vary considerably due to differences between regional
markets, transportation availability and demand for
different grades of oil, gas and NGLs. Over 97% of Devon's
revenues are attributable to sales of these three
commodities. Consequently, Devon's financial results and
resources are highly influenced by this price volatility.
Estimates for Devon's future production of oil, natural
gas and NGLs are based on the assumption that market demand
and prices for oil and gas will continue at levels that
allow for profitable production of these products. There
can be no assurance of such stability.
Certain of Devon's individual oil and gas properties,
such as the Northeast Blanco Unit in the San Juan Basin, are
of a size such that significant declines in production at
these properties could have a material impact on the overall
financial results.
The production, transportation and marketing of oil,
natural gas and NGLs are complex processes which are subject
to disruption due to transportation and processing
availability, mechanical failure, human error,
meteorological events including, but not limited to,
hurricanes, and numerous other factors. The following
forward-looking statements were prepared assuming demand,
curtailment, producibility and general market conditions for
Devon's oil, natural gas and NGLs for 2000 will be
substantially similar to those of 1999, unless otherwise
noted. Given the general limitations expressed herein,
Devon's forward-looking statements for 2000 are set forth
below. Unless otherwise noted, all of the following dollar
amounts are expressed in U.S. dollars. Those amounts
related to Canadian operations have been converted to U.S.
dollars using the year-end 1999 exchange rate of $0.6929
U.S. dollar to $1.00 Canadian dollar. The actual 2000
exchange rate may vary materially from the year-end 1999
rate used. Such variations could have a material effect on
the following Canadian estimates.
Year 2000 Potential Operating Items
Oil Production Devon expects its oil production in
2000 to total between 21.1 million barrels and 23.9 million
barrels. Northern Division production is expected to be
between 9.8 million barrels and 11.1 million barrels,
Southern Division production is expected to be between 5.7
million barrels and 6.5 million barrels, Canadian production
is expected to be between 4.3 million barrels and 4.9
million barrels, and International production is expected to
be between 1.3 million barrels and 1.4 million barrels.
Oil Prices Devon expects its 2000 net oil prices per
barrel will average from $1.50 to $2.40 above West Texas
Intermediate ("WTI") posted prices for its Northern Division
production and $0.10 to $0.95 above WTI posted prices for
its Southern Division production.
Devon expects to receive a price from $1.25 and $2.25
below WTI posted prices for its Canadian production. This
expected range includes an estimated $0.30 per barrel
decrease resulting from foreign currency hedges. These
hedges, in which Devon will sell $30 million in 2000 at an
average Canadian-to-U.S. exchange rate of $0.726 and buy the
same amount of dollars at the floating exchange rate, offset
a portion of the exposure to currency fluctuations on those
Canadian oil sales that are based on U.S. prices. The $0.30
per barrel decrease is based on the assumption that the year-
end 1999 Canadian-to-U.S. conversion rate of $0.6929 remains
constant during 2000.
Almost 90% of expected International oil production in
2000 is in Venezuela. Due to the terms of the controlling
production sharing contract, the net price Devon records for
its Venezuelan oil production is substantially less than WTI
posted prices.
Gas Production Devon expects its 2000 gas production
to total between 269 Bcf and 306 Bcf. It is expected that
Northern Division production will be between 115 Bcf and 130
Bcf, and Southern Division production will be between 93 Bcf
and 106 Bcf. Canadian production is expected to be between
61 Bcf and 70 Bcf. No significant gas production is
expected in 2000 from Devon's International properties.
Gas Prices - Fixed Through various fixed price
contracts or hedging instruments, Devon has fixed the price
it will receive in 2000 on a portion of its natural gas
production. The Northern Division has fixed volumes of 9.5
Bcf at $1.97 per Mcf, which is a modest amount of total
expected Northern Division production. Devon's Canadian
operation has fixed volumes of 25.6 Bcf at $1.44 per Mcf,
which is a more significant amount of total expected
Canadian production.
Gas Prices - Floating For the gas production for which
prices have not been fixed, Devon's Northern Division
production is expected to average from $0.25 less than Texas
Gulf Coast spot averages ("TGC") to $0.05 more than TGC,
Southern Division production is expected to average from an
amount equal to TGC to $0.30 more than TGC and Canadian
production is expected to average from $0.40 to $0.80 less
than the New York Mercantile Exchange price ("NYMEX").
NGLs Production Devon expects its 2000 production of
NGLs to total between 6.6 million barrels and 7.6 million
barrels. Between 4.7 million barrels and 5.4 million
barrels are expected to be produced in the Northern
Division, between 1.5 million barrels and 1.7 million
barrels are expected to be produced in the Southern
Division, and between 0.4 million barrels and 0.5 million
barrels are expected to be produced in Canada. No
significant NGLs production is expected in 2000 from Devon's
International properties.
Other Revenues Devon's other revenues in 2000 are
expected to be between $29 million and $33 million.
Approximately $18.5 million of 2000's expected other
revenues is from dividends on Devon's investment of 7.1
million shares of Chevron Corporation common stock.
Production and Operating Expenses Devon's production
and operating expenses vary in response to several factors.
Among the most significant of these factors are additions to
or deletions from Devon's property base, changes in
production taxes, general changes in the prices of services
and materials that are used in the operation of the
properties and the amount of repair and workover activity
required.
Oil, gas and NGLs prices will have a direct effect on
production taxes to be incurred in 2000. Future prices also
could have an effect on whether proposed workover projects
are economically feasible. These factors, coupled with the
uncertainty of future oil, gas and NGLs prices, increase the
uncertainty inherent in estimating future production and
operating costs. Given these uncertainties, Devon estimates
that year 2000 total production and operating costs will be
between $288 million and $318 million.
Depreciation, Depletion and Amortization ("DD&A") The
2000 oil and gas property DD&A rate will depend on various
factors. Most notable among such factors are the amount of
proved reserves that could be added from drilling or
acquisition efforts in 2000 compared to the costs incurred
for such efforts, and the revisions to Devon's year-end 1999
reserve estimates that, based on prior experience, are
likely to be made during 2000.
As of the current date, Devon has not finalized its
1999 results. Therefore, the actual oil and gas property
DD&A rate as of January 1, 2000, is not available. However,
such rate is expected to be between $5.30 per Boe and $5.50
per Boe. Assuming a full year 2000 oil and gas property
DD&A rate of between $5.25 per Boe and $6.00 per Boe, Devon
expects that its consolidated oil and gas property DD&A
expense in 2000 will be between $400 million and $460
million.
In addition to its oil and gas property DD&A expense,
Devon also expects to record goodwill amortization in 2000
of between $37 million and $41 million. The goodwill was
recorded in connection with the PennzEnergy merger.
Additionally, Devon expects its 2000 DD&A expense related to
non-oil and gas property fixed assets to total between $27
million and $29 million.
General and Administrative Expenses ("G&A") Devon's
G&A includes the costs of many different goods and services
used in support of its business. These goods and services
are subject to general price level increases or decreases.
In addition, Devon's G&A varies with its level of activity
and the related staffing needs as well as with the amount of
professional services required during any given period.
Should Devon's needs or the prices of the required goods and
services differ significantly from current expectations,
actual G&A could vary materially from the estimate. Given
these limitations, consolidated G&A in 2000 is expected to
be between $48 million and $53 million.
Interest Expense Future interest rates and oil,
natural gas and NGLs prices have a significant effect on
Devon's interest expense. Approximately $1.2 billion of
Devon's January 21, 2000, long-term debt balance of $1.7
billion bears interest at fixed rates. Such fixed rates
remove the uncertainty of future interest rates from some,
but not all, of Devon's long-term debt. Also, Devon can
only marginally influence the prices, and the resulting cash
flow, it will receive in 2000 from sales of oil, gas and
NGLs. These factors increase the margin of error inherent
in estimating future interest expense. Other factors which
affect interest expense, such as the amount and timing of
capital expenditures, are within Devon's control. Given the
uncertainty of future interest rates and commodity prices,
Devon estimates that the consolidated interest expense in
2000 will be between $103 million and $114 million.
Deferred Effect of Changes in Foreign Currency Exchange
Rate on Subsidiary's Long-term Debt Devon's Canadian subsidiary
Northstar Energy Corporation had $225 million of U.S. dollar
denominated debt that gave rise to this item in prior periods.
This debt was retired in January, 2000. Therefore, there
will be no significant deferred effect of changes in foreign
currency exchange rate on subsidiary's long-term debt
recognized in 2000.
Reduction of Carrying Value of Oil and Gas Properties
As of December 31, 1999, the full cost ceiling exceeded
Devon's carrying value of oil and gas properties, less
deferred income taxes. However, such excess could easily be
eliminated by declines in oil and/or gas prices between year-
end 1999 and the end of any quarter during 2000. The result
would be a 2000 reduction of the carrying value of oil and
gas properties.
Income Taxes Devon expects its consolidated financial
income tax rate in 2000 to be between 48% and 57%. These
rates are the combined current and deferred tax rates.
There are certain items that will have a fixed impact on
2000's income tax expense regardless of the level of pre-tax
earnings that are produced. These items include Section 29
tax credits in the U.S., which reduce income taxes based on
production levels of certain properties and are not
necessarily affected by pre-tax financial earnings. The
amount of Section 29 tax credits expected to be used to
offset financial income tax expense in 2000 is approximately
$4 million. Also, Devon's Canadian subsidiaries are subject
to Canada's "large corporation tax" of approximately $2
million which is based on total capitalization levels, not
pre-tax earnings. The financial income tax in 2000 will
also be increased by approximately $16 million due to the
financial amortization of certain costs, such as goodwill
amortization, that are not deductible for income tax
purposes. Significant changes in estimated production
levels of oil, gas and NGLs, the prices of such products, or
any of the various expense items could materially alter the
effect of the aforementioned items on 2000's financial
income tax rates.
Based on its current expectations of 2000 taxable
income, Devon anticipates its current portion of 2000 income
taxes will be $36 million to $40 million. However,
unanticipated revenue and/or expense fluctuations could
easily make these tax estimates inaccurate.
Property Acquisitions and Divestitures Though Devon
has completed several major property acquisitions in recent
years, these transactions are opportunity driven. Thus,
Devon does not "budget," nor can it reasonably predict, the
timing or size of such possible acquisitions, if any.
During 2000, Devon contemplates the disposition of
certain oil and gas properties (the "Disposition
Properties"). The Disposition Properties are predominantly
properties that are either outside of Devon's core-operating
areas or otherwise do not fit Devon's current strategic
objectives. Most, but not all, of such properties were
acquired in the August 1999, merger with PennzEnergy
Company. The Disposition Properties are located in the
U.S., Canada and other International areas. At this time,
Devon is in the early stages of the disposition process, and
it is impossible to identify when, or if, the dispositions
will occur.
The estimates of Devon's 2000 results set forth above
include the full-year results from the Disposition
Properties without any effect given to their potential
disposition. The actual effect the dispositions will have
on Devon's overall estimates will depend upon the actual
timing of the dispositions. The estimated full-year results
from the Disposition Properties that are included in the
overall 2000 estimates above include oil production of
between 4.1 million barrels and 4.6 million barrels, gas
production of between 2.1 Bcf and 2.3 Bcf, NGLs production
of between 0.9 million barrels and 1.0 million barrels and
production and operating expenses of between $37.8 million
and $41.8 million.
Because Devon is in the early stages of the disposition
process, it is difficult to accurately predict the amount of
proceeds to be generated from the property dispositions.
However, the dispositions are expected to increase Devon's
oil and gas property depreciation, depletion and
amortization rate by $0.35 per Boe to $0.45 per Boe after
all dispositions are completed.
Capital Sources, Uses and Liquidity
Capital Expenditures Devon's capital expenditures
budget is based on an expected range of future oil, natural
gas and NGLs prices as well as the expected costs of the
capital additions. Should Devon's price expectations for
its future production change significantly, some projects
may be accelerated or deferred and, consequently, may
increase or decrease total 2000 capital expenditures. In
addition, if the actual costs of the budgeted items vary
significantly from the anticipated amounts, actual capital
expenditures could vary materially from Devon's estimates.
Though Devon has completed several major property
acquisitions in recent years, these transactions are
opportunity driven. Thus, Devon does not "budget", nor can
it reasonably predict, the timing or size of such possible
acquisitions, if any.
The company expects its capital expenditures for the year
2000 will be materially higher than those for 1999. For 1999
the company's capital expenditures for drilling and development
efforts will have been between $220 million and $250 million.
However, for the year 2000, the company expects capital
expenditures for drilling and development efforts to
total between $480 million and $510 million. These amounts
include between $110 million and $130 million for drilling
and facilities costs related to reserves classified as
proved as of year-end 1999. In addition, these amounts
include between $240 million and $260 million for other low
risk/reward projects and between $120 million and $130
million for new, higher risk/reward projects. The following
table shows expected drilling and facilities expenditures by
major operating division.
<TABLE>
Drilling and Production Facilities Expenditures ($ in millions)
Northern Southern Inter-
Division Division Canada national
<S> <C> <C> <C> <C>
Related to Proved Reserves $60-$70 $30-$35 $5-$10 $8-$12
Lower Risk/Reward Projects $100-$110 $65-$75 $70-$80 ---
Higher Risk/Reward Projects $15-$20 $45-$50 $30-$35 $22-$28
Total $175-$200 $140-$160 $105-$125 $30-$40
</TABLE>
In addition to the above expenditures for drilling and
development, Devon is participating through a joint venture
in the construction of gas gathering and processing systems
in the Powder River Basin of Wyoming. Devon expects to
spend from $10 million to $20 million as its share of the
project in 2000. Devon also expects to capitalize between
$25 million and $35 million of G&A expenses in accordance
with the full cost method of accounting. Also, Devon
expects to spend from $10 million to $20 million for
plugging and abandonment costs on some of its oil and gas
properties.
Other Cash Uses Devon's management expects the policy
of paying a quarterly dividend to continue. With the
current $0.05 per share quarterly dividend rate and 86.1
million shares of common stock outstanding, 2000 dividends
are expected to approximate $17 million.
Capital Resources and Liquidity Devon's estimated 2000
cash uses, including its drilling and development
activities, are expected to be funded primarily through a
combination of working capital and operating cash flow, with
the remainder, if any, funded with borrowings from Devon's
credit facilities. The amount of operating cash flow to be
generated during 2000 is uncertain due to the factors
affecting revenues and expenses as previously cited.
However, Devon expects its combined capital resources to be
more than adequate to fund its anticipated capital
expenditures and other cash uses for 2000. As of January
21, 2000, Devon had $337 million available under its $750
million credit facilities. If significant acquisitions or
other unplanned capital requirements arise during the year,
Devon could utilize its existing credit facilities and/or
seek to establish and utilize other sources of financing.
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
Vice President - Accounting
Date: January 26, 2000
