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| DVN > SEC Filings for DVN > Form 8-K on 5-Aug-2009 | All Recent SEC Filings |
5-Aug-2009
Other Events
"LIBOR" means London Interbank Offered Rate. "MMBbls" means million Bbls. "MMBoe" means million Boe. "MMBtu" means million Btu. "MMBtu/d" means million Btu per day. "Mcf" means thousand cubic feet. "MMcf" means million cubic feet. "NGL" or "NGLs" means natural gas liquids. |
"U.S. Offshore" means our operations encompassing oil and gas properties in
the Gulf of Mexico.
"U.S. Onshore" means our operations encompassing oil and gas properties in
the continental United States.
Forward-Looking Estimates
General Assumptions and Risks Related to Our Estimates
The forward-looking statements provided in this discussion are based on our
examination of historical operating trends, the information used to prepare our
December 31, 2008 reserve reports and other data in our possession or available
from third parties. We caution that our future oil, gas and NGL production,
revenues and expenses are subject to all of the risks and uncertainties normally
associated with exploring for, developing, producing and selling oil, gas and
NGLs. 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 discussed below.
Additionally, we caution that our future marketing and midstream revenues and
expenses are subject to all of the risks and uncertainties normally associated
with transporting oil, gas and NGLs and processing natural gas. These risks
include, but are not limited to, price volatility, environmental risks,
regulatory changes, the uncertainty inherent in estimating future processing
volumes and pipeline throughput, cost of goods and services and other risks
discussed below.
Also, the financial results of our foreign operations are subject to currency
exchange rate risks. Unless otherwise noted, all of the following dollar amounts
are expressed in U.S. dollars. Financial amounts related to our Canadian
operations have been converted to U.S. dollars using an estimated average 2009
exchange rate of $0.86 dollar to $1.00 Canadian dollar. The actual 2009 exchange
rate may vary materially from this estimate. Such variations could have a
material effect on these forward-looking estimates.
Other specific risks associated with our price and production estimates are
provided immediately below. Additional risks are discussed throughout this
report in the context of line items most affected by such risks.
Specific Assumptions and Risks Related to Price and Production Estimates
Prices for oil, gas and NGLs are determined primarily by prevailing market
conditions. Market conditions for these products are influenced by regional and
worldwide economic conditions, weather and other local market conditions. These
factors are beyond our control and are difficult to predict. In addition,
volatility in general oil, gas and NGL prices may vary considerably due to
differences between regional markets, differing quality of oil produced (i.e.,
sweet crude versus heavy or sour crude), differing Btu content of gas produced,
transportation availability and costs and demand for the various products
derived from oil, gas and NGLs. Substantially all of our revenues are
attributable to sales, processing and transportation of these three commodities.
Consequently, our financial results and resources are highly influenced by price
volatility. Although we expect this volatility to continue throughout 2009, we
expect 2009 oil, gas and NGL prices will be noticeably lower than those for
2008.
Estimates for future production of oil, gas and NGLs are based on the
assumption that market demand and prices for oil, gas and NGLs will continue at
levels that allow for profitable discovery and production of these products.
There can be no assurance of such stability. Most of our Canadian production of
oil, gas and NGLs is subject to government royalties that fluctuate with prices.
Thus, price fluctuations can affect reported production. Also, our production of
oil in Azerbaijan and China is governed by payout agreements with the
governments of these countries. If the payout under these agreements is attained
earlier than projected, our net production and proved reserves in such areas
could be reduced.
Estimates for future processing and transport of oil, gas and NGLs are based
on the assumption that market demand and prices for oil, gas and NGLs will
continue at levels that allow for profitable processing and transport of these
products. There can be no assurance of such stability.
The production, transportation, processing and marketing of oil, gas and NGLs
are complex processes which are subject to disruption due to transportation and
processing availability, mechanical failure, human error, hurricanes and other
meteorological events, and numerous other factors. The forward-looking estimates
in this report were prepared assuming demand, curtailment, producibility and
general market conditions for our oil, gas and NGLs during 2009 will be
substantially similar to those that existed in 2008, unless otherwise noted.
Geographic Reporting Areas
Our estimates of production, average price differentials compared to industry
benchmarks and capital expenditures included in this report are provided
separately for each of the following geographic areas:
• United States Onshore;
• United States Offshore;
• Canada; and
• International.
Operating Items
Oil, Gas and NGL Production
Set forth below are our estimates of oil, gas and NGL production for 2009. We
estimate that our combined 2009 oil, gas and NGL production will total
approximately 243 to 247 MMBoe. The following estimates for oil, gas and NGL
production are calculated at the midpoint of the estimated range for total
production.
Oil Gas NGLs Total
(MMBbls) (Bcf) (MMBbls) (MMBoe)
United States Onshore 12 693 25 153
United States Offshore 5 45 - 12
Canada 26 216 3 65
International 15 1 - 15
Total 58 955 28 245
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Oil and Gas Prices
We expect our 2009 average prices for the oil and gas production from each of
our operating areas to differ from the NYMEX price as set forth in the following
table. The expected ranges for gas prices are exclusive of the anticipated
effects of the gas financial contracts presented in the "Commodity Price Risk
Management" section below.
The NYMEX price for oil is the monthly average of settled prices on each
trading day for benchmark West Texas Intermediate crude oil delivered at
Cushing, Oklahoma. The NYMEX price for gas is determined to be the
first-of-month South Louisiana Henry Hub price index as published monthly in
Inside FERC.
Expected Range of Prices
as a % of NYMEX Price
Oil Gas
United States Onshore 85% to 95% 75% to 85%
United States Offshore 95% to 105% 100% to 110%
Canada 65% to 75% 83% to 93%
International 90% to 100% N/M
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N/M - Not meaningful.
Commodity Price Risk Management
From time to time, we enter into NYMEX related financial commodity collar and
price swap contracts. Such contracts are used to manage the inherent uncertainty
of future revenues due to oil and gas price volatility. Although these financial
contracts do not relate to specific production from our operating areas, they
will affect our overall revenues, earnings and cash flow in 2009.
As of August 3, 2009, our financial commodity contracts pertaining to 2009
consisted of gas price collars and swaps. The key terms of these contracts are
presented in the following table.
Gas Financial Contracts
Price Collar Contracts Price Swap Contracts
Floor Price Ceiling Price
Weighted Weighted Weighted
Floor Average Ceiling Average Average
Volume Range Price Range Price Volume Price
Period (MMBtu/d) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (MMBtu/d) ($/MMBtu)
First Quarter 277,056 $ 8.00 - $8.50 $ 8.25 $ 10.60 - $14.00 $ 12.02 - -
Second Quarter 265,000 $ 8.00 - $8.50 $ 8.25 $ 10.60 - $14.00 $ 12.05 - -
Third Quarter 265,000 $ 8.00 - $8.50 $ 8.25 $ 10.60 - $14.00 $ 12.05 52,174 $ 4.01
Fourth Quarter 265,000 $ 8.00 - $8.50 $ 8.25 $ 10.60 - $14.00 $ 12.05 600,000 $ 4.81
2009 Average 267,973 $ 8.00 - $8.50 $ 8.25 $ 10.60 - $14.00 $ 12.05 164,384 $ 4.75
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To the extent that monthly NYMEX prices in 2009 are outside of the ranges
established by the collars or differ from those established by the swaps, we and
the counterparties to the contracts will settle the difference. Such settlements
will either increase or decrease our revenues for the period. Also, we will
mark-to-market the contracts based on their fair values throughout 2009. Changes
in the contracts' fair values will also be recorded as increases or decreases to
our revenues. The expected ranges of our realized prices as a percentage of
NYMEX prices, which are presented earlier in this report, do not include any
estimates of the impact on our prices from monthly settlements or changes in the
fair values of our price collars and swaps.
In January 2009, we entered into an early settlement arrangement with one of
our counterparties. As a result of this early settlement, we received
$36 million in January 2009.
Marketing and Midstream Revenues and Expenses
Marketing and midstream revenues and expenses are derived primarily from our
gas processing plants and gas pipeline systems. These revenues and expenses vary
in response to several factors. The factors include, but are not limited to,
changes in production from wells connected to the pipelines and related
processing plants, changes in the absolute and relative prices of gas and NGLs,
provisions of contractual agreements and the amount of repair and maintenance
activity required to maintain anticipated processing levels and pipeline
throughput volumes.
These factors increase the uncertainty inherent in estimating future
marketing and midstream revenues and expenses. Given these uncertainties, we
estimate that our 2009 marketing and midstream operating profit will be between
$430 million and $500 million. We estimate that marketing and midstream revenues
will be between $1.18 billion and $1.40 billion, and marketing and midstream
expenses will be between $0.75 billion and $0.90 billion.
Production and Operating Expenses
Our production and operating expenses include lease operating expenses,
transportation costs and production taxes. These expenses vary in response to
several factors. Among the most significant of these factors are additions to or
deletions from the property base, changes in the general price level of services
and materials that are used in the operation of the properties, the amount of
repair and workover activity required and changes in production tax rates. Oil,
gas and NGL prices also have an effect on lease operating expenses and impact
the economic feasibility of planned workover projects.
Given these uncertainties, we expect that our 2009 lease operating expenses
will be between $1.93 billion and $2.27 billion. Additionally, we estimate that
our production taxes for 2009 will be between 3.00% and 3.50% of total oil, gas
and NGL revenues, excluding the effect on revenues from derivative contracts
upon which production taxes are not assessed.
Depreciation, Depletion and Amortization ("DD&A")
Our 2009 oil and gas property DD&A rate will depend on various factors. Most
notable among such factors are the amount of proved reserves that will be added
from drilling or acquisition efforts in 2009 compared to the costs incurred for
such efforts, revisions to our year-end 2008 reserve estimates that, based on
prior experience, are likely to be made during 2009, as well as reductions of
carrying value resulting from full cost ceiling tests.
Given these uncertainties, we estimate that our oil and gas property related
DD&A rate will be between $8.00 per Boe and $8.50 per Boe. Based on these DD&A
rates and the production estimates set forth earlier, oil and gas property
related DD&A expense for 2009 is expected to be between $1.95 billion and
$2.07 billion.
Additionally, we expect that our depreciation and amortization expense
related to non-oil and gas property fixed assets will total between $280 million
and $300 million in 2009.
Accretion of Asset Retirement Obligation
Accretion of asset retirement obligation in 2009 is expected to be between
$85 million and $95 million.
General and Administrative Expenses ("G&A")
Our G&A includes employee compensation and benefits costs and the costs of
many different goods and services used in support of our business. G&A varies
with the level of our operating activities and the related staffing and
professional services requirements. In addition, employee compensation and
benefits costs vary due to various market factors that affect the level and type
of compensation and benefits offered to employees. Also, goods and services are
subject to general price level increases or decreases. Therefore, significant
variances in any of these factors from current expectations could cause actual
G&A to vary materially from the estimate.
Given these limitations, we estimate our G&A for 2009 will be between
$650 million and $680 million. This estimate includes approximately $130 million
of non-cash, share-based compensation, net of related capitalization in
accordance with the full cost method of accounting for oil and gas properties.
Reduction of Carrying Value of Oil and Gas Properties
We follow the full cost method of accounting for our oil and gas properties.
Under the full cost method, our net book value of oil and gas properties, less
related deferred income taxes (the "costs to be recovered"), may not exceed a
calculated "full cost ceiling." The ceiling limitation is the discounted
estimated after-tax future net revenues from oil and gas properties plus the
cost of unevaluated properties. The ceiling is imposed separately by country. In
calculating future net revenues, current prices and costs used are those as of
the end of the appropriate quarterly period. These prices are not changed except
where different prices are fixed and determinable from applicable contracts for
the remaining term of those contracts. The costs to be recovered are compared to
the ceiling on a quarterly basis. If the costs to be recovered exceed the
ceiling, the excess is written off as an expense. An expense recorded in one
period may not be reversed in a subsequent period even though higher oil and gas
prices may have increased the ceiling applicable to the subsequent period.
Because the ceiling calculation dictates that prices in effect as of the last
day of the applicable quarter are held constant indefinitely, and requires a 10%
discount factor, the resulting value is not indicative of the true fair value of
the reserves. Oil and gas prices have historically been cyclical and, on any
particular day at the end of a quarter, can be either substantially higher or
lower than our long-term price forecast, which is a more appropriate input for
estimating fair value. Therefore, oil and gas property writedowns that result
from applying the full cost ceiling limitation, and that are caused by
fluctuations in price as opposed to reductions to the underlying quantities of
reserves, should not be viewed as absolute indicators of a reduction of the
ultimate value of the related reserves.
Because of the volatile nature of oil and gas prices, it is not possible to
predict whether we will incur full cost writedowns in the last half of 2009.
However, such writedowns may be more likely to occur in the future than in
recent periods, considering current and near-term estimates of oil and gas
prices.
In the first quarter of 2009, we recognized full cost ceiling writedowns
related to our oil and gas properties in the United States and Brazil. In the
fourth quarter of 2008, we also recognized full cost ceiling writedowns related
to our oil and gas properties in Canada, as well as the United States and
Brazil. These writedowns resulted primarily from significant declines in oil and
gas prices compared to previous quarter-end prices. The weighted average
wellhead prices used in the calculation of the full cost ceiling writedowns for
these countries are presented in the following table.
March 31, 2009 December 31, 2008
Country Oil Gas NGLs Oil Gas NGLs
United States $ 47.30 $ 2.67 $ 17.04 $ 42.21 $ 4.68 $ 16.16
Canada N/A N/A N/A $ 23.23 $ 5.31 $ 20.89
Brazil $ 36.71 N/A N/A $ 26.61 N/A N/A
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N/A - Not applicable.
The March 31, 2009 wellhead prices in the table above compare to the NYMEX
cash price of $49.66 per Bbl for crude oil and the Henry Hub spot price of $3.63
per MMBtu for natural gas. The December 31, 2008 wellhead prices in the table
above compare to the NYMEX cash price of $44.60 per Bbl for crude oil and the
Henry Hub spot price of $5.71 per MMBtu for natural gas. Should quarter-end
prices in the last half of 2009 approximate or decrease from these prices, the
likelihood that we will incur full cost writedowns during the last half of 2009
will increase.
Interest Expense
Future interest rates and debt outstanding have a significant effect on our
interest expense. We can only marginally influence the prices we will receive in
2009 from sales of oil, gas and NGLs and the resulting cash flow. This increases
the margin of error inherent in estimating future outstanding debt balances and
related interest expense. Other factors which affect outstanding debt balances
and related interest expense, such as the amount and timing of capital
expenditures are generally within our control.
As of June 30, 2009, we had total debt of $7.4 billion. This included
$6.1 billion of fixed-rate debt and $1.3 billion of variable-rate commercial
paper borrowings. The fixed-rate debt bears interest at an overall weighted
average rate of 7.23%. The commercial paper borrowings bear interest at variable
rates based on a standard index such as the Federal Funds Rate, LIBOR, or the
money market rate as found on the commercial paper market. As of June 30, 2009,
the weighted average variable rate for our commercial paper borrowings was
0.48%. Additionally, any future borrowings under our credit facilities would
bear interest at various fixed-rate options for periods up to twelve months and
are generally less than the prime rate.
Based on the factors above, we expect our 2009 interest expense to be between
$345 million and $355 million. This estimate assumes no material changes in
prevailing interest rates or to our existing interest rate swap contracts
presented later in this report. This estimate also assumes that our total debt
will increase approximately $1.7 billion during 2009, primarily in the form of
commercial paper borrowings.
The 2009 interest expense estimate above is comprised of three primary
components - interest related to outstanding debt, fees and issuance costs, and
capitalized interest. We expect the interest expense in 2009 related to our
fixed-rate and floating-rate debt, including net accretion of related discounts,
to be between $435 million and $445 million. We expect the interest expense in
2009 related to facility and agency fees, amortization of debt issuance costs
and other miscellaneous items not related to outstanding debt balances to be
between $5 million and $15 million. We also expect to capitalize between
$95 million and $105 million of interest during 2009.
Interest Rate Risk Management
We also have interest rate swaps to mitigate a portion of the fair value
effects of interest rate fluctuations on our fixed-rate debt. Under the terms of
these swaps, we receive a fixed rate and pay a variable rate on a total notional
amount of $1.15 billion. The key terms of these interest rate swaps as of
July 31, 2009 are presented in the following table.
Fixed Rate Variable
Notional Received Rate Paid Expiration
(In millions)
$ 500 3.90 % Federal funds rate July 18, 2013
$ 300 4.30 % Six month LIBOR July 18, 2011
$ 250 3.85 % Federal funds rate July 22, 2013
$ 100 1.90 % Federal funds rate August 3, 2012
$ 1,150 3.82 %
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Including the effects of these swaps, the weighted-average interest rate
related to our fixed-rate debt was 6.62% as of June 30, 2009.
Income Taxes
Our financial income tax rate in 2009 will vary materially depending on the
actual amount of financial pre-tax earnings. The tax rate for 2009 will be
significantly affected by the proportional share of consolidated pre-tax
earnings generated by U.S., Canadian and International operations due to the
different tax rates of each country. There are certain tax deductions and
credits that will have a fixed impact on 2009 income tax expense regardless of
the level of pre-tax earnings that are produced.
Given the uncertainty of pre-tax earnings, we expect that our consolidated
financial income tax rate in 2009 will be between 20% and 40%. The current
income tax rate is expected to be between 10% and 20%. The deferred income tax
rate is expected to be between 10% and 20%. Significant changes in estimated
capital expenditures, production levels of oil, gas and NGLs, the prices of such
products, marketing and midstream revenues, or any of the various expense items
could materially alter the effect of the aforementioned tax deductions and
credits on 2009 financial income tax rates.
Capital Resources, Uses and Liquidity
Capital Expenditures
Though we have completed several major property acquisitions in recent years,
these transactions are opportunity driven. Thus, we do not "budget," nor can we
reasonably predict, the timing or size of such possible acquisitions.
Our capital expenditures budget is based on an expected range of future oil,
gas and NGL prices as well as the expected costs of the capital additions.
Should actual prices received differ materially from our price expectations for
our future production, some projects may be accelerated or deferred and,
consequently, may increase or decrease total 2009 capital expenditures. In
addition, if the actual material or labor costs of the budgeted items vary
significantly from the anticipated amounts, actual capital expenditures could
vary materially from our estimates.
Given the limitations discussed above, the following table shows expected
ranges for drilling, development and facilities expenditures by geographic area.
Development capital includes development activity related to reserves classified
as proved and drilling that does not offset currently productive units and for
which there is not a certainty of continued production from a known productive
formation. Exploration capital includes exploratory drilling to find and produce
oil or gas in previously untested fault blocks or new reservoirs.
During the second quarter of 2009, our operations in Angola ceased to qualify
as discontinued operations. As a result, the capital expenditure estimates
related to our Angolan operations are now included in the continuing operations
amounts included in the table below.
United United
States States
. . .
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