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| DVN > SEC Filings for DVN > Form 10-Q on 7-May-2009 | All Recent SEC Filings |
7-May-2009
Quarterly Report
• The combined realized price without hedges for oil, gas and NGLs decreased 56% to $24.39 per Boe.
• Marketing and midstream operating profit decreased 18% to $142 million.
• Per unit operating costs decreased 16% to $9.19 per Boe.
• Oil and gas hedges generated a net gain of $154 million in the first quarter of 2009 and a net loss of $788 million in the first quarter of 2008. Included in these amounts were cash receipts of $118 million and payments of $8 million, respectively.
• General and administrative expenses increased 12% to $166 million.
• Operating cash flow decreased 54% to $1.0 billion in the first quarter of 2009.
• Cash spent on capital expenditures was approximately $2.0 billion in the first quarter of 2009. Approximately half this amount was funded with operating cash flow and the remainder was funded with commercial paper borrowings.
Additionally, in January 2009, we issued $500 million of 5.625% senior
unsecured notes due January 15, 2014 and $700 million of 6.30% senior unsecured
notes due January 15, 2019. The net proceeds received of $1.187 billion, after
discounts and issuance costs, were used primarily to repay our $1.0 billion of
outstanding commercial paper as of December 31, 2008.
Although oil and gas prices remain depressed compared to recent highs
achieved in 2008, and our operating cash flow has been negatively impacted, we
expect to have adequate liquidity to execute our near-term operating strategy
and maintain momentum on our longer-term projects. As of April 30, 2009, we had
unused lines of credit totaling $2.2 billion and continue to have access to the
commercial paper market. We anticipate these capital sources combined with our
operating cash flow will be sufficient to fund our planned capital expenditures
and other capital uses over the near-term.
Results of Operations
Revenues
The three-month comparison of our oil, gas and NGL production, prices and
revenues for the first quarters of 2009 and 2008 are shown in the following
tables. The amounts for all periods presented exclude our West African
operations that were sold in the second and third quarters of 2008 and are
classified as discontinued operations in our financial statements.
Total
Three Months Ended March 31,
2009 2008 Change(2)
Production
Oil (MMBbls) 13 14 -5 %
Gas (Bcf) 245 223 +10 %
NGLs (MMBbls) 7 7 +6 %
Total (MMBoe)(1) 62 58 +6 %
Realized prices without hedges
Oil (per Bbl) $ 33.61 $ 88.23 -62 %
Gas (per Mcf) $ 3.73 $ 7.31 -49 %
NGLs (per Bbl) $ 18.60 $ 47.40 -61 %
Combined (per Boe)(1) $ 24.39 $ 55.07 -56 %
Revenues ($ in millions)
Oil sales $ 454 $ 1,250 -64 %
Gas sales 913 1,630 -44 %
NGL sales 136 328 -58 %
Total $ 1,503 $ 3,208 -53 %
Domestic
Three Months Ended March 31,
2009 2008 Change(2)
Production
Oil (MMBbls) 4 4 -12 %
Gas (Bcf) 192 171 +12 %
NGLs (MMBbls) 6 6 +8 %
Total (MMBoe)(1) 43 39 +9 %
Realized prices without hedges
Oil (per Bbl) $ 36.89 $ 95.70 -61 %
Gas (per Mcf) $ 3.53 $ 7.24 -51 %
NGLs (per Bbl) $ 17.53 $ 44.86 -61 %
Combined (per Boe)(1) $ 22.11 $ 49.84 -56 %
Revenues ($ in millions)
Oil sales $ 150 $ 443 -66 %
Gas sales 676 1,236 -45 %
NGL sales 112 266 -58 %
Total $ 938 $ 1,945 -52 %
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Canada
Three Months Ended March 31,
2009 2008 Change(2)
Production
Oil (MMBbls) 6 5 +35 %
Gas (Bcf) 53 52 +2 %
NGLs (MMBbls) 1 1 -5 %
Total (MMBoe)(1) 16 14 +13 %
Realized prices without hedges
Oil (per Bbl) $ 27.89 $ 72.68 -62 %
Gas (per Mcf) $ 4.48 $ 7.53 -41 %
NGLs (per Bbl) $ 25.85 $ 62.67 -59 %
Combined (per Boe)(1) $ 27.21 $ 55.42 -51 %
Revenues ($ in millions)
Oil sales $ 177 $ 340 -48 %
Gas sales 236 389 -39 %
NGL sales 24 62 -61 %
Total $ 437 $ 791 -45 %
International
Three Months Ended March 31,
2009 2008 Change(2)
Production
Oil (MMBbls) 3 5 -36 %
Gas (Bcf) - - -45 %
NGLs (MMBbls) - - N/M
Total (MMBoe)(1) 3 5 -36 %
Realized prices without hedges
Oil (per Bbl) $ 41.00 $ 96.08 -57 %
Gas (per Mcf) $ 3.47 $ 8.41 -59 %
NGLs (per Bbl) $ - $ - N/M
Combined (per Boe)(1) $ 40.68 $ 95.24 -57 %
Revenues ($ in millions)
Oil sales $ 127 $ 467 -73 %
Gas sales 1 5 -77 %
NGL sales - - N/M
Total $ 128 $ 472 -73 %
(1) Gas volumes
are
converted to
Boe or MMBoe
at the rate
of six Mcf
of gas per
barrel of
oil, based
upon the
approximate
relative
energy
content of
gas and oil,
which rate
is not
necessarily
indicative
of the
relationship
of oil and
gas prices.
NGL volumes
are
converted to
Boe on a
one-to-one
basis with
oil.
(2) All
percentage
changes
included in
this table
are based on
actual
figures and
are not
calculated
using the
rounded
figures
included in
this table.
N/M Not
meaningful.
The volume and price changes in the tables above caused the following changes
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Oil Gas NGLs Total
(In millions)
2008 sales $ 1,250 $ 1,630 $ 328 $ 3,208
Changes due to volumes (59 ) 159 19 119
Changes due to prices (737 ) (876 ) (211 ) (1,824 )
2009 sales $ 454 $ 913 $ 136 $ 1,503
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Oil Sales
Oil sales decreased $737 million in the first quarter of 2009 as a result of
a 62% decrease in our realized price without hedges. The average NYMEX West
Texas Intermediate index price decreased 56% during the same time period,
accounting for the majority of the decrease.
Oil sales decreased $59 million in the first quarter of 2009 due to a one
million barrel decrease in production. Our International production decreased
approximately two million barrels due to reaching certain cost recovery
thresholds of our carried interest in Azerbaijan. Also, we deferred
approximately 0.3 million barrels of Gulf of Mexico oil production due to
hurricanes. These decreases were partially offset by additional production of
almost two million barrels from our Jackfish operation in Canada.
Gas Sales
Gas sales decreased $876 million during the first quarter of 2009 as a result
of a 49% decrease in our realized price without hedges. This decrease was
largely due to decreases in the North American regional index prices upon which
our gas sales are based.
A 22 Bcf increase in production during the first quarter of 2009 caused gas
sales to increase by $159 million. Our drilling and development program in the
Barnett Shale field in north Texas contributed 15 Bcf to the gas production
increase. This increase and the effect of new drilling and development in our
other North American properties were partially offset by natural production
declines, mainly in the Gulf of Mexico, and the deferral of two Bcf of
production due to hurricane damage suffered in the third quarter of 2008.
NGL Sales
NGL sales decreased $211 million during the first quarter of 2009 as a result
of a 61% decrease in our realized price without hedges. This decrease was
largely due to decreases in the regional index prices upon which our NGL sales
are based.
Net Gain (Loss) on Oil and Gas Derivative Financial Instruments
The following tables provide financial information associated with our oil
and gas hedges for the first quarters of 2009 and 2008. The first table presents
the cash settlements and unrealized gains and losses recognized as components of
our revenues. The subsequent tables present our oil, gas and NGL prices with,
and without, the effects of the cash settlements for the first quarters of 2009
and 2008. The prices do not include the effects of unrealized gains and losses.
Three Months Ended March 31,
2009 2008
(In millions)
Cash settlements:
Gas price swaps $ - $ (8 )
Gas price collars 118 -
Total cash settlements received (paid) 118 (8 )
Unrealized gains (losses) on fair value changes:
Gas price swaps - (371 )
Gas price collars 36 (408 )
Oil price collars - (1 )
Total unrealized gains (losses) on fair value changes 36 (780 )
Net gain (loss) on oil and gas derivative financial instruments $ 154 $ (788 )
Three Months Ended March 31, 2009
Oil Gas NGLs Total
(Per Bbl) (Per Mcf) (Per Bbl) (Per Boe)
Realized price without hedges $ 33.61 $ 3.73 $ 18.60 $ 24.39
Cash settlements of hedges - 0.48 - 1.91
Realized price, including cash settlements $ 33.61 $ 4.21 $ 18.60 $ 26.30
|
Three Months Ended March 31, 2008
Oil Gas NGLs Total
(Per Bbl) (Per Mcf) (Per Bbl) (Per Boe)
Realized price without hedges $ 88.23 $ 7.31 $ 47.40 $ 55.07
Cash settlements of hedges - (0.04 ) - (0.14 )
Realized price, including cash settlements $ 88.23 $ 7.27 $ 47.40 $ 54.93
|
In the first quarter of 2009, our derivative financial instruments were
comprised of gas price collars. In the first quarter of 2008, our derivative
financial instruments included gas price swaps and oil and gas price collars.
For the price swaps, we receive a fixed price for our production and pay a
variable market price to the contract counterparty. The price collars set a
floor and ceiling price. If the applicable monthly price indices are outside of
the ranges set by the floor and ceiling prices in the various collars, we
cash-settle the difference with the counterparty to the collars. Cash
settlements as presented in the tables above represent realized losses or gains
related to our price swaps and collars.
During the first quarter of 2009, we received $118 million, or $0.48 per Mcf
from counterparties to settle our gas price collars. During the first quarter of
2008, we paid $8 million, or $0.04 per Mcf, to counterparties to settle our gas
price swaps and collars.
In addition to recognizing these cash settlement effects, we also recognize
unrealized changes in the fair values of our oil and gas derivative instruments
in each reporting period. We estimate the fair values of our oil and gas
derivative financial instruments primarily by using internal discounted cash
flow calculations. From time to time, we validate our valuation techniques by
comparing our internally generated fair value estimates with those obtained from
contract counterparties and/or brokers.
The most significant variable to our cash flow calculations is our estimate
of future commodity prices. We base our estimate of future prices upon published
forward commodity price curves such as the Inside FERC Henry Hub forward curve
for gas instruments and the NYMEX West Texas Intermediate forward curve for oil
instruments. Based on the amount of volumes subject to our gas price collars at
March 31, 2009, a 10% increase in these forward curves would have decreased our
first quarter 2009 unrealized gain for our gas collar derivative financial
instruments by approximately $29 million. Another key input to our cash flow
calculations is our estimate of volatility for these forward curves, which we
base primarily upon implied volatility.
Counterparty credit risk is also a component of commodity derivative
valuations. We have mitigated our exposure to any single counterparty by
contracting with numerous counterparties. Our commodity derivative contracts are
held with eight separate counterparties. Additionally, our derivative contracts
generally require cash collateral to be posted if either our or the
counterparty's credit rating falls below "investment grade". The threshold for
collateral posting decreases as the debt rating falls further below investment
grade. Such thresholds generally range from zero to $50 million for the majority
of our contracts. As of March 31, 2009, the credit ratings of all our
counterparties were investment grade.
During the first quarter of 2009, we recognized a $36 million unrealized gain
as a result of decreases in the Inside FERC Henry Hub forward curve subsequent
to December 31, 2008.
During the first quarter of 2008, we recognized unrealized losses totaling
$779 million related to our gas derivative instruments. These losses resulted
primarily from a significant increase in the Inside FERC Henry Hub forward curve
subsequent to our contract trade dates.
Marketing and Midstream Revenues and Operating Costs and Expenses The details of the changes in marketing and midstream revenues, operating costs and expenses and the resulting operating profit between the three months ended March 31, 2009 and 2008 are shown in the table below.
Three Months Ended March 31,
2009 2008 Change(1)
($ in millions)
Marketing and midstream:
Revenues $ 371 $ 555 -33 %
Operating costs and expenses 229 382 -40 %
Operating profit $ 142 $ 173 -18 %
|
(1) All percentage changes included in this table are based on actual figures and are not calculated using the rounded figures included in this table.
During the first quarter of 2009, marketing and midstream revenues decreased
$184 million and operating costs and expenses also decreased $153 million,
causing operating profit to decrease $31 million. Revenues and expenses
decreased primarily due to lower natural gas and NGL prices, partially offset by
increased gas pipeline throughput.
Oil, Gas and NGL Production and Operating Expenses
The details of the changes in oil, gas and NGL production and operating
expenses between the three months ended March 31, 2009 and 2008 are shown in the
table below.
Three Months Ended March 31,
2009 2008 Change(1)
($ in millions)
Production and operating expenses:
Lease operating expenses $ 524 $ 506 +4 %
Production taxes 42 134 -68 %
Total production and operating expenses $ 566 $ 640 -12 %
Production and operating expenses per Boe:
Lease operating expenses $ 8.50 $ 8.69 -2 %
Production taxes 0.69 2.30 -70 %
Total production and operating expenses per Boe $ 9.19 $ 10.99 -16 %
|
(1) All percentage changes included in this table are based on actual figures and are not calculated using the rounded figures included in this table.
Lease Operating Expenses ("LOE")
LOE increased $18 million in the first quarter of 2009. LOE increased
$29 million due to our 6% growth in production. Higher per-unit costs associated
with our thermal heavy oil production from our Jackfish operations in Canada and
new oil production from Brazil caused LOE to increase an additional $24 million.
Until these large-scale projects reach their target full-scale production
levels, their per-unit operating costs will be higher than the per-unit costs
for our overall portfolio of producing properties. LOE also increased $7 million
due to additional costs associated with damages of certain of our facilities and
transportation systems that were caused by Hurricane Ike in the third quarter of
2008. These increases were partially offset by the effects of changes in the
exchange rate between the U.S. and Canadian dollar. The exchange rate caused LOE
to decrease $43 million and was the main contributor to the decrease in LOE per
Boe.
Production Taxes
The following table details the changes in production taxes between the three
months ended March 31, 2009 and 2008. The majority of our production taxes are
assessed on our U.S. onshore properties and are based on a fixed percentage of
revenues. Production taxes are also assessed on certain of our International
properties based on a variable percentage of revenues that generally moves in
tandem with commodity prices. Therefore, the changes due to revenues in the
following table primarily relate to changes in oil, gas and NGL revenues from
our U.S. onshore and International properties.
Three Months
Ended March 31,
(In millions)
2008 production taxes $ 134
Change due to revenues (71 )
Change due to rate (21 )
2009 production taxes $ 42
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Depreciation, Depletion and Amortization Expenses ("DD&A") The changes in our production volumes, DD&A rate per unit and DD&A of oil and gas properties between the three months ended March 31, 2009 and 2008 are shown in the table below.
Three Months Ended March 31,
2009 2008 Change(1)
Total production volumes (MMBoe) 62 58 +6 %
DD&A rate ($ per Boe) $ 9.72 $ 12.64 -23 %
DD&A expense ($ in millions) $ 599 $ 737 -19 %
|
(1) All percentage changes included in this table are based on actual figures and are not calculated using the rounded figures included in this table.
The following table details the changes in DD&A of oil and gas properties between the three months ended March 31, 2009 and 2008.
Three Months
Ended March 31,
(In millions)
2008 DD&A $ 737
Change due to volumes 42
Change due to rate (180 )
2009 DD&A $ 599
|
The 6% production increase during the first quarter of 2009 caused oil and gas property related DD&A to increase $42 million. Oil and gas property-related DD&A decreased $180 million due to a 23% decrease in the DD&A rate. The largest contributors to the rate decrease were reductions of the carrying values of certain of our oil and gas properties recognized in the fourth quarter of 2008. These reductions totaled $10.4 billion and resulted from full cost ceiling limitations. In addition, the effects of changes in the exchange rate between the U.S. and Canadian dollar contributed to the rate decrease. These decreases were offset by the effects of inflationary pressure on costs incurred during most of 2008 and the transfer of previously unproved costs to the depletable base as a result of drilling activities. General and Administrative Expenses ("G&A") The following schedule includes the components of G&A expense for the three-month periods ended March 31, 2009 and 2008.
Three Months Ended March 31,
2009 2008 Change (1)
(In millions)
Gross G&A $ 305 $ 277 +10 %
Capitalized G&A (104 ) (99 ) +5 %
Reimbursed G&A (35 ) (30 ) +17 %
Net G&A $ 166 $ 148 +12 %
. . .
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