HOUSTON, Feb. 7, 2012 /PRNewswire/ --
2011 Fourth-Quarter Average Daily Sales Volumes:
- Daily sales increased 13% to 105,396 barrels of oil equivalent
(BOE) per day, or 26% pro forma for asset sales, compared to
fourth-quarter 2010
- Oil/liquids volumes increased 12% to 52,262 barrels per day, or
16% pro forma for asset sales, compared to fourth-quarter 2010
2011 Full-Year Average Daily Sales Volumes:
- Daily sales increased 12% to 98,950 BOE per day, or 23% pro
forma for asset sales, compared to 2010
- Oil/liquids volumes increased 7% to 48,964 barrels per day, or
8% pro forma for asset sales, compared to 2010
2011 Total Proved Reserves:
- Total proved reserves, pro forma for asset sales, increased 16%
to 410.9 million BOE
- Standardized measure of discounted net cash flows increased 66%
to $5.1 billion from $3.1 billion in 2010
- PV-10 value increased 58% to $7.9 billion from $5.0
billion in 2010
- Reserve replacement is 222% or 290% pro forma for asset
sales
2011 Oil/Liquids Proved Reserves:
- Oil/liquids reserves, pro forma for asset sales, increased 18%
to 244.0 million barrels
- Oil/liquids are 59% of total proved, up from 54% in 2010
- Oil/liquids reserve replacement is 280%
- Oil/liquids reserve-to-pro forma production ratio is 14
years
Plains Exploration & Production Company (NYSE:PXP) ("PXP" or
the "Company") today reported preliminary 2011 operational results
and an update to its derivative position.
DAILY SALES VOLUMES
PXP's 2011 fourth-quarter daily sales volumes averaged 105,396
BOE per day, a 13% increase over 92,994 BOE per day in the
fourth-quarter of 2010. Adjusting for the 2010 and 2011 asset
divestments, the 13% sales volume increase would have been 26% and
2011 fourth-quarter daily sales volumes would have averaged 90,349
BOE per day.
PXP's 2011 fourth-quarter oil/liquids daily sales volumes
averaged 52,262 barrels per day, a 12% increase over 46,658 barrels
per day in the fourth-quarter 2010. Adjusting for the 2010 and 2011
asset divestments, the 12% sales volume increase would have been
16% and 2011 fourth-quarter daily sales volumes would have averaged
47,464 barrels per day.
The robust volume growth is driven primarily by strong
performance in the Eagle Ford Shale and Haynesville Shale asset
areas combined with steady, consistent performance in California.
In the Eagle Ford Shale, fourth-quarter daily sales
volumes averaged approximately 9,123 BOE per day net to PXP,
compared to approximately 1,500 BOE per day net to PXP from
November acquisition to end of the fourth-quarter 2010.
January 2012 volumes averaged
approximately 13,700 BOE per day compared to approximately 1,970
BOE per day net to PXP in January
2011. The Company had 6.9 net rigs operating on its acreage
at the end of January.
In California,
fourth-quarter average daily sales volumes were 40,003 BOE per day,
essentially flat compared to the fourth-quarter 2010; and in the
Haynesville Shale, fourth-quarter average daily sales volumes
were approximately 200 million cubic feet equivalent (MMcfe) net to
PXP compared to approximately 146 MMcfe in the fourth-quarter
2010.
PXP's 2011 full-year daily sales volumes averaged approximately
98,950 BOE per day, a 12% increase over full-year 2010 volumes of
88,451 BOE per day. Adjusting for the 2010 and 2011 asset
divestments, the 12% sales volume increase would have been 23% and
2011 full-year daily sales volumes would have averaged 82,197 BOE
per day.
PXP's 2011 full-year oil/liquids daily sales volumes averaged
48,964 barrels per day, a 7% increase over 45,943 barrels per day
in 2010. Adjusting for the 2010 and 2011 asset divestments, the 7%
sales volume increase would have been 8% and 2011 fourth-quarter
daily sales volumes would have averaged 43,858 barrels per day.
PROVED RESERVES
Year-end estimated proved reserves of 410.9 million BOE, net of
asset sales, were 59% oil, 55% developed and had a pre-tax PV-10
value of $7.9 billion, a 58% increase
over 2010 PV-10 value. The robust increase in the PV-10 value is
primarily attributable to a greater concentration of oil/liquids
reserves, higher oil/liquids reference prices and stronger
marketing contract terms for oil sales. Pro forma for asset sales,
proved reserves increased 16% over 2010 proved reserves.
In 2011, PXP added total proved reserves of 81.0 million BOE.
The Company reported a total of 75.2 million BOE of extensions and
discoveries, including 22.5 million BOE in the Eagle Ford Shale,
19.3 million BOE in the Gulf of
Mexico, and 25.5 million BOE in the Haynesville Shale, 4.3
million BOE of acquisitions and 1.5 million BOE of revisions. These
additions replaced 222% of 2011 production. Pro forma for asset
sales, PXP replaced 290% of 2011 production.
Oil/liquids proved reserves increased 9%, or 18% pro forma for
asset sales, due primarily to the rapidly expanding Eagle Ford
Shale asset area, project sanctioning of the Lucius development
located in the Gulf of Mexico, and
a higher oil reference price compared to 2010 resulting in positive
price related revisions in California.
Natural gas proved reserves decreased 13% due primarily to the
2011 asset sales. With persistent low natural gas prices and a
corresponding assumed reduction in the pace of development in the
Haynesville Shale, PXP classified 44 million BOE of its Haynesville
undeveloped reserves as probable undeveloped. These reserves meet
the reasonable certainty, economic and other conditions needed to
be classified as proved undeveloped reserves but the slower pace of
drilling extends the development of these reserves past five years.
PXP's reserve estimate, the Standardized Measure and PV-10
calculations are based on the twelve-month average of
first-day-of-the-month West Texas Intermediate spot oil price of
$95.99 per barrel and Henry Hub spot
natural gas price of $4.12 per
million British thermal unit. All prices were adjusted for energy
content, quality and basis differentials by area and were held
constant through the lives of the properties, unless prices are
defined by contractual arrangements, excluding escalations based
upon future conditions. A detailed breakdown of reserves and costs
incurred for 2011 will be provided when PXP reports full-year
results on February 23, 2012. The
following tables provide summary reconciliations.
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Estimated Proved Reserves
(MMBOE)
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2010 Year-end proved
reserves
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416.1
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2011 Extensions, discoveries,
revisions and other additions
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81.0
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2011 Divestments
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(49.7)
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2011 Production
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(36.5)
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2011 Year-end proved
reserves
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410.9
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Reserve replacement ratio
(1)
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222%
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Estimated Pro Forma Proved
Reserves (MMBOE) (2)
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2010 Year-end proved
reserves
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355.0
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2011 Extensions, discoveries,
revisions and other additions
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88.1
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2011 Divestments
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(1.8)
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2011 Pro forma
production
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(30.4)
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2011 Year-end proved
reserves
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410.9
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Pro forma reserve replacement
ratio (1)
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290%
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(1) Calculation: reserve
extensions, discoveries, revisions, and other additions divided by
production. The Reserve Replacement
Ratio is an indicator of PXP's ability
to replace annual production volume and grow reserves. It is
important to economically find and develop new reserves that offset
produced volumes and provide for future production given the
inherent decline of hydrocarbon reserves as they are produced. This
statistical indicator has limitations, including its predictive and
comparative value. As such, this metric should not be considered in
isolation or as a substitute for an analysis of PXP's performance
as reported under GAAP. Furthermore, this metric may not be
comparable to similarly titled measurements used by other
companies.
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(2) Reflects the impact of the
fourth-quarter property divestments.
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PV-10 to Standardized Measure
Reconciliation (in millions)
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Estimated undiscounted future
net cash flows before income taxes
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$
15,942.2
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Present value of estimated
future net cash flows before income taxes (PV-10) (1)
(2)
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$
7,884.5
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Discounted future income
taxes
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(2,750.3)
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Standardized measure of
discounted net cash flows
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$
5,134.2
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(1) PV-10 is
PXP's estimate of the present value of future net revenues from
proved oil and gas reserves after deducting estimated production
and ad valorem taxes, future capital costs and operating expenses,
but before deducting any estimates of future income taxes. PV-10 is
a non-GAAP, financial measure and generally differs from the
Standardized Measure, the most directly comparable GAAP financial
measure, because it does not include the effects of income taxes on
future cash flows. PV-10 should not be considered as an alternative
to the Standardized Measure as computed under GAAP.
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(2) PXP believes
PV-10 to be an important measure for evaluating the relative
significance of its oil and gas properties and that the
presentation of the non-GAAP financial measure of PV-10 provides
useful information to investors because it is widely used by
professional analysts and sophisticated investors in evaluating oil
and gas companies. Because there are many unique factors that can
impact an individual company when estimating the amount of future
income taxes to be paid, PXP believes the use of a pre-tax measure
is valuable for evaluating its company. PXP believes that most
other companies in the oil and gas industry calculate PV-10 on the
same basis.
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DEPRECIATION, DEPLETION AND AMORTIZATION
2011 fourth-quarter depreciation, depletion and amortization
(DD&A) is expected to be $21.79
per BOE. For the full-year 2011, DD&A is expected to be
$18.40 per BOE.
DERIVATIVE UPDATE
PXP converted 5,000 of the 22,000 barrels of oil per day (BOPD)
of Brent crude oil put option contracts in 2013 to three-way
collars. These modified three-way collars have a floor price of
$90 per barrel with a limit of
$70 per barrel and a weighted average
ceiling price of $126.08 and
eliminates approximately $11 million
of deferred premiums. PXP will continue to lower the deferred
premiums by converting put option spread contracts into three-way
collars.
Additionally, the Company entered into the following Brent oil
derivatives for 2013 and 2014:
- Brent crude oil put option spread contracts on 13,000 BOPD for
2013 with a floor price of $100 per
barrel and a limit of $80 per
barrel.
- Brent three-way collars on 25,000 BOPD for 2013 that have a
floor price of $100 per barrel with a
limit of $80 per barrel and a
weighted average ceiling price of $124.29 per barrel.
- Brent crude oil put option spread contracts on 20,000 BOPD for
2014 with a floor price of $90 per
barrel and a limit of $70 per
barrel.
PXP has elected not to use hedge accounting for these
derivatives and consequently the derivatives will be
marked-to-market with fair value gains and losses recognized
currently as a gain or loss on mark-to-market derivative contracts
on the income statement.
As of February 7, 2012, PXP had
the following outstanding commodity derivative contracts, all of
which settle monthly:
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Average
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Instrument
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Daily
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Average
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Deferred
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Period
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Type
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Volumes
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Price
(1)
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Premium
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Index
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Sales of Crude Oil
Production
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2012
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Feb -
Dec
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Three-way
collars (2)
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40,000
Bbls
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$100.00
Floor with a $80.00 Limit
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-
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Brent
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$120.00
Ceiling
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2013
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Jan -
Dec
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Put options
(3)
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17,000
Bbls
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$90.00 Floor
with a $70.00 Limit
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$6.253 per
Bbl
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Brent
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Jan -
Dec
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Put options
(4)
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13,000
Bbls
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$100.00
Floor with a $80.00 Limit
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$6.800 per
Bbl
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Brent
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Jan -
Dec
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Three-way
collars (5)
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25,000
Bbls
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$100.00
Floor with a $80.00 Limit
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-
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Brent
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$124.29
Ceiling
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Jan -
Dec
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Three-way
collars (6)
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5,000
Bbls
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$90.00 Floor
with a $70.00 Limit
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-
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Brent
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$126.08
Ceiling
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2014
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Jan -
Dec
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Put options
(7)
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20,000
Bbls
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$90.00 Floor
with a $70.00 Limit
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$6.555 per
Bbl
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Brent
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Sales of Natural Gas
Production
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2012
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Feb -
Dec
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Put options
(8)
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120,000
MMBtu
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$4.30 Floor
with a $3.00 Limit
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$0.298 per
MMBtu
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Henry Hub
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Feb -
Dec
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Three-way
collars (9)
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40,000
MMBtu
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$4.30 Floor
with a $3.00 Limit
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-
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Henry Hub
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$4.86
Ceiling
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2013
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Jan -
Dec
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Swap
contracts (10)
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110,000
MMBtu
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$4.27
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-
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Henry Hub
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(1)
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The average strike prices do not
reflect any premiums to purchase the put options.
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(2)
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If the index price is less than
the $100 per barrel floor, we receive the difference between the
$100 per barrel floor and the index price up to a maximum of $20
per barrel. We pay the difference between the index price and $120
per barrel if the index price is greater than the $120 per barrel
ceiling. If the index price is at or above $100 per barrel but at
or below $120 per barrel, no cash settlement is
required.
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(3)
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If the index price is less than
the $90 per barrel floor, we receive the difference between the $90
per barrel floor and the index price up to a maximum of $20 per
barrel less the option premium. If the index price is at or above
$90 per barrel, we pay only the option premium.
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(4)
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If the index price is less than
the $100 per barrel floor, we receive the difference between the
$100 per barrel floor and the index price up to a maximum of $20
per barrel less the option premium. If the index price is at or
above $100 per barrel, we pay only the option premium.
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(5)
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If the index price is less than
the $100 per barrel floor, we receive the difference between the
$100 per barrel floor and the index price up to a maximum of $20
per barrel. We pay the difference between the index price and
$124.29 per barrel if the index price is greater than the $124.29
per barrel ceiling. If the index price is at or above $100 per
barrel but at or below $124.29 per barrel, no cash settlement is
required.
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(6)
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If the index price is less than
the $90 per barrel floor, we receive the difference between the $90
per barrel floor and the index price up to a maximum of $20 per
barrel. We pay the difference between the index price and $126.08
per barrel if the index price is greater than the $126.08 per
barrel ceiling. If the index price is at or above $100 per barrel
but at or below $126.08 per barrel, no cash settlement is
required.
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(7)
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If the index price is less than
the $90 per barrel floor, we receive the difference between the $90
per barrel floor and the index price up to a maximum of $20 per
barrel less the option premium. If the index price is at or above
$90 per barrel, we pay only the option premium.
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(8)
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If the index price is less than
the $4.30 per MMBtu floor, we receive the difference between the
$4.30 per MMBtu floor and the index price up to a maximum of $1.30
per MMBtu less the option premium. If the index price is at or
above $4.30 per MMBtu, we pay only the option premium.
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(9)
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If the index price is less than
the $4.30 per MMBtu floor, we receive the difference between the
$4.30 per MMBtu floor and the index price up to a maximum of $1.30
per MMBtu. We pay the difference between the index price and $4.86
per MMBtu if the index price is greater than the $4.86 per MMBtu
ceiling. If the index price is at or above $4.30 per MMBtu but at
or below $4.86 per MMBtu, no cash settlement is
required.
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(10)
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If the index price is less than
the $4.27 per MMBtu fixed price, we receive the difference between
the $4.27 per MMBtu fixed price and the index price. We pay the
difference between the index price and the fixed price if the index
price is greater than the fixed price.
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CREDIT SUISSE ENERGY SUMMIT
PXP is scheduled to present at the 2012 Credit Suisse Energy
Summit on Tuesday, February 7, 2012
at 8:45 a.m. Mountain time. A live
webcast and a copy of the presentation will be available in the
Investor Information section of PXP's website at www.pxp.com.
EARNINGS CONFERENCE CALL
PXP is scheduled to release 2011 fourth-quarter and year-end
results on Thursday, February 23,
2012 before the market opens and will host its quarterly
conference call that same day at 8:00 a.m.
Central time. Investors wishing to participate in the
conference call may dial 1-800-567-9836 or 1-973-935-8460. The
conference call and replay ID is: 42174570. The replay can be
accessed by dialing 1-855-859-2056 or 1-404-537-3406. A live
webcast of the conference call and a slide presentation will be
available in the Investor Information section of PXP's website at
www.pxp.com.
PXP is an independent oil and gas company primarily engaged in
the activities of acquiring, developing, exploring and producing
oil and gas in California,
Texas, Louisiana, and the Gulf of Mexico. PXP is headquartered in
Houston, Texas.
ADDITIONAL INFORMATION & FORWARD-LOOKING
STATEMENTS
This press release contains forward-looking information
regarding PXP that is intended to be covered by the safe harbor
"forward-looking statements" provided by the Private Securities
Litigation Reform Act of 1995. All statements included in this
press release that address activities, events or developments that
PXP expects, believes or anticipates will or may occur in the
future are forward-looking statement. These include statements
regarding:
* reserve and production estimates,
* oil and gas prices,
* the impact of derivative positions,
* production expense estimates,
* cash flow estimates,
* future financial performance,
* capital and credit market conditions,
* planned capital expenditures, and
* other matters that are discussed in PXP's filings with the
SEC.
These statements are based on our current expectations and
projections about future events and involve known and unknown
risks, uncertainties, and other factors that may cause our actual
results and performance to be materially different from any future
results or performance expressed or implied by these
forward-looking statements. Please refer to our filings with the
SEC, including our Form 10-K, for a discussion of these risks.
References to quantities of oil or natural gas may include
amounts that the Company believes will ultimately be produced, but
that are not yet classified as "proved reserves" under SEC
definitions.
All forward-looking statements in this press release are made as
of the date hereof, and you should not place undue reliance on
these statements without also considering the risks and
uncertainties associated with these statements and our business
that are discussed in this press release and our other filings with
the SEC. Moreover, although we believe the expectations reflected
in the forward-looking statements are based upon reasonable
assumptions, we can give no assurance that we will attain these
expectations or that any deviations will not be material. Except as
required by law, we do not intend to update these forward-looking
statements and information.
SOURCE Plains Exploration & Production Company