Amends Haynesville Shale Joint Venture Agreement With Chesapeake
Energy HOUSTON, Aug. 6 /PRNewswire-FirstCall/ -- Plains Exploration
& Production Company (NYSE:PXP) ("PXP" or the "Company")
announces quarterly results, an operations update, and amends the
Haynesville Shale joint venture agreement. SECOND QUARTER FINANCIAL
HIGHLIGHTS -- Adjusted net income was $171 million, or $1.44 per
diluted share (a non-GAAP measure), which includes realized gains
and losses and excludes unrealized gains and losses on our
mark-to-market derivative contracts, a legal settlement recovery,
and a beneficial income tax effect from a change in the balance of
our unrecognized tax benefits. -- Net income, as reported, was
$43.6 million, or $0.37 per diluted share. -- Operating cash flow
was approximately $392 million (a non-GAAP measure), which does not
include the $87.3 million legal settlement received during the
quarter. -- Total production costs were $14.43 per barrel of oil
equivalent (BOE). -- Daily sales volumes were 80.6 thousand BOE. An
explanation and reconciliation of all non-GAAP financial measures
used in this release is included with the financial tables in this
release. James C. Flores, Chairman, President and CEO of PXP
commented, "The second quarter of 2009 is noted for the operational
and financial results that everyone at PXP worked hard to achieve
and that better positioned our Company during the challenging low
commodity price environment gripping our industry. Strong
production with lower operational and administrative costs, plus
effective hedging has proven essential for our business to remain
profitable. Continued progress on the current operational and
financial aspects of our business, as well as fully evaluating our
outstanding exploration portfolio throughout the second half of the
year, should position PXP for long-term incremental expansion of
both production and reserves beyond the development of our existing
assets in California and the Haynesville Shale. "As part of our
conservative long-term financial strategy, we are announcing today
an amendment to the joint venture agreement with Chesapeake Energy
that provides for us to pay the remaining Haynesville Shale
drilling carries, originally agreed to in July 2008, on a
discounted and accelerated basis. PXP previously agreed to fund 50%
of Chesapeake's share of drilling and completion costs for future
Haynesville Shale wells up to $1.65 billion over a several year
period. On August 5, 2009, PXP and Chesapeake entered into an
amendment that provides for PXP to pay $1.1 billion of an estimated
$1.25 billion carry balance on September 29, 2009. This represents
an approximate 12% reduction in the total amount of drilling carry
commitments due to Chesapeake. In addition, Chesapeake has agreed
to maintain a minimum level of activity on the jointly owned
Haynesville acreage by drilling a minimum of 150 wells during each
of the next three twelve month periods commencing on October 1,
2009. After the closing of the amendment, PXP and Chesapeake will
each pay their proportionate working interest costs on future
drilling. "By pre-paying this carry, we unlock potential capital
for PXP's other high quality assets and allow PXP to achieve an
appropriate long-term financing structure that correlates with our
tremendous Haynesville Shale assets. This structure maintains our
balance sheet strength and increases our financial flexibility on a
go forward basis to increase investment in our existing oil and gas
leasehold. As a result, we are projecting our production growth
rate to double to 8-10% in 2010 and +10% in 2011 forward while
simultaneously improving the equilibrium between operating cash
flow and capital spending. "PXP will remain focused on its
conservative financial strategy while aggressively deploying both
development and exploration capital to expand current production
and reserves as well as position the Company for consistent growth
in the future." CONSERVATIVE FINANCIAL STRATEGY -- PXP had no
amounts outstanding under its $1.34 billion senior revolving credit
facility and held approximately $455.8 million in cash at quarter
end. Debt-to-capitalization was 43% at June 30, 2009 compared to
54% at year-end 2008. -- Approximately 80% of our 2009 estimated
sales volumes, using the mid-point of our annual guidance, are
protected by oil and natural gas derivative positions and natural
gas physical purchases. For 2009, natural gas volumes are protected
with $10 by $20 collars on 150,000 MMBtu per day while crude oil
volumes have put options with a $55 strike price on 32,500 barrels
per day. For 2010, PXP acquired natural gas three-way collars on
45,000 MMBtu per day bringing the total natural gas derivative
position to 85,000 MMBtu per day. Crude oil volumes for 2010 have
put options with a $55 strike price on 40,000 barrels per day. A
summary of PXP's open commodity derivative positions is located
after the financial tables in this release. AGGRESSIVE OPERATIONAL
STRATEGY -- PXP and its partner, and operator, Chesapeake Energy
Corporation (NYSE:CHK), have drilled and completed 74 horizontal
wells in the Haynesville Shale and continue to experience
outstanding drilling results. PXP now owns approximately 113,000
net acres of leasehold in the Haynesville Shale with 1,400
potential net drilling locations and 6.8 Tcfe of estimated net
resource potential. -- Haynesville Shale average daily net
production during the second quarter 2009 was 28 million cubic feet
equivalent (MMCFE) per day net to PXP, a 100% increase from the 14
MMCFE per day net average during the first quarter 2009. Current
production is approximately 43 MMCFE per day net to PXP and is
expected to exceed approximately 70 MMCFE net per day by year-end
2009 and approximately 125 MMCFE net per day by year-end 2010. The
joint venture expects to operate an average of 33 rigs in the
second half of 2009 and 36 rigs in 2010. -- During the second
quarter there were three exceptional wells as noted by the
operator: The CLD 23 H-1 in Caddo Parish, Louisiana commenced
production on June 22, 2009 and achieved a peak rate of 29.1 MMCFE
per day and a pipeline-constrained first 30-day average rate of
15.3 MMCFE per day. The Frith 29 H-1 in De Soto Parish, Louisiana
commenced production on June 27, 2009 and achieved a
pipeline-constrained peak rate of 23.7 MMCFE per day and a
pipeline-constrained first 30-day average rate of 14.2 MMCFE per
day. The Chesapeake Royalty LLC 30 H-1 in De Soto Parish, Louisiana
commenced production on June 27, 2009 and achieved a
pipeline-constrained peak rate of 22.6 MMCFE per day and a
pipeline-constrained first 30-day average rate of 15.2 MMCFE per
day. -- The Flatrock area wells are producing over 65 MMCFE per day
net to PXP. As previously reported, in May 2009 the operator
completed a planned facility expansion at the Tiger Shoal
production facility. -- Positive drilling results at the Blueberry
Hill deep gas exploratory well, operated by McMoRan and located on
Louisiana State Lease 340 in the Gulf of Mexico, indicate a
potential discovery. As previously reported, the exploratory
sidetrack well was drilled to a true vertical depth of 21,900 feet
and log-while-drilling tools indicated resistive zones
approximating 150 gross feet. Operations are currently underway to
deepen the well to a proposed total depth of 24,000 feet to assess
deeper targets. PXP holds a 47.9% working interest. -- A drilling
rig is on location at the Davy Jones prospect. McMoRan, as the
operator, is re-entering a previously abandoned well bore located
on South Marsh Island Block 230 in the Gulf of Mexico, which had
been drilled to 19,957 feet, and plans to deepen the well to a
proposed total depth of 28,000 feet. PXP has a 30.8% working
interest. -- Four more high-potential exploration prospects, each
one with a reserve potential of more than 100 million barrels of
oil equivalent net to PXP, are currently drilling or will begin
drilling during the third quarter 2009. -- The Friesian #2 well,
operated by PXP and located in Green Canyon 643, is preparing to
drill below 31,000 feet towards a proposed total depth of over
34,000 feet. The drilled portion of the Friesian #2 well shows
strong correlation, both geologic and pressure, with the initial
Miocene field pay sands at the Tahiti Field. The well has
encountered a total of 478 net feet of oil pay of which 389 net
feet was encountered in the initial well and 89 net feet
encountered in the deeper section of the well. A liner has been set
and plans are to re-drill the M-18 sand and drill ahead to the M-21
sands, the prolific main field equivalent sands at the Tahiti
Field. Well results are expected during the third quarter 2009. --
The Northwood exploration prospect, operated by Chevron and located
on Green Canyon Block 945 in the Gulf of Mexico, began drilling in
the second quarter and is currently below 27,000 feet drilling
towards a proposed total depth of approximately 32,000 feet. PXP
holds a 27.5% working interest. -- The Rickenbacker exploration
prospect, operated by Anadarko and located on Keathley Canyon Block
470 in the Gulf of Mexico, is scheduled to begin drilling in the
third quarter 2009. PXP holds a 15% working interest. -- The Purple
Tiger exploration prospect, operated by PXP and located on Block
124 offshore Vietnam, is scheduled to begin drilling in the third
quarter 2009. PXP holds a 100% working interest. -- The Salida
exploration prospect, located on Garden Banks Block 988 in the Gulf
of Mexico, was drilled to a total depth of approximately 27,300
feet and is being plugged and abandoned. -- PXP is currently
evaluating its exposure to the recently announced positive industry
Granite Wash results in the Texas Panhandle. PXP holds leases
covering 9,040 gross and about 5,650 net acres in the Stiles Ranch
Field area in Wheeler County, Texas. The acreage is located within
the productive trend of horizontal drilling that is targeting
multiple Pennsylvanian Granite Wash/Atoka Wash reservoirs. In
addition to the horizontal potential at Wheeler, PXP is also
evaluating the horizontal potential of the Marvin Lake Area in
Hemphill County, Texas where PXP holds approximately 14,000
gross/net acres. PXP has identified a minimum of 29 horizontal well
locations targeting discrete units within the Granite Wash/Atoka
Wash section. More information is being obtained and added to the
interpretation both regionally and locally. It is likely that more
locations will be identified as additional information is
integrated and the critical criteria for economically attractive
horizontal targets are better defined. -- PXP is evaluating its
exposure to the recently announced positive industry discovery in
Kern County, California. The discovery area is under evaluation and
apparently consists of conventional oil and gas bearing formations.
PXP holds approximately 9,800 net acres in the Kern County area. --
PXP's T-Ridge project, offshore California, continues to maintain
strong support and has benefited from the attention it received
during the recent high profile California budget debate. Although
the California State Assembly failed to approve legislation
authorizing a path forward for the T-Ridge project, PXP intends to
continue pushing for the project based on its merits to the state
of California. The project has received support from Santa Barbara
County, the California State Senate, the Governor and a large
environmental coalition, including the Environmental Defense
Center, Trust for Public Land, and "Get Oil Out", as well as
firefighters and peace officers throughout the state. More than two
dozen environmental groups have urged approval for T-Ridge because
of the significant merits of the project. We will aggressively
utilize this time to address and remedy any misconceptions that
groups and individuals may have regarding the project. The T-Ridge
project utilizes an existing platform and facilities operating off
the Santa Barbara coast to access oil and gas reserves currently
drained by PXP and upon project approval will include a steady new
revenue stream to the state of California, as well as a range of
significant environmental protections and offsets. THREE MONTHS
ENDED JUNE 30, 2009 For the second quarter 2009, PXP reported
adjusted net income of $171.2 million, or $1.44 per diluted share
(a non-GAAP measure), which includes realized gains and losses and
excludes unrealized gains and losses on our mark-to-market
derivative contracts, an $87.3 million pre-tax legal settlement
recovery, and a beneficial income tax effect from a change in the
balance of our unrecognized tax benefits. Net income, as reported,
was $43.6 million, or $0.37 per diluted share, on revenues of
$278.7 million. Daily sales volumes for the second quarter 2009
were 80.6 thousand BOE compared to 87.5 thousand BOE for the prior
year period. Lower volumes primarily reflect the impact of the 2008
divestments. Excluding divestments, higher production from our
Flatrock and Haynesville Shale properties is primarily responsible
for a 9% increase in sales volumes in the second quarter 2009
compared to the same period a year ago. Total production costs
decreased 30% to $14.43 per BOE for the second quarter 2009
compared to the prior year period. Lower per unit lease operating
expense, steam gas costs and production and ad valorem tax costs
accounted for the year-over-year improvement. Lease operating
expense per unit reflects the impact of our cost reduction program
implemented earlier this year. Total general and administrative
costs declined 17% during the second quarter 2009 compared to the
prior year period. The cost reduction program contributed to this
improvement. The average realized sales price before derivatives
was $49.44 per barrel of oil and $3.37 per Mcf of natural gas for
the second quarter 2009. The average realized cash sales price
including derivative settlements (a non-GAAP measure) was $86.32
per barrel and $8.17 per Mcf for the period. Cash margin (a
non-GAAP measure) was $57.16 per BOE in the second quarter 2009
compared to $68.05 per BOE in the second quarter 2008. Oil and gas
capital expenditures were $452.1 million for the second quarter
2009 compared to $231.5 million for the prior year period. SIX
MONTHS ENDED JUNE 30, 2009 For the first six months of 2009, PXP
reported adjusted net income of $304.8 million, or $2.68 per
diluted share (a non-GAAP measure), which includes realized gains
and losses and excludes unrealized gains and losses on our
mark-to-market derivative contracts, debt extinguishment costs, a
legal settlement recovery, and a beneficial income tax effect from
a change in the balance of our unrecognized tax benefits. Net
income, as reported, was $48.8 million, or $0.43 per diluted share,
on revenues of $507.2 million. Daily sales volumes for the first
six months of 2009 were 80.7 thousand BOE compared to 91.6 thousand
BOE for the same period in 2008. The variance primarily reflects
the impact of the 2008 divestments. Total production costs per BOE
were 20% lower for the first six months of 2009 compared to the
same period in 2008. Lower per unit lease operating, steam gas and
production and ad valorem tax costs accounted for the
year-over-year improvement. Total general and administrative costs
declined 12% for the first six months of 2009 compared to the same
period in 2008. Operating cash flow (a non-GAAP measure) was $735.3
million for the first six months of 2009 compared to $902.7 million
for the same period in 2008. FULL-YEAR GUIDANCE UPDATE For 2009,
PXP has increased its capital budget to $1.4 billion from $1.05
billion. The increase reflects our participation in anticipated
additional Haynesville Shale wells and additional acreage purchases
offset by the elimination of the Haynesville carry commitments in
the fourth quarter combined with slower than anticipated reduction
in rig rates and service costs as well as additional Gulf of Mexico
high-potential exploratory drilling. PXP reaffirms the previously
announced estimated full-year 2009 daily sales volumes of 78 to 82
thousand BOE. PXP is targeting a 2010 capital budget of
approximately $1.0 billion of which 45% is uncommitted capital. PXP
estimates its full-year 2010 daily sales volumes to be 86 to 90
thousand BOE. CONFERENCE CALL PXP will host a conference call
today, Thursday, August 6, 2009 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: 19203752. The replay can be accessed by dialing 1-800-642-1687
or 1-706-645-9291. A live webcast of the conference call will be
available in the Investor Information section of PXP's website at
http://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 statements. 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 the year ended December 31, 2008,
for a discussion of these risks. All forward-looking statements in
this report 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 report 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 for any obligation to disclose material
information under the Federal securities laws, we do not intend to
update these forward-looking statements and information. Plains
Exploration & Production Company Consolidated Statements of
Income (Unaudited) (amounts in thousands, except per share data)
Three Months Ended Six Months Ended June 30, June 30, --------
-------- 2009 2008 2009 2008 ---- ---- ---- ---- Revenues Oil sales
$219,589 $545,767 $376,203 $1,002,351 Gas sales 58,541 182,334
129,805 346,403 Other operating revenues 551 4,602 1,185 7,026 ---
----- ----- ----- 278,681 732,703 507,193 1,355,780 ------- -------
------- --------- Costs and Expenses Production costs Lease
operating expenses 63,404 85,248 134,288 159,756 Steam gas costs
10,912 40,599 26,469 72,757 Electricity 12,368 10,661 23,310 22,298
Production and ad valorem taxes 10,457 24,181 22,078 50,409
Gathering and transportation expenses 8,671 2,462 15,318 10,951
General and administrative 37,554 45,203 74,647 85,131
Depreciation, depletion and amortization 90,822 130,749 178,936
271,602 Accretion 3,556 3,223 7,087 6,610 Legal settlement recovery
(87,272) - (87,272) - Other operating expenses 1,499 - 5,956 -
----- --- ----- --- 151,971 342,326 400,817 679,514 ------- -------
------- ------- Income from Operations 126,710 390,377 106,376
676,266 Other Income (Expense) Gain on sale of assets - - - 34,658
Interest expense (15,935) (23,511) (37,932) (54,120) Debt
extinguishment costs (667) - (10,910) (10,263) Loss on mark-to-
market derivative contracts (89,717) (51,427) (1,578) (60,908)
Other income 899 1,686 192 1,661 --- ----- --- ----- Income Before
Income Taxes 21,290 317,125 56,148 587,294 Income tax benefit
(expense) Current 43,730 (61,716) (12,061) (102,253) Deferred
(21,371) (52,491) 4,760 (118,622) ------- ------- ----- --------
Net Income $43,649 $202,918 $48,847 $366,419 ======= ========
======= ======== Earnings per share Basic $0.37 $1.88 $0.43 $3.33
Diluted $0.37 $1.84 $0.43 $3.27 Weighted Average Shares Outstanding
Basic 118,145 107,707 112,979 109,939 ======= ======= =======
======= Diluted 118,798 110,138 113,541 112,147 ======= =======
======= ======= Plains Exploration & Production Company
Operating Data (Unaudited) Three Months Ended Six Months Ended June
30, June 30, -------- -------- 2009 2008 2009 2008 ---- ---- ----
---- Daily Average Volumes Oil and liquids sales (Bbls) 48,792
55,153 49,092 56,399 Gas (Mcf) Production 197,500 200,358 196,727
217,573 Used as fuel 6,422 6,015 6,797 6,236 Sales 191,078 194,343
189,930 211,337 BOE Production 81,710 88,546 81,880 92,662 Sales
80,638 87,543 80,747 91,622 Unit Economics (in dollars) Average
NYMEX Prices Oil $59.79 $123.80 $51.68 $111.12 Gas 3.50 10.90 4.17
9.50 Average Realized Sales Price Before Derivative Transactions
Oil (per Bbl) $49.44 $108.74 $42.33 $97.65 Gas (per Mcf) 3.37 10.31
3.77 9.01 Per BOE 37.90 91.40 34.62 80.89 Cash Margin per BOE (1)
Oil and gas revenues $37.90 $91.40 $34.62 $80.89 Costs and expenses
Lease operating expenses (8.64) (10.70) (9.19) (9.58) Steam gas
costs (1.49) (5.10) (1.81) (4.36) Electricity (1.69) (1.34) (1.59)
(1.34) Production and ad valorem taxes (1.43) (3.04) (1.51) (3.02)
Gathering and transportation (1.18) (0.31) (1.05) (0.66) Oil and
gas related DD&A (11.49) (15.70) (11.49) (15.73) ------ ------
------ ------ Gross margin (GAAP) 11.98 55.21 7.98 46.20 Oil and
gas related DD&A 11.49 15.70 11.49 15.73 Realized gains and
losses on derivative instruments (2) 33.69 (2.86) 35.28 (2.35)
----- ----- ----- ----- Cash margin (Non-GAAP) $57.16 $68.05 $54.75
$59.58 ====== ====== ====== ====== Oil and gas capital expenditures
accrued ($ in thousands) (3) $452,060 $231,534 $802,418 $449,647
(1) Cash margin per BOE (a non-GAAP measure) is calculated by
adjusting gross margin per BOE (a GAAP measure) to include realized
gains and losses on derivative instruments and to exclude DD&A.
Management believes this presentation may be helpful to investors
as it represents the cash generated by our oil and gas production
that is available for, among other things, capital expenditures and
debt service. PXP management uses this information to analyze
operating trends for comparative purposes within the industry. This
measure is not intended to replace the GAAP statistic but rather to
provide additional information that may be helpful in evaluating
trends and performance. (2) Second quarter and six month 2009
amounts include $37.82 per barrel or $22.89 per BOE attributable to
April-June 2009 production and $25.34 per barrel or $15.41 per BOE
attributable to March-June 2009 production, respectively, for the
$106 crude oil puts and $54 crude oil swaps that were monetized in
the first quarter of 2009. Year to date amounts also include $13.66
per barrel or $8.31 per BOE associated with the January and
February settlement of the $106 crude oil puts and the $54 crude
oil swaps that we monetized in the first quarter of 2009. (3)
Additions to oil and gas properties reported in our consolidated
statement of cash flows differ from the accrual basis amounts
reflected above due to the timing of cash payments. Plains
Exploration & Production Company Reconciliation of GAAP to
Non-GAAP Measure Three Months Ended June 30, 2009
------------------- Oil Gas BOE --- --- --- Average Realized Sales
Price Average realized price before derivative instruments (GAAP)
(1) $49.44 $3.37 $37.90 Realized gains on derivative instruments
(2) 36.88 4.80 33.69 ----- ---- ----- Realized cash price including
derivative settlements (non- GAAP) $86.32 $8.17 $71.59 ====== =====
====== Three Months Ended June 30, 2008 ------------------- Oil Gas
BOE --- --- --- Average Realized Sales Price Average realized price
before derivative instruments (GAAP) (1) $108.74 $10.31 $91.40
Realized gains and losses on derivative instruments (4.54) - (2.86)
----- --- ----- Realized cash price including derivative
settlements (non- GAAP) $104.20 $10.31 $88.54 ======= ====== ======
(1) Excludes the impact of production costs and expenses and
DD&A. (2) Includes $37.82 per barrel or $22.89 per BOE
attributable to April- June 2009 production for the $106 crude oil
puts and $54 crude oil swaps that we monetized in the first quarter
of 2009. Six Months Ended June 30, 2009 --------------------- Oil
Gas BOE --- --- --- Average Realized Sales Price Average realized
price before derivative instruments (GAAP) (1) $42.33 $3.77 $34.62
Realized gains on derivative instruments (2) 41.40 4.30 35.28 -----
---- ----- Realized cash price including derivative settlements
(non- GAAP) $83.73 $8.07 $69.90 ====== ===== ====== Six Months
Ended June 30, 2008 --------------------- Oil Gas BOE --- --- ---
Average Realized Sales Price Average realized price before
derivative instruments (GAAP) (1) $97.65 $9.01 $80.89 Realized
gains and losses on derivative instruments (3.86) 0.01 (2.35) -----
---- ----- Realized cash price including derivative settlements
(non- GAAP) $93.79 $9.02 $78.54 ====== ===== ====== (1) Excludes
the impact of production costs and expenses and DD&A. (2)
Includes $25.34 per barrel or $15.41 per BOE attributable to March-
June 2009 production for the $106 crude oil puts and $54 crude oil
swaps that were monetized in the first quarter of 2009. Also
includes $13.66 per barrel or $8.31 per BOE associated with the
January and February settlement of the $106 crude oil puts and the
$54 crude oil swaps that we monetized in the first quarter of 2009.
Plains Exploration & Production Company Consolidated Statements
of Cash Flows (Unaudited) (in thousands of dollars) Three Months
Ended Six Months Ended June 30, June 30, -------- -------- 2009
2008 2009 2008 ---- ---- ---- ---- CASH FLOWS FROM OPERATING
ACTIVITIES Net income $43,649 $202,918 $48,847 $366,419 Items not
affecting cash flows from operating activities Gain on sale of
assets - - - (34,658) Depreciation, depletion, amortization and
accretion 94,378 133,972 186,023 278,212 Deferred income tax
expense (benefit) 21,371 52,491 (4,760) 118,622 Debt extinguishment
costs 667 - 10,910 10,263 Loss on mark- to-market derivative
contracts 89,717 51,427 1,578 60,908 Noncash compensation 18,067
28,378 32,566 40,451 Other noncash items 1,087 1,936 2,913 2,886
Change in assets and liabilities from operating activities (97,895)
(146,514) (136,387) (233,741) ------- -------- -------- --------
Net cash provided by operating activities 171,041 324,608 141,690
609,362 ------- ------- ------- ------- CASH FLOWS FROM INVESTING
ACTIVITIES Additions to oil and gas properties (410,611) (186,423)
(826,961) (441,123) Acquisition of oil and gas properties -
(311,136) - (331,293) Acquisition of Pogo Producing Company -
(62,625) - (74,844) Proceeds from sales of oil and gas properties
and related assets, net of costs and expenses - 7,901 - 1,717,781
Derivative settlements 86,165 (12,946) 1,380,322 (29,593) Decrease
in restricted cash and cash held in escrow - 339,974 - 59,092
Additions to other property and equipment (3,541) (4,754) (9,360)
(27,443) Other - 505 - (1,229) --- --- --- ------ Net cash (used
in) provided by investing activities (327,987) (229,504) 544,001
871,348 -------- -------- ------- ------- CASH FLOWS FROM FINANCING
ACTIVITIES Revolving credit facilities Borrowings - 1,083,315
2,240,090 4,237,756 Repayments - (1,532,315) (3,545,090)
(5,831,756) Proceeds from issuance of Senior Notes 185,938 400,000
523,099 400,000 Costs incurred in connection with financing
arrangements (5,573) (5,927) (12,114) (6,064) Derivative
settlements - (7,898) 1,392 (13,088) Issuance of common stock
250,874 - 250,874 - Purchase of treasury stock - (32,385) -
(304,192) Other 28 (5,709) 28 13,682 --- ------ --- ------ Net cash
provided by (used in) financing activities 431,267 (100,919)
(541,721) (1,503,662) ------- -------- -------- ---------- Net
increase (decrease) in cash and cash equivalents 274,321 (5,815)
143,970 (22,952) Cash and cash equivalents, beginning of period
181,524 8,309 311,875 25,446 ------- ----- ------- ------ Cash and
cash equivalents, end of period $455,845 $2,494 $455,845 $2,494
======== ====== ======== ====== Plains Exploration & Production
Company Consolidated Balance Sheets (Unaudited) (in thousands of
dollars) June 30, December 31, 2009 2008 ---- ---- ASSETS Current
Assets Cash and cash equivalents $455,845 $311,875 Accounts
receivable 175,875 175,896 Commodity derivative contracts 138,457
945,838 Inventories 19,718 23,368 Other current assets 35,775
19,464 ------ ------ 825,670 1,476,441 ------- --------- Property
and Equipment, at cost Oil and natural gas properties - full cost
method Subject to amortization 7,808,889 7,106,785 Not subject to
amortization 2,606,628 2,513,424 Other property and equipment
120,350 110,990 ------- ------- 10,535,867 9,731,199 Less allowance
for depreciation, depletion, amortization and impairment
(5,391,935) (5,217,803) ---------- ---------- 5,143,932 4,513,396
--------- --------- Goodwill 535,265 535,265 ------- -------
Commodity Derivative Contracts 852 530,181 --- ------- Other Assets
58,338 56,632 ------ ------ $6,564,057 $7,111,915 ==========
========== LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities
Accounts payable $350,542 $363,713 Royalties and revenues payable
73,532 87,874 Interest payable 34,528 20,843 Income taxes payable -
102,948 Deferred income taxes 91,385 285,426 Other current
liabilities 114,234 132,841 ------- ------- 664,221 993,645 -------
------- Long-Term Debt 2,024,129 2,805,000 --------- ---------
Other Long-Term Liabilities Asset retirement obligation 166,429
159,473 Other 45,125 32,061 ------ ------ 211,554 191,534 -------
------- Deferred Income Taxes 955,124 744,456 ------- -------
Stockholders' Equity Common stock 1,267 1,129 Additional paid-in
capital 2,987,761 2,739,625 Retained earnings (deficit) (36,254)
(85,101) Accumulated other comprehensive income (loss) - (684)
Treasury stock, at cost (243,745) (277,689) -------- --------
2,709,029 2,377,280 --------- --------- $6,564,057 $7,111,915
========== ========== Plains Exploration & Production Company
Summary of Open Derivative Positions At July 1, 2009 Average
Instrument Daily Average Deferred Period (1) Type Volumes Price(2)
Premium Index Sales of Crude Oil Production 2009 July - Dec Put
options 32,500 $55.00 Strike $3.38 WTI Bbls price per Bbl 2010 Jan
- Dec Put options 40,000 $55.00 Strike $5.00 WTI Bbls price per
Bbl(3) Sales of Natural Gas Production 2009 July - Dec Collars
150,000 $10.00 Floor - $0.346 Henry MMBtu $20.00 Ceiling per MMBtu
Hub 2010 Jan - Dec Three-way collars(4) 85,000 $6.12 Floor $0.034
Henry MMBtu with a MMBtu Hub $4.64 Limit $8.00 Ceiling (1) All of
our derivative instruments are settled monthly. (2) The average
strike prices do not reflect the cost to purchase the put options
or collars. (3) In addition to the deferred premium, a premium
averaging $3.86 per barrel was paid from the proceeds of our first
quarter 2009 derivative monetization upon entering into these
derivative contracts. (4) If NYMEX is less than the $6.12 per MMBtu
floor, we receive the difference between NYMEX and the $6.12 per
MMBtu floor up to a maximum of $1.48 per MMBtu. We pay the
difference between NYMEX and $8.00 per MMBtu if NYMEX is greater
than the $8.00 ceiling. Plains Exploration & Production Company
Reconciliation of GAAP to Non-GAAP Measure The following table
reconciles net income (GAAP) to adjusted net income (non-GAAP) for
the quarters and six months ended June 30, 2009 and 2008. Adjusted
net income includes realized gains and losses and excludes
unrealized gains and losses on mark-to-market derivative contracts,
debt extinguishment costs, gain on sale of assets, legal settlement
recovery and the effects of nonrecurring tax related expenses and
benefits. Management believes this presentation may be helpful to
investors. PXP management uses this information to analyze
operating trends and for comparative purposes within the industry.
This measure is not intended to replace the GAAP statistic but
rather to provide additional information that may be helpful in
evaluating the Company's operational trends and performance. Three
Months Ended June 30, ------------- 2009 2008 ---- ---- (millions
of dollars) Net income (GAAP) $43.6 $202.9 Unrealized loss on
mark-to-market derivative contracts 89.7 51.4 Realized gain (loss)
on mark- to-market derivative contracts(1) 247.2 (22.8) Debt
extinguishment costs 0.7 - Legal settlement recovery (87.3) -
Adjust income taxes(2) (122.7) (13.8) ------ ----- Adjusted net
income (non-GAAP) $171.2 $217.7 ====== ====== Six Months Ended June
30, -------------- 2009 2008 ---- ---- (millions of dollars) Net
income (GAAP) $48.8 $366.4 Unrealized loss on mark-to-market
derivative contracts 1.6 60.9 Realized gain (loss) on
mark-to-market Derivative contracts (1) 515.6 (39.2) Debt
extinguishment costs 10.9 10.3 Gain on sale of assets - (34.7)
Legal settlement recovery (87.3) - Adjust income taxes (2) (184.8)
1.0 ------ --- Adjusted net income (non-GAAP) $304.8 $364.7 ======
====== (1) Second quarter and six month 2009 totals include $167.9
million attributable to April-June 2009 production and $225.2
million attributable to March-June production, respectively, for
the $106 crude oil puts and $54 crude oil swaps that were monetized
in the first quarter of 2009. Six month 2009 totals also include
$121.4 million associated with the January and February settlement
of the $106 crude oil puts and the $54 crude swaps that we
monetized in the first quarter of 2009. The remaining proceeds from
the monetization are not included in the above table because they
are attributable to production months subsequent to June 30, 2009.
The amounts presented in the above table differ from the
adjustments reflected in the calculation of operating cash flow on
the following page due to the accrued amounts reflected in the
income statement versus the actual cash received or paid reflected
in the consolidated statement of cash flows. (2) Tax rates assumed
based upon adjusted earnings are 36.9% and 37.0% for the quarters
ended June 30, 2009 and 2008, respectively. Tax rates assumed based
upon adjusted earnings are 38.7% and 37.8% for the six months ended
June 30, 2009 and 2008, respectively. Tax rates exclude the effects
of nonrecurring tax related expenses and benefits. Plains
Exploration & Production Company Reconciliation of GAAP to
Non-GAAP Measure The following tables reconcile Net Cash Provided
by Operating Activities (GAAP) to Operating Cash Flow (non-GAAP)
for the quarters and six months ended June 30, 2009 and 2008.
Management believes this presentation may be useful to investors.
PXP management uses this information for comparative purposes
within the industry and as a means of measuring the Company's
ability to fund capital expenditures and service debt. This measure
is not intended to replace the GAAP statistic but rather to provide
additional information that may be helpful in evaluating the
Company's operational trends and performance. Operating cash flow
is calculated by adjusting net income to add back certain non-cash
and non-operating items, including unrealized gains and losses on
mark-to-market derivative contracts, to include derivative cash
settlements for realized gains and losses on mark-to-market
derivative contracts that are classified as either investing or
financing activities for GAAP purposes and to exclude certain
nonrecurring items. Three Months Six Months Ended Ended June 30,
June 30, ------------- ----------- 2009 2008 2009 2008 ---- ----
---- ---- (millions of dollars) Net income $43.6 $202.9 $48.8
$366.4 Items not affecting operating cash flows Gain on sale of
assets - - - (34.7) Depreciation, depletion, amortization and
accretion 94.4 134.0 186.0 278.2 Deferred income tax expense
(benefit) 21.4 52.5 (4.8) 118.6 Debt extinguishment costs 0.7 -
10.9 10.3 Unrealized loss on mark-to-market derivative contracts
89.7 51.4 1.6 60.9 Noncash compensation 18.0 28.4 32.6 40.5 Other
noncash items 1.1 1.9 2.9 2.9 Realized gain (loss) on mark-to-
market derivative contracts (1) 254.1 (20.8) 532.5 (42.6) Legal
settlement recovery (87.3) - (87.3) - Current income taxes
attributable to derivative contracts and property sales (43.7) 61.7
12.1 102.2 ----- ---- ---- ----- Operating cash flow (non-GAAP)
$392.0 $512.0 $735.3 $902.7 ====== ====== ====== ======
Reconciliation of non-GAAP to GAAP measure Operating cash flow
(non-GAAP) $392.0 $512.0 $735.3 $902.7 Legal settlement recovery
87.3 - 87.3 - Changes in assets and liabilities from operating
activities (97.9) (146.5) (136.3) (233.7) Realized (gain) loss on
mark-to- market derivative contracts (1) (254.1) 20.8 (532.5) 42.6
Current income taxes attributable to derivative contracts and
property sales 43.7 (61.7) (12.1) (102.2) ---- ----- ----- ------
Net cash provided by operating activities (GAAP) $171.0 $324.6
$141.7 $609.4 ====== ====== ====== ====== (1) Second quarter and
six month 2009 totals include $167.9 million attributable to
April-June 2009 production and $225.2 million attributable to
March-June production, respectively, for the $106 crude oil puts
and $54 crude oil swaps that were monetized in the first quarter of
2009. Six month 2009 totals also include $121.4 million associated
with the January and February settlement of the $106 crude oil puts
and the $54 crude oil swaps that were monetized in the first
quarter of 2009. Such amounts are classified as investing
activities for GAAP purposes. The remaining proceeds from the
monetization are included as a cash receipt from investing
activities in the accompanying consolidated statement of cash flows
but are not included in the non-GAAP measure of operating cash flow
because they are attributable to production months subsequent to
June 30, 2009. Plains Exploration & Production Company
Derivative Settlements (in thousands of dollars) The following
tables reflect cash receipts (payments) for derivatives
attributable to the following production periods. Three Months
Ended Six Months Ended June 30, June 30, 2009 2008 2009 2008 ----
---- ---- ---- Oil sales $(4,173) $(22,784) $142,692 $(39,644) Gas
sales 83,449 - 147,761 427 ------- -------- -------- --------
$79,276 $(22,784) $290,453 $(39,217) ======= ======== ========
======== 2009 2010 ---- ---- Amortization of monetized derivatives
(1) First quarter $57,211 $123,730 Second quarter 167,943 125,105
Third quarter 169,788 126,479 Fourth quarter 169,788 126,479
------- ------- $564,730 $501,793 ======== ======== (1) Represents
the net receipts for derivatives monetized in the first quarter of
2009 attributable to their production periods. DATASOURCE: Plains
Exploration & Production Company CONTACT: Investors, Hance
Myers, +1-713-579-6291, , or Media, Scott Winters, +1-713-579-6190,
, both of Plains Exploration & Production Company Web Site:
http://www.pxp.com/
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