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PXP Announces Third Quarter Results, Including A Surge in Oil Revenue, Record Oil Sales Volumes, and Improved Crude Oil Realized

PXP Announces Third Quarter Results, Including A Surge in Oil Revenue, Record
          Oil Sales Volumes, and Improved Crude Oil Realized Pricing

PR Newswire

HOUSTON, Nov. 1, 2012

HOUSTON, Nov. 1, 2012 /PRNewswire/ --Plains Exploration & Production Company
(NYSE:PXP) ("PXP" or the "Company") announces 2012 third-quarter financial and
operating results.

THIRD-QUARTER HIGHLIGHTS

  oTotal revenues were $605.1 million, a 21% increase compared to
    third-quarter 2011.
  oOil revenues were $540.4 million, a 43% increase compared to third-quarter
    2011 and the third consecutive quarterly increase.
  oTotal daily sales volumes averaged approximately 105.6 thousand barrels of
    oil equivalent ("BOE"), a 10% increase per diluted share, or a 36%
    increase per diluted share pro forma for the December 2011 asset sales,
    compared to third-quarter 2011.
  oOil daily sales volumes averaged 63.5 thousand barrels, a 36% increase per
    diluted share, or 56% per diluted share pro forma for the December 2011
    asset sales, compared to third-quarter 2011.
  oAverage crude oil realized price per barrel before derivative transactions
    was $96.74, a 14% increase compared to third-quarter 2011, despite a lower
    Brent benchmark price.
  oAverage crude oil and liquids realized price per barrel before derivative
    transactions was $92.44, a 14% increase compared to third-quarter 2011,
    despite a lower Brent benchmark price.
  oNet cash provided by operating activities was $415.6 million, a 20%
    increase over third-quarter 2011. Operating cash flow (a non-GAAP measure)
    was $382.2 million, a 27% increase over third-quarter 2011 and the third
    consecutive quarterly increase.
  oNet loss attributable to common stockholders was $53.1 million, or $0.41
    per diluted share compared to third-quarter 2011 net loss of $88.3
    million, or $0.62 per diluted share.
  oAdjusted net income attributable to common stockholders (a non-GAAP
    measure) was $51.6 million, or $0.39 per diluted share compared to
    third-quarter 2011 adjusted net income of $64.9 million, or $0.45 per
    diluted share.

FINANCIAL SUMMARY

PXP reported third-quarter revenues of $605.1 million and a net loss
attributable to common stockholders of $53.1 million, or $0.41 per diluted
share, compared to revenues of $501.8 million and a net loss of $88.3 million,
or $0.62 per diluted share, for the third-quarter 2011. The third-quarter net
income attributable to common stockholders includes certain items affecting
the comparability of operating results. Those items consist of realized and
unrealized gains and losses on our mark-to-market derivative contracts
resulting in a net loss of $100.2 million due in large part to increased crude
oil forward prices, a $43.1 million unrealized loss on investment in McMoRan
Exploration Co. ("McMoRan") common stock, and other items. When considering
these items, PXP reports net income attributable to common stockholders of
$51.6 million, or $0.39 per diluted share (a non-GAAP measure).

For the first nine months of 2012, PXP reports revenues of $1.7 billion and
net income attributable to common stockholders of $87.8 million, or $0.67 per
diluted share, compared to revenues of $1.4 billion and net income of $107.6
million, or $0.75 per diluted share, for the same period in 2011. These
results include certain items affecting comparability of operating results.
These items consist of realized and unrealized gains and losses on our
mark-to-market derivative contracts, an unrealized loss on investment in
McMoRan common stock, and other items. When considering these items, net
income attributable to common stockholdersfor the first nine months of 2012
was $174.3 million, or $1.32 per diluted share (a non-GAAP measure), compared
to $194.5 million, or $1.36 per diluted share, for the same period in 2011.

A reconciliation of non-GAAP financial measures used in this release to
comparable GAAP financial measures is included with the financial tables.

OPERATIONAL SUMMARY

PXP's 2012 third-quarter daily sales volumes averaged 105.6 thousand BOE per
day, a 10% increase per diluted share and a 36% increase per diluted share pro
forma for the December 2011 asset sales compared to third-quarter 2011.

Crude oil sales volumes averaged 58.7 thousand barrels per day, compared to
third-quarter 2011 average volumes of 45.2 thousand barrels per day. The
healthy volume growth is driven primarily by a strong performance in the Eagle
Ford Shale and steady, consistent performance in California.

Natural gas liquids sales volumes averaged 4.8 thousand barrels per day,
compared to third-quarter 2011 average volumes of 5.6 thousandbarrels per day
reflecting the impact of the South Texas and Texas Panhandle asset sales in
December 2011.

Natural gas sales volumes averaged 252.0 million cubic feet ("MMcf") per day
compared to 321.3 MMcf per day in the third-quarter 2011. Lower volumes
reflect the impact of the December 2011 asset sales and lower drilling
activity in the Haynesville Shale, partially offset by increased production
from the Eagle Ford Shale.

In the Eagle Ford Shale, third-quarter daily sales volumes averaged 30.4
thousand BOE per day net to PXP compared to third-quarter 2011 average daily
sales volumes of 5.2 thousand BOE per day net to PXP. At the end of October,
PXP had 7.1 net drilling rigs operating on its acreage and 35 wells drilled
but waiting on completion or connection to pipelines. PXP expects to exit the
year between 32 – 36 thousand BOE per day net to PXP.

In California, third-quarter daily sales volumes averaged 38.1 thousand BOE
per day net to PXP compared to the third-quarter 2011 daily sales volume
average of 39.7 thousand BOE per day net to PXP. PXP expects to exit the year
between 38 – 39 thousand BOE per day net to PXP.

In the Haynesville Shale, third-quarter daily sales volumes averaged 190.4
MMcf per day net to PXP compared to third-quarter 2011 average daily sales
volumes of 201.3 MMcf per day net to PXP. The sales volume decline reflects
significantly lower drilling activity during the quarter. At the end of
October, there were no drilling rigs operating in which PXP had a working
interest. PXP expects to exit the year between 142 – 146 MMcf per day net to
PXP.

CAPITAL SPENDING UPDATE

For the third-quarter of 2012, PXP had cash expenditures of approximately
$564.1 million for additions to oil and gas properties and $6.2 million for
leasehold acquisitions. Of the $570.3 million total, $78.3 million was funded
by Plains Offshore Operations Inc., PXP's consolidated subsidiary. PXP's
third-quarter net cash provided by operating activities was $415.6 million.

For the nine months ended September, PXP had cash expenditures of
approximately $1.4 billion for additions to oil and gas properties and
leasehold acquisitions. Of the $1.4 billion total, $168.5 million was funded
by Plains Offshore Operations Inc. PXP's net cash provided by operating
activities and proceeds from sales of oil and gas properties during this
period were $1.1 billion.

For the full-year of 2012, PXP's total capital spending is expected to be
approximately $2.0 billion of which approximately $180 million is funded by
Plains Offshore Operations Inc. The increase in PXP's capital spending over
its base plan is attributed to oil & gas capital and seismic data acquisition
capital for development and drilling activities of the Gulf of Mexico
deepwater assets to be acquired and to accelerated development activity in the
Eagle Ford Shale. Higher spending in the Eagle Ford Shale is leading to an
approximate 78% increase in wells drilled and a 25% increase in average daily
sales volumes over the 2012 base plan. PXP's 2013 capital spending is expected
to be approximately $2.0 billion, including capitalized interest and general
and administrative costs.

FULL-YEAR 2012 SALES VOLUMES UPDATE

PXP expects full-year 2012 average sales volumes, excluding sales volumes
associated with the Gulf of Mexico acquisition, to be slightly above the
revised guidance range of 95 - 97 thousand BOE per day. PXP revised its sales
volume guidance in August 2012 from original guidance of 92 - 96 thousand BOE
due to anticipated sales volume increases at the Eagle Ford Shale. Including
one month of sales volumes associated with the Gulf of Mexico acquisition, PXP
now anticipates full-year 2012 sales volumes to be approximately 103 thousand
BOE per day.

COMMODITY PRICES

During the third-quarter of 2012, Brent crude oil price averaged $109.37 per
barrel compared to $112.01 per barrel in the third-quarter 2011. PXP's 2012
third-quarter crude oil average realized price per barrel before derivative
transactions was $96.74 per barrel, or approximately 88% of Brent, compared to
$84.53 per barrel in the third-quarter 2011, or approximately 75% of Brent.
Including the impact of derivative transactions, the third-quarter 2012 crude
oil average realized price was $96.74 per barrel, or approximately 88% of
Brent, compared to $81.00 per barrel in the third-quarter 2011, or 72% of
Brent.

During the third-quarter of 2012, the oil/liquids average realized price per
barrel before derivative transactions, which includes 4.8 thousand BOE per day
net to PXP of natural gas liquids, was $92.44 per barrel, or approximately 85%
of Brent, compared to $80.96 per barrel in the third-quarter 2011, or 72% of
Brent. Including the impact of derivative transactions, the average realized
price in the third-quarter 2012 was $92.44 per barrel, or 85% of Brent,
compared to $77.83 per barrel in the third-quarter 2011, or 69% of Brent.

During the third-quarter of 2012, NYMEX gas price averaged $2.82 per million
British thermal units ("MMBtu") compared to $4.20 per MMBtu in the
third-quarter 2011. PXP's 2012 third-quarter natural gas average realized
price before derivative transactions was $2.70 per MMBtu, or approximately 96%
of NYMEX, compared to $4.10 per MMBtu in the third-quarter 2011, or 98% of
NYMEX. Including the impact of derivative transactions, the average realized
price in the third-quarter 2012 was $3.33 per MMBtu, or approximately 118% of
NYMEX, compared to $4.11 per MMBtu in the third-quarter 2011, or 98% of NYMEX.

ACQUISITION FINANCING UPDATE

PXP successfully secured $8.0 billion dollars in total debt financing for the
$6.11 billion Gulf of Mexico acquisition at a weighted average cost of debt of
4.8% as of October 29, 2012. The Company remains on track to close the
acquisition by the end of November 2012.

In early October, PXP successfully syndicated $7.0 billion of committed
financing to a group of banks and institutional lenders. The $7.0 billion of
committed financing will be comprised of an amended and restated credit
facility with a $5.3 billion borrowing base, which consists of (i) a $3.0
billion senior secured five-year revolving credit facility, (ii) a $750.0
million senior secured five-year term loan and (iii) a $1.25 billion senior
secured seven-year term loan, as well as a $2.0 billion senior unsecured
bridge facility.

At the end of October, PXP completed a public offering of $3.0 billion of
senior notes, consisting of $1.5 billion in aggregate principal amount of
Senior Notes due 2020, issued at par, and $1.5 billion in aggregate principal
amount of Senior Notes due 2023, issued at par. This replaced the $2.0 billion
senior unsecured bridge facility and lowered the borrowing base under the
amended and restated credit facility by $125 million.

DERIVATIVE UPDATE

PXP continues to implement its crude oil hedging program and is well underway
in achieving its stated goal to protect up to 90% of expected crude oil sales
volumes in 2013, 2014 and 2015. Approximately 90% of expected 2013 and 2014
sales volumes are protected by put option spread contracts, swaps or three-way
collars. In 2015, PXP has approximately 47% of expected sales volumes covered
by put option spread contracts and continues to target up to 90% of
anticipated oil sales volumes. A detailed list of PXP's current derivative
positions is included at the end of this release.

MANAGEMENT COMMENT

James C. Flores, Chairman, President and CEO of PXP commented, "The
fundamentals of our business are healthy as evidenced by strong third-quarter
growth in total revenue, cash flow provided by operating activities, cash
margin per BOE and production per diluted share compared to the same period a
year ago. Our high-margin, fast growing onshore oil business will soon be
complimented by the substantial addition of high-margin offshore Gulf of
Mexico deepwater properties with current production and substantial future
development inventory. With long-term financing in place, our attention is
laser focused on closing the transaction, completing our stated hedging
program objectives, transitioning to the new long-term operational plan and
reducing long-term debt. This strategic initiative transforms PXP into a large
capitalization exploration and production company with a business model
dominated by a portfolio of onshore and offshore oil assets capable of
doubling pro forma oil production by 2020 while generating substantial cash
flow provided by operating activities in excess of capital investment to meet
debt reduction targets."

CONFERENCE CALL

PXP will host a conference call today, Thursday, November 1 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
36633286. The replay can be accessed by dialing 1-855-859-2056 or
1-404-537-3406. A live webcast of the conference call 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 for "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:

* completion of the previously announced acquisition and realization of the
expected benefits therefrom,
* 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 and Forms 10-Q, 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. References in this press release
to oil revenue and oil sales volumes include natural gas liquid volumes.

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.

Plains Exploration & Production Company

Consolidated Statements of Income

(in thousands, except per share data)
                                Three Months Ended    Nine Months Ended
                                September 30,         September 30,
                                2012       2011       2012         2011
                                           (Unaudited)
Revenues
   Oil sales                    $        $        $           $ 
                                540,434   379,079   1,527,430    1,110,228
   Gas sales                   62,630     121,014    162,113      331,486
   Other operating revenues     2,040      1,755      6,560        5,233
                                605,104    501,848    1,696,103    1,446,947
Costs and Expenses
   Lease operating expenses     98,087     79,987     268,755      234,380
   Steam gas costs              12,096     17,015     32,931       49,641
   Electricity                  9,930      10,112     32,081       30,203
   Production and ad valorem    21,066     10,636     52,782       39,084
   taxes
   Gathering and transportation 19,218     15,237     54,519       44,825
   expenses
   General and administrative
   G&A                          32,515     28,158     102,598      94,964
   Acquisition related costs    6,683      -          6,683        -
   Depreciation, depletion and  270,598    167,894    699,025      453,194
   amortization
   Accretion                    3,749      4,307      11,252       12,878
   Other operating income       (605)      (50)       (3,142)      (657)
                                473,337    333,296    1,257,484    958,512
Income from Operations          131,767    168,552    438,619      488,435
Other (Expense) Income
   Interest expense             (59,174)   (43,495)   (157,404)    (113,141)
   Debt extinguishment costs    -          -          (5,167)      -
   (Loss) gain on
   mark-to-market derivative    (100,160)  125,551    12,573       93,467
   contracts
   Loss on investment measured  (43,121)   (395,490)  (92,301)     (284,929)
   at fair value
   Other income                 11         1,399      440          2,949
(Loss) Income Before Income     (70,677)   (143,483)  196,760      186,781
Taxes
   Income tax benefit (expense)
   Current                      3,540      26,718     2,535        25,959
   Deferred                     23,163     28,469     (84,297)     (105,165)
Net (Loss) Income              $        $        $          $  
                                (43,974)  (88,296)  114,998     107,575
   Net income attributable to
   noncontrolling interestin   (9,114)               (27,206)
   the form of preferred stock
   of subsidiary
Net (Loss) Income Attributable  $                   $   
to Common Stockholders          (53,088)             87,792
(Loss) Earnings per Common
Share
   Basic                        $      $      $       $     
                                (0.41)    (0.62)    0.68        0.76
   Diluted                      $      $      $       $     
                                (0.41)    (0.62)    0.67        0.75
Weighted Average Common Shares
Outstanding
   Basic                        130,047    141,826    129,806      141,500
   Diluted                      130,047    141,826    131,774      143,351







Plains Exploration & Production Company

Operating Data
                                    Three Months Ended    Nine Months Ended
                                    September 30,         September 30,
                                    2012        2011      2012       2011
                                                (Unaudited)
Daily Average Volumes
     Oil and liquids sales (Bbls)   63,548      50,891    57,683     47,853
     Gas (Mcf)
         Production                 255,363     327,248   241,553    299,423
         Used as fuel               3,353       5,962     3,952      5,875
         Sales                     252,010     321,286   237,601    293,548
     BOE
         Production                 106,109     105,432   97,942     97,756
         Sales                     105,550     104,438   97,283     96,777
Unit Economics (in dollars)
     Average Index Prices
         ICE Brent Price per Bbl    $         $       $        $  
                                    109.37     112.01   112.16    111.47
         NYMEX Price per Bbl        92.20       89.54     96.16      95.47
         NYMEX Price per Mcf        2.82        4.20      2.59       4.20
     Average Realized Sales Price
     Before Derivative Transactions
         Oil (per Bbl)              $        $      $       $   
                                    92.44      80.96    96.64     84.98
         Gas (per Mcf)              2.70        4.10      2.49       4.14
         Per BOE                    62.10       52.05     63.38      54.57
     Cash Margin per BOE ^(1)
         Oil and gas revenues      $        $      $       $   
                                    62.10      52.05    63.38     54.57
         Costs and expenses
             Lease operating        (10.10)     (8.32)    (10.08)    (8.87)
             expenses
             Steam gas costs        (1.25)      (1.77)    (1.24)     (1.88)
             Electricity            (1.02)      (1.05)    (1.20)     (1.14)
             Production and ad      (2.17)      (1.11)    (1.98)     (1.48)
             valorem taxes
             Gathering and          (1.98)      (1.59)    (2.05)     (1.70)
             transportation
             Oil and gas related    (27.21)     (16.86)   (25.54)    (16.49)
             DD&A
         Gross margin (GAAP)        18.37       21.35     21.29      23.01
             Oil and gas related    27.21       16.86     25.54      16.49
             DD&A
             Realized gain (loss)
             on derivative          1.50        (1.48)    1.59       (1.63)
             instruments
         Cash margin (non-GAAP)     $        $      $       $   
                                    47.08      36.73    48.42     37.87
Oil and gas capital expenditures    $          $        $          $
accrued ($ in thousands) ^(2)       531,924    502,745  1,470,669  1,364,142
     Cash margin per BOE (a non-GAAP measure) is calculated by adjusting gross
     margin per BOE (a GAAP measure) to include the realized gain and loss on
     derivative instruments and to exclude DD&A. Management believes this
     presentation may be helpful to investors as it represents the cash
^(1) 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.
     Additions to oil and gas properties reported in our consolidated
^(2) statement of cash flows differ from the accrual basis amounts reflected
     above due to the timing of cash payments. Excludes acquisitions.





Plains Exploration & Production Company

Reconciliation of GAAP to Non-GAAP
Measure
                                         Three Months Ended September 30, 2012
                                         Oil           Gas           BOE
                                         (per Bbl)     (per Mcf)
Average Realized Sales Price
Average realized price before            $         $        $    
derivative instruments (GAAP) ^(1)      92.44        2.70         62.10
     Realized gain on derivative         -             0.63          1.50
     instruments
Realized cash price including            $         $        $    
derivative settlements (non-GAAP)        92.44        3.33         63.60
                                         Three Months Ended September 30, 2011
                                         Oil           Gas           BOE
                                         (per Bbl)     (per Mcf)
Average Realized Sales Price
Average realized price before            $         $        $    
derivative instruments (GAAP) ^(1)      80.96        4.10         52.05
     Realized (loss) gain on derivative  (3.13)        0.01          (1.48)
     instruments
Realized cash price including            $         $        $    
derivative settlements (non-GAAP)        77.83        4.11         50.57
                                         Nine Months Ended September 30, 2012
                                         Oil           Gas           BOE
                                         (per Bbl)     (per Mcf)
Average Realized Sales Price
Average realized price before            $         $        $    
derivative instruments (GAAP) ^(1)      96.64        2.49         63.38
     Realized (loss) gain on derivative  (0.20)        0.70          1.59
     instruments
Realized cash price including            $         $        $    
derivative settlements (non-GAAP)        96.44        3.19         64.97
                                         Nine Months Ended September 30, 2011
                                         Oil           Gas           BOE
                                         (per Bbl)     (per Mcf)
Average Realized Sales Price
Average realized price before            $         $        $    
derivative instruments (GAAP) ^(1)      84.98        4.14         54.57
     Realized (loss) gain on derivative  (3.38)        0.01          (1.63)
     instruments
Realized cash price including            $         $        $    
derivative settlements (non-GAAP)        81.60        4.15         52.94
^(1) Excludes the impact of production costs and expenses and DD&A.







Plains Exploration & Production Company

Consolidated Statements of Cash Flows

(in thousands of dollars)
                                               Nine Months Ended
                                               September 30,
                                               2012            2011
                                               (Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income                                    $   114,998  $   107,575
Items not affecting cash flows from operating
activities
Depreciation, depletion, amortization and      710,277         466,072
accretion
Deferred income tax expense                    84,297          105,165
Debt extinguishment costs                      939             -
Gain on mark-to-market derivative contracts    (12,573)        (93,467)
Loss on investment measured at fair value      92,301          284,929
Non-cash compensation                          37,898          27,257
Other non-cash items                           10,431          (6,332)
Change in assets and liabilities from          8,009           31,451
operating activities
Net cash provided by operating activities      1,046,577       922,650
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties            (1,388,356)     (1,261,196)
Acquisition of oil and gas properties^        (26,377)        (36,750)
Deposit related to the Gulf of Mexico          (555,000)       -
Acquisition
Proceeds from sales of oil and gas             60,470          11,987
properties, net of costs and expenses
Derivative settlements                         37,385          (47,448)
Additions to other property and equipment      (9,271)         (9,454)
Other                                          -               1,552
Net cash used in investing activities          (1,881,149)     (1,341,309)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities    6,756,425       4,026,900
Repayments of revolving credit facilities      (6,596,425)     (4,191,900)
Principal payments of long-term debt           (156,182)       -
Proceeds from issuance of Senior Notes         750,000         600,000
Costs incurred in connection with financing    (12,586)        (11,320)
arrangements
Purchase of treasury stock                     (88,490)        -
Distributions to holders of noncontrolling
interest in the form of preferred stock of     (20,250)        -
subsidiary
Other                                          -               9
Net cash provided by financing activities      632,492         423,689
Net (decrease) increase in cash and cash       (202,080)       5,030
equivalents
Cash and cash equivalents, beginning of        419,098         6,434
period
Cash and cash equivalents, end of period       $   217,018  $    11,464





Plains Exploration & Production Company

Consolidated Balance Sheets

(in thousands of dollars)
                                                  September 30,  December 31,
                                                  2012           2011
                 ASSETS                           (Unaudited)
Current Assets
 Cash and cash equivalents                        $        $      
                                                  217,018        419,098
 Accounts receivable                              315,195        302,675
 Commodity derivative contracts                   26,302         50,964
 Inventories                                      19,076         20,173
 Investment                                       519,370        611,671
 Deferred income taxes                            166,002        20,723
 Prepaid expenses and other current assets        24,644         16,073
                                                  1,287,607      1,441,377
Property and Equipment, at cost
 Oil and natural gas properties - full cost
 method
       Subject to amortization                    14,083,960     12,016,252
       Not subject to amortization                1,718,876      2,409,449
 Other property and equipment                     150,031        145,959
                                                  15,952,867     14,571,660
 Less allowance for depreciation, depletion,      (7,473,140)    (6,846,365)
 amortization and impairment
                                                  8,479,727      7,725,295
Goodwill                                          535,140        535,140
Commodity Derivative Contracts                    19,459         12,678
Deposit Related to the Gulf of Mexico Acquisition 555,000        -
Other Assets                                      97,862         76,982
                                                  $           $    
                                                  10,974,795    9,791,472
                 LIABILITIES AND EQUITY
Current Liabilities
 Accounts payable                                 $        $      
                                                  470,284        385,231
 Commodity derivative contracts                   8,253          3,761
 Royalties and revenues payable                   130,820        97,095
 Interest payable                                 88,588         39,342
 Other current liabilities                        80,599         100,757
                                                  778,544        626,186
Long-Term Debt                                    4,516,571      3,760,952
Other Long-Term Liabilities
 Asset retirement obligation                      242,390        230,633
 Commodity derivative contracts                   4,239          823
 Other                                            17,133         15,749
                                                  263,762        247,205
Deferred Income Taxes                             1,691,473      1,461,897
Equity
Stockholders' equity
 Common stock                                     1,439          1,439
 Additional paid-in capital                       3,426,909      3,434,928
 Retained earnings                                418,789        337,991
 Treasury stock, at cost                          (560,244)      (509,722)
                                                  3,286,893      3,264,636
Noncontrolling interest
 Preferred stock of subsidiary                    437,552        430,596
                                                  3,724,445      3,695,232
                                                  $           $    
                                                  10,974,795    9,791,472







Plains Exploration & Production Company

Summary of Open Derivative Positions

At October 19, 2012
                                             Average     Average
               Instrument        Daily
Period ^(1)                                  Price       Deferred      Index
               Type              Volumes     ^(2)
                                                         Premium
Sales of Crude Oil Production
2012
                                             $100.00
       Oct -   Three-way         40,000      Floor
       Dec     collars^(3)       Bbls        with an     -             Brent
                                             $80.00
                                             Limit
                                             $120.00
                                             Ceiling
2013
       Jan -   Swap              40,000      $109.23     -             Brent
       Dec     contracts^(4)     Bbls
                                             $100.00
       Jan -                     13,000      Floor       $6.800 per
       Dec     Put options^(5)   Bbls        with an     Bbl           Brent
                                             $80.00
                                             Limit
                                             $100.00
       Jan -   Three-way         25,000      Floor
       Dec     collars^(3)       Bbls        with an     -             Brent
                                             $80.00
                                             Limit
                                             $124.29
                                             Ceiling
                                             $90.00
       Jan -   Three-way         5,000       Floor
       Dec     collars^(3)       Bbls        with a      -             Brent
                                             $70.00
                                             Limit
                                             $126.08
                                             Ceiling
                                             $90.00
       Jan -                     17,000      Floor       $6.253 per
       Dec     Put options^(5)   Bbls        with a      Bbl           Brent
                                             $70.00
                                             Limit
2014
                                             $100.00
       Jan -                     5,000       Floor       $7.110 per
       Dec     Put options^(5)   Bbls        with an     Bbl           Brent
                                             $80.00
                                             Limit
                                             $95.00
       Jan -                     30,000      Floor       $6.091 per
       Dec     Put options^(5)   Bbls        with a      Bbl           Brent
                                             $75.00
                                             Limit
                                             $90.00
       Jan -                     75,000      Floor       $5.739 per
       Dec     Put options^(5)   Bbls        with a      Bbl           Brent
                                             $70.00
                                             Limit
2015
                                             $90.00
       Jan -                     65,000      Floor       $6.904 per
       Dec     Put options^(5)   Bbls        with a      Bbl           Brent
                                             $70.00
                                             Limit
Sales of Natural Gas
Production
2012
                                             $4.30
       Oct -                     120,000     Floor       $0.298 per    Henry
       Dec     Put options^(6)   MMBtu       with a      MMBtu         Hub
                                             $3.00
                                             Limit
                                             $4.30
       Oct -   Three-way         40,000      Floor                     Henry
       Dec     collars^(7)       MMBtu       with a      -             Hub
                                             $3.00
                                             Limit
                                             $4.86
                                             Ceiling
       Oct -   Swap              80,000      $2.72       -             Henry
       Dec     contracts^(4)     MMBtu                                 Hub
2013
       Jan -   Swap              110,000     $4.27       -             Henry
       Dec     contracts^(4)     MMBtu                                 Hub
2014
       Jan -   Swap              100,000     $4.09       -             Henry
       Dec     contracts^(4)     MMBtu                                 Hub
^(1)   All of our derivatives are settled monthly.
^(2)   The average strike prices do not reflect any premiums to purchase the
       put options.
       If the index price is less than the per barrel floor, we receive the
       difference between the per barrel floor and the index price up to a
       maximum of $20 per barrel. We pay the difference between the index
^(3)   price and the per barrel ceiling if the index price is greater than
       the per barrel ceiling. If the index price is at or above the per
       barrel floor but at or below the per barrel ceiling, no cash
       settlement is required.
       If the index price is less than the fixed price, we receive the
^(4)   difference between the 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.
       If the index price is less than the per barrel floor, we receive the
^(5)   difference between the 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 the per barrel floor, we pay only the option premium.
       If the index price is less than the per MMBtu floor, we receive the
       difference between the per MMBtu floor and the index price up to a
^(6)   maximum of $1.30 per MMBtu less the option premium. If the index
       price is at or above the per MMBtu floor, we pay only the option
       premium.
       If the index price is less than the per MMBtu floor, we receive the
       difference between the per MMBtu floor and the index price up to a
       maximum of $1.30 per MMBtu. We pay the difference between the index
^(7)   price and the per MMBtu ceiling if the index price is greater than the
       per MMBtu ceiling. If the index price is at or above the per MMBtu
       floor but at or below the per MMBtu ceiling, no cash settlement is
       required.
Derivative Settlements

(in thousands of dollars)
The following tables reflect cash receipts (payments)
for derivatives attributable to the stated production
periods.
               Three Months Ended            Nine Months Ended
               September 30,                 September 30,
               2012              2011        2012        2011
                                 $       $       $     
               $                             
Oil sales                               
                  -           (14,672)            (44,209)
                                             (3,201)
Natural gas    14,590            414         45,499      1,034
sales
                                 $       $       $     
               $                             
                                           
               14,590            (14,258)             (43,175)
                                             42,298







Plains Exploration & Production Company

Reconciliation of GAAP to Non-GAAP Measure
The following tables reconcile net income (loss) (GAAP) to adjusted net income
and adjusted net income attributable to common stockholders (non-GAAP) for the
three and nine months ended September 30, 2012 and 2011. Adjusted net income
and adjusted net income attributable to common stockholders exclude certain
items affecting the comparability of operating results and the related tax
effects. 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
                                                 September 30,
                                                 2012           2011
                                                 (millions of dollars)
Net loss (GAAP)                                 $        $     
                                                 (44.0)         (88.3)
 Unrealized loss (gain) on mark-to-market        100.2          (125.6)
 derivative contracts
 Realized gain (loss) on mark-to-market          14.6           (14.3)
 derivative contracts ^(1)
 Unrealized loss on investment measured at fair  43.1           395.5
 value
 Acquisition related costs                       6.7            -
 Adjust income taxes ^(2)                        (59.9)         (102.4)
Adjusted net income (non-GAAP)                  $        $      
                                                 60.7          64.9
 Net income attributable to noncontrolling
 interest in the form of preferred stock of      (9.1)
 subsidiary
Adjusted net income attributable to common       $      
stockholders (non-GAAP)                         51.6
                                                 Nine Months Ended
                                                 September 30,
                                                 2012           2011
                                                 (millions of dollars)
Net income (GAAP)                                $         $     
                                                 115.0         107.6
 Unrealized gain on
 mark-to-market derivative                       (12.6)         (93.5)
 contracts
 Realized gain (loss) on mark-to-market          42.3           (43.2)
 derivative contracts ^(1)
 Unrealized loss on investment measured at fair  92.3           284.9
 value
 Debt extinguishment costs                       5.2            -
 Acquisition related costs                       6.7            -
 Adjust income taxes ^(2)                        (47.4)         (61.3)
Adjusted net income (non-GAAP)                  $         $     
                                                 201.5         194.5
 Net income attributable to noncontrolling
 interest in the form of preferred stock of      (27.2)
 subsidiary
Adjusted net income attributable to common       $     
stockholders (non-GAAP)                         174.3

     The amounts presented in the above tables differ from the adjustments
^(1) 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.
     Tax rates assumed based upon adjusted earnings are 35% and 42% for the
     three months ended September 30, 2012 and 2011, respectively. Tax rates
^(2) assumed based upon adjusted earnings are 39% and 42% for the nine months
     ended September 30, 2012 and 2011. 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 three and nine months ended
September 30, 2012 and 2011. 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 debt extinguishment costs, the
unrealized gain and loss on mark-to-market derivative contracts, to include
derivative cash settlements for the realized gain and loss on mark-to-market
derivative contracts that are classified as investing activities for GAAP
purposes, to exclude the unrealized gain and loss on the investment measured
at fair value, to include distributions to holders of noncontrolling interest
in the form of preferred stock of subsidiary that are classified as financing
activities for GAAP purposes and to exclude certain other items.



                                   Three Months Ended     Nine Months Ended
                                   September 30,          September 30,
                                   2012       2011        2012       2011
                                              (millions of dollars)
 Net (loss) income                $      $       $      $    
                                   (44.0)    (88.3)     115.0     107.6
 Items not affecting operating
 cash flows
  Depreciation, depletion,        274.4      172.2       710.3      466.1
 amortization and accretion
  Deferred income tax (benefit)   (23.2)     (28.4)      84.3       105.2
 expense
  Debt extinguishment costs       -          -           5.2        -
  Unrealized loss (gain) on
 mark-to-market derivative         100.2      (125.6)     (12.6)     (93.5)
 contracts
  Unrealized loss on investment   43.1       395.5       92.3       284.9
 measured at fair value
  Non-cash compensation           11.6       (0.8)       37.9       27.3
  Other non-cash items            7.4        (6.0)       10.4       (6.3)
 Realized gain (loss) on
 mark-to-market derivative         19.5       (17.4)      37.4       (47.4)
 contracts
 Distributions to holders of
 noncontrolling interest in
 theform of preferred stock       (6.8)      -           (20.3)     -

 of subsidiary
 Operating cash flow (non-GAAP)    $      $       $       $    
                                   382.2     301.2      1,059.9    843.9
 Reconciliation of non-GAAP to
 GAAP measure
  Operating cash flow (non-GAAP) $      $       $       $    
                                   382.2     301.2      1,059.9    843.9
  Cash portion of debt           -          -           (4.2)      -
 extinguishment costs
  Changes in assets and
 liabilities from operating        46.1       26.6        8.0        31.4
 activities
  Realized (gain) loss on
 mark-to-market derivative         (19.5)     17.4        (37.4)     47.4
 contracts
  Distributions to holders of
 noncontrolling interest in
 theform of preferred stock       6.8        -           20.3       -

  of subsidiary
 Net cash provided by operating    $      $       $       $    
 activities (GAAP)                 415.6     345.2      1,046.6    922.7







SOURCE Plains Exploration & Production Company

Website: http://www.pxp.com
Contact: Hance Myers, +1-713-579-6291, hmyers@pxp.com