PXP Announces 2012 Full-Year Results: Realizes Significant Net Income Growth Year-over-Year, Generates Substantial Growth in Net

 PXP Announces 2012 Full-Year Results: Realizes Significant Net Income Growth
Year-over-Year, Generates Substantial Growth in Net Cash Provided by Operating
 Activities, and Delivers Solid Reserve Replacement and Substantially Higher
                                Reserve Value

PR Newswire

HOUSTON, Feb. 21, 2013

HOUSTON, Feb. 21, 2013 /PRNewswire/ --Plains Exploration & Production Company
(NYSE:PXP) ("PXP" or the "Company") announces 2012 fourth-quarter and
full-year financial and operating results. These results reflect the one month
benefit of the Gulf of Mexico assets acquired on November 30, 2012.

FOURTH-QUARTER HIGHLIGHTS

  oTotal revenues were $869.2 million, a 68% increase compared to
    fourth-quarter 2011.
  oTotal daily sales volumes averaged approximately 132.9 thousand barrels of
    oil equivalent ("BOE"), a 35% increase per diluted share, or a 62%
    increase per diluted share pro forma for the December 2011 asset sales,
    compared to fourth-quarter 2011.
  oOil daily sales volumes averaged 93.0 thousand barrels, a 91% increase per
    diluted share, or 115% per diluted share pro forma for the December 2011
    asset sales, compared to fourth-quarter 2011.
  oNet cash provided by operating activities was $284.2 million, a 51%
    increase over fourth-quarter 2011.
  oOperating cash flow (a non-GAAP measure) was $536.2 million, an 89%
    increase over fourth-quarter 2011.
  oIncome from operations was $177.0 million, a 73% increase over
    fourth-quarter 2011.
  oNet income attributable to common stockholders was $218.6 million, or
    $1.65 per diluted share compared to fourth-quarter 2011 net income
    attributable to common stockholders of $97.7 million, or $0.69 per diluted
    share.
  oAdjusted net income attributable to common stockholders (a non-GAAP
    measure) was $54.8 million, or $0.41 per diluted share, compared to
    fourth-quarter 2011 adjusted net income attributable to common
    stockholders of $28.6 million, or $0.20 per diluted share. The adjusted
    fourth-quarter results include an increase in stock-based compensation
    expense which resulted in a $0.05 after-tax decrease in earnings per
    diluted share. Stock-based compensation increased due to the 30% increase
    in PXP stock price following the Freeport-McMoRan Copper & Gold Inc.
    merger announcement in December. Also included in the adjusted quarterly
    results was an increase in the oil and gas depreciation, depletion and
    amortization ("DD&A") rate which resulted in a $0.29 after-tax decrease in
    earnings per diluted share. The higher DD&A rate primarily reflects the
    impact of lower sustained natural gas prices on gas reserves and our Gulf
    of Mexico acquisition. 

FULL-YEAR HIGHLIGHTS

  oTotal revenues were $2.6 billion, a 31% increase compared to full-year
    2011.
  oTotal daily sales volumes averaged approximately 106.2 thousand BOE, a 16%
    increase per diluted share, or a 42% increase per diluted share pro forma
    for the December 2011 asset sales, compared to full-year 2011.
  oOil daily sales volumes averaged 66.6 thousand barrels, a 47% increase per
    diluted share, or 67% per diluted share pro forma for the December 2011
    asset sales, compared to full-year 2011.
  oNet cash provided by operating activities was $1.3 billion, a 20% increase
    over full-year 2011.
  oOperating cash flow (a non-GAAP measure) was $1.6 billion, a 42% increase
    over full-year 2011.
  oIncome from operations was $615.7 million, a 4% increase over full-year
    2011.
  oNet income attributable to common stockholders was $306.4 million, or
    $2.32 per diluted share compared to full-year 2011 net income attributable
    to common stockholders of $205.3 million, or $1.44 per diluted share.
  oAdjusted net income attributable to common stockholders (a non-GAAP
    measure) was $229.2 million, or $1.74 per diluted share, compared to
    full-year 2011 adjusted net income attributable to common stockholders of
    $223.0 million, or $1.56 per diluted share. Included in the adjusted
    results was an increase in the oil and gas DD&A rate which resulted in a
    $1.11 after-tax decrease in earnings per diluted share. The higher DD&A
    rate primarily reflects the impact of lower sustained natural gas prices
    on gas reserves.

2012 RESERVES

  oProved reserves increased 7% to 440.4 million BOE.
  oProbable reserves are 193.8 million BOE.
  oThe Company estimates possible reserves to be 157.0 million BOE and
    resource potentialto be2,817.0 million BOE.
  o100% of proved reserve volumes and 99% of probable reserve volumes are
    based upon reserve reports prepared by independent petroleum engineers. 1%
    of probable reserve volumes, possible reserve volumes and resource
    potential were prepared by PXP, which were not audited by an independent
    petroleum engineer.
  oStandardized measure of discounted future net cash flows for proved
    reserves is $10.0 billion compared to $5.1 billion in 2011.
  oPV-10 value for proved reserves (a non-GAAP measure) is $13.7 billion
    compared to $7.9 billion in 2011.
  oProved developed reserves are 63% of total proved reserves.
  oProved oil reserves as a percentage of proved reserves are 82%.
  oReserve replacement for proved reserves (a non-GAAP measure) is 181%.

FINANCIAL SUMMARY

PXP reported fourth-quarter revenues of $869.2 million and net income
attributable to common stockholders of $218.6 million, or $1.65 per diluted
share, compared to revenues of $517.5 million and net income attributable to
common stockholders of $97.7 million, or $0.69 per diluted share, for the
fourth-quarter 2011. The fourth-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 $15.5
million due in large part to increased crude oil forward prices, a $298.9
million unrealized gain on investment in McMoRan Exploration Co. ("McMoRan")
common stock, acquisition, merger and related financing costs of $70.5
million, and other items. When considering these items, PXP reports adjusted
net income attributable to common stockholders of $54.8 million, or $0.41 per
diluted share (a non-GAAP measure), compared to $28.6 million, or $0.20 per
diluted share, for the same period in 2011.

For the full-year, PXP reports revenues of $2.6 billion and net income
attributable to common stockholders of $306.4 million, or $2.32 per diluted
share, compared to revenues of $2.0 billion and net income attributable to
common stockholders of $205.3 million, or $1.44 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 gain on investment in McMoRan common stock, acquisition, merger and
related financing costs and other items. When considering these items,
adjusted net income attributable to common stockholders for the full-year of
2012 was $229.2 million, or $1.74 per diluted share (a non-GAAP measure),
compared to $223.0 million, or $1.56 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 UPDATE

PXP's 2012 fourth-quarter daily sales volumes averaged 132.9 thousand BOE per
day, a 35% increase per diluted share and a 62% increase per diluted share pro
forma for the December 2011 asset sales compared to fourth-quarter 2011.

Crude oil sales volumes averaged 85.4 thousand barrels per day, compared to
fourth-quarter 2011 average volumes of 46.4 thousand barrels per day. The
robust volume growth is driven primarily by one month contribution from the
deepwater Gulf of Mexico assets acquired in November 2012, continued strength
in the Eagle Ford Field, and steady, consistent performance in California.

Natural gas liquids sales volumes averaged 7.7 thousand barrels per day,
compared to fourth-quarter 2011 average volumes of 5.9 thousand barrels per
day. The increase reflects one month contribution from the deepwater Gulf of
Mexico assets acquired in November 2012 partially offset by the South Texas
and Texas Panhandle asset sales in December 2011.

Natural gas sales volumes averaged 239.2 million cubic feet ("MMcf") per day
compared to 318.8 MMcf per day in the fourth-quarter 2011. Lower volumes
reflect the impact of the December 2011 asset sales and lower drilling
activity in the Haynesville Field, partially offset by one month contribution
from the deepwater Gulf of Mexico assets acquired in November 2012 and
increased production from the Eagle Ford Field.

In the Eagle Ford Field, fourth-quarter daily sales volumes averaged 40.4
thousand BOE per day net to PXP compared to fourth-quarter 2011 average daily
sales volumes of 9.1 thousand BOE per day net to PXP. At the end of January,
PXP had 7.9 net drilling rigs operating on its acreage and 39 wells drilled
but waiting on completion or connection to pipelines.

In the Gulf of Mexico, PXP closed the acquisition of interests in certain
deepwater Gulf of Mexico oil and gas properties including 100% interests in
the Holstein, Marlin and Horn Mountain production facilities in November 2012.
Post-closing production from the platforms is reflected in PXP's fourth
quarter results beginning in December. After pre-closing adjustments of
approximately $218.9 million from the effective date of October 1, 2012, PXP
paid a total of $5.9 billion. At the sanctioned Lucius development in Keathley
Canyon, the operator and its partners completed the drilling of a development
well on the western flank of the field that encountered 910 net feet of oil
pay. Currently another development well is drilling on the eastern flank of
the structure with three additional development wells and/or sidetracks
scheduled for 2013. Drilling operations began during the fourth quarter at the
Phobos prospect, a large multi-block, four-way closure with Tertiary
objectives, approximately 12 miles south of the Lucius Field on Sigsbee
Escarpment Block 39.

In California, fourth-quarter daily sales volumes averaged 38.7 thousand BOE
per day net to PXP compared to the fourth-quarter 2011 daily sales volume
average of 40.0 thousand BOE per day net to PXP.

In the Haynesville Field, fourth-quarter daily sales volumes averaged 162.8
MMcf per day net to PXP compared to fourth-quarter 2011 average daily sales
volumes of 199.8 MMcf per day net to PXP. The sales volume decline reflects
significantly lower drilling activity during the quarter. At the end of
January, there were no drilling rigs operating in which PXP had a working
interest.

CAPITAL SPENDING

For the fourth-quarter of 2012, PXP had cash expenditures of approximately
$491 million for additions to oil and gas properties and leasehold
acquisitions. Of the $491 million total, $36 million was funded by Plains
Offshore Operations Inc., PXP's consolidated subsidiary. PXP's fourth quarter
operating cash flow was $536 million.

For the full year of 2012, PXP had cash expenditures of approximately $1.9
billion for additions to oil and gas properties and leasehold acquisitions. Of
the $1.9 billion total, $205 million was funded by Plains Offshore Operations
Inc. PXP's full-year operating cash flow was approximately $1.6 billion.

COMMODITY PRICES

During the fourth-quarter of 2012, Brent crude oil price averaged $110.05 per
barrel compared to $108.96 per barrel in the fourth-quarter 2011. PXP's 2012
fourth-quarter crude oil average realized price per barrel before derivative
transactions was $98.34 per barrel, or approximately 89% of Brent, compared to
$90.71 per barrel in the fourth-quarter 2011, or approximately 83% of Brent.
Since October, PXP's realized price before derivative transactions has
increased from approximately 86% of Brent to approximately 94% of Brent in
January. Including the impact of derivative transactions, the fourth-quarter
2012 crude oil average realized price was $98.34 per barrel, or approximately
89% of Brent, compared to $87.19 per barrel in the fourth-quarter 2011, or 80%
of Brent.

During the fourth-quarter of 2012, the oil average realized price per barrel
before derivative transactions, which includes 7.7 thousand BOE per day net to
PXP of natural gas liquids, was $93.28 per barrel, or approximately 85% of
Brent, compared to $87.02 per barrel in the fourth-quarter 2011, or 80% of
Brent. Including the impact of derivative transactions, the average realized
price in the fourth-quarter 2012 was $93.28 per barrel, or 85% of Brent,
compared to $83.90 per barrel in the fourth-quarter 2011, or 77% of Brent.

During the fourth-quarter of 2012, NYMEX gas price averaged $3.38 per million
British thermal units ("MMBtu") compared to $3.57 per MMBtu in the
fourth-quarter 2011. PXP's 2012 fourth-quarter natural gas average realized
price before derivative transactions was $3.19 per MMBtu, or approximately 94%
of NYMEX, compared to $3.30 per MMBtu in the fourth-quarter 2011, or 92% of
NYMEX. Including the impact of derivative transactions, the average realized
price in the fourth-quarter 2012 was $3.44 per MMBtu, or approximately 102% of
NYMEX, compared to $3.53 per MMBtu in the fourth-quarter 2011, or 99% of
NYMEX.

PROVED RESERVES

Year-end estimated proved reserves of 440.4 million BOE were 82% oil, 63%
developed and had a pre-tax PV-10 value of $13.7 billion, a 74% increase over
2011 PV-10 value. The robust increase in the PV-10 value is primarily
attributable to a greater concentration of oil reserves.

In 2012, PXP added total proved reserves of 68.6 million BOE. Extensions and
discoveries were 58.9 million BOE, primarily in the Eagle Ford Field and
Lucius Field. Deepwater Gulf of Mexico acquired reserves were 126.4 million
BOE, negative revisions, predominately gas price related in the Haynesville
Field and Madden Field, were 114.4 million BOE, and minor reserve divestments
were 2.3 million BOE. These reserve additions replaced 181% of 2012
production.

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 $94.71 per barrel and Henry Hub spot natural
gas price of $2.76 per million British thermal unit. All prices were adjusted
for energy content, quality and basis differentials by area and were held
constant throughout the lives of the properties, unless prices are defined by
contractual arrangements, excluding escalations based upon future conditions.
A summary of the Company's proved reserves reconciliation, costs incurred,
Standardized Measure, and PV-10 are included with the financial tables.

MANAGEMENT COMMENT

James C. Flores, Chairman, President and CEO of PXP commented, "PXP delivered
exceptional quarterly results and ended the year ahead of expectations. For
the year, PXP attained record sales volumes, increased its oil margins and
cash flow, preserved commodity price upside through its hedging program and
acquired high-margin offshore deepwater Gulf of Mexico assets to ensure
long-term sustainable growth. PXP begins 2013 with a durable onshore and
offshore oil business, increasing oil production per share, strong oil growth
assets with premium pricing, and increasing cash flow growth potential. These
characteristics complement the large, long-life, low cost, and expandable
asset base characteristics of Freeport-McMoRan Copper & Gold Inc. with whom we
have entered into a transaction to merge our operations."

CONFERENCE CALL

PXP will host a conference call today, Thursday, February 21, 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:
88518328. 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 proposed merger,
* 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. In this press release, the Company
uses the terms "possible reserves" and "resource potential" to describe the
Company's internal estimates of volumes of oil and gas that are not classified
as proved reserves but are potentially recoverable through exploratory
drilling or additional drilling or recovery techniques. Resource potential is
a broader description of potentially recoverable volumes than probable and
possible reserves, as defined by the SEC regulations. SEC guidelines prohibit
us from including resource potential in filings with the SEC. References in
this press release to oil include crude oil, condensate, and 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.

IMPORTANT ADDITIONAL INFORMATION WILL BE FILED WITH THE SEC
In connection with the proposed business combination transaction between PXP
and FCX, FCX has filed with the SEC a registration statement on Form S-4 that
contains a proxy statement/prospectus to be mailed to the PXP stockholders in
connection with the proposed transaction. THE REGISTRATION STATEMENT AND THE
PROXY STATEMENT/PROSPECTUS CONTAIN IMPORTANT INFORMATION ABOUT PXP, FCX, THE
PROPOSED TRANSACTION AND RELATED MATTERS. INVESTORS AND SECURITY HOLDERS ARE
URGED TO READ THE REGISTRATION STATEMENT AND THE PROXY STATEMENT/PROSPECTUS
CAREFULLY WHEN THEY BECOME AVAILABLE. Investors and security holders may
obtain free copies of the registration statement and the proxy
statement/prospectus and other documents filed with the SEC by PXP and FCX
through the web site maintained by the SEC at www.sec.gov. In addition,
investors and security holders may obtain free copies of the registration
statement and the proxy statement/prospectus by phone, e-mail or written
request by contacting the investor relations department of PXP or FCX at the
following:

Plains Exploration & Production Company
700 Milam, Suite 3100
Houston, TX 77002
Attention: Investor Relations
Phone: (713) 579-6000
Email: investor@pxp.com

Freeport-McMoRan Copper & Gold Inc.
333 N. Central Ave.
Phoenix, AZ 85004
Attention: Investor Relations
Phone: (602) 366-8400
Email: ir@fmi.com

PARTICIPANTS IN THE SOLICITATION
PXP and FCX, and their respective directors and executive officers, may be
deemed to be participants in the solicitation of proxies in respect of the
proposed transactions contemplated by the merger agreement. Information
regarding directors and executive officers of PXP is contained in the proxy
statement/prospectus dated February 8, 2013, which is filed with the SEC.
Information regarding FCX's directors and executive officers is contained in
FCX's definitive proxy statement dated April 27, 2012, which is filed with the
SEC.

This document shall not constitute an offer to sell or the solicitation of an
offer to buy any securities, nor shall there be any sale of securities in any
jurisdiction in which such offer, solicitation or sale would be unlawful prior
to registration or qualification under the securities laws of any such
jurisdiction. No offering of securities shall be made except by means of a
prospectus meeting the requirements of Section 10 of the U.S. Securities Act
of 1933, as amended.



Plains Exploration & Production Company
Consolidated Statements of Income
(in thousands, except per share data)
                            Three Months Ended        Twelve Months Ended
                            December 31,              December 31,
                            2012         2011         2012         2011
                            (Unaudited)
Revenues
  Oil sales                 $          $          $           $ 
                            798,492     418,428     2,325,922    1,528,656
  Gas sales                70,328       96,734       232,441      428,220
  Other operating revenues  384          2,379        6,944        7,612
                            869,204      517,541      2,565,307    1,964,488
Costs and Expenses
  Lease operating expenses  124,705      100,543      393,460      334,923
  Steam gas costs           14,386       15,841       47,317       65,482
  Electricity               11,869       11,039       43,950       41,242
  Production and ad         21,091       16,141       73,873       55,225
  valorem taxes
  Gathering and             19,333       17,278       73,852       62,103
  transportation expenses
  General and
  administrative
      G&A                   54,424       39,080       157,022      134,044
      Acquisition and       35,468       -            42,151       -
      merger related costs
  Depreciation, depletion   402,083      211,284      1,101,108    664,478
  and amortization
  Accretion                 5,692        4,299        16,944       17,177
  Other operating expense   3,115        (78)         (27)         (735)
  (income)
                            692,166      415,427      1,949,650    1,373,939
Income from Operations      177,038      102,114      615,657      590,549
Other (Expense) Income
  Interest expense          (140,135)    (48,175)     (297,539)    (161,316)
  Debt extinguishment       (3,221)      (120,954)    (8,388)      (120,954)
  costs
  (Loss) gain on
  mark-to-market            (15,452)     (11,486)     (2,879)      81,981
  derivative contracts
  Gain (loss) on
  investment measured at    298,853      232,254      206,552      (52,675)
  fair value
  Other income              254          407          694          3,356
Income Before Income        317,337      154,160      514,097      340,941
Taxes
  Income tax benefit
  (expense)
      Current               1,567        (7)          4,102        25,952
      Deferred              (91,115)     (55,049)     (175,412)    (160,214)
Net Income                 227,789      99,104       342,787      206,679
  Net income attributable
  to noncontrolling
  interest                  (9,161)      (1,400)      (36,367)     (1,400)
   in the form of
  preferred stock of
  subsidiary
Net Income Attributable to  $ 218,628    $ 97,704     $ 306,420    $ 205,279
Common Stockholders
Earnings per Common Share
  Basic                     $       $       $       $     
                            1.68        0.70        2.36        1.45
  Diluted                   $       $       $       $     
                            1.65        0.69        2.32        1.44
Weighted Average Common
Shares Outstanding
  Basic                     130,277      140,414      129,925      141,227
  Diluted                   132,137      141,951      131,867      142,999







Plains Exploration & Production Company
Operating Data
                                  Three Months Ended  Twelve Months Ended
                                  December 31,        December 31,
                                  2012      2011      2012         2011
                                            (Unaudited)
Daily Average Volumes
 Oil and liquids sales (Bbls)     93,043    52,262    66,571       48,964
 Gas (Mcf)
   Production                     242,241   324,288   241,726      305,691
   Used as fuel                   3,032     5,481     3,721        5,776
   Sales                         239,209   318,807   238,005      299,915
 BOE
   Production                     133,416   106,310   106,859      99,912
   Sales                         132,911   105,396   106,239      98,950
Unit Economics (in dollars)
 Average Index Prices
   ICE Brent Price per Bbl        $       $       $          $  
                                  110.05   108.96   111.63      110.85
   NYMEX Price per Bbl            88.23     94.06     94.15        95.11
   NYMEX Price per Mcf            3.38      3.57      2.79         4.04
 Average Realized Sales Price
 Before Derivative Transactions
   Oil (per Bbl)                  $      $      $         $   
                                  93.28    87.02    95.46       85.53
   Gas (per Mcf)                  3.19      3.30      2.67         3.91
   Per BOE                        71.05     53.13     65.79        54.18
 Cash Margin per BOE ^(1)
   Oil and gas revenues          $      $      $         $   
                                  71.05    53.13    65.79       54.18
   Costs and expenses
    Lease operating expenses    (10.20)   (10.37)   (10.12)      (9.27)
    Steam gas costs             (1.18)    (1.63)    (1.22)       (1.81)
    Electricity                 (0.97)    (1.14)    (1.13)       (1.14)
    Production and ad valorem   (1.72)    (1.66)    (1.90)       (1.53)
   taxes
    Gathering and               (1.58)    (1.78)    (1.90)       (1.72)
   transportation
    Oil and gas related DD&A    (32.18)   (21.22)   (27.62)      (17.76)
   Gross margin (GAAP)            23.22     15.33     21.90        20.95
           Oil and gas related    32.18     21.22     27.62        17.76
           DD&A
           Realized gain (loss)
           on derivative          0.45      (0.84)    1.23         (1.42)
           instruments
   Cash margin (non-GAAP)         $      $      $         $   
                                  55.85    35.71    50.75       37.29
Oil and gas capital expenditures  $        $        $ 1,908,076  $ 1,856,377
accrued ($ in thousands) ^(2)     437,407  492,235

     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 December 31,
                                             2012
                                             Oil        Gas          BOE
                                             (per Bbl)  (per Mcf)
 Average Realized Sales Price
 Average realized price before derivative    $      $       $    
 instruments (GAAP) ^(1)                    93.28     3.19        71.05
  Realized gain onderivative  -          0.25         0.45
 instruments
 Realized cash price including derivative    $      $       $    
 settlements (non-GAAP)                      93.28     3.44        71.50
                                             Three Months Ended December 31,
                                             2011
                                             Oil        Gas          BOE
                                             (per Bbl)  (per Mcf)
 Average Realized Sales Price
 Average realized price before derivative    $      $       $    
 instruments (GAAP) ^(1)                    87.02     3.30        53.13
  Realized (loss) gain         (3.12)     0.23         (0.84)
 onderivative instruments
 Realized cash price including derivative    $      $       $    
 settlements (non-GAAP)                      83.90     3.53        52.29
                                             Twelve Months Ended December 31,
                                             2012
                                             Oil        Gas          BOE
                                             (per Bbl)  (per Mcf)
 Average Realized Sales Price
 Average realized price before derivative    $      $       $    
 instruments (GAAP) ^(1)                    95.46     2.67        65.79
  Realized (loss) gain         (0.13)     0.58         1.23
 onderivativeinstruments
 Realized cash price including derivative    $      $       $    
 settlements (non-GAAP)                      95.33     3.25        67.02
                                             Twelve Months Ended December 31,
                                             2011
                                             Oil        Gas          BOE
                                             (per Bbl)  (per Mcf)
 Average Realized Sales Price
 Average realized price before derivative    $      $       $    
 instruments (GAAP) ^(1)                    85.53     3.91        54.18
  Realized (loss) gain          (3.31)     0.07         (1.42)
 onderivative instruments
 Realized cash price including derivative    $      $       $    
 settlements (non-GAAP)                      82.22     3.98        52.76

^(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)
                                                Twelve Months Ended
                                                December 31,
                                                2012            2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income                                     $   342,787  $   206,679
Items not affecting cash flows from operating
activities
Depreciation, depletion, amortization and  1,118,052       681,655
accretion
Deferred income tax expense                175,412         160,214
Debt extinguishment costs                  4,160           2,844
Loss (gain) on mark-to-market derivative   2,879           (81,981)
contracts
(Gain) loss on investment measured at      (206,552)       52,675
fair value
Non-cash compensation                      60,247          49,193
Other non-cash items                       8,270           (5,559)
Change in assets and liabilities from           (174,464)       45,035
operating activities
Net cash provided by operating activities       1,330,791       1,110,755
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties             (1,854,255)     (1,783,304)
Acquisition of oil and gas properties^         (51,051)        (40,515)
Gulf of Mexico Acquisition                      (5,895,878)     -
Proceeds from sales of oil and gas properties
and                                             67,619          736,228
 related assets, net of costs and expenses
Derivative settlements                          42,894          (55,412)
Additions to other property and equipment       (12,584)        (13,140)
Other                                           -               1,552
Net cash used in investing activities           (7,703,255)     (1,154,591)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities     9,479,075       6,305,300
Repayments of revolving credit facilities       (8,644,075)     (6,190,300)
Proceeds from five-year term loan               730,331         -
Proceeds from seven-year term loan              1,220,533       -
Principal payments of long-term debt            (156,182)       (1,295,737)
Proceeds from issuance of Senior Notes          3,750,000       1,600,000
Costs incurred in connection with financing     (130,261)       (30,239)
arrangements
Purchase of treasury stock                      (88,490)        (361,729)
Net proceeds from issuance of noncontrolling
interest                                        -               430,246
 in the form of preferred stock of
subsidiary
Distributions to holders of noncontrolling
interest in the                                 (27,000)        (1,050)
 form of preferred stock of subsidiary
Other                                           -               9
Net cash provided by financing activities       6,133,931       456,500
Net (decrease) increase in cash and cash        (238,533)       412,664
equivalents
Cash and cash equivalents, beginning of period  419,098         6,434
Cash and cash equivalents, end of period        $   180,565  $   419,098







Plains Exploration & Production Company
Consolidated Balance Sheets
(in thousands of dollars)
                                                  December 31,   December 31,
                                                  2012           2011
                 ASSETS
Current Assets
 Cash and cash equivalents                        $        $      
                                                  180,565        419,098
 Accounts receivable                              584,722        302,675
 Commodity derivative contracts                   56,208         50,964
 Inventories                                      27,672         20,173
 Investment                                       818,223        611,671
 Deferred income taxes                            150,876        20,723
 Prepaid expenses and other current assets        21,464         16,073
                                                  1,839,730      1,441,377
Property and Equipment, at cost
 Oil and natural gas properties - full cost
 method
       Subject to amortization                    18,814,337     12,016,252
       Not subject to amortization                3,631,475      2,409,449
 Other property and equipment                     153,344        145,959
                                                  22,599,156     14,571,660
 Less allowance for depreciation, depletion,      (7,870,356)    (6,846,365)
 amortization and impairment
                                                  14,728,800     7,725,295
Goodwill                                          535,140        535,140
Commodity Derivative Contracts                    903            12,678
Other Assets                                      193,710        76,982
                                                  $           $    
                                                  17,298,283    9,791,472
                 LIABILITIES AND EQUITY
Current Liabilities
 Accounts payable                                 $        $      
                                                  431,422        385,231
 Commodity derivative contracts                   18,942         3,761
 Royalties and revenues payable                   139,717        97,095
 Interest payable                                 105,440        39,342
 Other current liabilities                        120,192        100,757
 Current maturities of long-term debt             164,288        -
                                                  980,001        626,186
Long-Term Debt                                    9,979,369      3,760,952
Other Long-Term Liabilities
 Asset retirement obligation                      565,989        230,633
 Commodity derivative contracts                   26,810         823
 Other                                            19,105         15,749
                                                  611,904        247,205
Deferred Income Taxes                             1,770,568      1,461,897
Equity
Stockholders' equity
 Common stock                                     1,439          1,439
 Additional paid-in capital                       3,437,826      3,434,928
 Retained earnings                                637,411        337,991
 Treasury stock, at cost                          (560,198)      (509,722)
                                                  3,516,478      3,264,636
Noncontrolling interest
 Preferred stock of subsidiary                 439,963        430,596
                                                  3,956,441      3,695,232
                                                  $           $    
                                                  17,298,283    9,791,472





Plains Exploration & Production Company
Summary of Open Derivative Positions
At February 20, 2013
                                                             Average
           Instrument          Daily        Average          Deferred
Period     Type                Volumes      Price ^(2)       Premium     Index
^(1)
Sales of Crude Oil Production
2013
   Feb -   Swap contracts^(3)  40,000 Bbls  $109.23          -           Brent
   Dec
   Feb -                                    $100.00 Floor    $6.800 per
   Dec     Put options^(4)     13,000 Bbls  with an $80.00   Bbl         Brent
                                            Limit
   Feb -   Three-way                        $100.00 Floor
   Dec     collars^(5)         25,000 Bbls  with an $80.00   -           Brent
                                            Limit
                                            $124.29 Ceiling
   Feb -   Three-way                        $90.00 Floor
   Dec     collars^(5)         5,000 Bbls   with a $70.00    -           Brent
                                            Limit
                                            $126.08 Ceiling
   Feb -                                    $90.00 Floor     $6.253 per
   Dec     Put options^(4)     17,000 Bbls  with a $70.00    Bbl         Brent
                                            Limit
2014
   Jan -                                    $100.00 Floor    $7.110 per
   Dec     Put options^(4)     5,000 Bbls   with an $80.00   Bbl         Brent
                                            Limit
   Jan -                                    $95.00 Floor     $6.091 per
   Dec     Put options^(4)     30,000 Bbls  with a $75.00    Bbl         Brent
                                            Limit
   Jan -                                    $90.00 Floor     $5.739 per
   Dec     Put options^(4)     75,000 Bbls  with a $70.00    Bbl         Brent
                                            Limit
2015
   Jan -                                    $90.00 Floor     $6.889 per
   Dec     Put options^(4)     84,000 Bbls  with a $70.00    Bbl         Brent
                                            Limit
Sales of Natural Gas
Production
2013
   Feb -   Swap contracts^(3)  110,000      $4.27            -           Henry
   Dec                         MMBtu                                     Hub
2014
   Jan -   Swap contracts^(3)  100,000      $4.09            -           Henry
   Dec                         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 fixed price, we receive the
^(3) 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
^(4) 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 barrel floor, we receive the
     difference between the per barrel floor and the index price up to a
^(5) maximum of $20 per barrel. We pay the difference between the index 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.

Derivative Settlements
(in thousands of dollars)
The following tables reflect cash receipts (payments) for derivatives
attributable to the stated production periods.
               Three Months Ended          Twelve Months Ended
               December 31,                December 31,
               2012         2011           2012                    2011
Oil sales     $       $          $                $     
                  -     (15,008)      (3,201)                 (59,217)
Natural gas    5,454        6,881          50,954                  7,915
sales
               $        $        $        47,753  $     
               5,454       (8,127)                                (51,302)





Plains Exploration & Production Company
Reconciliation of GAAP to Non-GAAP Measure
The following tables reconcile net income (GAAP) to adjusted net income and
adjusted net income attributable to common stockholders (non-GAAP) for the
three and twelve months ended December 31, 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
                                            December 31,
                                            2012                 2011
                                            (millions of dollars)
Net income (GAAP)                           $ 227.8              $  99.1
          Unrealized loss on mark-to-market 15.5                 11.5
          derivative contracts
          Realized gain (loss) on
          mark-to-market derivative         5.5                  (8.0)
          contracts ^(1)
          Unrealized gain on investment     (298.9)              (232.3)
          measured at fair value
          Debt extinguishment costs         3.2                  121.0
          Acquisition and merger related    35.5                 -
          costs
          Bridge loan facility commitment   31.8                 -
          fee and related expenses
          Adjust income taxes ^(2)          43.6                 38.7
Adjusted net income (non-GAAP)            $  64.0             $  30.0
          Net income attributable to
          noncontrolling interest in the
          form                              (9.2)                (1.4)
           of preferred stock of
          subsidiary
Adjusted net income attributable to common $  54.8             $  28.6
stockholders (non-GAAP)
                                            Twelve Months Ended
                                            December 31,
                                            2012                 2011
                                            (millions of dollars)
Net income (GAAP)                           $ 342.8              $ 206.7
          Unrealized loss (gain) on
          mark-to-market derivative         2.9                  (82.0)
          contracts
          Realized gain (loss) on
          mark-to-market derivative         47.8                 (51.3)
          contracts ^(1)
          Unrealized (gain) loss on         (206.6)              52.7
          investment measured at fair value
          Debt extinguishment costs         8.4                  121.0
          Acquisition and merger related    42.2                 -
          costs
          Bridge loan facility commitment   31.8                 -
          fee and related expenses
          Adjust income taxes ^(2)          (3.7)                (22.7)
Adjusted net income (non-GAAP)            $ 265.6              $ 224.4
          Net income attributable to
          noncontrolling interest in the
          form                              (36.4)               (1.4)
           of preferred stock of
          subsidiary
Adjusted net income attributable to common $ 229.2              $ 223.0
stockholders (non-GAAP)
          The amounts presented in the above tables differ from the
          adjustments reflected in the calculation of operating cash flow on
^(1)      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 42% and 36% for
          the three months ended December 31, 2012 and 2011, respectively. Tax
^(2)      rates assumed based upon adjusted earnings are 40% and 41% for the
          twelve months ended December 31, 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 twelve months ended
December 31, 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     Twelve Months Ended
                                   December 31,           December 31,
                                   2012       2011        2012       2011
                                              (millions of dollars)
Net income                        $      $       $      $    
                                   227.8      99.1     342.8     206.7
Items not affecting operating cash
flows
Depreciation, depletion,        407.8      215.6       1,118.1    681.7
amortization and accretion
 Deferred income tax expense    91.1       55.0        175.4      160.2
 Debt extinguishment costs        3.2        121.0       8.4        121.0
 Unrealized loss (gain) on
mark-to-market derivative          15.5       11.5        2.9        (82.0)
contracts
 Unrealized (gain) loss on       (298.9)    (232.3)     (206.6)    52.7
investment measured at fair value
 Acquisition and merger related   38.9       -           38.9       -
costs
 Bridge loan facility commitment  31.8       -           31.8       -
fee and related expenses
 Non-cash compensation            22.3       22.0        60.2       49.2
 Other non-cash items             (2.1)      0.8         8.3        (5.6)
 Realized gain (loss) on
mark-to-market derivative          5.5        (8.0)       42.9       (55.4)
contracts
Distributions to holders of
noncontrolling interest in the     (6.7)      (1.1)       (27.0)     (1.1)
form of preferred stock of
subsidiary
Operating cash flow (non-GAAP)     $      $       $       $   
                                   536.2     283.6      1,596.1    1,127.4
Reconciliation of non-GAAP to GAAP
measure
 Operating cash flow (non-GAAP)  $      $       $       $   
                                   536.2     283.6      1,596.1    1,127.4
 Cash portion of debt            -          (118.2)     (4.2)      (118.2)
extinguishment costs
 Acquisition and merger related  (38.9)     -           (38.9)     -
costs
 Bridge loan facility commitment (31.8)     -           (31.8)     -
fee and related expenses
 Changes in assets and
liabilities from operating         (182.5)    13.6        (174.5)    45.1
activities
 Realized (gain) loss on
mark-to-market derivative          (5.5)      8.0         (42.9)     55.4
contracts
 Distributions to holders of
noncontrolling interest in the     6.7        1.1         27.0       1.1
form of preferred stock of
subsidiary

                                   $      $       $       $   
Net cash provided by operating     284.2     188.1      1,330.8    1,110.8
activities (GAAP)







Plains Exploration & Production Company
Proved Reserves, Reserve Replacement Ratio, PV-10 to Standardized Measure
Reconciliation
Estimated Proved Reserves ^(1)(MMBOE)
2011 Year-end proved reserves                                    410.9
2012 Extensions and discoveries                                  58.9
2012 Revisions                                                   (114.4)
2012 Acquisitions                                               126.4
2012 Divestments                                                 (2.3)
2012 Production                                                  (39.1)
2012 Year-end proved reserves^                                  440.4
Reserve Replacement Ratio ^(2)                                  181%
PV-10 to Standardized Measure Reconciliation (in millions)
Estimated undiscounted future net cash flows before income       $  22,535.8
taxes
Present value of estimated future net cash flows before income   $  13,737.7
taxes (PV-10) ^(3)
Discounted future income taxes                                   (3,713.2)
Standardized measure of discounted future net cash flows         $  10,024.5

Estimated Probable Reserves^(1)
The Company had probable reserves of 193.8 MMBOE, estimated undiscounted
future net cash flows before income taxes for probable reserves of $12.9
billion and a PV-10^(3)of $5.5 billion at December 31, 2012. Probable reserves
are not recognized by GAAP, and therefore the PV-10 of probable reserves can
not be reconciled to a GAAP measure.

     Proved oil and gas reserves are those quantities of oil and gas, which,
     by analysis of geoscience and engineering data, can be estimated with
     reasonable certainty to be economically producible from a given date
^(1) forward, from known reservoirs and under the existing economic and
     operational environment.

     
     Probable reserves are additional reserves that are less certain to be
     recovered than proved reserves, but which, together with proved reserves,
     are as likely as not to be recovered. In addition to the uncertainties
     inherent in estimating quantities and values of proved reserves, probable
     reserves may be assigned to areas where data control or interpretations
     of available data are less certain and are structurally higher than
     proved reserves if they are adjacent to the proved reservoirs.
     Calculation: reserve extensions, discoveries, revisions and acquisitions
     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 will
     offset produced volumes and provide for future production given the
^(2) 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.
     PV-10 is PXP's estimate of the present value of future net revenues from
     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, for proved oil and gas reserves, generally differs from the
     Standardized Measure, the most directly comparable GAAP financial measure
     for proved oil and gas reserves, 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. PXP
^(3) 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.



Plains Exploration & Production Company
Costs Incurred
                               Twelve Months Ended
                               December 31, 2012
Costs Incurred (in millions):
Property acquisition costs:
 Unproved properties      $     2,102.6
 Proved properties              4,139.0
Exploration costs                    1,079.0
Development costs                    829.1
Total costs incurred ^(1)      $     8,149.7

^(1) Includes capitalized interest expense of $49.1 million and capitalized
     general and administrative expense of $93.5 million.



SOURCE Plains Exploration & Production Company

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