PXP Reports Second-Quarter 2011 Net Income of $125 Million or 87 Cents Per Diluted Share and 15% Growth in Year-Over-Year Production

PXP Announces Eagle Ford Shale Flow Rates from the Carmody #1 and Carmody #2 Wells at the Combined Initial Production Rate of 2,919 Net Barrels of Oil Equivalent per Day

News provided by

Plains Exploration & Production Company

Aug 04, 2011, 07:31 ET

HOUSTON, Aug. 4, 2011 /PRNewswire/ --

Second-Quarter Highlights:

  • Revenues of $514.8 million and net income of $124.9 million, or $0.87 per diluted share.
  • Adjusted net income of $77.1 million, or $0.54 per diluted share (a non-GAAP measure).
  • Income from operations of $186.1 million.
  • Net cash provided by operating activities of $287.5 million.
  • Operating cash flow of $299.6 million (a non-GAAP measure).
  • Average daily sales volumes of approximately 97.7 thousand barrels of oil equivalent (BOE), a 15% increase compared to second-quarter 2010 or 27% increase pro-forma for the 2010 asset sale.
  • Average daily liquids sales volumes increased 7% compared to second-quarter 2010 or 12% pro-forma for the 2010 asset sale and are expected to increase ratably throughout the rest of the year.
  • Crude oil price realization of 88%.
  • Executed crude oil contracts significantly improving differentials.
  • Total production costs per BOE of $16.09.
  • Gross margin per BOE was $25.31 and cash margin per BOE was $39.92 (a non-GAAP measure).

Plains Exploration & Production Company (NYSE: PXP) ("PXP" or the "Company") announces 2011 second-quarter financial and operating results.

FINANCIAL SUMMARY

PXP reports second-quarter revenues of $514.8 million and net income of $124.9 million, or $0.87 per diluted share, compared to revenues of $364.6 million and net income of $45.4 million, or $0.32 per diluted share, for the second-quarter 2010. 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, and other items. When considering these items, net income for the second-quarter 2011 was $77.1 million, or $0.54 per diluted share (a non-GAAP measure), compared to $36.9 million, or $0.26 per diluted share, for the second-quarter 2010.

For the first six months of 2011, PXP reports revenues of $945.1 million and net income of $195.9 million, or $1.37 per diluted share, compared to revenues of $748.6 million and net income of $103.9 million, or $0.73 per diluted share, for the same period in 2010. 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, and other items. When considering these items, net income for the first six months of 2011 was $129.6 million, or $0.90 per diluted share (a non-GAAP measure), compared to $80.5 million, or $0.57 per diluted share, for the same period in 2010.

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

CRUDE OIL MARKETING UPDATE

In August, PXP executed a new marketing contract for its California crude production with ConocoPhillips (NYSE: COP). Currently PXP sells approximately 65% of its California crude oil to ConocoPhillips. The new contract covers approximately 90% of PXP's California production, extends the dedication from January 1, 2015 to January 1, 2023 and replaces the percent of NYMEX index pricing mechanism with a market-based pricing approach beginning in 2012.

Separately, PXP executed an agreement with a third party purchaser to sell a large portion of its Eagle Ford crude oil using a Light Louisiana Sweet (LLS) based pricing mechanism.

In 2012, using the current market price outlook and the new marketing contracts, PXP currently expects full-year oil price realization to be between 101% - 103% of NYMEX. PXP expects 2012 total company liquids price realization, which includes crude oil and natural gas liquids, to be between 93% - 95% of NYMEX compared to full-year 2011 total company liquids price realization guidance range of 84% - 86%.

MANAGEMENT COMMENT

James C. Flores, Chairman, President and CEO of PXP commented, "Today's announcement underscores the strength of our asset base and the skill of our dedicated employees as we continue to execute our plan to manage volume growth and strong margins. Compared to the second-quarter 2010 our total Company sales volumes increased 15% and liquids sales volumes increased 12%, pro-forma for the 2010 asset sale. In our Eagle Ford area, daily sales volumes are expected to more than double by year-end 2011 as operational momentum builds during the second half of the year. In each of our core asset areas, we remain focused on the execution of the onshore oil drilling and expansion plan and results continue to be positive. With higher crude volumes and stronger crude pricing, the business generated a 41% increase in operating cash flow and a 20% increase in cash margin per BOE over the second-quarter 2010. We expect these trends to continue supported by the accelerated Eagle Ford activity and the recently executed crude oil marketing contracts reflecting premium pricing to NYMEX."

GUIDANCE UPDATE

Due primarily to our accelerated drilling activity in the Eagle Ford and a higher than originally planned rig count in the Haynesville, PXP's Board of Directors approved an increase in 2011 capital spending  which is estimated to be approximately $1.5 billion, excluding deepwater spending, up from $1.2 billion.

For the first six months, average daily sales volumes were 92.9 thousand BOE. With higher drilling activity year-to-date than originally planned in the Haynesville and the Eagle Ford, full-year 2011 average daily sales volumes are now expected to be near the upper end of a new guidance range of 97 – 100 thousand BOE per day.

PXP expects its oil price realization for the full-year 2011 to be above the guidance range due to continued strength of California crude oil pricing relative to NYMEX West Texas Intermediate.

PXP expects lease operating expense per BOE, a component of total production cost per BOE, to be at the high end of the $7.90 - $8.30 per BOE full-year 2011 guidance range due to the increased activity in the Eagle Ford.

OPERATIONAL UPDATE

In the Texas Panhandle asset area, PXP has 5 drilling rigs operating in the Granite Wash trend and expects to continue this level of activity through 2011. Second-quarter daily sales volumes averaged approximately 13,620 BOE per day net to PXP, or 52% higher than first-quarter 2011 and 139% higher than the second-quarter 2010. Average daily sales volumes are expected to increase to approximately 17,000 BOE net per day by year-end 2011. During 2010 and early 2011, PXP built 15 production handling facilities and related infrastructure in order to support the rapid growth in sales volumes that PXP is now reporting.

In the Eagle Ford asset area, PXP has 5.5 net drilling rigs operating, up from the 3 net rig program originally planned for 2011. Second-quarter daily sales volumes averaged approximately 2,330 BOE per day net to PXP, an increase of approximately 4% to first-quarter 2011 average daily sales volumes. For the month of July, daily sales volumes averaged approximately 4,400 BOE per day net to PXP; and PXP expects to exit the year above 10,000 BOE net per day for this asset area.

The two most recent initial production test rates are as follows: The Carmody Trust 1H and the Carmody Trust 2H, both located in Karnes County, Texas, achieved an initial production rate of approximately 1,745 gross and 1,396 net  BOE  per day and 1,904 gross and 1,523 net  BOE  per day, respectively.

During the first half of this year, PXP built 4 production handling facilities and related infrastructure out of the 12 facilities currently planned through 2012 to support future sales volume growth. Each facility has the capability of supporting multiple wells and construction continues on future production facilities. Timing of right-of-way approvals temporarily slowed construction during the second quarter which slowed the process of connecting completed wells to pipelines. With many of the initial logistics resolved, PXP anticipates a ramp up in sales volumes during the second half of 2011.

In the California asset area, PXP has 3 drilling rigs operating onshore where PXP continues its active development program in the Los Angeles and San Joaquin Basins. Daily sales volumes onshore and offshore averaged 40,500 BOE per day net to PXP, or 7% higher than first-quarter 2011 and slightly higher than the second-quarter 2010. Average daily sales volumes are expected to be above 41,000 BOE net per day by year-end 2011.

In the Haynesville Shale asset area, PXP's primary operator is currently operating 31 rigs and expects to reduce the rig count during the quarter. In addition, PXP expects 15 or more rigs run by other operators on its acreage. Second-quarter daily sales volumes averaged approximately 181.7 million cubic feet equivalent (MMcfe) per day net to PXP, or 12% higher than first-quarter 2011 and 71% higher than second-quarter 2010. The rate of increase in sales volumes is anticipated to slow as the rig count decreases later this year.

In the Wyoming Mowry Shale, PXP drilled and completed its first well in June 2011 and produced high-quality oil in small quantities. PXP drilled its second well and is in the process of completing this well. We will study the results of these initial wells and drill two additional wells in 2012 to further evaluate the project.

In the Gulf of Mexico asset area, the operator of the Lucius discovery, Anadarko Petroleum Corporation (NYSE: APC), recently announced the finalization of a unitization agreement with Exxon Mobil Corporation and co-owners to develop the Lucius field. Anadarko will operate the unit which includes portions of Keathley Canyon blocks 874, 875, 918 and 919 in the deepwater Gulf of Mexico. Following the unitization agreement, the Lucius interest owners entered into an agreement with the Hadrian South co-venturers whereby natural gas produced from the Hadrian South field will be processed through the Lucius facility in return for a production-handling fee and reimbursement for any required facility upgrades.

CONFERENCE CALL

PXP will host a conference call today, Thursday, August 4, 2011 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: 82594675. The replay can be accessed by dialing 1-855-859-2056 or 1-404-537-3406. A live webcast of the conference call and a slide presentation will be available in the Investor Information section of PXP's website at www.pxp.com.

PXP is an independent oil and gas company primarily engaged in the activities of acquiring, developing, exploring and producing oil and gas in California, Texas, and Louisiana. PXP is headquartered in Houston, Texas.

ADDITIONAL INFORMATION & FORWARD-LOOKING STATEMENTS

This press release contains forward-looking information regarding PXP that is intended to be covered by the safe harbor "forward-looking statements" provided by the Private Securities Litigation Reform Act of 1995. All statements included in this press release that address activities, events or developments that PXP expects, believes or anticipates will or may occur in the future are forward-looking statement. These include statements regarding:

* reserve and production estimates,
* oil and gas prices,
* the impact of derivative positions,
* production expense estimates,
* cash flow estimates,
* future financial performance,
* capital and credit market conditions,
* planned capital expenditures, and
* other matters that are discussed in PXP's filings with the SEC.

These statements are based on our current expectations and projections about future events and involve known and unknown risks, uncertainties, and other factors that may cause our actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. Please refer to our filings with the SEC, including our Form 10-K, for a discussion of these risks.

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

Six Months Ended




June 30,

June 30,




2011


2010


2011


2010







(Unaudited)

Revenues







Oil sales

$ 399,306

$ 276,263

$ 731,149

$ 552,267

Gas sales

113,670

87,678

210,472

195,417

Other operating revenues

1,809

652

3,478

959




514,785

364,593

945,099

748,643

Costs and Expenses







Lease operating expenses

82,142

57,536

154,393

120,039

Steam gas costs

16,865

15,357

32,626

35,020

Electricity

10,371

11,115

20,091

21,149

Production and ad valorem taxes

16,920

3,828

28,448

12,275

Gathering and transportation expenses

16,841

12,912

29,588

22,331

General and administrative

30,783

30,301

66,806

67,691

Depreciation, depletion and amortization

150,757

123,810

285,300

246,203

Impairment of oil and gas properties

-

59,475

-

59,475

Accretion

4,314

4,407

8,571

8,818

Legal recovery

-

-

-

(8,423)

Other operating income

(303)

(3,945)

(607)

(4,514)




328,690

314,796

625,216

580,064











Income from Operations

186,095

49,797

319,883

168,579

Other (Expense) Income







Interest expense

(37,242)

(28,039)

(69,646)

(49,092)

Debt extinguishment costs

-

-

-

(728)

Gain (loss) on mark-to-market derivative contracts

18,912

57,984

(32,084)

65,840

Gain on investment measured at fair value

43,307

-

110,561

-

Other income

996

11,235

1,550

12,541

Income Before Income Taxes

212,068

90,977

330,264

197,140

Income tax expense








Current

(387)

(2,672)

(759)

(7,410)


Deferred

(86,789)

(42,930)

(133,634)

(85,827)

Net Income

$ 124,892

$   45,375

$ 195,871

$ 103,903

Earnings per Share







Basic

$       0.88

$       0.32

$       1.39

$       0.74

Diluted

$       0.87

$       0.32

$       1.37

$       0.73

Weighted Average Shares Outstanding







Basic

141,797

140,560

141,335

140,153

Diluted

143,300

141,557

143,361

141,752

Plains Exploration & Production Company

Operating Data







Three Months Ended

Six Months Ended







June 30,

June 30,







2011

2010

2011

2010









(Unaudited)

Daily Average Volumes








Oil and liquids sales (Bbls)

48,524

45,395

46,308

45,307

Gas (Mcf)










Production

301,162

242,961

285,280

243,773


Used as fuel

5,874

5,272

5,831

5,292


Sales



295,288

237,689

279,449

238,481

BOE












Production

98,718

85,889

93,855

85,935


Sales



97,739

85,010

92,883

85,053

Unit Economics (in dollars)










Average NYMEX Prices









Oil


$   102.34

$     78.05

$     98.50

$     78.46


Gas


4.32

4.09

4.20

4.67

Average Realized Sales Price Before Derivative Transactions








Oil (per Bbl)

$     90.42

$     66.87

$     87.23

$     67.34


Gas (per Mcf)

4.23

4.05

4.16

4.52


Per BOE

57.68

47.05

56.01

48.57

Cash Margin per BOE (1)









Oil and gas revenues


$     57.68

$     47.05

$     56.01

$     48.57


Costs and expenses









  Lease operating expenses

(9.23)

(7.44)

(9.19)

(7.80)


  Steam gas costs

(1.90)

(1.99)

(1.94)

(2.27)


  Electricity

(1.17)

(1.44)

(1.20)

(1.37)


  Production and ad valorem taxes

(1.90)

(0.49)

(1.69)

(0.80)


  Gathering and transportation

(1.89)

(1.67)

(1.76)

(1.45)


  Oil and gas related DD&A

(16.28)

(15.33)

(16.28)

(15.33)


Gross margin (GAAP)

25.31

18.69

23.95

19.55


  Oil and gas related DD&A

16.28

15.33

16.28

15.33


  Realized losses on derivative
   instruments

(1.67)

(0.84)

(1.72)

(1.23)


Cash margin (Non-GAAP)

$     39.92

$     33.18

$     38.51

$     33.65














Oil and gas capital expenditures accrued ($ in thousands) (2)

$ 472,056

$ 284,753

$ 861,397

$ 508,169














(1)  Cash margin per BOE (a non-GAAP measure) is calculated by adjusting gross margin per BOE (a GAAP measure) to include realized gains and losses on derivative instruments and to exclude DD&A.  Management believes this presentation may be helpful to investors as it represents the cash generated by our oil and gas production that is available for, among other things, capital expenditures and debt service.  PXP management  uses this information to analyze operating trends for comparative purposes within the industry.  This measure is not intended to replace the GAAP statistic but rather to provide additional information that may be helpful in evaluating trends and performance.    

(2)  Additions to oil and gas properties reported in our consolidated statement of cash flows differ from the accrual basis amounts reflected above due to the timing of cash payments.  Excludes acquisitions.  

Plains Exploration & Production Company

Reconciliation of GAAP to Non-GAAP Measure















Three Months Ended June 30, 2011





Oil

Gas

BOE





(per Bbl)

(per Mcf)


Average Realized Sales Price


















Average realized price before derivative instruments (GAAP) (1)

$   90.42

$      4.23

$ 57.68


Realized losses on derivative instruments

(3.36)

-

(1.67)











Realized cash price including derivative settlements (non-GAAP)

$   87.06

$      4.23

$ 56.01

























Three Months Ended June 30, 2010





Oil

Gas

BOE





(per Bbl)

(per Mcf)


Average Realized Sales Price
















Average realized price before derivative instruments (GAAP) (1)

$   66.87

$      4.05

$ 47.05


Realized (losses) gains on derivative instruments

(4.27)

0.52

(0.84)











Realized cash price including derivative settlements (non-GAAP)

$   62.60

$      4.57

$ 46.21

























Six Months Ended June 30, 2011





Oil

Gas

BOE





(per Bbl)

(per Mcf)


Average Realized Sales Price


















Average realized price before derivative instruments (GAAP) (1)

$   87.23

$      4.16

$ 56.01


Realized (losses) gains on derivative instruments

(3.52)

0.01

(1.72)











Realized cash price including derivative settlements (non-GAAP)

$   83.71

$      4.17

$ 54.29

























Six Months Ended June 30, 2010





Oil

Gas

BOE





(per Bbl)

(per Mcf)


Average Realized Sales Price
















Average realized price before derivative instruments (GAAP) (1)

$   67.34

$      4.52

$ 48.57


Realized (losses) gains on derivative instruments

(4.28)

0.38

(1.23)











Realized cash price including derivative settlements (non-GAAP)

$   63.06

$      4.90

$ 47.34










(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)




Six Months Ended




June 30,




2011

2010




(Unaudited)

CASH FLOWS FROM OPERATING ACTIVITIES



Net income


$   195,871

$   103,903

Items not affecting cash flows from operating activities




Depreciation, depletion, amortization and accretion

293,871

255,021

Impairment of oil and gas properties

-

59,475

Deferred income tax expense

133,634

85,827

Debt extinguishment costs

-

728

Loss (gain) on mark-to-market derivative contracts

32,084

(65,840)

Gain on investment measured at fair value

(110,561)

-

Non-cash compensation

28,031

22,955

Other non-cash items

(302)

1,672

Change in assets and liabilities from operating activities

4,797

10,691

Net cash provided by operating activities

577,425

474,432

CASH FLOWS FROM INVESTING ACTIVITIES



Additions to oil and gas properties

(800,170)

(558,386)

Acquisition of oil and gas properties (1)

(32,456)

43,923

Proceeds from sales of oil and gas properties, net of costs and expenses

11,987

7,230

Derivative settlements

(30,039)

(16,153)

Additions to other property and equipment

(6,534)

(4,394)

Net cash used in investing activities

(857,212)

(527,780)

CASH FLOWS FROM FINANCING ACTIVITIES



Borrowings from revolving credit facilities

2,679,200

860,455

Repayments of revolving credit facilities

(2,989,200)

(1,090,455)

Proceeds from issuance of Senior Notes

600,000

300,000

Costs incurred in connection with financing arrangements

(11,320)

(5,932)

Other

4

-

Net cash provided by financing activities

278,684

64,068

Net (decrease) increase in cash and cash equivalents

(1,103)

10,720

Cash and cash equivalents, beginning of period

6,434

1,859

Cash and cash equivalents, end of period

$       5,331

$     12,579














(1)  Cash inflow in 2010 is associated with an adjustment to the final settlement of the $1.1 billion payment in September 2009 related to the prepayment of the Haynesville drilling carry.    

Plains Exploration & Production Company

Consolidated Balance Sheets

(in thousands of dollars)




June 30,

December 31,




2011

2010



ASSETS

(Unaudited)

Current Assets



Cash and cash equivalents

$        5,331

$            6,434

Accounts receivable

250,413

269,024

Inventories

27,166

24,406

Deferred income taxes

66,002

74,086

Prepaid expenses and other current assets

27,412

28,937




376,324

402,887

Property and Equipment, at cost



Oil and natural gas properties - full cost method




Subject to amortization

10,844,515

9,975,056


Not subject to amortization

3,309,642

3,304,554

Other property and equipment

143,684

137,150




14,297,841

13,416,760

Less allowance for depreciation, depletion, amortization and impairment

(6,475,951)

(6,196,008)




7,821,890

7,220,752

Goodwill

535,142

535,144

Investment

774,907

664,346

Other Assets

76,179

71,808




$ 9,584,442

$     8,894,937










LIABILITIES AND STOCKHOLDERS' EQUITY


Current Liabilities



Accounts payable

$    315,242

$        284,628

Commodity derivative contracts

59,786

52,971

Royalties and revenues payable

82,818

70,990

Interest payable

58,446

49,127

Other current liabilities

74,338

75,973




590,630

533,689

Long-Term Debt

3,637,447

3,344,717







Other Long-Term Liabilities



Asset retirement obligation

239,361

225,571

Commodity derivative contracts

20,400

24,740

Other

23,146

28,205




282,907

278,516

Deferred Income Taxes

1,480,598

1,355,050

Stockholders'  Equity



Common stock

1,439

1,439

Additional paid-in capital

3,410,856

3,427,869

Retained earnings

328,624

148,620

Treasury stock, at cost

(148,059)

(194,963)




3,592,860

3,382,965




$ 9,584,442

$     8,894,937

Plains Exploration & Production Company

Summary of Open Derivative Positions

At July 1, 2011





















Average




Instrument

Daily

Average

Deferred

Period (1)

Type

Volumes

Price (2)

Premium

Index

Sales of Crude Oil Production








2011










July - Dec

Put options (3)

31,000 Bbls

$80.00 Floor with a $60.00 Limit

$5.023 per Bbl

WTI













July - Dec

Three-way collars (4)

9,000 Bbls

$80.00 Floor with a $60.00 Limit

$1.00 per Bbl

WTI






$110.00 Ceiling



2012










Jan - Dec

      Put options (3)      

40,000 Bbls

$80.00 Floor with a $60.00 Limit

$6.087 per Bbl

WTI











Sales of Natural Gas Production








2011










July - Dec

Three-way collars (5)

200,000 MMBtu

$4.00 Floor with a $3.00 Limit

-

Henry Hub







$4.92 Ceiling















2012









Jan - Dec

Put options (6)

160,000 MMBtu

$4.30 Floor with a $3.00 Limit

$0.294 per MMBtu

Henry Hub












(1)  All of our derivatives are settled monthly.  

(2)  The average strike prices do not reflect the cost to purchase the put options or collars.  

(3)  If the index price is less than the $80 per barrel floor, we receive the difference between the $80 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 $80 per barrel, we pay only the option premium.  

(4)  If the index price is less than the $80 per barrel floor, we receive the difference between the $80 per barrel floor and the index price up to a maximum of $20 per barrel less the option premium. We pay the difference between the index price and $110 per barrel plus the option premium if the index price is greater than the $110 per barrel ceiling. If the index price is at or above $80 per barrel but at or below $110 per barrel, we pay only the option premium.  

(5)  If the index price is less than the $4.00 per MMBtu floor, we receive the difference between the $4.00 per MMBtu floor and the index price up to a maximum of $1.00 per MMBtu. We pay the difference between the index price and $4.92 per MMBtu if the index price is greater than the $4.92 per MMBtu ceiling. If the index price is at or above $4.00 per MMBtu but at or below $4.92 per MMBtu, no cash settlement is required.  

(6)  If the index price is less than the $4.30 per MMBtu floor, we receive the difference between the $4.30 per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu less the option premium. If the index price is at or above $4.30 per MMBtu, we pay only the option premium.  

Derivative Settlements

(in thousands of dollars)










The following table reflects cash (payments) receipts for derivatives attributable to the stated production periods.













Three Months Ended

Six Months Ended



June 30,

June 30,



2011

2010

2011

2010

Oil sales


$           (14,855)

$        (17,660)

$                (29,537)

$             (35,126)

Natural gas sales

-

11,161

620

16,250



$           (14,855)

$          (6,499)

$                (28,917)

$             (18,876)

Plains Exploration & Production Company

Reconciliation of GAAP to Non-GAAP Measure

The following table reconciles net income (GAAP) to adjusted net income (non-GAAP) for the three and six months ended June 30, 2011 and 2010. Adjusted net income excludes 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



June 30,



2011

2010



(millions of dollars)






Net income (GAAP)

$ 124.9

$   45.4

Unrealized gains on mark-to-market derivative contracts

(18.9)

(58.0)

Realized losses on mark-to-market derivative contracts (1)

(14.9)

(6.5)

Unrealized gain on investment measured at fair value

(43.3)

-

Impairment of oil and gas properties

-

59.5

Other non-operating income

-

(8.1)

Adjust income taxes (2)

29.3

4.6






Adjusted net income (non-GAAP)


$   77.1

$   36.9









Six Months Ended



June 30,



2011

2010



(millions of dollars)






Net income (GAAP)

$ 195.9

$ 103.9

Unrealized losses (gains) on mark-to-market derivative contracts

32.1

(65.8)

Realized losses on mark-to-market derivative contracts (1)

(28.9)

(18.9)

Unrealized gain on investment measured at fair value

(110.6)

-

Impairment of oil and gas properties

-

59.5

Legal recovery


-

(8.4)

Other non-operating income

-

(8.1)

Adjust income taxes (2)

41.1

18.3






Adjusted net income (non-GAAP)


$ 129.6

$   80.5












(1) The amounts presented in the above table differ from the adjustments reflected in the calculation of operating cash flow on the following page due to the accrued amounts reflected in the income statement versus the actual cash received or paid reflected in the consolidated statement of cash flows.


(2) Tax rates assumed based upon adjusted earnings are 43% and 53% for the three months ended June 30, 2011 and 2010, respectively. Tax rates assumed based upon adjusted earnings are 42% and 48% for the six months ended June 30, 2011 and 2010. 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 six months ended June 30, 2011 and 2010.  Management believes this presentation may be useful to investors.  PXP management uses this information for comparative purposes within the industry and as a means of measuring the Company's ability to fund capital expenditures and service debt. This measure is not intended to replace the GAAP statistic but rather to provide additional information that may be helpful in evaluating the Company's operational trends and performance.

Operating cash flow is calculated by adjusting net income to add back certain non-cash and non-operating items, including unrealized gains and losses on mark-to-market derivative contracts, to include derivative cash settlements for realized gains and losses on mark-to-market derivative contracts that are classified as investing activities for GAAP purposes, to exclude the unrealized gain on the investment measured at fair value and to exclude certain items.  















Three Months Ended

Six Months Ended




June 30,

June 30,




2011


2010


2011


2010







(millions of dollars)


Net income


$ 124.9

$   45.4

$ 195.9

$ 103.9

Items not affecting operating cash flows








 Depreciation, depletion, amortization and accretion

155.1

128.2

293.9

255.0

 Impairment of oil and gas properties

-

59.5

-

59.5

 Deferred income tax expense

86.8

42.9

133.6

85.8

 Debt extinguishment costs

-

-

-

0.7

 Unrealized (gains) losses on mark-to-market derivative
  contracts

(18.9)

(58.0)

32.1

(65.8)

 Unrealized gain on investment measured at fair value

(43.3)

-

(110.6)

-

 Non-cash compensation

11.2

6.1

28.0

23.0

 Other non-cash items

(1.2)

0.3

(0.3)

1.7

Realized losses on mark-to-market derivative contracts

(15.0)

(6.7)

(30.0)

(16.2)

Legal recovery and other

-

(8.1)

-

(16.5)

Current income taxes attributable to derivative contracts

-

2.7

-

7.4












Operating cash flow (non-GAAP)

$ 299.6

$ 212.3

$ 542.6

$ 438.5























Reconciliation of non-GAAP to GAAP measure









Operating cash flow (non-GAAP)

$ 299.6

$ 212.3

$ 542.6

$ 438.5


Legal recovery and other

-

8.1

-

16.5


Changes in assets and liabilities from operating activities

(27.1)

28.3

4.8

10.6


Realized losses on mark-to-market derivative contracts

15.0

6.7

30.0

16.2


Current income taxes attributable to derivative contracts

-

(2.7)

-

(7.4)












Net cash provided by operating activities (GAAP)

$ 287.5

$ 252.7

$ 577.4

$ 474.4

SOURCE Plains Exploration & Production Company

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