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

Feb 21, 2013, 07:21 ET from Plains Exploration & Production Company

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

  • Total revenues were $869.2 million, a 68% increase compared to fourth-quarter 2011.
  • Total 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.
  • Oil 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.
  • Net cash provided by operating activities was $284.2 million, a 51% increase over fourth-quarter 2011.
  • Operating cash flow (a non-GAAP measure) was $536.2 million, an 89% increase over fourth-quarter 2011.
  • Income from operations was $177.0 million, a 73% increase over fourth-quarter 2011.
  • Net 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.
  • Adjusted 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

  • Total revenues were $2.6 billion, a 31% increase compared to full-year 2011.
  • Total 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.
  • Oil 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.
  • Net cash provided by operating activities was $1.3 billion, a 20% increase over full-year 2011.
  • Operating cash flow (a non-GAAP measure) was $1.6 billion, a 42% increase over full-year 2011.
  • Income from operations was $615.7 million, a 4% increase over full-year 2011.
  • Net 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.
  • Adjusted 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

  • Proved reserves increased 7% to 440.4 million BOE.
  • Probable reserves are 193.8 million BOE.
  • The Company estimates possible reserves to be 157.0 million BOE and resource potential to be 2,817.0 million BOE.
  • 100% 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.
  • Standardized measure of discounted future net cash flows for proved reserves is $10.0 billion compared to $5.1 billion in 2011.
  • PV-10 value for proved reserves (a non-GAAP measure) is $13.7 billion compared to $7.9 billion in 2011.
  • Proved developed reserves are 63% of total proved reserves.
  • Proved oil reserves as a percentage of proved reserves are 82%.
  • Reserve 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 valorem taxes

21,091

16,141

73,873

55,225

Gathering and transportation expenses

19,333

17,278

73,852

62,103

General and administrative

G&A

54,424

39,080

157,022

134,044

Acquisition and merger related costs

35,468

-

42,151

-

Depreciation, depletion and amortization

402,083

211,284

1,101,108

664,478

Accretion

5,692

4,299

16,944

17,177

Other operating expense (income)

3,115

(78)

(27)

(735)

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 costs

(3,221)

(120,954)

(8,388)

(120,954)

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

(15,452)

(11,486)

(2,879)

81,981

Gain (loss) on investment measured at fair value

298,853

232,254

206,552

(52,675)

Other income

254

407

694

3,356

Income Before Income Taxes 

317,337

154,160

514,097

340,941

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    in the form of preferred stock of subsidiary

(9,161)

(1,400)

(36,367)

(1,400)

Net Income Attributable to Common Stockholders

$ 218,628

$ 97,704

$ 306,420

$ 205,279

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 taxes

(1.72)

(1.66)

(1.90)

(1.53)

   Gathering and transportation

(1.58)

(1.78)

(1.90)

(1.72)

   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 DD&A

32.18

21.22

27.62

17.76

Realized gain (loss) on derivative instruments

0.45

(0.84)

1.23

(1.42)

Cash margin (non-GAAP)

$        55.85

$        35.71

$        50.75

$        37.29

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

$    437,407

$    492,235

$ 1,908,076

$ 1,856,377

(1)

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 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 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 on derivative instruments

-

0.25

0.45

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 on derivative instruments

(3.12)

0.23

(0.84)

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 on derivative instruments

(0.13)

0.58

1.23

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 on derivative instruments

(3.31)

0.07

(1.42)

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 accretion

1,118,052

681,655

     Deferred income tax expense

175,412

160,214

     Debt extinguishment costs

4,160

2,844

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

2,879

(81,981)

     (Gain) loss on investment measured at fair value

(206,552)

52,675

     Non-cash compensation

60,247

49,193

     Other non-cash items

8,270

(5,559)

Change in assets and liabilities from operating activities

(174,464)

45,035

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    related assets, net of costs and expenses

67,619

736,228

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 arrangements

(130,261)

(30,239)

Purchase of treasury stock

(88,490)

(361,729)

Net proceeds from issuance of noncontrolling interest    in the form of preferred stock of subsidiary

-

430,246

Distributions to holders of noncontrolling interest in the    form of preferred stock of subsidiary

(27,000)

(1,050)

Other

-

9

Net cash provided by financing activities

6,133,931

456,500

Net (decrease) increase in cash and cash equivalents

(238,533)

412,664

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, amortization and impairment

(7,870,356)

(6,846,365)

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 (1)

Type

Volumes

Price (2)

Premium

Index

Sales of Crude Oil Production

2013

Feb - Dec

Swap contracts(3)

40,000 Bbls

$109.23

-

Brent

Feb - Dec

Put options(4)

13,000 Bbls

$100.00 Floor with an $80.00 Limit

$6.800 per Bbl

Brent

Feb - Dec

Three-way collars(5)

25,000 Bbls

$100.00 Floor with an $80.00 Limit

-

Brent

$124.29 Ceiling

Feb - Dec

Three-way collars(5)

5,000 Bbls

$90.00 Floor with a $70.00 Limit

-

Brent

$126.08 Ceiling

Feb - Dec

Put options(4)

17,000 Bbls

$90.00 Floor with a $70.00 Limit

$6.253 per Bbl

Brent

2014

Jan - Dec

Put options(4)

5,000 Bbls

$100.00 Floor with an $80.00 Limit

$7.110 per Bbl

Brent

Jan - Dec

Put options(4)

30,000 Bbls

$95.00 Floor with a $75.00 Limit

$6.091 per Bbl

Brent

Jan - Dec

Put options(4)

75,000 Bbls

$90.00 Floor with a $70.00 Limit

$5.739 per Bbl

Brent

2015

Jan - Dec

Put options(4)

84,000 Bbls

$90.00 Floor with a $70.00 Limit

$6.889 per Bbl

Brent

Sales of Natural Gas Production

2013

Feb - Dec

Swap contracts(3)

110,000 MMBtu

$4.27

-

Henry Hub

2014

Jan - Dec

Swap contracts(3)

100,000 MMBtu

$4.09

-

Henry Hub

(1)

All of our derivatives are settled monthly.

(2)

The average strike prices do not reflect any premiums to purchase the put options.

(3)

If the index price is less than the fixed price, we receive the 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.

(4)

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 less the option premium.  If the index price is at or above the per barrel floor, we pay only the option premium.

(5)

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 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 sales

5,454

6,881

50,954

7,915

$          5,454

$             (8,127)

$               47,753

$           (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 derivative contracts

15.5

11.5

Realized gain (loss) on mark-to-market derivative contracts (1)

5.5

(8.0)

Unrealized gain on investment measured at fair value

(298.9)

(232.3)

Debt extinguishment costs

3.2

121.0

Acquisition and merger related costs

35.5

-

Bridge loan facility commitment fee and related expenses

31.8

-

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    of preferred stock of subsidiary 

(9.2)

(1.4)

 Adjusted net income attributable to common stockholders (non-GAAP) 

$   54.8

$   28.6

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 contracts

2.9

(82.0)

Realized gain (loss) on mark-to-market derivative contracts (1)

47.8

(51.3)

Unrealized (gain) loss on investment measured at fair value

(206.6)

52.7

Debt extinguishment costs

8.4

121.0

Acquisition and merger related costs

42.2

-

Bridge loan facility commitment fee and related expenses

31.8

-

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    of preferred stock of subsidiary 

(36.4)

(1.4)

 Adjusted net income attributable to common stockholders (non-GAAP) 

$ 229.2

$ 223.0

(1)

The amounts presented in the above tables 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 42% and 36% for the three months ended December 31, 2012 and 2011, respectively. Tax 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,  amortization and accretion

407.8

215.6

1,118.1

681.7

   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 contracts

15.5

11.5

2.9

(82.0)

   Unrealized (gain) loss on investment measured at fair value

(298.9)

(232.3)

(206.6)

52.7

  Acquisition and merger related costs

38.9

-

38.9

-

  Bridge loan facility commitment fee and related expenses

31.8

-

31.8

-

  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 contracts

5.5

(8.0)

42.9

(55.4)

  Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary

(6.7)

(1.1)

(27.0)

(1.1)

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 extinguishment costs

-

(118.2)

(4.2)

(118.2)

   Acquisition and merger related costs

(38.9)

-

(38.9)

-

   Bridge loan facility commitment fee and related expenses

(31.8)

-

(31.8)

-

   Changes in assets and liabilities from operating activities

(182.5)

13.6

(174.5)

45.1

  Realized (gain) loss on mark-to-market derivative contracts

(5.5)

8.0

(42.9)

55.4

   Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary

6.7

1.1

27.0

1.1

 

Net cash provided by operating activities (GAAP)

$          284.2

$          188.1

$       1,330.8

$       1,110.8

 

 

 

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 taxes

$    22,535.8

Present value of estimated future net cash flows before income taxes (PV-10) (3)

$   13,737.7

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.

(1)

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 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.  

(2)

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 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.

(3)

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 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



RELATED LINKS

http://www.pxp.com