PXP Announces 2009 Third Quarter Results
-- Net income was $39.3 million or $0.30 per diluted share.
-- Net income including realized gains and losses and excluding unrealized gains and losses on our mark-to-market derivative contracts was $185.3 million, or $1.40 per diluted share (a non-GAAP measure).
-- Average daily sales volumes increased 3% to 83.0 thousand barrels of oil equivalent (BOE) from the second quarter 2009. Excluding the impact of our 2008 divestments, increased production from the Haynesville Shale and Flatrock resulted in an 8% increase in the average daily sales volumes for the first nine months of 2009 compared to the same period a year ago.
-- Total production costs per BOE decreased 9% to $13.11 from the second quarter 2009.
-- Haynesville Shale average daily production net to PXP increased 71% to approximately 48 million cubic feet equivalent (MMCFE) per day from the second quarter 2009. Production is expected to exceed 70 MMCFE per day net to PXP by year-end 2009.
-- Active Gulf of Mexico drilling program with delineation drilling success at the Friesian development project in the Green Canyon area and an announced discovery at Blueberry Hill exploratory prospect on Louisiana State Lease 340; plus three significant exploration prospects are currently drilling with a total reserve potential of more than 200 million BOE net to PXP: Davy Jones, Rickenbacker and Lucius.
- Press Release
- Source: Plains Exploration & Production Company
- On 7:35 am EST, Thursday November 5, 2009
HOUSTON, Nov. 5 /PRNewswire-FirstCall/ -- Plains Exploration & Production Company (NYSE: PXP - News; "PXP" or the "Company") announces third quarter 2009 financial and operating results and files full-year 2010 guidance with the SEC on a Form 8-K.
Related Quotes
| Symbol | Price | Change |
|---|---|---|
| CHK | 23.03 | -0.35 |
Revenues of $312.2 million generated $39.3 million of net income, or $0.30 per diluted share, in the third quarter 2009. Net income including realized gains and losses and excluding unrealized gains and losses on our mark-to-market derivative contracts was $185.3 million, or $1.40 per diluted share (a non-GAAP measure). Net cash provided by operating activities was $168.2 million and operating cash flow was $427.9 million (a non-GAAP measure).
A reconciliation of non-GAAP financial measures used in this release to comparable GAAP financial measures is included with the financial tables in this release.
James C. Flores, Chairman, President and CEO of PXP commented, "We delivered solid results for the third quarter and are financially and operationally well positioned to continue delivering strong and consistent reserve and production growth. PXP reports significant progress in lowering costs, increasing production, strengthening liquidity and expanding its resource potential during today's challenging environment. Excluding the impact of our 2008 divestments, increased production from the Haynesville Shale and Flatrock properties resulted in an 8% increase in sales volumes in the first nine months of 2009 compared to the same period a year ago. Lease operating expenses per unit decreased 7% for the first nine months due to the success of our cost reduction program. The favorable quarterly results again highlight our sound execution of the strategic plan, successful hedge program, and high-quality asset base.
"Our 2010 capital spending plan leverages on those strengths and allocates capital to asset areas with the greatest returns and highest growth prospects. PXP's Board of Directors approved a $900 million to $1.1 billion 2010 capital budget versus an estimated $1.55 billion 2009 capital budget. The 2010 capital investment is predominately focused on the continued development of our substantial Haynesville Shale acreage position, our large, high free-cash flow California oil business and our Texas Panhandle, South Texas and Gulf of Mexico asset areas. Approximately 10% of the 2010 capital plan is allocated to Gulf of Mexico exploration. We continue to target reserve growth of 20% through 2011 and production growth of 8-10% in 2010 and 2011 driven by the Haynesville Shale layered on top of our stable oil production base. PXP remains focused on cost control, operational execution and reserve and production growth from its balanced portfolio of excellent assets."
OPERATIONAL HIGHLIGHTS
-- Outstanding drilling results continue in the Haynesville Shale and
production from this resource base is growing quickly. Third quarter
average daily production of approximately 48 million cubic feet
equivalent (MMCFE) net to PXP has ramped up from 14 MMCFE per day net
during the first quarter 2009 and 28 MMCFE per day net in the second
quarter. Production is expected to continue to increase and exceed
approximately 70 MMCFE per day net by year-end 2009 and approximately
125 MMCFE net per day by year-end 2010. PXP and its partner, and
operator, Chesapeake Energy Corporation (NYSE: CHK - News) are currently
operating 35 rigs and expect to operate an average of 40 rigs in 2010,
plus 15 or more rigs operated by others on our acreage consistent with
this year's activity.
Two notable Haynesville Shale wells completed by Chesapeake are as
follows: The Caspiana 13-15-12 H-1 in Caddo Parish, LA achieved a
peak rate of 20.2 million cubic feet (MMCF) per day; and The Bradway
24-15-12 H-1 in Caddo Parish, LA achieved a peak rate of 18.6 MMCF
per day.
-- The Flatrock area wells averaged 59 MMCFE per day net to PXP in the
third quarter of 2009. As previously reported, the Flatrock #5 well
was re-completed in the primary Rob-L zone in September 2009. The
Flatrock #3 well is currently offline and will be re-completed in the
fourth quarter of 2009. The Flatrock #4 well was shut in during August
2009 because of a mechanical (not reservoir) issue associated with the
well bore and is expected to recommence production by year-end 2009.
-- Positive drilling results at the Blueberry Hill exploratory well,
operated by McMoRan and located on Louisiana State Lease 340 in the
Gulf of Mexico, indicate a discovery. A second sidetrack well was
drilled to a total depth of 21,942 feet in October 2009. The operator
plans to temporarily abandon the sidetrack #2 well and drill an offset
appraisal well approximately 2,000 feet southeast with a proposed total
depth of 21,850 feet. Offset drilling operations are expected to
commence in November 2009. Development planning is underway. Blueberry
Hill is located 11 miles southeast of Flatrock. PXP holds a 47.9%
working interest.
-- The Hurricane Deep sidetrack well, operated by Chevron and located on
South Marsh Island 217, on the southern flank of the Flatrock structure
has a proposed total depth of 21,750 feet and is targeting the
significant Gyro sand encountered in the Hurricane Deep well. The
operator plans to commence sidetrack operations in the fourth quarter
of 2009. PXP holds a 30.0% working interest.
-- Three significant Gulf of Mexico exploration prospects with a total
reserve potential of more than 200 million BOE net to PXP are currently
drilling:
- The Davy Jones exploration prospect, operated by McMoRan and located
on South Marsh Island Block 230 is drilling towards a proposed total
depth of 28,000 feet. PXP holds a 27.7% working interest.
- The Rickenbacker exploration prospect, operated by Anadarko and
located on Keathley Canyon Block 470, is drilling towards a
proposed total depth of approximately 33,700 feet. PXP holds a
15.0% working interest.
- The Lucius exploration prospect, operated by Anadarko and located on
Keathley Canyon Block 875, began drilling operations in October and
is drilling towards a proposed total depth of 21,000 feet. PXP holds
a 33.3% working interest.
-- The Northwood exploration prospect, operated by Chevron and located on
Green Canyon Block 945, was drilled to a total depth of 35,955 feet and
is being plugged and abandoned.
DERIVATIVE SUMMARY
Approximately 80% of our 2009 estimated sales volumes, using the mid-point of our annual guidance, are protected by oil and natural gas derivative positions and natural gas physical purchases. For 2009, natural gas volumes are protected with $10 by $20 collars on 150,000 MMBtu per day while crude oil volumes have put options with a $55 strike price on 32,500 barrels per day. Approximately 68% of our 2010 estimated sales volumes, using the mid-point of our annual guidance, are protected by oil and natural gas derivative positions and natural gas physical purchases. For 2010, natural gas volumes are protected by three-way collars having a $6.12 floor with $4.64 limit and an $8.00 ceiling on 85,000 MMBtu per day, and crude oil volumes for 2010 have put options with a $55 strike price on 40,000 barrels per day. A summary of PXP's open commodity derivative positions is included with the financial tables in this release.
2010 FULL-YEAR GUIDANCE
PXP filed full-year 2010 guidance with the SEC in a Form 8-K.
CONFERENCE CALL
PXP will host a conference call today, Thursday, November 5, 2009 at 8:00 a.m. Central time. Investors wishing to participate in the conference call may dial 1-800-567-9836 or 1-973-935-8460. The conference call and replay ID is: 34949709. The replay can be accessed by dialing 1-800-642-1687 or 1-706-645-9291. A live webcast of the conference call will be available in the Investor Information section of PXP's website at www.pxp.com.
PXP is an independent oil and gas company primarily engaged in the activities of acquiring, developing, exploring and producing oil and gas in California, Texas, Louisiana and the Gulf of Mexico. PXP is headquartered in Houston, Texas.
ADDITIONAL INFORMATION & FORWARD-LOOKING STATEMENTS
This press release contains forward-looking information regarding PXP that is intended to be covered by the safe harbor "forward-looking statements" provided by the Private Securities Litigation Reform Act of 1995. All statements included in this press release that address activities, events or developments that PXP expects, believes or anticipates will or may occur in the future are forward-looking 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 the year ended December 31, 2008, for a discussion of these risks.
All forward-looking statements in this report are made as of the date hereof, and you should not place undue reliance on these statements without also considering the risks and uncertainties associated with these statements and our business that are discussed in this report and our other filings with the SEC. Moreover, although we believe the expectations reflected in the forward-looking statements are based upon reasonable assumptions, we can give no assurance that we will attain these expectations or that any deviations will not be material. Except for any obligation to disclose material information under the Federal securities laws, we do not intend to update these forward-looking statements and information.
Plains Exploration & Production Company
Consolidated Statements of Income (Unaudited)
(amounts in thousands, except per share data)
Three Months Ended Nine Months Ended
September 30, September 30,
------------- -------------
2009 2008 2009 2008
---- ---- ---- ----
Revenues
Oil sales $249,619 $528,787 $625,822 $1,531,138
Gas sales 62,428 181,971 192,233 528,374
Other operating revenues 141 8,779 1,326 15,805
--- ----- ----- ------
312,188 719,537 819,381 2,075,317
------- ------- ------- ---------
Costs and Expenses
Lease operating expenses 60,276 76,943 194,564 236,699
Steam gas costs 10,956 37,418 37,425 110,175
Electricity 10,585 14,367 33,895 36,665
Production and ad valorem
taxes 7,917 27,348 29,995 77,757
Gathering and transportation
expenses 10,349 4,405 25,667 15,356
General and administrative 36,419 29,374 111,066 114,505
Depreciation, depletion and
amortization 101,755 139,956 280,691 411,558
Accretion 3,541 3,258 10,628 9,868
Legal recovery - - (87,272) -
Other operating (income)
expense (4,403) - 1,553 -
------ --- ----- ---
237,395 333,069 638,212 1,012,583
------- ------- ------- ---------
Income from Operations 74,793 386,468 181,169 1,062,734
Other Income (Expense)
Gain on sale of assets - - - 34,658
Interest expense (16,355) (32,994) (54,287) (87,114)
Debt extinguishment costs (1,183) (3,138) (12,093) (13,401)
Gain on mark-to-market
derivative contracts 14,795 451,083 13,217 390,175
Other income (expense) 569 (13,842) 761 (12,181)
--- ------- --- -------
Income Before Income Taxes 72,619 787,577 128,767 1,374,871
Income tax expense
Current (21,696) (210,023) (33,757) (312,276)
Deferred (11,597) (84,409) (6,837) (203,031)
------- ------- ------ --------
Net Income $39,326 $493,145 $88,173 $859,564
======= ======== ======= ========
Earnings per Share
Basic $0.30 $4.58 $0.74 $7.87
Diluted $0.30 $4.50 $0.73 $7.72
Weighted Average Shares
Outstanding
Basic 131,701 107,725 119,288 109,195
======= ======= ======= =======
Diluted 132,725 109,617 120,003 111,297
======= ======= ======= =======
Plains Exploration & Production Company
Operating Data (Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
------------- -------------
2009 2008 2009 2008
---- ---- ---- ----
Daily Average Volumes
Oil and liquids sales (Bbls) 47,399 55,803 48,521 56,199
Gas (Mcf)
Production 220,103 225,232 204,605 220,145
Used as fuel 6,443 5,691 6,678 6,053
Sales 213,660 219,541 197,927 214,092
BOE
Production 84,083 93,342 82,622 92,890
Sales 83,009 92,393 81,509 91,881
Unit Economics (in dollars)
Average NYMEX Prices
Oil $68.24 $118.22 $57.32 $113.52
Gas 3.40 10.28 3.91 9.76
Average Realized Sales
Price Before
Derivative Transactions
Oil (per Bbl) $57.26 $103.00 $47.24 $99.43
Gas (per Mcf) 3.18 9.01 3.56 9.00
Per BOE 40.86 83.62 36.76 81.81
Cash Margin per BOE (1)
Oil and gas revenues $40.86 $83.62 $36.76 $81.81
Costs and expenses
Lease operating
expenses (7.89) (9.06) (8.75) (9.40)
Steam gas costs (1.43) (4.40) (1.68) (4.38)
Electricity (1.39) (1.69) (1.52) (1.46)
Production and ad
valorem taxes (1.04) (3.22) (1.35) (3.09)
Gathering and
transportation (1.36) (0.52) (1.15) (0.61)
Oil and gas related
DD&A (12.66) (15.71) (11.89) (15.72)
------ ------ ------ ------
Gross margin (GAAP) 15.09 49.02 10.42 47.15
Oil and gas related DD&A 12.66 15.71 11.89 15.72
Realized gains and losses
on derivative
instruments (2) 32.30 (1.81) 34.25 (2.17)
----- ----- ----- -----
Cash margin (Non-GAAP) $60.05 $62.92 $56.56 $60.70
====== ====== ====== ======
Oil and gas capital
expenditures accrued ($ in
thousands) (3) $446,630 $356,762 $1,249,048 $806,408
(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) Three and nine months ended September 30, 2009 amounts include $38.94
per barrel or $22.23 per BOE attributable to July-September 2009
production and $29.82 per barrel or $17.75 per BOE attributable to
March-September 2009 production, respectively, for the $106 crude oil
puts and $54 crude oil swaps that were monetized in the first quarter
of 2009. Year to date amounts also include $9.16 per barrel or $5.45
per BOE associated with the January and February settlement of the
$106 crude oil puts and the $54 crude oil swaps that we monetized in
the first quarter of 2009.
(3) Additions to oil and gas properties reported in our consolidated
statement of cash flows differ from the accrual basis amounts
reflected above due to the timing of cash payments. Excludes
acquisitions.
Plains Exploration & Production Company
Reconciliation of GAAP to Non-GAAP Measure
Three Months Ended
September 30, 2009
------------------
Oil Gas BOE
--- --- ---
Average Realized Sales Price
Average realized price before
derivative instruments (GAAP) (1) $57.26 $3.18 $40.86
Realized gains on derivative
instruments (2) 36.83 4.38 32.30
----- ---- -----
Realized cash price including derivative
settlements (non-GAAP) $94.09 $7.56 $73.16
====== ===== ======
Three Months Ended
September 30, 2008
------------------
Oil Gas BOE
--- --- ---
Average Realized Sales Price
Average realized price before derivative
instruments (GAAP) (1) $103.00 $9.01 $83.62
Realized gains and losses on derivative
instruments (4.22) 0.31 (1.81)
----- ---- -----
Realized cash price including derivative
settlements (non-GAAP) $98.78 $9.32 $81.81
====== ===== ======
(1) Excludes the impact of production costs and expenses and DD&A.
(2) Includes $38.94 per barrel or $22.23 per BOE attributable to July-
September 2009 production for the $106 crude oil puts and $54 crude
oil swaps that were monetized in the first quarter of 2009.
Nine Months Ended
September 30, 2009
-------------------
Oil Gas BOE
--- --- ---
Average Realized Sales Price
Average realized price before derivative
instruments (GAAP) (3) $47.24 $3.56 $36.76
Realized gains on derivative
instruments (4) 39.90 4.33 34.25
----- ---- -----
Realized cash price including derivative
settlements (non-GAAP) $87.14 $7.89 $71.01
====== ===== ======
Nine Months Ended
September 30, 2008
-------------------
Oil Gas BOE
--- --- ---
Average Realized Sales Price
Average realized price before derivative
instruments (GAAP) (3) $99.43 $9.00 $81.81
Realized gains and losses on derivative
instruments (3.98) 0.12 (2.17)
----- ---- -----
Realized cash price including derivative
settlements (non-GAAP) $95.45 $9.12 $79.64
====== ===== ======
(3) Excludes the impact of production costs and expenses and DD&A.
(4) Includes $29.82 per barrel or $17.75 per BOE attributable to March-
September 2009 production for the $106 crude oil puts and $54 crude
oil swaps that were monetized in the first quarter of 2009. Also
includes $9.16 per barrel or $5.45 per BOE associated with the
January and February settlement of the $106 crude oil puts and the
$54 crude oil swaps that we monetized in the first quarter of 2009.
Plains Exploration & Production Company
Consolidated Statements of Cash Flows (Unaudited)
(in thousands of dollars)
Three Months Ended Nine Months Ended
September 30, September 30,
------------- -------------
2009 2008 2009 2008
---- ---- ---- ----
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $39,326 $493,145 $88,173 $859,564
Items not affecting cash
flows from operating
activities
Gain on sale of assets - - - (34,658)
Depreciation, depletion,
amortization and
accretion 105,296 143,214 291,319 421,426
Deferred income tax
expense 11,597 84,409 6,837 203,031
Debt extinguishment
costs 1,183 3,138 12,093 13,401
Gain on mark-to-market
derivative contracts (14,795) (451,083) (13,217) (390,175)
Noncash compensation 15,250 (1,520) 47,816 38,931
Other noncash items 1,566 1,344 4,479 4,230
Change in assets and
liabilities from operating
activities 8,773 264,930 (127,614) 31,189
----- ------- -------- ------
Net cash provided by
operating activities 168,196 537,577 309,886 1,146,939
------- ------- ------- ---------
CASH FLOWS FROM INVESTING
ACTIVITIES
Additions to oil and gas
properties (415,737) (247,082) (1,242,698) (688,205)
Acquisition of oil and gas
properties (1,137,142) (1,681,676) (1,137,142) (2,012,969)
Payment of accrued merger
costs - (1,801) - (76,645)
Proceeds from sales of oil
and gas properties and
related assets, net of
costs and expenses - 18,278 - 1,736,059
Derivative settlements 76,910 (6,619) 1,457,232 (36,212)
Decrease in restricted
cash - - - 59,092
Additions to other property
and equipment (2,807) (7,005) (12,167) (34,448)
Other 162 (442) 162 (1,671)
--- ---- --- ------
Net cash used in investing
activities (1,478,614) (1,926,347) (934,613) (1,054,999)
---------- ---------- -------- ----------
CASH FLOWS FROM FINANCING
ACTIVITIES
Borrowings from revolving
credit facilities 75,000 7,263,596 2,315,090 11,501,352
Repayments of revolving
credit facilities - (5,840,465) (3,545,090)(11,672,221)
Proceeds from issuance of
Senior Notes 393,340 - 916,439 400,000
Costs incurred in connection
with financing arrangements (7,327) (19,384) (19,441) (25,448)
Derivative settlements - (11,009) 1,392 (24,097)
Issuance of common stock 397,161 - 648,035 -
Purchase of treasury stock - - - (304,192)
Other - (4,035) 28 9,647
--- ------ --- -----
Net cash provided by (used
in) financing activities 858,174 1,388,703 316,453 (114,959)
------- --------- ------- --------
Net decrease in cash
and cash equivalents (452,244) (67) (308,274) (23,019)
Cash and cash equivalents,
beginning of period 455,845 2,494 311,875 25,446
------- ----- ------- ------
Cash and cash equivalents,
end of period $3,601 $2,427 $3,601 $2,427
====== ====== ====== ======
Plains Exploration & Production Company
Consolidated Balance Sheets (Unaudited)
(in thousands of dollars)
September 30, December 31,
2009 2008
---- ----
ASSETS
Current Assets
Cash and cash equivalents $3,601 $311,875
Accounts receivable 159,107 175,896
Commodity derivative contracts 63,913 945,838
Inventories 20,491 23,368
Prepaid expenses and other current assets 29,514 19,464
------ ------
276,626 1,476,441
------- ---------
Property and Equipment, at cost
Oil and natural gas properties - full cost
method
Subject to amortization 8,661,710 7,106,785
Not subject to amortization 3,346,861 2,513,424
Other property and equipment 123,157 110,990
------- -------
12,131,728 9,731,199
Less allowance for depreciation,
depletion, amortization and impairment (5,491,734) (5,217,803)
---------- ----------
6,639,994 4,513,396
--------- ---------
Goodwill 535,265 535,265
------- -------
Commodity Derivative Contracts - 530,181
--- -------
Other Assets 59,994 56,632
------ ------
$7,511,879 $7,111,915
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable $361,041 $363,713
Royalties and revenues payable 73,579 87,874
Interest payable 33,548 20,843
Income taxes payable - 102,948
Deferred income taxes 131,716 285,426
Other current liabilities 126,426 132,841
------- -------
726,310 993,645
------- -------
Long-Term Debt 2,493,583 2,805,000
--------- ---------
Other Long-Term Liabilities
Asset retirement obligation 169,287 159,473
Other 34,746 32,061
------ ------
204,033 191,534
------- -------
Deferred Income Taxes 926,124 744,456
------- -------
Stockholders' Equity
Common stock 1,439 1,129
Additional paid-in capital 3,400,559 2,739,625
Retained earnings (deficit) 3,072 (85,101)
Accumulated other comprehensive loss - (684)
Treasury stock, at cost (243,241) (277,689)
-------- --------
3,161,829 2,377,280
--------- ---------
$7,511,879 $7,111,915
========== ==========
Plains Exploration & Production Company
Summary of Open Derivative Positions
At October 1, 2009
Average
Instrument Daily Average Deferred
Period (1) Type Volumes Price (2) Premium Index
---------- ---- ------- -------- ------- -----
Sales of Crude Oil Production
2009
Oct - Dec Put options 32,500 Bbls $55.00 Strike $3.38 per Bbl WTI
price
2010
Jan - Dec Put options 40,000 Bbls $55.00 Strike $5.00 per Bbl (3) WTI
price
Sales of Natural Gas Production
2009
Oct - Dec Collars 150,000 MMBtu $10.00 Floor - $0.346 per MMBtu Henry
$20.00 Ceiling Hub
2010
Jan - Dec Three-way 85,000 MMBtu $6.12 Floor $0.034 MMBtu Henry
collars (4) with a Hub
$4.64 Limit
$8.00 Ceiling
(1) All of our derivative instruments are settled monthly.
(2) The average strike prices do not reflect the cost to purchase the put
options or collars.
(3) In addition to the deferred premium, a premium averaging $3.86 per
barrel was paid from the proceeds of our first quarter 2009
derivative monetization upon entering into these derivative
contracts.
(4) If NYMEX is less than the $6.12 per MMBtu floor, we receive the
difference between NYMEX and the $6.12 per MMBtu floor up to a
maximum of $1.48 per MMBtu. We pay the difference between NYMEX and
$8.00 per MMBtu if NYMEX is greater than the $8.00 ceiling.
Plains Exploration & Production Company
Reconciliation of GAAP to Non-GAAP Measure
The following table reconciles net income (GAAP) to adjusted net income
(non-GAAP) for the three and nine months ended September 30, 2009 and
2008. Adjusted net income includes realized gains and losses and excludes
unrealized gains and losses on mark-to-market derivative contracts, gain
on sale of assets and legal recovery and the effects of nonrecurring tax
related expenses and benefits. Management believes this presentation may
be helpful to investors. PXP management uses this information to analyze
operating trends and for comparative purposes within the industry. This
measure is not intended to replace the GAAP statistic but rather to
provide additional information that may be helpful in evaluating the
Company's operational trends and performance.
Three Months Ended
September 30,
-------------
2009 2008
---- ----
(millions of dollars)
Net income (GAAP) $39.3 $493.1
Unrealized gain on mark-to-market
derivative contracts (14.8) (451.1)
Realized gain (loss) on mark-to-market
derivative contracts (1) 246.7 (15.4)
Adjust income taxes (2) (85.9) 169.7
----- -----
Adjusted net income (non-GAAP) $185.3 $196.3
====== ======
Nine Months Ended
September 30,
-------------
2009 2008
---- ----
(millions of dollars)
Net income (GAAP) $88.2 $859.6
Unrealized gain on mark-to-market
derivative contracts (13.2) (390.2)
Realized gain (loss) on mark-to-market
derivative contracts (1) 762.3 (54.6)
Gain on sale of assets - (34.7)
Legal recovery (87.3) -
Adjust income taxes (2) (266.6) 174.4
------ -----
Adjusted net income (non-GAAP) $483.4 $554.5
====== ======
(1) Three and nine months ended September 30, 2009 totals include $169.8
million attributable to July-September 2009 production and $394.9
million attributable to March-September production, respectively, for
the $106 crude oil puts and $54 crude oil swaps that were monetized
in the first quarter of 2009. Nine month 2009 totals also include
$121.4 million associated with the January and February settlement of
the $106 crude oil puts and the $54 crude swaps that we monetized in
the first quarter of 2009. The remaining proceeds from the
monetization are not included in the above table because they are
attributable to production months subsequent to September 30, 2009.
The amounts presented in the above table differ from the adjustments
reflected in the calculation of operating cash flow on the following
page due to the accrued amounts reflected in the income statement
versus the actual cash received or paid reflected in the consolidated
statement of cash flows.
(2) Tax rates assumed based upon adjusted earnings are 39% for the three
months ended September 30, 2009 and 2008. Tax rates assumed based
upon adjusted earnings are 39% and 38% for the nine months ended
September 30, 2009 and 2008, respectively. Tax rates exclude the
effects of nonrecurring tax related expenses and benefits.
Plains Exploration & Production Company
Reconciliation of GAAP to Non-GAAP Measure
The following tables reconcile Net Cash Provided by Operating Activities
(GAAP) to Operating Cash Flow (non-GAAP) for the three and nine months
ended September 30, 2009 and 2008. Management believes this presentation
may be useful to investors. PXP management uses this information for
comparative purposes within the industry and as a means of measuring the
Company's ability to fund capital expenditures and service debt. This
measure is not intended to replace the GAAP statistic but rather to
provide additional information that may be helpful in evaluating the
Company's operational trends and performance.
Operating cash flow is calculated by adjusting net income to add back
certain non-cash and non-operating items, including unrealized gains and
losses on mark-to-market derivative contracts, to include derivative cash
settlements for realized gains and losses on mark-to-market derivative
contracts that are classified as either investing or financing activities
for GAAP purposes and to exclude certain nonrecurring items.
Three Months Ended Nine Months Ended
September 30, September 30,
------------- -------------
2009 2008 2009 2008
---- ---- ---- ----
(millions of dollars)
Net income $39.3 $493.1 $88.2 $859.6
Items not affecting
operating cash flows
Gain on sale of assets - - - (34.6)
Depreciation, depletion,
amortization and accretion 105.3 143.2 291.3 421.4
Deferred income tax expense 11.6 84.4 6.8 203.0
Debt extinguishment costs 1.2 3.1 12.1 13.4
Unrealized gain on
mark-to-market derivative
contracts (14.8) (451.0) (13.2) (390.2)
Noncash compensation 15.3 (1.5) 47.8 38.9
Other noncash items 1.6 1.3 4.5 4.2
Realized gain (loss) on
mark-to-market derivative
contracts (1) 246.7 (17.6) 779.2 (60.3)
Legal recovery - - (87.3) -
Current income taxes
attributable to derivative
contracts and property sales 21.7 210.0 33.8 312.3
---- ----- ---- -----
Operating cash flow (non-GAAP) $427.9 $465.0 $1,163.2 $1,367.7
====== ====== ======== ========
Reconciliation of non-GAAP
to GAAP measure
Operating cash flow
(non-GAAP) $427.9 $465.0 $1,163.2 $1,367.7
Legal recovery - - 87.3 -
Changes in assets and
liabilities from operating
activities 8.7 265.0 (127.6) 31.2
Realized (gain) loss on
mark-to-market derivative
contracts (1) (246.7) 17.6 (779.2) 60.3
Current income taxes
attributable to derivative
contracts and property sales (21.7) (210.0) (33.8) (312.3)
----- ------ ----- ------
Net cash provided by operating
activities (GAAP) $168.2 $537.6 $309.9 $1,146.9
====== ====== ====== ========
(1) Three and nine months ended September 30, 2009 totals include $169.8
million attributable to July-September 2009 production and $394.9
million attributable to March-September production, respectively, for
the $106 crude oil puts and $54 crude oil swaps that were monetized
in the first quarter of 2009. Nine month 2009 totals also include
$121.4 million associated with the January and February settlement of
the $106 crude oil puts and the $54 crude oil swaps that were
monetized in the first quarter of 2009. Such amounts are classified
as investing activities for GAAP purposes. The remaining proceeds
from the monetization are included as a cash receipt from investing
activities in the accompanying consolidated statement of cash flows
but are not included in the non-GAAP measure of operating cash flow
because they are attributable to production months subsequent to
September 30, 2009.
Plains Exploration & Production Company
Derivative Settlements
(in thousands of dollars)
The following tables reflect cash receipts (payments) for derivatives
attributable to the following production periods.
Three Months Ended Nine Months Ended
September 30, September 30,
------------- -------------
2009 2008 2009 2008
---- ---- ---- ----
Oil sales $(9,199) $(21,686) $133,494 $(61,330)
Natural gas sales 86,110 6,325 233,871 6,752
------ ----- ------- -----
$76,911 $(15,361) $367,365 $(54,578)
======= ======== ======== ========
2009 2010
---- ----
Amortization of monetized
derivatives (1)
First Quarter $57,211 $123,730
Second Quarter 167,943 125,105
Third Quarter 169,788 126,479
Fourth Quarter 169,788 126,479
------- -------
$564,730 $501,793
======== ========
(1) Represents the net receipts for derivatives monetized in the first
quarter of 2009 attributable to their production periods.
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