PXP Announces Third Quarter Results, Including A Surge in Oil Revenue, Record Oil Sales Volumes, and Improved Crude Oil Realized Pricing
HOUSTON, Nov. 1, 2012 /PRNewswire/ -- Plains Exploration & Production Company (NYSE:PXP) ("PXP" or the "Company") announces 2012 third-quarter financial and operating results.
THIRD-QUARTER HIGHLIGHTS
- Total revenues were $605.1 million, a 21% increase compared to third-quarter 2011.
- Oil revenues were $540.4 million, a 43% increase compared to third-quarter 2011 and the third consecutive quarterly increase.
- Total daily sales volumes averaged approximately 105.6 thousand barrels of oil equivalent ("BOE"), a 10% increase per diluted share, or a 36% increase per diluted share pro forma for the December 2011 asset sales, compared to third-quarter 2011.
- Oil daily sales volumes averaged 63.5 thousand barrels, a 36% increase per diluted share, or 56% per diluted share pro forma for the December 2011 asset sales, compared to third-quarter 2011.
- Average crude oil realized price per barrel before derivative transactions was $96.74, a 14% increase compared to third-quarter 2011, despite a lower Brent benchmark price.
- Average crude oil and liquids realized price per barrel before derivative transactions was $92.44, a 14% increase compared to third-quarter 2011, despite a lower Brent benchmark price.
- Net cash provided by operating activities was $415.6 million, a 20% increase over third-quarter 2011. Operating cash flow (a non-GAAP measure) was $382.2 million, a 27% increase over third-quarter 2011 and the third consecutive quarterly increase.
- Net loss attributable to common stockholders was $53.1 million, or $0.41 per diluted share compared to third-quarter 2011 net loss of $88.3 million, or $0.62 per diluted share.
- Adjusted net income attributable to common stockholders (a non-GAAP measure) was $51.6 million, or $0.39 per diluted share compared to third-quarter 2011 adjusted net income of $64.9 million, or $0.45 per diluted share.
FINANCIAL SUMMARY
PXP reported third-quarter revenues of $605.1 million and a net loss attributable to common stockholders of $53.1 million, or $0.41 per diluted share, compared to revenues of $501.8 million and a net loss of $88.3 million, or $0.62 per diluted share, for the third-quarter 2011. The third-quarter net income attributable to common stockholders includes certain items affecting the comparability of operating results. Those items consist of realized and unrealized gains and losses on our mark-to-market derivative contracts resulting in a net loss of $100.2 million due in large part to increased crude oil forward prices, a $43.1 million unrealized loss on investment in McMoRan Exploration Co. ("McMoRan") common stock, and other items. When considering these items, PXP reports net income attributable to common stockholders of $51.6 million, or $0.39 per diluted share (a non-GAAP measure).
For the first nine months of 2012, PXP reports revenues of $1.7 billion and net income attributable to common stockholders of $87.8 million, or $0.67 per diluted share, compared to revenues of $1.4 billion and net income of $107.6 million, or $0.75 per diluted share, for the same period in 2011. These results include certain items affecting comparability of operating results. These items consist of realized and unrealized gains and losses on our mark-to-market derivative contracts, an unrealized loss on investment in McMoRan common stock, and other items. When considering these items, net income attributable to common stockholders for the first nine months of 2012 was $174.3 million, or $1.32 per diluted share (a non-GAAP measure), compared to $194.5 million, or $1.36 per diluted share, for the same period in 2011.
A reconciliation of non-GAAP financial measures used in this release to comparable GAAP financial measures is included with the financial tables.
OPERATIONAL SUMMARY
PXP's 2012 third-quarter daily sales volumes averaged 105.6 thousand BOE per day, a 10% increase per diluted share and a 36% increase per diluted share pro forma for the December 2011 asset sales compared to third-quarter 2011.
Crude oil sales volumes averaged 58.7 thousand barrels per day, compared to third-quarter 2011 average volumes of 45.2 thousand barrels per day. The healthy volume growth is driven primarily by a strong performance in the Eagle Ford Shale and steady, consistent performance in California.
Natural gas liquids sales volumes averaged 4.8 thousand barrels per day, compared to third-quarter 2011 average volumes of 5.6 thousand barrels per day reflecting the impact of the South Texas and Texas Panhandle asset sales in December 2011.
Natural gas sales volumes averaged 252.0 million cubic feet ("MMcf") per day compared to 321.3 MMcf per day in the third-quarter 2011. Lower volumes reflect the impact of the December 2011 asset sales and lower drilling activity in the Haynesville Shale, partially offset by increased production from the Eagle Ford Shale.
In the Eagle Ford Shale, third-quarter daily sales volumes averaged 30.4 thousand BOE per day net to PXP compared to third-quarter 2011 average daily sales volumes of 5.2 thousand BOE per day net to PXP. At the end of October, PXP had 7.1 net drilling rigs operating on its acreage and 35 wells drilled but waiting on completion or connection to pipelines. PXP expects to exit the year between 32 – 36 thousand BOE per day net to PXP.
In California, third-quarter daily sales volumes averaged 38.1 thousand BOE per day net to PXP compared to the third-quarter 2011 daily sales volume average of 39.7 thousand BOE per day net to PXP. PXP expects to exit the year between 38 – 39 thousand BOE per day net to PXP.
In the Haynesville Shale, third-quarter daily sales volumes averaged 190.4 MMcf per day net to PXP compared to third-quarter 2011 average daily sales volumes of 201.3 MMcf per day net to PXP. The sales volume decline reflects significantly lower drilling activity during the quarter. At the end of October, there were no drilling rigs operating in which PXP had a working interest. PXP expects to exit the year between 142 – 146 MMcf per day net to PXP.
CAPITAL SPENDING UPDATE
For the third-quarter of 2012, PXP had cash expenditures of approximately $564.1 million for additions to oil and gas properties and $6.2 million for leasehold acquisitions. Of the $570.3 million total, $78.3 million was funded by Plains Offshore Operations Inc., PXP's consolidated subsidiary. PXP's third-quarter net cash provided by operating activities was $415.6 million.
For the nine months ended September, PXP had cash expenditures of approximately $1.4 billion for additions to oil and gas properties and leasehold acquisitions. Of the $1.4 billion total, $168.5 million was funded by Plains Offshore Operations Inc. PXP's net cash provided by operating activities and proceeds from sales of oil and gas properties during this period were $1.1 billion.
For the full-year of 2012, PXP's total capital spending is expected to be approximately $2.0 billion of which approximately $180 million is funded by Plains Offshore Operations Inc. The increase in PXP's capital spending over its base plan is attributed to oil & gas capital and seismic data acquisition capital for development and drilling activities of the Gulf of Mexico deepwater assets to be acquired and to accelerated development activity in the Eagle Ford Shale. Higher spending in the Eagle Ford Shale is leading to an approximate 78% increase in wells drilled and a 25% increase in average daily sales volumes over the 2012 base plan. PXP's 2013 capital spending is expected to be approximately $2.0 billion, including capitalized interest and general and administrative costs.
FULL-YEAR 2012 SALES VOLUMES UPDATE
PXP expects full-year 2012 average sales volumes, excluding sales volumes associated with the Gulf of Mexico acquisition, to be slightly above the revised guidance range of 95 - 97 thousand BOE per day. PXP revised its sales volume guidance in August 2012 from original guidance of 92 - 96 thousand BOE due to anticipated sales volume increases at the Eagle Ford Shale. Including one month of sales volumes associated with the Gulf of Mexico acquisition, PXP now anticipates full-year 2012 sales volumes to be approximately 103 thousand BOE per day.
COMMODITY PRICES
During the third-quarter of 2012, Brent crude oil price averaged $109.37 per barrel compared to $112.01 per barrel in the third-quarter 2011. PXP's 2012 third-quarter crude oil average realized price per barrel before derivative transactions was $96.74 per barrel, or approximately 88% of Brent, compared to $84.53 per barrel in the third-quarter 2011, or approximately 75% of Brent. Including the impact of derivative transactions, the third-quarter 2012 crude oil average realized price was $96.74 per barrel, or approximately 88% of Brent, compared to $81.00 per barrel in the third-quarter 2011, or 72% of Brent.
During the third-quarter of 2012, the oil/liquids average realized price per barrel before derivative transactions, which includes 4.8 thousand BOE per day net to PXP of natural gas liquids, was $92.44 per barrel, or approximately 85% of Brent, compared to $80.96 per barrel in the third-quarter 2011, or 72% of Brent. Including the impact of derivative transactions, the average realized price in the third-quarter 2012 was $92.44 per barrel, or 85% of Brent, compared to $77.83 per barrel in the third-quarter 2011, or 69% of Brent.
During the third-quarter of 2012, NYMEX gas price averaged $2.82 per million British thermal units ("MMBtu") compared to $4.20 per MMBtu in the third-quarter 2011. PXP's 2012 third-quarter natural gas average realized price before derivative transactions was $2.70 per MMBtu, or approximately 96% of NYMEX, compared to $4.10 per MMBtu in the third-quarter 2011, or 98% of NYMEX. Including the impact of derivative transactions, the average realized price in the third-quarter 2012 was $3.33 per MMBtu, or approximately 118% of NYMEX, compared to $4.11 per MMBtu in the third-quarter 2011, or 98% of NYMEX.
ACQUISITION FINANCING UPDATE
PXP successfully secured $8.0 billion dollars in total debt financing for the $6.11 billion Gulf of Mexico acquisition at a weighted average cost of debt of 4.8% as of October 29, 2012. The Company remains on track to close the acquisition by the end of November 2012.
In early October, PXP successfully syndicated $7.0 billion of committed financing to a group of banks and institutional lenders. The $7.0 billion of committed financing will be comprised of an amended and restated credit facility with a $5.3 billion borrowing base, which consists of (i) a $3.0 billion senior secured five-year revolving credit facility, (ii) a $750.0 million senior secured five-year term loan and (iii) a $1.25 billion senior secured seven-year term loan, as well as a $2.0 billion senior unsecured bridge facility.
At the end of October, PXP completed a public offering of $3.0 billion of senior notes, consisting of $1.5 billion in aggregate principal amount of Senior Notes due 2020, issued at par, and $1.5 billion in aggregate principal amount of Senior Notes due 2023, issued at par. This replaced the $2.0 billion senior unsecured bridge facility and lowered the borrowing base under the amended and restated credit facility by $125 million.
DERIVATIVE UPDATE
PXP continues to implement its crude oil hedging program and is well underway in achieving its stated goal to protect up to 90% of expected crude oil sales volumes in 2013, 2014 and 2015. Approximately 90% of expected 2013 and 2014 sales volumes are protected by put option spread contracts, swaps or three-way collars. In 2015, PXP has approximately 47% of expected sales volumes covered by put option spread contracts and continues to target up to 90% of anticipated oil sales volumes. A detailed list of PXP's current derivative positions is included at the end of this release.
MANAGEMENT COMMENT
James C. Flores, Chairman, President and CEO of PXP commented, "The fundamentals of our business are healthy as evidenced by strong third-quarter growth in total revenue, cash flow provided by operating activities, cash margin per BOE and production per diluted share compared to the same period a year ago. Our high-margin, fast growing onshore oil business will soon be complimented by the substantial addition of high-margin offshore Gulf of Mexico deepwater properties with current production and substantial future development inventory. With long-term financing in place, our attention is laser focused on closing the transaction, completing our stated hedging program objectives, transitioning to the new long-term operational plan and reducing long-term debt. This strategic initiative transforms PXP into a large capitalization exploration and production company with a business model dominated by a portfolio of onshore and offshore oil assets capable of doubling pro forma oil production by 2020 while generating substantial cash flow provided by operating activities in excess of capital investment to meet debt reduction targets."
CONFERENCE CALL
PXP will host a conference call today, Thursday, November 1 at 8:00 a.m. Central time. Investors wishing to participate in the conference call may dial 1-800-567-9836 or 1-973-935-8460. The conference call and replay ID is 36633286. The replay can be accessed by dialing 1-855-859-2056 or 1-404-537-3406. A live webcast of the conference call will be available in the Investor Information section of PXP's website at www.pxp.com.
PXP is an independent oil and gas company primarily engaged in the activities of acquiring, developing, exploring and producing oil and gas in California, Texas, Louisiana, and the Gulf of Mexico. PXP is headquartered in Houston, Texas.
ADDITIONAL INFORMATION & FORWARD-LOOKING STATEMENTS
This press release contains forward-looking information regarding PXP that is intended to be covered by the safe harbor for "forward-looking statements" provided by the Private Securities Litigation Reform Act of 1995. All statements included in this press release that address activities, events or developments that PXP expects, believes or anticipates will or may occur in the future are forward-looking statements.
These include statements regarding:
* completion of the previously announced acquisition and realization of the expected benefits therefrom,
* reserve and production estimates,
* oil and gas prices,
* the impact of derivative positions,
* production expense estimates,
* cash flow estimates,
* future financial performance,
* capital and credit market conditions,
* planned capital expenditures, and
* other matters that are discussed in PXP's filings with the SEC.
These statements are based on our current expectations and projections about future events and involve known and unknown risks, uncertainties, and other factors that may cause our actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. Please refer to our filings with the SEC, including our Form 10-K and Forms 10-Q, for a discussion of these risks.
References to quantities of oil or natural gas may include amounts that the Company believes will ultimately be produced, but that are not yet classified as "proved reserves" under SEC definitions. References in this press release to oil revenue and oil sales volumes include natural gas liquid volumes.
All forward-looking statements in this press release are made as of the date hereof, and you should not place undue reliance on these statements without also considering the risks and uncertainties associated with these statements and our business that are discussed in this press release and our other filings with the SEC. Moreover, although we believe the expectations reflected in the forward-looking statements are based upon reasonable assumptions, we can give no assurance that we will attain these expectations or that any deviations will not be material. Except as required by law, we do not intend to update these forward-looking statements and information.
|
Plains Exploration & Production Company Consolidated Statements of Income (in thousands, except per share data) | ||||||||||
|
Three Months Ended |
Nine Months Ended | |||||||||
|
September 30, |
September 30, | |||||||||
|
2012 |
2011 |
2012 |
2011 | |||||||
|
(Unaudited) |
||||||||||
|
Revenues |
||||||||||
|
Oil sales |
$ 540,434 |
$ 379,079 |
$ 1,527,430 |
$ 1,110,228 | ||||||
|
Gas sales |
62,630 |
121,014 |
162,113 |
331,486 | ||||||
|
Other operating revenues |
2,040 |
1,755 |
6,560 |
5,233 | ||||||
|
605,104 |
501,848 |
1,696,103 |
1,446,947 | |||||||
|
Costs and Expenses |
||||||||||
|
Lease operating expenses |
98,087 |
79,987 |
268,755 |
234,380 | ||||||
|
Steam gas costs |
12,096 |
17,015 |
32,931 |
49,641 | ||||||
|
Electricity |
9,930 |
10,112 |
32,081 |
30,203 | ||||||
|
Production and ad valorem taxes |
21,066 |
10,636 |
52,782 |
39,084 | ||||||
|
Gathering and transportation expenses |
19,218 |
15,237 |
54,519 |
44,825 | ||||||
|
General and administrative |
||||||||||
|
G&A |
32,515 |
28,158 |
102,598 |
94,964 | ||||||
|
Acquisition related costs |
6,683 |
- |
6,683 |
- | ||||||
|
Depreciation, depletion and amortization |
270,598 |
167,894 |
699,025 |
453,194 | ||||||
|
Accretion |
3,749 |
4,307 |
11,252 |
12,878 | ||||||
|
Other operating income |
(605) |
(50) |
(3,142) |
(657) | ||||||
|
473,337 |
333,296 |
1,257,484 |
958,512 | |||||||
|
Income from Operations |
131,767 |
168,552 |
438,619 |
488,435 | ||||||
|
Other (Expense) Income |
||||||||||
|
Interest expense |
(59,174) |
(43,495) |
(157,404) |
(113,141) | ||||||
|
Debt extinguishment costs |
- |
- |
(5,167) |
- | ||||||
|
(Loss) gain on mark-to-market derivative contracts |
(100,160) |
125,551 |
12,573 |
93,467 | ||||||
|
Loss on investment measured at fair value |
(43,121) |
(395,490) |
(92,301) |
(284,929) | ||||||
|
Other income |
11 |
1,399 |
440 |
2,949 | ||||||
|
(Loss) Income Before Income Taxes |
(70,677) |
(143,483) |
196,760 |
186,781 | ||||||
|
Income tax benefit (expense) |
||||||||||
|
Current |
3,540 |
26,718 |
2,535 |
25,959 | ||||||
|
Deferred |
23,163 |
28,469 |
(84,297) |
(105,165) | ||||||
|
Net (Loss) Income |
$ (43,974) |
$ (88,296) |
$ 114,998 |
$ 107,575 | ||||||
|
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary |
(9,114) |
(27,206) |
||||||||
|
Net (Loss) Income Attributable to Common Stockholders |
$ (53,088) |
$ 87,792 |
||||||||
|
(Loss) Earnings per Common Share |
||||||||||
|
Basic |
$ (0.41) |
$ (0.62) |
$ 0.68 |
$ 0.76 | ||||||
|
Diluted |
$ (0.41) |
$ (0.62) |
$ 0.67 |
$ 0.75 | ||||||
|
Weighted Average Common Shares Outstanding |
||||||||||
|
Basic |
130,047 |
141,826 |
129,806 |
141,500 | ||||||
|
Diluted |
130,047 |
141,826 |
131,774 |
143,351 | ||||||
|
Plains Exploration & Production Company Operating Data |
|||||||||||||
|
Three Months Ended |
Nine Months Ended | ||||||||||||
|
September 30, |
September 30, | ||||||||||||
|
2012 |
2011 |
2012 |
2011 | ||||||||||
|
(Unaudited) |
|||||||||||||
|
Daily Average Volumes |
|||||||||||||
|
Oil and liquids sales (Bbls) |
63,548 |
50,891 |
57,683 |
47,853 | |||||||||
|
Gas (Mcf) |
|||||||||||||
|
Production |
255,363 |
327,248 |
241,553 |
299,423 | |||||||||
|
Used as fuel |
3,353 |
5,962 |
3,952 |
5,875 | |||||||||
|
Sales |
252,010 |
321,286 |
237,601 |
293,548 | |||||||||
|
BOE |
|||||||||||||
|
Production |
106,109 |
105,432 |
97,942 |
97,756 | |||||||||
|
Sales |
105,550 |
104,438 |
97,283 |
96,777 | |||||||||
|
Unit Economics (in dollars) |
|||||||||||||
|
Average Index Prices |
|||||||||||||
|
ICE Brent Price per Bbl |
$ 109.37 |
$ 112.01 |
$ 112.16 |
$ 111.47 | |||||||||
|
NYMEX Price per Bbl |
92.20 |
89.54 |
96.16 |
95.47 | |||||||||
|
NYMEX Price per Mcf |
2.82 |
4.20 |
2.59 |
4.20 | |||||||||
|
Average Realized Sales Price Before Derivative Transactions |
|||||||||||||
|
Oil (per Bbl) |
$ 92.44 |
$ 80.96 |
$ 96.64 |
$ 84.98 | |||||||||
|
Gas (per Mcf) |
2.70 |
4.10 |
2.49 |
4.14 | |||||||||
|
Per BOE |
62.10 |
52.05 |
63.38 |
54.57 | |||||||||
|
Cash Margin per BOE (1) |
|||||||||||||
|
Oil and gas revenues |
$ 62.10 |
$ 52.05 |
$ 63.38 |
$ 54.57 | |||||||||
|
Costs and expenses |
|||||||||||||
|
Lease operating expenses |
(10.10) |
(8.32) |
(10.08) |
(8.87) | |||||||||
|
Steam gas costs |
(1.25) |
(1.77) |
(1.24) |
(1.88) | |||||||||
|
Electricity |
(1.02) |
(1.05) |
(1.20) |
(1.14) | |||||||||
|
Production and ad valorem taxes |
(2.17) |
(1.11) |
(1.98) |
(1.48) | |||||||||
|
Gathering and transportation |
(1.98) |
(1.59) |
(2.05) |
(1.70) | |||||||||
|
Oil and gas related DD&A |
(27.21) |
(16.86) |
(25.54) |
(16.49) | |||||||||
|
Gross margin (GAAP) |
18.37 |
21.35 |
21.29 |
23.01 | |||||||||
|
Oil and gas related DD&A |
27.21 |
16.86 |
25.54 |
16.49 | |||||||||
|
Realized gain (loss) on derivative instruments |
1.50 |
(1.48) |
1.59 |
(1.63) | |||||||||
|
Cash margin (non-GAAP) |
$ 47.08 |
$ 36.73 |
$ 48.42 |
$ 37.87 | |||||||||
|
Oil and gas capital expenditures accrued ($ in thousands) (2) |
$ 531,924 |
$ 502,745 |
$ 1,470,669 |
$ 1,364,142 | |||||||||
|
(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 September 30, 2012 | |||||||||
|
Oil |
Gas |
BOE | |||||||
|
(per Bbl) |
(per Mcf) |
||||||||
|
Average Realized Sales Price |
|||||||||
|
Average realized price before derivative instruments (GAAP) (1) |
$ 92.44 |
$ 2.70 |
$ 62.10 | ||||||
|
Realized gain on derivative instruments |
- |
0.63 |
1.50 | ||||||
|
Realized cash price including derivative settlements (non-GAAP) |
$ 92.44 |
$ 3.33 |
$ 63.60 | ||||||
|
Three Months Ended September 30, 2011 | |||||||||
|
Oil |
Gas |
BOE | |||||||
|
(per Bbl) |
(per Mcf) |
||||||||
|
Average Realized Sales Price |
|||||||||
|
Average realized price before derivative instruments (GAAP) (1) |
$ 80.96 |
$ 4.10 |
$ 52.05 | ||||||
|
Realized (loss) gain on derivative instruments |
(3.13) |
0.01 |
(1.48) | ||||||
|
Realized cash price including derivative settlements (non-GAAP) |
$ 77.83 |
$ 4.11 |
$ 50.57 | ||||||
|
Nine Months Ended September 30, 2012 | |||||||||
|
Oil |
Gas |
BOE | |||||||
|
(per Bbl) |
(per Mcf) |
||||||||
|
Average Realized Sales Price |
|||||||||
|
Average realized price before derivative instruments (GAAP) (1) |
$ 96.64 |
$ 2.49 |
$ 63.38 | ||||||
|
Realized (loss) gain on derivative instruments |
(0.20) |
0.70 |
1.59 | ||||||
|
Realized cash price including derivative settlements (non-GAAP) |
$ 96.44 |
$ 3.19 |
$ 64.97 | ||||||
|
Nine Months Ended September 30, 2011 | |||||||||
|
Oil |
Gas |
BOE | |||||||
|
(per Bbl) |
(per Mcf) |
||||||||
|
Average Realized Sales Price |
|||||||||
|
Average realized price before derivative instruments (GAAP) (1) |
$ 84.98 |
$ 4.14 |
$ 54.57 | ||||||
|
Realized (loss) gain on derivative instruments |
(3.38) |
0.01 |
(1.63) | ||||||
|
Realized cash price including derivative settlements (non-GAAP) |
$ 81.60 |
$ 4.15 |
$ 52.94 | ||||||
|
(1) Excludes the impact of production costs and expenses and DD&A. | |||||||||
|
Plains Exploration & Production Company Consolidated Statements of Cash Flows (in thousands of dollars) | ||||
|
Nine Months Ended | ||||
|
September 30, | ||||
|
2012 |
2011 | |||
|
(Unaudited) | ||||
|
CASH FLOWS FROM OPERATING ACTIVITIES |
||||
|
Net income |
$ 114,998 |
$ 107,575 | ||
|
Items not affecting cash flows from operating activities |
||||
|
Depreciation, depletion, amortization and accretion |
710,277 |
466,072 | ||
|
Deferred income tax expense |
84,297 |
105,165 | ||
|
Debt extinguishment costs |
939 |
- | ||
|
Gain on mark-to-market derivative contracts |
(12,573) |
(93,467) | ||
|
Loss on investment measured at fair value |
92,301 |
284,929 | ||
|
Non-cash compensation |
37,898 |
27,257 | ||
|
Other non-cash items |
10,431 |
(6,332) | ||
|
Change in assets and liabilities from operating activities |
8,009 |
31,451 | ||
|
Net cash provided by operating activities |
1,046,577 |
922,650 | ||
|
CASH FLOWS FROM INVESTING ACTIVITIES |
||||
|
Additions to oil and gas properties |
(1,388,356) |
(1,261,196) | ||
|
Acquisition of oil and gas properties |
(26,377) |
(36,750) | ||
|
Deposit related to the Gulf of Mexico Acquisition |
(555,000) |
- | ||
|
Proceeds from sales of oil and gas properties, net of costs and expenses |
60,470 |
11,987 | ||
|
Derivative settlements |
37,385 |
(47,448) | ||
|
Additions to other property and equipment |
(9,271) |
(9,454) | ||
|
Other |
- |
1,552 | ||
|
Net cash used in investing activities |
(1,881,149) |
(1,341,309) | ||
|
CASH FLOWS FROM FINANCING ACTIVITIES |
||||
|
Borrowings from revolving credit facilities |
6,756,425 |
4,026,900 | ||
|
Repayments of revolving credit facilities |
(6,596,425) |
(4,191,900) | ||
|
Principal payments of long-term debt |
(156,182) |
- | ||
|
Proceeds from issuance of Senior Notes |
750,000 |
600,000 | ||
|
Costs incurred in connection with financing arrangements |
(12,586) |
(11,320) | ||
|
Purchase of treasury stock |
(88,490) |
- | ||
|
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary |
(20,250) |
- | ||
|
Other |
- |
9 | ||
|
Net cash provided by financing activities |
632,492 |
423,689 | ||
|
Net (decrease) increase in cash and cash equivalents |
(202,080) |
5,030 | ||
|
Cash and cash equivalents, beginning of period |
419,098 |
6,434 | ||
|
Cash and cash equivalents, end of period |
$ 217,018 |
$ 11,464 | ||
|
Plains Exploration & Production Company Consolidated Balance Sheets (in thousands of dollars) | ||||||
|
September 30, |
December 31, | |||||
|
2012 |
2011 | |||||
|
ASSETS |
(Unaudited) |
|||||
|
Current Assets |
||||||
|
Cash and cash equivalents |
$ 217,018 |
$ 419,098 | ||||
|
Accounts receivable |
315,195 |
302,675 | ||||
|
Commodity derivative contracts |
26,302 |
50,964 | ||||
|
Inventories |
19,076 |
20,173 | ||||
|
Investment |
519,370 |
611,671 | ||||
|
Deferred income taxes |
166,002 |
20,723 | ||||
|
Prepaid expenses and other current assets |
24,644 |
16,073 | ||||
|
1,287,607 |
1,441,377 | |||||
|
Property and Equipment, at cost |
||||||
|
Oil and natural gas properties - full cost method |
||||||
|
Subject to amortization |
14,083,960 |
12,016,252 | ||||
|
Not subject to amortization |
1,718,876 |
2,409,449 | ||||
|
Other property and equipment |
150,031 |
145,959 | ||||
|
15,952,867 |
14,571,660 | |||||
|
Less allowance for depreciation, depletion, amortization and impairment |
(7,473,140) |
(6,846,365) | ||||
|
8,479,727 |
7,725,295 | |||||
|
Goodwill |
535,140 |
535,140 | ||||
|
Commodity Derivative Contracts |
19,459 |
12,678 | ||||
|
Deposit Related to the Gulf of Mexico Acquisition |
555,000 |
- | ||||
|
Other Assets |
97,862 |
76,982 | ||||
|
$ 10,974,795 |
$ 9,791,472 | |||||
|
LIABILITIES AND EQUITY |
||||||
|
Current Liabilities |
||||||
|
Accounts payable |
$ 470,284 |
$ 385,231 | ||||
|
Commodity derivative contracts |
8,253 |
3,761 | ||||
|
Royalties and revenues payable |
130,820 |
97,095 | ||||
|
Interest payable |
88,588 |
39,342 | ||||
|
Other current liabilities |
80,599 |
100,757 | ||||
|
778,544 |
626,186 | |||||
|
Long-Term Debt |
4,516,571 |
3,760,952 | ||||
|
Other Long-Term Liabilities |
||||||
|
Asset retirement obligation |
242,390 |
230,633 | ||||
|
Commodity derivative contracts |
4,239 |
823 | ||||
|
Other |
17,133 |
15,749 | ||||
|
263,762 |
247,205 | |||||
|
Deferred Income Taxes |
1,691,473 |
1,461,897 | ||||
|
Equity |
||||||
|
Stockholders' equity |
||||||
|
Common stock |
1,439 |
1,439 | ||||
|
Additional paid-in capital |
3,426,909 |
3,434,928 | ||||
|
Retained earnings |
418,789 |
337,991 | ||||
|
Treasury stock, at cost |
(560,244) |
(509,722) | ||||
|
3,286,893 |
3,264,636 | |||||
|
Noncontrolling interest |
||||||
|
Preferred stock of subsidiary |
437,552 |
430,596 | ||||
|
3,724,445 |
3,695,232 | |||||
|
$ 10,974,795 |
$ 9,791,472 | |||||
|
Plains Exploration & Production Company Summary of Open Derivative Positions At October 19, 2012 |
||||||||||||
|
Period (1) |
Instrument Type |
Daily Volumes |
Average Price (2) |
Average Deferred Premium |
Index | |||||||
|
Sales of Crude Oil Production |
||||||||||||
|
2012 |
||||||||||||
|
Oct - Dec |
Three-way collars(3) |
40,000 Bbls |
$100.00 Floor with an $80.00 Limit |
- |
Brent | |||||||
|
$120.00 Ceiling |
||||||||||||
|
2013 |
||||||||||||
|
Jan - Dec |
Swap contracts(4) |
40,000 Bbls |
$109.23 |
- |
Brent | |||||||
|
Jan - Dec |
Put options(5) |
13,000 Bbls |
$100.00 Floor with an $80.00 Limit |
$6.800 per Bbl |
Brent | |||||||
|
Jan - Dec |
Three-way collars(3) |
25,000 Bbls |
$100.00 Floor with an $80.00 Limit |
- |
Brent | |||||||
|
$124.29 Ceiling |
||||||||||||
|
Jan - Dec |
Three-way collars(3) |
5,000 Bbls |
$90.00 Floor with a $70.00 Limit |
- |
Brent | |||||||
|
$126.08 Ceiling |
||||||||||||
|
Jan - Dec |
Put options(5) |
17,000 Bbls |
$90.00 Floor with a $70.00 Limit |
$6.253 per Bbl |
Brent | |||||||
|
2014 |
||||||||||||
|
Jan - Dec |
Put options(5) |
5,000 Bbls |
$100.00 Floor with an $80.00 Limit |
$7.110 per Bbl |
Brent | |||||||
|
Jan - Dec |
Put options(5) |
30,000 Bbls |
$95.00 Floor with a $75.00 Limit |
$6.091 per Bbl |
Brent | |||||||
|
Jan - Dec |
Put options(5) |
75,000 Bbls |
$90.00 Floor with a $70.00 Limit |
$5.739 per Bbl |
Brent | |||||||
|
2015 |
||||||||||||
|
Jan - Dec |
Put options(5) |
65,000 Bbls |
$90.00 Floor with a $70.00 Limit |
$6.904 per Bbl |
Brent | |||||||
|
Sales of Natural Gas Production |
||||||||||||
|
2012 |
||||||||||||
|
Oct - Dec |
Put options(6) |
120,000 MMBtu |
$4.30 Floor with a $3.00 Limit |
$0.298 per MMBtu |
Henry Hub | |||||||
|
Oct - Dec |
Three-way collars(7) |
40,000 MMBtu |
$4.30 Floor with a $3.00 Limit |
- |
Henry Hub | |||||||
|
$4.86 Ceiling |
||||||||||||
|
Oct - Dec |
Swap contracts(4) |
80,000 MMBtu |
$2.72 |
- |
Henry Hub | |||||||
|
2013 |
||||||||||||
|
Jan - Dec |
Swap contracts(4) |
110,000 MMBtu |
$4.27 |
- |
Henry Hub | |||||||
|
2014 |
||||||||||||
|
Jan - Dec |
Swap contracts(4) |
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 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. | |||||||||||
|
(4) |
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. | |||||||||||
|
(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 less the option premium. If the index price is at or above the per barrel floor, we pay only the option premium. | |||||||||||
|
(6) |
If the index price is less than the per MMBtu floor, we receive the difference between the per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu less the option premium. If the index price is at or above the per MMBtu floor, we pay only the option premium. | |||||||||||
|
(7) |
If the index price is less than the per MMBtu floor, we receive the difference between the per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu. We pay the difference between the index price and the per MMBtu ceiling if the index price is greater than the per MMBtu ceiling. If the index price is at or above the per MMBtu floor but at or below the per MMBtu ceiling, no cash settlement is required. | |||||||||||
|
Derivative Settlements (in thousands of dollars) |
||||||||||||
|
The following tables reflect cash receipts (payments) for derivatives attributable to the stated production periods. |
||||||||||||
|
Three Months Ended |
Nine Months Ended |
|||||||||||
|
September 30, |
September 30, |
|||||||||||
|
2012 |
2011 |
2012 |
2011 |
|||||||||
|
Oil sales |
$ - |
$ (14,672) |
$ (3,201) |
$ (44,209) |
||||||||
|
Natural gas sales |
14,590 |
414 |
45,499 |
1,034 |
||||||||
|
$ 14,590 |
$ (14,258) |
$ 42,298 |
$ (43,175) |
|||||||||
|
Plains Exploration & Production Company Reconciliation of GAAP to Non-GAAP Measure |
|||||||
|
The following tables reconcile net income (loss) (GAAP) to adjusted net income and adjusted net income attributable to common stockholders (non-GAAP) for the three and nine months ended September 30, 2012 and 2011. Adjusted net income and adjusted net income attributable to common stockholders exclude certain items affecting the comparability of operating results and the related tax effects. Management believes this presentation may be helpful to investors. PXP management uses this information to analyze operating trends and for comparative purposes within the industry. This measure is not intended to replace the GAAP statistic but rather to provide additional information that may be helpful in evaluating the Company's operational trends and performance. | |||||||
|
Three Months Ended | |||||||
|
September 30, | |||||||
|
2012 |
2011 | ||||||
|
(millions of dollars) | |||||||
|
Net loss (GAAP) |
$ (44.0) |
$ (88.3) | |||||
|
Unrealized loss (gain) on mark-to-market derivative contracts |
100.2 |
(125.6) | |||||
|
Realized gain (loss) on mark-to-market derivative contracts (1) |
14.6 |
(14.3) | |||||
|
Unrealized loss on investment measured at fair value |
43.1 |
395.5 | |||||
|
Acquisition related costs |
6.7 |
- | |||||
|
Adjust income taxes (2) |
(59.9) |
(102.4) | |||||
|
Adjusted net income (non-GAAP) |
$ 60.7 |
$ 64.9 | |||||
|
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary |
(9.1) |
||||||
|
Adjusted net income attributable to common stockholders (non-GAAP) |
$ 51.6 |
||||||
|
Nine Months Ended | |||||||
|
September 30, | |||||||
|
2012 |
2011 | ||||||
|
(millions of dollars) | |||||||
|
Net income (GAAP) |
$ 115.0 |
$ 107.6 | |||||
|
Unrealized gain on mark-to-market derivative contracts |
(12.6) |
(93.5) | |||||
|
Realized gain (loss) on mark-to-market derivative contracts (1) |
42.3 |
(43.2) | |||||
|
Unrealized loss on investment measured at fair value |
92.3 |
284.9 | |||||
|
Debt extinguishment costs |
5.2 |
- | |||||
|
Acquisition related costs |
6.7 |
- | |||||
|
Adjust income taxes (2) |
(47.4) |
(61.3) | |||||
|
Adjusted net income (non-GAAP) |
$ 201.5 |
$ 194.5 | |||||
|
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary |
(27.2) |
||||||
|
Adjusted net income attributable to common stockholders (non-GAAP) |
$ 174.3 |
||||||
|
(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 35% and 42% for the three months ended September 30, 2012 and 2011, respectively. Tax rates assumed based upon adjusted earnings are 39% and 42% for the nine months ended September 30, 2012 and 2011. Tax rates exclude the effects of nonrecurring tax related expenses and benefits. | ||||||
|
Plains Exploration & Production Company Reconciliation of GAAP to Non-GAAP Measure |
|||||||||||||
|
The following tables reconcile Net Cash Provided by Operating Activities (GAAP) to Operating Cash Flow (non-GAAP) for the three and nine months ended September 30, 2012 and 2011. Management believes this presentation may be useful to investors. PXP management uses this information for comparative purposes within the industry and as a means of measuring the Company's ability to fund capital expenditures and service debt. This measure is not intended to replace the GAAP statistic but rather to provide additional information that may be helpful in evaluating the Company's operational trends and performance. | |||||||||||||
|
Operating cash flow is calculated by adjusting net income to add back certain non-cash and non-operating items, including debt extinguishment costs, the unrealized gain and loss on mark-to-market derivative contracts, to include derivative cash settlements for the realized gain and loss on mark-to-market derivative contracts that are classified as investing activities for GAAP purposes, to exclude the unrealized gain and loss on the investment measured at fair value, to include distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary that are classified as financing activities for GAAP purposes and to exclude certain other items. | |||||||||||||
|
Three Months Ended |
Nine Months Ended | ||||||||||||
|
September 30, |
September 30, | ||||||||||||
|
2012 |
2011 |
2012 |
2011 | ||||||||||
|
(millions of dollars) |
|||||||||||||
|
Net (loss) income |
$ (44.0) |
$ (88.3) |
$ 115.0 |
$ 107.6 | |||||||||
|
Items not affecting operating cash flows |
|||||||||||||
|
Depreciation, depletion, amortization and accretion |
274.4 |
172.2 |
710.3 |
466.1 | |||||||||
|
Deferred income tax (benefit) expense |
(23.2) |
(28.4) |
84.3 |
105.2 | |||||||||
|
Debt extinguishment costs |
- |
- |
5.2 |
- | |||||||||
|
Unrealized loss (gain) on mark-to-market derivative contracts |
100.2 |
(125.6) |
(12.6) |
(93.5) | |||||||||
|
Unrealized loss on investment measured at fair value |
43.1 |
395.5 |
92.3 |
284.9 | |||||||||
|
Non-cash compensation |
11.6 |
(0.8) |
37.9 |
27.3 | |||||||||
|
Other non-cash items |
7.4 |
(6.0) |
10.4 |
(6.3) | |||||||||
|
Realized gain (loss) on mark-to-market derivative contracts |
19.5 |
(17.4) |
37.4 |
(47.4) | |||||||||
|
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary |
(6.8) |
- |
(20.3) |
- | |||||||||
|
Operating cash flow (non-GAAP) |
$ 382.2 |
$ 301.2 |
$ 1,059.9 |
$ 843.9 | |||||||||
|
Reconciliation of non-GAAP to GAAP measure |
|||||||||||||
|
Operating cash flow (non-GAAP) |
$ 382.2 |
$ 301.2 |
$ 1,059.9 |
$ 843.9 | |||||||||
|
Cash portion of debt extinguishment costs |
- |
- |
(4.2) |
- | |||||||||
|
Changes in assets and liabilities from operating activities |
46.1 |
26.6 |
8.0 |
31.4 | |||||||||
|
Realized (gain) loss on mark-to-market derivative contracts |
(19.5) |
17.4 |
(37.4) |
47.4 | |||||||||
|
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary |
6.8 |
- |
20.3 |
- | |||||||||
|
Net cash provided by operating activities (GAAP) |
$ 415.6 |
$ 345.2 |
$ 1,046.6 |
$ 922.7 | |||||||||
SOURCE Plains Exploration & Production Company
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