Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - PLAINS EXPLORATION & PRODUCTION CO | d387292d8k.htm |
Exhibit 99.1
|
|
Plains Exploration & Production Company 700 Milam, Suite 3100, Houston, TX 77002 www.pxp.com |
NEWS RELEASE
FOR IMMEDIATE RELEASE
PXP Reports Second-Quarter Results:
Delivers Robust Eagle Ford Oil/Liquids Sales Volume Growth,
Registers Higher Realized Oil/Liquids Prices, and
Generates Strong Cash Flow and Cash Margins
Houston, Texas, August 2, 2012 - Plains Exploration & Production Company (NYSE:PXP) (“PXP” or the “Company”) announces 2012 second-quarter financial and operating results.
SECOND-QUARTER HIGHLIGHTS
| • | Total revenues were $566.7 million, a 10% increase compared to second-quarter 2011. |
| • | Oil/liquids revenues were $519.5 million, a 30% increase compared to second-quarter 2011. |
| • | Average crude oil realized price per barrel before derivative transactions was $99.29, a 5% increase compared to second-quarter 2011, despite lower benchmark prices. |
| • | Average oil/liquids realized price per barrel before derivative transactions was $95.50, a 6% increase compared to second-quarter 2011, despite lower benchmark prices. |
| • | Daily sales volumes averaged approximately 98.3 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 second-quarter 2011. |
| • | Oil/liquids daily sales volumes averaged 59.8 thousand BOE, a 34% increase per diluted share, or 53% per diluted share pro forma for the December 2011 asset sales, compared to second-quarter 2011. |
| • | Net cash provided by operating activities was $295.6 million and operating cash flow (a non-GAAP measure) was $348.5 million, a 3% and 16% increase over second-quarter 2011, respectively. |
| • | Gross margin per BOE was $19.63 and cash margin per BOE (a non-GAAP measure) was $48.97, compared to gross margin per BOE of $25.31 and cash margin per BOE of $39.92 in the second-quarter 2011. |
| • | Net income attributable to common stockholders was $223.2 million, or $1.70 per diluted share compared to second-quarter 2011 net income of $124.9 million, or $0.87 per diluted share. |
Page 2
| • | Adjusted net income attributable to common stockholders (a non-GAAP measure) was $45.8 million, or $0.35 per diluted share compared to second-quarter 2011 adjusted net income of $77.1 million, or $0.54 per diluted share. The 2012 results include an increase in the oil and gas depreciation, depletion and amortization (“DD&A”) rate which resulted in a $0.24 after-tax decrease in earnings per diluted share. The higher DD&A rate reflects the impact of lower sustained natural gas prices which caused reductions in the value of undeveloped locations in the Haynesville Shale and increased transfers from the unproved property pool to the full cost pool. |
| • | The standardized measure of discounted future net cash flows was $6.0 billion and PV-10 value (a non-GAAP measure) was $8.9 billion at June 30, 2012, compared to $5.1 billion and $7.9 billion at December 31, 2011, respectively. |
| • | PXP continues to expand its large, high-margin onshore oil business through the Eagle Ford Shale development while divesting lower margin natural gas assets. In June, PXP entered into an agreement to sell certain non-core properties located in Polk and Tyler counties of East Texas for approximately $24 million, subject to purchase price adjustments. Year-to-date asset sales are approximately $67 million. |
FINANCIAL SUMMARY
PXP reported second-quarter revenues of $566.7 million and net income attributable to common stockholders of $223.2 million, or $1.70 per diluted share, compared to revenues of $514.8 million and net income of $124.9 million, or $0.87 per diluted share, for the second-quarter 2011.
The second-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 gain of $221.8 million due in large part to decreased crude oil forward prices, an $86.7 million unrealized gain 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 $45.8 million, or $0.35 per diluted share (a non-GAAP measure).
For the first six months of 2012, PXP reports revenues of $1.1 billion and net income attributable to common stockholders of $140.9 million, or $1.07 per diluted share, compared to revenues of $945.1 million and net income of $195.9 million, or $1.37 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, and other items. When considering these items, net income attributable to common stockholders for the first six months of 2012 was $122.8 million, or $0.93 per diluted share (a non-GAAP measure), compared to $129.6 million, or $0.90 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 second-quarter daily sales volumes averaged 98.3 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 second-quarter 2011.
Page 3
Crude oil sales volumes averaged 55.8 thousand barrels per day, a 34% increase, pro forma for the December 2011 asset sales, compared to the second-quarter of 2011. The robust volume growth is driven primarily by strong performance in the Eagle Ford Shale and steady, consistent performance in California.
Natural gas liquids sales volumes averaged 4 thousand barrels per day net to PXP, compared to second-quarter 2011 average volumes of 5 thousand barrels per day net to PXP reflecting the impact of the South Texas and Texas Panhandle asset sales in December 2011.
Natural gas sales volumes averaged 231 million cubic feet (“MMcf”) per day net to PXP compared to 295 MMcf per day in the second-quarter 2011. Lower volumes reflect the impact of the December 2011 asset sales and voluntary production curtailments at the Haynesville Shale, partially offset by increased production from the Eagle Ford Shale.
In the Eagle Ford Shale, second-quarter daily sales volumes averaged 25.7 thousand BOE per day net to PXP compared to second-quarter 2011 average daily sales volumes of 2.3 thousand BOE per day net to PXP. At the end of July PXP had 9.1 net drilling rigs operating on its acreage and the number of wells drilled but waiting on completion or connection to pipelines was 27 wells.
In California, second-quarter daily sales volumes averaged 38.7 thousand BOE per day net to PXP compared to the second-quarter 2011 daily sales volume average of 40.5 thousand BOE per day net to PXP. The 2012 development plan is on track and PXP expects to exit the year between 39 – 41 thousand BOE per day. PXP reached total depth on its Point Pedernales Field development well offshore California. The well encountered over 3,500 feet of Monterey section in 5 zones and successfully extended the previously defined reservoir limits.
In the Haynesville Shale, second-quarter daily sales volumes averaged 172.9 MMcf per day net to PXP compared to second-quarter 2011 average daily sales volumes of 181.7 MMcf per day net to PXP. The sales volume decline reflects operator driven production curtailments and reduced drilling activity. At the end of July PXP’s primary operator was operating 2 rigs.
CAPITAL SPENDING
For the second-quarter of 2012, PXP had cash expenditures of $423.0 million for additions to oil and gas properties and $3.6 million for leasehold acquisitions. Of the $426.6 million total, approximately $43.6 million was funded by Plains Offshore Operations Inc., PXP’s consolidated subsidiary.
COMMODITY PRICES
During the second-quarter 2012, Brent crude oil price averaged $108.73 per barrel compared to $116.89 per barrel in the second-quarter 2011. PXP’s 2012 second-quarter crude oil average realized price per barrel before derivative transactions was $99.29 per barrel, or approximately 91% of Brent, compared to $94.43 per barrel in the second-quarter 2011, or approximately 81% of Brent. Including the impact of derivative transactions, the second-quarter 2012 crude oil average realized price was $99.94 per barrel, or approximately 92% of Brent, compared to $90.69 per barrel in the second-quarter 2011, or 78% of Brent.
During the second-quarter 2012, the oil/liquids average realized price per barrel before derivative transactions, which includes 4 thousand BOE per day net to PXP of natural gas liquids, was $95.50 per barrel, or approximately 88% of Brent, compared to $90.42 per barrel in the second-quarter 2011, or 77% of Brent. Including the impact of derivative transactions, the average realized price in the second-quarter 2012 was $96.11 per barrel, or 88% of Brent, compared to $87.06 per barrel in the second-quarter 2011, or 74% of Brent.
Page 4
During the second-quarter 2012, NYMEX gas price averaged $2.22 per million British thermal units (“MMBtu”) compared to $4.32 per MMBtu in the second-quarter 2011. PXP’s 2012 second-quarter natural gas average realized price before derivative transactions was $2.18 per MMBtu, or approximately 98% of NYMEX, compared to $4.23 per MMBtu in the second-quarter 2011, or 98% of NYMEX. Including the impact of derivative transactions, the average realized price in the second-quarter 2012 was $2.93 per MMBtu, or approximately 132% of NYMEX, compared to $4.23 per MMBtu in the second-quarter 2011, or 98% of NYMEX.
DERIVATIVE UPDATE
With higher natural gas production from the Haynesville Shale than originally anticipated, PXP chose to enter into additional swap contracts for 2012. During the three months ended June 30, 2012, PXP entered into natural gas swap contracts on 80,000 MMBtu per day for 2012 with an average price of $2.72 per MMBtu. A detailed list of PXP’s current derivative positions is included with the financial tables at the end of this release.
FULL-YEAR GUIDANCE UPDATE
PXP updated its 2012 full-year operating and financial guidance to reflect higher sales volumes, higher oil volumes as a percentage of total volumes, updated oil price realizations, and higher DD&A expense per BOE. The 2012 operating and financial guidance is included with the financial tables at the end of this release.
MANAGEMENT COMMENT
James C. Flores, Chairman, President and CEO of PXP commented, “We had an impressive quarter with continued robust Eagle Ford expansion and solid California operating performance demonstrating the strength of the Company’s underlying oil asset base. Our growing oil sales volumes, our improved crude oil marketing contracts and our hedging strategy are driving higher revenues, stronger cash flow and healthy cash margins. As part of our focused oil growth strategy, we remain committed to aggressively expanding our large, high-margin oil business. In the short-term, PXP is providing stellar execution of its Eagle Ford growth plan. We are not only seeing strong production growth but also beginning to see efficiencies across all aspects of our Eagle Ford activity. Longer-term, PXP is moving forward on its exciting Gulf of Mexico projects that are expected to add significant future production. The Lucius Field in the deepwater Keathley Canyon area is on schedule for production in the second half of 2014 and the plans to spud the Phobos prospect, located in the same complex as Lucius and part of the same emerging Pliocene trend, are on track for late this year or early 2013. Financially, PXP’s strength is supported by both growing oil-driven cash flow and ample debt/liquidity availability, enabling the execution of our capital expenditure and our stock buy-back programs.”
CONFERENCE CALL
PXP will host a conference call today, Thursday, August 2, 2012 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: 92628335. 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.
Page 5
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:
* reserve and production estimates,
* oil and gas prices,
* the impact of derivative positions,
* production expense estimates,
* cash flow estimates,
* future financial performance,
* capital and credit market conditions,
* planned capital expenditures, and
* other matters that are discussed in PXP’s filings with the SEC.
These statements are based on our current expectations and projections about future events and involve known and unknown risks, uncertainties, and other factors that may cause our actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. Please refer to our filings with the SEC, including our Form 10-K, for a discussion of these risks.
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.
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.
Contact: Hance Myers: hmyers@pxp.com; 713.579.6291
Page 6
Plains Exploration & Production Company
Consolidated Statements of Income
(in thousands, except per share data)
| Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| (Unaudited) | ||||||||||||||||
| Revenues |
||||||||||||||||
| Oil sales |
$ | 519,508 | $ | 399,306 | $ | 986,996 | $ | 731,149 | ||||||||
| Gas sales |
45,959 | 113,670 | 99,483 | 210,472 | ||||||||||||
| Other operating revenues |
1,257 | 1,809 | 4,520 | 3,478 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| 566,724 | 514,785 | 1,090,999 | 945,099 | |||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Costs and Expenses |
||||||||||||||||
| Lease operating expenses |
87,662 | 82,142 | 170,668 | 154,393 | ||||||||||||
| Steam gas costs |
9,711 | 16,865 | 20,835 | 32,626 | ||||||||||||
| Electricity |
10,777 | 10,371 | 22,151 | 20,091 | ||||||||||||
| Production and ad valorem taxes |
19,085 | 16,920 | 31,716 | 28,448 | ||||||||||||
| Gathering and transportation expenses |
19,029 | 16,841 | 35,301 | 29,588 | ||||||||||||
| General and administrative |
31,701 | 30,783 | 70,083 | 66,806 | ||||||||||||
| Depreciation, depletion and amortization |
250,730 | 150,757 | 428,427 | 285,300 | ||||||||||||
| Accretion |
3,750 | 4,314 | 7,503 | 8,571 | ||||||||||||
| Other operating income |
(1,276 | ) | (303 | ) | (2,537 | ) | (607 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| 431,169 | 328,690 | 784,147 | 625,216 | |||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Income from Operations |
135,555 | 186,095 | 306,852 | 319,883 | ||||||||||||
| Other (Expense) Income |
||||||||||||||||
| Interest expense |
(52,977 | ) | (37,242 | ) | (98,230 | ) | (69,646 | ) | ||||||||
| Debt extinguishment costs |
(5,167 | ) | — | (5,167 | ) | — | ||||||||||
| Gain (loss) on mark-to-market derivative contracts |
221,783 | 18,912 | 112,733 | (32,084 | ) | |||||||||||
| Gain (loss) on investment measured at fair value |
86,750 | 43,307 | (49,180 | ) | 110,561 | |||||||||||
| Other income |
834 | 996 | 429 | 1,550 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Income Before Income Taxes |
386,778 | 212,068 | 267,437 | 330,264 | ||||||||||||
| Income tax expense |
||||||||||||||||
| Current |
(986 | ) | (387 | ) | (1,005 | ) | (759 | ) | ||||||||
| Deferred |
(153,517 | ) | (86,789 | ) | (107,460 | ) | (133,634 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net Income |
$ | 232,275 | $ | 124,892 | $ | 158,972 | $ | 195,871 | ||||||||
|
|
|
|
|
|||||||||||||
| Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary |
(9,076 | ) | (18,092 | ) | ||||||||||||
|
|
|
|
|
|||||||||||||
| Net Income Attributable to Common Stockholders |
$ | 223,199 | $ | 140,880 | ||||||||||||
|
|
|
|
|
|||||||||||||
| Earnings per Common Share |
||||||||||||||||
| Basic |
$ | 1.72 | $ | 0.88 | $ | 1.09 | $ | 1.39 | ||||||||
| Diluted |
$ | 1.70 | $ | 0.87 | $ | 1.07 | $ | 1.37 | ||||||||
| Weighted Average Common Shares Outstanding |
||||||||||||||||
| Basic |
130,019 | 141,797 | 129,683 | 141,335 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Diluted |
131,509 | 143,300 | 131,701 | 143,361 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
Page 7
Plains Exploration & Production Company
Operating Data
| Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| (Unaudited) | ||||||||||||||||
| Daily Average Volumes |
||||||||||||||||
| Oil and liquids sales (Bbls) |
59,780 | 48,524 | 54,718 | 46,308 | ||||||||||||
| Gas (Mcf) |
||||||||||||||||
| Production |
235,142 | 301,162 | 234,572 | 285,280 | ||||||||||||
| Used as fuel |
3,804 | 5,874 | 4,255 | 5,831 | ||||||||||||
| Sales |
231,338 | 295,288 | 230,317 | 279,449 | ||||||||||||
| BOE |
||||||||||||||||
| Production |
98,970 | 98,718 | 93,814 | 93,855 | ||||||||||||
| Sales |
98,336 | 97,739 | 93,105 | 92,883 | ||||||||||||
| Unit Economics (in dollars) |
||||||||||||||||
| Average Index Prices |
||||||||||||||||
| ICE Brent Price per Bbl |
$ | 108.73 | $ | 116.89 | $ | 113.57 | $ | 111.20 | ||||||||
| NYMEX Price per Bbl |
93.35 | 102.34 | 98.15 | 98.50 | ||||||||||||
| NYMEX Price per Mcf |
2.22 | 4.32 | 2.47 | 4.20 | ||||||||||||
| Average Realized Sales Price Before Derivative Transactions |
||||||||||||||||
| Oil (per Bbl) |
$ | 95.50 | $ | 90.42 | $ | 99.11 | $ | 87.23 | ||||||||
| Gas (per Mcf) |
2.18 | 4.23 | 2.37 | 4.16 | ||||||||||||
| Per BOE |
63.19 | 57.68 | 64.12 | 56.01 | ||||||||||||
| Cash Margin per BOE (1) |
||||||||||||||||
| Oil and gas revenues |
$ | 63.19 | $ | 57.68 | $ | 64.12 | $ | 56.01 | ||||||||
| Costs and expenses |
||||||||||||||||
| Lease operating expenses |
(9.80 | ) | (9.23 | ) | (10.07 | ) | (9.19 | ) | ||||||||
| Steam gas costs |
(1.09 | ) | (1.90 | ) | (1.23 | ) | (1.94 | ) | ||||||||
| Electricity |
(1.20 | ) | (1.17 | ) | (1.31 | ) | (1.20 | ) | ||||||||
| Production and ad valorem taxes |
(2.13 | ) | (1.90 | ) | (1.87 | ) | (1.69 | ) | ||||||||
| Gathering and transportation |
(2.13 | ) | (1.89 | ) | (2.08 | ) | (1.76 | ) | ||||||||
| Oil and gas related DD&A |
(27.21 | ) | (16.28 | ) | (24.58 | ) | (16.28 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Gross margin (GAAP) |
19.63 | 25.31 | 22.98 | 23.95 | ||||||||||||
| Oil and gas related DD&A |
27.21 | 16.28 | 24.58 | 16.28 | ||||||||||||
| Realized gain (loss) on derivative instruments |
2.13 | (1.67 | ) | 1.63 | (1.72 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Cash margin (non-GAAP) |
$ | 48.97 | $ | 39.92 | $ | 49.19 | $ | 38.51 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Oil and gas capital expenditures accrued ($ in thousands) (2) |
$ | 498,806 | $ | 472,056 | $ | 938,745 | $ | 861,397 | ||||||||
| (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. |
Page 8
Plains Exploration & Production Company
Reconciliation of GAAP to Non-GAAP Measure
| Three Months Ended June 30, 2012 | ||||||||||||
| Oil | Gas | BOE | ||||||||||
| (per Bbl) | (per Mcf) | |||||||||||
| Average Realized Sales Price |
||||||||||||
| Average realized price before derivative instruments (GAAP) (1) |
$ | 95.50 | $ | 2.18 | $ | 63.19 | ||||||
| Realized gain on derivative instruments |
0.61 | 0.75 | 2.13 | |||||||||
|
|
|
|
|
|
|
|||||||
| Realized cash price including derivative settlements (non-GAAP) |
$ | 96.11 | $ | 2.93 | $ | 65.32 | ||||||
|
|
|
|
|
|
|
|||||||
| Three Months Ended June 30, 2011 | ||||||||||||
| Oil | Gas | BOE | ||||||||||
| (per Bbl) | (per Mcf) | |||||||||||
| Average Realized Sales Price |
||||||||||||
| Average realized price before derivative instruments (GAAP) (1) |
$ | 90.42 | $ | 4.23 | $ | 57.68 | ||||||
| Realized loss on derivative instruments |
(3.36 | ) | — | (1.67 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Realized cash price including derivative settlements (non-GAAP) |
$ | 87.06 | $ | 4.23 | $ | 56.01 | ||||||
|
|
|
|
|
|
|
|||||||
| Six Months Ended June 30, 2012 | ||||||||||||
| Oil | Gas | BOE | ||||||||||
| (per Bbl) | (per Mcf) | |||||||||||
| Average Realized Sales Price |
||||||||||||
| Average realized price before derivative instruments (GAAP) (1) |
$ | 99.11 | $ | 2.37 | $ | 64.12 | ||||||
| Realized (loss) gain on derivative instruments |
(0.32 | ) | 0.74 | 1.63 | ||||||||
|
|
|
|
|
|
|
|||||||
| Realized cash price including derivative settlements (non-GAAP) |
$ | 98.79 | $ | 3.11 | $ | 65.75 | ||||||
|
|
|
|
|
|
|
|||||||
| Six Months Ended June 30, 2011 | ||||||||||||
| Oil | Gas | BOE | ||||||||||
| (per Bbl) | (per Mcf) | |||||||||||
| Average Realized Sales Price |
||||||||||||
| Average realized price before derivative instruments (GAAP) (1) |
$ | 87.23 | $ | 4.16 | $ | 56.01 | ||||||
| Realized (loss) gain on derivative instruments |
(3.52 | ) | 0.01 | (1.72 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Realized cash price including derivative settlements (non-GAAP) |
$ | 83.71 | $ | 4.17 | $ | 54.29 | ||||||
|
|
|
|
|
|
|
|||||||
| (1) | Excludes the impact of production costs and expenses and DD&A. |
Page 9
Plains Exploration & Production Company
Consolidated Statements of Cash Flows
(in thousands of dollars)
| Six Months
Ended June 30, |
||||||||
| 2012 | 2011 | |||||||
| (Unaudited) | ||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||
| Net income |
$ | 158,972 | $ | 195,871 | ||||
| Items not affecting cash flows from operating activities |
||||||||
| Depreciation, depletion, amortization and accretion |
435,930 | 293,871 | ||||||
| Deferred income tax expense |
107,460 | 133,634 | ||||||
| Debt extinguishment costs |
939 | — | ||||||
| (Gain) loss on mark-to-market derivative contracts |
(112,733 | ) | 32,084 | |||||
| Loss (gain) on investment measured at fair value |
49,180 | (110,561 | ) | |||||
| Non-cash compensation |
26,229 | 28,031 | ||||||
| Other non-cash items |
3,060 | (302 | ) | |||||
| Change in assets and liabilities from operating activities |
(38,081 | ) | 4,797 | |||||
|
|
|
|
|
|||||
| Net cash provided by operating activities |
630,956 | 577,425 | ||||||
|
|
|
|
|
|||||
| CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||
| Additions to oil and gas properties |
(824,280 | ) | (800,170 | ) | ||||
| Acquisition of oil and gas properties |
(20,141 | ) | (32,456 | ) | ||||
| Proceeds from sales of oil and gas properties, net of costs and expenses |
42,842 | 11,987 | ||||||
| Derivative settlements |
17,862 | (30,039 | ) | |||||
| Additions to other property and equipment |
(6,426 | ) | (6,534 | ) | ||||
|
|
|
|
|
|||||
| Net cash used in investing activities |
(790,143 | ) | (857,212 | ) | ||||
|
|
|
|
|
|||||
| CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||
| Borrowings from revolving credit facilities |
4,334,675 | 2,679,200 | ||||||
| Repayments of revolving credit facilities |
(4,771,675 | ) | (2,989,200 | ) | ||||
| 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 |
(12,582 | ) | (11,320 | ) | ||||
| Purchase of treasury stock |
(88,490 | ) | — | |||||
| Distributions to holders of noncontrolling interest in the form of |
(13,500 | ) | — | |||||
| Other |
— | 4 | ||||||
|
|
|
|
|
|||||
| Net cash provided by financing activities |
42,246 | 278,684 | ||||||
|
|
|
|
|
|||||
| Net decrease in cash and cash equivalents |
(116,941 | ) | (1,103 | ) | ||||
| Cash and cash equivalents, beginning of period |
419,098 | 6,434 | ||||||
|
|
|
|
|
|||||
| Cash and cash equivalents, end of period |
$ | 302,157 | $ | 5,331 | ||||
|
|
|
|
|
|||||
Page 10
Plains Exploration & Production Company
Consolidated Balance Sheets
(in thousands of dollars)
| June 30, 2012 |
December 31, 2011 |
|||||||
| (Unaudited) | ||||||||
| ASSETS | ||||||||
| Current Assets |
||||||||
| Cash and cash equivalents |
$ | 302,157 | $ | 419,098 | ||||
| Accounts receivable |
284,591 | 302,675 | ||||||
| Commodity derivative contracts |
99,458 | 50,964 | ||||||
| Inventories |
18,517 | 20,173 | ||||||
| Investment |
562,491 | 611,671 | ||||||
| Deferred income taxes |
53,300 | 20,723 | ||||||
| Prepaid expenses and other current assets |
14,323 | 16,073 | ||||||
|
|
|
|
|
|||||
| 1,334,837 | 1,441,377 | |||||||
|
|
|
|
|
|||||
| Property and Equipment, at cost |
||||||||
| Oil and natural gas properties - full cost method |
||||||||
| Subject to amortization |
13,533,372 | 12,016,252 | ||||||
| Not subject to amortization |
1,747,325 | 2,409,449 | ||||||
| Other property and equipment |
152,385 | 145,959 | ||||||
|
|
|
|
|
|||||
| 15,433,082 | 14,571,660 | |||||||
| Less allowance for depreciation, depletion, amortization and impairment |
(7,210,472 | ) | (6,846,365 | ) | ||||
|
|
|
|
|
|||||
| 8,222,610 | 7,725,295 | |||||||
|
|
|
|
|
|||||
| Goodwill |
535,140 | 535,140 | ||||||
|
|
|
|
|
|||||
| Commodity Derivative Contracts |
54,431 | 12,678 | ||||||
|
|
|
|
|
|||||
| Other Assets |
84,417 | 76,982 | ||||||
|
|
|
|
|
|||||
| $ | 10,231,435 | $ | 9,791,472 | |||||
|
|
|
|
|
|||||
| LIABILITIES AND EQUITY | ||||||||
| Current Liabilities |
||||||||
| Accounts payable |
$ | 439,718 | $ | 385,231 | ||||
| Commodity derivative contracts |
— | 3,761 | ||||||
| Royalties and revenues payable |
103,074 | 97,095 | ||||||
| Interest payable |
66,005 | 39,342 | ||||||
| Other current liabilities |
82,111 | 100,757 | ||||||
|
|
|
|
|
|||||
| 690,908 | 626,186 | |||||||
|
|
|
|
|
|||||
| Long-Term Debt |
3,918,940 | 3,760,952 | ||||||
|
|
|
|
|
|||||
| Other Long-Term Liabilities |
||||||||
| Asset retirement obligation |
239,165 | 230,633 | ||||||
| Commodity derivative contracts |
454 | 823 | ||||||
| Other |
16,524 | 15,749 | ||||||
|
|
|
|
|
|||||
| 256,143 | 247,205 | |||||||
|
|
|
|
|
|||||
| Deferred Income Taxes |
1,601,934 | 1,461,897 | ||||||
|
|
|
|
|
|||||
| Equity |
||||||||
| Stockholders’ equity |
||||||||
| Common stock |
1,439 | 1,439 | ||||||
| Additional paid-in capital |
3,415,323 | 3,434,928 | ||||||
| Retained earnings |
471,903 | 337,991 | ||||||
| Treasury stock, at cost |
(560,343 | ) | (509,722 | ) | ||||
|
|
|
|
|
|||||
| 3,328,322 | 3,264,636 | |||||||
| Noncontrolling interest |
||||||||
| Preferred stock of subsidiary |
435,188 | 430,596 | ||||||
|
|
|
|
|
|||||
| 3,763,510 | 3,695,232 | |||||||
|
|
|
|
|
|||||
| $ | 10,231,435 | $ | 9,791,472 | |||||
|
|
|
|
|
|||||
Page 11
Plains Exploration & Production Company
Summary of Open Derivative Positions
At June 30, 2012
| Period (1) |
Instrument Type |
Daily Volumes |
Average Price (2) |
Average Deferred Premium |
Index | |||||
| Sales of Crude Oil Production |
||||||||||
| 2012 |
||||||||||
| Jul - Dec |
Three-way collars (3) | 40,000 Bbls | $100.00 Floor with an $80.00 Limit | — | Brent | |||||
| $120.00 Ceiling | ||||||||||
| 2013 |
||||||||||
| Jan - Dec |
Put options (4) | 17,000 Bbls | $90.00 Floor with a $70.00 Limit | $6.253 per Bbl | Brent | |||||
| Jan - Dec |
Put options (4) | 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 | ||||||||||
| 2014 |
||||||||||
| Jan - Dec |
Put options (4) | 50,000 Bbls | $90.00 Floor with a $70.00 Limit | $5.979 per Bbl | Brent | |||||
| Sales of Natural Gas Production |
||||||||||
| 2012 |
||||||||||
| Jul - Dec |
Put options (5) | 120,000 MMBtu | $4.30 Floor with a $3.00 Limit | $0.298 per MMBtu | Henry Hub | |||||
| Jul - Dec |
Three-way collars (6) | 40,000 MMBtu | $4.30 Floor with a $3.00 Limit | — | Henry Hub | |||||
| $4.86 Ceiling | ||||||||||
| Jul - Dec |
Swap contracts (7) | 80,000 MMBtu | $2.72 | — | Henry Hub | |||||
| 2013 |
||||||||||
| Jan - Dec |
Swap contracts (7) | 110,000 MMBtu | $4.27 | — | Henry Hub | |||||
| 2014 |
||||||||||
| Jan - Dec |
Swap contracts (7) | 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 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 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. |
| (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. 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. |
| (7) | 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. |
Derivative Settlements
(in thousands of dollars)
The following tables reflect cash receipts (payments) for derivatives attributable to the stated production periods.
| Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| Oil sales |
$ | 3,308 | $ | (14,855 | ) | $ | (3,201 | ) | $ | (29,537 | ) | |||||
| Natural gas sales |
15,732 | — | 30,909 | 620 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| $ | 19,040 | $ | (14,855 | ) | $ | 27,708 | $ | (28,917 | ) | |||||||
|
|
|
|
|
|
|
|
|
|||||||||
Page 12
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 six months ended June 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 June 30, |
||||||||
| 2012 | 2011 | |||||||
| (millions of dollars) | ||||||||
| Net income (GAAP) |
$ | 232.3 | $ | 124.9 | ||||
| Unrealized gain on mark-to-market derivative contracts |
(221.8 | ) | (18.9 | ) | ||||
| Realized gain (loss) on mark-to-market derivative contracts (1) |
19.0 | (14.9 | ) | |||||
| Unrealized gain on investment measured at fair value |
(86.7 | ) | (43.3 | ) | ||||
| Debt extinguishment costs |
5.2 | — | ||||||
| Adjust income taxes (2) |
106.9 | 29.3 | ||||||
|
|
|
|
|
|||||
| Adjusted net income (non-GAAP) |
$ | 54.9 | $ | 77.1 | ||||
|
|
|
|||||||
| Net income attributable to noncontrolling interest in the form of |
(9.1 | ) | ||||||
|
|
|
|||||||
| Adjusted net income attributable to common stockholders (non-GAAP) |
$ | 45.8 | ||||||
|
|
|
|||||||
| Six Months Ended June 30, |
||||||||
| 2012 | 2011 | |||||||
| (millions of dollars) | ||||||||
| Net income (GAAP) |
$ | 159.0 | $ | 195.9 | ||||
| Unrealized (gain) loss on mark-to-market derivative contracts |
(112.7 | ) | 32.1 | |||||
| Realized gain (loss) on mark-to-market derivative contracts (1) |
27.7 | (28.9 | ) | |||||
| Unrealized loss (gain) on investment measured at fair value |
49.2 | (110.6 | ) | |||||
| Debt extinguishment costs |
5.2 | — | ||||||
| Adjust income taxes (2) |
12.5 | 41.1 | ||||||
|
|
|
|
|
|||||
| Adjusted net income (non-GAAP) |
$ | 140.9 | $ | 129.6 | ||||
|
|
|
|||||||
| Net income attributable to noncontrolling interest in the form of |
(18.1 | ) | ||||||
|
|
|
|||||||
| Adjusted net income attributable to common stockholders (non-GAAP) |
$ | 122.8 | ||||||
|
|
|
|||||||
| (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 47% and 43% for the three months ended June 30, 2012 and 2011, respectively. Tax rates assumed based upon adjusted earnings are 41% and 42% for the six months ended June 30, 2012 and 2011. Tax rates exclude the effects of nonrecurring tax related expenses and benefits. |
Page 13
Plains Exploration & Production Company
Reconciliation of GAAP to Non-GAAP Measure
The following tables reconcile Net Cash Provided by Operating Activities (GAAP) to Operating Cash Flow (non-GAAP) for the three and six months ended June 30, 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 June 30, |
Six Months Ended June 30, |
|||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| (millions of dollars) | ||||||||||||||||
| Net income |
$ | 232.3 | $ | 124.9 | $ | 159.0 | $ | 195.9 | ||||||||
| Items not affecting operating cash flows |
||||||||||||||||
| Depreciation, depletion, amortization and accretion |
254.5 | 155.1 | 435.9 | 293.9 | ||||||||||||
| Deferred income tax expense |
153.5 | 86.8 | 107.5 | 133.6 | ||||||||||||
| Debt extinguishment costs |
5.2 | — | 5.2 | — | ||||||||||||
| Unrealized (gain) loss on mark-to-market derivative contracts |
(221.8 | ) | (18.9 | ) | (112.7 | ) | 32.1 | |||||||||
| Unrealized (gain) loss on investment measured at fair value |
(86.7 | ) | (43.3 | ) | 49.2 | (110.6 | ) | |||||||||
| Non-cash compensation |
8.0 | 11.2 | 26.2 | 28.0 | ||||||||||||
| Other non-cash items |
1.6 | (1.2 | ) | 3.0 | (0.3 | ) | ||||||||||
| Realized gain (loss) on mark-to-market derivative contracts |
8.6 | (15.0 | ) | 17.9 | (30.0 | ) | ||||||||||
| Distributions to holders of noncontrolling interest in the form of |
(6.7 | ) | — | (13.5 | ) | — | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating cash flow (non-GAAP) |
$ | 348.5 | $ | 299.6 | $ | 677.7 | $ | 542.6 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Reconciliation of non-GAAP to GAAP measure |
||||||||||||||||
| Operating cash flow (non-GAAP) |
$ | 348.5 | $ | 299.6 | $ | 677.7 | $ | 542.6 | ||||||||
| Cash portion of debt extinguishment costs |
(4.2 | ) | — | (4.2 | ) | — | ||||||||||
| Changes in assets and liabilities from operating activities |
(46.8 | ) | (27.1 | ) | (38.1 | ) | 4.8 | |||||||||
| Realized (gain) loss on mark-to-market derivative contracts |
(8.6 | ) | 15.0 | (17.9 | ) | 30.0 | ||||||||||
| Distributions to holders of noncontrolling interest in the form of |
6.7 | — | 13.5 | — | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net cash provided by operating activities (GAAP) |
$ | 295.6 | $ | 287.5 | $ | 631.0 | $ | 577.4 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
Page 14
Plains Exploration & Production Company
PV-10 to Standardized Measure Reconciliation (in millions of dollars)
| June 30, 2012 |
December 31, 2011 |
|||||||
| Estimated undiscounted future net cash flows before income taxes |
$ | 16,185.1 | $ | 15,942.2 | ||||
|
|
|
|
|
|||||
| Present value of estimated future net cash flows before income taxes (PV-10) (1) |
$ | 8,897.3 | $ | 7,884.5 | ||||
| Discounted future income taxes |
(2,870.7 | ) | (2,750.3 | ) | ||||
|
|
|
|
|
|||||
| Standardized measure of discounted net cash flows |
$ | 6,026.6 | $ | 5,134.2 | ||||
|
|
|
|
|
|||||
| (1) | PV-10 is PXP’s estimate of the present value of future net revenues from proved 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 generally differs from the Standardized Measure, the most directly comparable GAAP financial measure, 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.
Page 15
Plains Exploration & Production Company
Full-Year 2012 Operating and Financial Guidance
| Year Ended December 31, 2012 | ||||||||
| Production Volumes (MBOE/day) |
||||||||
| Total Production volumes sold |
95 — 97 | |||||||
| Oil |
57% — 60% | |||||||
| NGLs |
3% — 4% | |||||||
| Natural Gas |
40% — 36% | |||||||
| Product Price Realization (Unhedged) |
||||||||
| Oil - Brent |
94% — 96% | |||||||
| Oil - Transportation expense |
$5.00 | |||||||
| NGLs - WTI |
40% | |||||||
| Gas - Henry Hub |
100% | |||||||
| Gas - Transportation expense |
$0.15 | |||||||
| Production Costs per BOE |
||||||||
| Lease operating expense |
$9.50 — $10.50 | |||||||
| Steam gas costs (1) |
$1.25 — $1.75 | |||||||
| Electricity |
$1.20 — $1.40 | |||||||
| Production and ad valorem taxes (2) |
$2.00 — $2.25 | |||||||
| Gathering and transportation |
$1.50 — $2.00 | |||||||
| Depreciation, Depletion and Amortization per BOE |
$26 — $28 | |||||||
| General and Administrative Expenses (in millions) |
||||||||
| Cash |
$107 — $111 | |||||||
| Stock-based compensation (3) |
$40 — $46 | |||||||
| Interest Expense |
||||||||
| Average revolver balance |
30 Day | LIBOR + 1.50% | - 2.50% | |||||
| $185 Million Senior Notes |
10.000% | |||||||
| $400 Million Senior Notes |
7.625% | |||||||
| $750 Million Senior Notes |
6.125% | |||||||
| $400 Million Senior Notes |
8.625% | |||||||
| $300 Million Senior Notes |
7.625% | |||||||
| $600 Million Senior Notes |
6.625% | |||||||
| $1,000 Million Senior Notes |
6.750% | |||||||
| Effective Tax Rate |
38% — 40% | |||||||
| Weighted Average Equivalent Shares Outstanding (in thousands) |
||||||||
| Basic |
127,600 | |||||||
| Diluted |
129,300 | |||||||
| Capital Expenditures (in millions) (4) |
||||||||
| PXP |
$1,366 | |||||||
| Gulf of Mexico - Plains Offshore |
234 | |||||||
|
|
||||||||
| Total |
$1,600 | |||||||
|
|
||||||||
| (1) | Steam gas costs assume a base SoCal Border index price of $3.84 per MMBtu. The purchased volumes are anticipated to be 43,000 - 45,000 MMBtu per day. |
| (2) | Production and ad valorem taxes assume base index prices of $110.00 per barrel and $4.00 per MMBtu. (Note: Brent index price for Oil) |
| (3) | Based on current outstanding and projected awards and current stock price. |
| (4) | Includes capitalized interest and general and administrative expenses. |
###