| PXP | Plains Exploration & Production Company 500 Dallas St., Suite 700 Houston, TX 77002 |
NEWS RELEASE
Contact: | Winston Talbert | |
| Vice President Finance and Investor Relations | ||
| (713) 739-6700 or (800) 934-6083 |
FOR IMMEDIATE RELEASE
PLAINS EXPLORATION REPORTS SECOND QUARTER EARNINGS
Financial Results
Houston, Texas – August 7, 2003—Plains Exploration & Production Company (NYSE:PXP) (“PXP” or the “Company”) today reported second quarter 2003 net income of $7.2 million, or $0.25 per diluted share, compared to net income of $8.2 million, or $0.34 per diluted share, for the second quarter of 2002. Net income in the second quarter of 2003 includes pre-tax expenses of $0.9 million ($0.5 million after tax) for merger related costs and approximately $4.0 million ($2.4 million after tax) of non cash expenses attributable to outstanding Stock Appreciation Rights (“SARS”). In aggregate, these charges reduced net income by $2.9 million ($0.10 per diluted share). Accounting for SARS requires that we record an expense or credit to the income statement depending on whether, during the period, our stock price either increased or decreased, respectively. Accordingly, since our stock price at June 30, 2003 was $10.81 as compared to $8.25 on March 31, 2003 the Company recorded a non-cash expense. The Company will incur cash expenditures only as SARS are exercised.
For the first six months of the year net income was $28.2 million, or $1.06 per diluted share, compared to net income of $14.1 million, or $0.58 per diluted share for the same period of 2002. Net income in the first six months of 2003 includes a non-cash expense of approximately $1.6 million ($0.06 per diluted share) related to the SARS and $0.6 million ($0.02 per diluted share) attributable to merger related costs. Net income for the first six months of 2003 also includes a $12.3 million credit ($0.47 per diluted share) for the adoption of FAS 143.
Results for the second quarter and the first six months include the impact from the acquisition of 3TEC Energy effective as of June 1, 2003.
Oil and gas production volumes increased 24% to 30.2 thousand barrels of oil equivalent (MBOE) per day in the second quarter of 2003, compared to 24.4 MBOE/day in the 2002 period. Natural gas production increased to 30.2 MMcf/day for the quarter as compared to 9.3 MMcf/day in 2002. For the six month period, daily production averaged 27.9 MBOE as compared to 24.3 MBOE for the same period in 2002.
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The Company’s average wellhead price, which is net of location and quality differentials and the impact of hedges, was $22.67 per BOE for the second quarter of 2003 as compared to $20.33 per BOE for the same period a year ago. For the first six months of 2003, the Company’s average wellhead price was $22.54 per BOE as compared to $19.50 per BOE in the same period in 2002.
Oil and gas capital expenditures for the second quarter of 2003 were $37.1 million as compared to $18.4 million in the same period in 2002. For the first six months of the year capital expenditures were $54.2 million as compared to $42.3 million in 2002.
As reflected in the accompanying tables, gross margin per BOE was $13.74 in the second quarter of 2003 as compared to $12.29 in same period in 2002. For the first six months of 2003, gross margin was $13.52 per BOE as compared to $11.53 per BOE in the same period a year ago. The increase is due primarily to the increase in natural gas production attributable to the 3TEC acquisition.
Gross profit per BOE for the quarter was $10.31 compared to $11.27 per BOE in the same period in 2002. Current quarter gross profit was impacted by per BOE charges of $1.46 and $0.31, respectively, for SARS and merger related General and Administrative expenses (“G&A”). In addition, G&A in 2002 consisted of amounts allocated from Plains Resources and is not comparable to 2003 expenses as it did not include all the costs of operating as a public company. For the first six months of 2003, gross profit per BOE was $11.04 as compared to $10.46 in the same period in 2002. The six month period includes a per BOE charge of $0.52 and $0.22, respectively, for SARS and merger related G&A expenses in the 2003 period.
Pro Forma Operating Results
“As demonstrated above, the Company delivered a solid set of second quarter results consistent with 8-K guidance previously provided. Furthermore, we have expanded our disclosure efforts this quarter by providing both actual results as mandated as well as pro forma results to provide a clear understanding of how results would look had the organization been combined for the entire quarter and year, respectively. To that end, assimilation continues to progress smoothly as all major components of the integration of the 3TEC transaction are on time and within budget.
As evidenced by the 8-K guidance provided this morning for the remainder of the year, we expect the organization to continue to perform both financially and operationally in a manner that is highly consistent with expectations set forth in previous guidance as each of the three business units continue to deliver solid results. Additionally, the organization continues to advance several key projects that provide the foundation for long term success” stated Mr. John T. Raymond, President and Chief Operating Officer.
On a pro forma basis (assuming PXP and 3TEC were combined as of January 1, 2003) the combined company produced 39.2 MBOE/day in the second quarter and 39.3 MBOE/day for the six month period. For the second quarter and six month period the combined company produced 75.4 MMcf/day and 76.5 MMcf/day of natural gas, respectively. The pro forma average sales price was $24.34 per BOE for the quarter and $24.12 per BOE for the first six months of 2003.
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Pro forma gross margin per BOE was $16.11 and $15.93 for the quarter and six months, respectively. The pro forma gross profit per BOE was $12.99 in the second quarter and $13.60 for the first six months of 2003. The second quarter gross profit per BOE includes a charge of $1.12 and $0.24, for SARS and merger related G&A expenses. For the six month period, gross profit included a charge of $0.37 per BOE and $0.15 per BOE for SARS and merger related G&A expenses, respectively.
Operational Update
Effective with the 3TEC Energy acquisition, the Company reorganized its Exploration and Production activities geographically into three Business Units. Eastern, headquartered in Lafayette, Louisiana manages activities in south Louisiana and the Gulf of Mexico; Central, located in Houston, manages activities primarily in Texas and Illinois, and Western in Los Angles handles California.
In the Eastern Business Unit, successful activity has continued in the Breton Sound area, offshore Louisiana. At the time of the PXP/3TEC acquisition announcement in February 2003, 3TEC had recorded six successful wells in seven attempts. There are now ten apparent successes in 11 attempts. The State Lease 17294 #1, “Aquila Prospect” tested 6.8 MMcf and 495 Bbls of condensate per day on April 28, 2003 and began production to sales on June 1. PXP’s interest is 50%. The State Lease 14216 #1, “Zeus Prospect” tested 8.7 MMcf and 653 Bbls of condensate per day on June 9, 2003 and began production to sales on June 27. PXP is operator of the Zeus prospect and has a 58.75% interest. Both the State Lease #17691 #1, “Perseus Prospect” and State Lease 17408 #1, “Treasure Bay East Prospect” found expected pay in the prospective interval. Casing has been cemented in place and normal completion operations are ongoing on both at this time. PXP’s interest is 50% in Perseus and 100% in Treasure Bay East. Production to sales from both wells is expected to begin later in the third quarter. Drilling efforts are ongoing in this area and are expected to continue into 2004.
Also in the Eastern Business Unit in the Garden City Field in St. Mary Parish, Louisiana, the Bailey Mineral Partnership #1 was recompleted to the MA-1E upper sand after producing approximately 4 Bcfe, slightly more than it’s initially assigned reserves, from the MA-1E lower sand. The MA–1E upper tested to sales at 16.2 MMcf and 1,075 Bbls condensate per day at 8,900 psi flowing tubing pressure on July 20, 2003. PXP operates the Bailey #1 with a 49% interest. Also in the Garden City Field, PXP spud the Bailey Mineral Partnership #2 on June 17 to test an adjacent up-thrown fault block to the Bailey #1. Present depth is approximately 16,500’ with a planned total depth of about 18,000’. Overlapping and in the Garden City Field and Bayou Carlin area, PXP completed acquisition of 102 square miles of new 3-D seismic data on August 1. Data processing is in progress with interpretation expected to begin early in the fourth quarter.
In PXP’s Central Business Unit, development of East Texas area Cotton Valley Sand gas reserves continued through the second quarter with four to five drilling rigs continuously operating. That pace is expected to continue through the third quarter. While PXP’s ownership varies by location, the Company has an approximate average 40% interest.
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In the Western Business Unit, acquisition of 21.5 square miles of proprietary 3-D seismic data over the Inglewood Field in the onshore Los Angeles Basin was completed on May 19. Delivery of processed data is expected later this month. The Inglewood Field has produced about 400 million barrels of oil since discovery from a variety of depths, zones, and fault blocks but heretofore all development had been conducted without benefit of any seismic data. PXP currently produces about 7,000 net barrels of oil equivalent per day from the Inglewood Field and has a 100% interest. Also in the LA Basin, PXP completed San Vicente Field development wells S-20B and S-94A at 223 and 199 barrels of oil per day, respectively. These wells increased total field production to slightly over 3,000 barrels of oil per day, the highest production level since 1978. PXP owns a 100% interest in the San Vicente Field. Elsewhere in the Western Business Unit, PXP completed a 96 well drilling program in the shallow primary recovery Mount Poso Field in Kern County and initiated an 18 well development drilling program in the Arroyo Grande field in San Luis Obispo County.
The Company will host a conference call to discuss the results and other forward-looking items at 10:00 a.m. Central on Thursday, August 7, 2003. Investors wishing to participate may dial 1-800-223-9488 or international: 785-832-1508. Reference Conference I.D.#: Plains XP. The replay will be available for 2 weeks at 1-800-934-2750 or international: 402-220-1142. To access the Internet webcast, please go to the Company’s website at:http://www.plainsxp.com, under the Investor Relations section choose “conference calls.” Following the live webcast, the call will be archived for a period of sixty (60) days on the Company’s website.
PXP is an independent oil and gas company primarily engaged in the upstream activities of acquiring, exploiting, developing and producing oil and gas in its core areas of operation: onshore California, primarily in the Los Angeles Basin, and offshore California in the Point Arguello unit, the Illinois Basin in southern Illinois, East Texas and the Gulf Coast region of the United States. PXP is headquartered in Houston, Texas.
ADDITIONAL INFORMATION & FORWARD LOOKING STATEMENTS
This press release includes “forward-looking statements” as defined by the Securities and Exchange Commission (“SEC”). Such statements include those concerning PXP’s strategic plans, expectations and objectives for future operations. 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:
* reliability of reserve and production estimates,
* production expense estimates,
* cash flow estimates,
* future financial performance, and
* other matters that are discussed in PXP’s filings with the SEC.
These statements are based on certain assumptions PXP made based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond PXP’s control.
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Statements regarding future production are subject to all of the risks and uncertainties normally incident to the exploration for and development and production of oil and gas. These risks include, but are not limited to, inflation or lack of availability of goods and services, environmental risks, drilling risks and regulatory changes. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements.
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Plains Exploration & Production Company
Consolidated Statements of Income
(amounts in thousands, except per share data)
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2003(1) | 2002 | 2003(1) | 2002 | |||||||||||||
Revenues | ||||||||||||||||
Oil sales | $ | 47,547 | $ | 42,537 | $ | 94,974 | $ | 81,222 | ||||||||
Gas sales | 14,677 | 2,590 | 18,781 | 4,578 | ||||||||||||
Other operating revenues | 200 | 13 | 407 | 13 | ||||||||||||
| 62,424 | 45,140 | 114,162 | 85,813 | |||||||||||||
Costs and Expenses | ||||||||||||||||
Production expenses | 22,373 | 16,649 | 42,351 | 32,754 | ||||||||||||
Production and ad valorem taxes | 1,821 | 1,204 | 2,856 | 2,328 | ||||||||||||
Gathering and transportation expenses | 327 | — | 327 | — | ||||||||||||
General and administrative | ||||||||||||||||
G&A excluding item s below | 4,561 | 2,274 | 8,757 | 4,726 | ||||||||||||
Stock appreciation rights | 4,010 | — | 2,647 | — | ||||||||||||
Merger related costs | 854 | — | 1,097 | — | ||||||||||||
Depletion, depreciation and amortization | 10,145 | 6,816 | 17,868 | 13,507 | ||||||||||||
Accretion of asset retirement obligation | 594 | — | 1,176 | — | ||||||||||||
| 44,685 | 26,943 | 77,079 | 53,315 | |||||||||||||
Income from Operations | 17,739 | 18,197 | 37,083 | 32,498 | ||||||||||||
Other Income (Expense) | ||||||||||||||||
Interest expense | (5,338 | ) | (4,726 | ) | (10,194 | ) | (9,418 | ) | ||||||||
Interest and other income (expense) | (200 | ) | 18 | (167 | ) | 36 | ||||||||||
Income Before Income Taxes and Cumulative Effect of Accounting Change | 12,201 | 13,489 | 26,722 | 23,116 | ||||||||||||
Income tax expense | (4,971 | ) | (5,271 | ) | (10,889 | ) | (9,034 | ) | ||||||||
Income Before Cumulative Effect of Accounting Change | 7,230 | 8,218 | 15,833 | 14,082 | ||||||||||||
Cumulative effect of accounting change, net of tax | — | — | 12,324 | — | ||||||||||||
Net Income | $ | 7,230 | $ | 8,218 | $ | 28,157 | $ | 14,082 | ||||||||
Earnings per Share | ||||||||||||||||
Basic | ||||||||||||||||
Income before cumulative effect of accounting change | $ | 0.25 | $ | 0.34 | $ | 0.60 | $ | 0.58 | ||||||||
Cumulative effect of accounting change | — | — | 0.47 | — | ||||||||||||
Net income | $ | 0.25 | $ | 0.34 | $ | 1.07 | $ | 0.58 | ||||||||
Diluted | ||||||||||||||||
Income before cumulative effect of accounting change | $ | 0.25 | $ | 0.34 | $ | 0.59 | $ | 0.58 | ||||||||
Cumulative effect of accounting change | — | — | 0.47 | — | ||||||||||||
Net income | $ | 0.25 | $ | 0.34 | $ | 1.06 | $ | 0.58 | ||||||||
Weighted Average Shares Outstanding | ||||||||||||||||
Basic | 28,787 | 24,200 | 26,414 | 24,200 | ||||||||||||
Diluted | 29,111 | 24,200 | 26,682 | 24,200 | ||||||||||||
| (1) | Reflects the acquisition of 3TEC Energy Corporation effective June 1, 2003. |
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Plains Exploration & Production Company
Operating Data
| Three Months Ended June 30, | Pro Forma Quarter Ended June 30, 2003 (2) | |||||||||||
| 2003(1) | 2002 | |||||||||||
Total Period Production | ||||||||||||
Oil and Liquids (MBbls ) | 2,287 | 2,080 | 2,424 | |||||||||
Gas (MMcf) | 2,745 | 842 | 6,864 | |||||||||
MBOE | 2,745 | 2,220 | 3,569 | |||||||||
Average Daily Production | ||||||||||||
Oil and Liquids (Bbls ) | 25,132 | 22,857 | 26,638 | |||||||||
Gas (Mcf) | 30,165 | 9,253 | 75,429 | |||||||||
BOE | 30,160 | 24,399 | 39,209 | |||||||||
Unit Economics (in dollars) | ||||||||||||
Average Oil & Liquids Sales Price ($/Bbl) | ||||||||||||
Average NYMEX | $ | 28.91 | $ | 26.27 | $ | 28.91 | ||||||
Hedging revenue (expense) | (3.91 | ) | (1.87 | ) | (3.65 | ) | ||||||
Differential | (4.21 | ) | (3.95 | ) | (3.95 | ) | ||||||
Net realized price | $ | 20.79 | $ | 20.45 | $ | 21.31 | ||||||
Average Gas Sales Price ($/Mcf) | ||||||||||||
Average NYMEX | $ | 5.57 | $ | 3.41 | $ | 5.57 | ||||||
Hedging revenue (expense) | (0.53 | ) | — | (0.31 | ) | |||||||
Differential | 0.31 | (0.33 | ) | (0.13 | ) | |||||||
Net realized price | $ | 5.35 | $ | 3.08 | $ | 5.13 | ||||||
Average realized price per BOE | $ | 22.67 | $ | 20.33 | $ | 24.34 | ||||||
Production expenses per BOE | (8.15 | ) | (7.50 | ) | (7.09 | ) | ||||||
Production and ad valorem taxes per BOE | (0.66 | ) | (0.54 | ) | (0.85 | ) | ||||||
Gathering and transportation per BOE | (0.12 | ) | — | (0.29 | ) | |||||||
Gross margin per BOE | 13.74 | 12.29 | 16.11 | |||||||||
G&A per BOE | ||||||||||||
G&A excluding items below | (1.66 | ) | (1.02 | ) | (1.76 | ) | ||||||
Stock appreciation rights | (1.46 | ) | — | (1.12 | ) | |||||||
Merger related costs | (0.31 | ) | — | (0.24 | ) | |||||||
Gross profit per BOE | $ | 10.31 | $ | 11.27 | $ | 12.99 | ||||||
| (1) | Reflects the acquisition of 3TEC Energy Corporation effective June 1, 2003. |
| (2) | Pro forma information shows the pro forma effects of the acquisition of 3TEC Energy Corporation as if the acquisition took place on January 1, 2003. 3TEC held certain derivative instruments that they elected not to qualify for hedge accounting under the provisions of SFAS 133. Accordingly, the realized and unrealized gains and losses with respect to such derivatives were recognized currently in 3TEC’s results of operations. At the time of the acquisition, the derivative instruments were assigned to us and were qualified for hedge accounting. The amounts presented for Hedging revenue (expense) include the realized gains or losses related to the 3TEC derivatives as if they had been qualified for hedge accounting. Oil hedging revenue (expense) includes $0.04 per Bbl related to such derivatives and gas hedging revenue (expense) includes ($0.09) per Mcf related to such derivatives. |
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Plains Exploration & Production Company
Operating Data
| Six Months Ended June 30, | Pro Forma Six Months Ended June 30, 2003 (2) | |||||||||||
| 2003(1) | 2002 | |||||||||||
Total Period Production | ||||||||||||
Oil and Liquids (MBbls ) | 4,468 | 4,113 | 4,810 | |||||||||
Gas (MMcf) | 3,474 | 1,719 | 13,855 | |||||||||
MBOE | 5,047 | 4,400 | 7,119 | |||||||||
Average Daily Production | ||||||||||||
Oil and Liquids (Bbls ) | 24,685 | 22,724 | 26,575 | |||||||||
Gas (Mcf) | 19,193 | 9,497 | 76,546 | |||||||||
BOE | 27,884 | 24,307 | 39,333 | |||||||||
Unit Economics (in dollars) | ||||||||||||
Average Oil & Liquids Sales Price ($/Bbl) | ||||||||||||
Average NYMEX | $ | 31.32 | $ | 24.02 | $ | 31.32 | ||||||
Hedging revenue (expense) | (5.88 | ) | (0.11 | ) | (5.46 | ) | ||||||
Differential | (4.18 | ) | (4.16 | ) | (3.95 | ) | ||||||
Net realized price | $ | 21.26 | $ | 19.75 | $ | 21.91 | ||||||
Average Gas Sales Price ($/Mcf) | ||||||||||||
Average NYMEX | $ | 5.63 | $ | 2.93 | $ | 5.63 | ||||||
Hedging revenue (expense) | (0.42 | ) | — | (1.23 | ) | |||||||
Differential | 0.20 | (0.27 | ) | 0.39 | ||||||||
Net realized price | $ | 5.41 | $ | 2.66 | $ | 4.79 | ||||||
Average realized price per BOE | $ | 22.54 | $ | 19.50 | $ | 24.12 | ||||||
Production expenses per BOE | (8.39 | ) | (7.44 | ) | (6.93 | ) | ||||||
Production and ad valorem taxes per BOE | (0.57 | ) | (0.53 | ) | (0.96 | ) | ||||||
Gathering and transportation per BOE | (0.06 | ) | — | (0.30 | ) | |||||||
Gross margin per BOE | 13.52 | 11.53 | 15.93 | |||||||||
G&A per BOE | ||||||||||||
G&A excluding items below | (1.74 | ) | (1.07 | ) | (1.81 | ) | ||||||
Stock appreciation rights | (0.52 | ) | — | (0.37 | ) | |||||||
Merger related costs | (0.22 | ) | — | (0.15 | ) | |||||||
Gross profit per BOE | $ | 11.04 | $ | 10.46 | $ | 13.60 | ||||||
| (1) | Reflects the acquisition of 3TEC Energy Corporation effective June 1, 2003. |
| (2) | Pro forma information shows the pro forma effects of the acquisition of 3TEC Energy Corporation as if the acquisition took place on January 1, 2003. 3TEC held certain derivative instruments that they elected not to qualify for hedge accounting under the provisions of SFAS 133. Accordingly, the realized and unrealized gains and losses with respect to such derivatives were recognized currently in 3TEC’s results of operations. At the time of the acquisition, the derivative instruments were assigned to us and were qualified for hedge accounting. The amounts presented for Hedging revenue (expense) include the realized gains or losses related to the 3TEC derivatives as if they had been qualified for hedge accounting. Gas hedging revenue (expense) includes ($1.12) per Mcf related to such derivatives. |
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Plains Exploration & Production Company
Consolidated Balance Sheets
(thousands of dollars)
| June 30, 2003 | December 31, 2002 | |||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 3,466 | $ | 1,028 | ||||
Accounts receivable | 43,283 | 28,868 | ||||||
Commodity hedging contracts | 1,675 | 2,594 | ||||||
Inventories | 7,706 | 5,198 | ||||||
Other current assets | 8,215 | 1,051 | ||||||
| 64,345 | 38,739 | |||||||
Properties and Equipment | ||||||||
Oil and natural gas properties—full cost method | 1,063,471 | 659,499 | ||||||
Other property and equipment | 3,165 | 2,207 | ||||||
| 1,066,636 | 661,706 | |||||||
Less—accumulated depletion, depreciation and amortization | (154,996 | ) | (168,494 | ) | ||||
| 911,640 | 493,212 | |||||||
Goodwill | 143,961 | — | ||||||
Other Assets | 18,616 | 18,929 | ||||||
| $ | 1,138,562 | $ | 550,880 | |||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current Liabilities | ||||||||
Accounts payable and other current liabilities | $ | 99,554 | $ | 61,092 | ||||
Commodity hedging contracts | 39,748 | 24,572 | ||||||
Current maturities of long-term debt | 511 | 511 | ||||||
| 139,813 | 86,175 | |||||||
Long-Term Debt | 510,502 | 233,166 | ||||||
Asset Retirement Obligation | 31,411 | — | ||||||
Other Long-Term Liabilities | 17,577 | 6,303 | ||||||
Deferred Income Taxes | 99,226 | 51,416 | ||||||
Stockholders’ Equity | ||||||||
Common stock | 405 | 244 | ||||||
Additional paid-in capital | 327,705 | 174,279 | ||||||
Retained earnings | 40,312 | 12,155 | ||||||
Accumulated other comprehensive income | (28,389 | ) | (12,858 | ) | ||||
| 340,033 | 173,820 | |||||||
| $ | 1,138,562 | $ | 550,880 | |||||
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