EX-99 3 f8k-earnings1q03ex991.htm EXHIBIT 99.1 - PRESS RELEASE Exhibit 99.1

Exhibit 99.1

STONE ENERGY CORPORATION

Announces 773% Growth in Comparable Quarterly Earnings and Deep Gas Discovery in Coastal Louisiana Waters

NYSE — SGY
LAFAYETTE, LA. May 7, 2003

Stone Energy Corporation today announced that relative to the first quarter of 2002, first quarter 2003 income increased 773% benefiting from higher realized oil and gas prices. Income before the cumulative effects of accounting changes totaled a record $54.6 million, or $2.06 per share for the first quarter of 2003 compared to first quarter 2002 net income of $6.3 million, or $0.24 per share. Including the cumulative effects of accounting changes, net income for the first quarter of 2003 totaled $55.9 million, or $2.11 per share, and exceeded full-year 2002 net income of $55.4 million, or $2.09 per share. All per share amounts are on a diluted basis.

Discretionary cash flow increased 140% to a record $129.7 million during the first quarter of 2003, compared to $54.1 million during the first quarter of 2002. Net cash flow provided by operating activities, as defined by generally accepted accounting principles (GAAP), totaled $109.3 million during the first quarter of 2003, compared to $53.9 million in the first quarter of 2002. (Please see the accompanying financial statements for a reconciliation of discretionary cash flow, a non-GAAP financial measure, to net cash flow provided by operating activities.)

As a result of higher realized prices, first quarter 2003 oil and gas revenue increased 96% to a quarterly record of $157.5 million, compared to first quarter 2002 oil and gas revenue of $80.5 million. Prices realized during the first quarter of 2003 averaged $33.53 per barrel of oil and $6.66 per Mcf of gas versus first quarter 2002 average realized prices of $20.97 per barrel of oil and $2.76 per Mcf of gas, representing a 108% increase in realized oil and gas prices on a thousand cubic feet of gas equivalent basis (Mcfe). All unit pricing amounts include the cash effects of hedging.

Average daily production for the first quarter of 2003 increased 6% over fourth quarter 2002 to 278.1 MMcfe. Oil production during the first quarter of 2003 totaled approximately 1,419,000 barrels compared to fourth quarter 2002 oil production of approximately 1,438,000 barrels and first quarter 2002 oil production of approximately 1,618,000 barrels, while natural gas production during the first quarter of 2003 totaled approximately 16.5 billion cubic feet, compared to fourth quarter 2002 natural gas production of approximately 15.5 billion cubic feet and first quarter 2002 natural gas production of approximately 16.9 billion cubic feet.

Normal lease operating expenses during the first quarter of 2003 totaled $15.0 million, or $0.60 per Mcfe, compared to $14.6 million, or $0.55 per Mcfe, for the first quarter of 2002. On a sequential basis, per unit normal lease operating expenses decreased from $0.62 per Mcfe incurred in the fourth quarter of 2002.

Effective January 1, 2003, management elected to change to the Units of Production (UOP) method of amortizing proved oil and gas property costs versus the formerly used Future Gross Revenue (FGR) method. Under the UOP method, the quarterly provision for depreciation, depletion and amortization (DD&A) is computed by dividing production volumes for the period by total proved reserves, and applying the respective rate to the net cost of proved oil and gas properties, including future development costs. Under the FGR method, the DD&A rate was calculated by dividing revenue for the period by future gross revenue. The cumulative effect of the change in accounting principle was $4.0 million, net of tax, and was recorded as a non-cash charge during the first quarter of 2003.

DD&A expense on oil and gas properties under the UOP method for the first quarter of 2003 totaled $41.0 million, or $1.64 per Mcfe. DD&A expense under the FGR method was $40.2 million, or $1.51 per Mcfe, for the first quarter of 2002. Under the UOP method, DD&A expense would have been $40.4 million, or $1.52 per Mcfe, during the first quarter of 2002, and $40.9 million, or $1.69 per Mcfe, during the fourth quarter of 2002.

In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 143, “Accounting for Asset Retirement Obligations,” effective for fiscal years beginning after June 15, 2002. This statement requires us to record our estimate of the fair value of liabilities related to future asset retirement obligations in the period the obligation is incurred. The adoption of SFAS No. 143 requires the use of management’s estimates with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of capital.

We adopted SFAS No. 143 on January 1, 2003. Upon adoption, we recognized a credit for a cumulative transition adjustment of $5.3 million, net of tax, for existing asset retirement obligation liabilities, asset retirement costs and accumulated depreciation. In addition, we recorded a $32.1 million increase in the capitalized costs of our oil and gas properties, net of accumulated depreciation, and recognized $76.3 million in additional liabilities related to asset retirement obligations. During the first quarter of 2003, we recognized a non-cash expense of $1.6 million related to the accretion of our asset retirement obligation in accordance with SFAS No. 143. As required by SFAS No. 143, our estimate of our asset retirement obligation does not give consideration to the value that the related assets could have to other parties.

General and administrative expenses for the first quarter of 2003 were $3.3 million, or $0.13 per Mcfe, compared to $3.4 million, or $0.13 per Mcfe, in the first quarter of 2002. Due to Stone’s financial and operational results, incentive compensation expense increased to $0.7 million during the first quarter of 2003 compared to $0.2 million incurred during the first quarter of 2002.

Stone entered into additional natural gas hedges during January 2003 under fixed-price swap contracts for its Rocky Mountain production based upon Inside FERC published prices for deliveries at Kern River and put contracts for its Gulf Coast Basin production. The swap contracts effectively hedge 10,000 million British Thermal Units (“MMBtu”) per day of Rocky Mountain production at a swap price of $3.68 per MMBtu from April 2003 until December 2003 and 15,000 MMBtu per day at a swap price of $3.42 per MMBtu from January 2004 until December 2005. The put contracts effectively hedge an additional 25,000 MMBtu per day of Gulf Coast Basin production with a floor price of $3.50 per MMBtu from March 2003 until December 2003. The put contracts’ cost of approximately $0.5 million will be charged to earnings as the contracts settle.

During the first quarter of 2003, we recognized non-cash expenses of $2.2 million relative to commodity derivatives, $1.2 million of which represents the cost of natural gas put contracts that settled during the period. For the three months ended March 31, 2002, we recognized $5.0 million of non-cash expenses related to derivatives, of which $2.1 million related to the cost of put contracts that settled during the period.

During the first quarter of 2003, we repaid $20 million of borrowings under our bank credit facility. We have a borrowing base under the bank credit facility of $300 million, with availability of an additional $175.9 million of borrowings as of May 5, 2003.

Stone Energy’s 2003 capital expenditures budget, excluding acquisitions, is currently $240 million. First quarter 2003 additions to oil and gas property costs of $119.1 million included $52.0 million of asset retirement costs recorded in connection with the adoption of SFAS No. 143. Capital expenditures during the first quarter of 2003 totaled $67.1 million, including $14.3 million of acquisition costs, $3.5 million of capitalized general and administrative expenses and $2.0 million of capitalized interest. These investments were financed by cash flow from operations and working capital.

Operational Update Includes Deep Gas Discovery

With this press release we are announcing the discovery of deep gas on our Seagull Prospect on South Timbalier Block 8. This is the third consecutive deep gas discovery we have announced this year from our Deep Shelf Exploratory Program that includes nine scheduled tests for 2003.

During the first quarter of 2003, Stone drilled nine successful wells and one dry hole resulting in a 90% drilling success rate. Stone has spudded seven wells during the second quarter of 2003 with two discoveries and five wells currently drilling. Through May 5, 2003, Stone has spudded 16 of the 52 wells planned for 2003. The following is an update of certain ongoing operations:

Gulf Coast Basin

Gulf of Mexico — Louisiana State Waters:

South Timbalier Block 8. The State Lease No. 4237 No. 3 Well drilled on the Seagull Prospect to a total depth of 16,142 feet and encountered 148 net feet of gas pay in five zones. Evaluation of the well, which was drilled adjacent to a producing complex, is in progress. We expect to have the well completed and on production by mid-June 2003. Three of the five productive sands are stratigraphically deeper than previously established producing reservoirs in the field. Stone interprets the deep sands to be deposited against the flanks of the structures that support the established gas accumulation in the field. Stone has a 100% working interest (WI) and a 79.5% net revenue interest (NRI) in this well.

Gulf of Mexico — Federal Waters:

South Pelto Block 22. As previously announced, the South Pelto Block 22 OCS-G 18054 No. 2 Well drilled to a total depth of 18,869 feet on the Can of Corn Prospect and logged 524 net feet of pay in 11 sands before casing was run to total depth. We believe this is a significant discovery that will require two to five additional wells to fully develop the reserves found to date as well as to evaluate untested fault traps on the deep structure. The operator is evaluating options to produce the property including waiting until the second well is drilled to make the determination. The rig is expected to return to the property late in the second quarter or beginning of the third quarter to begin a multi-well program. The second well is planned to be directionally drilled from a surface location approximately 2,000 feet southwest of the surface location of the discovery well. This well is planned to test approximately 1,000 feet of section beneath the sands found productive in the discovery well. While the operator is still working toward a firm evaluation and development program for the discovery, we have budgeted the second and third wells to be drilled and all three wells to be completed during 2003. Stone has a 50% WI and a 40.7% NRI in the No. 2 Well and the planned No. 3 Well.

South Pelto Block 23. Drilling operations are in progress on the Hammerhead Prospect on the south flank of the deep structure. The OCS-G 1238 No. C-4 Well is drilling below 2,400 feet toward a planned total depth of 19,133 feet. The objectives are field pay sands in an untested fault trap associated with the large regional fault that traps gas accumulation in the recently announced discovery on South Pelto Block 22. Stone has a 100% WI and an 80.9% NRI in the C-4 Well.

East Cameron Block 378. Drilling is complete and casing run to total depth of 14,467 feet on the East Cameron Block 378 OCS-G 12856 No. 4 BP-4 Well on the Canvasback Prospect. As earlier reported, the well found gas in two sands including a deep sand objective that was seismic amplitude indicated. A subsea completion and tieback is planned for this well, first production is expected in the first quarter of 2004 and we are awaiting further guidance from the operator as to the timing of additional drilling. Stone has a 57% WI and a 42% NRI in this well.

Main Pass Block 287. We are drilling the second well of a multi-well drilling program to evaluate prospects on two previously undrilled primary term leaseblocks: MP Block 287 and MP Block 276. The Main Pass Block 287 OCS-G 19869 No. 1 Well, our initial test on the John Quincy Prospect, was drilled directionally from an open water location to a total depth of 8,778 feet. The well encountered 53 net feet of oil and gas pay in four zones with the principal accumulation found to be 30 net feet of oil in the primary objective 6,000 foot sand. Casing was run to total depth and operations on the well suspended pending the outcome of additional drilling to test separate prospects.

From the same surface location, operations are in progress on the North Polk Prospect where the OCS-G 19866 No. 1 Well is drilling beneath 7,250 feet toward a planned total depth of 9,100 feet on Main Pass Block 276. Following the drilling of the second well, we plan to drill a third well to approximately 8,900 feet to test the same objective reservoirs on the Polk Prospect on Main Pass Block 287.

Dependent on the results of the drilling program, we plan to install a four pile structure and pipeline to tie back production to our A platform on MP Block 288, with estimated first production to begin by the first quarter of 2004. Stone has a 100% WI and 78.3% NRI in Main Pass Block 276 and a 100% WI and 81.3% NRI in Main Pass Block 287.

South Marsh Island Block 288. Construction of a new pipeline was completed during the first quarter to allow additional production from recent new wells to come on line. In addition to an increase of daily production from the property of approximately 3.8 MMcfe net to Stone, the pipeline provides additional daily capacity of approximately 28.1 MMcfe for wells planned to be drilled during 2003. A rig is scheduled to arrive on the block during June for a multi-well drilling program. Two wells are currently approved, both to be drilled from existing platforms to depths between 16,500 and 17,000 feet. These wells are targeting field pay sands in untested fault blocks. Stone has a 50% WI and a 41.7% NRI in the field.

East Cameron Block 44. Drilling operations are in progress on the OCS-G 19730 No. 1 Well on the Palomino Prospect. The well is planned to a total depth of 14,846 feet to test geopressured sands in one of multiple traps under lease. Stone has a 33.3% WI and 27% NRI in this well.

Eugene Island Block 243. The OCS-G 2899 B-4 Well was drilled to 2,214 feet and completed as a horizontal well across 872 net feet of gas productive section. The well began producing on March 7 and is flowing at an average gross daily rate of 2.5 MMcf. Stone has a 91% WI and a 72.7% NRI in this well.

Vermilion Block 83. The OCS G 19756 No. 4 Well was drilled to total depth of 11,676 feet on the Captain Prospect and was plugged and abandoned as non-commercial. Stone had a 66.7% WI in this well.

Onshore Louisiana:

Lafitte Field – Jefferson Parish. Stone completed a three well drilling program at Lafitte Field in Jefferson Parish, Louisiana, during the first quarter of 2003. All of the wells are completed and on production at a combined gross daily rate of 290 barrels of oil and 525 Mcf of gas (867 Mcfe per day net to Stone). Stone has an approximate 51% WI and 38.3% NRI in the three wells.

Cut Off Field – Lafourche Parish. Drilling is in progress on the south flank of the field on the Sequoia Prospect. The Clovelly No. 37 Well is drilling toward a planned total depth of 17,500 feet. Stone has a 100% WI and an 80% NRI in the well.

Rocky Mountain Basin

Pinedale Anticline, Wyoming. We plan to drill eight wells on the Pinedale Anticline structure during 2003. The Antelope 5-4 Well, the third well under our previously announced commitment on the structure, was drilled to a total depth of 13,995 feet, completed, and is producing at a gross daily rate of 2.5 MMcf. Drilling is in progress below 10,000 feet on the Rainbow No. 15-32 well to a proposed total depth of 14,000 feet. A second drilling rig has moved into the field to spud the Rainbow 10-32 Well, a 14,010 foot test, to accelerate production rates and reserve development and to complete Stone’s drilling and investment commitments during 2003. Stone’s WI during the commitment (“earning”) phase is 100% of costs through completion for a 50% WI and an approximate 40% NRI in all production. After the commitment phase, Stone will have a 50% WI and an approximate 40% NRI in all wells.

Jonah Field, Wyoming. The Stud Horse Butte No. 7-28 drilled to a total depth of 11,129 feet and encountered 357 net feet gas pay in the Cretaceous age Lance formation. The well is producing from multiple frac stages at a combined gross daily rate of 7.2 MMcfe. Stone has an approximate 30% WI and 24% NRI in the well.

Other Information

In this press release, we refer to a non-GAAP financial measure we call discretionary cash flow because of management’s belief that this measure is a financial indicator of our company’s ability to internally fund capital expenditures and service debt. Management also believes that this non-GAAP financial measure of cash flow is useful information to investors because it is widely used by professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. Many investors use the published research of these analysts in making their investment decisions. Discretionary cash flow should not be considered an alternative to net cash provided by operating activities or net income, as defined by GAAP.

Stone Energy has planned a conference call for 3:00 p.m. CDT on Thursday, May 8, 2003 to discuss the operational and financial results for the first quarter of 2003. Anyone wishing to participate should visit our website at www.StoneEnergy.com for a live webcast or dial 1-877-228-3598 and request the “Stone Energy Call.” If you are unable to participate in the original conference call, a replay will be available immediately following the completion of the call on Stone Energy’s web page at www.StoneEnergy.com. The replay will be available for approximately one week.

Stone Energy is an independent oil and gas company headquartered in Lafayette, Louisiana, and is engaged in the acquisition and subsequent exploitation, development and operation of oil and gas properties located in the Gulf Coast Basin and Rocky Mountains. For additional information, contact James H. Prince, chief financial officer at 337-237-0410-phone, 337-237-0426-fax or via e-mail at princejh@StoneEnergy.com.

Certain statements in this press release are forward-looking and are based upon Stone’s current belief as to the outcome and timing of future events. All statements, other than statements of historical facts, that address activities that Stone plans, expects, believes, projects, estimates or anticipates will, should or may occur in the future, including future production of oil and gas, future capital expenditures and drilling of wells and future financial or operating results are forward-looking statements. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and gas, operating risks and other risk factors as described in Stone’s Annual Report on Form 10-K as filed with the Securities and Exchange Commission. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, Stone’s actual results and plans could differ materially from those expressed in the forward-looking statements.

STONE ENERGY CORPORATION SUMMARY STATISTICS
(In thousands, except per share/unit amounts) (Unaudited)
		Three Months Ended March 31,
		2003	2002
FINANCIAL RESULTS
	Income before cumulative adjustments (1)	$54,633	$6,256
	Income before cumulative adjustments per share (1)	$2.06	$0.24

	Net income	$55,858	$6,256
	Net income per share	$2.11	$0.24

PRODUCTION QUANTITIES
	Oil (MBbls)	1,419	1,618
	Gas (MMcf)	16,516	16,877
	Oil and gas (MMcfe)	25,030	26,585

AVERAGE DAILY PRODUCTION
	Oil (MBbls)	15.8	18.0
	Gas (MMcf)	183.5	187.5
	Oil and gas (MMcfe)	278.1	295.4

SALES DATA (2)
	Total oil sales	$47,572	$33,931
	Total gas sales	109,974	46,599
	Total oil and gas sales	157,546	80,530

AVERAGE SALES PRICES (2)
	Oil (per Bbl)	$33.53	$20.97
	Gas (per Mcf)	6.66	2.76
	Per Mcfe	6.29	3.03

COST DATA
	Normal lease operating expenses	$15,025	$14,613
	Major maintenance expenses	2,701	1,289
	General and administrative expenses	3,335	3,400
	DD&A expense on oil and gas properties	40,959	40,163

AVERAGE COSTS (Per Mcfe)
	Normal lease operating expenses	$0.60	$0.55
	Major maintenance expenses	0.11	0.05
	General and administrative expenses	0.13	0.13
	DD&A expense on oil and gas properties	1.64	1.51

AVERAGE SHARES OUTSTANDING – Diluted		26,489	26,447

(1) Excludes the cumulative effects of adoption of and change in accounting principles.
(2) Includes the cash effects of hedging.

STONE ENERGY CORPORATION CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands) (Unaudited)
		Three Months Ended March 31,
		2003		2002
STATEMENT OF OPERATIONS
Operating revenue:
	Oil production	$47,572		$33,931
	Gas production	109,974		46,599
	Total operating revenue	157,546		80,530
Operating expenses:
	Normal lease operating expenses	15,025		14,613
	Major maintenance expenses	2,701		1,289
	Production taxes	1,459		1,070
	Depreciation, depletion and amortization	41,719		40,749
	Non-cash accretion expense	1,573		-
	General and administrative expenses	3,335		3,400
	Incentive compensation expense	660		188
	Non-cash derivative expenses	2,173		5,021
	Total operating expenses	68,645		66,330
Income from operations		88,901		14,200
Other (income) expenses:
	Interest	5,521		5,454
	Other income	(671	)	(878	)
	Total other expenses	4,850		4,576
Income before income taxes		84,051		9,624
Provision for income taxes:
	Current	-		-
	Deferred	29,418		3,368
	Total income taxes	29,418		3,368
Income before cumulative effects of adoption of and change in accounting principles, net of tax		54,633		6,256
	Cumulative effect of adoption of new accounting principle	5,256		-
	Cumulative effect of change in accounting principle	(4,031	)	-
Net income		$55,858		$6,256
NET CASH FLOW INFORMATION
Reconciliation of non-GAAP financial measure:
	Discretionary cash flow	$129,702		$54,062

	Net working capital changes and other	(19,890	)	(176	)
	Investment in derivative contracts	(516	)	-
	Net cash flow provided by operating activities – GAAP	$109,296		$53,886

STONE ENERGY CORPORATION CONSOLIDATED BALANCE SHEET (In thousands)
	March 31, 2003		December 31, 2002
Assets	(Unaudited)
Current assets:
Cash and cash equivalents	$35,388		$27,609
Accounts receivable	107,396		74,800
Fair value of put contracts	328		859
Other current assets	2,862		3,601
Total current assets	145,974		106,869
Oil and gas properties:
Proved, net	1,035,237		940,463
Unevaluated	117,039		107,473
Building and land, net	5,203		5,238
Fixed assets, net	5,248		5,452
Other assets, net	11,149		13,876
Total assets	$1,319,850		$1,179,371
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable to vendors	$55,481		$72,012
Undistributed oil and gas proceeds	39,051		29,027
Fair value of swap contracts	2,625		-
Other accrued liabilities	9,074		7,043
Total current liabilities	106,231		108,082

8¼% Senior Subordinated Notes due 2011	200,000		200,000
8¾% Senior Subordinated Notes due 2007	100,000		100,000
Bank debt	111,000		131,000
Deferred taxes	88,978		59,604
Fair value of swap contracts	2,490		-
Asset retirement obligation	76,968		-
Other long-term liabilities	3,124		3,197
Total liabilities	688,791		601,883
Common stock	263		263
Additional paid-in capital	453,384		453,176
Retained earnings	186,323		130,523
Treasury stock	(1,550	)	(1,706	)
Accumulated other comprehensive income (loss)	(7,361	)	(4,768	)
Total stockholders' equity	631,059		577,488
Total liabilities and stockholders' equity	$1,319,850		$1,179,371