Stone Energy today reported its 2001 year-end reserves and preliminary
results of its 2001 capital expenditures program. With new reserves of 464.5
Bcfe and utilizing estimated production, before adjustment for the volumetric
production payment, Stone increased pre-merger reserves by 94% and reserves per
share by 37% at a total estimated cost of $2.05 per Mcfe. The reserve volumes
were based upon the recently completed independent engineering reports of its
estimated proved oil and gas reserves dated as of December 31, 2001. All cost
and production information are based on preliminary estimates subject to Stone's
annual audit of its financial statements.
2001 Year-End Proved Reserve Estimates
The following table includes proved reserve data at December 31, 2001 and
2000. Proved reserve data at December 31, 2000 is shown before and after the
impact of Stone's February 1, 2001 merger, which was accounted for as a
pooling-of-interests. The oil and gas prices used in the preparation of the
reports for both years were based upon the rules and regulations of the
Securities and Exchange Commission ("SEC") and accordingly do not reflect the
impact of hedges in place.
December 31,
-------------------------------------------------------
2000
-------------------------------------
2001 Post-Merger Pre-Merger
-------------- ---------------- ----------------
Total estimated proved reserves in
equivalent cubic feet of gas (Bcfe) 775.0 600.3 400.2
Estimated proved oil reserves (MMBbls) 55.4 33.6 21.3
Estimated proved gas reserves (Bcf) 442.7 398.5 272.2
Present value of estimated future
pre-tax net cash flows @ 10%
annual discount ($MM) $1,038.8 $2,941.8 $2,029.4
Future capital expenditures ($MM) $285.6 $249.6 $159.3
Average oil price at end of period ($/Bbl) $18.64 $27.30 $28.01
Average gas price at end of period ($/Mcf) $2.79 $9.97 $10.13
Independent petroleum consultants prepared the reserve estimates presented
above in accordance with the guidelines established by the SEC. The adherence to
these guidelines limits the booking of proved reserves on successfully drilled
wells to the extent of the base of known productive sands. Actual limits of the
productive sands will ultimately be determined through production or additional
drilling.
At December 31, 2001, 94% of Stone's estimated proved reserves were located
in the Gulf Coast Basin and 6% were located in the Rocky Mountains, after a
negative revision of 13.6 Bcfe of proved reserves due to low year-end prices. On
a post-merger basis, estimated proved reserves were split 89% in the Gulf Coast
Basin and 11% in the Rocky Mountains at year-end 2000.
Estimated Production
Stone's estimated production during 2001 totaled 4.0 million barrels of oil
and 68.2 billion cubic feet ("Bcf") of gas or a total of approximately 92.4 Bcfe
(89.7 Bcfe before accounting for the volumetric production payment), a 39%
increase as compared to pre-merger 2000 production of 66.5 Bcfe. Estimated
production during 2001 was derived 96% from the Gulf Coast Basin and 4% from the
Rocky Mountains. Based on the independently engineered estimates of proved
reserves, and our preliminary estimate of production, Stone's reserve
replacement ratio for 2001 was 295% using post-merger 2000 reserves and 518% on
a pre-merger basis.
We believe that our average daily production rate for the first quarter of
2002 will be 295-305 MMcfe, or approximately 18% higher than 2001's average
daily rate. The Conoco property acquisition closed December 31, 2001. Our first
quarter 2002 estimate includes associated production volumes from the Conoco
properties, as well as estimated production from one well at South Pass Block 38
and four wells from our Indigo Project at Vermilion Block 255.
Estimated Costs
For 2001, we had an overall estimated finding cost of $2.05 per Mcfe of
proved reserves, as shown by the following table:
Estimated Cost Estimated
Volumes (Bcfe) ($MM) Cost per Mcfe
---------------- ---------------- ----------------
Proved reserves pre-merger December 31, 2000 (1) 400.2
Proved reserves added through merger (2) 200.1 $366.1 $1.83
Proved reserves added through acquisitions (3) 208.5 249.7 1.20
Proved reserves added through capital expenditures:
Drilling 71.7 250.7 3.50
Facilities - 42.6
Seismic/other (4) - 41.0
---------------- ---------------- ----------------
Total 71.7 334.3 4.66
Proved reserve revisions during 2001 (5) (15.8) -
---------------- ----------------
TOTAL FOR 2001 464.5 $950.1 $2.05
Proved reserves produced during 2001 (6) (89.7)
----------------
Proved reserves December 31, 2001 (1) 775.0
================
(1) Excludes 4 Bcf and 1.3 Bcf at December 31, 2000 and 2001,
respectively, related to volumetric production payment
(2) Cost computed as 7.4 million shares at year-end 2001 stock price of
$39.50/share plus $48 million in debt assumed and $25.8 million in
merger expenses
(3) Excludes $63.2 million of estimated costs allocated to unevaluated
properties
(4) Includes $5.6 million of net estimated costs transferred from 2000
unevaluated costs
(5) Includes 13.6 Bcfe writedown of Rocky Mountain long-life reserves due
to low year-end prices
(6) Excludes 2.7 Bcfe related to volumetric production payment
During 2001, we drilled 42 gross exploratory wells representing 73% of our
total estimated drilling expenditures. Approximately half of the proved reserves
added through the drillbit during 2001 were derived from properties acquired in
the merger. We achieved a 52% exploratory drilling success rate and found
substantially less reserves at higher costs than we internally forecasted in our
pre-drill modeling. Our exploratory drilling results, when combined with the
results from the 21 development wells drilled, resulted in a composite drilling
success rate of 67% during 2001.
During 2001, we experienced significant increases in drilling and service
costs and rig utilization rates. As the demand for drilling rigs and services
grew, the availability of experienced service company personnel diminished. The
combination of these factors and our exploratory drilling results contributed to
our high 2001 finding cost.
During 2001, Stone built and installed production platforms and facilities
on a number of properties. Additional drilling opportunities from the new
structures have been identified, which we believe should benefit future finding
costs. The 2001 capital expenditures program also included the acquisition of a
substantial volume of new seismic data. A portion of the data purchased during
2001 was utilized in evaluating the property acquisition from Conoco. We believe
that this data should provide future benefits in locating prospects on our
existing properties and evaluating future acquisition opportunities.
2002 Capital Expenditures Budget
Stone's 2002 capital expenditures budget is approximately $200 million with
which we plan to drill approximately 50 gross wells with an investment of
approximately $140 million. A majority of the 2002 budgeted wells are
development wells. We have lowered budgeted expenditures and the number of wells
planned for 2002 because of lower commodity price expectations and our intent to
finance the capital expenditures budget with operating cash flow.
Currently, 95% of our capital expenditures budget is allocated to Gulf
Coast Basin operations, including approximately $35 million earmarked for
exploitation of the recently acquired Conoco properties. Approximately $50
million is expected to be invested in workovers, recompletions and the
development of proved reserves. Consistent with our budgeting practices, the
2002 capital expenditures budget excludes acquisition costs. We continue to
evaluate opportunities that fit our specific acquisition profile.
Hedges
The following table summarizes Stone's hedge positions at January 1, 2002:
Gas Puts Oil Puts
------------------------- ----------------------
MMbtu/d Floor Bbls/d Floor
-------------- -------- ---------- --------
2002 60,000 $3.50 3,500 $24.00
Gas Swaps
------------------------------------------------
MMbtu/d Price
--------------------- -----------------------
2002 10,000 $2.15
2003 10,000 2.15
The 2002 hedged volumes represent approximately 30% of Stone's estimated
first quarter 2002 daily production volumes on a gas equivalent basis. The gas
swap contracts above are with a subsidiary of Enron Corp. while the put
contracts are with parties not related to Enron Corp. As of February 12, 2002,
the gas swap contracts were valued as a net liability due an Enron subsidiary
totaling $4.7 million. Depending on fluctuations in gas prices, these contracts
may create a receivable owed to us from Enron's subsidiary. Based on Enron
Corp.'s financial difficulties, there is no assurance that we will receive full
or partial payment of any amount that may become owed to us under these
contracts.
Conference Call
Stone has planned a conference call for 3:00 p.m. C.S.T February 14, 2002
to discuss the information in this release. Participants should dial
1-800-213-1352 and request the "Stone Energy Call". If you are unable to
participate in the original conference call, a rebroadcast will be available for
24 hours beginning at 5:00 p.m. C.S.T. To access the replay, dial 1-800-633-8284
and request reservation number 20347864. After the 24-hour replay period has
elapsed, you may listen to a replay of the call on Stone Energy's web page at
www.StoneEnergy.com for a period of approximately one week.
Stone Energy is an independent oil and gas company headquartered in
Lafayette, Louisiana, and is engaged in the acquisition, 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 Energy'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 Energy 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 Energy'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
Energy's actual results and plans could differ materially from those expressed
in the forward-looking statements.