UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d)
THE SECURITIES EXCHANGE ACT OF 1934
DATE OF REPORT (DATE OF EARLIEST EVENT REPORTED): September 19, 2001
STONE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 1-12074 72-1235413
(State or other jurisdiction (Commission File (I.R.S. employer
of incorporation or organization) Number) identification no.)
625 E. Kaliste Saloom Road
Lafayette, Louisiana 70508
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (337) 237-0410
ITEM 5. OTHER EVENTS
On February 1, 2001, Stone Energy Corporation ("Stone") and Basin
Exploration, Inc. ("Basin") completed their merger. The merger was accounted for
under the pooling-of-interests method of accounting for business combinations.
Accordingly, we have combined the two companies' historical financial and
operating data as though they had been combined at the beginning of the earliest
period presented.
Presented on the following pages are certain financial disclosures that
would have been included in Stone's year-end 2000 Annual Report on Form 10-K had
the Basin merger been completed prior to the end of 2000. These combined results
should be used for information purposes only as they are not necessarily
indicative of the results that would have occurred if the merger had been
completed at the beginning of the earliest period presented.
TABLE OF CONTENTS
Page
Selected Financial Data........................................... 1
Management's Discussion and Analysis of Financial
Condition and Results of Operations.............................. 2
Quantitative and Qualitative Disclosures About Market Risk........ 8
Independent Auditors' Report...................................... 11
Consolidated Financial Statements:
Consolidated Balance Sheet - December 31, 2000 and 1999...... 12
Consolidated Statement of Operations -
Years Ended December 31, 2000, 1999 and 1998............ 13
Consolidated Statement of Cash Flows -
Years Ended December 31, 2000, 1999 and 1998............ 14
Consolidated Statement of Changes in Stockholders' Equity -
Years Ended December 31, 2000, 1999 and 1998............ 15
Notes to Consolidated Financial Statements................... 16
SELECTED FINANCIAL DATA
-----------------------
The following table sets forth a summary of selected financial information
for each of the years in the five-year period ended December 31, 2000. All
information presented gives retroactive effect to the merger of Stone and Basin,
which has been accounted for as a pooling-of-interests. This information should
be read in conjunction with Management's Discussion and Analysis of Financial
Condition and Results of Operations and the Consolidated Financial Statements
and the notes thereto included elsewhere in this Form 8-K.
Year Ended December 31,
--------------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(In thousands, except per share amounts)
STATEMENT OF OPERATIONS DATA:
Operating revenues:
Oil production revenue........................... $118,628 $70,025 $48,262 $40,926 $39,080
Gas production revenue........................... 263,310 148,390 114,955 52,554 34,941
Gain on sale of assets (1) ...................... - - - - 22,472
Other revenue.................................... 4,228 2,349 2,102 2,227 3,135
-------- -------- -------- -------- --------
Total revenues................................. 386,166 220,764 165,319 95,707 99,628
-------- -------- -------- -------- --------
Expenses:
Normal lease operating expenses.................. 41,474 33,372 26,318 14,723 13,401
Major maintenance expenses....................... 6,538 1,115 1,278 1,844 427
Production taxes................................. 7,607 2,933 2,853 3,475 5,228
Depreciation, depletion and amortization......... 110,859 101,105 98,457 40,038 27,170
Write-down of oil and gas properties............. - - 114,341 - -
Interest expense................................. 9,395 15,186 15,017 5,768 5,890
Merger expenses.................................. 1,297 - - - -
Salaries, general and administrative costs....... 12,217 9,532 8,184 7,070 7,217
Incentive compensation plan...................... 1,722 1,510 763 833 928
Stock compensation, net.......................... 508 1,232 452 439 98
-------- -------- -------- -------- --------
Total expenses................................. 191,617 165,985 267,663 74,190 60,359
-------- -------- -------- -------- --------
Net income (loss) before income taxes.............. 194,549 54,779 (102,344) 21,517 39,269
-------- -------- -------- -------- --------
Income tax provision (benefit):
Current.......................................... 450 25 23 (471) 1,208
Deferred......................................... 67,642 17,688 (35,843) 8,053 11,458
-------- -------- -------- -------- --------
Total income taxes............................. 68,092 17,713 (35,820) 7,582 12,666
-------- -------- -------- -------- --------
Net income (loss).................................. $126,457 $37,066 ($66,524) $13,935 $26,603
======== ======== ======== ======== ========
Earnings and dividends per common share:
Basic net income (loss) per common share ........ $4.90 $1.61 ($3.23) $0.72 $1.62
===== ===== ===== ===== =====
Diluted net income (loss) per common share ...... $4.80 $1.58 ($3.23) $0.71 $1.61
===== ===== ===== ===== =====
Cash dividends declared.......................... - - - - -
CASH FLOW DATA:
Net cash provided by operating
activities (before working capital changes)...... $300,097 $154,152 $110,869 $62,450 $42,975
Net cash provided by operating activities.......... 302,082 123,010 118,014 43,606 36,084
BALANCE SHEET DATA (AT END OF PERIOD):
Working capital (deficit) ......................... $53,065 $12,509 ($3,340) ($1,708) $25,861
Oil and gas properties, net........................ 747,574 587,661 492,349 437,832 223,278
Total assets ...................................... 944,104 706,958 581,134 515,426 294,363
Long-term debt, less current portion............... 148,000 134,000 289,936 143,077 26,390
Stockholders' equity .............................. 587,577 452,870 213,131 277,975 213,192
(1) Primarily related to the sales of D-J Basin properties by Basin Exploration in 1996.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in understanding our
financial condition and results of operations for each year of the three-year
period ended December 31, 2000. All financial and operating information
presented give retroactive effect to the merger of Stone and Basin, which has
been accounted for as a pooling-of-interests. The consolidated financial
statements and the notes thereto, which are found elsewhere in this Form 8-K,
contain detailed information that should be referred to in conjunction with the
following discussion.
OVERVIEW
We are an independent oil and gas company engaged in the acquisition,
exploration, development and operation of oil and gas properties in the Gulf
Coast Basin and Rocky Mountains. We have been active in the Gulf Coast Basin
since 1973, which gives us extensive geophysical, technical and operational
expertise in this area.
On February 1, 2001, the stockholders of Stone Energy Corporation and Basin
Exploration, Inc. voted in favor of, and thereby consummated, the combination of
the two companies in a tax-free, stock-for-stock transaction accounted for under
the pooling-of-interests method. In connection with the approval of the merger,
stockholders of Stone Energy also approved a proposal to increase the authorized
shares of Stone common stock from 25 million to 100 million shares. Under the
merger agreement, Basin stockholders received 0.3974 of a share of Stone common
stock for each share of Basin common stock they owned. Stone issued
approximately 7.4 million shares of common stock, which, based upon Stone's
closing price of $53.70 on February 1, 2001, resulted in total equity value
related to the transaction of approximately $400 million. In addition, Stone
assumed, and subsequently retired with cash on hand, $48 million of Basin bank
debt. The expenses incurred in relation to the merger of $25.6 million were
recorded as a non-recurring item in 2001.
In accordance with the pooling-of-interests method of accounting for
business combinations, the financial condition and results of operations were
combined to give effect to the combination of Stone and Basin as if the merger
occurred at the beginning of the earliest period presented. These combined
results should be used for information purposes only as they are not necessarily
indicative of the results that would have occurred if the merger had been
completed during the periods presented.
Prior to the merger, Basin accounted for depreciation, depletion and
amortization (DD&A) of oil and gas properties using the units of production
method. In connection with the restatement of our financial statements on a
pooling-of-interests basis, Basin's historical provision for DD&A was restated
to conform to the future gross revenue method used by Stone. This restatement
included related adjustments to Basin's historical reduction in carrying value
of oil and gas properties recorded at the end of 1998 and their historical
provision for income taxes. All periods presented reflect the effects of these
adjustments. In addition, we reclassified certain amounts in Basin's historical
financial statements to conform to Stone's presentation.
Historically, we have sought growth primarily through the acquisition and
development of mature fields with a prolific production history. As commodity
prices increase and provide financial stability through additional cash flow it
becomes more feasible to pursue an aggressive exploratory drilling strategy.
During 2000, we designed a drilling program that provided an acceptable mix of
high and low risk projects in an effort to capitalize on an opportunity to test
certain prospects that have higher reward potential but are too high risk to
drill in periods of low prices. As a result, we drilled a record number of
wells, the majority of which were classified as exploratory wells.
The commodity price environment during 2000 also impacted the property
acquisition market. It is generally more expensive to buy properties at times
when oil and gas prices have increased, which is what we witnessed during the
year 2000. Therefore, we pursued stock-for-stock merger targets and non-cash
acquisition opportunities such as farmins, whereby we earned a working interest
in desirable acreage by drilling a well versus buying the field.
During 2000, we remained focused on our objectives of increasing
production, cash flow and reserves. We set a Stone record for annual production
by producing 98.9 billion cubic feet of gas equivalent (Bcfe). We also set a
record for annual cash flow before working capital changes with 2000 results of
$300.1 million representing a 95% increase over 1999 results. Finally, at
December 31, 2000, we reported 600.3 Bcfe of estimated proved reserves, which is
the largest proved reserve base in our history.
RESULTS OF OPERATIONS
The following table sets forth certain operating information with respect
to our oil and gas operations and summary information with respect to our
estimated proved oil and gas reserves.
Year Ended December 31,
------------------------------------------------
2000 1999 1998
------------- ------------ -------------
PRODUCTION:
Oil (MBbls).................................................. 4,449 4,324 3,601
Gas (MMcf) .................................................. 72,239 65,513 50,897
Oil and gas (MMcfe) ......................................... 98,933 91,457 72,503
AVERAGE SALES PRICES:
Oil (per Bbl)................................................ $26.66 $16.19 $13.40
Gas (per Mcf) ............................................... 3.64 2.27 2.26
Oil and gas (per Mcfe) ...................................... 3.86 2.39 2.25
AVERAGE COSTS (PER MCFE):
Normal operating costs....................................... $0.42 $0.36 $0.36
Salaries, general and administrative costs................... 0.12 0.10 0.11
DD&A on oil and gas properties............................... 1.10 1.08 1.33
PROVED RESERVES AT DECEMBER 31:
Oil (MBbls).................................................. 33,625 35,213 27,143
Gas (MMcf)................................................... 398,524 385,667 370,772
Oil and gas (MMcfe).......................................... 600,274 596,945 533,630
Present value of estimated future net cash flows before
income taxes (in thousands)............................... $2,941,790 $830,606 $450,583
Standardized measure of discounted future net cash flows
(in thousands).......................................... $1,982,749 $691,481 $418,403
2000 COMPARED TO 1999. For the year 2000 we reported record net income
totaling $126.5 million, or $4.80 per share, compared to net income for the year
ended December 31, 1999 of $37.1 million, or $1.58 per share. The favorable
results in net income were due to improvements in the following components:
PRODUCTION. During 2000, production volumes reached a record high totaling
98.9 Bcfe compared to 91.5 Bcfe produced during 1999. Natural gas production
during 2000 increased 10% to approximately 72.2 billion cubic feet compared to
1999 gas production of 65.5 billion cubic feet, while oil production during 2000
increased to approximately 4.4 million barrels compared to 4.3 million barrels
produced during 1999.
The increase in 2000 production rates, compared to 1999, was due to
increases at several of our fields, the most significant of which were Eugene
Island Block 243 and East Cameron Block 64.
PRICES. Prices realized during 2000 averaged $26.66 per barrel of oil and
$3.64 per Mcf of gas. This represents a 62% increase, on a Mcfe basis, over 1999
average realized prices of $16.19 per barrel of oil and $2.27 per Mcf of gas.
All unit pricing amounts include the effects of hedging.
From time to time, we enter into various hedging contracts in order to
reduce our exposure to the possibility of declining oil and gas prices. Due to
increases in commodity prices throughout 2000, hedging transactions reduced the
average price we received during the year for oil by $3.55 per barrel and for
gas by $0.46 per Mcf, compared to net decreases of $1.72 per barrel and $0.06
per Mcf realized during 1999.
OIL AND GAS REVENUE. As a result of higher production rates and realized
prices, oil and gas revenue reached a record high during 2000, increasing 75% to
$381.9 million, compared to 1999 oil and gas revenue of $218.4 million.
EXPENSES. Normal operating costs during 2000 increased to $41.5 million,
compared to $33.4 million during 1999. On a unit of production basis, 2000
operating costs were $0.42 per Mcfe compared to $0.36 per Mcfe for 1999. The
increase in operating costs was due primarily to industry-wide increases in the
costs of oil field products and services.
During 2000, we performed significant workover operations on nine wells at
three fields. As a result, major maintenance expenses for the year totaled $6.5
million compared to $1.1 million for 1999.
Due to increased 2000 onshore production volumes combined with higher oil
and gas prices, production revenue from onshore properties increased 100%. As a
result, production tax expense increased to $7.6 million from $2.9 million in
1999. Included in the 1999 amount was a $1 million production tax refund related
to the abatement of severance taxes for certain wells under Louisiana state law.
Depreciation, depletion and amortization (DD&A) expense on our oil and gas
properties totaled $109.2 million, or $1.10 per Mcfe, compared to $99.2 million,
or $1.08 per Mcfe, for 1999. The higher DD&A rate was partially attributable to
the rising costs of oil and gas exploration and development activities during
2000.
Salaries, general and administrative expenses for 2000 increased in total
to $12.2 million, or $0.12 per Mcfe, from $9.5 million, or $0.10 per Mcfe,
during 1999. Due to our operational and financial results and our stock price
performance during the year, incentive compensation expense for 2000 increased
to $1.7 million compared to $1.5 million in 1999.
Interest expense for 2000 decreased to $9.4 million, compared to $15.2
million during 1999, due primarily to the repayment of approximately $120
million of borrowings under Stone Energy's bank credit facility in August 1999.
RESERVES. At December 31, 2000, our estimated proved oil and gas reserves
totaled 600.3 Bcfe, compared to December 31, 1999 reserves of 596.9 Bcfe.
Estimated proved gas reserves grew to 398.5 Bcf at the end of 2000 from 385.7
Bcf at year-end 1999, while estimated proved oil reserves declined to 33.6
MMBbls at the end of 2000 from 35.2 MMBbls at the beginning of the year.
Our reserve estimates at December 31, 2000 were prepared by independent
petroleum consultants in accordance with guidelines established by the SEC.
Adherence to these guidelines limited our recognition of proved reserves on
certain 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.
Our present values of estimated future net cash flows before income taxes
were $2.9 billion and $830.6 million at December 31, 2000 and 1999,
respectively. You should not assume that the present values of estimated future
net cash flows represent the fair value of our estimated proved oil and gas
reserves. As required by the SEC, we determine the present value of estimated
future net cash flows using market prices for oil and gas on the last day of the
fiscal period. The average year-end oil and gas prices on all of our properties
used in determining these amounts were $27.30 per barrel and $9.97 per Mcf for
2000 and $24.83 per barrel and $2.42 per Mcf for 1999. During 2001, the market
price for gas has decreased, which would result in a reduction of estimated
future net cash flows and the present value of estimated future net cash flows
at December 31, 2000 if recomputed.
1999 COMPARED TO 1998. We recognized net income for the year ended December
31, 1999 totaling $37.1 million, or $1.58 per share, compared to the 1998 net
loss of $66.5 million, or $3.23 per share. The 1998 results included an
after-tax non-cash ceiling test write-down of $74.3 million, or $3.61 per share.
Excluding the write-down, favorable results in 1999 net income versus 1998 were
due to improvements in the following components:
PRODUCTION. Production volumes of oil and gas reached a then record high
during 1999 and, as compared to 1998, rose 20% and 29%, respectively, totaling
4.3 million barrels of oil and 65.5 billion cubic feet of gas. On a thousand
cubic feet of gas equivalent (Mcfe) basis, production rates for 1999 were 26%
higher than 1998 production rates.
The increase in 1999 production rates, compared to 1998, was due to
increases at several of our fields, the most significant of which were Vermilion
Block 255, South Pelto Block 23, West Cameron Block 56 and West Delta Block 61.
PRICES. Average realized prices during 1999 were $16.19 per barrel of oil
and $2.27 per Mcf of gas and represented a 6% increase, on a Mcfe basis, over
average prices of $13.40 per barrel of oil and $2.26 per Mcf of gas recognized
during 1998. All unit prices reflect the effects of hedging.
From time to time, we enter into various hedging contracts in order to
reduce our exposure to the possibility of declining oil and gas prices. As a
result of rising commodity prices during 1999, hedging transactions reduced the
average price we received by $1.72 per barrel of oil and by $0.06 per Mcf of gas
compared to net increases of $0.55 per barrel of oil and $0.11 per Mcf of gas
during 1998.
OIL AND GAS REVENUE. Oil and gas revenue reached a then record high during
1999. The increases in oil and gas production rates combined with higher
commodity prices resulted in oil and gas revenue increasing 34% to $218.4
million, compared to oil and gas revenue of $163.2 million during 1998.
EXPENSES. Normal operating costs during 1999 increased to $33.4 million,
compared to $26.3 million during 1998. On a unit of production basis, 1999
operating costs were unchanged from 1998.
As a result of increased 1999 production volumes due to acquisitions and
discoveries, combined with higher oil and gas prices during the year, production
revenue from onshore properties increased 41% during 1999. Our production tax
expense, however, was unchanged from the 1998 amount of $2.9 million. On a per
unit basis, production taxes declined from $0.04 per Mcfe in 1998 to $0.03 per
Mcfe in 1999. This decline resulted from the abatement of severance taxes for
certain wells under Louisiana state law. Accordingly, we accrued in December
1999, and received in early 2000, a production tax refund of $1 million.
Salaries, general and administrative expenses for 1999 increased in total
to $9.5 million from $8.2 million during 1998. Due to our operational results
and stock performance during the year, incentive compensation expense for 1999
increased to $1.5 million compared to $0.8 million in 1998.
DD&A expense on our oil and gas properties for 1999 totaled $99.2 million
compared to $96.5 million for 1998. However, on a unit of production basis, 1999
expense decreased to $1.08 per Mcfe compared to $1.33 per Mcfe for 1998. The
decrease in the DD&A rate resulted from a combination of the $114.3 million
non-cash ceiling test write-down of oil and gas properties recorded at the end
of 1998 and the improvement in oil and gas prices throughout 1999.
Our provision for income taxes was $17.7 million for the year ended
December 31, 1999 and was net of a $1.5 million reduction in deferred taxes
related to estimates of tax basis that were resolved during 1999. In order to
conform Stone and Basin's accounting methods, we recognized the $5.7 million tax
benefit related to Basin's 1998 write-down of oil and gas properties by
reversing the valuation allowance that Basin recorded in 1998. This resulted in
additional deferred tax benefit for the year ended December 31, 1998 and
deferred tax expense for the years ended December 31, 1999 and 2000. During 1999
and 2000, Basin had previously reduced its effective tax rate through the
reversal of the valuation allowance recorded in 1998.
RESERVES. At December 31, 1999, our estimated proved oil and gas reserves
totaled 596.9 Bcfe compared to December 31, 1998 reserves of 533.6 Bcfe.
Estimated proved oil reserves increased to 35.2 MMBbls at the end of 1999 from
27.1 MMBbls at the beginning of the year, and estimated proved gas reserves grew
to 385.7 Bcf at December 31, 1999 compared to 370.8 Bcf at year-end 1998.
The increases in our 1999 estimated proved reserve volumes were primarily
attributable to drilling results and acquisitions made during the year. The
majority of our reserve estimates were prepared by independent petroleum
consultants in accordance with guidelines established by the SEC. Adherence to
these guidelines limited our recognition of proved reserves on certain
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.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW AND WORKING CAPITAL. Net cash flow from operations before working
capital changes for 2000 was $300.1 million, or $11.40 per share, compared to
$154.2 million, or $6.58 per share, reported for 1999. Working capital at
December 31, 2000 totaled $53.1 million.
CAPITAL EXPENDITURES. Capital expenditures during 2000 totaled $269.1
million and included $13.6 million of capitalized employee, general and
administrative costs, net of reimbursements, and $4 million of capitalized
interest. These investments were financed by a combination of cash flows from
operations, working capital and bank borrowings.
BUDGETED CAPITAL EXPENDITURES AND LONG-TERM FINANCING. Our estimated 2001
capital expenditures budget of approximately $290 million is expected to be
allocated approximately 93% to Gulf Coast operations and 7% to Rocky Mountain
activities. We expect to drill 70 gross wells during 2001, 45 in the onshore and
shallow water offshore regions of the Gulf Coast Basin and 25 in the Rocky
Mountains. While the 2001 capital expenditures budget does not include any
projected acquisitions, we continue to seek growth opportunities that fit our
specific acquisition profile.
Based upon our outlook of oil and gas prices and production rates, we
believe that our cash on hand and cash flow from operations will be sufficient
to fund the current 2001 capital expenditures budget. If oil and gas prices or
production rates fall below our current expectations, we believe that the
available borrowings under our bank credit facility will be sufficient to fund
2001 capital expenditures in excess of operating cash flows.
We do not budget acquisitions; however, we are currently evaluating several
opportunities that fit our specific acquisition profile. One or a combination of
certain of these possible transactions could fully utilize our existing sources
of capital. Under these circumstances, we would compare the cost of debt
financing with the potential dilution of equity offerings to determine the
appropriate financing vehicle to provide capital in excess of what is currently
available to us with the objective of maximizing stockholder value.
BANK CREDIT FACILITIES. During 2000, Stone's bank group increased the
borrowing base under its credit facility to $200 million and extended the
maturity date from July 30, 2001 to July 30, 2005. The borrowing base limitation
is based on a borrowing base amount established by the banks for our oil and gas
properties. During 2000, Stone did not draw upon its credit facility, and at
December 31, 2000 had outstanding letters of credit totaling $7.5 million.
At December 31, 2000, the borrowing base under Basin's credit facility was
$90 million with $48 million of outstanding borrowings. Concurrent with closing
the merger on February 1, 2001, all borrowings outstanding under Basin's
revolving credit facility were repaid with cash on hand and the credit facility
was terminated.
Our credit facility provides for certain covenants, including restrictions
or requirements with respect to working capital, tangible net worth, disposition
of properties, incurrence of additional debt, change of ownership and reporting
responsibilities. These covenants may limit or prohibit us from paying cash
dividends.
HEDGING. See "Quantitative and Qualitative Disclosure About Market Risk -
Commodity Price Risk."
NEW ACCOUNTING STANDARDS. For information regarding SFAS No. 133, see
"Quantitative and Qualitative Disclosure About Market Risk - Commodity Price
Risk - Adoption of SFAS No. 133."
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations," effective for fiscal years beginning after June 15,
2002. This statement will require us to record the fair value of liabilities
related to future asset retirement obligations in the period the obligation is
incurred. We expect to adopt SFAS No. 143 on January 1, 2003. Upon adoption, we
will be required to recognize cumulative transition amounts for existing asset
retirement obligation liabilities, asset retirement costs and accumulated
depreciation. We have not yet determined the transition amounts.
REGULATORY AND LITIGATION ISSUES. In August 1989, we were advised by the
EPA that it believed we were a potentially responsible party (a "PRP") for the
cleanup of an oil field waste disposal facility located near Abbeville,
Louisiana, which was included on CERCLA's National Priority List (the "Superfund
List") by the EPA in March 1989. Although we did not dispose of wastes or salt
water at this site, the EPA contends that transporters of salt water may have
rinsed their trucks' tanks at this site. By letter dated December 9, 1998, the
EPA made demand for cleanup costs on 23 of the PRP's, including us, who had not
previously settled with the EPA. Since that time we, together with other PRPs,
have been negotiating the settlement of our respective potential liability for
environmental conditions at this site with the U.S. Department of Justice. Given
the number of PRP's at this site and the current satisfactory progress of these
negotiations, we do not believe that any liability for this site would have a
material adverse affect on our financial condition. A tentative settlement has
been reached with the U.S. Department of Justice regarding our potential
liability at this site. The amount of this tentative settlement is immaterial to
our financial statements and was not accrued at December 31, 2000. However, the
settlement has not been formally approved by all parties, and we cannot assure
you that a settlement will be formally approved.
Since November 26, 1993, new levels of lease and area-wide bonds have been
required of lessees taking certain actions with regard to OCS leases. Operators
in the OCS waters of the Gulf of Mexico were required to increase their
area-wide bonds and individual lease bonds to $3 million and $1 million,
respectively, unless the MMS allowed exemptions or reduced amounts. We currently
have two area-wide right-of-way bonds for $0.3 million each and two area-wide
lessee's and operator's bonds for $3 million each issued in favor of the MMS by
Stone and Basin for our existing offshore properties. The MMS also has
discretionary authority to require supplemental bonding in addition to the
foregoing required bonding amounts, but this authority is exercised on a
case-by-case basis at the time of filing an assignment of record title interest
for MMS approval. Based upon certain financial parameters, Stone has been
granted exempt status by the MMS, which exempts it from supplemental bonding
requirements. Currently, supplemental bonds totaling $0.6 million are filed with
the MMS on behalf of Basin's prior obligations. Based on Stone's financial
position, we have requested the release of all Basin bonds filed with the MMS.
We cannot assure you that this request will be approved. Under certain
circumstances, the MMS may require any of our operations on federal leases to be
suspended or terminated. Any such suspension or termination could materially and
adversely affect our financial condition and operations.
OPA imposes ongoing requirements on a responsible party, including the
preparation of oil spill response plans and proof of financial responsibility to
cover environmental cleanup and restoration costs that could be incurred in
connection with an oil spill. Under OPA and a MMS final rule adopted in August
1998, responsible parties of covered offshore facilities that have a worst case
oil spill potential of more than 1,000 barrels must demonstrate financial
responsibility in amounts ranging from at least $10 million in specified state
waters to at least $35 million in OCS waters, with higher amounts of up to $150
million in certain limited circumstances where the MMS believes such a level is
justified by the risks posed by the operations or if the worst case oil-spill
discharge volume possible at the facility may exceed the applicable threshold
volumes specified under the MMS's final rule. We do not anticipate that we will
experience any difficulty in continuing to satisfy the MMS's requirements for
demonstrating financial responsibility under the current OPA and MMS's August
1998 final rule.
We operate under numerous state and federal laws enacted for the protection
of the environment. In the ordinary course of business, we conduct an ongoing
review of the effects of these various environmental laws on our business and
operations. The estimated cost of continued compliance with current
environmental laws, based upon the information currently available, is not
material to our results of operations or financial position. It is impossible to
determine whether and to what extent our future performance may be affected by
environmental laws; however, we believe that such laws will not have a material
adverse effect on our results of operations or financial position.
We are named as a defendant in certain lawsuits and are a party to certain
regulatory proceedings arising in the ordinary course of business. We do not
expect these matters, individually or in the aggregate, to have a material
adverse effect on our financial condition.
FORWARD-LOOKING STATEMENTS
This Form 8-K contains statements that constitute "forward-looking
statements" within the meaning of Section 27A of the Securities Act and Section
21E of the Securities Exchange Act. The words "expect", "project", "estimate",
"believe", "anticipate", "intend", "budget", "plan", "forecast", "predict" and
other similar expressions are intended to identify forward-looking statements.
These statements appear in a number of places and include statements regarding
our plans, beliefs or current expectations, including the plans, beliefs and
expectations of our officers and directors with respect to, among other things:
o earnings growth;
o budgeted capital expenditures;
o increases in oil and gas production;
o future project dates;
o our outlook on oil and gas prices;
o estimates of our proved oil and gas reserves;
o our future financial condition or results of operations; and
o our business strategy and other plans and objectives for future operations.
When considering any forward-looking statement, you should keep in mind the
risk factors that could cause our actual results to differ materially from those
contained in any forward-looking statement. 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 our Annual Report on
Form 10-K as filed with the Securities and Exchange Commission. Furthermore, the
assumptions that support our forward-looking statements are based upon
information that is currently available and is subject to change. We
specifically disclaim all responsibility to publicly update any information
contained in a forward-looking statement or any forward-looking statement in its
entirety and therefore disclaim any resulting liability for potentially related
damages.
All forward-looking statements attributable to Stone Energy Corporation are
expressly qualified in their entirety by this cautionary statement.
ACCOUNTING MATTERS
BASIS OF PRESENTATION. The financial statements include our accounts and
our proportionate interest in certain partnerships. These partnerships were
dissolved on December 31, 1999. All intercompany balances have been eliminated.
Certain prior year amounts have been reclassified to conform to current year
presentation.
In accordance with the pooling-of-interests method of accounting for
business combinations, all results were combined to give effect to the
combination of Stone and Basin as if the merger occurred at the beginning of the
first period presented. Prior to the merger, Basin accounted for depreciation,
depletion and amortization (DD&A) of oil and gas properties using the units of
production method. In connection with the restatement of our financial
statements on a pooling-of-interests basis, Basin's historical provision for
DD&A was restated to conform to the future gross revenue method used by Stone.
This restatement included related adjustments to Basin's historical reduction in
carrying value of oil and gas properties recorded at the end of 1998 and their
historical provision for income taxes. All periods presented reflect the effects
of these adjustments.
In addition to the DD&A adjustment, we reclassified certain amounts in
Basin's historical financial statements to conform to Stone's presentation.
These combined results should be used for information purposes only as they are
not necessarily indicative of the results that would have occurred if the merger
had been completed at the beginning of the earliest period presented.
FULL COST METHOD. We use the full cost method of accounting for our oil and
gas properties. Under this method, all acquisition and development costs,
including certain related employee and general and administrative costs (less
any reimbursements for such costs) and interest incurred for the purpose of
acquiring and finding oil and gas are capitalized. We amortize our investment in
oil and gas properties using the future gross revenue method.
DEFERRED INCOME TAXES. Deferred income taxes have been determined in
accordance with Financial Accounting Standards Board Statement No. 109,
"Accounting for Income Taxes." As of December 31, 2000, we had a net deferred
tax liability of $68.9 million which was calculated based on our assumption that
it is more likely than not that we will have sufficient taxable income in future
years to utilize certain tax attribute carryforwards.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
----------------------------------------------------------
COMMODITY PRICE RISK
Our revenues, profitability and future rate of growth depend substantially
upon the market prices of oil and natural gas, which fluctuate widely. Oil and
gas price declines and volatility could adversely affect our revenues, cash
flows and profitability. In order to manage our exposure to oil and gas price
declines, we occasionally enter into oil and gas price hedging arrangements to
secure a price for a portion of our expected future production. We do not enter
into hedging transactions for trading purposes. While intended to reduce the
effects of volatile oil and gas prices, such transactions, depending on the
hedging instrument used, may limit our potential gains if oil and gas prices
were to rise substantially over the price established by the hedge. In addition,
such transactions may expose us to the risk of financial loss in certain
circumstances, including instances in which:
o our production is less than expected;
o there is a widening of price differentials between delivery points for
our production and the delivery point assumed in the hedge
arrangement;
o the counterparties to our hedging contracts fail to perform the
contracts; or
o a sudden, unexpected event materially impacts oil or gas prices.
Our hedging policy provides that not more than one-half of our production
quantities can be hedged without the consent of the Board of Directors.
Additionally, not more than 75% of our production quantities can be committed to
hedging agreements regardless of the prices available.
HEDGING. During 2000, we realized a net reduction in revenue from our
hedging transactions of $47.9 million. Our contracts totaled 1,868 MBbls of oil
and 29,303 BBtus of gas, which represented approximately 42% and 41%,
respectively, of our oil and gas production for the year. The net reduction in
revenue from hedging transactions for 1999 was $11.3 million. Our contracts
totaled 2,094 MBbls of oil and 44,949 BBtus of gas, which represented
approximately 48% and 69%, respectively, of our oil and gas production for that
year.
At December 31, 2000, our oil puts were reflected as assets at a historical
cost of $5 million. Put contracts are purchased at a rate per unit of hedged
production that fluctuates with the commodity futures market. The historical
cost of the put contracts represents our maximum cash exposure. We are not
obligated to make any further payments under the put contracts regardless of
future commodity price fluctuations. Under put contracts, monthly payments are
made to us if prices fall below the agreed upon floor price, while allowing us
to fully participate in commodity prices above that floor.
In addition to put contracts, we utilized fixed price swaps to hedge a
portion of our future gas production. Fixed price swaps typically provide for
monthly payments by us if NYMEX prices rise above the fixed swap price or to us
if NYMEX prices fall below the fixed swap price.
Since over 90% of our production has historically been derived from the
Gulf Coast Basin, we believe that fluctuations in prices will closely match
changes in the market prices we receive for our production. Oil contracts
typically settle using the average of the daily closing prices for a calendar
month. Natural gas contracts typically settle using the average closing prices
for near month NYMEX futures contracts for the three days prior to the
settlement date.
The following table shows our hedging position as of February 23, 2001.
Puts
----------------------------------------------------------------------------------------------
Gas Oil
-------------------------------------------- ---------------------------------------------
Volume Cost Volume Cost
(BBtus) Floor (millions) (Bbls) Floor (millions)
----------- ----------- ------------ ----------- ------------- -------------
2001 (1)................. 22,000 $3.50 $1.3 1,277,500 $25.00 $1.8
2002..................... 21,900 $3.50 $5.2 1,277,500 $24.00 $3.2
(1) The hedged volumes related to the 2001 gas put contracts are from April 2001 - December 2001.
Fixed Price Gas Swaps
-------------------------------------
Volume (BBtus) Price
---------------- ----------------
2001...................... 7,300 $2.33
2002...................... 3,650 $2.15
2003...................... 3,650 $2.15
ADOPTION OF SFAS NO. 133. Under SFAS No. 133, as amended, the nature of a
derivative instrument must be evaluated to determine if it qualifies for hedge
accounting treatment. Instruments qualifying for hedge accounting treatment are
recorded as an asset or liability measured at fair value and subsequent changes
in fair value are recognized in equity through other comprehensive income, net
of related taxes, to the extent the hedge is effective. Instruments not
qualifying for hedge accounting treatment are recorded in the balance sheet and
changes in fair value are recognized in earnings.
At December 31, 2000, our oil put contracts were reflected as assets at a
historical cost of $5 million and, in accordance with generally accepted
accounting principles in effect at year-end 2000, our fixed price gas swap
contracts were not recorded since they were costless. Our gas put contracts were
purchased subsequent to year-end and therefore were not reflected in the
December 31, 2000 balance sheet. At December 31, 2000, the fair values of our
oil put contracts and fixed price gas swaps were $7.7 million and ($42.8)
million, respectively.
We adopted SFAS No. 133 effective January 1, 2001. Upon adoption of SFAS
No. 133, as amended, the after-tax increase in fair value over historical cost
of our oil put contracts of $1.7 million was a transition adjustment that was
recorded as a gain in equity through other comprehensive income. In addition,
the fair market value of the fixed price gas swaps was recorded as a liability
and the corresponding after-tax loss of $27.8 million was recorded in equity
through other comprehensive income. Our current hedge instruments are considered
effective cash flow hedges and changes in fair value of the hedge instruments
are reflected in other comprehensive income, net of related taxes.
PROJECTED REVENUE. Based on current sales projections for the second half
of 2001, a 10% decline in the prices we are projecting to receive for our crude
oil and natural gas production would have an approximate $19 million impact on
our revenue. This hypothetical impact of the decline in oil and gas prices is
net of the incremental increase in revenue that we would realize, upon a decline
in prices, from the oil and gas hedging contracts in place.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of cash and cash equivalents, net accounts receivable,
accounts payable and the debt under Basin's revolving credit facility
approximated book value at December 31, 2000. At December 31, 2000, the fair
value of the 8-3/4% Notes totaled $102 million and the fair values of our oil
put contracts and fixed price gas swaps were $7.7 million and ($42.8) million,
respectively.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of
Stone Energy Corporation:
We have audited the accompanying consolidated balance sheets of Stone Energy
Corporation (a Delaware corporation) as of December 31, 2000 and 1999, and the
related consolidated statements of operations, changes in stockholders' equity
and cash flows for each of the three years in the period ended December 31,
2000. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Stone Energy Corporation as of
December 31, 2000 and 1999, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2000, in
conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana
February 23, 2001
STONE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEET
(Dollar amounts in thousands, except per share amounts)
December 31,
-------------------------------
ASSETS 2000 1999
------ ------------ -------------
Current assets:
Cash and cash equivalents................................................... $78,557 $17,651
Marketable securities, at market............................................ 300 34,906
Accounts receivable......................................................... 95,722 50,061
Other current assets........................................................ 2,916 5,036
Investment in put contracts................................................. 1,847 -
------------ -------------
Total current assets...................................................... 179,342 107,654
Oil and gas properties--full cost method of accounting:
Proved, net of accumulated depreciation, depletion and
amortization of $620,510 and $511,279, respectively....................... 691,883 543,912
Unevaluated................................................................. 55,691 43,749
Building and land, net of accumulated depreciation of $465 and
$355, respectively........................................................ 4,914 3,864
Fixed assets, net of accumulated depreciation of $8,059 and $6,756,
respectively.............................................................. 4,441 4,204
Other assets, net of accumulated depreciation and amortization
of $1,499 and $1,157, respectively........................................ 4,681 3,575
Investment in put contracts..................................................... 3,152 -
------------ -------------
Total assets.............................................................. $944,104 $706,958
============ =============
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable to vendors................................................. $83,423 $67,550
Undistributed oil and gas proceeds.......................................... 32,858 16,793
Other accrued liabilities................................................... 9,996 10,802
------------ -------------
Total current liabilities................................................. 126,277 95,145
Long-term debt.................................................................. 148,000 134,000
Production payments............................................................. 10,906 17,284
Deferred tax liability.......................................................... 68,926 4,941
Other long-term liabilities..................................................... 2,418 2,718
------------ -------------
Total liabilities......................................................... 356,527 254,088
------------ -------------
Common stock, $.01 par value; authorized 100,000,000 shares;
issued and outstanding 25,981,000 and 25,672,000 shares, respectively....... 260 257
Additional paid-in capital...................................................... 440,729 432,482
Retained earnings............................................................... 146,588 20,131
------------ -------------
Total stockholders' equity................................................ 587,577 452,870
------------ -------------
Total liabilities and stockholders' equity................................ $944,104 $706,958
============ =============
The accompanying notes are an integral part of this balance sheet.
STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
(Amounts in thousands, except per share amounts)
Year Ended December 31,
-----------------------------------------------------------
2000 1999 1998
----------------- ----------------- -----------------
Revenues:
Oil and gas production........................................ $381,938 $218,415 $163,217
Other revenue................................................. 4,228 2,349 2,102
----------------- ----------------- -----------------
Total revenues.............................................. 386,166 220,764 165,319
----------------- ----------------- -----------------
Expenses:
Normal lease operating expenses............................... 41,474 33,372 26,318
Major maintenance expenses.................................... 6,538 1,115 1,278
Production taxes.............................................. 7,607 2,933 2,853
Depreciation, depletion and amortization...................... 110,859 101,105 98,457
Write-down of oil and gas properties.......................... - - 114,341
Interest...................................................... 9,395 15,186 15,017
Merger expenses............................................... 1,297 - -
Salaries, general and administrative costs.................... 12,217 9,532 8,184
Incentive compensation plan................................... 1,722 1,510 763
Stock compensation, net....................................... 508 1,232 452
----------------- ----------------- -----------------
Total expenses.............................................. 191,617 165,985 267,663
----------------- ----------------- -----------------
Net income (loss) before income taxes ........................... 194,549 54,779 (102,344)
----------------- ----------------- -----------------
Income tax provision (benefit):
Current....................................................... 450 25 23
Deferred...................................................... 67,642 17,688 (35,843)
----------------- ----------------- -----------------
Total income taxes.......................................... 68,092 17,713 (35,820)
----------------- ----------------- -----------------
Net income (loss)................................................. $126,457 $37,066 ($66,524)
================= ================= =================
Earnings (loss) per common share:
Basic earnings (loss) per share............................... $4.90 $1.61 ($3.23)
================= ================= =================
Diluted earnings (loss) per share ............................ $4.80 $1.58 ($3.23)
================= ================= =================
Average shares outstanding.................................... 25,804 22,954 20,574
================= ================= =================
Average shares outstanding assuming dilution.................. 26,335 23,416 20,574
================= ================= =================
The accompanying notes are an integral part of this statement.
STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollar amounts in thousands)
Year Ended December 31,
-------------------------------------------------------
2000 1999 1998
--------------- ---------------- ---------------
Cash flows from operating activities:
Net income (loss)............................................... $126,457 $37,066 ($66,524)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization................... 110,859 101,105 98,457
Deferred income tax provision (benefit).................... 67,642 17,688 (35,843)
Non-cash effect of production payments..................... (5,784) (2,981) -
Write-down of oil and gas properties....................... - - 114,341
Other non-cash expenses.................................... 923 1,274 438
--------------- ---------------- ---------------
300,097 154,152 110,869
(Increase) decrease in marketable securities............... 34,606 (18,053) 3,088
Increase in accounts receivable............................ (45,661) (13,223) (5,759)
(Increase) decrease in other current assets................ 2,040 (1,663) 956
Increase in other accrued liabilities...................... 15,258 6,285 3,909
Investment in put contracts................................ (4,999) - -
Other...................................................... 741 (4,488) 4,951
--------------- ---------------- ---------------
Net cash provided by operating activities........................... 302,082 123,010 118,014
--------------- ---------------- ---------------
Cash flows from investing activities:
Investment in oil and gas properties............................ (259,074) (165,664) (265,766)
Sale of unevaluated properties.................................. 4,302 10,630 -
Sale of reserves................................................ - - 9
Building additions and renovations.............................. (1,160) (405) (110)
(Increase) decrease in other assets............................. (2,705) (3,128) 185
--------------- ---------------- ---------------
Net cash used in investing activities............................... (258,637) (158,567) (265,682)
--------------- ---------------- ---------------
Cash flows from financing activities:
Proceeds from borrowings........................................ 59,500 67,500 174,245
Repayment of debt............................................... (45,500) (223,782) (27,274)
Deferred financing costs........................................ (200) (538) (160)
Proceeds from common stock offerings............................ - 198,242 -
Expenses from common stock offerings............................ - (844) -
Proceeds from exercise of stock options......................... 4,404 2,048 954
Purchase of treasury stock...................................... (743) (299) (51)
--------------- ---------------- ---------------
Net cash provided by financing activities........................... 17,461 42,327 147,714
--------------- ---------------- ---------------
Net increase in cash and cash equivalents........................... 60,906 6,770 46
Cash and cash equivalents beginning of year......................... 17,651 10,881 10,835
--------------- ---------------- ---------------
Cash and cash equivalents end of year............................... $78,557 $17,651 $10,881
=============== ================ ===============
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest (net of amount capitalized)........................ $8,793 $15,648 $14,438
Income taxes................................................ 450 25 23
The accompanying notes are an integral part of this statement.
STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(Dollar amounts in thousands)
Additional Retained
Common Paid-In Treasury Earnings
Stock Capital Stock (Deficit)
--------------- ---------------- --------------- ---------------
Balance, December 31, 1997............................ $205 $229,593 ($1,412) $49,589
Net loss............................................ - - - (66,524)
Exercise of stock options........................... 2 952 - -
Exercise of warrants for common stock............... - 1,108 (1,108) -
Purchase of treasury stock.......................... - - (51) -
Issuance and vesting of restricted stock............ - 777 - -
--------------- ---------------- --------------- ---------------
Balance, December 31, 1998............................ 207 232,430 (2,571) (16,935)
Net income ......................................... - - - 37,066
Sale of common stock................................ 49 198,193 - -
Expenses from common stock offerings................ - (844) - -
Exercise of stock options........................... 1 2,047 - -
Stock compensation plans............................ - 370 - -
Tax benefit from stock option exercises............. - 1,467 - -
Exercise of warrants for common stock............... - 1,716 (1,716) -
Purchase of treasury stock.......................... - - (669) -
Issuance and vesting of restricted stock............ 1 2,058 - -
Retirement of treasury stock........................ (1) (4,955) 4,956 -
--------------- ---------------- --------------- ---------------
Balance, December 31, 1999............................ 257 432,482 - 20,131
Net income.......................................... - - - 126,457
Exercise of stock options........................... 3 4,401 - -
Stock compensation plans............................ 1 2,442 - -
Tax benefit from stock option exercises............. - 3,657 - -
Purchase of treasury stock.......................... - - (3,185) -
Issuance and vesting of restricted stock............ - 931 - -
Retirement of treasury stock........................ (1) (3,184) 3,185 -
--------------- ---------------- --------------- ---------------
Balance, December 31, 2000............................ $260 $440,729 - $146,588
=============== ================ =============== ===============
The accompanying notes are an integral part of this statement.
STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollar amounts in thousands, except per share and price amounts)
NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Stone Energy Corporation is an independent oil and gas company engaged in
the acquisition, exploration, development and operation of oil and gas
properties in the Gulf Coast Basin and Rocky Mountains.
Our business strategy is to increase production, cash flow and reserves
through the acquisition and development of mature properties. Currently, our
property base consists of 84 producing properties, 52 in the Gulf Coast Basin
and 32 in the Rocky Mountains, and 41 primary term leases. We serve as operator
on 56 of our producing properties, which enables us to better control the timing
and cost of rejuvenation activities. We believe that there will continue to be
opportunities to acquire properties in the Gulf Coast Basin due to the increased
focus by major and large independent companies on projects away from the onshore
and shallow water shelf regions of the Gulf of Mexico.
We are headquartered in Lafayette, Louisiana, with additional offices in
New Orleans, Houston and Denver.
A summary of significant accounting policies followed in the preparation of
the accompanying consolidated financial statements is set forth below:
MERGER WITH BASIN EXPLORATION:
On February 1, 2001, the stockholders of Stone Energy Corporation and Basin
Exploration, Inc. voted in favor of, and thereby consummated, the combination of
the two companies in a tax-free, stock-for-stock transaction accounted for under
the pooling-of-interests method. In connection with the approval of the merger,
stockholders of Stone Energy also approved a proposal to increase the authorized
shares of Stone common stock from 25,000,000 to 100,000,000 shares. Under the
merger agreement, Basin stockholders received 0.3974 of a share of Stone common
stock for each share of Basin common stock they owned. Stone issued 7,436,652
shares of common stock, which, based upon Stone's closing price of $53.70 on
February 1, 2001, resulted in total equity value related to the transaction of
approximately $400,000. In addition, Stone assumed, and subsequently retired
with cash on hand, $48,000 of Basin bank debt. The expenses incurred in relation
to the merger of $25,631 were recorded as a non-recurring item in 2001.
BASIS OF PRESENTATION:
In accordance with the pooling-of-interests method of accounting for
business combinations, the financial position and results of operations were
combined to give effect to the combination of Stone and Basin as if the merger
occurred at the beginning of the first period presented. Prior to the merger,
Basin accounted for depreciation, depletion and amortization (DD&A) of oil and
gas properties using the units of production method. In connection with the
restatement of our financial statements on a pooling-of-interests basis, Basin's
historical provision for DD&A was restated to conform to the future gross
revenue method used by Stone. This restatement included related adjustments to
Basin's historical reduction in carrying value of oil and gas properties
recorded at the end of 1998 and their historical provision for income taxes. All
periods presented reflect the effects of these adjustments.
We reclassified certain amounts in Basin's historical financial statements
to conform to Stone's presentation.
The financial statements include our accounts and our proportionate
interest in certain partnerships. These partnerships were dissolved on December
31, 1999. All intercompany balances have been eliminated. Certain prior year
amounts have been reclassified to conform to current year presentation.
USE OF ESTIMATES:
The preparation of financial statements in conformity with generally
accepted accounting principles requires us to make estimates and assumptions
that affect the reported amounts of assets and liabilities, the disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates. Estimates are used primarily
when accounting for depreciation, depletion and amortization, unevaluated
property costs, estimated future net cash flows, taxes and contingencies.
FAIR VALUE OF FINANCIAL INSTRUMENTS:
The fair value of cash and cash equivalents, net accounts receivable,
accounts payable and the debt under Basin's revolving credit facility
approximated book value at December 31, 2000. At December 31, 2000, the fair
value of the 8-3/4% Senior Subordinated Notes totaled $102,000 and the fair
values of our oil put contracts and fixed price gas swaps were $7,669 and
($42,846), respectively.
CASH AND CASH EQUIVALENTS:
We consider all highly liquid investments in overnight securities through
our commercial bank accounts, which result in available funds on the next
business day, to be cash and cash equivalents.
OIL AND GAS PROPERTIES:
We follow the full cost method of accounting for oil and gas properties.
Under this method, all acquisition, exploration and development costs, including
certain related employee and general and administrative costs (less any
reimbursements for such costs) and interest incurred for the purpose of finding
oil and gas are capitalized. Such amounts include the cost of drilling and
equipping productive wells, dry hole costs, lease acquisition costs, delay
rentals and other costs related to such activities. Employee, general and
administrative costs that are capitalized include salaries and all related
fringe benefits paid to employees directly engaged in the acquisition,
exploration and development of oil and gas properties, as well as all other
directly identifiable general and administrative costs associated with such
activities, such as rentals, utilities and insurance. Fees received from managed
partnerships for providing such services are accounted for as a reduction of
capitalized costs. Employee, general and administrative costs associated with
production operations and general corporate activities are expensed in the
period incurred.
As required by the Securities and Exchange Commission, under the full cost
method of accounting we are required to periodically compare the present value
of estimated future net cash flows from proved reserves (based on period-end
commodity prices) to the net capitalized costs of proved oil and gas properties.
If the net capitalized costs of proved oil and gas properties exceed the
estimated discounted future net cash flows from proved reserves, we are required
to write-down the value of our oil and gas properties to the value of the
discounted cash flows. Due to the impact of low year-end commodity prices on
December 31, 1998 proved reserve values, we recorded a $114,341 reduction in the
carrying value of our oil and gas properties at December 31, 1998.
Our investment in oil and gas properties is amortized using the future
gross revenue method, a unit of production method, whereby the annual provision
for depreciation, depletion and amortization is computed by dividing revenue
earned during the period by future gross revenues at the beginning of the
period, and applying the resulting rate to the cost of oil and gas properties,
including estimated future development, restoration, dismantlement and
abandonment costs. Transactions involving sales of unevaluated properties are
recorded as adjustments to oil and gas properties and sales of reserves in
place, unless extraordinarily large portions of reserves are involved, are
recorded as adjustments to accumulated depreciation, depletion and amortization.
Oil and gas properties included $55,691 and $43,749 of unevaluated property
and related costs that were not being amortized at December 31, 2000 and 1999,
respectively. These costs were associated with the acquisition and evaluation of
unproved properties and major development projects expected to entail
significant costs to ascertain quantities of proved reserves. We believe that a
majority of unevaluated properties at December 31, 2000 will be evaluated within
one to 24 months. The excluded costs and related reserve volumes will be
included in the amortization base as the properties are evaluated and proved
reserves are established or impairment is determined. Interest capitalized on
unevaluated properties during the years ended December 31, 2000 and 1999 was
$4,027 and $2,299, respectively.
BUILDING AND LAND:
Building and land are recorded at cost. Our Lafayette office building is
being depreciated on the straight-line method over its estimated useful life of
39 years.
FIXED ASSETS:
Fixed assets at December 31, 2000 and 1999 included approximately $2,764
and $2,625, respectively, of computer hardware and software costs, net of
accumulated depreciation. These costs are being depreciated on the straight-line
method over an estimated useful life of 5 years.
OTHER ASSETS:
Other assets at December 31, 2000 and 1999 included approximately $2,637
and $2,910, respectively, of deferred financing costs, net of accumulated
amortization, related to the sale of the 8-3/4% Notes (see Note 7). These costs
are being amortized over the life of the notes using the effective interest
method. Other assets at December 31, 2000 also included approximately $840 of
deferred expenses related to the Basin merger, which were recorded in the
statement of operations as a non-recurring item in the first quarter of 2001.
EARNINGS PER COMMON SHARE:
Basic net income per share of common stock was calculated by dividing net
income applicable to common stock by the weighted-average number of common
shares outstanding during the year. Diluted net income per share of common stock
was calculated by dividing net income applicable to common stock by the
weighted-average number of common shares outstanding during the year plus the
weighted-average number of dilutive stock options granted to outside directors,
officers and employees. There were approximately 531,000 and 462,000
weighted-average dilutive shares for the years ending December 31, 2000 and
December 31, 1999, respectively, and there were no dilutive shares during 1998.
Options that were considered antidilutive because the exercise price of the
stock exceeded the average price for the applicable period totaled approximately
279,000 shares and 71,000 shares during 2000 and 1999, respectively. All options
were considered antidilutive in 1998 due to the net loss incurred in that year.
GAS PRODUCTION REVENUE:
We record as revenue only that portion of gas production sold and allocable
to our ownership interest in the related well. Any gas production proceeds
received in excess of our ownership interest are reflected as a liability in the
accompanying balance sheet.
Revenue relating to net undelivered gas production to which we are entitled
but for which we have not received payment are not recorded in the financial
statements until such amounts are received. These amounts at December 31, 2000,
1999 and 1998 were immaterial.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:
From time to time, we utilize hedging activities to reduce the effect of
commodity price volatility. Upon settlement, these transactions are accounted
for as increases or decreases in revenue from oil and gas production in the
financial statements (See Note 9).
INCOME TAXES:
Income taxes are accounted for in accordance with SFAS No. 109, "Accounting
for Income Taxes." Provisions for income taxes include deferred taxes resulting
primarily from temporary differences due to different reporting methods for oil
and gas properties for financial reporting purposes and income tax purposes. For
financial reporting purposes, all exploratory and development expenditures
related to evaluated projects are capitalized and depreciated, depleted and
amortized on the future gross revenue method. For income tax purposes, only the
equipment and leasehold costs relative to successful wells are capitalized and
recovered through depreciation or depletion. Generally, most other exploratory
and development costs are charged to expense as incurred; however, we follow
certain provisions of the Internal Revenue Code that allow capitalization of
intangible drilling costs where management deems appropriate. Other financial
and income tax reporting differences occur as a result of statutory depletion,
different reporting methods for sales of oil and gas reserves in place, and
different reporting methods used in the capitalization of employee, general and
administrative and interest expenses.
NEW ACCOUNTING STANDARDS:
Under SFAS No. 133, as amended, the nature of a derivative instrument must
be evaluated to determine if it qualifies for hedge accounting treatment.
Instruments qualifying for hedge accounting treatment are recorded as an asset
or liability measured at fair value and subsequent changes in fair value are
recognized in equity through other comprehensive income, net of related taxes,
to the extent the hedge is effective. Instruments not qualifying for hedge
accounting treatment are recorded in the balance sheet and changes in fair value
are recognized in earnings.
At December 31, 2000, our oil put contracts were reflected as assets at a
historical cost of $4,999 and, in accordance with generally accepted accounting
principles in effect at year-end 2000, our fixed price gas swap contracts were
not recorded since they were costless. Our gas put contracts were purchased
subsequent to year-end and therefore were not reflected in the December 31, 2000
balance sheet. At December 31, 2000, the fair values of our oil put contracts
and fixed price gas swaps were $7,669 and ($42,846), respectively.
We adopted SFAS No. 133 effective January 1, 2001. Upon adoption of SFAS
No. 133, as amended, the after-tax increase in fair value over historical cost
of our oil put contracts of $1,735 was a transition adjustment that was recorded
as a gain in equity through other comprehensive income. In addition, the fair
market value of the fixed price gas swaps was recorded as a liability and the
corresponding after-tax loss of $27,850 was recorded in equity through other
comprehensive income. Our current hedge instruments are considered effective
cash flow hedges and changes in fair value of the hedge instruments are
reflected in other comprehensive income, net of related taxes.
NOTE 2 -- ACCOUNTS RECEIVABLE:
In our capacity as operator for our co-venturers, we incur drilling and
other costs that we bill to the respective parties based on their working
interests. We also receive payments for these billings and, in some cases, for
billings in advance of incurring costs. Our accounts receivable are comprised of
the following amounts:
December 31,
---------------------------------
2000 1999
-------------- --------------
Accounts Receivable:
Other co-venturers.............. $12,697 $7,733
Trade........................... 75,670 32,857
Officers and employees.......... 22 64
Unbilled accounts receivable.... 7,333 9,407
-------------- --------------
$95,722 $50,061
============== ==============
NOTE 3 -- CONCENTRATIONS:
SALES TO MAJOR CUSTOMERS
Our production is sold on month-to-month contracts at prevailing prices.
The following table identifies customers from whom we derived 10% or more of our
total oil and gas revenue during each of the twelve-month periods ended:
December 31,
----------------------------------------
2000 1999 1998
---------- ---------- ----------
Adams Resources Energy, Inc....... (a) 10% (a)
Columbia Energy Services.......... (a) 16% (a)
Conoco, Incorporated ............. (a) (a) 17%
Duke Energy Corporation .......... 11% (a) (a)
Dynegy, Incorporated ............. (a) 11% 11%
El Paso Merchant Energy, LP....... 13% (a) (a)
Enron North America Corporation... 10% (a) (a)
Northridge Energy Marketing....... (a) 12% (a)
(a) less than 10 percent.
Since alternative purchasers of oil and gas are readily available, we
believe that the loss of any of these purchasers would not result in a material
adverse effect on our ability to market future oil and gas production.
PRODUCTION VOLUMES
Production from South Pelto Block 23 and Eugene Island Block 243 accounted
for approximately 18% and 16%, respectively, of our total oil and gas production
volumes during 2000.
NOTE 4 -- INVESTMENT IN OIL AND GAS PROPERTIES:
The following table discloses certain financial data relative to our oil
and gas producing activities, which are located onshore and offshore the
continental United States:
Year Ended December 31,
-------------------------------------------------------
2000 1999 1998
--------------- --------------- ---------------
Oil and gas properties--
Balance, beginning of year..................................... $1,098,940 $904,456 $639,082
Costs incurred during year:
Capitalized--
Acquisition costs, net of sales of unevaluated properties (1) 15,086 27,316 42,933
Exploratory drilling....................................... 138,420 66,848 135,175
Development drilling....................................... 98,004 86,218 77,560
Employee, general and administrative costs and interest.... 19,234 15,440 10,965
Less: overhead reimbursements.............................. (1,600) (1,338) (1,259)
--------------- --------------- ---------------
Total costs incurred during year........................... 269,144 194,484 265,374
--------------- --------------- ---------------
Balance, end of year........................................... $1,368,084 $1,098,940 $904,456
=============== =============== ===============
Charged to expense--
Operating costs:
Normal lease operating expenses............................ $41,474 $33,372 $26,318
Major maintenance expenses................................. 6,538 1,115 1,278
--------------- --------------- ---------------
Total operating costs...................................... 48,012 34,487 27,596
Production taxes........................................... 7,607 2,933 2,853
--------------- --------------- ---------------
$55,619 $37,420 $30,449
=============== =============== ===============
Unevaluated oil and gas properties--
Costs incurred during year:
Acquisition costs.......................................... $22,760 $22,381 $32,858
Exploration costs.......................................... 6,229 806 610
--------------- --------------- ---------------
$28,989 $23,187 $33,468
=============== =============== ===============
Accumulated depreciation, depletion
and amortization--
Balance, beginning of year................................. ($511,279) ($412,107) ($201,250)
Provision for depreciation, depletion and amortization..... (109,231) (99,172) (96,507)
Write-down of oil and gas properties....................... - - (114,341)
Sale of reserves........................................... - - (9)
--------------- --------------- ---------------
Balance, end of year........................................... (620,510) (511,279) (412,107)
=============== =============== ===============
Net capitalized costs (proved and unevaluated)..................... $747,574 $587,661 $492,349
=============== =============== ===============
DD&A per Mcfe...................................................... $1.10 $1.08 $1.33
=============== =============== ===============
(1) Costs incurred during 1999 included non-cash additions of $20,272 related to acquisitions made through production payments.
At December 31, 2000 and 1999, unevaluated oil and gas properties of
$55,691 and $43,749, respectively, were not subject to depletion. Of the $55,691
in unevaluated costs at December 31, 2000, $28,989 was incurred in 2000 and
$26,702 was incurred in prior years. We believe that a majority of unevaluated
properties will be evaluated within one to 24 months.
NOTE 5 -- INCOME TAXES:
We follow the provisions of SFAS No. 109, "Accounting For Income Taxes,"
which provides for recognition of deferred taxes for deductible temporary timing
differences, operating loss carryforwards, statutory depletion carryforwards and
tax credit carryforwards net of a valuation allowance. An analysis of our
deferred tax liability follows:
Year Ended December 31,
----------------------------
2000 1999
------------ ------------
Net operating loss carryforward............... $8,056 $10,983
Statutory depletion carryforward.............. 4,527 4,770
Contribution carryforward..................... 112 80
Capital loss carryforward..................... 43 -
Alternative minimum tax credit carryforward... 1,142 698
Temporary differences:
Oil and gas properties-- full cost......... (83,773) (21,696)
Other...................................... 967 224
------------ ------------
($68,926) ($4,941)
============ ============
For tax reporting purposes, operating loss carryforwards totaled $23,000 at
December 31, 2000. If not utilized, such carryforwards would begin expiring in
2011 and would completely expire by the year 2020. In addition, we had $14,222
in statutory depletion deductions available for tax reporting purposes that may
be carried forward indefinitely. Recognition of a deferred tax asset associated
with these carryforwards is dependent upon our evaluation that it is more likely
than not that the asset will ultimately be realized.
During 1999, our provision for income taxes was net of a $1,460 reduction
in deferred taxes related to estimates of tax basis that were resolved during
1999. In order to conform Stone and Basin's accounting methods, we recognized
the $5,729 million tax benefit related to Basin's 1998 write-down of oil and gas
properties by reversing the valuation allowance that Basin recorded in 1998.
This resulted in additional deferred tax benefit for the year ended December 31,
1998 and deferred tax expense for the years ended December 31, 1999 and 2000.
During 1999 and 2000, Basin had previously reduced its effective tax rate
through the reversal of the valuation allowance recorded in 1998.
Reconciliations between the statutory federal income tax expense rate and our
effective income tax expense rate as a percentage of income before income taxes
were as follows:
Year Ended December 31,
------------------------
2000 1999 1998
------ ------ ------
Income tax expense (benefit) computed
at the statutory federal
income tax rate................... 35% 35% (35%)
Reduction in deferred taxes........... - (3%) -
------ ------ ------
Effective income tax rate............. 35% 32% (35%)
====== ====== ======
NOTE 6-- PRODUCTION PAYMENTS:
In June 1999, we acquired a 100% working interest in the Lafitte Field by
executing an agreement that included a dollar-denominated production payment to
be satisfied through the sale of production from the purchased property. At that
time, we recorded a production payment of $4,600 representing the estimated
discounted present value of production payments to be made. As provided for in a
separate agreement, on September 23, 1999, Goodrich Petroleum Company, L.L.C.
exercised its option to participate for a 49% working interest in the Lafitte
Field resulting in a reduction of the production payment to $2,346 at September
30, 1999. At December 31, 2000, the production payment associated with this
transaction totaled $1,943.
In July 1999, we acquired an additional working interest in East Cameron
Block 64 and a 100% working interest in West Cameron Block 176 in exchange for a
volumetric production payment. This agreement requires that 7.3 MMcf of gas per
day be delivered to the seller from South Pelto Block 23 until 8 Bcf of gas have
been distributed. At the transaction date, we recorded a volumetric production
payment of $17,926 representing the estimated discounted cash flows associated
with the specific production volumes to be delivered. We amortize the volumetric
production payment as specified deliveries of gas are made to the seller and
recognize non-cash revenue in the form of gas production revenue. At December
31, 2000, the volumetric production payment was $8,963 and $5,975 had been
recognized as gas revenue during 2000.
NOTE 7 -- LONG-TERM DEBT:
Long-term debt consisted of the following at:
December 31,
-----------------------
2000 1999
---------- ----------
8-3/4% Senior Subordinated Notes due 2007...... $100,000 $100,000
Basin Exploration revolving credit facility.... 48,000 34,000
---------- ----------
Total long-term debt........................... $148,000 $134,000
========== ==========
At December 31, 2000 and 1999, long-term debt included of $100,000 8-3/4%
Senior Subordinated Notes due 2007 and there were no minimum principal payments
due for the next five years. At December 31, 2000, $2,601 had been accrued in
connection with the March 2001 interest payment. The Notes were sold at a
discount for an aggregate price of $99,283. There are no sinking fund
requirements on the Notes and they are redeemable at our option, in whole or in
part, at 104.375% of their principal amount beginning September 15, 2002, and
thereafter at prices declining annually to 100% on and after September 15, 2005.
The Notes provide for certain covenants which include, without limitation,
restrictions on liens, indebtedness, asset sales, dividend payments and other
restricted payments.
At December 31, 2000, the borrowing base under Stone's credit facility had
no outstanding borrowings and outstanding letters of credit totaling $7,522 had
been issued pursuant to the facility. In February 2000, Stone's bank group
increased its credit facility from $150,000 to $200,000 and extended the
maturity date from July 30, 2001 to July 30, 2005. The borrowing base limitation
is re-determined periodically and is based on a borrowing base amount
established by the banks for our oil and gas properties. Our credit facility
provides for certain covenants, including restrictions or requirements with
respect to working capital, tangible net worth, disposition of properties,
incurrence of additional debt, change of ownership and reporting
responsibilities. These covenants may limit or prohibit us from paying cash
dividends.
At December 31, 2000, the borrowing base under Basin's credit facility was
$90,000 with $48,000 of outstanding borrowings. Concurrent with closing the
merger on February 1, 2001, all borrowings outstanding under Basin Exploration's
revolving credit facility were repaid with cash on hand and the credit facility
was terminated.
NOTE 8 -- TRANSACTIONS WITH RELATED PARTIES:
James H. Stone and Joe R. Klutts, both directors of Stone Energy,
collectively own 9% of the working interest in certain wells drilled on Section
19 on the east flank of Weeks Island Field. These interests were acquired at the
same time that our predecessor company acquired its interests in Weeks Island
Field. In their capacity as working interest owners, they are required to pay
their proportional share of all costs and are entitled to receive their
proportional share of revenues.
Our interests in certain oil and gas properties are burdened by various net
profit interests granted at the time of acquisition to certain of our officers
and other employees. Such net profit interest owners do not receive any cash
distributions until we have recovered all acquisition, development, financing
and operating costs. We believe the estimated value of these interests at the
time of acquisition is not material to our financial position or results of
operations. Effective January 1, 2001, we acquired the net profit interests from
our employees through a final settlement payment and discontinued this benefit
program. Certain of our officers remain net profit interest owners.
We received certain fees as a result of our function as managing partner of
certain partnerships. These partnerships were dissolved on December 31, 1999.
All participants in the partnerships, including four of our directors, James H.
Stone, Joe R. Klutts, Raymond B. Gary and Robert A. Bernhard, received
overriding royalty interests in the related properties in exchange for their
partnership interests. For the years ended December 31, 1999 and 1998,
management fees and overhead reimbursements from partnerships totaled $224 and
$834, respectively, the majority of which was treated as a reduction of our
investment in oil and gas properties.
Until their dissolution, we collected and distributed production revenue as
managing partner for the partnerships' interests in oil and gas properties.
In June 2000, we purchased property, that adjoins our Lafayette office,
from StoneWall Associates for an independently appraised value of approximately
$540. Two of our directors, James H. Stone and Joe R. Klutts, are partners of
StoneWall Associates.
Laborde Marine Lifts, Inc., a company of which John P. Laborde, one of our
directors and Audit Committee members, is Chairman, provided services to us
during 2000. The value of these services was approximately $75.
The law firm of Gordon, Arata, McCollam, Duplantis and Eagan, of which B.J.
Duplantis, one of our directors and Audit Committee members, is a Senior
Partner, provided legal services for us during 2000. The value of these services
totaled approximately $9.
NOTE 9 -- HEDGING ACTIVITIES:
We enter into hedging transactions to secure a price for a portion of
future production that is acceptable at the time at which the transaction is
entered. These futures contracts qualify as hedging activities. The primary
objective of these activities is to reduce our exposure to the possibility of
declining oil and gas prices during the term of the hedge. We do not enter into
hedging transactions for trading purposes. Monthly settlements of these
contracts are reflected in revenue from oil and gas production. Under generally
accepted accounting principles in effect at year-end 2000, in order to consider
these futures contracts as hedges, (i) we must designate the futures contract as
a hedge of future production and (ii) the contract must be effective at reducing
our exposure to the risk of changes in prices. Changes in the market value of
futures contracts treated as hedges are not recognized in income until the
hedged item is also recognized in income. If the above criteria are not met, we
will record the market value of the contract at the end of each month and
recognize a related increase or decrease in oil and gas revenue. Any proceeds
received or paid related to terminated contracts or contracts that have been
sold are amortized over the original contract period and reflected in revenue
from oil and gas production.
At December 31, 2000, our oil puts were reflected as assets at a historical
cost of $4,999. Put contracts are purchased at a rate per unit of hedged
production that fluctuates with the commodity futures market. The historical
cost of the put contracts represents our maximum cash exposure. We are not
obligated to make any further payments under the put contracts regardless of
future commodity price fluctuations. Under put contracts, monthly payments are
made to us if NYMEX prices fall below the agreed upon floor price, while
allowing us to fully participate in commodity prices above that floor.
In addition to put contracts, we utilized fixed price swaps to hedge a
portion of our future gas production. Fixed price swaps typically provide for
monthly payments by us if NYMEX prices rise above the fixed swap price or to us
if NYMEX prices fall below the fixed swap price.
Since over 90% of our production has historically been derived from the
Gulf Coast Basin, we believe that fluctuations in NYMEX prices will closely
match changes in the market prices we receive for our production. Oil contracts
typically settle using the average of the daily closing prices for a calendar
month. Natural gas contracts typically settle using the average closing prices
for near month NYMEX futures contracts for the three days prior to the
settlement date.
The following table shows our hedging position as of February 23, 2001.
Puts
----------------------------------------------------------------------------------------------
Gas Oil
-------------------------------------------- ---------------------------------------------
Volume Volume
(BBtus) Floor Cost (Bbls) Floor Cost
----------- ----------- ------------ ----------- ------------- -------------
2001 (1)................. 22,000 $3.50 $1,265 1,277,500 $25.00 $1,847
2002..................... 21,900 $3.50 $5,201 1,277,500 $24.00 $3,152
(1) The hedged volumes related to the 2001 gas put contracts are from April 2001 - December 2001.
Fixed Price Gas Swaps
-------------------------------------
Volume (BBtus) Price
---------------- ----------------
2001...................... 7,300 $2.33
2002...................... 3,650 $2.15
2003...................... 3,650 $2.15
For the years ended December 31, 2000, 1999 and 1998, we realized net
increases (decreases) in oil and gas revenue related to hedging transactions of
($47,899), ($11,295) and $7,797, respectively.
NOTE 10 -- COMMON STOCK:
In connection with the Basin merger, our stockholders approved a proposal
on February 1, 2001 to amend our certificate of incorporation in order to
increase the number of authorized shares of our common stock from 25,000,000 to
100,000,000.
On July 28, 1999, Stone Energy completed an offering of 3,162,500 shares of
its common stock at a price to the public of $43.75 per share. After payment of
the underwriting discount and related expenses, Stone received net proceeds of
$130,760.
On June 23, 1999, Basin Exploration completed an offering of 4,312,500
shares (approximately 1,713,788 shares post merger) of its common stock at a
price to the public of $16.50 per share (approximately $41.52 per share post
merger). After payment of the underwriting discount and related expenses, Basin
received net proceeds of $66,638.
In connection with the acquisition of Sterling Energy Corporation in
November 1994, Basin issued warrants to purchase 300,000 shares (approximately
119,220 shares post merger) of Basin common stock at an exercise price of $14.00
per share (approximately $35.23 per share post merger). These warrants became
exercisable on October 13, 1994. During 1999 and 1998, 122,572 and 79,145
warrants (approximately 48,710 and 31,452 warrants post merger) were exercised,
respectively. The remaining 49,760 warrants (approximately 19,775 warrants post
merger) expired on December 31, 1999.
During 1998, Stone Energy's Board of Directors authorized the adoption of a
stockholder rights plan to protect and advance its interests and those of its
stockholders in the event of a proposed takeover. The plan provides for the
issuance of one right for each outstanding share of common stock. The rights
will become exercisable only if a person or group acquires 15% or more of the
combined outstanding voting stock or announces a tender or exchange offer that
would result in ownership of 15% or more of the combined voting stock. The
rights were issued on October 26, 1998 to Stone Energy stockholders of record on
that date, and expire on September 30, 2008.
NOTE 11 -- COMMITMENTS AND CONTINGENCIES:
We lease office facilities in New Orleans, Louisiana, Denver, Colorado and
at two locations in Houston, Texas under the terms of long-term, non-cancelable
leases expiring on April 4, 2003, March 15, 2005 and December 31, 2004 and May
31, 2006, respectively. We also lease automobiles under the terms of
non-cancelable leases expiring at various dates through 2003. The minimum net
annual commitments under all leases, subleases and contracts noted above at
December 31, 2000 were as follows:
2001............................... $1,165
2002................................ 1,269
2003................................ 1,248
2004................................ 1,268
2005................................ 508
Thereafter.......................... 98
Payments related to our lease obligations for the years ended December 31,
2000, 1999 and 1998 were approximately $1,146, $859 and $1,228, respectively. We
sublease office space to third parties, and for the years ended 2000, 1999 and
1998 we recorded related receipts of $181, $186 and $506, respectively.
Until December 31, 1999, we were the managing general partner of eight
partnerships and are contingently liable for any recourse debts and other
liabilities that resulted from their operations until dissolution. We are not
aware of the existence of any such liabilities that would have a material impact
on future operations.
In August 1989, we were advised by the EPA that it believed we were a
potentially responsible party (a "PRP") for the cleanup of an oil field waste
disposal facility located near Abbeville, Louisiana, which was included on
CERCLA's National Priority List (the "Superfund List") by the EPA in March 1989.
Although we did not dispose of wastes or salt water at this site, the EPA
contends that transporters of salt water may have rinsed their trucks' tanks at
this site. By letter dated December 9, 1998, the EPA made demand for cleanup
costs on 23 of the PRP's, including us, who had not previously settled with the
EPA. Since that time we, together with other PRPs, have been negotiating the
settlement of our respective potential liability for environmental conditions at
this site with the U.S. Department of Justice. Given the number of PRP's at this
site and the current satisfactory progress of these negotiations, we do not
believe that any liability for this site would have a material adverse affect on
our financial condition. A tentative settlement has been reached with the U.S.
Department of Justice regarding our potential liability at this site. The amount
of this tentative settlement is immaterial to our financial statements. However,
the settlement has not been formally approved by all parties, and we cannot
assure you that a settlement will be formally approved.
We are contingently liable to surety insurance companies in the aggregate
amount of $19,346 relative to bonds issued on behalf of Stone and Basin to the
MMS, federal and state agencies and certain third parties from which we
purchased oil and gas working interests. The bonds represent guarantees by the
surety insurance companies that we will operate in accordance with applicable
rules and regulations and perform certain plugging and abandonment obligations
as specified by applicable working interest purchase and sale agreements.
We are also named as a defendant in certain lawsuits and are a party to
certain regulatory proceedings arising in the ordinary course of business. We do
not expect these matters, individually or in the aggregate, to have a material
adverse effect on our financial condition.
OPA imposes ongoing requirements on a responsible party, including the
preparation of oil spill response plans and proof of financial responsibility to
cover environmental cleanup and restoration costs that could be incurred in
connection with an oil spill. Under OPA and the MMS's August 1998 final rule,
responsible parties of offshore facilities must provide financial assurance in
the amount of $35,000 to cover potential OPA liabilities. This amount can be
increased up to $150,000 if a formal risk assessment indicates that an amount
higher than $35,000 should be required. We do not anticipate that we will
experience any difficulty in continuing to satisfy the MMS's requirements for
demonstrating financial responsibility under the current OPA and MMS's August
1998 final rule.
NOTE 12 -- EMPLOYEE BENEFIT PLANS:
We have entered into deferred compensation and disability agreements with
certain of our employees whereby we have purchased split-dollar life insurance
policies to provide certain retirement and death benefits for our employees and
death benefits payable to us. The aggregate death benefit of the policies was
$3,204 at December 31, 2000, of which $1,975 was payable to employees or their
beneficiaries and $1,229 was payable to us. Total cash surrender value of the
policies, net of related surrender charges at December 31, 2000, was
approximately $1,021. Additionally, the benefits under the deferred compensation
agreements vest after certain periods of employment, and at December 31, 2000,
the liability for such vested benefits was approximately $847. The difference
between the actuarial determined liability for retirement benefits or the vested
amounts, where applicable, and the net cash surrender value has been recorded as
an other long-term asset.
We have adopted a series of incentive compensation plans designed to align
the interests of our directors and employees with those of our stockholders. The
following is a brief description of each of the plans:
i. The Annual Incentive Compensation Program provides for an annual cash
incentive bonus that ties incentives to the annual return on our
common stock, to a comparison of the price performance of our common
stock to the average quarterly returns on the shares of stock of a
peer group of companies with which we compete and to the growth in our
net earnings, net cash flows and net asset value. Incentive bonuses
are awarded to participants based upon individual performance factors.
ii. The Nonemployee Directors' Stock Option Plan provides for the issuance
of up to 275,000 shares of common stock upon the exercise of such
options granted pursuant to this plan. Generally, options outstanding
under the Nonemployee Directors' Stock Option Plan: (a) are granted at
prices that equate to the fair market value of the common stock on
date of grant, (b) vest ratably over a three year service vesting
period, and (c) expire five years subsequent to award.
iii. The 2000 Amended and Restated Stock Option Plan provides for 2,500,000
shares of common stock to be reserved for issuance pursuant to this
plan. Under this plan, we may grant both incentive stock options
qualifying under Section 422 of the Internal Revenue Code and options
that are not qualified as incentive stock options to all employees.
All such options: (a) must have an exercise price of not less than the
fair market value of the common stock on the date of grant, (b) vest
ratably over a five year service vesting period, and (c) expire ten
years subsequent to award.
iv. The Stone Energy 401(k) Profit Sharing Plan provides eligible
employees with the option to defer receipt of a portion of their
compensation and we may, at our discretion, match a portion or all of
the employee's deferral. The amounts held under the plan are invested
in various investment funds maintained by a third party in accordance
with the directions of each employee. An employee is 20% vested in
matching contributions (if any) for each year of service and is fully
vested upon five years of service. For the years ended December 31,
2000, 1999 and 1998, Stone contributed $445, $313 and $270,
respectively, to the plan.
The following Basin benefit plans were in effect during the periods
presented but were terminated upon consummation of the merger on February 1,
2001. The following share amounts do not reflect the conversion factor of .3974
of a share of Stone common stock for each share of Basin common stock:
i. Basin Exploration had a 401(k) profit sharing plan. All Basin
employees who joined Stone were eligible to participate in Stone's
401(k) plan based on years of service with Basin. During 2000, 1999
and 1998, Basin contributed $383, $241 and $208, respectively, to the
Basin 401(k) profit sharing plan.
ii. Under the Equity Incentive Plan, Basin's officers, key employees,
consultants and directors were eligible to receive incentive stock
options, non-qualified stock options, restricted stock and performance
shares. At December 31, 2000, approximately 1,599,000 shares were
available for grant under the plan. Of this total, an aggregate of
1,283,000 shares of Basin common stock were subject to prior issuances
under such plan, including 182,000 non-vested shares of restricted
stock and performance shares and 1,100,000 outstanding stock options.
Basin granted 19,000 and 59,000 shares of restricted stock during 2000
and 1998, respectively. Approximately $291, $466 and $409 of related
compensation expense was recognized during 2000, 1999 and 1998,
respectively. Cumulatively through December 31, 2000, 98,000 shares of
restricted stock had been forfeited, 101,000 shares were no longer
subject to restriction and 101,000 shares of restricted stock remained
subject to forfeiture.
Basin granted 50,000, 55,000 and 50,000 performance shares during
2000, 1999 and 1998, respectively. Expense was recognized based on
vesting schedules, projections of performance and changes in the price
of Basin common stock during the applicable vesting periods. Related
compensation expense of $640, $1,593 and $367 was recognized during
the years ended 2000, 1999 and 1998, respectively.
During the third quarter of 1998, Stone's Board of Directors elected to
reprice all non-Director employee stock options that had an exercise price above
the then market value of $26.00 per share. As a result, 265,000 stock options,
which were granted to non-Director employees during 1997 and 1998, were repriced
from a weighted average exercise price of $29.35 per share to the then market
value of $26.00 per share.
In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation," which became effective with respect to us in 1996. Under SFAS No.
123, companies can either record expense based on the fair value of stock-based
compensation upon issuance or elect to remain under the current Accounting
Principles Board Opinion No. 25 ("APB 25") method whereby no compensation cost
is recognized upon grant if certain requirements are met. We have continued to
account for our stock-based compensation under APB 25. However, disclosures as
if we adopted the cost recognition requirements under SFAS No. 123 are presented
below.
If the compensation cost for stock-based compensation plans had been
determined consistent with SFAS No. 123, our 2000, 1999 and 1998 net income
(loss) and basic and diluted earnings (loss) per common share would have
approximated the pro forma amounts below:
Year Ended December 31,
--------------------------------------------------------------------------------
2000 1999 1998
----------------------- ----------------------- -----------------------
As Reported Pro Forma As Reported Pro Forma As Reported Pro Forma
----------- --------- ----------- --------- ------------ ---------
Net income (loss)............. $126,457 $121,248 $37,066 $33,957 ($66,524) ($68,849)
Earnings (loss) per common
share:
Basic................... $4.90 $4.70 $1.61 $1.48 ($3.23) ($3.35)
Diluted................. $4.80 $4.60 $1.58 $1.45 ($3.23) ($3.35)
A summary of stock options as of December 31, 2000, 1999 and 1998 and
changes during the years ended on those dates is presented below.
Year Ended December 31,
--------------------------------------------------------------------------------------------
2000 1999 1998
---------------------------- ---------------------------- --------------------------
Wgtd. Wgtd. Wgtd.
Number Avg. Number Avg. Number Avg.
of Exer. of Exer. of Exer.
Options Price Options Price Options Price
------------- -------- --------------- --------- -------------- --------
Outstanding at beginning of year.... 1,771,668 $27.22 1,428,029 $21.95 1,267,389 $18.89
Granted............................. 455,045 51.92 530,197 37.47 237,103 36.25
Expired............................. (13,000) 23.95 (34,923) 22.73 - -
Exercised........................... (333,636) 20.52 (151,635) 15.96 (76,463) 12.55
------------- --------------- --------------
Outstanding at end of year.......... 1,880,077 $34.39 1,771,668 $27.22 1,428,029 $21.95
Options exercisable at year-end..... 808,072 24.48 782,082 20.29 672,486 17.85
Options available for future grant.. 957,250 299,750 346,000
Weighted average fair value of
options granted during the year.. $28.65 $22.87 $21.18
The weighted average fair value of each option granted during the periods
presented is estimated on the date of grant using the Black-Scholes
option-pricing model with the following assumptions: (a) dividend yield of 0%,
(b) expected volatility of 45.72%, 47.18% and 52.05% in the years 2000, 1999 and
1998, respectively, (c) risk-free interest rate of 6.76%, 6.07% and 5.64% in the
years 2000, 1999 and 1998, respectively and (d) expected life of six years for
employee options and four years for director options.
The following table summarizes information regarding stock options
outstanding at December 31, 2000:
Options Outstanding Options Exercisable
---------------------------------------------------------------------- ----------------------------
Range of Options Wgtd. Avg. Wgtd. Avg. Options Wgtd. Avg.
Exercise Outstanding Remaining Exercise Exercisable Exercise
Prices at 12/31/00 Contractual Life Price at 12/31/00 Price
----------------- --------------- --------------------- --------------- -------------- -------------
$9 - $20 254,767 4.1 years $12.85 254,767 $12.85
20 - 30 573,848 6.1 years 24.38 328,851 23.69
30 - 40 518,887 7.3 years 35.53 160,413 35.57
40 - 50 133,046 8.1 years 44.31 46,476 44.22
50 - 61.93 399,529 8.7 years 57.74 17,565 54.28
-------------- --------------
1,880,077 6.9 years 34.39 808,072 24.48
============== ==============
NOTE 13 -- OIL AND GAS RESERVE INFORMATION - UNAUDITED:
Our net proved oil and gas reserves at December 31, 2000 have been
estimated by independent petroleum consultants in accordance with guidelines
established by the Securities and Exchange Commission ("SEC"). Accordingly, the
following reserve estimates are based upon existing economic and operating
conditions at the respective dates.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in providing the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. In addition, the present values
should not be construed as the market value of the oil and gas properties or the
cost that would be incurred to obtain equivalent reserves.
The following table sets forth an analysis of the estimated quantities of
net proved and proved developed oil (including condensate) and natural gas
reserves, all of which are located onshore and offshore the continental United
States:
Oil in Natural Gas
MBbls in MMcf
-------------- -------------
Proved reserves as of December 31, 1997..................................... 25,917 278,773
Revisions of previous estimates......................................... (2,487) (3,974)
Extensions, discoveries and other additions............................. 6,410 128,824
Purchase of producing properties........................................ 904 18,046
Production.............................................................. (3,601) (50,897)
-------------- -------------
Proved reserves as of December 31, 1998.................................... 27,143 370,772
Revisions of previous estimates......................................... 3,961 (7,027)
Extensions, discoveries and other additions............................. 3,305 67,001
Purchase of producing properties........................................ 5,128 19,101
Production (1).......................................................... (4,324) (64,180)
-------------- -------------
Proved reserves as of December 31, 1999..................................... 35,213 385,667
Revisions of previous estimates......................................... (3,568) (10,499)
Extensions, discoveries and other additions............................. 6,375 85,534
Purchase of producing properties........................................ 54 7,394
Production (1).......................................................... (4,449) (69,572)
-------------- -------------
Proved reserves as of December 31, 2000..................................... 33,625 398,524
============== =============
Proved developed reserves:
as of December 31, 1998................................................. 18,594 304,244
============== =============
as of December 31, 1999................................................. 25,194 309,696
============== =============
as of December 31, 2000................................................. 25,374 307,320
============== =============
(1) Excludes gas production volumes related to the volumetric production
payment. See "Note 6 - Production Payments."
The following tables present the standardized measure of future net cash
flows related to proved oil and gas reserves together with changes therein, as
defined by the FASB. You should not assume that the future net cash flows or the
discounted future net cash flows, referred to in the table below, represent the
fair value of our estimated oil and gas reserves. As required by the SEC, we
determine future cash flows using market prices for oil and gas on the last day
of the fiscal period. The average 2000 year-end product prices for all of our
properties were $27.30 per barrel of oil and $9.97 per Mcf of gas. During 2001,
market prices for oil and gas have decreased, which would result in a reduction
of future cash flows if recomputed. Future production and development costs are
based on current costs with no escalations. Estimated future cash flows net of
future income taxes have been discounted to their present values based on a 10%
annual discount rate.
Standardized Measure
Year Ended December 31,
------------------------------------------------------------
2000 1999 1998
---------------- ---------------- ----------------
Future cash flows.............................................. $4,902,297 $1,806,565 $1,012,979
Future production and development costs........................ (701,533) (613,129) (408,434)
Future income taxes............................................ (1,392,078) (215,879) (40,303)
---------------- --------------- ---------------
Future net cash flows.......................................... 2,808,686 977,557 564,242
10% annual discount............................................ (825,937) (286,076) (145,839)
---------------- --------------- ---------------
Standardized measure of discounted future net cash flows....... $1,982,749 $691,481 $418,403
================ =============== ===============
Changes in Standardized Measure
Year Ended December 31,
-----------------------------------------------------
2000 1999 1998
-------------- -------------- --------------
Standardized measure at beginning of year...................... $691,481 $418,403 $431,822
Sales and transfers of oil and gas produced, net of
production costs........................................... (368,243) (178,007) (132,768)
Changes in price, net of future production costs............... 1,784,727 326,300 (207,964)
Extensions and discoveries, net of future production
and development costs...................................... 656,944 138,945 203,488
Changes in estimated future development costs, net of
development costs incurred during the period............... 30,608 13,348 26,458
Revisions of quantity estimates................................ (162,462) 28,735 (12,563)
Accretion of discount.......................................... 83,064 45,059 52,886
Net change in income taxes..................................... (819,893) (108,160) 66,070
Purchases of reserves in place................................. 48,752 60,065 17,858
Changes in production rates due to timing and other............ 37,771 (53,207) (26,884)
-------------- -------------- --------------
Standardized measure at end of year............................ $1,982,749 $691,481 $418,403
============== ============== ==============
NOTE 14 -- SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED:
Basic Diluted
Net Earnings Earnings
Revenues Expenses Income Per Share Per Share
------------- ------------- ------------- ------------- -------------
2000
First Quarter........... $70,869 $53,097 $17,772 $0.69 $0.68
Second Quarter.......... 84,302 59,007 25,295 0.98 0.96
Third Quarter........... 109,547 72,165 37,382 1.45 1.42
Fourth Quarter.......... 121,448 75,440 46,008 1.78 1.74
------------- ------------- -------------
$386,166 $259,709 $126,457 4.90 4.80
============= ============= =============
1999
First Quarter........... $43,977 $42,573 $1,404 $0.07 $0.07
Second Quarter.......... 56,585 48,468 8,117 0.39 0.38
Third Quarter........... 60,490 48,082 12,408 0.50 0.49
Fourth Quarter.......... 59,712 44,575 15,137 0.59 0.58
------------- ------------- -------------
$220,764 $183,698 $37,066 1.61 1.58
============= ============= =============
The quarterly financial information for the first quarter of 2000 differs
from amounts previously filed due to a change in Stone's treatment of its tax
valuation allowance.
ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS
------------------------------------------
(c) Exhibits
23.1 -- Consent of Arthur Andersen LLP.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this Report to be signed on its behalf by the
undersigned thereunto duly authorized.
STONE ENERGY CORPORATION
Date: September 19, 2001 By: /s/ James H. Prince
----------------------
James H. Prince
Chief Financial Officer