SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2000
Commission File Number 1-8754
SWIFT ENERGY COMPANY
(Exact Name of Registrant as Specified in its Charter)
TEXAS 74-2073055
(State of Incorporation) (I.R.S. Employer Identification No.)
16825 Northchase Drive, Suite 400
Houston, Texas 77060
(281) 874-2700
(Address and telephone number of principal executive offices)
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the Registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
----------- ------------
Indicate the number of shares outstanding of each of
the Registrant's classes of common stock, as
of the latest practicable date.
Common Stock 22,171,465 Shares
($.01 Par Value) (Outstanding at July 31, 2000)
(Class of Stock)
<PAGE>
SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2000
INDEX
<TABLE>
<CAPTION>
<S> <C>
PART I. FINANCIAL INFORMATION PAGE
Item 1. Condensed Consolidated Financial Statements
Condensed Consolidated Balance Sheets
- June 30, 2000 and December 31, 1999 3
Condensed Consolidated Statements of Income
- For the Three-month and Six-month periods ended
June 30, 2000 and 1999 5
Condensed Consolidated Statements of Stockholders' Equity
- June 30, 2000 and December 31, 1999 6
Condensed Consolidated Statements of Cash Flows
- For the Six-month periods ended June 30, 2000 and 1999 7
Notes to Condensed Consolidated Financial Statements 8
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 13
Item 3. Quantitative and Qualitative Disclosures About Market Risk 20
PART II. OTHER INFORMATION
Item 1. Legal Proceedings None
Item 2. Changes in Securities and Use of Proceeds None
Item 3. Defaults Upon Senior Securities None
Item 4. Submission of Matters to a Vote of Security Holders 21
Item 5. Other 21
Item 6. Exhibits and Reports on Form 8-K 21
SIGNATURES 22
</TABLE>
2
<PAGE>
SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
June 30, 2000 December 31, 1999
--------------- -----------------
(Unaudited)
ASSETS
<S> <C> <C>
Current Assets:
Cash and cash equivalents $ 36,212,108 $ 22,685,648
Accounts receivable -
Oil and gas sales 22,950,516 15,634,019
Associated limited partnerships
and joint ventures 4,006,393 5,359,596
Joint interest owners 4,222,188 5,550,048
Other current assets 1,361,017 1,376,177
--------------- -----------------
Total Current Assets 68,752,222 50,605,488
--------------- -----------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized 621,122,973 573,360,199
Unproved properties not being amortized 63,032,057 57,662,739
--------------- -----------------
684,155,030 631,022,938
Furniture, fixtures, and other equipment 8,303,568 7,778,571
--------------- -----------------
692,458,598 638,801,509
Less-Accumulated depreciation, depletion,
and amortization (265,943,962) (242,966,019)
--------------- -----------------
426,514,636 395,835,490
--------------- -----------------
Other Assets:
Receivables from associated limited
partnerships, net of current portion --- 628,228
Deferred charges 6,853,354 7,230,208
--------------- -----------------
6,853,354 7,858,436
--------------- -----------------
$ 502,120,212 $ 454,299,414
=============== =================
</TABLE>
See accompanying notes to condensed consolidated financial statements.
3
<PAGE>
SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
June 30, 2000 December 31, 1999
--------------- -----------------
(Unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
<S> <C> <C>
Current Liabilities:
Accounts payable and accrued liabilities $ 31,289,733 $ 25,674,143
Payable to associated limited partnerships 638,979 609,967
Undistributed oil and gas revenues 10,979,135 7,785,975
--------------- -----------------
Total Current Liabilities 42,907,847 34,070,085
--------------- -----------------
Long-Term Debt 239,098,143 239,068,423
Deferred Revenues 180,458 576,658
Deferred Income Taxes 21,624,171 10,180,131
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000
shares authorized, none outstanding --- ---
Common stock, $.01 par value, 35,000,00
shares authorized, 22,170,565 and 21,683,185
shares issued, and 21,326,761 and 20,823,729
shares outstanding, respectively 221,706 216,832
Additional paid-in capital 194,965,882 191,092,851
Treasury stock held, at cost, 843,804 and 859,456
shares, respectively (12,101,199) (12,325,668)
Retained earnings (deficit) 15,223,204 (8,579,898)
--------------- -----------------
198,309,593 170,404,117
--------------- -----------------
$ 502,120,212 $ 454,299,414
=============== =================
</TABLE>
See accompanying notes to condensed consolidated financial statements.
4
<PAGE>
SWIFT ENERGY COMPANY
Condensed Consolidated Statements of Income
(UNAUDITED)
<TABLE>
<CAPTION>
Three months ended Six months ended
---------------------------------- ----------------------------------
06/30/00 06/30/99 06/30/00 06/30/99
-------------- -------------- -------------- --------------
Revenues:
<S> <C> <C> <C> <C>
Oil and gas sales $ 45,502,573 $ 23,572,785 $ 82,686,664 44,668,421
Fees from limited partnerships
and joint ventures 76,092 57,272 119,166 99,649
Interest income 371,211 9,538 638,642 23,282
Other, net 177,499 289,139 430,548 625,469
-------------- -------------- -------------- --------------
46,127,375 23,928,734 83,875,020 45,416,821
-------------- -------------- -------------- --------------
Costs and Expenses:
General and administrative, net
of reimbursement 1,459,737 1,184,612 2,607,525 2,294,286
Depreciation, depletion, and amortization 11,550,774 10,478,278 23,021,628 21,226,751
Oil and gas production 6,888,069 4,130,804 13,032,141 8,550,948
Interest expense, net 4,010,437 3,348,635 8,076,324 6,653,012
-------------- -------------- -------------- --------------
23,909,017 19,142,329 46,737,618 38,724,997
-------------- -------------- -------------- --------------
Income before Income Taxes 22,218,358 4,786,405 37,137,402 6,691,824
Provision for Income Taxes 8,005,084 1,634,378 13,334,300 2,258,042
-------------- -------------- -------------- --------------
Net Income $ 14,213,274 $ 3,152,027 $ 23,803,102 $ 4,433,782
============== ============== ============== ==============
Per share amounts -
Basic: $ 0.68 $ 0.20 $ 1.14 $ 0.27
============== ============== ============== ==============
Diluted: $ 0.61 $ 0.20 $ 1.04 $ 0.27
============== ============== ============== ==============
Weighted Average Shares Outstanding 21,007,545 16,151,514 20,928,081 16,153,982
============== ============== ============== ==============
</TABLE>
See accompanying notes to condensed consolidated financial statements.
5
<PAGE>
SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Additional
Common Paid-In Treasury Retained
Stock(1) Capital Stock Earnings Total
----------- -------------- -------------- -------------- -------------
<S> <C> <C> <C> <C> <C>
Balance, December 31, 1998 $ 169,725 $ 148,901,270 $ (11,841,884) $ (27,866,472) $ 109,362,639
Stock issued for benefit plans
(90,738 shares) 224 (366,408) 978,956 --- 612,772
Stock options exercised
(65,477 shares) 655 461,102 --- --- 461,757
Employee stock purchase plan
(22,771 shares) 228 181,577 --- --- 181,805
Public stock offering
(4,600,000 shares) 46,000 41,915,310 --- --- 41,961,310
Purchase of 246,500 shares as
treasury stock --- --- (1,462,740) --- (1,462,740)
Net income --- --- --- 19,286,574 19,286,574
----------- -------------- -------------- -------------- -------------
Balance, December 31, 1999 $ 216,832 $ 191,092,851 $ (12,325,668) $ (8,579,898) $ 170,404,117
=========== ============== ============== ============== =============
Stock issued for benefit plans
(46,632 shares)(2) 310 297,060 224,469 --- 521,839
Stock options exercised
(426,511 shares)(2) 4,265 3,278,557 --- --- 3,282,822
Employee stock purchase plan
(29,889 shares) (2) 299 297,414 --- --- 297,713
Net income (2) --- --- --- 23,803,102 23,803,102
----------- -------------- -------------- -------------- -------------
Balance, June 30, 2000 (2) $ 221,706 $ 194,965,882 $ (12,101,199) $ 15,223,204 $ 198,309,593
=========== ============== ============== ============== =============
</TABLE>
(1) $.01 Par Value
(2) Unaudited
See accompanying notes to condensed consolidated financial statements.
6
<PAGE>
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
Period Ended June 30,
----------------------------------
2000 1999
-------------- --------------
<S> <C> <C>
Cash Flows From Operating Activities:
Net income $ 23,803,102 $ 4,433,782
Adjustments to reconcile net income to net cash provided
by operating activities -
Depreciation, depletion, and amortization 23,021,628 21,226,751
Deferred income taxes 13,011,040 2,157,818
Deferred revenue amortization related to production payment (414,025) (557,616)
Other 406,574 257,572
Change in assets and liabilities -
(Increase) decrease in accounts receivable (5,847,463) 1,373,493
Increase (decrease) in accounts payable and accrued
liabilities, excluding income taxes payable 1,367,883 (702,149)
Increase in income taxes payable --- 113,569
-------------- --------------
Net Cash Provided by Operating Activities 55,348,739 28,303,220
-------------- --------------
Cash Flows From Investing Activities:
Additions to property and equipment (51,150,928) (23,190,252)
Proceeds from the sale of property and equipment 758,643 1,746,559
Net cash received (distributed) as operator of
oil and gas properties 4,887,289 (1,354,867)
Net cash received as operator of partnerships
and joint ventures 1,353,203 3,243,695
Limited partnership formation and marketing costs --- (648,637)
Other (25,860) (183,267)
-------------- --------------
Net Cash Used in Investing Activities (44,177,653) (20,386,769)
-------------- --------------
Cash Flows From Financing Activities:
Net payments of bank borrowings --- (6,200,000)
Net proceeds from issuances of common stock 2,355,374 476,971
Purchase of treasury stock --- (1,462,740)
-------------- --------------
Net Cash Provided by (Used in) Financing Activities 2,355,374 (7,185,769)
-------------- --------------
Net Increase in Cash and Cash Equivalents 13,526,460 730,682
Cash and Cash Equivalents at Beginning of Period 22,685,648 1,630,649
-------------- --------------
Cash and Cash Equivalents at End of Period $ 36,212,108 $ 2,361,331
============== ==============
Supplemental disclosures of cash flows information:
Cash paid during period for interest, net of amounts capitalized $ 7,562,978 $ 6,395,440
Cash paid during period for income taxes $ --- $ ---
</TABLE>
See accompanying notes to condensed consolidated financial statements.
7
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000 (UNAUDITED) AND DECEMBER 31, 1999
(1) GENERAL INFORMATION
The condensed consolidated financial statements included herein have
been prepared by Swift Energy Company and are unaudited, except for the
balance sheet at December 31, 1999, which has been prepared from the
audited financial statements at that date. The financial statements
reflect necessary adjustments, all of which were of a recurring nature,
and are in the opinion of our management necessary for a fair
presentation. Certain information and footnote disclosures normally
included in financial statements prepared in accordance with accounting
principles generally accepted in the United States have been omitted
pursuant to the rules and regulations of the Securities and Exchange
Commission. We believe that the disclosures presented are adequate to
allow the information presented not to be misleading. The condensed
consolidated financial statements should be read in conjunction with the
audited financial statements and the notes thereto included in the latest
Form 10-K and Annual Report.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Oil and Gas Properties
----------------------
We follow the "full-cost" method of accounting for oil and gas property
and equipment costs. Under this method of accounting, all productive and
nonproductive costs incurred in the acquisition, exploration, and
development of oil and gas reserves are capitalized. Under the full-cost
method of accounting, such costs may be incurred both prior to or after
the acquisition of a property and include lease acquisitions, geological
and geophysical services, drilling, completion, equipment, and certain
general and administrative costs directly associated with acquisition,
exploration, and development activities. Interest costs related to
unproved properties are also capitalized to unproved oil and gas
properties. General and administrative costs related to production and
general overhead are expensed as incurred.
At the end of each quarterly reporting period, the unamortized cost of
oil and gas properties, net of related deferred income taxes, is limited
to the sum of the estimated future net revenues from proved properties
using current period-end prices, discounted to present value at 10% per
annum, and the lower of cost or fair value of unproved properties,
adjusted for related income tax effects ("Ceiling Test"). This calculation
is done on a country-by-country basis for those countries with proved
reserves. Currently, we have proved reserves in the United States only.
No gains or losses are recognized upon the sale or disposition of oil
and gas properties, except in transactions that involve a significant
amount of reserves. The proceeds from the sale of oil and gas properties
are generally treated as a reduction of oil and gas property costs. Fees
from associated oil and gas exploration and development limited
partnerships are credited to oil and gas property costs to the extent they
do not represent reimbursement of general and administrative expenses
currently charged to expense.
Future development, site restoration, and dismantlement and abandonment
costs, net of salvage values, are estimated on a property-by-property
basis, based on current economic conditions, and are amortized to expense
as our capitalized oil and gas property costs are amortized. Our
properties are all onshore, and historically the salvage value of the
tangible equipment offsets our site restoration and dismantlement and
abandonment costs, which we expect to continue in the future.
8
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000 (UNAUDITED) AND DECEMBER 31, 1999-CONTINUED
We compute the provision for depreciation, depletion, and amortization
of oil and gas properties on the unit-of-production method. Under this
method, we compute the provision by multiplying the total unamortized
costs of oil and gas properties - including future development, site
restoration, and dismantlement and abandonment costs, but excluding costs
of unproved properties - by an overall rate determined by dividing the
physical units of oil and gas produced during the period by the total
estimated units of proved oil and gas reserves. This calculation is done
on a country-by-country basis for those countries with oil and gas
production.
The cost of unproved properties not being amortized is assessed
quarterly, on a country- by-country basis, to determine whether such
properties have been impaired. Any impairment assessed is added to the
cost of proved properties being amortized and is therefore subject to the
Ceiling Test. To the extent costs accumulated in countries that do not
have proved reserves, any impairment is charged to income. In determining
whether such costs should be impaired, our management evaluates, among
other factors, the results of drilling, current oil and gas industry
conditions, economic conditions, capital availability, foreign currency
exchange rates, the political stability in the countries in which we have
an investment, and available geological and geophysical information.
The calculation of the Ceiling Test and provision for depreciation,
depletion, and amortization is based on estimates of proved reserves.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production, timing,
and plan of development. The accuracy of any reserves estimate is a
function of the quality of available data and of engineering and
geological interpretation and judgment. Results of drilling, testing, and
production subsequent to the date of the estimate may justify revision of
such estimate. Accordingly, reserves estimates are often different from
the quantities of oil and gas that are ultimately recovered.
Use of Estimates
----------------
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to
make estimates and assumptions that affect the reported amounts of assets
and liabilities and disclosure of contingent assets and liabilities, if
any, at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Such estimates are based
on management's best information at the time and accordingly, actual
results in the subsequent reporting period could differ from estimates.
Earnings Per Share
------------------
Basic earnings per share ("Basic EPS") has been computed using the
weighted average number of common shares outstanding during the respective
periods.
The calculation of diluted earnings per share ("Diluted EPS") assumes
conversion of our convertible notes as of the beginning of the respective
periods and the elimination of the related after-tax interest expense and
assumes, as of the beginning of the period, exercise of stock options and
warrants using the treasury stock method. The assumed conversion of our
convertible notes has been excluded from the calculation of Diluted EPS
for the 1999 period as they would have been antidilutive for that period.
The following is a reconciliation of the calculation of Basic and Diluted
EPS for the three-month and six-month periods ended June 30, 2000 and
1999:
9
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000 (UNAUDITED) AND DECEMBER 31, 1999-CONTINUED
<TABLE>
<CAPTION>
Three Months Ended June 30,
--------------------------------------------------------------------------------
2000 1999
------------------------------------- --------------------------------------
Net Per Share Net Per Share
Income Shares Amount Income Shares Amount
------------ ---------- --------- ------------ ----------- ---------
<S> <C> <C> <C> <C> <C> <C>
Basic EPS:
Net Income and
Share Amounts $ 14,213,274 21,007,545 $ .68 $ 3,152,027 16,151,514 $ .20
Dilutive Securities:
6.25% Convertible Notes 1,213,074 3,646,847 --- ---
Stock Options --- 569,632 --- 4,442
------------ ---------- ------------ -----------
Diluted EPS:
Net Income and
Assumed Share
Conversions $ 15,426,348 25,224,024 $ .61 $ 3,152,027 16,155,956 $ .20
============ ========== ============ ===========
Six Months Ended June 30,
--------------------------------------------------------------------------------
2000 1999
------------------------------------- --------------------------------------
Net Per Share Net Per Share
Income Shares Amount Income Shares Amount
------------ ---------- --------- ------------ ----------- ---------
Basic EPS:
Net Income and
Share Amounts $ 23,803,102 20,928,081 $ 1.14 $ 4,433,782 16,153,982 $ .27
Dilutive Securities:
6.25% Convertible Notes 2,432,058 3,646,847 --- ---
Stock Options --- 569,632 --- 4,442
------------ ---------- ------------ -----------
Diluted EPS:
Net Income and
Assumed Share
Conversions $ 26,235,160 25,144,560 $ 1.04 $ 4,433,782 16,158,424 $ .27
============ ========== ============ ===========
</TABLE>
New Accounting Pronouncement
----------------------------
In June 1998, the Financial Accounting Standards Board issued SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities." The
Statement establishes accounting and reporting standards requiring that
every derivative instrument (including certain derivative instruments
embedded in other contracts) be recorded in the balance sheet as either an
asset or liability measured at its fair value. SFAS No. 133 requires that
changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special accounting for
qualifying hedges allows the gains and losses on derivatives to offset
related results on the hedged item in the income statements and requires
that a company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting. SFAS No. 133,
as amended by SFAS No. 137 "Accounting for Derivative Instruments and
Hedging Activities - Deferral of the Effective Date of FASB Statement No.
133" and as amended by SFAS No. 138 "Accounting for Certain Derivative
Instruments and Certain Hedging Activities - an Amendment of FASB
Statement No. 133"," is effective for fiscal years beginning after June
15, 2000. We are currently evaluating the new standard, but have not yet
determined the impact it will have on our financial position and results
of operations.
10
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000 (UNAUDITED) AND DECEMBER 31, 1999-CONTINUED
LONG-TERM DEBT
Our long-term debt as of June 30, 2000 and December 31, 1999, is as
follows (in thousands):
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
----------- ------------
<S> <C> <C>
Bank Borrowings $ --- $ ---
Convertible Notes 115,000 115,000
Senior Notes 124,098 124,068
----------- ------------
Long-Term debt $ 239,098 $ 239,068
----------- ------------
</TABLE>
Under our restated $250.0 million revolving credit facility with a
syndicate of nine banks, at June 30, 2000 and at December 31, 1999 we had
no outstanding borrowings, as previous borrowings were paid in full during
August 1999 with proceeds from our third quarter concurrent public
offerings of senior subordinated notes and common stock. At June 30, 2000,
the credit facility consisted of a $250.0 million secured revolving line
of credit with a $100 million borrowing base. The interest rate is either
(a) the lead bank's prime rate (9.5% at June 30, 2000) or (b) the adjusted
London Interbank Offered Rate ("LIBOR") plus the applicable margin
depending on the level of outstanding debt. The applicable margin is based
on the ratio of our outstanding balance on the credit facility to the last
calculated borrowing base.
The terms of the credit facility include, among other restrictions, a
limitation on the level of cash dividends (not to exceed $2.0 million in
any fiscal year), requirements as to maintenance of certain minimum
financial ratios (principally pertaining to working capital, debt, and
equity ratios), and limitations on incurring other debt. Since inception,
no cash dividends have been declared on our common stock. We are currently
in compliance with the provisions of this agreement. The borrowing base is
redetermined at least every six months with November 1, 2000 as the next
scheduled borrowing base re-determination date. By its terms, the credit
facility extends until August 2002.
Our Convertible Notes at June 30, 2000, consist of $115,000,000 of
6.25% Convertible Subordinated Notes due 2006. The Convertible Notes were
issued on November 25, 1996, and will mature on November 15, 2006. The
Convertible Notes are unsecured and convertible into common stock of Swift
at the option of the holders at any time prior to maturity at an adjusted
conversion price of $31.534 per share, subject to adjustment upon the
occurrence of certain events. The original conversion price of $34.6875
was adjusted downward to reflect the 10% stock dividend in October 1997.
Interest on the notes is payable semiannually on May 15 and November 15.
The Convertible Notes are redeemable for cash at the option of Swift, with
certain restrictions, at 104.375% of principal, declining to 100.625% in
2005. Upon certain changes in control of Swift, if the price of our common
stock is not above certain levels, each holder of Convertible Notes will
have the right to require us to repurchase the Convertible Notes at 101%
of the principal amount thereof, together with accrued and unpaid interest
to the date of repurchase, but after the repayment of any Senior
Indebtedness, as defined.
11
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000 (UNAUDITED) AND DECEMBER 31, 1999-CONTINUED
Our Senior Notes at June 30, 2000, consist of $125,000,000 of 10.25%
Senior Subordinated Notes due 2009. The Senior Notes were issued at
99.236% of the principal amount on August 4, 1999, and will mature on
August 1, 2009. The notes are unsecured senior subordinated obligations
and are subordinated in right of payment to all our existing and future
senior debt, including our bank debt. Interest on the Senior Notes is
payable semiannually on February 1 and August 1, and commenced with the
first payment on February 1, 2000. On or after August 1, 2004, the Senior
Notes are redeemable for cash at the option of Swift, with certain
restrictions, at 105.125% of principal, declining to 100% in 2007. In
addition, prior to August 1, 2002, we may redeem up to 33.33% of the
Senior Notes with the proceeds of qualified offerings of our equity at
110.25% of the principal amount of the Senior Notes, together with accrued
and unpaid interest. Upon certain changes in control of Swift, each holder
of Senior Notes will have the right to require us to repurchase the Senior
Notes at a purchase price in cash equal to 101% of the principal amount,
plus accrued and unpaid interest to the date of purchase.
(3) STOCKHOLDERS' EQUITY
In August of 1999, we sold 4.6 million shares of common stock in a
public offering for $9.75 per share, with net proceeds of approximately
$42.1 million.
(4) FOREIGN ACTIVITIES
New Zealand. We own a petroleum exploration permit in New Zealand. The
first permit covered approximately 65,000 acres in the Onshore Taranaki
Basin of New Zealand's North Island, and the second covered approximately
69,300 adjacent acres. In March 1998, we surrendered approximately 46,400
acres covered by the first permit, and the remaining acreage has been
included as an extension of the area covered in the second permit, leaving
us with only one expanded permit. On October 18, 1999, this expanded
permit was again extended to include approximately 12,800 adjacent
offshore acres. This permit now contains approximately 100,700 acres.
In late 1999, our first exploratory well on this permit, the Rimu-A1
was completed, and a ten-day production draw-down/build-up test was
performed. Our portion of the drilling, completion, and testing costs
incurred through June 30, 2000 was approximately $7.0 million. We are
performing additional seismic acquisition and analysis on the permit area
and are analyzing further delineation activities on the Rimu block. We
commenced drilling the first delineation well, the Rimu-B1, on July 18,
2000.
As of June 30, 2000, our investment in New Zealand totaled
approximately $16.7 million. Approximately $0.7 million of such costs have
been impaired, while the remaining $16.0 million is included in the
unproved properties portion of oil and gas properties. All other
obligations under the permit have been fulfilled.
12
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
Over the last several years, we have emphasized adding reserves through
drilling activity. We also add reserves through strategic purchases of
producing properties when oil and gas prices are lower and other market
conditions are appropriate, as we did in the third quarter of 1998 with the
purchase of the Masters Creek and Brookeland Areas from Sonat Exploration
Company. In 1997, 1998, and 1999, we used this flexible strategy of
employing both drilling and acquisitions to add more reserves than we
depleted through production. Oil and gas sales attributable to properties
in which we own a direct or indirect interest comprise virtually all of our
revenues.
LIQUIDITY AND CAPITAL RESOURCES
During the first six months of 2000, we relied upon our internally
generated cash flows of $55.3 million to fund capital expenditures of $51.2
million. We expect internally generated cash flows, together with cash on
hand of $36.2 million at June 30,2000, to provide funds for capital costs
and working capital through the remainder of 2000.
During 1999, we primarily relied upon internally generated cash flows
of $73.6 million to fund capital expenditures of $78.1 million. Capital
expenditures were also partially funded with the remaining proceeds, after
repayment of our bank borrowings, from our public sale of senior notes and
common stock in August 1999.
Net Cash Provided by Operating Activities. For the first six months of
2000, net cash provided by our operating activities increased by 96% to
$55.3 million, as compared to $28.3 million during the first six months a
year earlier. The increase of $27.0 million was primarily due to $38.0
million of additional oil and gas sales during the 2000 period. However,
this increase was partially offset by a $4.5 million increase in oil and
gas production costs and a $1.4 million increase in interest expense.
Financing Activities. In August 1999, in two concurrent public
offerings, we sold $125.0 million of 10.25% Senior Subordinated Notes and
4.6 million shares of common stock for $44.9 million. The notes were issued
at 99.236% of the principal amount and will mature on August 1, 2009.
Proceeds from the two offerings have been used to repay our bank borrowings
of $136.0 million. The remaining proceeds were used, together with
internally generated cash flows, to fund capital expenditures and working
capital needs. The principal terms of these notes are more fully described
in Note 3 to our condensed consolidated financial statements.
Credit Facility. At June 30, 2000 and at December 31, 1999, we had no
outstanding borrowings under our credit facility. At June 30, 2000, our
credit facility was a $250.0 million revolving line of credit with a
$100.0 million borrowing base. Our revolving credit facility includes,
among other restrictions, requirements as to maintenance of certain
minimum financial ratios (principally pertaining to working capital, debt,
and equity ratios), and limitations on incurring other debt. We are
currently in compliance with the provisions of this agreement.
13
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Debt Maturities. The credit facility extends until August 18, 2002. Our
$115.0 million convertible notes mature November 15, 2006. Our $125.0
million senior notes mature August 1, 2009.
Working Capital. Our working capital increased from $16.5 million at
December 31, 1999, to $25.8 million at June 30, 2000, primarily due to
increased oil and gas sales, which reflect the increase in commodity
prices.
Common Stock Repurchase Program. In March 1997, we commenced a common
stock repurchase program that terminated pursuant to its terms as of June
30, 1999. We spent $13.3 million to acquire 927,774 shares at an average
cost of $14.34 per share. In March 1999, we used 68,318 shares of common
stock held as treasury stock to fund our employer contribution in the
401(k) program for our employees. In May 2000, we contributed 15,652
shares of common stock held as treasury stock to our Employee Stock
Ownership Plan.
Capital Expenditures. During the first six months of 2000, we used
$51.2 million to fund capital expenditures for property, plant, and
equipment. These capital expenditures included:
o $38.3 million for drilling costs, both development and exploratory;
o $8.5 million of domestic prospect costs, principally prospect
leasehold, seismic and geological costs of unproved prospects;
o $3.1 million invested in New Zealand;
o $0.8 million on property, plant and equipment; and
o $0.5 million spent primarily for computer equipment, software and
furniture and fixtures.
In the remaining six months of 2000, we expect to make capital
expenditures of approximately $94.0 million, including investments in all
areas in which investments were made during the first six months of the
year as described above. These amounts include approximately $35.0 million
for property acquisitions, which may or may not take place, principally
dependent upon our ability to find and purchase attractive properties at
reasonable prices.
We drilled or participated in the drilling of 32 wells in the first six
months of 2000, and 28 were successful. Development wells had a success
rate of 26 out of 29, while two out of three exploratory wells drilled
were successful. For the remaining six months of 2000 we anticipate
drilling or participating in the drilling of an additional 37 wells, made
up of 28 domestic development wells and seven domestic exploratory wells,
and two delineation wells to our New Zealand Rimu well, the first of which
commenced drilling in mid-July. We estimate capital expenditures for 2000
to be approximately $145.0 million, an increase from 1999 capital
expenditures of $78.0 million. This upward adjustment in the 2000 capital
expenditures budget is in response to increased cash flows resulting from
the improvement in commodity prices. We believe that 2000's anticipated
internally generated cash flows, together with cash on hand, will be
sufficient to finance the costs associated with our currently budgeted
remaining 2000 capital expenditures. We also have access to bank
borrowings, should they become necessary.
14
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
RESULTS OF OPERATIONS - Three Months Ended June 30, 2000 and 1999
Revenues. Our revenues increased 93% during the second quarter of 2000
as compared to the same period in 1999. This increase was caused by growth
in our oil and gas sales which resulted from the 81% increase in oil
prices received and the 94% increase in gas prices received.
Oil and Gas Sales. Our oil and gas sales increased 93% to $45.5 million
in the second quarter of 2000, compared to $23.6 million for the
comparable period in 1999. Our natural gas production increased 3% and oil
production increased 1% resulting in a 2%, or 0.3 Bcfe, increase in
volumes produced compared to production in the same period in 1999.
Our $21.9 million increase in oil and gas sales during the second
quarter of 2000 resulted from:
o Price increases which had a favorable impact on sales of $21.4 million,
with $8.0 million of the increase coming from the increase in average
oil prices received and $13.4 million coming from the increase in
average gas prices received; and
o Volume increases which had an favorable impact on sales of $0.5
million, with $0.4 million of the increase coming from the 0.2 Bcf
increase in gas sales volumes and $0.1 million of the increase coming
from the 5,600 barrel increase in oil sales volumes.
The following table provides additional information regarding the
changes in the sources of our oil and gas sales and volumes from our four
core areas in the second quarter periods of 2000 and 1999.
<TABLE>
<CAPTION>
Three Months Ended June 30,
Area Revenues (In Millions) Net Sales Volumes (Bcfe)
---- ---------------------- ------------------------
2000 1999 2000 1999
------ ------ ------ ------
<S> <C> <C> <C> <C>
AWP Olmos $ 11.5 $ 7.0 3.2 3.2
Brookeland $ 5.7 $ 2.4 1.3 1.0
Giddings $ 3.0 $ 2.2 0.8 1.0
Masters Creek $ 23.7 $ 10.6 5.1 4.6
</TABLE>
15
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
The following table provides additional information regarding our oil
and gas sales:
<TABLE>
<CAPTION>
Net Sales Volume Average Sales Price
----------------------------------------- ----------------------
Oil (Bbl) Gas (Mcf) Combined (Mcfe) Oil (Bbl) Gas (Mcf)
--------- --------- --------------- --------- ---------
1999
<S> <C> <C> <C> <C> <C>
Three Months Ended
June 30, 644,323 6,688,316 10,554,254 $ 15.25 $ 2.05
2000
Three Months Ended
June 30, 649,894 6,910,947 10,810,311 $ 27.55 $ 3.99
</TABLE>
Costs and Expenses. Our general and administrative expenses for the
second quarter of 2000 increased $275,000, or 23%, when compared to the
same period in 1999. Our general and administrative expenses per Mcfe
produced also increased to $0.14 per Mcfe from $0.11 per Mcfe for the
comparable period in 1999. Such increases are reflective of additional
staffing costs as our activities increase. Supervision fees netted from
general and administrative expenses were $0.8 million for the three-month
periods ended June 30, 2000 and 1999.
Depreciation, depletion and amortization of our assets, or DD&A,
increased approximately $1.1 million, or 10%, for the second quarter of
2000. This was primarily due to additions to our reserves and associated
costs and to the related 2% increase in production volumes. Our DD&A rate
per Mcfe of production increased to $1.07 per Mcfe in the second quarter
of 2000 from $0.99 per Mcfe in the same 1999 period.
Our production costs increased by $2.8 million to $0.64 per Mcfe in the
second quarter of 2000 from $0.39 per Mcfe in the same 1999 period. Of the
$2.8 million increase, $1.4 million related to the increase in severance
and ad valorem taxes, which are commodity price sensitive. Severance taxes
increased primarily from the higher commodity prices received, from the
expiration of certain specific well severance tax exemptions, and from the
increase in production volumes. The remainder of the $2.8 million increase
reflects costs associated with newly drilled wells as well as increased
activities related to production enhancements during periods of high
commodity prices, such as the increased use of production chemicals.
Supervision fees netted from production costs were $0.8 million for the
three-month periods ended June 30, 2000 and 1999.
Interest expense on our convertible notes due 2006, including
amortization of debt issuance costs, was the same in the second quarter of
2000 and 1999, totaling $1.9 million. Interest expense on the credit
facility, including commitment fees and amortization of debt issuance
costs, totaled $0.1 million in the second quarter of 2000, compared to
$2.5 million in the same 1999 period. Interest expense and discount on our
newly issued senior notes due 2009, including amortization of debt
issuance costs, totaled $3.3 million in 2000 only. Thus, total interest
charges for the second quarter of 2000 were $5.3 million, of which $1.3
million was capitalized. In the second quarter of 1999, these charges
totaled $4.4 million, of which $1.0 million was capitalized. The increase
in interest expense in 2000 is attributable to the higher interest rate on
our new senior notes. The capitalized portion of interest is related to
our exploration and foreign business development activities.
16
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Net Income. Our net income for the second quarter of 2000 of $14.2
million and Basic EPS of $0.68 were 351% and 240% higher than net income
of $3.2 million and Basic EPS of $0.20 in the second quarter of 1999.
These increases primarily reflected the effect of the increased oil and
gas prices received in the 2000 period, as discussed above. The lower
percentage increase in Basic EPS, as compared to net income, resulted from
the public sale of 4.6 million shares of common stock in the third quarter
of 1999.
RESULTS OF OPERATIONS - Six Months Ended June 30, 2000 and 1999
Revenues. Our revenues increased 85% during the first half of 2000 as
compared to the same period in 1999. This increase was caused by growth in
our oil and gas sales which resulted from the 112% increase in oil prices
received and the 79% increase in gas prices received.
Oil and Gas Sales. Our oil and gas sales increased 85% to $82.7 million
in the first six months of 2000, compared to $44.7 million for the
comparable period in 1999. Our natural gas production decreased 3% and oil
production decreased 5% resulting in a 4%, or 0.8 Bcfe, decrease in
volumes produced compared to production in the same period in 1999. These
volume decreases were more than offset by increased prices received. The
decrease in production volumes resulted primarily from our decision to
reduce development drilling during 1999 due to low oil and gas prices at
the time. With drilling curtailed in 1999, not enough new production was
placed online to offset the normal production decline in the AWP Olmos and
Giddings areas, as can be seen in the table below. Also, property sales
relating to the ongoing liquidation of partnerships we manage have reduced
our share of production volumes in areas outside of our four core areas.
With increased levels of drilling in late 1999 and in 2000, we have begun
to turn this trend around, as second quarter 2000 production exceeded 1999
second quarter production as described above. We currently expect that
production quantities going forward will also be higher than production
during the comparable quarters in 1999. Second quarter 2000 production of
10.8 Bcfe represented a 3% increase over the 10.5 Bcfe produced in the
first quarter of 2000 and a 6% increase over the 10.2 Bcfe produced in the
fourth quarter of 1999.
Our $38.0 million increase in oil and gas sales during the first half
of 2000 resulted from:
o Price increases which had a favorable impact on sales of $39.7 million,
with $18.9 million of the increase coming from the increase in average
oil prices received and $20.8 million coming from the increase in
average gas prices received; offset by
o Volume decreases which had an unfavorable impact on sales of $1.7
million, with $0.8 million of the decrease coming from the 0.4 Bcf
decrease in gas sales volumes and $0.9 million of the decrease coming
from the 69,500 barrel decrease in oil sales volumes.
The following table provides additional information regarding the
changes in the sources of our oil and gas sales and volumes from our four
core areas in the first six-month periods of 2000 and 1999.
17
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
<TABLE>
<CAPTION>
Six Months Ended June 30,
Area Revenues (In Millions) Net Sales Volumes (Bcfe)
---- ---------------------- ------------------------
2000 1999 2000 1999
------ ------ ------ ------
<S> <C> <C> <C> <C>
AWP Olmos $ 21.8 $ 13.8 6.5 6.9
Brookeland $ 8.7 $ 4.7 2.2 2.1
Giddings $ 5.4 $ 3.6 1.6 1.9
Masters Creek $ 44.0 $ 20.4 10.1 9.9
</TABLE>
The following table provides additional information regarding our oil
and gas sales:
<TABLE>
<CAPTION>
Net Sales Volume Average Sales Price
------------------------------------------ ----------------------
Oil (Bbl) Gas (Mcf) Combined (Mcfe) Oil (Bbl) Gas (Mcf)
--------- ---------- --------------- --------- ---------
<S> <C> <C> <C> <C> <C>
1999
Six Months Ended
June 30, 1,372,133 13,912,504 22,145,302 $ 12.93 $ 1.94
2000
Six Months Ended
June 30, 1,302,642 13,513,318 21,329,170 $ 27.45 $ 3.47
</TABLE>
Costs and Expenses. Our general and administrative expenses for the
first six months of 2000 increased $313,000, or 14%, when compared to the
same period in 1999. Our general and administrative expenses per Mcfe
produced also increased to $0.12 per Mcfe from $0.10 per Mcfe for the
comparable period in 1999. Such increases are reflective of increases in
our activities as discussed above in the comparison of second quarter
results. Supervision fees netted from general and administrative expenses
were $1.7 million for the current year period and $1.5 million for the
1999 period.
DD&A increased approximately $1.8 million, or 8%, for the first six
months of 2000. This was primarily due to additions to our reserves and
associated costs and to the related 4% decrease in production volumes. Our
DD&A rate per Mcfe of production increased to $1.08 per Mcfe in the first
six months of 2000 from $0.96 per Mcfe in the same 1999 period.
Our production costs per Mcfe increased by $4.5 million or $0.61 per
Mcfe in the first half of 2000 from $0.39 per Mcfe in the same 1999
period. Of the $4.5 million increase, $2.4 million related to the increase
in severance and ad valorem taxes which are commodity price sensitive.
Severance taxes increased primarily from the higher commodity prices
received and from the expiration of certain specific well severance tax
exemptions. The remainder of the $4.5 million increase reflects increased
activities discussed above in the comparison of second quarter results.
Supervision fees netted from production costs for the first six months of
2000 were $1.7 million and for the same period of 1999 were $1.5 million.
18
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Interest expense on our convertible notes due 2006, including
amortization of debt issuance costs, was the same in the first six months
of 2000 and 1999, totaling $3.8 million. Interest expense on the credit
facility, including commitment fees and amortization of debt issuance
costs, totaled $0.3 million in the first six months of 2000, compared to
$4.9 million in the same 1999 period. Interest expense and discount on our
newly issued senior notes due 2009, including amortization of debt
issuance costs, totaled $6.5 million in 2000 only. Thus, total interest
charges for the first six months of 2000 were $10.6 million, of which $2.5
million was capitalized. In the first six months of 1999, these charges
totaled $8.7 million, of which $2.1 million was capitalized. The increase
in interest expense in 2000 is attributable to the higher interest rate on
our new senior notes. The capitalized portion of interest is related to
our exploration and foreign business development activities.
Net Income. Our net income for the first six months of 2000 of $23.8
million and Basic EPS of $1.14 were 437% and 322% higher than net income
of $4.4 million and Basic EPS of $0.27 in the first six months of 1999.
This increase primarily reflected the effect of increased oil and gas
prices received in the 2000 period, as discussed above. The lower
percentage increase in Basic EPS, as compared to net income, resulted from
the public sale of 4.6 million shares of common stock in the third quarter
of 1999.
Forward Looking Statements
The statements contained in this report that are not historical facts
are forward-looking statements as that term is defined in Section 21E of
the Securities and Exchange Act of 1934, as amended. Such forward-looking
statements may pertain to, among other things, financial results, capital
expenditures, drilling activity, development activities, cost savings,
production efforts and volumes, hydrocarbon reserves, hydrocarbon prices,
liquidity, regulatory matters and competition. Such forward-looking
statements generally are accompanied by words such as "plan," "estimate,"
"expect," "budget," "predict," "anticipate," "projected," "should,"
"believe" or other words that convey the uncertainty of future events or
outcomes. Such forward-looking information is based upon management's
current plans, expectations, estimates and assumptions and is subject to a
number of risks and uncertainties and therefore, actual results may differ
materially. Among the factors that could cause actual results to differ
materially are: fluctuations of the prices received or demand for our oil
and natural gas; the uncertainty of drilling results and reserve
estimates; operating hazards; requirements for capital; general economic
conditions; competition and government regulations; as well as the risks
and uncertainties discussed herein, and set forth from time to time in our
other public reports, filings and public statements. Also, because of the
volatility in oil and gas prices and other factors, interim results are
not necessarily indicative of those for a full year.
19
<PAGE>
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Commodity Risk
--------------
Our revenues are primarily the result of sales of our oil and natural
gas production. Market prices of oil and natural gas may fluctuate and
adversely affect operating results. To mitigate some of this risk, we do
engage periodically in certain limited hedging activities, which includes
buying protection price floors and entering into participating collars for
portions of our and our managed limited partnerships' oil and natural gas
production. These derivative financial instruments are placed with major
financial institutions that we believe present minimum credit risk. Costs
and any benefits derived from the price floors are recorded as a reduction
or increase, as applicable, in oil and gas sales revenue. The costs to
purchase the price floors are amortized over the option period. The
participating collars are designated as hedges and realized gains or
losses are recognized in oil and gas revenues when the associated
production occurs.
The costs related to 2000 hedging activities through June 30, 2000 on
both the price floors and the participating collars totaled $782,984, or
$0.037 per Mcfe produced.
The costs relating to 2000 hedging activities through June 30, 2000 on
the price floors totaled $173,364 with no benefits having been received,
resulting in a net cash outflow of $173,364, or $0.008 per Mcfe produced.
At June 30, 2000, six months of participating collars had closed with our
recording a loss of $609,620, or $0.029 per Mcfe produced.
The costs related to open price floor contracts as of June 30, 2000
totaled $396,750, which is our maximum exposure under these contracts.
These open contracts had a fair market value of $80,300 at June 30, 2000.
There are no open participating collars at this time.
20
<PAGE>
SWIFT ENERGY COMPANY
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings - N/A
Item 2. Changes in Securities and Use of Proceeds - N/A
Item 3. Defaults Upon Senior Securities - N/A
Item 4. Submission of Matters to a Vote of Security Holders -
Our annual meeting of shareholders was held on May 9, 2000. At the record date,
20,859,456 shares of common stock were outstanding and entitled to one vote per
share upon all matters submitted at the meeting. At the annual meeting, two
nominees were elected to serve as Directors of Swift for three year terms to
expire at the 2003 annual meeting of shareholders:
<TABLE>
<CAPTION>
FOR AGAINST ABSTENTIONS
--- ------- -----------
NOMINEES FOR DIRECTORS
<S> <C> <C> <C>
Terry E. Swift 19,929,806 85,124 ---
Clyde W. Smith Jr. 19,929,348 85,582 ---
</TABLE>
The terms of Directors A. Earl Swift, Henry C. Montgomery, and Harold Withrow
expire at the 2001 annual meeting and the terms of Directors Virgil N. Swift and
G. Robert Evans expire at the 2002 annual meeting.
Item 5. Other Information -
Effective June 30, 2000, Executive Vice President Virgil N. Swift retired from
his day-to-day responsibilities in that position. He will continue to serve as
Vice Chairman of the Board of Swift Energy Company and will also continue to
serve as Chairman and CEO of Swift Energy International.
On July 28, 2000, we announced the early retirement of Senior Vice President and
Chief Financial Officer John R. Alden. His retirement will become effective on
September 30, 2000. Effective August 1, 2000, Alton D. Heckaman, Jr., our Vice
President and Controller since 1986, became Senior Vice President and Chief
Financial Officer.
Item 6. Exhibits & Reports on Form 8-K -
(a) Documents filed as part of the report
(3) Exhibits
12 Swift Energy Company Ratio of Earnings to Fixed Charges
(b) Reports on Form 8-K filed during the quarter ended June 30, 2000 - None
21
<PAGE>
SIGNATURES
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.
SWIFT ENERGY COMPANY
<TABLE>
<CAPTION>
(Registrant)
<S> <C>
Date: August 11, 2000 By: (Original Signed By)
------------------------ ---------------------------------------
Alton D. Heckaman, Jr.
Senior Vice President,
Chief Financial Officer, Controller and
Principal Accounting Officer
</TABLE>
22
<PAGE>
Exhibit 12
<PAGE>
SWIFT ENERGY COMPANY
RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
Six Months Ended
June 30,
-----------------------------
2000 1999
------------ ------------
<S> <C> <C>
GROSS G&A 11,386,483 10,577,434
NET G&A 2,607,525 2,294,286
INTEREST EXPENSE 8,076,324 6,653,012
RENT EXPENSE 626,497 674,885
NET INCOME BEFORE TAXES 37,137,402 6,691,824
CAPITALIZED INTEREST 2,427,537 1,843,664
DEPLETED CAPITALIZED INTEREST 170,640 172,848
CALCULATED DATA
----------------------------------
UNALLOCATED G&A (%) 22.90% 21.69%
NON-CAPITAL RENT EXPENSE 143,469 146,385
1/3 NON-CAPITAL RENT EXPENSE 47,823 48,795
FIXED CHARGES 10,551,684 8,545,471
EARNINGS 45,432,189 13,566,479
RATIO OF EARNINGS TO FIXED CHARGES 4.31 1.59
============ ============
</TABLE>
For purposes of calculating the ratio of earnings to fixed charges,
fixed charges include interest expense, capitalized interest, amortization
of debt issuance costs and discounts, and that portion of non-capitalized
rental expense deemed to be the equivalent of interest. Earnings represent
income before income taxes from continuing operations before fixed
charges.
