<PAGE> 1
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------
FORM 10-Q
QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR QUARTER ENDED SEPTEMBER 30, 2000 COMMISSION FILE NUMBER 0-25192
CALLON PETROLEUM COMPANY
-----------------------------------------------------
(Exact name of Registrant as specified in its charter)
DELAWARE 64-0844345
------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
200 NORTH CANAL STREET
NATCHEZ, MISSISSIPPI 39120
--------------------------------------------------
(Address of principal executive offices)(Zip code)
(601) 442-1601
-------------------------------
(Registrant's telephone number,
including area code)
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 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 .
--- ---
As of November 3, 2000, there were 13,327,675 shares of the Registrant's Common
Stock, par value $0.01 per share, outstanding.
<PAGE> 2
CALLON PETROLEUM COMPANY
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE NO.
--------
<S> <C>
PART I. FINANCIAL INFORMATION
Consolidated Balance Sheets as of September 30, 2000
and December 31, 1999 3
Consolidated Statements of Operations for Each of the
Three and Nine Months in the Periods Ended September 30, 2000
and September 30, 1999 4
Consolidated Statements of Cash Flows for Each of the
Nine Months in the Periods Ended September 30, 2000 and
September 30, 1999 5
Notes to Consolidated Financial Statements 6
Management's Discussion and Analysis of
Financial Condition and Results of Operations 9
Quantitative and Qualitative Disclosures about Market Risk 16
PART II. OTHER INFORMATION 17
</TABLE>
2
<PAGE> 3
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
2000 1999
------------- -------------
<S> <C> <C>
(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents $ 10,268 $ 34,671
Accounts receivable 8,347 5,362
Other current assets 1,372 1,004
------------- -------------
Total current assets 19,987 41,037
------------- -------------
Oil and gas properties, full cost accounting method:
Evaluated properties 558,166 511,689
Less accumulated depreciation, depletion and amortization (374,401) (361,758)
------------- -------------
183,765 149,931
Unevaluated properties excluded from amortization 61,517 44,434
------------- -------------
Total oil and gas properties 245,282 194,365
------------- -------------
Pipeline and other facilities 5,618 5,860
Other property and equipment, net 1,722 1,450
Deferred tax asset 10,607 14,995
Long-term gas balancing receivable 404 243
Other assets, net 1,459 1,927
------------- -------------
Total assets $ 285,079 $ 259,877
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 11,852 $ 16,786
Undistributed oil and gas revenues 1,762 2,082
Accrued net profits payable 1,847 1,676
------------- -------------
Total current liabilities 15,461 20,544
------------- -------------
Long-term debt 126,250 100,250
Deferred revenue on sale of production payment interest 8,454 12,080
Accrued retirement benefits 1,941 2,107
Long-term gas balancing payable 522 516
------------- -------------
Total liabilities 152,628 135,497
------------- -------------
Stockholders' equity:
Preferred stock, $0.01 par value, 2,500,000 shares authorized; 1,006,461 shares of
Convertible Exchangeable Preferred Stock, Series A, issued and outstanding at
September 30, 2000 and 1,045,461 shares outstanding at December 31, 1999
with a liquidation preference of $25,161,525 at September 30, 2000 10 11
Common stock, $0.01 par value, 20,000,000 shares authorized; 12,373,688 and
12,239,238 outstanding at September 30, 2000 and at December 31, 1999,
respectively 124 122
Treasury stock (99,078 shares at cost) (1,183) (1,183)
Capital in excess of par value 150,567 149,425
Accumulated deficit (17,067) (23,995)
------------- -------------
Total stockholders' equity 132,451 124,380
------------- -------------
Total liabilities and stockholders' equity $ 285,079 $ 259,877
============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
3
<PAGE> 4
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------------- -----------------------------
2000 1999 2000 1999
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales $ 15,960 $ 10,240 $ 39,720 $ 26,777
Interest and other 462 344 1,536 1,212
------------- ------------- ------------- -------------
Total revenues 16,422 10,584 41,256 27,989
------------- ------------- ------------- -------------
Costs and expenses:
Lease operating expenses 2,295 1,803 6,449 5,289
Depreciation, depletion and amortization 4,568 4,284 12,885 12,236
General and administrative 992 999 2,964 3,439
Interest 2,103 1,900 5,949 4,371
------------- ------------- ------------- -------------
Total costs and expenses 9,958 8,986 28,247 25,335
------------- ------------- ------------- -------------
Income from operations 6,464 1,598 13,009 2,654
Income tax expense 2,197 543 4,423 902
------------- ------------- ------------- -------------
Net income 4,267 1,055 8,586 1,752
Preferred stock dividends 553 555 1,658 1,942
------------- ------------- ------------- -------------
Net income (loss) available to common shares $ 3,714 $ 500 $ 6,928 $ (190)
============= ============= ============= =============
Net income (loss) per common share:
Basic $ 0.30 $ 0.06 $ 0.57 $ (0.02)
============= ============= ============= =============
Diluted $ 0.29 $ 0.06 $ 0.56 $ (0.02)
============= ============= ============= =============
Shares used in computing net income (loss)
per common share:
Basic 12,228 8,459 12,185 8,465
============= ============= ============= =============
Diluted 14,968 8,567 12,476 8,465
============= ============= ============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
4
<PAGE> 5
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(IN THOUSANDS)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
--------------------------------
SEPTEMBER 30, SEPTEMBER 30,
2000 1999
-------------- --------------
<S> <C> <C>
Cash flows from operating activities:
Net income $ 8,586 $ 1,752
Adjustments to reconcile net income to cash provided by operating
activities:
Depreciation, depletion and amortization 13,207 12,612
Amortization of deferred costs 704 464
Amortization of deferred production payment revenue (3,626) (1,470)
Deferred income tax expense 4,423 902
Noncash charge related to compensation plans 907 206
Changes in current assets and liabilities:
Accounts receivable (2,985) (2,391)
Other current assets (368) (281)
Current liabilities (1,527) (199)
Change in gas balancing receivable (161) (17)
Change in gas balancing payable 6 47
Change in other long-term liabilities (166) (162)
Change in other assets, net (271) (1,535)
-------------- --------------
Cash provided (used) by operating activities 18,729 9,928
-------------- --------------
Cash flows from investing activities:
Capital expenditures (68,531) (33,870)
Cash proceeds from sale of mineral interests 821 --
-------------- --------------
Cash provided (used) by investing activities (67,710) (33,870)
-------------- --------------
Cash flows from financing activities:
Payment on debt -- (35,500)
Increase in debt 26,000 64,500
Equity issued related to employee stock plans 236 121
Purchase of treasury shares -- (262)
Common stock cancelled -- (1,615)
Cash dividends on preferred stock (1,658) (1,667)
-------------- --------------
Cash provided (used) by financing activities 24,578 25,577
-------------- --------------
Net increase (decrease) in cash and cash equivalents (24,403) 1,635
Cash and cash equivalents:
Balance, beginning of period 34,671 6,300
-------------- --------------
Balance, end of period $ 10,268 $ 7,935
============== ==============
</TABLE>
The accompanying notes are an integral part of these financial statements.
5
<PAGE> 6
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2000
1. BASIS OF PRESENTATION
The financial information presented as of any date other than December
31, has been prepared from the books and records without audit.
Financial information as of December 31, has been derived from the
audited financial statements of the Company, but does not include all
disclosures required by generally accepted accounting principles. In
the opinion of management, all adjustments, consisting only of normal
recurring adjustments, necessary for the fair presentation of the
financial information for the period indicated, have been included. For
further information regarding the Company's accounting policies, refer
to the Consolidated Financial Statements and related notes for the year
ended December 31, 1999 included in the Company's Annual Report on Form
10-K dated March 23, 2000.
2. PER SHARE AMOUNTS
Basic earnings or loss per common share were computed by dividing net
income or loss by the weighted average number of shares of common stock
outstanding during the quarter. Diluted earnings or loss per common
share were determined on a weighted average basis using common shares
issued and outstanding adjusted for the effect of stock options
considered common stock equivalents computed using the treasury stock
method and the effect of the convertible preferred stock (if dilutive).
The earnings per share computation for the nine-month period ended
September 30, 1999 excluded all stock options from the computation of
diluted loss per share because they were antidilutive. The conversion
of the preferred stock was not included in the calculation, except for
the quarter ended September 30, 2000, due to their antidilutive effect
on diluted income or loss per share.
A reconciliation of the basic and diluted earnings per share
computation is as follows (in thousands, except per share amounts):
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------------- -----------------------------
2000 1999 2000 1999
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
(a) Net income (loss) available
for common stock $ 3,714 $ 500 $ 6,928 $ (190)
Preferred dividends assuming conversion
of preferred stock (if dilutive) $ 553 $ -- $ -- $ --
(b) Income available for common stock
assuming conversion of preferred
stock (if dilutive) $ 4,267 $ 500 $ 6,928 $ (190)
(c) Weighted average shares outstanding 12,228 8,459 12,185 8,465
Dilutive impact of stock options 414 108 291 --
Convertible preferred stock (if dilutive) 2,236 -- -- --
(d) Total diluted shares 14,968 8,567 12,476 $8,465
Basic income (loss) per share (a/c) $ 0.30 $ 0.06 $ 0.57 $(0.02)
Diluted income (loss) per share (b/d) $ 0.29 $ 0.06 $ 0.56 $(0.02)
</TABLE>
6
<PAGE> 7
3. HEDGING CONTRACTS
The Company periodically uses derivative financial instruments to
manage oil and gas price risks. Settlements of gains and losses on
commodity price swap contracts are generally based upon the difference
between the contract price or prices specified in the derivative
instrument and a NYMEX price and are reported as a component of oil and
gas revenues. Gains or losses attributable to the termination of a swap
contract are deferred and recognized in revenue when the oil and gas is
sold. Approximately $2.8 million and $0.9 million related to these
financial instruments were recognized as a reduction of oil and gas
revenue in the first nine months of 2000 and 1999, respectively.
As of September 30, 2000, the Company had open natural gas collar
contracts with a third party whereby minimum floor prices and maximum
ceiling prices are contracted and applied to related contract volumes.
This agreement is for gas volumes of 200,000 Mcf for the month of
October 2000 at a ceiling price of $2.75 and floor price of $2.50. The
Company had no open crude oil contracts at September 30, 2000.
4. STOCKHOLDERS' EQUITY
During the first quarter of 1999, certain preferred stockholders,
through private transactions, converted 210,350 shares of Preferred
Stock into 502,632 shares of the Company's Common Stock. In addition,
5,000 shares of Preferred Stock were converted during the first quarter
of 2000 and 34,000 shares of Preferred Stock were converted in the
third quarter of 2000 to the Company's Common Stock at the conversion
rate.
In October 2000, preferred shareholders, through private transactions,
converted 405,600 shares of the Company's Preferred Stock into 947,462
shares of the Company's Common Stock.
Any non-cash premiums negotiated in excess of the conversion rate were
recorded as additional preferred stock dividends and excluded from the
Consolidated Statements of Cash Flows.
The Company granted 533,000 stock options to employees on March 23,
2000 and 120,000 stock options to directors on July 25, 2000 at $10.50
per share. The March 23, 2000 grant was subject to shareholder approval
of an amendment to the 1996 Stock Incentive Plan. The amendment, which
was approved on May 9, 2000 at the Annual Meeting of Shareholders,
increased the number of shares reserved for issuance under the 1996
plan. The excess of the market price over the exercise price on the
approval date of the amendment is amortized over the three-year vesting
period of the options.
5. STOCKHOLDER RIGHTS PLAN
The Company adopted a stockholder rights plan on March 30, 2000,
designed to assure that the Company's stockholders receive fair and
equal treatment in the event of any proposed takeover of the Company
and to guard against partial tender offers, squeeze-outs, open market
accumulations, and other abusive tactics to gain control without paying
all stockholders a fair price. The rights plan was not adopted in
response to any specific takeover proposal. Under the rights plan, the
Company declared a dividend of one right ("Right") on each share of the
Company's Common Stock. Each Right will entitle the holder to purchase
one one-thousandth of a share of a Series B
7
<PAGE> 8
Preferred Stock, par value $0.01 per share, at an exercise price of $90
per one one-thousandth of a share. The Rights are not currently
exercisable and will become exercisable only in the event a person or
group acquires, or engages in a tender or exchange offer to acquire,
beneficial ownership of 15 percent or more (one existing stockholder
was granted an exception for up to 21 percent) of the Company's Common
Stock. After the Rights become exercisable, each Right will also
entitle its holder to purchase a number of common shares of the Company
having a market value of twice the exercise price. The dividend
distribution was made to stockholders of record at the close of
business on April 10, 2000. The Rights will expire on March 30, 2010.
6. LONG-TERM DEBT
The existing Credit Facility matured at the end of October 2000. The
Company negotiated a new Credit Facility on October 30, 2000 whereby
the Company secured more favorable terms, including maturity and the
size of the borrowing base than it currently had through its existing
Credit Facility. The maturity date of the new Credit Facility is
October 31, 2001. The amount outstanding under the Credit Facility at
September 30, 2000, approximately $26.1 million, has been reclassified
as long-term on the balance sheet to reflect the maturity date of the
new Credit Facility. The new Credit Facility is for $75 million with an
initial borrowing base of $50 million.
The Company completed the sale of its $32 million Senior Subordinated
Notes due 2005, which were priced to yield 11 percent on October 26,
2000 and has granted the underwriters the right to purchase up to an
additional $4.8 million aggregate principal amount of notes to cover
over-allotments. The Company netted approximately $30.6 million from
the offering after deducting the underwriters' discount and offering
expenses. Approximately $20.8 million of the net proceeds from the
offering were used to purchase the Company's outstanding 10% Senior
Subordinated Notes due 2001 in conjunction with a tender offer. In
addition, the Company has initiated a redemption of all of its 10%
Senior Subordinated Notes due 2001 not tendered in the offer.
7. NEW ACCOUNTING STANDARDS
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." The Statement establishes
accounting and reporting standards that require every derivative
instrument (including certain derivative instruments embedded in other
contracts) to be recorded in the balance sheet as either an asset or
liability measured at its fair value and that changes in the
derivative's fair value be recognized currently in earnings unless
specific hedge accounting criteria are met. If those criteria are met,
the instruments are treated as hedges under SFAS No. 133 creating
volatility in equity through changes in other comprehensive income due
to the marking to market of the hedging contracts. We will adopt SFAS
No. 133 on January 1, 2001.
We currently have no derivative instruments or hedging contracts, which
extend past December 31, 2000, other than the volumetric production
payment, which qualifies for the normal sales exception under SFAS 133.
However, we may enter into new hedging arrangements prior to December
31, 2000. Depending upon the nature of any future hedging arrangements,
the adoption of SFAS 133 may create volatility in our results of
operations and/or stockholders' equity.
8
<PAGE> 9
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS
This report includes "forward-looking statements" within the meaning of Section
27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. All statements other than statements of historical facts included in
this report regarding the Company's financial position, adequacy of resources,
estimated reserve quantities, business strategies, plans, objectives and
expectations for future operations and covenant compliance, are forward-looking
statements. The Company can give no assurances that the assumptions upon which
such forward-looking statements are based will prove to have been correct.
Important factors that could cause actual results to differ materially from the
Company's expectations ("Cautionary Statements") are disclosed below, in the
section "Risk Factors" included in the Company's Form 10-K, elsewhere in this
report and from time to time in other filings made by the Company with the
Securities and Exchange Commission. All subsequent written and oral
forward-looking statements attributable to the Company or persons acting on its
behalf are expressly qualified by the Cautionary Statements.
GENERAL
The Company's revenues, profitability and future growth and the carrying value
of its oil and gas properties are substantially dependent on prevailing prices
of oil and gas and its ability to find, develop and acquire additional oil and
gas reserves that are economically recoverable. The Company's ability to
maintain or increase its borrowing capacity and to obtain additional capital on
attractive terms is also influenced by oil and gas prices. Prices for oil and
gas are subject to large fluctuations in response to relatively minor changes in
the supply of and demand for oil and gas, market uncertainty and a variety of
additional factors beyond the control of the Company. These factors include
weather conditions in the United States, the condition of the United States
economy, the actions of the Organization of Petroleum Exporting Countries,
governmental regulations, political stability in the Middle East and elsewhere,
the foreign supply of oil and gas, the price of foreign imports and the
availability of alternate fuel sources. Any substantial and extended decline in
the price of oil or gas would have an adverse effect on the Company's carrying
value of its proved reserves, borrowing capacity, revenues, profitability and
cash flows from operations. The Company uses derivative financial instruments
for price protection purposes on a limited amount of its future production and
does not use them for trading purposes.
The following discussion is intended to assist in an understanding of the
Company's historical financial position and results of operations. The Company's
historical financial statements and notes thereto included elsewhere in this
quarterly report contains detailed information that should be referred to in
conjunction with the following discussion.
LIQUIDITY AND CAPITAL RESOURCES
The Company's primary sources of capital are its cash flows from operations,
borrowings from financial institutions and the sale of debt and equity
securities. Net cash and cash equivalents during the nine months ending
September 30, 2000 decreased by $24.4 million and net cash flows from operations
before working capital changes totaled $24.2 million. Net capital expenditures
from the cash flow statement for the period
9
<PAGE> 10
totaled $67.7 million. These funds were expended in exploration, drilling and
completion of oil and gas properties.
At September 30, 2000, the Company had working capital of $4.5 million.
The existing Credit Facility matured at the end of October 2000. The Company
negotiated a new Credit Facility on October 30, 2000 whereby the Company secured
more favorable terms, including maturity and the size of the borrowing base than
it currently had through its existing Credit Facility. The maturity date of the
new Credit Facility is October 31, 2001. The amount outstanding under the Credit
Facility at September 30, 2000 has been reclassified as long-term on the balance
sheet to reflect the maturity date of the new Credit Facility. The new Credit
Facility is for $75 million with an initial borrowing base of $50 million.
The Company completed the sale of its $32 million Senior Subordinated Notes due
2005, which were priced to yield 11 percent on October 26, 2000 and has granted
the underwriters the right to purchase up to an additional $4.8 million
aggregate principal amount of notes to cover over-allotments. The Company netted
approximately $30.6 million from the offering after deducting the underwriters'
discount and offering expenses. Approximately $20.8 million of the net proceeds
from the offering were used to purchase the Company's outstanding 10% Senior
Subordinated Notes due 2001 in conjunction with a tender offer. In addition, the
Company has initiated a redemption of all of its 10% Senior Subordinated Notes
due 2001 not tendered in the offer.
CAPITAL EXPENDITURES
Capital expenditures for exploration and development costs related to oil and
gas properties totaled approximately $64.1 million in the first nine months of
2000. The Company incurred approximately $25.5 million in the Gulf of Mexico
Shelf area primarily in the development of the 1999 discoveries at South Marsh
Island 261 and East Cameron 275. Included in these expenditures as exploration
costs, were approximately $7.3 million related to three unsuccessful Gulf of
Mexico Shelf prospects evaluated during the first six months of 2000. The Gulf
of Mexico Deepwater area expenditures accounted for the remainder of the total
capital expended, with two unsuccessful exploration projects totaling $7.1
million and the balance for additional delineation drilling at the Company's
Medusa discovery and the drilling of a test well at the Entrada prospect in the
first half of 2000. The Company also began drilling operation on its Cumberland
prospect in September 2000 and announced in early November 2000 that the well
was unsuccessful. Interest and general and administrative costs allocable
directly to exploration and development projects were approximately $8.1 million
for the first nine months of 2000.
The Entrada prospect test well, located on Garden Banks Block 782, discussed
above reached total depth in April 2000. Several sidetrack wells were then
drilled; however, future delineation drilling and testing will be required to
quantify the impact the Entrada discovery will have on the Company. As
evaluation is not complete, costs incurred related to Entrada are included in
unevaluated properties as of September 30, 2000. As a result of the recent
successes by the Company in the Gulf of Mexico Deepwater area, the Company is
faced with increased costs to develop these significant proved undeveloped
reserves. Substantially all of the future development costs will be incurred in
2001 and beyond. The Company is currently evaluating various financing
alternatives to address these issues. While management believes there are a
number of financing sources available to the Company, no assurances can be made
that the Company will be able to fund these development costs.
10
<PAGE> 11
For the remainder of the year, the Company will continue evaluating property
acquisitions and drilling opportunities. The Company has budgeted up to $13.1
million in capital expenditures for the remainder of 2000. The major portion of
the capital expenditure budget will be used to drill development and exploratory
wells to increase total proved reserves and increase production for the Company.
The Company currently estimates that its budget for the remainder of 2000 can be
financed with available cash, projected cash flow from operations and the
Company's Credit Facility.
RESULTS OF OPERATIONS
The following table sets forth certain unaudited operating information with
respect to the Company's oil and gas operations for the periods indicated.
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------- -------------------------------
2000(a)(b) 1999(a)(b) 2000(a)(b) 1999(a)(b)
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Production volumes:
Oil (MBbls) 56 81 186 257
Gas (MMcf) 3,950 3,996 10,956 10,839
Total production (MMcfe) 4,285 4,481 12,072 12,379
Average daily production (MMcfe) 46.6 48.7 44.1 45.3
Average sales price:(a)
Oil (Bbls) $29.37 $12.27 $ 27.42 $ 12.06
Gas (Mcf) 3.63 2.31 3.16 2.18
Total (Mcfe) 3.72 2.29 3.29 2.16
Average costs (per Mcfe):
Lease operating (excluding severance taxes) $ 0.49 $ 0.34 $ 0.48 $ 0.36
Severance taxes 0.05 0.06 0.06 0.06
Depreciation, depletion and amortization 1.05 0.96 1.05 0.99
General and administrative (net of management fees) 0.23 0.22 0.25 0.28
</TABLE>
(a) Includes hedging gains and losses.
(b) Includes volumes of 587 MMcf for the quarter ended September 30, 2000
and 1,747 MMcf for the nine months ended September 30, 2000 at an
average price of $2.08 per Mcf associated with a volumetric production
payment. Also includes volumes of 587 MMcf for the quarter ended
September 30, 1999 and 708 MMcf for the nine months ended September 30,
1999 at the same average price.
11
<PAGE> 12
COMPARISON OF RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 30,
2000 AND THE THREE MONTHS ENDED SEPTEMBER 30, 1999.
Oil and Gas Production and Revenues
Total oil and gas revenues increased 57% from $10.2 million in the third quarter
of 1999 to $16.0 million in the third quarter of 2000. Oil and gas prices were
significantly higher when compared to the same period in 1999.
Total production for the third quarter was less than anticipated due to down
time at Mobile Block 864 Area (compressor repairs) and Main Pass 36 (downtime to
recomplete a new production zone). East Cameron 275 was shut-in in mid September
2000 due to the outside-operated production facility (repairs and maintenance)
being unavailable to process our production. Production from East Cameron 275
should resume in mid November 2000; however fourth quarter results will be
impacted by this well being off production as well as downtime at Mobile Block
864 caused by the compressor repair.
Gas production during the third quarter of 2000 totaled 4.0 billion cubic feet
and generated $14.3 million in revenues compared to 4.0 billion cubic feet and
$9.2 million in revenues during the same period in 1999. The average sales price
for the third quarter of 2000 averaged $3.63 per thousand cubic feet compared to
$2.31 per thousand cubic feet at this time last year. When compared to the same
quarter last year, the Company's gas production remained stable as a result of
new production at East Cameron 275, South Marsh Island 261, and Vermilion 130
which was offset by production declines in some of the Company's older producing
properties and the depletion of Main Pass 31 and Main Pass 36. The production
declines were expected and considered normal.
Oil production during the third quarter of 2000 totaled 55,700 barrels and
generated $1.6 million in revenues compared to 81,000 barrels and $1.0 million
in revenues for the same period in 1999. Average oil prices received in the
third quarter of 2000 were $29.37 compared to $12.27 in 1999. The strong oil
prices received in the third quarter of 2000 offset the decrease in production,
which was expected and considered normal. See the table below for variances by
major producing property.
12
<PAGE> 13
The following table summarizes oil and gas production from the Company's major
producing properties for the comparable periods.
<TABLE>
<CAPTION>
OIL PRODUCTION GAS PRODUCTION
(BBLS) (MCF)
----------------------------- -----------------------------
THREE MONTHS ENDED THREE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
2000 1999 2000 1999
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
Mobile Block 864 Area 0 0 1,202,600 1,465,000
Chandeleur Block 40 0 0 83,700 163,000
Main Pass 163 Area 0 0 294,200 477,000
Main Pass 164/165 0 0 37,200 0
North Dauphin Island 0 0 76,200 110,000
Eugene Island 335 3,900 6,000 170,900 326,000
Vermilion 130 0 0 127,100 0
Main Pass 26 4,400 7,000 53,400 146,000
Main Pass 31 0 5,000 0 175,000
Main Pass 36 300 10,000 6,000 302,000
High Island Block A-494 0 0 123,400 553,000
Escambia Minerals 24,400 38,000 38,800 63,000
East Cameron 275 4,000 0 424,700 0
South Marsh Island 261 3,500 0 1,199,000 0
Other properties 15,200 15,000 113,200 216,000
------------- ------------- ------------- -------------
Total 55,700 81,000 3,950,400 3,996,000
============= ============= ============= =============
</TABLE>
Lease Operating Expenses
Lease operating expenses, including severance taxes, for the three-month period
ending September 30, 2000 were $2.3 million compared to $1.8 million for the
same period in 1999 and reflect the increased costs related to new production.
Production declines related to older properties that have relatively fixed
operating costs also contributed to the higher per Mcf costs.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the three months ending September
30, 2000 and 1999 was $4.6 million and $4.3 million, respectively. A higher
average rate in the third quarter of 2000 resulted in the increase.
General and Administrative
General and administrative expense remained constant at $1.0 million for the
three months ended September 30, 2000 as compared to the quarter ended September
30, 1999.
Interest Expense
Interest expense increased from $1.9 million during the three months ended
September 30, 1999 to $2.1 million during the three months ended September 30,
2000 reflecting the increase in the Company's long-term debt.
13
<PAGE> 14
COMPARISON OF RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000
AND THE NINE MONTHS ENDED SEPTEMBER 30, 1999.
Oil and Gas Production and Revenues
Total oil and gas revenues increased 48% from $26.8 million in the first nine
months of 1999 to $39.7 million for the same period in 2000. Oil and gas prices
were significantly higher when compared to 1999.
Gas production during the first nine months of 2000 totaled 11.0 billion cubic
feet and generated $34.8 million in revenues compared to 10.8 billion cubic feet
and $23.7 million in revenues during the same period in 1999. The average sales
price for the first nine months of 2000 averaged $3.16 per thousand cubic feet
compared to $2.18 per thousand cubic feet for the first nine months of 1999.
When compared to the same period last year, the Company's gas production
remained stable as a result of new production at East Cameron 275, South Marsh
Island 261, and Vermilion 130 which was offset by production declines in some of
the Company's older producing properties and the depletion of Main Pass 31 and
Main Pass 36. The production declines were expected and considered normal.
Oil production during the first nine months of 2000 totaled 186,100 barrels and
generated $5.1 million in revenues compared to 257,000 barrels and $3.1 million
in revenues for the same period in 1999. Average oil prices received in the
first nine months of 2000 were $27.42 compared to $12.06 in 1999. The strong oil
prices received in the first nine months of 2000 partially offset the decrease
in production, which was expected and considered normal. See the table below for
variances by major producing property.
The following table summarizes oil and gas production from the Company's major
producing properties for the comparable periods.
<TABLE>
<CAPTION>
OIL PRODUCTION GAS PRODUCTION
(BBLS) (MCF)
--------------------------- ---------------------------
NINE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
2000 1999 2000 1999
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Mobile Block 864 Area 0 0 4,017,600 4,018,000
Chandeleur Block 40 0 0 277,600 672,000
Main Pass 163 Area 0 0 899,800 1,537,000
Main Pass 164/165 0 0 149,400 0
North Dauphin Island 0 0 235,300 373,000
Eugene Island 335 14,600 20,000 628,100 832,000
Vermilion 130 0 0 417,300 0
Main Pass 26 13,800 41,000 242,900 723,000
Main Pass 31 0 32,000 0 1,083,000
Main Pass 36 5,100 10,000 128,000 302,000
High Island Block A-494 0 0 571,900 553,000
Escambia Minerals 81,800 108,000 144,300 190,000
Kemah 3,200 0 193,700 0
East Cameron 275 15,000 0 1,064,700 0
South Marsh Island 261 3,500 0 1,622,200 0
Other properties 49,100 46,000 362,800 556,000
------------ ------------ ------------ ------------
Total 186,100 257,000 10,955,600 10,839,000
============ ============ ============ ============
</TABLE>
14
<PAGE> 15
Lease Operating Expenses
Lease operating expenses, including severance taxes, for the nine-month period
ending September 30, 2000 were $6.4 million compared to $5.3 million for the
same period in 1999 and reflect the increased costs associated with expenses
related to new production.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the nine months ending September
30, 2000 and 1999 was $12.9 million and $12.2 million, respectively. A higher
average rate in 2000 resulted in the increase.
General and Administrative
General and administrative expense decreased from $3.4 million for the nine
months ended September 30, 1999 to $3.0 million for the nine months ended
September 30, 2000. This decrease is primarily the result of severance benefits
paid in 1999 related to personnel reductions that were effective June 1, 1999.
Interest Expense
Interest expense increased from $4.4 million during the nine months ended
September 30, 1999 to $5.9 million during the nine months ended September 30,
2000 reflecting the increase in the Company's long-term debt.
15
<PAGE> 16
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's revenues are derived from the sale of its crude oil and natural
gas production. In recent months, the prices for oil and gas have increased;
however, they remain extremely volatile and sometimes experience large
fluctuations as a result of relatively small changes in supplies, weather
conditions, economic conditions and government actions. From time to time, the
Company enters into derivative financial instruments to hedge oil and gas price
risks for the production volumes to which the hedge relates. The hedges reduce
the Company's exposure on the hedged volumes to decreases in commodity prices
and limit the benefit the Company might otherwise have received from any
increases in commodity prices on the hedged volumes.
The Company also enters into price "collars" to reduce the risk of changes in
oil and gas prices. Under these arrangements, no payments are due by either
party so long as the market price is above the floor price set in the collar and
below the ceiling. If the price falls below the floor, the counter-party to the
collar pays the difference to the Company and if the price is above the ceiling,
the counter-party receives the difference from the Company. The Company enters
into these various agreements from time to time to reduce the effects of
volatile oil and gas prices and does not enter into hedge transactions for
speculative purposes. See Note 3 to the Consolidated Financial Statements for a
description of the Company's hedged position at September 30, 2000.
Approximately $2.8 million related to hedging was recognized as a reduction in
oil and gas revenue in the first nine months of 2000. There have been no
significant changes in market risks faced by the Company since the end of 1999.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." The Statement establishes accounting and
reporting standards that require every derivative instrument (including certain
derivative instruments embedded in other contracts) to be recorded in the
balance sheet as either an asset or liability measured at its fair value and
that changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. If those criteria are met,
the instruments are treated as hedges under SFAS No. 133 creating volatility in
equity through changes in other comprehensive income due to the marking to
market of the hedging contracts. We will adopt SFAS No. 133 on January 1, 2001.
We currently have no derivative instruments or hedging contracts, which extend
past December 31, 2000, other than the volumetric production payment, which
qualifies for the normal sales exception under SFAS 133. However, we may enter
into new hedging arrangements prior to December 31, 2000. Depending upon the
nature of any future hedging arrangements, the adoption of SFAS 133 may create
volatility in our results of operations and/or stockholders' equity.
16
<PAGE> 17
CALLON PETROLEUM COMPANY
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a.) Exhibits
2. Plan of acquisition, reorganization, arrangement,
liquidation or succession*
3. Articles of Incorporation and By-Laws
3.1 Certificate of Incorporation of the Company,
as amended (incorporated by reference from
Exhibit 3.1 of the Company's Registration
Statement on Form S-4, filed August 4, 1994,
Reg. No. 33-82408)
3.2 Certificate of Merger of Callon Consolidated
Partners, L. P. with and into the Company
dated September 16, 1994 (incorporated by
reference from Exhibit 3.2 of the Company's
Report on Form 10-K for the period ended
December 31, 1994)
3.3 Bylaws of the Company (incorporated by
reference from Exhibit 3.2 of the Company's
Registration Statement on Form S-4, filed
August 4, 1994, Reg. No. 33-82408)
4. Instruments defining the rights of security holders,
including indentures
4.1 Specimen stock certificate (incorporated by
reference from Exhibit 4.1 of the Company's
Registration Statement on Form S-4, filed
August 4, 1994, Reg. No. 33-82408)
4.2 Specimen Preferred Stock Certificate
(incorporated by reference from Exhibit 4.2
of the Company's Registration Statement on
Form S-1, Reg. No. 33-96700)
4.3 Designation for Convertible Exchangeable
Preferred Stock, Series A (incorporated by
reference from Exhibit 4.3 of the Company's
Registration Statement on Form S-1/A, filed
November 13, 1995, Reg. No. 33-96700)
17
<PAGE> 18
4.4 Indenture for Convertible Debentures
(incorporated by reference from Exhibit 4.4
of the Company's Registration Statement on
Form S-1, filed November 13, 1995, Reg. No.
33-96700)
4.5 Certificate of Correction on Designation of
Series A Preferred Stock (incorporated by
reference from Exhibit 4.4 of the Company's
Registration Statement on Form S-1, filed
November 22, 1996, Reg. No. 333-15501)
4.6 Form of Note Indenture for the Company's 10%
Senior Subordinated Notes due 2001
(incorporated by reference from Exhibit 4.6
of the Company's Registration Statement on
Form S-1, filed November 22, 1996, Reg. No.
333-15501)
4.7 Form of Note Indenture for the Company's
10.25% Senior Subordinated Notes due 2004
(incorporated by reference from Exhibit 4.10
of the Company's Registration Statement on
Form S-2, filed June 14, 1999, Reg. No.
333-80579)
4.8 Rights Agreement between Callon Petroleum
Company and American Stock Transfer & Trust
Company, Rights Agent, dated March 30, 2000
(incorporated by reference from Exhibit 4 of
the Company's 8-K filed April 6, 2000)
4.9 Subordinated Indenture for the Company dated
October 26, 2000 (incorporated by reference
from Exhibit 4.1 of the Company's Current
Report on Form 8-K dated October 24, 2000)
4.10 Supplemental Indenture for the Company's 11%
Senior Subordinated Notes due 2005
(incorporated by reference from Exhibit 4.2
of the Company's Current Report on Form 8-K
dated October 24, 2000)
10. Material contracts
10.1 Callon Petroleum Company 1996 Stock
Incentive Plan as amended on May 9, 2000
(incorporated by reference from Appendix I
of the Company's Definitive Proxy Statement
on Schedule 14A filed March 28, 2000)
10.2 Credit Agreement dated as of October 30,
2000 between the Company and First Union
National Bank, as administrative agent for
the lenders
11. Statement re computation of per share earnings*
15. Letter re unaudited interim financial information*
18
<PAGE> 19
18. Letter re change in accounting principles*
19. Report furnished to security holders*
22. Published report regarding matters submitted to vote
of security holders*
23. Consents of experts and counsel*
24. Power of attorney*
27. Financial Data Schedule
99. Additional exhibits*
(b) Reports on Form 8-K
The Company filed an 8-K on September 28, 2000
regarding a press release describing the Tender Offer
for Subordinated Notes due 2001 and an intention to
sell additional Subordinated Notes due 2005.
*Inapplicable to this filing
19
<PAGE> 20
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.
CALLON PETROLEUM COMPANY
Date: November 10, 2000 By: /s/ John S. Weatherly
--------------------- ---------------------------------------
John S. Weatherly, Senior Vice President
and Chief Financial Officer
(on behalf of the registrant and as the
principal financial officer)
20
<PAGE> 21
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C>
10.2 Credit Agreement dated as of October 30, 2000 between the
Company and First Union National Bank, as administrative agent
for the lenders
27 Financial Data Schedule
</TABLE>
