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 June 30, 1999 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
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(Address of principal executive offices)(Zip code)
(601) 442-1601
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(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 August 10, 1999, there were 8,557,906 shares of the Registrant's
Common Stock, par value $0.01 per share, outstanding.
<PAGE>
CALLON PETROLEUM COMPANY
INDEX
Page No.
Part I. Financial Information
Consolidated Balance Sheets as of June 30,
1999 and December 31, 1998 3-4
Consolidated Statements of Operations for Each of the
three and six-months in the periods ended June 30, 1999
and June 30, 1998 5
Consolidated Statements of Cash Flows for Each of the
six-months in the periods ended June 30, 1999 and
June 30, 1998 6
Notes to Consolidated Financial Statements 7-8
Management's Discussion and Analysis of
Financial Condition and Results of Operations 9-14
Part II. Other Information 15
<PAGE>
Callon Petroleum Company
Consolidated Balance Sheets
(In thousands, except per share data)
June 30, December 31,
1999 1998
--------- ---------
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents $ 7,334 $ 6,300
Accounts receivable 5,287 6,024
Other current assets 939 1,924
--------- ---------
Total current assets 13,560 14,248
--------- ---------
Oil and gas properties, full cost accounting method:
Evaluated properties 484,202 444,579
Less accumulated depreciation, depletion and
amortization (353,144) (345,353)
--------- ---------
131,058 99,226
Unevaluated properties excluded from amortization 42,509 42,679
--------- ---------
Total oil and gas properties 173,567 141,905
--------- ---------
Pipeline and other facilities 6,021 6,182
Other property and equipment, net 1,556 1,753
Deferred tax asset 15,989 16,348
Long-term gas balancing receivable 224 199
Other assets, net 909 1,017
--------- ---------
Total assets $ 211,826 $ 181,652
========= =========
The accompanying notes are an integral part of the financial statements.
<PAGE>
Callon Petroleum Company
Consolidated Balance Sheets
(In thousands, except per share data)
June 30, December 31,
1999 1998
--------- ---------
(Unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 8,913 $ 11,257
Deferred revenue on sale of production
payment interest - current portion 4,844 --
Undistributed oil and gas revenues 2,029 1,720
Accrued net profits payable 250 129
--------- ---------
Total current liabilities 16,036 13,106
--------- ---------
Accounts payable and accrued liabilities to
be refinanced 1,763 3,000
Long-term debt 99,250 78,250
Deferred revenue on sale of production
payment interest 9,671 --
Accrued retirement benefits 2,215 2,323
Long-term gas balancing payable 491 489
--------- ---------
Total liabilities 129,426 97,168
--------- ---------
Stockholders' equity:
Preferred stock, $0.01 par value, 2,500,000
shares authorized; 1,045,461 shares of
Convertible Exchangeable Preferred Stock,
Series A, issued and outstanding with a
liquidation preference of $26,136,525 at
June 30, 1999 10 13
Common stock, $0.01 par value, 20,000,000
shares authorized; 8,545,517 and
8,178,406 outstanding at June 30, 1999
and at December 31, 1998, respectively 86 82
Treasury stock (98,578 shares at cost) (1,177) (915)
Capital in excess of par value 108,296 109,429
Retained earnings (deficit) (24,815) (24,125)
--------- ---------
Total stockholders' equity 82,400 84,484
--------- ---------
Total liabilities and stockholders' equity $ 211,826 $ 181,652
========= =========
The accompanying notes are an integral part of the financial statements.
<PAGE>
Callon Petroleum Company
Consolidated Statements Of Operations
(Unaudited)
(In thousands, except per share amounts)
Three Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
1999 1998 1999 1998
------- ------- ------- -------
Revenues:
Oil and gas sales $ 8,568 $ 9,277 $16,537 $20,322
Interest and other 463 456 868 903
------- ------- ------- -------
Total revenues 9,031 9,733 17,405 21,225
------- ------- ------- -------
Costs and expenses:
Lease operating expenses 1,878 2,148 3,486 4,089
Depreciation, depletion and
amortization 3,989 4,896 7,952 10,466
General and administrative 1,379 1,230 2,440 2,732
Interest 1,444 332 2,471 983
------- ------- ------- -------
Total costs and expenses 8,690 8,606 16,349 18,270
------- ------- ------- -------
Income from operations 341 1,127 1,056 2,955
Income tax expense 116 380 359 1,001
------- ------- ------- -------
Net income 225 747 697 1,954
Preferred stock dividends 555 699 1,386 1,398
------- ------- ------- -------
Net income (loss) available to
common shares $ (330) $ 48 $ (689) $ 556
======= ======= ======= =======
Net income (loss) per common share:
Basic $ (0.04) $ 0.01 $ (0.08) $ 0.07
Diluted $ (0.04) $ 0.01 $ (0.08) $ 0.07
Shares used in computing net income
(loss) per common share:
Basic 8,447 8,028 8,462 8,021
Diluted 8,447 8,247 8,462 8,233
The accompanying notes are an integral part of these financial statements.
<PAGE>
Callon Petroleum Company
Consolidated Statements Of Cash Flows
(Unaudited)
(In thousands)
Six Months Ended
June 30, June 30,
1999 1998
-------- --------
Cash flows from operating activities:
Net income $ 697 $ 1,954
Adjustments to reconcile net income to
cash provided by operating activities:
Depreciation, depletion and amortization 8,210 10,722
Amortization of deferred costs 276 318
Amortization of deferred production
payment revenue (252) --
Deferred income tax expense 359 1,001
Noncash compensation related to compensations plans 141 1,033
Changes in current assets and liabilities:
Accounts receivable 737 1,344
Other current assets 985 (430)
Current liabilities (1,532) 357
Changes in gas balancing receivable (25) 20
Changes in gas balancing payable 2 (52)
Change in other long-term liabilities (108) --
Change in other assets, net (168) (82)
------- --------
Cash provided (used) by operating activities 9,322 16,185
------- --------
Cash flows from investing activities:
Capital expenditures (25,129) (23,733)
Cash proceeds from sale of mineral interests -- 10,211
Cash proceeds from sale of mineral interest burdened
by a net profits interest -- 19,957
------- --------
Cash provided (used) by investing activities (25,129) 6,435
------- --------
Cash flows from financing activities:
Decrease in accounts payable and accrued liabilities
to be refinanced (1,237) --
Increase in debt 21,000 --
Equity issued related to employee stock plans 66 249
Purchase of treasury shares (262) --
Common stock cancelled (1,615) (145)
Dividends on preferred stock (1,111) (1,398)
------- --------
Cash provided (used) by financing activities 16,841 (1,294)
------- --------
Net increase (decrease) in cash and cash equivalents 1,034 21,326
Cash and cash equivalents:
Balance, beginning of period 6,300 15,597
------- --------
Balance, end of period $ 7,334 $ 36,923
======= ========
The accompanying notes are an integral part of these financial statements
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
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, 1998 included in the
Company's Annual Report on Form 10-K dated March 29, 1999.
2. Per Share Amounts
In February 1997, the Financial Accounting Standards Board issued Statement
No. 128 ("FAS 128"), Earnings Per Share, which generally simplified the manner
in which earnings per share are determined. The Company adopted FAS 128
effective December 15, 1997.
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 per common share for 1998 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). In the 1999 earnings per share
computations, all stock options were excluded from the computation of diluted
loss per share because they were antidilutive. The conversion of the
preferred stock was not included in any calculation 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):
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
------ ------ ------ ------
(a) Net income (loss) available for
common shares $ (330) $ 48 $ (689) $ 556
(b) Weighted average shares outstanding 8,447 8,028 8,462 8,021
(c) Dilutive impact of stock options -- 219 -- 212
(d) Total diluted shares 8,447 8,247 8,462 8,233
Stock options excluded as antidilutive 34 -- 39 --
Basic earnings (loss) per share (a/b) $(0.04) $ 0.01 $(0.08) $ 0.07
Diluted earnings (loss) per share (a/d) $(0.04) $ 0.01 $(0.08) $ 0.07
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 $730,000 and $763,000 was
recognized as additional oil and gas revenue in the first six months of 1999
and 1998, respectively.
<PAGE>
As of June 30, 1999, the Company had open collar contracts with third parties
whereby minimum floor prices and maximum ceiling prices are contracted and
applied to related contract volumes. These agreements in effect for 1999 are
for average gas volumes of 450,000 Mcf per month through November 1999 at
(on average) a ceiling price of $2.35 and floor price of $2.02. In addition,
the Company had open oil collar contracts averaging 25,000 barrels per month
at (on average) a ceiling of $16.22 and a floor of $13.85 from April 1999
through December 1999.
Also at June 30, 1999 the Company had open forward natural gas swap contracts
of 200,000 Mcf per month from July 1999 through September 1999 with a fixed
contract price of $2.35. In addition, the Company had open forward crude oil
swap contracts of 10,000 barrels per month with a fixed contract price of
$14.10 per month from July 1999 through September 1999.
4. Preferred Stock
During the first quarter of 1999 certain preferred stockholders through
private transactions, agreed to convert 210,350 shares of Preferred Stock
into 502,632 shares of the Company's Common Stock. Any noncash premium
negotiated in excess of the conversion rate was recorded as additional
preferred stock dividends and excluded from the Consolidated Statements
of Cash Flows.
5. Senior Subordinated Notes
On July 14, 1999 the Company issued $40 million of 10.25% Senior Subordinated
Notes due 2004. Interest is payable quarterly beginning September 15, 1999.
The net proceeds to the Company, after costs of the transaction, were used to
repay the outstanding balance on the Credit Facility.
6. Deferred Revenue on Sale of Production Payment Interest
In June 1999, the Company acquired a working interest in the Mobile Block 864
Area in which the Company already owned an interest. Concurrent with this
acquisition, the seller received a volumetric production payment, valued at
approximately $14.8 million, from production attributable to a portion of the
Company's interest in the area over a three and a quarter year period. The
Company deferred the revenue associated with the sale of this production
payment interest because a substantial obligation for future performance
existed. Under the terms of the sale, the Company was obligated to deliver
the production volumes free and clear of royalties, lease operating expenses,
production taxes and all capital costs. The production payment was recorded
at the present value of the volumetric production committed to the seller at
market value and, beginning in June 1999, is amortized to oil and gas sales
on the units-of-production method as associated hydrocarbons are delivered.
<PAGE>
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 contain 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 increased during the six months
ending June 30, 1999 by $1.0 million. Net cash flow from operations before
working capital changes for the period totaled $9.4 million. Net capital
expenditures for the period totaled $25.1 million. These funds were
primarily expended in drilling and completion of six wells and the completion
of three additional wells. Increases in cash flows from financing activities
during the six-month period included $21.0 million borrowed against the credit
facility. Decreases for the same period included a $1.2 million reduction in
accounts payable and accrued liabilities to be refinanced, $1.6 million
related to the surrender and cancellation of common stock in satisfaction of
payroll taxes related to performance share awards previously issued pursuant
<PAGE>
to the Company's Stock Incentive Plans and $1.1 million was paid to the
preferred stockholders as dividends.
On July 15, 1999, the Company announced its offering of $40 million Senior
Subordinated Notes due 2004 at a yield of 10.25 percent. The net proceeds
from the offering (approximately $38.4 million), together with cash flows and
borrowings under its credit facility, will be used to fund the Company's
remaining 1999 capital expenditure budget and a portion of its 2000 capital
expenditure budget. Pending the use of the net proceeds, the Company
repaid amounts under its credit facility, which may be reborrowed at a later
date.
For the balance of the year, the Company will continue evaluating property
acquisitions and drilling opportunities. The Company's current total capital
expenditure budget for 1999 is $66.8 million (which includes a $14.8 million
non-cash production payment). The remaining capital expenditure budget for
1999 is approximately $27 million. Approximately $15 million is associated
with the drilling of six exploratory wells to evaluate acreage in the Company's
prospect inventory. The balance of the budget amount is allocated to
completion costs for successful wells and potential lease acquisitions. The
capital budget will be financed with available cash, projected cash flow
from operations and unused capacity under the Company's credit facility.
Disclosure About Market Risks
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 a 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.
We enter into these various agreements to reduce the effects of volatile oil
and gas prices and do 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 June 30, 1999. Approximately
$730,000 related to hedging was recognized as additional oil and gas revenue
in the first six months of 1999. There have been no significant changes in
market risks faced by the Company since the end of 1998.
Year 2000 Compliance
There have not been any significant developments nor significant additional
risks identified since the end of 1998. The Company continues to focus
efforts on identifying and solving the many threats to its business posed by
the Year 2000 issue. These risks are generally divided into three areas,
(1) failure of our financial and administrative systems, (2) failure of the
embedded systems which control our automated production facilities and
(3) failure of our suppliers and purchasers to correct their Year 2000
problems. The Company believes that its financial accounting software and
the embedded systems affecting its automated production facilities are in
compliance. The Company continues to correspond with our suppliers and
purchasers to access compliance. Since we are unable to independently
verify that they are taking appropriate steps to remedy problems, no
<PAGE>
assurances can be made that the Company may not encounter adverse effects
caused by the Year 2000 problems.
Although the Company does not separately account for its internal costs
incurred for its Year 2000 compliance efforts, consisting mainly of
payroll and related benefits for our information systems personnel, we
are still projecting the compliance costs to be less than $200,000.
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.
Three Months Six Months
Ended June 30, Ended June 30,
1999 1998 1999 1998
----- ----- ----- -----
Production volumes:
Oil (MBbls) 86 82 176 193
Gas (MMcf) 3,474 3,640 6,843 7,676
Total (MMcfe) 3,989 4,129 7,898 8,835
Average sales price: (a)
Oil (Bbl) $12.46 $11.98 $11.96 $13.06
Gas (Mcf) 2.16 2.28 2.11 2.32
Total (Mcfe) 2.15 2.25 2.09 2.30
Average costs (per Mcfe):
Lease operating (excluding severance
taxes) $ 0.41 $ 0.46 $ 0.38 $ 0.39
Severance taxes 0.06 0.06 0.06 0.07
Depreciation, depletion and amortization 1.00 1.19 1.01 1.18
General and administrative (net of
management fees) 0.35 0.30 0.31 0.31
_____
(a) Includes hedging gains and losses.
Comparison of Results of Operations for the Three Months Ended June 30, 1999
and the Three Months Ended June 30, 1998.
Oil and Gas Production and Revenues
Total oil and gas revenues decreased 8% from $9.3 million in 1998 to $8.6
million. When compared to the same period last year, oil production and prices
were higher while gas production and prices were lower.
Oil production during the second quarter of 1999 totaled 86,000 barrels and
generated $1.1 million in revenues compared to 82,000 barrels and $1.0 million
in revenues for the same period in 1998. Second quarter average daily
production increased from 896 barrels per day in 1998 to 942 barrels per day
in 1999. When the second quarter of 1999 production is compared to the same
period in 1998, the increases from Main Pass 26 and Eugene Island 335 totaling
28,000 barrels is partially offset by the 17,000 barrel loss from Black Bay,
which was sold in May 1998.
Gas production during the second quarter of 1999 totaled 3.5 billion cubic
feet and generated $7.5 million in revenues compared to 3.6 billion cubic
feet and $8.3 million in revenues during the same period in 1998. The average
sales price for the second quarter of 1999 averaged $2.16 per thousand cubic
feet compared to $2.28 per thousand cubic feet at this time last year. When
compared to the same quarter last year, the Company has added gas production
from new discoveries at Main Pass 26 and Eugene Island 335 but has experienced
reduced production from several Shallow Miocene wells which normally have a
steep decline curve. Except for the increase at Main Pass 31, which was the
<PAGE>
result of a recompletion, other properties continue to experience normal and
expected declines.
The following table summarizes oil and gas production from the Company's major
producing properties for the comparable periods.
Oil Production Gas Production
(Barrels) (Mcf)
Three Months Ended Three Months Ended
June 30, June 30,
1999 1998 1999 1998
------- ------- --------- ---------
Mobile Block 864 Area -- -- 1,290,000 1,390,000
Chandeleur Block 40 -- -- 207,000 682,000
Main Pass 163 Area -- -- 398,000 531,000
Main Pass 26 18,000 -- 342,000 --
Eugene Island 335 10,000 -- 316,000 --
Main Pass 31 11,000 11,000 429,000 304,000
Main Pass 164/165 -- -- 133,000 305,000
North Dauphin Island Field -- -- 121,000 180,000
Black Bay -- 17,000 -- --
Escambia Mineral properties 34,000 37,000 60,000 61,000
Other properties 13,000 17,000 178,000 187,000
------- ------- --------- ---------
Total 86,000 82,000 3,474,000 3,640,000
======= ======= ========= =========
Lease Operating Expenses
Lease operating expenses, including severance taxes, for the three-month
period ending June 30, 1999 were $1.9 million compared to $2.1 million for
the same period in 1998. This reduction is attributable to the sale of
Black Bay in May 1998.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the three months ending June 30,
1999 and 1998 was $4.0 million and $4.9 million, respectively, reflecting the
overall decrease in production. During the three months ended June 30, 1999
and 1998, the rate on a per unit basis was $1.00 and $1.19, respectively. The
reduction in the rate was a result of the ceiling test writedown in December
1998.
General and Administrative
General and administrative expense for the three months ended June 30, 1999
was $1.4 million compared to $1.2 million for the three months ended June 30,
1998. This expense increase is generally attributable to severance benefits
related to personnel reductions effective June 1, 1999 and reduced overhead
recoveries through management fees and operating fees from Black Bay, which
was sold in May 1998.
Interest Expense
Interest expense increased from $332,000 during the three months ended June 30,
1998 to $1.4 million during the three months ended June 30, 1999 reflecting
the increase in the Company's long-term debt. The Company capitalizes a
portion of the total interest charges as additional property costs associated
with its drilling and exploration activities.
Income Taxes
Income taxes were provided at the expected statutory rate of 34% of net income.
<PAGE>
Comparison of Results of Operations for the Six Months Ended June 30, 1999
and the Six Months Ended June 30, 1998.
Oil and Gas Production and Revenues
For the six months ended June 30, 1999, total oil and gas revenues decreased by
$3.8 million, or 19%, to $16.5 million when compared to $20.3 million for the
same period in 1998. When compared to the same period last year, both oil and
gas production and prices declined.
For the six months ending June 30, 1999, oil production and oil revenues
decreased to 176,000 barrels and $2.1 million, respectively. For the
comparable period in 1998, oil production was 193,000 barrels while revenues
totaled $2.5 million. Oil prices during the first six months of 1999 averaged
$11.96, compared to $13.06 for the same period in 1998. When the production
in the first six months in 1999 is compared to the same period in 1998, the
increases from new discoveries at Main Pass 26 and Eugene Island 335 totaling
49,000 barrels was offset by the 57,000 barrel loss from Black Bay, which was
sold in May 1998. A normal decline was experienced at the Escambia Mineral
property.
Natural gas production and revenue for the six-month period ending June 30,
1999 were 6.8 billion cubic feet and $14.4 million, respectively, decreasing
from 7.7 billion cubic feet and gas revenues of $17.8 million in the first
six months of 1998. The average sales price for natural gas in the first six
months in 1999 was $2.11 per thousand cubic feet, a $0.21 per thousand cubic
feet decrease over the same period in 1998. When compared to the same six-
month period last year, the Company added gas production from new discoveries
at Main Pass 26 and Eugene Island 335 but has experienced reduced production
from several Shallow Miocene wells which normally have a steep decline curve.
Except for the increase at Main Pass 31, which is the result of a recompletion,
other properties continue to experience normal and expected declines.
The following table summarizes oil and gas production from the Company's major
producing properties for the comparable periods.
Oil Production Gas Production
(Barrels) (Mcf)
Six Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
------- ------- --------- ---------
Mobile Block 864 Area -- -- 2,553,000 2,904,000
Chandeleur Block 40 -- -- 509,000 1,461,000
Main Pass 163 Area -- -- 727,000 1,190,000
Main Pass 26 35,000 -- 578,000 --
Eugene Island 335 14,000 -- 505,000 --
Main Pass 31 27,000 27,000 907,000 648,000
Main Pass 164/165 -- -- 332,000 616,000
North Dauphin Island Field -- -- 263,000 403,000
Black Bay -- 57,000 -- --
Escambia Mineral properties 71,000 80,000 127,000 135,000
Other properties 29,000 29,000 342,000 319,000
------- ------- --------- ---------
Total 176,000 193,000 6,843,000 7,676,000
======= ======= ========= =========
Lease Operating Expenses
Lease operating expenses, excluding severance taxes, for the first half of
1999 decreased 14% to $3.0 million from $3.5 million for the 1998 comparable
period. This decrease is primarily the result of the sale of Black Bay in
May 1998. Severance taxes were $0.5 million for the 1999 period and compares
to $0.6 million for the same six-month period in 1998.
<PAGE>
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the first six months of 1999 was
$8.0 million, or $1.01 per thousand cubic feet equivalent. For the same period
in 1998, the total was $10.5 million and $1.18 per thousand cubic feet
equivalent. This decline is primarily a result of lower production volumes in
the period and a reduction in the rate as a result of the ceiling test
writedown in December 1998.
General and Administrative
During the first six months of 1999, general and administrative expenses
decreased by 11% to $2.4 million when compared to $2.7 million for the
six-month period in 1998. While expenses associated with personnel
reductions were incurred during the first six months of 1999, there were no
expenses associated with bonuses under the incentive compensation plan and
amortization of expenses associated with the vesting of performance shares
which were incurred during the first half of 1998.
Interest Expense
Interest expense during the first half of 1999 was $2.5 million compared to
$1.0 million for the first half of 1998 as a result of the increase in the
Company's long-term debt. The Company capitalizes a portion of the total
interest charges as additional property costs associated with its drilling
and exploration activities.
Income Taxes
Income taxes were provided at the expected statutory rate of 34% of net income.
<PAGE>
CALLON PETROLEUM COMPANY
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders.
The Company's annual meeting was held on April 29, 1999, at which
three Class II directors were elected and the appointment of Arthur
Andersen LLP as the Company's independent public accountants for
the year ending December 31,1999 was ratified.
The nominees for director were Messrs. John S. Callon, B. F. Weatherly
and Leif Dons. Mr. Callon received 7,444,273 votes for, 17,251 votes
against or withheld and no votes abstained. Mr. Weatherly received
7,445,791 votes for, 15,733 votes against or withheld and no votes
abstained. Mr. Dons received 7,445,644 votes for, 15,880 votes
against or withheld and no votes abstained.
The ratification of Arthur Andersen LLP received 7,447,820 votes for,
6,713 votes against or withheld and 6,991 votes abstained.
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 fiscal year 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/A, filed November 13, 1995,
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)
4.4 Indenture for Convertible Debentures (incorporated by
reference from Exhibit 4.4 of the Company's Registration
Statement on Form S-1/A, filed November 13, 1995,
Reg. No. 33-96700)
<PAGE>
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/A,
filed November 22, 1996, Reg. No. 333-15501)
4.6 Form of Note Indenture (incorporated by reference from
Exhibit 4.6 of the Company's Registration Statement on Form
S-1/A, filed November 22, 1996, Reg. No. 333-15501)
4.7 Form of Note Indenture (incorporated by reference from
Exhibit 4.10 of the Company's Registration Statement on Form
S-2/A, filed June 25, 1999, Reg. No. 333-80579)
10. Material contracts
10.1 Purchase and Sale Agreement between Callon Petroleum
Operating Company and Murphy Exploration Company, dated May 26,
1999 (incorporated by reference from Exhibit 10.11 on Form S-2,
filed June 14, 1999, Reg. No. 333-80579)
11. Statement re computation of per share earnings
11.1 Computation of Per Share Earnings
15. Letter re unaudited interim financial information*
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
None
- -------------
*Inapplicable to this filing
<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.
CALLON PETROLEUM COMPANY
Date August 11, 1999 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)
<PAGE>
Exhibit 11.1
CALLON PETROLEUM COMPANY
COMPUTATION OF PER SHARE EARNINGS
(In thousands, except per share data)
Three Months Ended Six Months Ended
June 30, June 30,
---------------- -----------------
1999 1998 1999 1998
------ ------ ------ ------
Net income $ 225 $ 747 $ 697 $1,954
Preferred stock dividends 555 699 1,386 1,398
------ ------ ------ ------
Net income (loss) available to
common shares $ (330) $ 48 $ (689) $ 556
====== ====== ======= ======
Net income (loss) per common share:
Basic $(0.04) $ 0.01 $(0.08) $ 0.07
Diluted $(0.04) $ 0.01 $(0.08) $ 0.07
Shares used in computing net income
(loss) per common share:
Basic 8,447 8,028 8,462 8,021
Dilutive impact of stock options -- 219 -- 212
------ ------ ------ ------
Diluted 8,447 8,247 8,462 8,233
====== ====== ====== ======
Stock options excluded as
antidilutive 34 -- 39 --
====== ====== ====== ======
Note: 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 per common share for
1998 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). In the 1999 earnings
per share computations, all stock options were excluded from the computation
of diluted loss per share because they were antidilutive. The conversion of
the preferred stock was not included in any calculation due to their
antidilutive effect on diluted income or loss per share.
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS FINANCIAL DATA SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED
FROM THE CONSOLIDATED FINANCIAL STATEMENTS OF CALLON PETROLEUM COMPANY FOR THE
PERIOD ENDING JUNE 30, 1999 WHICH ARE PRESENTED IN ITS QUARTERLY REPORT ON FORM
10-Q AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<CASH> 7,334
<SECURITIES> 0
<RECEIVABLES> 5,287
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 13,560
<PP&E> 534,288
<DEPRECIATION> 353,144
<TOTAL-ASSETS> 211,826
<CURRENT-LIABILITIES> 16,036
<BONDS> 0
0
10
<COMMON> 86
<OTHER-SE> 82,304
<TOTAL-LIABILITY-AND-EQUITY> 211,826
<SALES> 16,537
<TOTAL-REVENUES> 17,405
<CGS> 0
<TOTAL-COSTS> 13,878
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 2,471
<INCOME-PRETAX> 1,056
<INCOME-TAX> 359
<INCOME-CONTINUING> 697
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 697
<EPS-BASIC> (0.08)
<EPS-DILUTED> (0.08)
</TABLE>
