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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-QSB
[X] QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
FOR THE QUARTER ENDED SEPTEMBER 30, 2003
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF EXCHANGE ACT
COMMISSION FILE NO. 0-12185
DAUGHERTY RESOURCES, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
PROVINCE OF BRITISH COLUMBIA NOT APPLICABLE
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
120 PROSPEROUS PLACE, SUITE 201
LEXINGTON, KENTUCKY 40509-1844
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (859) 263-3948
Number of shares outstanding of each of the issuer's classes of common equity,
as of the latest practicable date.
TITLE OF CLASS OUTSTANDING AT OCTOBER 31, 2003
COMMON STOCK 9,959,902
Transitional Small Business Disclosure Format. Yes [ ] No [X]
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DAUGHERTY RESOURCES, INC.
INDEX
PART I. FINANCIAL INFORMATION PAGE
----
ITEM 1. FINANCIAL STATEMENTS:
Review Engagement Report............................................. 2
Condensed Consolidated Balance Sheets -- September 30, 2003
(unaudited) and December 31, 2002.................................. 3
Condensed Consolidated Statement of Operations and Deficit --
Three months and nine months ended September 30, 2003 and
2002 (unaudited)................................................... 4
Condensed Consolidated Statement of Cash Flows -- Three months
and nine months ended September 30, 2003 and 2002 (unaudited)...... 5
Notes to Condensed Consolidated Financial Statements................. 6
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.......................................... 15
ITEM 3. CONTROLS AND PROCEDURES..................................... 23
PART II. OTHER INFORMATION........................................... 24
1
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
REVIEW ENGAGEMENT REPORT
To the Directors of
DAUGHERTY RESOURCES, INC.
We have reviewed the condensed consolidated balance sheet of DAUGHERTY
RESOURCES, INC. as at September 30, 2003 and the condensed consolidated
statements of operations and deficit and cash flows for the three and nine
months ended September 30, 2003. Our review was made in accordance with
generally accepted standards for review engagements in Canada and the United
States of America and accordingly consisted primarily of enquiry, analytical
procedures and discussion related to information supplied to us by the Company.
A review does not constitute an audit and, consequently, we do not express an
audit opinion on these condensed consolidated financial statements.
Based on our review, nothing has come to our attention that causes us to believe
that these condensed consolidated financial statements are not, in all material
respects, in accordance with Canadian generally accepted accounting principles.
We have previously audited, in accordance with auditing standards generally
accepted in Canada and the United States of America, the balance sheet as at
December 31, 2002 and the related statements of operations and deficit and cash
flows for the year then ended (not presented herein) and, in our report dated
March 23, 2003, we expressed an unqualified opinion on those financial
statements. In our opinion, the information set forth in the accompanying
consolidated balance sheet as of December 31, 2002 is fairly stated in all
material respects in relation to the balance sheet from which it has been
derived.
/s/ KRAFT, BERGER, GRILL, SCHWARTZ, COHEN & MARCH LLP
-----------------------------------------------------
KRAFT, BERGER, GRILL, SCHWARTZ, COHEN & MARCH LLP
CHARTERED ACCOUNTANTS
Toronto, Ontario
November 4, 2003
2
DAUGHERTY RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(U.S. FUNDS)
(UNAUDITED)
SEPTEMBER 30, DECEMBER 31,
2003 2002
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents ......................................... $ 14,162,407 $ 7,031,307
Accounts receivable ............................................... 542,251 328,035
Prepaid expenses and other current assets ......................... 668,130 460,663
Loans to related parties (Note 4) ................................. 117,301 64,162
------------ ------------
Total current assets ............................................. 15,490,089 7,884,167
Bonds and deposits ................................................. 41,000 41,000
Oil and gas properties (Note 2) .................................... 12,850,415 9,679,549
Property and equipment (Note 3) .................................... 1,490,871 918,855
Loans to related parties (Note 4) .................................. 576,614 711,658
Investment (Note 5) ................................................ 119,081 119,081
Deferred financing costs (Note 6) .................................. 593,526 43,546
Goodwill (Note 7) .................................................. 313,177 313,177
------------ ------------
Total assets ..................................................... $ 31,474,773 $ 19,711,033
============ ============
LIABILITIES
Current liabilities:
Bank loans (Note 8) ............................................... $ 134,162 $ 134,162
Accounts payable .................................................. 1,064,276 1,094,941
Accrued liabilities ............................................... 1,167,101 1,212,094
Income taxes payable .............................................. 274,765 --
Customers' drilling deposits ...................................... 4,824,300 6,764,200
Long term debt, current portion (Note 9) .......................... 409,669 192,341
------------ ------------
Total current liabilities ........................................ 7,874,273 9,397,738
Long term debt (Note 9) ............................................ 7,474,097 4,027,198
------------ ------------
Total liabilities ................................................ 15,348,370 13,424,936
------------ ------------
SHAREHOLDERS' EQUITY
Capital Stock (Note 10)
Authorized:
5,000,000 Preferred shares, non-cumulative, convertible
100,000,000 Common shares
Issued: 0 Preferred shares (2002 - 558,476) ..................... -- 1,784,493
9,932,102 Common shares (2002 - 5,505,670) ...................... 33,528,535 24,589,797
21,100 Common shares held in treasury, at cost ............... (23,630) (23,630)
Paid in capital -- Warrants ........................................ 223,086 --
To be issued:
24,887 Common shares ......................................... 55,226 55,226
------------ ------------
33,783,217 26,405,886
Accumulated deficit ................................................ (17,656,814) (20,119,789)
------------ ------------
Total shareholders' equity ....................................... 16,126,403 6,286,097
------------ ------------
Total liabilities and shareholders' equity ........................... $ 31,474,773 $ 19,711,033
============ ============
See Notes to Condensed Consolidated Financial Statements.
3
DAUGHERTY RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT
(U.S. FUNDS)
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------------- ----------------------------
2003 2002 2003 2002
------------ ------------ ------------ ------------
REVENUE
Contract drilling (Note 12) ...................... $ 3,866,000 $ 556,733 $ 14,924,000 $ 4,040,733
Oil and gas production ........................... 749,340 320,453 1,815,630 777,899
Gas transmission and compression ................. 269,801 220,343 827,835 715,606
------------ ------------ ------------ ------------
Total revenue ................................... 4,885,141 1,097,529 17,567,465 5,534,238
------------ ------------ ------------ ------------
DIRECT EXPENSES
Contract drilling ................................ 2,026,249 240,145 6,704,598 2,016,779
Oil and gas production ........................... 227,853 225,562 648,797 572,211
Gas transmission and compression ................. 144,436 72,128 399,198 417,021
------------ ------------ ------------ ------------
Total direct expenses ........................... 2,398,538 537,835 7,752,593 3,006,011
------------ ------------ ------------ ------------
GROSS PROFIT ....................................... 2,486,603 559,694 9,814,872 2,528,227
------------ ------------ ------------ ------------
OTHER INCOME (EXPENSES)
Selling, general and administrative .............. (1,437,407) (691,872) (5,635,136) (1,698,987)
Compensation from options and warrants ........... -- -- (589,200) --
Depreciation, depletion and amortization ......... (225,560) (139,380) (598,720) (418,140)
Interest expense ................................. (153,677) (60,651) (358,310) (182,418)
Interest income .................................. 48,001 10,144 105,536 34,442
Other, net ....................................... 6,850 2,673 (1,302) 2,673
------------ ------------ ------------ ------------
Total other income (expenses) ................... (1,761,793) (879,086) (7,077,132) (2,262,430)
------------ ------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES .................. 724,810 (319,392) 2,737,740 265,797
INCOME TAX EXPENSE
Current .......................................... 274,765 (121,369) 1,039,679 101,003
Benefit realized on loss carried forward ......... -- 121,369 (764,914) (101,003)
------------ ------------ ------------ ------------
NET INCOME (LOSS) .................................. $ 450,045 $ (319,392) $ 2,462,975 $ 265,797
============ ============ ============ ============
DEFICIT, beginning of period ....................... $(18,106,859) $(20,169,550) $(20,119,789) $(20,754,739)
============ ============ ============ ============
DEFICIT, end of period ............................. $(17,656,814) $(20,488,942) $(17,656,814) $(20,488,942)
============ ============ ============ ============
NET INCOME (LOSS) PER SHARE
Basic ............................................ $ 0.05 $ (0.06) $ 0.33 $ 0.05
============ ============ ============ ============
Diluted .......................................... $ 0.04 $ (0.06) $ 0.24 $ 0.04
============ ============ ============ ============
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING:
Basic ............................................ 9,557,613 5,460,724 7,364,447 5,294,499
============ ============ ============ ============
Diluted .......................................... 13,130,760 5,460,724 10,867,193 5,925,338
============ ============ ============ ============
See Notes to Condensed Consolidated Financial Statements.
4
DAUGHERTY RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(U.S. FUNDS) (UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ --------------------------
2003 2002 2003 2002
----------- --------- ----------- -----------
OPERATING ACTIVITIES
Net income (loss) ................................................ $ 450,045 $(319,392) $ 2,462,975 $ 265,797
Adjustments to reconcile net income (loss)
to net cash used in operating activities:
Incentive bonus paid in common shares ........................... -- -- 351,420 109,620
Compensation from options and warrants .......................... -- -- 589,200 --
Depreciation, depletion and amortization ........................ 225,560 139,380 598,720 418,140
Write-off of deferred financing costs ........................... 29,786 -- 29,786 --
Notes issued in kind for interest on notes ...................... 23,973 -- 23,973 --
Gain on sale of assets .......................................... (6,050) -- (2,255) --
Changes in assets and liabilities
Accounts receivable ............................................ (135,316) 147,983 (214,216) 232,054
Prepaid expenses and other assets .............................. (297,702) (268,770) (207,467) (355,610)
Accounts payable ............................................... (72,352) 359,511 133,461 387,617
Accrued liabilities ............................................ (672,029) (281,159) (44,993) 72,866
Income taxes payable ........................................... 274,765 -- 274,765 --
Customers' drilling deposits ................................... 3,011,600 368,750 (1,939,900) (2,334,250)
----------- --------- ----------- -----------
Net cash provided by (used in) operating activities ................ 2,832,280 146,303 2,055,469 (1,203,766)
----------- --------- ----------- -----------
INVESTING ACTIVITIES
Proceeds from sale of assets ..................................... 17,500 -- 20,745 --
Purchase of property and equipment ............................... (236,678) (157,057) (712,106) (226,909)
Purchase of investment ........................................... -- -- -- (9,827)
Additions to oil and gas properties, net ......................... (1,012,445) (162,196) (3,625,866) (562,100)
----------- --------- ----------- -----------
Net cash used in investing activities .............................. (1,231,623) (319,253) (4,317,227) (798,836)
----------- --------- ----------- -----------
FINANCING ACTIVITIES
Net payments on short term borrowings ............................ -- -- -- (11,905)
Decrease (increase) in loans to related parties .................. 29,326 13,197 81,905 (186,601)
Proceeds from issuance of common shares .......................... 509,815 102,500 3,585,699 102,500
Proceeds from issuance of long term debt ......................... 5,000,000 241,250 8,236,125 241,250
Payments of deferred financing costs ............................. (410,000) -- (410,000) --
Payments of long term debt ....................................... (17,467) (46,762) (2,100,871) (84,645)
----------- --------- ----------- -----------
Net cash provided by financing activities .......................... 5,111,674 310,185 9,392,858 60,599
----------- --------- ----------- -----------
CHANGE IN CASH AND CASH EQUIVALENTS ................................ 6,712,331 137,235 7,131,100 (1,942,003)
CASH AND CASH EQUIVALENTS:
Beginning of period .............................................. 7,450,076 165,182 7,031,307 2,244,420
----------- --------- ----------- -----------
End of period .................................................... $14,162,407 $ 302,417 $14,162,407 $ 302,417
=========== ========= =========== ===========
SUPPLEMENTAL DISCLOSURE
Interest paid ...................................................... $ 190,308 $ 79,665 $ 363,250 $ 196,960
Income taxes paid .................................................. -- -- -- --
SUPPLEMENTAL SCHEDULE OF NONCASH
INVESTING AND FINANCING ACTIVITIES
Preferred shares issued for acquisition and debt settlement ........ -- -- -- 418,785
Common shares issued for settlement of accounts payable ............ -- -- 164,126 155,031
Common shares issued upon conversion of notes ...................... 1,235,000 -- 2,495,000 --
See Notes to Condensed Consolidated Financial Statements.
5
DAUGHERTY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(U.S. FUNDS)
(UNAUDITED)
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) General. The accompanying unaudited condensed consolidated financial
statements of Daugherty Resources, Inc., a British Columbia corporation (the
"Company"), have been prepared in accordance with generally accepted accounting
principles in Canada. Except as described in Note 14, those accounting
principles conform in all material respects with accounting principles generally
accepted in the United States of America. In the opinion of management, the
accompanying unaudited condensed consolidated financial statements reflect all
adjustments (consisting of normal recurring adjustments) necessary to fairly
present the Company's condensed consolidated financial position at September 30,
2003 and its condensed consolidated results of operations and cash flows for the
interim periods presented. The condensed consolidated financial statements
should be read in conjunction with the Company's consolidated financial
statements and related notes included in its Annual Report on Form 10-KSB for
the year ended December 31, 2002.
(b) Basis of Consolidation. The Company's condensed consolidated financial
statements include the accounts of Daugherty Petroleum, Inc. ("DPI"), a Kentucky
corporation wholly owned by the Company, and the accounts of Sentra Corporation
("Sentra"), a Kentucky corporation wholly owned by DPI. DPI conducts all of the
Company's oil and gas drilling and production operations, and Sentra owns and
operates natural gas distribution facilities in Kentucky. The condensed
consolidated financial statements also reflect DPI's interests in a total of 21
drilling programs that it has sponsored and managed since 1996 to conduct
development drilling operations on its prospects (the "Drilling Programs"). DPI
generally maintains a combined 25.75% interest as both general partner and an
investor in each Drilling Program. The Company accounts for those interests
using the proportionate consolidation method, combining DPI's share of assets,
liabilities, income and expenses of the Drilling Programs with those of its
separate operations. All material inter-company accounts and transactions for
the interim periods presented in the condensed consolidated financial statements
have been eliminated on consolidation.
(c) Estimates. The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities as of the balance sheet date and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates. Material estimates are
particularly significant as they relate to oil and gas reserve data, which
require estimates of future production volumes in determining the carrying value
of the Company's proved reserves.
(d) Reclassification. Certain amounts reported in the condensed
consolidated financial statements for interim periods in 2002 have been
reclassified to conform with the presentation in the current periods.
NOTE 2. OIL AND GAS PROPERTIES
Capitalized costs and accumulated depreciation, depletion and amortization
("DD&A") relating to the Company's oil and gas producing activities, all of
which are conducted within the continental United States, are summarized below.
DECEMBER 31,
SEPTEMBER 30, 2003 2002
------------------------------------------- ------------
ACCUMULATED
COST DD&A NET NET
----------- ----------- ----------- ----------
Proved oil and gas properties ..................... $13,967,720 $(2,315,179) $11,652,541 $8,576,375
Unproved oil and gas properties ................... 494,737 -- 494,737 419,737
Wells and related equipment ....................... 847,750 (144,613) 703,137 683,437
----------- ----------- ----------- ----------
Total oil and gas properties ...................... $15,310,207 $(2,459,792) $12,850,415 $9,679,549
=========== =========== =========== ==========
6
NOTE 3. PROPERTY AND EQUIPMENT
Capitalized costs and accumulated depreciation relating to the Company's
property and equipment are summarized below.
DECEMBER 31,
SEPTEMBER 30, 2003 2002
------------------------------------------- ------------
ACCUMULATED
COST DEPRECIATION NET NET
---------- ------------ ---------- --------
Land .......................................... $ 12,908 $ -- $ 12,908 $ 12,908
Building improvements ......................... 20,609 (2,920) 17,689 4,471
Machinery and equipment ....................... 1,139,660 (208,883) 930,777 625,086
Office furniture and fixtures ................. 131,248 (93,346) 37,902 18,176
Aircraft ...................................... 275,000 (25,280) 249,720 116,146
Vehicles ...................................... 376,255 (134,380) 241,875 142,068
---------- --------- ---------- --------
Total property and equipment .................. $1,955,680 $(464,809) $1,490,871 $918,855
========== ========= ========== ========
NOTE 4. LOANS TO RELATED PARTIES
Loans to related parties represent loans receivable from certain
shareholders and officers of the Company, payable monthly from production
revenues for periods ranging from five to ten years, with a balloon payment at
maturity. The loans receivable from shareholders aggregated $522,486 at
September 30, 2003 and $604,379 at December 31, 2002. These loans bear interest
at 6% per annum and are collateralized by ownership interests in Drilling
Programs. The loans receivable from officers aggregated $171,429 at September
30, 2003 and $171,441 at December 31, 2002. These loans are non-interest bearing
and unsecured.
NOTE 5. INVESTMENT
The Company has an investment of $119,081 in three series of bonds issued
by the City of Galax, Virginia Industrial Development Authority. The bonds bear
interest at rates ranging from 7% to 8.25% per annum, with maturity dates of
July 1, 2004 and July 1, 2010. Although the bonds have a face value of $154,040,
they are carried at cost on the Company's consolidated financial statements in
accordance with accounting principles generally accepted in Canada. Under
accounting principles generally accepted in the United States, the investments
are reportable at fair value, with unrealized gains and losses excluded from
earnings and reported as a separate component of shareholders' equity. As of
September 30, 2003 and December 31, 2002, the estimated market value of the
bonds was $36,970.
NOTE 6. DEFERRED FINANCING COSTS
The Company incurred financing costs of $137,607 during 1999 in connection
with the issuance of its 10% Convertible Secured Notes due July 31, 2004. These
costs were capitalized and have been amortized over the life of the notes.
Accumulated amortization aggregated $107,821 at June 30, 2003 and $94,061 at
December 31, 2002. During the three months ended September 30, 2003, the
remaining notes were converted into common shares in accordance with the terms
of the notes. See Note 10 - Capital Stock. As a result, the Company recognized a
non-cash charge of $29,786 at September 30, 2003 to reflect the retirement of
the notes.
The Company incurred financing costs of $601,886 during the third quarter
of 2003 in connection with the issuance of $5,000,000 principal amount of its 7%
Convertible Notes due September 5, 2008. These costs were capitalized and will
be amortized over the life of the notes. Accumulated amortization aggregated
$8,360 at September 30, 2003.
NOTE 7. GOODWILL
In connection with the acquisition of DPI in 1993, the Company recorded
goodwill of $1,789,564, which was amortized over ten years on a straight-line
basis. Unamortized goodwill at December 31, 2001 was $313,177.
7
At the beginning of 2002, the Company adopted Canadian Institute of Chartered
Accountants ("CICA") Handbook Section 3062, "Goodwill and Other Intangible
Assets," which is the Canadian equivalent of Statement of Financial Accounting
Standards ("SFAS") No. 142 for accounting standards generally accepted in the
United States of America. Under the adopted standard, goodwill is no longer
amortized but is instead tested for impairment upon adoption and at least
annually thereafter. The annual test may be performed any time during the year,
but must be performed at the same time in each subsequent year. Based on
analyses of its recorded goodwill performed in October 2002 and 2003, the
Company determined that no impairment charges were required. Accordingly,
accumulated amortization of goodwill remained at $1,476,387 as of September 30,
2003 and December 31, 2002.
NOTE 8. BANK LOAN
At September 30, 2003 and December 31, 2002, the Company had an
outstanding bank loan in the principal amount of $134,162, fully secured by a
certificate of deposit. The loan bears interest at the rate of 4.71% per annum
and is repayable on January 15, 2004.
NOTE 9. LONG TERM DEBT
(a) Credit Facility. The Company maintains a credit facility with KeyBank
NA of up to $10 million, subject to semi-annual borrowing base determinations by
the bank. At September 30, 2003, the borrowing base was $2,675,000. Borrowings
under the facility bear interest payable monthly at 1.25% above the bank's prime
rate, amounting to 5.25% at September 30, 2003. The facility is secured by liens
on all corporate assets, including a first mortgage on oil and gas interests and
pipelines, as well as an assignment of major production and transportation
contracts. Borrowings under the facility totaled $252,046 at September 30, 2003
and $2,247,984 at December 31, 2002.
(b) Convertible Notes. The Company has issued a series of convertible
notes in private placements to finance a substantial part of its drilling
activities. The notes are convertible by the holders into the Company's common
stock at fixed rates (subject to anti-dilution adjustments) and are generally
redeemable by the Company at 100% of their principal amount plus accrued
interest through the date of redemption. The terms of the notes are summarized
below.
PRINCIPAL AMOUNT OUTSTANDING AT SHARES
------------------------------- ISSUABLE
SEPTEMBER 30, DECEMBER 31, CONVERSION UPON
TITLE OF NOTES 2003 2002 PRICE CONVERSION
- -------------- ------------- ------------ ---------- ---------
10% Convertible Secured
Notes due July 31, 2004(1) .................... $ -- $ 850,000 $2.71 --
10% Convertible Notes
due May 1, 2007 ............................... 740,500 420,000 1.50 493,666
8% Convertible Notes
due April 10, 2008 ............................ 770,625 -- 1.90 405,592
8% Convertible Notes
due May 1, 2008 ............................... 500,000 -- 2.25 222,222
7% Convertible Notes
due September 5, 2008 ......................... 5,023,973 -- 4.50 1,116,438
---------- ---------- ---------
Total ......................................... $7,035,098 $1,270,000 2,237,918
========== ========== =========
- -------------------------
(1) Secured by liens on mining properties.
The Company's 7% Convertible Notes due September 5, 2008 (the
"Institutional Notes") were issued in September 2003, along with warrants to
purchase up to 222,222 common share (the "Institutional Warrants"), to
institutional investors with various provisions not provided under prior note
financings. Interest on the Institutional Notes is payable quarterly in cash or
additional Institutional Notes ("PIK Notes") and must be paid in PIK Notes
through September 30, 2004. PIK Notes aggregating $23,973 were issued as of
September 30, 2003. The Company has the right to repay any unconverted
Institutional Notes at maturity either in cash or in common shares valued for
8
that purpose at 90% of their prevailing market price. The Institutional Notes
are repayable upon any event of default in cash at the greater of 115% of their
principal amount or 100% of the prevailing market price of their underlying
conversion shares. Events of default include any delisting of the Company's
common stock, failure to pay interest, honor conversion requests or satisfy
registration requirements, any default for over $250,000 on other obligations
and any sale, merger or other change of control transaction not approved by
holders of the Institutional Notes.
The Institutional Notes are convertible into common shares at the option
their holders at an initial conversion price of $4.50. The conversion price is
subject to anti-dilution adjustments for any recapitalization transaction and
for any issuance of common stock or rights to acquire common stock for
consideration less than the prevailing conversion price. For purposes of these
adjustments, dilutive issuances do not include securities issued under existing
instruments, under board-approved incentive plans or in a public offering,
business acquisition or strategic transaction. In addition, no anti-dilution
adjustments will be made to the extent they would increase the total shares
issuable under the Institutional Notes and Institutional Warrants above
1,947,990 common shares. The same limitation applies to the payment of interest
in kind and to repayment of the Institutional Notes in common shares.
(c) Acquisition Debt. The Company issued a note in the principal amount of
$854,818 to finance its 1986 acquisition of mineral property on Unga Island,
Alaska. The debt is repayable without interest in monthly installments of $2,000
and is secured by liens on the acquired property and related buildings and
equipment. Although the purchase agreement for the acquisition provides for
royalties at 4% of net smelter returns or other production revenues, the
property has remained inactive. The acquisition debt is recorded at its
remaining face value of $422,818 at September 30, 2003.
(d) Miscellaneous Debt. The following table summarizes the Company's other
outstanding debt obligations at September 30, 2003 and December 31, 2002.
PRINCIPAL AMOUNT OUTSTANDING AT
-------------------------------
SEPTEMBER 30, DECEMBER 31,
TERMS OF DEBT 2003 2002
- ------------- ------------- ------------
Notes issued to finance equipment and vehicles,
payable monthly in various amounts through 2005,
with interest ranging from 6.0% to 9.5% per annum,
collateralized by the acquired equipment and vehicles ........... $ 30,843 $ 61,426
Loan payable to unaffiliated company, bearing interest
at 10% per annum payable quarterly, collateralized
by assets of subsidiary guarantor ............................... 64,779 64,779
Note payable to unaffiliated individual, payable in
60 installments of $1,370, together with interest at 8%
per annum, through February 2005 ................................ 24,067 35,704
Loans payable to various banks, payable monthly in
various amounts, together with interest at rates ranging
from 4.25% to 9.75% per annum, through May 2006,
collateralized by receivables and various vehicles .............. 54,115 76,178
Loan payable to unaffiliated company, bearing interest
at 10% per annum ................................................ -- 24,650
-------- --------
$173,804 $262,737
======== ========
(e) Total Long Term Debt. The following table sets forth the Company's
total long term debt and current portion at September 30, 2003 and December 31,
2002.
PRINCIPAL AMOUNT OUTSTANDING AT
-------------------------------
SEPTEMBER 30, DECEMBER 31,
2003 2002
------------- ------------
Total long term debt (including current portion) .................. $7,883,766 $4,219,539
Less current portion .............................................. 409,669 192,341
---------- ----------
Total long term debt .............................................. $7,474,097 $4,027,198
========== ==========
9
NOTE 10. CAPITAL STOCK
(a) Preferred and Common Shares. The following table reflects transactions
involving the Company's capital stock during the reported periods.
NUMBER OF
PREFERRED SHARES ISSUED SHARES AMOUNT
- ----------------------- --------- -----------
Balance, December 31, 2001 ................................ 563,249 $ 1,802,541
Converted into common shares ............................ (4,773) (18,048)
--------- -----------
Balance, December 31, 2002 ................................ 558,476 1,784,493
Converted into common shares ............................ (558,476) (1,784,493)
--------- -----------
Balance, September 30, 2003 ............................... -- $ --
========= ===========
COMMON SHARES ISSUED
- --------------------
Balance, December 31, 2001 ................................ 4,959,112 $24,184,198
Issued for cash ......................................... 125,000 102,500
Issued to employees as incentive bonus .................. 204,000 130,020
Issued upon conversion of preferred shares .............. 4,773 18,048
Issued for settlement of accounts payable ............... 212,785 155,031
--------- -----------
Balance, December 31, 2002 ................................ 5,505,670 24,589,797
Issued for cash ......................................... 950,000 2,460,450
Issued to employees as incentive bonus .................. 353,500 351,420
Issued upon conversion of preferred shares .............. 625,448
1,784,493
Issued for settlement of accounts payable ............... 146,888 164,126
Issued upon conversion of convertible notes ............. 1,447,173
2,495,000
Issued upon exercise of stock options and warrants ...... 903,423 1,683,249
--------- -----------
Balance, September 30, 2003 ............................... 9,932,102 $33,528,535
========= ===========
PAID IN CAPITAL -- WARRANTS ............................... -- $ 223,086
- -------------------------- ========= ===========
COMMON SHARES TO BE ISSUED
- --------------------------
To be issued in connection with 1999 purchase of oil
and gas properties ...................................... 24,887 $ 55,226
========= ===========
(b) Stock Options and Warrants. The Company maintains two stock option
plans for the benefit of its directors, officers, employees and, in the case of
the second plan, its consultants and advisors. The first plan, adopted in 1997,
provides for the grant of options to purchase up to 600,000 common shares at
prevailing market prices, vesting over a period of up to five years and expiring
no later than six years from the date of grant. The second plan, adopted in
2001, provides for the grant of options to purchase up to 3,000,000 common
shares at prevailing market prices, expiring no later than ten years from the
date of grant.
In accounting for stock options, the Company follows CICA Handbook Section
3870, "Stock-Based Compensation and Other Stock-Based Payments" and related
interpretations. The statement provides for a fair value based method of
accounting for stock compensation plans, but also permits compensation cost to
be measured by the intrinsic value based method of accounting prescribed by APB
Opinion No. 25, "Accounting for Stock Issued to Employees." Continuing reliance
on APB Opinion No. 25 requires pro forma disclosure of net income and earnings
per share as if the fair value accounting method had been applied.
Because the exercise price for each option issued under the Company's
stock option plans is set at the market price of its common shares at the time
of grant, the Company has not recorded any compensation expense from option
grants in the accompanying condensed consolidated financial statements. If the
fair value based method of accounting had been used, the Company's net income
for the nine months ended September 30, 2003 would have decreased to $2,309,375
or $0.31 per share, assuming a risk free interest rate of 4.5%, theoretical
volatility of .30 and no dividend yield. Since no options were granted under the
Company's stock option plans during the three
10
months ended September 30, 2003 or either of the interim reported periods in
2002, net income (loss) and earnings (loss) per share for those periods would
not have been affected by fair value based method of accounting.
During the second quarter of 2003, certain officers of the Company
exercised options covering a total of 300,000 common shares that were granted in
2000 with a stock-for-stock or "cashless" exercise feature at an exercise price
of $1.25 per share. Since the disclosure only alternative of CICA Handbook
Section 3870 and ABP Opinion No. 25 is not available for the exercise of stock
options with this feature, the Company recorded a compensation charge of
$558,000 for the nine months ended September 30, 2003, reflecting the difference
between the aggregate exercise price of the options and the market price of the
underlying shares on the date that the options were exercised. Additional
non-cash compensation of $31,200 was also recognized in the nine months ended
September 30, 2003 from the issuance of warrants for corporate consulting
services.
The exercise prices of options outstanding and exercisable at September
30, 2003 range from $1.00 to $5.00 per share, and their weighted average
remaining contractual life is 2.01 years. The following table reflects
transactions involving the Company's stock options during the reported periods.
WEIGHTED
AVERAGE
ISSUED EXERCISABLE EXERCISE PRICE
--------- ----------- --------------
STOCK OPTIONS
- -------------
Balance, December 31, 2001 .............. 2,479,210 2,479,210 $2.02
=========
Expired ................................ (894,000) 3.39
---------
Balance, December 31, 2002 .............. 1,585,210 1,585,210 1.30
=========
Granted ................................ 400,000 1.02
Exercised .............................. (773,646) 1.18
Expired ................................ (25,000) 5.00
---------
Balance. September 30, 2003 .............. 1,186,564 1,186,564 1.16
========= =========
The Company has issued common stock purchase warrants in various financing
transactions, including three-year warrants to purchase up to 222,222 common
shares at an initial exercise price of $5.11 issued in September 2003 as part of
the Institutional Note financing, with similar anti-dilution provisions. See
Note 9 - Long Term Debt - Convertible Notes. Other warrants outstanding at
September 30, 2003 have exercise prices ranging from $1.12 to $4.80 per share.
The weighted average remaining contractual life of all warrants outstanding at
September 30, 2003 is 1.65 years. The following table reflects transactions
involving the Company's common stock purchase warrants during the reported
periods.
WEIGHTED
AVERAGE
ISSUED EXERCISABLE EXERCISE PRICE
--------- ----------- --------------
COMMON STOCK PURCHASE WARRANTS
- ------------------------------
Balance, December 31, 2001 .............. 3,018,721 3,018,721 $2.61
=========
Expired ................................ (500,000) 0.63
---------
Balance, December 31, 2002 ............... 2,518,721 2,518,721 2.76
=========
Issued ................................. 649,622 4.05
Exercised .............................. (250,356) 2.35
---------
Balance. September 30, 2003 .............. 2,917,987 2,917,987 3.08
========= =========
NOTE 11. INCOME (LOSS) PER SHARE
(a) Basic. Income (loss) per share is calculated using the weighted
average number of shares outstanding during the period. The following table sets
forth the weighted average of common shares outstanding for the reported
periods.
11
WEIGHTED AVERAGE
REPORTING PERIOD COMMON SHARES OUTSTANDING
---------------- -------------------------
Three months ended September 30, 2003 9,557,613
Three months ended September 30, 2002 5,460,724
Nine months ended September 30, 2003 7,364,447
Nine months ended September 30, 2002 5,294,499
(b) Fully Diluted. The Company follows CICA Handbook Section 3500,
"Earnings per Share," effective January 31, 2001. The statement requires the
presentation of both basic and diluted earnings (loss) per share ("EPS") in the
statement of operations, using the "treasury stock" method to compute the
dilutive effect of stock options and warrants and the "if converted" method for
the dilutive effect of convertible instruments. For the three months and nine
months ended September 30, 2003, the assumed exercise of outstanding stock
options and warrants and conversion of outstanding convertible notes and
preferred stock would have a dilutive effect on EPS because their exercise or
conversion prices were below the average market price of the common stock during
the periods. For the nine months ended September 30, 2002, only the assumed
conversion of preferred stock would have a dilutive effect on EPS. Because the
Company recognized net losses for the three months ended September 30, 2002, the
assumed exercise or conversion of all these instruments would have been
anti-dilutive. The following table sets forth the computation of basic and
dilutive EPS for the three months and nine months ended September 30, 2003 and
2002.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------- -------------------------
2003 2002 2003 2002
----------- ---------- ----------- ----------
NUMERATOR:
- ----------
Net income (loss) as reported for basic EPS ........ $ 450,045 $ (319,392) $ 2,462,975 $ 265,797
Adjustments to income for diluted EPS .............. 48,347 -- 124,600 --
----------- ---------- ----------- ----------
Net income (loss) for diluted EPS ................ $ 498,392 $ (319,392) $ 2,587,575 $ 265,797
=========== ========== =========== ==========
DENOMINATOR:
- ------------
Weighted average shares for basic EPS .............. 9,557,613 5,460,724 7,364,447 5,294,499
Effect of dilutive securities:
Stock options .................................... 957,620 -- 1,018,815 --
Warrants ......................................... 980,486 -- 568,204 --
Convertible notes ................................ 1,588,196 -- 1,705,969 --
Convertible preferred shares ..................... 46,845 -- 209,758 630,839
----------- ---------- ----------- ----------
Adjusted weighted average shares and
Assumed conversions for dilutive EPS ............. 13,130,760 5,460,724 10,867,193 5,925,338
=========== ========== =========== ==========
Basic EPS .......................................... $ 0.05 $ (0.06) $ 0.33 $ 0.05
=========== ========== =========== ==========
Diluted EPS ........................................ $ 0.04 $ (0.06) $ 0.24 $ 0.04
=========== ========== =========== ==========
NOTE 12. RELATED PARTY TRANSACTIONS
(a) General. Because the Company operates through its subsidiaries and
affiliated Drilling Programs, its holding company structure causes various
agreements and transactions in the normal course of business to be treated as
related party transactions. It is the Company's policy to structure any
transactions with related parties only on terms that are no less favorable to
the Company than could be obtained on an arm's length basis from unrelated
parties. Significant related party transactions not disclosed elsewhere in these
notes are summarized below.
(b) Lease of Gas Compressors. A limited liability company owned by a
director and two officers of the Company has historically leased natural gas
compressors to DPI. For the nine months ended September 30, 2003 and 2002, lease
payments to the related party were $6,000 and $12,000, respectively.
12
(c) Drilling Programs. DPI invests in sponsored Drilling Programs on
substantially the same terms as unaffiliated investors, contributing capital in
proportion to its partnership interest. DPI also receives a 1% partnership
interest as a fee for managing each Drilling Program. DPI generally maintains a
25.75% combined interest in each Drilling Program organized as a limited
partnership and up to 50% in each Drilling Program organized as a joint venture.
In consideration for the assignment of drilling rights to the Drilling Programs,
their partnership agreements provide for specified increases in DPI's interest
after total distributions surpass contributed capital. The partnership
agreements also provide for each Drilling Program to enter into turkey drilling
contracts with DPI for all wells to be drilled by that Drilling Program. The
portion of profit on drilling contracts attributable to DPI's ownership interest
in the Drilling Programs has been eliminated on consolidation for the interim
periods presented in the Company's condensed consolidated financial statements.
The following table sets forth the total revenues recognized from the
performance of turnkey drilling contracts with sponsored Drilling Programs for
the reported periods.
REPORTING PERIOD DRILLING CONTRACT REVENUE
---------------- -------------------------
Three months ended September 30, 2003.......... $3,866,000
Three months ended September 30, 2002.......... 556,733
Nine months ended September 30, 2003........... 14,924,000
Nine months ended September 30, 2002........... 4,040,733
NOTE 13. SEGMENT INFORMATION
The Company has two reportable segments based on management responsibility
and key business operations. The following table presents summarized financial
information for the Company's business segments.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------- ---------------------------
2003 2002 2003 2002
---------- ---------- ----------- ----------
REVENUE:
- --------
Oil and gas development ................ $4,885,141 $1,097,529 $17,567,465 $5,534,238
Corporate .............................. -- -- -- --
---------- ---------- ----------- ----------
Total ................................ 4,885,141 1,097,529 17,567,465 5,534,238
---------- ---------- ----------- ----------
DD&A:
- -----
Oil and gas development ................ 199,800 125,000 536,067 375,000
Corporate .............................. 25,760 14,380 62,653 43,140
---------- ---------- ----------- ----------
Total ................................ 225,560 139,380 598,720 418,140
---------- ---------- ----------- ----------
INTEREST EXPENSE:
- -----------------
Oil and gas development ................ 51,767 39,401 162,758 118,668
Corporate .............................. 101,910 21,250 195,552 63,750
---------- ---------- ----------- ----------
Total ................................ 153,677 60,651 358,310 182,418
---------- ---------- ----------- ----------
NET INCOME (LOSS):
- ------------------
Oil and gas development ................ 782,349 (109,806) 3,792,542 1,003,007
Corporate .............................. (332,304) (209,586) (1,329,567) (737,210)
---------- ---------- ----------- ----------
Total ................................ 450,045 (319,392) 2,462,975 265,797
---------- ---------- ----------- ----------
CAPITAL EXPENDITURES:
- ---------------------
Oil and gas development ................ 1,170,230 266,901 4,100,603 713,373
Corporate .............................. 78,893 52,352 237,369 75,636
---------- ---------- ----------- ----------
Total ................................ $1,249,123 $ 319,253 $ 4,337,972 $ 789,009
========== ========== =========== ==========
SEPTEMBER 30,DECEMBER 31,
---------------------------
2003 2002
----------- -----------
IDENTIFIABLE ASSETS:
- --------------------
Oil and gas development ............................................ $20,824,682 $18,194,537
Corporate .......................................................... 10,650,091 1,516,496
----------- -----------
Total ............................................................ $31,474,773 $19,711,033
=========== ===========
13
NOTE 14. UNITED STATES ACCOUNTING PRINCIPLES AND RECENT PRONOUNCEMENTS
The Company follows accounting principles generally accepted in Canada,
which are different in some respects than accounting principles generally
accepted in the United States of America, including the recent accounting
pronouncements summarized below. Differences that could affect the Company's
consolidated financial statements are noted in the following summary.
(a) Comprehensive Income (Loss). SFAS No. 130, "Reporting Comprehensive
Income," establishes standards for reporting and presenting comprehensive income
and its components. It requires restatement of all previously reported
information for comparative purposes. For the three months and nine months ended
September 30, 2003 and 2002, the Company's comprehensive income (loss) was the
same as its reported net income (loss), except as otherwise described in Note 5.
(b) SFAS No. 143. SFAS No. 143, "Accounting for Asset Retirement
Obligations," was issued in August 2001 to address financial accounting and
reporting for obligations associated with the retirement of tangible long-lived
assets and related asset retirement costs. The Company's adoption of this
statement on January 1, 2003 did not have a material impact on its consolidated
financial statements for the reported periods.
(c) SFAS No. 144. SFAS No. 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," was issued in August 2001 to address financial accounting
or reporting for the impairment or disposal of long-lived assets. It broadens
the presentation of discontinued operations for long-lived assets. The Company's
adoption of this statement on January 1, 2002 did not have a material impact on
its consolidated financial statements for the reported periods.
(d) SFAS No. 145. SFAS No. 145, "Rescission of FASB Statements Nos. 4, 44
and 64, Amendment of FASB Statement No. 13, and Technical Corrections," was
issued in April 2002 and is effective for financial statements issued on or
after May 15, 2003. In addition to amending or rescinding existing
pronouncements, the statement precludes companies from recording gains and
losses from the extinguishment of debt as an extraordinary item. In August 2003,
the Company reported the write-off of unamortized deferred financing costs
aggregating $29,786 as a component of interest expense, whereas the write-off
would have been reported as an extraordinary loss under SFAS No. 4.
(e) SFAS No. 146. SFAS No. 146, "Accounting for Costs Associated with Exit
or Disposal Activities," was issued in July 2002. It requires a liability for
costs associated with an exit or disposal activity to be recognized and measured
initially at its fair value in the period in which the liability is incurred.
This statement is effective for exit or disposal activities that are initiated
after December 31, 2002 and has not had a material impact on the Company's
consolidated financial statements for the reported periods.
(f) Financial Accounting Standards Board Interpretation ("FIN") No. 45.
FIN 45 was issued in November 2002 to expand previously issued accounting
guidance and disclosure requirements for certain guarantees. It requires the
recognition of an initial liability for the fair value of an obligation assumed
by a guarantor to be applied on a prospective basis to guarantees issued or
modified after December 31, 2002. The adoption of FIN 45 has not had a material
impact on the Company's consolidated financial statements for the reported
periods.
(g) SFAS No. 148. SFAS No. 148, "Accounting for Stock-Based Compensation -
Transition and Disclosure," was issued in December 2002 to amend the transition
and disclosure provisions of SFAS No. 123. This statement has not had a material
impact on the Company's consolidated financial statements for the reported
periods.
(h) SFAS No. 149. SFAS No. 149, "Amendment of Statement 133 on Derivative
Instruments and Hedging Activities," was issued in April 2003 to amend and
clarify accounting for hedging activities and derivative instruments, including
certain derivative instruments embedded in other contracts. The statement is
effective for contracts entered into or modified after September 30, 2003 and is
not expected to have a material impact on the Company's consolidated financial
statements.
(i) SFAS No. 150. SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity," was issued in
May 2003. It establishes standards for classifying and measuring certain
financial instruments with characteristics of both debt and equity. It requires
many financial instruments previously classified as equity to be reclassified as
liabilities and is generally effective for financial instruments entered into or
modified after May 31, 2003 and otherwise at the beginning of the first interim
period beginning after June 15, 2003. The statement is not expected to have a
material impact on the Company's consolidated financial statements.
14
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
Daugherty Resources, Inc. (the "Company") is a diversified natural
resources company focused on natural gas development drilling and reserve
growth. Through our wholly owned subsidiary, Daugherty Petroleum, Inc. ("DPI"),
and DPI's interests in sponsored drilling partnerships (the "Drilling
Programs"), we hold and actively develop oil and gas interests in the
Appalachian and Illinois Basins, primarily within the State of Kentucky. DPI
also owns and operates natural gas distribution facilities in Kentucky through
its wholly owned subsidiary, Sentra Corporation ("Sentra"), and owns inactive
gold and silver prospects in Alaska. We commenced oil and gas operations in 1993
with the acquisition of DPI and have sponsored 22 separate Drilling Programs
since 1996. Unless otherwise indicated, references to the Company and to "we" or
"our" in this Report include DPI, its interests in the Drilling Programs and
Sentra.
Daugherty Resources is currently organized under the laws of the province
of British Columbia, Canada. We plan to seek shareholder approval for
reincorporation as a Delaware corporation in a transaction known as a
"domestication" under Delaware law. If approved and implemented as expected, the
domestication is intended to enhance shareholder value over the long term by
facilitating capital formation, increasing the marketability of our common stock
and easing the income tax and accounting complexities associated with foreign
incorporation.
STRATEGY
Our primary financial objective is capital appreciation through growth in
production, reserves and cash flow. During 2002, we increased our total revenues
by 12.2% over 2001 levels and added 10,634 million cubic feet (Mmcf) of natural
gas equivalents (MMcfe) to our estimated net proved reserves. Our strategy is to
continue expanding our natural gas reserves, production and distribution
facilities in our core geographic areas, primarily in the Appalachian Basin. To
implement this strategy, we emphasizes the following objectives:
- Expand drilling operations. We intend to continue developing our natural
gas properties through our interests in Drilling Programs that we sponsor
and manage.
- Acquire additional producing properties. Our acquisition efforts are
focused on natural gas properties that help build predictable, long-lived
oil and gas reserves in geographic areas where we have established
operations and expertise.
- Reduce drilling risks. We concentrate on drilling natural gas development
wells on our core prospects rather than exploratory drilling. This helps
to reduce the risk levels associated with natural gas drilling and
production.
- Reduce drilling and production costs. By managing Drilling Programs for
the Company and other investors, we generally control drilling and
production operations. This structure enables us to share administrative,
overhead and operating costs with our partners while providing
efficiencies that help reduce drilling and production costs for both.
- Gold and silver properties. Our objective is to monetize our dormant
Alaskan gold and silver properties by seeking a joint venture partner to
either provide funds for developing these prospects or to acquire them
from the Company.
RECENT DEVELOPMENTS
Property Acquisitions. In December 2002, we completed our acquisition of
oil and gas drilling rights covering approximately 100,000 acres on the
southeastern edge of the Big Sandy Gas Field, extending 41 miles through our
primary operating areas in eastern Kentucky (the "Leatherwood Prospect"). The
farmout increased our total acreage position in the Appalachian Basin to
approximately 160,000 acres. The Big Sandy Gas Field was discovered in 1921 and
covers 250,000 acres. It has produced over 2.5 trillion cubic feet of natural
gas from approximately 10,000 wells. We plan to drill development wells on the
Leatherwood Prospect to test five primary
15
natural gas pay zones at depths between 3,500 and 4,500 feet. We committed to
drill 25 wells on the Leatherwood Prospect during 2003, and we plan to focus our
long term drilling initiatives on further developing the acquired acreage. We
anticipate that part of our drilling commitment for 2003 will not be satisfied
until the first quarter of 2004 and expect to obtain our counterparty's consent
to the extension.
In June 2003, we increased our position in the Big Sandy Gas Field with
the acquisition of an oil and gas lease covering 9,400 acres on the north side
of the Pine Mountain Fault System. We began development drilling on the acquired
acreage in the third quarter of 2003 to test up to five natural gas pay zones at
depths between 3,500 and 4,500 feet.
Extension of Gas Gathering System. During the third quarter of 2003, we
completed a 10 mile extension of our natural gas gather system for connecting
new wells in the eastern section of our Kay Jay Field in Knox and Bell Counties,
Kentucky. We also installed a total of 1,200 horsepower of new compression for
the system. The new system connects to a major pipeline maintained by Delta
Natural Gas Company and increases our daily gross transportation capacity by
5,000 thousand cubic feet (Mcf). As of September 30, 2003, we connected 41 of
our new wells to this gathering system, increasing our net daily gas production
to 2,000 Mcf.
Equity Infusion. In June 2003, we completed an institutional private
placement of 900,000 shares of our common stock for $2,565,000, based on a 15%
discount to the stock's market price at the time an agreement in principal for
the transaction was reached. The investors also received three-year warrants to
purchase up to 180,000 common shares at an exercise price of $4.80 per share.
Our investment banking firm for the transaction received a 7% fee and a
five-year warrant to purchase up to 32,400 shares of our common stock at $4.80
per share.
Convertible Notes and Preferred Stock. Since 1999, we have financed a
substantial part of our drilling activities with proceeds from private
placements of six separate series of our convertible notes in the aggregate
principal amount of $9,506,125, including convertible notes totaling $8,236,125
in the first nine months of 2003. The notes are convertible into our common
stock at the option of the holders at specified rates, subject to anti-dilution
adjustments. See "Liquidity and Capital Resources - Capital Resources" below.
During the first nine months of 2003, our convertible note holders elected to
convert $2,495,000 aggregate principal amount of their notes into a total of
1,447,173 shares of our common stock. In addition, all of our outstanding
preferred shares were converted into common shares on a 1.12-for-1 basis during
the first nine months of 2003. As a result, we issued a total of 625,448 common
shares upon conversion of 558,476 outstanding preferred shares.
DRILLING PROGRAMS
Strategy. Because our natural gas reserves are generally long-lived, with
a very gradual decline curve, production from our developed reserves tends to be
predictable and steady from a long term perspective but moderate from a near
term point of view. With our current density of connected natural gas wells, our
cash flows from oil and gas producing activities are not adequate to finance the
level of drilling activities needed for the efficient development of our proved
undeveloped oil and gas reserves, which represented over 75% of our total
estimated proved reserves (developed and undeveloped) on an energy equivalent
basis at December 31, 2002. As a result, our business focuses on development
drilling and is highly capital intensive. Our strategy of sponsoring and
managing Drilling Programs helps address these capital requirements. The
strategy has benefited over the last few years from substantial increases in the
demand and market price for natural gas, attracting investment capital to
industry participants.
Structure. The Drilling Programs are sponsored and managed by DPI to
conduct development drilling operations on our prospects. Drilling rights for
specified wells are assigned by DPI to each Drilling Program, which enters into
turnkey drilling contracts with DPI for drilling and completion of the wells.
Most of the Drilling Programs are structured in two partnership tiers to
optimize tax advantages for private investors and simplify operations. DPI
generally contributes 25% of total program capital and maintains a combined
25.75% interest as both general partner and an investor in these tiered Drilling
Programs. We also manage smaller Drilling Programs structured as joint ventures
with strategic or industry partners, maintaining working interests up to 50%.
The agreements for both the tiered and joint venture Drilling Programs generally
provide for specified increases in our program interests after return of
partners' investment or "payout." This structure provides us with long term
incentives and a mechanism for accelerating the development of our properties by
sharing risks and costs without relinquishing control over drilling and
operating decisions.
16
Recent Financings. Private placements of interests in two separate
Drilling Programs were completed in December 2002 with total contributed capital
of $8,775,000 from outside investors, representing a 60% increase in the size of
Drilling Program financings during 2001. In July 2003, we completed a private
placement of interests in our most recent tiered Drilling Program with
contributed capital of $6,750,000 from outside investors. The 2002 programs
entered into turnkey drilling contracts with DPI for a total of 39 wells, and
our drilling contracts with the initial 2003 program cover an additional 30
wells. During the third quarter of 2003, we also completed a joint venture
Drilling Program with a strategic partner for two wells in which we retained a
25% interest. We expect to complete two more Drilling Program financings in
2003, one for participation in our Leatherwood initiatives and another for
participation in up to 60 additional wells on other prospects.
Proportionate Consolidation. We contributed an aggregate of $2,925,000 to
the year-end 2002 Drilling Programs and $2,254,000 to the initial 2003 Drilling
Program for our 25.75% interest as an investor and managing partner of each
program. We contributed $150,000 to our 2003 joint venture Drilling Program for
our 25% interest. We account for our interests in Drilling Programs using the
proportionate consolidation method, combining our share of assets, liabilities,
income and expenses of the Drilling Programs with those of our separate
operations.
DRILLING RESULTS
Completed Wells. During the nine months ended September 30, 2003, we
drilled 55 gross (13.7985 net) natural gas wells. As of the date of this Report,
all of those wells have been completed as producers or successfully tested in at
least one primary pay zone. Most of these well were drilled by DPI under turnkey
drilling contracts with Drilling Programs. Each turnkey contract establishes the
price to drill and complete a specified well. We are responsible for any
drilling and completion costs exceeding the contract price, and we are entitled
to any surplus if the contract price exceeds our costs. We are responsible for
all engineering and administrative services under these contracts, retaining
control over all drilling decisions and supervisory responsibility for
specialized subcontractors we engage to perform substantially all drilling and
completion work.
Well Characteristics. Our proved reserves, both developed and undeveloped,
are concentrated in the Appalachian Basin in eastern Kentucky, one of the oldest
and most prolific natural gas producing areas in the United States.
Historically, wells in this area generally produce between 200 to 450 Mmcf of
natural gas over a reserve life of up to 25 years. The natural gas in this area
is also known for being environmentally friendly in the sense that wells produce
virtually no water with the gas production. This helps us minimize production
(or lifting) costs. In addition, the average energy (or MMBtu) value of the
natural gas produced in this area is substantially higher than normal pipeline
quality gas, ranging from 1,100 to 1,236 MMBtu per thousand cubic feet (Mcf).
Our gas sales contracts generally provide upward adjustments to index based
pricing for our natural gas with an energy value above 1,000 MMBtu per Mcf,
enhancing our near term cash flows and contributing to the long term returns on
our investments in these properties.
RESULTS OF OPERATIONS
Quarters Ended September 30, 2003 and 2002. Total revenues for the quarter
ended September 30, 2003 were $4,885,141, an increase of 345% from $1,097,529 in
the same quarter last year. Our revenue mix for the third quarter of 2003 was
79% contract drilling, 15% oil and gas production and 6% natural gas
transmission and compression. For the comparable quarter of 2002, our total
revenues were derived 51% from contract drilling, 29% from oil and gas
production and 20% from natural gas transmission and compression activities.
Contract drilling revenues were $3,866,000 for the third quarter of 2003,
up 594% from $556,733 in the comparable quarter of 2002. This reflects both the
size and the timing of Drilling Program financings, from which we derive
substantially all our contract drilling revenues. Upon the closing of Drilling
Program financings, DPI receives most of the net proceeds as customers' drilling
deposits under turnkey drilling contracts with the programs. We recognize
revenues from drilling operations on the completed contract method as the wells
are drilled, rather than when funds are received. Drilling operations for the
initial 2003 Drilling Program and our 2003 joint venture Drilling Program were
ongoing during the third quarter of 2003, when we drilled 14 gross (3.5904 net)
natural gas wells, all of which have been completed as producers or successfully
tested in at least one primary pay zone as of the date of this Report.
Production revenues were $749,340 for the third quarter of 2003, an
increase of 134% from $320,453 in the comparable quarter of 2002. This primarily
reflects an increase of 49% in our average sales price of natural gas
17
(before certain transportation charges) to $5.35 per Mcf in the third quarter of
2003 from $3.60 per Mcf in the corresponding quarter of 2002. It also reflects a
50% increase in our production volumes to 132,773 Mcfe in the third quarter of
2003 from 88,727 Mcfe in the same quarter last year. Our growth in production
volumes resulted from new wells brought on line since the end of September 2002.
The improvement in average sales price for our natural gas is consistent with a
market-wide rebound in natural gas prices that began in the third quarter of
2002. Principal purchasers of our natural gas production are gas marketers and
transmission companies with facilities near our producing properties. During the
current reported quarter, approximately 40% our natural gas production was sold
under fixed-price contracts and the balance primarily at prices determined
monthly under formulas based on prevailing market indices.
Gas transmission and compression revenues were $269,801 during the third
quarter of 2003, up 22% from $220,343 in the comparable quarter of 2002. This
primarily reflects increased reliance on our own gathering systems for many of
our new wells, generating transmission and compression revenues from the
Drilling Programs holding the working interests in those wells. Our gas
transmission and compression revenues include contributions from Sentra, our
natural gas utility subsidiary, aggregating $33,874 for the third quarter of
2003 and $18,342 for the same quarter last year, an increase of 85%. During the
current reported quarter, Sentra had 184 customers, of which 67 were commercial
and agri-business accounts. Demand for Sentra's services has benefited from
continued growth and acceptance of natural gas by the poultry industry, which is
a major segment of the economy in Sentra's service areas.
Total direct expenses increased by 346% to $2,398,538 for the third
quarter of 2003 compared to $537,835 for the same quarter in 2002. Our direct
expense mix for the current reported quarter was 85% contract drilling, 9% oil
and gas production and 6% natural gas transmission and compression. For the
comparable quarter of 2002, our total direct expenses were incurred 45% in
contract drilling, 42% in oil and gas production and 13% in natural gas
transmission and compression.
Contract drilling expenses were $2,026,249 during the third quarter of
2003, an increase of 744% from $240,145 in the same quarter last year,
reflecting the substantial level of drilling activities on behalf of our initial
2003 Drilling Programs. Our current drilling activities have benefited from
related economies of scale as well as control of field overhead expenses and a
reduction in the total depth for some of the new wells. This decreases variable
drilling costs paid to outside drilling companies and reduces well completion
expenditures.
Production expenses increased slightly to $227,853 in the third quarter of
2003 from $225,562 in the same quarter last year, reflecting economies of scale
and field operating efficiencies. As a percentage of oil and gas production
revenues, production expenses decreased to 30% in the third quarter of 2003 from
70% in the same quarter last year. The improved margin reflects both cost
savings from operating efficiencies and revenue growth driven by substantially
higher natural gas prices in the third quarter of 2003.
Gas transmission and compression expenses in the third quarter of 2003
increased 100% to $144,436 from $72,128 in the same quarter last year. As a
percentage of gas transmission and compression revenues, these expenses
increased to 54% in the current reported quarter from 33% in the third quarter
of 2002.
Selling, general and administrative ("SG&A") expenses were $1,437,407 in
the third quarter of 2003, an increase of 108% from $691,872 in the same quarter
last year. As a percentage of total revenues, SG&A expenses were 29% in the
current reported quarter compared to 63% in the third quarter of 2002. The
increase in SG&A expenses was mainly from the timing and extent of selling and
promotional costs we assumed for the initial 2003 Drilling Programs. See
"Drilling Programs" above. Since approximately 44% of the total wells for these
Drilling Programs were drilled in the third quarter of 2003, we expensed the
same proportion of those costs in the quarter. The higher current period SG&A
expenses also reflects costs for supporting expanded operations as a whole,
including increased salary and other employee related expenses.
Depreciation, depletion and amortization ("DD&A") increased 62% to
$225,560 in the third quarter of 2003 from $139,380 in the same quarter of 2002.
The increase in DD&A expense reflects additions to oil and gas properties and
related equipment. Because of increased debt incurred to finance part of our
acquisition and development activities, we incurred higher interest expenses, up
153% to $153,677 in the third quarter of 2003 from $60,651 in the same quarter
last year. We also recognized income tax expense of $274,765 for the third
quarter of 2003, reflecting the prior utilization of all loss carryforwards at
the DPI level.
18
We realized net income of $450,045 for the third quarter of 2003, compared
to a net loss of $319,392 in the third quarter of 2002, reflecting the foregoing
factors. Basic earnings per share were $0.05 based on 9,557,613 weighted average
common shares outstanding in the third quarter of 2003, compared to loss per
share of $0.06 based on 5,460,724 weighted average common shares outstanding in
the same quarter last year.
Nine Months Ended September 30, 2003 and 2002. Total revenues for the
first nine months of 2003 were $17,567,465, an increase of 217% from $5,534,238
in the same period last year. Our revenue mix for the current reported period
was 85% contract drilling, 10% oil and gas production and 5% natural gas
transmission and compression. For the comparable period of 2002, our total
revenues were derived 73% from contract drilling, 14% from oil and gas
production and 13% from natural gas transmission and compression activities.
Contract drilling revenues were $14,924,000 for the first nine months of
2003, up 269% from $4,040,733 for the corresponding period in 2002, reflecting
both the size and the timing of our Drilling Program financings. See "Drilling
Programs" above. Based on the size of our 2002 year-end Drilling Programs and
our initial 2003 Drilling Programs, we drilled a total of 55 gross (13.7985 net)
natural gas wells during the first nine months of 2003. As of the date of this
Report, all of those wells have been completed as producers or successfully
tested in at least one primary pay zone. By comparison, based on the size of
2001 year-end Drilling Programs, we drilled 19 gross (5.4960 net) natural gas
wells during the first nine months of 2002.
Production revenues during the first nine months of 2003 were $1,815,630,
an increase of 133% from $777,899 in the comparable period of 2002. This
primarily reflects an increase of 71% in our average sales price of natural gas
(before certain transportation charges) to $5.26 per Mcf in the first nine
months of 2003 from $3.03 per Mcf in the first nine months of 2002. It also
reflects a 37% increase in our production volumes to 331,659 Mcfe in the current
reported period, compared to 242,673 Mcfe in the first nine months of 2002. Our
growth in production volumes resulted from new wells brought on line since the
end of September 2002. The improvement in average sales price for our natural
gas is consistent with a market-wide rebound in natural gas prices that began in
the third quarter of 2002. Principal purchasers of our natural gas production
are gas marketers and transmission companies with facilities near our producing
properties. During the current reported period, approximately half our natural
gas production was sold under fixed-price contracts and the balance primarily at
prices determined monthly under formulas based on prevailing market indices.
Gas transmission and compression revenues were $827,835 during the first
nine months of 2003, up 16% from $715,606 in the comparable period of 2002. This
primarily reflects increased reliance on our own gathering systems for many of
our new wells, generating transmission and compression revenues from the
Drilling Programs holding the working interests in those wells. Our gas
transmission and compression revenues include contributions from Sentra
aggregating $189,194 for the first nine months of 2003 and $107,848 for the same
period last year, an increase of 76%.
Total direct expenses increased by 158% to $7,752,593 for the first nine
months of 2003 compared to $3,006,011 for the same period in 2002. Our direct
expense mix for the current reported period was 87% contract drilling, 8% oil
and gas production and 5% natural gas transmission and compression. For the
comparable period of 2002, our total direct expenses were incurred 67% in
contract drilling, 19% in oil and gas production and 14% in natural gas
transmission and compression.
Contract drilling expenses increased 232% to $6,704,598 in the first nine
months of 2003 from $2,016,779 in the same period last year, reflecting the
substantial increase in drilling activities. Our current drilling activities
have benefited from related economies of scale as well as control of field
overhead expenses. Drilling expenses have been further contained by a reduction
in the total depth for some of the new wells, which generally decreases variable
costs paid to outside contractors and reduces well completion expenditures.
Production expenses increased 13% to $648,797 in the first nine months of
2003 from $572,211 in the same period last year, reflecting costs from higher
production volumes and severance taxes in the current period, partially offset
by economies of scale and field operating efficiencies achieved in the current
reported period. As a percentage of oil and gas production revenues, production
expenses decreased to 36% in the first nine months of 2003 from 74% in the
corresponding period of 2002. The improved margin reflects both cost savings
from operating efficiencies and revenue growth driven by substantially higher
natural gas prices in the current reported period.
19
Gas transmission and compression expenses in the first nine months of 2003
decreased 4% to $399,198 from $417,021 in the same period last year. As a
percentage of gas transmission and compression revenues, these expenses
decreased to 48% in the current reported period from 58% in the first nine
months of 2002.
SG&A expenses were $5,635,136 in the first nine months of 2003, an
increase of 232% from $1,698,987 in the same period last year. As a percentage
of total revenues, SG&A expenses were 32% in the current reported period
compared to 31% in the first nine months of 2002. The increase in SG&A expenses
was mainly from the timing and extent of selling and promotional costs we
assumed for the Drilling Program financings completed at the end of 2002 and in
July 2003. See "Drilling Programs" above. Since approximately 80% of the total
wells for these Drilling Programs were drilled in the first nine months of 2003,
we expensed the same proportion of those costs in the period. The higher current
period SG&A expenses also reflects costs for supporting expanded operations as a
whole, including increased salary and other employee related expenses.
During the second quarter of 2003, certain officers of the Company
exercised options covering a total of 300,000 common shares that were granted in
2000 with a stock-for-stock or "cashless" exercise feature at an exercise price
of $1.25 per share. Since the disclosure only accounting treatment otherwise
followed by the Company is not available for the exercise of stock options with
this feature, we recorded a compensation charge of $558,000 for the nine months
ended September 30, 2003, reflecting the difference between the aggregate
exercise price of the options and the market price of the underlying shares on
the date they were exercised. Additional non-cash compensation expense of
$31,200 was also recognized in the nine months ended September 30, 2003 from the
issuance of common stock purchase warrants for corporate consulting services.
DD&A increased 43% to $598,720 in the first nine months of 2003 from
$418,140 in the same period of 2002. The increase in DD&A expense reflects
additions to oil and gas properties and related equipment. Because of increased
debt incurred to finance part of our acquisition and development activities, we
incurred higher interest expenses, up 96% to $358,310 in the nine months of 2003
from $182,418 in the same period last year. We also recognized income tax
expense of $274,765 for the first nine months of 2003, reflecting the prior
utilization of all loss carryforwards at the DPI level.
We realized net income of $2,462,975 for the first nine months of 2003, an
increase of 827% compared to $265,797 realized in the first nine months of 2002,
reflecting the foregoing factors. Basic earnings per share were $0.33 based on
7,364,447 weighted average common shares outstanding in the first nine months of
2003 compared to earnings of $0.05 per share based on 5,294,499 weighted average
common shares outstanding in the same period last year.
The results of operations for the quarter and nine months ended September
30, 2003 are not necessarily indicative of results to be expected for the full
year.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity. During the nine months ended September 30, 2003, net cash
provided by operating activities was $4,053,819 before working capital
adjustments and $2,055,469 after accounting for changes in assets and
liabilities for the period, including a reduction of $1,939,900 in customers'
drilling deposits under turnkey drilling contracts with sponsored Drilling
Programs. Our cash position during the first nine months of 2003 was increased
by $9,392,858 provided by financing activities, consisting primarily of proceeds
from the issuance of our common shares and convertible notes. See "Recent
Developments - Equity Infusion" and "- Convertible Notes and Preferred Stock"
above. The increase in our cash position from financing activities during the
first nine months of 2003 was partially offset by the use of $4,317,227 of net
cash in investing activities. Funds used in investing activities were comprised
primarily of $3,625,866 in net additions to our oil and gas properties and
$712,106 in the purchase of property and equipment. As a result of these
activities, cash and cash equivalents increased from $7,031,307 at December 31,
2002 to $14,162,407 as of September 30, 2003.
As of September 30, 2003, we had working capital of $7,615,816, compared
to a working capital deficit of $1,513,571 at the end of 2002. Because of wide
fluctuations in our current assets and liabilities resulting from the timing of
customers' deposits and expenditures under turnkey drilling contracts with our
Drilling Programs, we generally do not consider working capital to be a reliable
measure of liquidity. Any working capital deficits at the end of future
reporting periods are not expected to have an adverse effect on our financial
condition or results of operations.
20
Capital Resources. Our business involves significant capital requirements.
The rate of production from oil and gas properties generally declines as
reserves are depleted. Without successful development activities, our proved
reserves will decline as oil and gas is produced from our proved developed
reserves. Our long term performance and profitability is dependent not only on
developing existing oil and gas reserves, but also on our ability to find or
acquire additional reserves on terms that are economically and operationally
advantageous. To fund our ongoing reserve development and acquisition
activities, we have historically relied on a combination of cash flows from
operations, bank borrowings and private placements of our convertible notes and
equity securities, as well as participation by outside investors in our
sponsored Drilling Programs.
During the first nine months of 2003, our property acquisitions,
convertible note financings and institutional private placement of common stock
added significantly to our reserve base and capital resources. See "Recent
Developments - Property Acquisitions," "- Convertible Notes and Preferred Stock"
and "- Equity Infusion" above. The means for developing our properties were also
significantly enhanced by our Drilling Program financings completed in the
fourth quarter of 2002 and the third quarter of 2003, with contributed capital
aggregating $15,975,000 from outside investors. Our 25% contributions to these
programs aggregated $5,329,000. See "Drilling Programs" above.
The agreements governing each of our Drilling Programs organized since
2000 provides program participants with the right, exercisable for 90 days at
the end of the fifth through ninth years following the program's organization,
to convert their program interests into our common stock at prevailing market
prices. Converted program interests will be valued based on their proportionate
share of the standardized measure of discounted future net cash flows from the
program's proved oil and gas reserves, as estimated in the program's year-end
reserve report. Each program participant's annual conversion right is limited to
49% of his program interest. In addition, the exercise of conversion rights in
all Drilling Programs for any year may not exceed, in aggregate, 19% of our
common shares then outstanding. Commencing in 2005, any exercise of these
conversion rights by participants in our recent Drilling Programs would increase
our interests in the programs' oil and gas production and reserves.
To finance part of our contributions to Drilling Programs, we have issued
six separate series of convertible notes since 1999 in the aggregate principal
amount of $9,506,125, including $3,236,125 principal amount of convertible notes
issued in the first six months of 2003 and $5,000,000 principal amount of
convertible notes issued to institutional investors (the "Institutional Notes")
in September 2003. The notes bear interest at rates from 4% to 10% per annum.
The notes of each series are convertible at the option of the holders into our
common stock at prices ranging from $0.85 to $4.50 per share and are generally
redeemable at the option of the Company at 100% of their principal amount plus
accrued interest through the date of redemption. As a result of note conversions
totaling $2,495,000 by several holders in the first nine months of 2003,
convertible notes in the aggregate principal amount of $7,035,098 were
outstanding at September 30, 2003. See "Recent Developments - Convertible Notes
and Preferred Stock" above.
The Institutional Notes issued in September 2003 have several features not
provided under prior note financings. Interest on the Institutional Notes at 7%
per annum is payable quarterly in cash or additional Institutional Notes ("PIK
Notes") and must be paid in PIK Notes through September 30, 2004. We issued PIK
Notes aggregating $23,973 as of September 30, 2003. We have the right to repay
any unconverted Institutional Notes at maturity either in cash or in common
shares valued for that purpose at 90% of their prevailing market price. The
Institutional Notes are repayable upon any event of default in cash at the
greater of 115% of their principal amount or 100% of the prevailing market price
of their underlying conversion shares. Events of default include any delisting
of the Company's common stock, failure to pay interest, honor conversion
requests or satisfy registration requirements, any default for over $250,000 on
other obligations and any sale, merger or other change of control transaction
not approved by holders of the Institutional Notes.
The Institutional Notes are convertible into common shares at the option
their holders at an initial conversion price of $4.50. Participants in the
financing also received three-year warrants to purchase up to an aggregate of
222,222 common shares at an exercise price of $5.11 per share. The conversion
price of the Institutional Notes and exercise price of the related warrants are
subject to anti-dilution adjustments for any recapitalization transaction and
for any issuance of common stock or rights to acquire common stock for
consideration less than the prevailing conversion price or warrant exercise
price. For purposes of these adjustments, dilutive issuances do not include
securities issued under existing instruments, under board-approved incentive
plans or in a public offering, business acquisition or strategic transaction. In
addition, no anti-dilution adjustments will be
21
made to the extent they would increase the total shares issuable under the
Institutional Notes and warrants above 1,947,990 common shares, representing
19.99% of the common shares outstanding at the time of the financing. The same
limitation applies to the payment of interest in kind and to repayment of the
Institutional Notes in common shares.
In addition to our outstanding convertible notes, we maintain a credit
facility with KeyBank NA of up to $10 million, subject to semi-annual borrowing
base determinations by the bank. At September 30, 2003, the borrowing base was
$2,675,000. Borrowings under the facility bear interest payable monthly at 1.25%
above the bank's prime rate, amounting to 5.25% at September 30, 2003. The
facility is secured by liens on all corporate assets, including a first mortgage
on oil and gas interests and pipelines, as well as an assignment of major
production and transportation contracts. During the first nine months of 2002,
we repaid $2,000,000 of the outstanding credit facility principal, reducing our
borrowings under the facility to $252,046 at September 30, 2003.
Our remaining long term debt outstanding at September 30, 2003, including
the current portions, aggregated $422,818 on a secured note issued in 1986 for
the acquisition of our mineral property in Alaska and $173,804 on miscellaneous
obligations incurred to finance various property and equipment acquisitions. Our
ability to repay this acquisition debt as well as our bank debt and any
convertible notes that are not converted prior to maturity will be subject to
our future performance and prospects as well as market and general economic
conditions. We may be dependent on additional financing to repay our outstanding
long term debt at maturity.
Our future revenues, profitability and rate of growth will continue to be
substantially dependent on the demand and market price for natural gas. Future
market prices for natural gas will also have a significant impact on our ability
to maintain or increase our borrowing capacity, to obtain additional capital on
acceptable terms and to continue attracting investment capital to Drilling
Programs. The market price for natural gas is subject to wide fluctuations in
response to relatively minor changes in supply and demand, market uncertainty
and a variety of other factors that are beyond our control.
We expect our cash reserves, cash flow from operations or borrowings
available under our credit facility to provide adequate working capital to meet
our capital expenditure objectives through the end of 2004. Thereafter, to fully
realize our financial goals for growth in revenues and reserves, we will
continue to be dependent on the capital markets or other financing alternatives
as well as continued participation by investors in future Drilling Programs.
RELATED PARTY TRANSACTIONS
Because we operate through subsidiaries and affiliated Drilling Programs,
our holding company structure causes various agreements and transactions in the
normal course of business to be treated as related party transactions. It is our
policy to structure any transactions with related parties only on terms that are
no less favorable to the Company than could be obtained on an arm's length basis
from unrelated parties. Significant related party transactions are summarized in
Notes 4 and 12 of the footnotes to the accompanying condensed consolidated
financial statements.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
General. The preparation of financial statements requires management to
make estimates and judgments that affect the reported amounts of assets,
liabilities, revenues and expenses and related disclosure of contingent assets
and liabilities. On an ongoing basis, management evaluates its estimates,
including evaluations of any allowance for doubtful accounts and impairment of
long-lived assets. Management bases its estimates on historical experience and
on various other assumptions it believes to be reasonable under the
circumstances. The results of these evaluations form a basis for making
judgments about the carrying value of assets and liabilities that are not
readily apparent from other sources. Although actual results may differ from
these estimates under different assumptions or conditions, management believes
that its estimates are reasonable and that actual results will not vary
significantly from the estimated amounts.
The following critical accounting policies relate to the more significant
judgments and estimates used in the preparation of the condensed consolidated
financial statements.
Allowance for Doubtful Accounts. We maintain an allowance for doubtful
accounts when deemed appropriate to reflect losses that could result from
failures by customers or other parties to make payments on our trade
receivables. The estimates of this allowance, when maintained, are based on a
number of factors, including historical experience, aging of
22
the trade accounts receivable, specific information obtained on the financial
condition of customers and specific agreements or negotiated amounts with
customers.
Impairment of Long-Lived Assets. Our long-lived assets include property
and equipment and goodwill. Long-lived assets with an indefinite life are
reviewed at least annually for impairment, while other long-lived assets are
reviewed whenever events or changes in circumstances indicate that carrying
values of these assets are not recoverable.
FORWARD LOOKING STATEMENTS
This Report includes forward looking statements within the meaning of
Section 21E of the Securities Exchange Act relating to matters such as
anticipated operating and financial performance, business and financing
prospects, developments and results of our operations. Actual performance,
prospects, developments and results may differ materially from anticipated
results due to economic conditions and other risks, uncertainties and
circumstances partly or totally outside our control, including operating risks
inherent in oil and gas development and producing activities, fluctuations in
market prices of oil and natural gas, changes in future development and
production costs and uncertainties in the availability and cost of capital.
Words such as "anticipated," "expect," "intend," "plan" and similar expressions
are intended to identify forward looking statements, all of which are subject to
these risks and uncertainties.
ITEM 3. CONTROLS AND PROCEDURES
Under the supervision and with the participation of our management,
including our Chief Executive Officer and Chief Financial Officer, we have
evaluated the effectiveness of the design and operation of our disclosure
controls and procedures within 90 days of the filing of this Report. Based on
their evaluation, our Chief Executive Officer and Chief Financial Officer have
concluded that these controls and procedures are effective. There were no
significant changes in our internal controls or other factors that significantly
affected these controls after the date of their evaluation.
23
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits.
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
- ------- ----------------------
3.1 Memorandum and Articles for Catalina Energy & Resources Ltd., a
British Columbia corporation, dated January 31, 1979 (incorporated
by reference to Exhibit 3[a] to its Registration Statement on Form
10 [File No. 0-12185], filed May 25, 1984).
3.2 Certificate for Catalina Energy & Resources Ltd., a British Columbia
corporation, dated November 27, 1981, changing the name of Catalina
Energy & Resources Ltd. to Alaska Apollo Gold Mines Ltd.
(incorporated by reference to Exhibit 3[b] to its Registration
Statement on Form 10 [File No. 0-12185] filed May 25, 1984).
3.3 Certificate of Change of Name for Alaska Apollo Gold Mines Ltd., a
British Columbia corporation, dated October 14, 1992, changing the
name of Alaska Apollo Gold Mines Ltd. to Daugherty Resources, Inc.,
and changing its authorized capital stock to 6,000,000 shares of
common stock, without par value (incorporated by reference to
Exhibit 3[c] to Amendment No. 1 to its Annual Report on Form 10-K
[File No. 0-12185] for the year ended December 31, 1993).
3.4 Altered Memorandum of Daugherty Resources, dated September 9, 1994,
changing its authorized capital stock to 20,000,000 shares of common
stock, without par value (incorporated by reference to Exhibit 3[d]
to Amendment No. 1 to its Annual Report on Form 10-K [File No.
0-12185] for the year ended December 31, 1993).
3.5 Altered Memorandum of Daugherty Resources, dated June 30, 1999,
changing its authorized capital stock to 100,000,000 shares of
common stock, without par value, and 5,000,000 shares of preferred
stock, without par value, and accompanying Special Resolution
setting forth the terms of preferred shares (incorporated by
reference to Exhibit 3[a] to its Current Report on Form 8-K [File
No. 0-12185] dated October 25, 1999).
10.1 1997 Stock Option Plan of Daugherty Resources (incorporated by
reference to Exhibit 10[a] to its Annual Report on Form 10-K [File
No. 0-12185] for the year ended December 31, 2002).
10.2 2001 Stock Option Plan of Daugherty Resources (incorporated by
reference to Exhibit 10[b] to its Annual Report on Form 10-K [File
No. 0-12185] for the year ended December 31, 2002).
10.3 Securities Purchase Agreement dated as of June 10, 2003 between
Daugherty Resources and the investors named therein (incorporated by
reference to Exhibit 10.1 to the Current Report on Form 8-K [File
No. 0-12185] of Daugherty Resources dated June 13, 2003).
10.4 Registration Rights Agreement dated as of June 13, 2003 between
Daugherty Resources and the investors named therein (incorporated by
reference to Exhibit 10.2 to the Current Report on Form 8-K [File
No. 0-12185] of Daugherty Resources dated June 13, 2003).
10.5 Form of Common Stock Purchase Warrant dated June 13, 2003 issued
pursuant to Securities Purchase Agreement dated as of June 10, 2003
between Daugherty Resources, Inc. and the investors named therein
(incorporated by reference to Exhibit 10.1 to the Current Report on
Form 8-K [File No. 0-12185] of Daugherty Resources dated June 13,
2003).
10.6 Securities Purchase Agreement dated as of September 5, 2003 between
Daugherty Resources and the investors named therein (incorporated by
reference to Exhibit 10.1 to the Current Report on Form 8-K [File
No. 0-12185] of Daugherty Resources dated September 9, 2003).
24
10.7 Form of 7% Convertible Promissory Note dated as of September 5, 2003
issued pursuant to the Securities Purchase Agreement dated as of
September 5, 2003 between Daugherty Resources, Inc. and the
investors named therein (incorporated by reference to Exhibit 10.2
to the Current Report on Form 8-K [File No. 0-12185] of Daugherty
Resources dated September 5, 2003).
10.8 Registration Rights Agreement dated as of September 5, 2003 between
Daugherty Resources and the investors named therein (incorporated by
reference to Exhibit 10.3 to the Current Report on Form 8-K [File
No. 0-12185] of Daugherty Resources dated September 9, 2003).
10.9 Form of Common Stock Purchase Warrant dated September 5, 2003 issued
pursuant to Securities Purchase Agreement dated as of September 5,
2003 between Daugherty Resources, Inc. and the investors named
therein (incorporated by reference to Exhibit 10.4 to the Current
Report on Form 8-K [File No. 0-12185] of Daugherty Resources dated
September 9, 2003).
31.1 Certification of Chief Executive Officer Pursuant to Rule
13a-14(a) under the Securities Exchange Act of 1934, as amended.
31.2 Certification of Chief Financial Officer Pursuant to Rule
13a-14(a) under the Securities Exchange Act of 1934, as amended.
32.1 Certification pursuant to 18 U.S.C. Section 1350, as adopted
under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 Certification pursuant to 18 U.S.C. Section 1350, as adopted
under Section 906 of the Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K.
Current Report on Form 8-K dated September 9, 2003 regarding
completion of the transactions contemplated by a Securities Purchase
Agreement dated as of September 5, 2003 among Daugherty Resources,
Inc. and the investors named therein.
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.
DAUGHERTY RESOURCES, INC.
Date: November 10, 2003 By: /s/ William S. Daugherty
-----------------------------------
William S. Daugherty
Chief Executive Officer
(Duly Authorized Officer)
(Principal Executive Officer)
25