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 JUNE 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 AUGUST 7, 2003
COMMON STOCK 9,592,710
Transitional Small Business Disclosure Format. Yes [ ] No [X]
DAUGHERTY RESOURCES, INC.
INDEX
PAGE
----
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS:
Review Engagement Report.................................................................................... 2
Condensed Consolidated Balance Sheets -- June 30, 2003 (unaudited) and December 31, 2002.................... 3
Condensed Consolidated Statement of Operations and Deficit -- Three months and six months
ended June 30, 2003 and 2002 (unaudited)................................................................. 4
Condensed Consolidated Statement of Cash Flows -- Three months and six months
ended June 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............................................................................. 22
PART II. OTHER INFORMATION.................................................................................. 23
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 June 30, 2003, and the condensed consolidated statements
of operations and deficit, and cash flows for the three and six months then
ended. 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, 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
August 7, 2003
2
DAUGHERTY RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(U.S. FUNDS)
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
------------- --------------
ASSETS
Current assets:
Cash and cash equivalents.................................................. $ 7,450,076 $ 7,031,307
Accounts receivable........................................................ 406,935 328,035
Prepaid expenses and other current assets.................................. 370,428 460,663
Loans to related parties (Note 4).......................................... 122,855 64,162
------------- --------------
Total current assets..................................................... 8,350,294 7,884,167
Bonds and deposits........................................................... 41,000 41,000
Oil and gas properties (Note 2).............................................. 12,002,970 9,679,549
Property and equipment (Note 3).............................................. 1,317,843 918,855
Loans to related parties (Note 4)............................................ 600,386 711,658
Investment (Note 5).......................................................... 119,081 119,081
Deferred financing costs (Note 6)............................................ 29,786 43,546
Goodwill (Note 7)............................................................ 313,177 313,177
------------- --------------
Total assets............................................................. $ 22,774,537 $ 19,711,033
============= ==============
LIABILITIES
Current liabilities:
Bank loans (Note 8)........................................................ $ 134,162 $ 134,162
Accounts payable........................................................... 1,167,828 1,094,941
Accrued liabilities........................................................ 1,839,130 1,212,094
Customers' drilling deposits............................................... 1,812,700 6,764,200
Long term debt, current portion (Note 9)................................... 165,546 192,341
------------- --------------
Total current liabilities................................................ 5,119,366 9,397,738
Long term debt (Note 9)...................................................... 3,946,714 4,027,198
------------- --------------
Total liabilities........................................................ 9,066,080 13,424,936
------------- --------------
SHAREHOLDERS' EQUITY
Capital Stock (Note 10)
Authorized:
5,000,000 Preferred shares, non-cumulative, convertible
100,000,000 Common shares
Issued:
226,354 Preferred shares (2002 - 558,476)............ ................. 417,489 1,784,493
8,798,737 Common shares (2002 - 5,505,670).............. ................ 31,366,231 24,589,797
21,100 Common shares held in treasury, at cost........ ............... (23,630) (23,630)
To be issued:
24,887 Common shares................................... .............. 55,226 55,226
------------- --------------
31,815,316 26,405,886
Accumulated deficit.......................................................... (18,106,859) (20,119,789)
------------- --------------
Total shareholders' equity............................................... 13,708,457 6,286,097
------------- --------------
Total liabilities and shareholders' equity...................................... $ 22,774,537 $ 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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------------- -------------------------------
2003 2002 2003 2002
------------- -------------- ------------- --------------
REVENUE
Contract drilling (Note 12)................... $ 3,025,000 $ -- $ 11,058,000 $ 3,484,000
Oil and gas production........................ 537,286 221,895 1,066,290 457,446
Gas transmission and compression.............. 289,183 210,886 558,034 495,263
------------- -------------- ------------- --------------
Total revenue............................... 3,851,469 432,781 12,682,324 4,436,709
------------- -------------- ------------- --------------
DIRECT EXPENSES
Contract drilling............................. 1,283,184 -- 4,678,349 1,776,634
Oil and gas production........................ 104,930 152,502 420,944 346,649
Gas transmission and compression.............. 146,573 112,518 254,762 344,893
------------- -------------- ------------- --------------
Total direct expenses....................... 1,534,687 265,020 5,354,055 2,468,176
------------- -------------- ------------- --------------
GROSS PROFIT..................................... 2,316,782 167,761 7,328,269 1,968,533
------------- -------------- ------------- --------------
OTHER INCOME (EXPENSES)
Selling, general and administrative........... (1,505,514) (367,454) (4,197,729) (1,007,115)
Compensation from options and warrants........ (589,200) -- (589,200) --
Depreciation, depletion and amortization...... (194,080) (139,380) (373,160) (278,760)
Interest expense.............................. (122,180) (49,241) (204,633) (121,767)
Interest income............................... 28,707 10,311 57,535 24,298
Other, net.................................... (4,397) -- (8,152) --
------------- -------------- ------------- --------------
Total other income (expenses)............... (2,386,664) (545,764) (5,315,339) (1,383,344)
------------- -------------- ------------- --------------
INCOME (LOSS) BEFORE INCOME TAXES................ (69,882) (378,003) 2,012,930 585,189
INCOME TAX EXPENSE
Current....................................... (26,555) (143,641) 764,914 222,372
Benefit realized on loss carried forward...... 26,555 143,641 (764,914) (222,372)
------------- -------------- ------------- --------------
NET INCOME (LOSS)................................ $ (69,882) $ (378,003) $ 2,012,930 $ 585,189
============= ============== ============= ==============
DEFICIT, beginning of period..................... $ (18,036,977) $ (19,791,547) $ (20,119,789) $ (20,754,739)
============= ============== ============= ==============
DEFICIT, end of period........................... $ (18,106,859) $ (20,169,550) $ (18,106,859) $ (20,169,550)
============= ============== ============= ==============
NET INCOME (LOSS) PER SHARE
Basic......................................... $ (0.01) $ (0.07) $ 0.32 $ 0.11
============= ============== ============= ==============
Diluted....................................... $ (0.01) $ (0.07) $ 0.22 $ 0.10
============= ============== ============= ==============
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING:
Basic......................................... 6,632,620 5,346,689 6,249,688 5,209,765
============= ============== ============= ==============
Diluted....................................... 6,632,620 5,346,689 9,523,329 6,154,095
============= ============== ============= ==============
See Notes to Condensed Consolidated Financial Statements.
4
DAUGHERTY RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(U.S. FUNDS)
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------------- --------------------------
2003 2002 2003 2002
----------- ----------- ----------- -----------
OPERATING ACTIVITIES
Net income (loss)....................................... $ (69,882) $ (378,003) $ 2,012,930 $ 585,189
Adjustments to reconcile net income (loss)
to net cash used in operating activities:
Incentive bonus paid in common shares ................ 115,290 -- 351,420 109,620
Compensation from options and warrants ............... 589,200 -- 589,200 --
Depreciation, depletion and amortization ............. 194,080 139,380 373,160 278,760
Loss on sale of assets ............................... -- -- 3,795 --
Changes in assets and liabilities
Accounts receivable ................................ (97,848) 14,533 (78,900) 84,071
Prepaid expenses and other assets .................. (146,891) (85,205) 90,235 (86,840)
Accounts payable ................................... (81,684) 34,456 205,813 28,106
Accrued liabilities ................................ (562,983) (206,943) 627,036 354,025
Customers' drilling deposits ....................... 953,500 -- (4,951,500) (2,703,000)
----------- ----------- ----------- -----------
Net cash provided by (used in) operating activities ....... 892,782 (481,782) (776,811) (1,350,069)
----------- ----------- ----------- -----------
INVESTING ACTIVITIES
Proceeds from sale of assets ........................... -- -- 3,245 --
Purchase of property and equipment ..................... (99,622) (27,368) (475,428) (69,852)
Purchase of investment ................................. -- -- -- (9,827)
Additions to oil and gas properties, net ............... (1,056,487) (70,020) (2,613,421) (399,904)
----------- ----------- ----------- -----------
Net cash used in investing activities ..................... (1,156,109) (97,388) (3,085,604) (479,583)
----------- ----------- ----------- -----------
FINANCING ACTIVITIES
Net payments on short term borrowings .................. -- (7,085) -- (11,905)
Decrease (increase) in loans to related parties ........ 30,714 (1,501) 52,579 (199,798)
Proceeds from issuance of common shares ................ 2,926,696 -- 3,075,884 --
Proceeds from issuance of long term debt ............... 2,170,625 -- 3,236,125
Payments of long term debt ............................. (2,030,057) (4,842) (2,083,404) (37,883)
----------- ----------- ----------- -----------
Net cash provided by (used in) financing activities ....... 3,097,978 (13,428) 4,281,184 (249,586)
----------- ----------- ----------- -----------
CHANGE IN CASH AND CASH EQUIVALENTS ....................... 2,834,651 (592,598) 418,769 (2,079,238)
CASH AND CASH EQUIVALENTS:
Beginning of period .................................... 4,615,425 757,780 7,031,307 2,244,420
----------- ----------- ----------- -----------
End of period........................................... $ 7,450,076 $ 165,182 $ 7,450,076 $ 165,182
=========== =========== =========== ===========
SUPPLEMENTAL DISCLOSURE
Interest paid.............................................. $ 68,364 $ 25,755 $ 172,942 $ 117,295
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 ... 50,000 -- 164,126 155,031
Common shares issued upon conversion of notes ............. 1,260,000 -- 1,260,000 --
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 June 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,
JUNE 30, 2003 2002
----------------------------------------- -----------
ACCUMULATED
COST DD&A NET NET
------------ ----------- ----------- -----------
Proved oil and gas properties.............. $ 12,957,595 $(2,160,285) $10,797,310 $ 8,576,375
Unproved oil and gas properties ............. 494,737 -- 494,737 419,737
Wells and related equipment ................. 845,430 (134,507) 710,923 683,437
------------ ----------- ----------- -----------
Total oil and gas properties................ $ 14,297,762 $(2,294,792) $12,002,970 $ 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,
JUNE 30, 2003 2002
----------------------------------------- -----------
ACCUMULATED
COST DEPRECIATION NET NET
------------ ----------- ----------- -----------
Land......................................... $ 12,908 $ -- $ 12,908 $ 12,908
Building improvements........................ 20,609 (2,366) 18,243 4,471
Machinery and equipment...................... 990,141 (178,262) 811,879 625,086
Office furniture and fixtures................ 131,717 (89,820) 41,897 18,176
Aircraft..................................... 275,000 (17,891) 257,109 116,146
Vehicles..................................... 321,627 (145,820) 175,807 142,068
------------ ----------- ----------- -----------
Total property and equipment................. $ 1,752,002 $ (434,159) $ 1,317,843 $ 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 $551,812 at June 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 June 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 June 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.
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. 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. The Company performed an analysis of
its recorded goodwill in October 2002 and determined that no impairment charge
was required. Accordingly, accumulated amortization of goodwill remained at
$1,476,387 as of June 30, 2003 and December 31, 2002.
7
NOTE 8. BANK LOAN
At June 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 June 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 June 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 $247,984 at June
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 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.
SHARES
PRINCIPAL AMOUNT OUTSTANDING AT ISSUABLE AT
------------------------------------ JUNE 30, 2003
JUNE 30, DECEMBER 31, CONVERSION UPON
TITLE OF NOTES 2003 2002 PRICE CONVERSION
-------------- -------------- -------------- ---------- --------------
10% Convertible Secured
Notes due July 31, 2004(1).... $ 555,000 $ 850,000 $ 2.71 204,691
10% Convertible Notes
due May 1, 2007............... 1,020,500 420,000 1.50 680,333
8% Convertible Notes
due April 10, 2008............ 770,625 -- 1.90 405,613
8% Convertible Notes
due May 1, 2008............... 900,000 -- 2.25 400,000
-------------- -------------- -----------
Total......................... $ 3,246,125 $ 1,270,000 1,690,637
============== ============== ===========
- -------------------------
(1) Secured by liens on mining properties.
(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 $424,818 at June 30, 2003.
8
(d) Miscellaneous Debt. The following table summarizes the Company's
other outstanding debt obligations at June 30, 2003 and December 31, 2002.
PRINCIPAL AMOUNT OUTSTANDING AT
-------------------------------
JUNE 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....................... $ 39,900 $ 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 ... 27,664 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 ................... 60,990 76,178
Loan payable to unaffiliated company, bearing interest at 10% per annum ....... -- 24,650
--------- ------------
$ 193,333 $ 262,737
========= ============
(e) Total Long Term Debt. The following table sets forth the Company's
total long term debt and current portion at June 30, 2003 and December 31, 2002.
PRINCIPAL AMOUNT OUTSTANDING AT
-------------------------------
JUNE 30, DECEMBER 31,
2003 2002
----------- ------------
Total long term debt (including current portion)......................... $ 4,112,260 $ 4,219,539
Less current portion .................................................... 165,546 192,341
----------- ------------
Total long term debt..................................................... $ 3,946,714 $ 4,027,198
=========== ============
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.......................................... (332,122) (1,367,004)
--------- ------------
Balance, June 30, 2003 (See Note 15)..................................... 226,354 $ 417,489
========= ============
9
NUMBER OF
COMMON SHARES ISSUED SHARES AMOUNT
-------------------- --------- -------------
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............................ 371,983 1,367,004
Issued for settlement of accounts payable............................. 146,888 164,126
Issued upon conversion of convertible notes........................... 878,070 1,260,000
Issued upon exercise of stock options and warrants.................... 592,626 1,173,434
--------- -------------
Balance, June 30, 2003................................................... 8,798,737 $ 31,366,231
========= =============
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 six months ended June 30, 2003 would have decreased to $1,870,930 or
$0.30 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 months ended June 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 three months and six months ended June 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 both the
three months and six months ended June 30, 2003 from the issuance of warrants
for corporate consulting services.
The exercise prices of options outstanding and exercisable at June 30,
2003 range from $1.00 to $5.00 per share, and their weighted average remaining
contractual life is 2.08 years. The following table reflects transactions
involving the Company's stock options during the reported periods.
10
WEIGHTED
AVERAGE
STOCK OPTIONS ISSUED EXERCISABLE EXERCISE PRICE
------------- ---------- ----------- --------------
Balance, December 31, 2001..................... 2,479,210 2,442,515 $ 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................................... (577,520) 1.19
Expired..................................... (25,000) 5.00
----------
Balance. June 30, 2003......................... 1,382,690 1,382,690 1.16
========== =========
The Company has issued common stock purchase warrants in various
financing transactions. The exercise prices of warrants outstanding at June 30,
2003 range from $1.12 to $4.80 per share, and their weighted average remaining
contractual life is 1.74 years. The following table reflects transactions
involving the Company's common stock purchase warrants during the reported
periods.
WEIGHTED
AVERAGE
COMMON STOCK PURCHASE WARRANTS ISSUED EXERCISABLE EXERCISE PRICE
------------------------------ ---------- ----------- --------------
Balance, December 31, 2001..................... 2,943,721 2,943,721 $ 2.61
=========
Expired..................................... (500,000) 0.63
----------
Balance, December 31, 2002..................... 2,443,721 2,443,721 2.76
=========
Issued...................................... 387,400 3.33
Expired..................................... (135,685) 2.26
----------
Balance. June 30, 2003......................... 2,695,436 2,695,436 2.87
========== =========
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.
WEIGHTED AVERAGE
REPORTING PERIOD COMMON SHARES OUTSTANDING
--------------- -------------------------
Three months ended June 30, 2003 6,632,620
Three months ended June 30, 2002 5,346,689
Six months ended June 30, 2003 6,249,688
Six months ended June 30, 2002 5,209,765
(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, warrants and convertible instruments. For the six
months ended June 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 period. For
the six months ended June 30, 2002, only the assumed conversion of convertible
notes and preferred stock would have a dilutive effect on EPS. Because the
Company recognized net losses for the three months ended June 30, 2003 and 2002,
the assumed exercise or conversion of all these instruments would have been
anti-dilutive in both three-month periods. The following table sets forth the
computation of basic and dilutive EPS for the six months ended June 30, 2003 and
2002.
11
SIX MONTHS ENDED
JUNE 30,
-----------------------
2003 2002
---------- ----------
NUMERATOR:
Net income (loss) as reported for basic EPS...... $2,012,930 $ 585,189
Adjustments to income (loss) for diluted EPS .... 65,959 24,557
---------- ----------
Net income (loss) for diluted EPS.............. $2,078,889 $ 609,746
========== ==========
DENOMINATOR:
Weighted average shares for basic EPS ........... 6,249,688 5,209,765
Effect of dilutive securities:
Stock options ................................. 943,262 --
Warrants ...................................... 296,185 --
Convertible notes ............................. 1,780,678 313,491
Convertible preferred shares .................. 253,516 630,839
---------- ----------
Adjusted weighted average shares and
assumed conversions for dilutive EPS .......... 9,523,329 6,154,095
========== ==========
Basic EPS ....................................... $ 0.32 $ 0.11
========== ==========
Diluted EPS ..................................... $ 0.22 $ 0.10
========== ==========
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 six months ended June 30, 2003 and 2002, lease
payments to the related party were $6,000 and $9,000, respectively.
(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 June 30, 2003................ $ 3,025,000
Three months ended June 30, 2002................ --
Six months ended June 30, 2003.................. 11,058,000
Six months ended June 30, 2002.................. 3,484,000
12
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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------------- ----------------------------
2003 2002 2003 2002
------------ ------------ ------------ ------------
REVENUE, NET:
Oil and gas development........................... $ 3,851,469 $ 432,781 $ 12,682,324 $ 4,436,709
Corporate ........................................ -- -- -- --
------------ ------------ ------------ ------------
Total ......................................... 3,851,469 432,781 12,682,324 4,436,709
------------ ------------ ------------ ------------
DD&A:
Oil and gas development .......................... 174,800 125,000 336,267 250,000
Corporate ........................................ 19,280 14,380 36,893 28,760
------------ ------------ ------------ ------------
Total ......................................... 194,080 139,380 373,160 278,760
------------ ------------ ------------ ------------
INTEREST EXPENSE:
Oil and gas development .......................... 73,133 27,991 110,991 79,267
Corporate ........................................ 49,047 21,250 93,642 42,500
------------ ------------ ------------ ------------
Total ......................................... 122,180 49,241 204,633 121,767
------------ ------------ ------------ ------------
NET INCOME (LOSS):
Oil and gas development .......................... 414,801 (191,151) 3,010,193 1,112,813
Corporate ........................................ (484,683) (186,852) (997,263) (527,624)
------------ ------------ ------------ ------------
Total ......................................... (69,882) (378,003) 2,012,930 585,189
------------ ------------ ------------ ------------
CAPITAL EXPENDITURES:
Oil and gas development .......................... 1,122,902 88,265 2,930,373 446,472
Corporate ........................................ 33,207 9,123 158,476 23,284
------------ ------------ ------------ ------------
Total.......................................... $ 1,156,109 $ 97,388 $ 3,088,849 $ 469,756
============ ============ ============ ============
JUNE 30, DECEMBER 31,
2003 2002
------------ ------------
IDENTIFIABLE ASSETS:
Oil and gas development......................................................... $ 16,550,741 $ 18,194,537
Corporate....................................................................... 6,223,796 1,516,496
------------ ------------
Total........................................................................ $ 22,774,537 $ 19,711,033
============ ============
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 six months ended
June 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, 2003 did not have a material
impact on its consolidated financial statements for the reported periods.
13
(d) SFAS No. 145. SFAS No. 145, "Rescission of FASB Statements No. 4,
44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," was
issued in April 2002. 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. The statement
is effective for financial statements issued on or after May 15, 2002 and has
not had a material impact on the Company's consolidated financial statements for
the reported periods.
(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 June 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.
NOTE 15. SUBSEQUENT EVENTS
Preferred Stock Conversion. On July 14, 2003, all of the Company's
outstanding preferred shares were automatically converted into common shares on
a 1.12-for-1 basis. As a result, the Company issued a total of 253,516 common
shares upon conversion of 226,354 outstanding preferred shares.
Drilling Program Financing. In July 2003, the Company completed a
private placement of interests in a new Drilling Program aggregating $6,750,000.
DPI contributed an additional $2,250,000 to the program for an aggregate program
interest of 25.75% as both an investor and general partner. The program entered
into a turnkey drilling contract with DPI for 30 new wells on sites for which
drilling rights will be assigned to the program by DPI.
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 interest 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 21 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
its 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 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 from approximately 10,000
wells. We plan to drill development wells on the acquired acreage to test five
primary natural gas pay zones at depths between 3,500
15
and 4,500 feet. We committed to drill at least 25 wells on the acquired acreage
during 2003, and we plan to focus our long term drilling initiatives on further
developing the property.
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 plan to begin development drilling on the
acquired acreage later in 2003 to test up to five natural gas pay zones at
depths between 3,500 and 4,500 feet.
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.
Conversion of Notes and Preferred Stock. Since 1999, we have financed a
substantial part of our drilling activities with proceeds from private
placements of five separate series of our convertible notes in the aggregate
principal amount of $4,506,125, including $3,236,125 principal amount of
convertible notes issued in the first six months of 2003. The notes are
convertible into our common stock at the option of the holders at specified
rates. During the first half of 2003, our convertible note holders elected to
convert $1,260,000 aggregate principal amount of their notes into a total of
878,070 shares of our common stock. See "Liquidity and Capital Resources -
Capital Resources" below. In addition, on July 14, 2003, all of our outstanding
preferred shares were automatically converted into common shares on a 1.12-for-1
basis. As a result, we issued a total of 253,516 common shares upon conversion
of 226,354 outstanding preferred shares, further simplifying our capital
structure.
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 nearly
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.
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 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.
Proportionate Consolidation. We contributed an aggregate of $2,925,000
to the year-end 2002 Drilling Programs and $2,250,000 to the initial 2003
Drilling Program for our 25.75% interest as an investor and managing
16
partner of each program. 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 six months ended June 30, 2003, we drilled
41 gross (10.2072 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. All of these wells 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 June 30, 2003 and 2002. Total revenues for the quarter
ended June 30, 2003 were $3,851,469, an increase of 790% from $432,781 in the
same quarter last year. Our revenue mix for the second quarter of 2003 was 79%
contract drilling, 14% oil and gas production and 7% natural gas transmission
and compression. For the comparable quarter of 2002, we did not realize any
revenues from contract drilling, and our total revenues were derived 51% from
oil and gas production and 49% from natural gas transmission and compression
activities.
Contract drilling revenues were $3,025,000 for the second quarter of
2003, with no drilling revenues recognized 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 2002 year-end Drilling Programs were substantially completed
in the first quarter of 2003, and operations on behalf of the initial 2003
Drilling Program were commenced during the second quarter of 2003, when we
drilled 12 gross (2.8325 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 $537,286 for the second quarter of 2003, an
increase of 142% from $221,895 in the comparable quarter of 2002. This primarily
reflects an increase of 98% in our average sales price of natural gas (before
certain transportation charges) to $5.86 per Mcf in the second quarter of 2003
from $2.96 per Mcf in the corresponding quarter of 2002. It also reflects a 31%
increase in our production volumes to 96,148 Mcfe in the second quarter of 2003.
Our growth in production volumes resulted from new wells brought on line since
the end of June 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 half our natural
production gas was sold under fixed-price contracts and the balance primarily at
prices determined monthly under formulas based on prevailing spot market prices.
17
Gas transmission and compression revenues were $289,183 during the
second quarter of 2003, up 37% from $210,886 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 $39,568 for the second quarter of
2003 and $24,218 for the same quarter last year, an increase of 63%. During the
current reported quarter, Sentra had 186 customers, of which 64 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 479% to $1,534,687 for the second
quarter of 2003 compared to $265,020 for the same quarter in 2002. Our direct
expense mix for the current reported quarter was 84% contract drilling, 7% oil
and gas production and 9% natural gas transmission and compression. For the
comparable quarter of 2002, we recognized no contract drilling expenses, and our
total direct expenses were incurred 58% in oil and gas production and 42% in
natural gas transmission and compression.
Contract drilling expenses were $1,283,184 in the second quarter of
2003, reflecting the substantial level of drilling activities on behalf of our
initial 2003 Drilling Program. 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 decreased 31% to $104,930 in the second quarter of
2003 from $152,502 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 20% in the second quarter of 2003
from 69% 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 second quarter of 2003.
Gas transmission and compression expenses in the second quarter of 2003
increased 30% to $146,573 from $112,518 in the same quarter last year. As a
percentage of gas transmission and compression revenues, these expenses
decreased to 51% in the current reported quarter from 53% in the second quarter
of 2002.
Selling, general and administrative ("SG&A") expenses were $1,505,514
in the second quarter of 2003, an increase of 310% from $367,454 in the same
quarter last year. As a percentage of total revenues, SG&A expenses were 39% in
the current reported quarter compared to 85% in the second 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 Program. See
"Drilling Programs" above. We drilled 12 wells or 40% of the 30 total wells for
the program in the second quarter of 2003 and 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.
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 three months
and six months ended June 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 both the three months and six months ended
June 30, 2003 from the issuance of common stock purchase warrants for corporate
consulting services.
Depreciation, depletion and amortization ("DD&A") increased 39% to
$194,714 in the second 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 also incurred higher interest
expenses, up 148% to $122,180 in the second quarter of 2003 from $49,241 in the
same quarter last year.
We recognized a net loss of $69,882 for the second quarter of 2003,
compared to a net loss of $378,003 in the second quarter of 2002, reflecting the
foregoing factors. Our net loss per share was $(0.01) based on 6,632,620
18
weighted average common shares outstanding in the second quarter of 2003,
compared to a net loss per share of ($0.07) based on 5,346,689 weighted average
common shares outstanding in the same quarter last year.
Six Months Ended June 30, 2003 and 2002. Total revenues for the first
six months of 2003 were $12,682,324, an increase of 186% from $4,436,709 in the
same period last year. Our revenue 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 revenues were derived
79% from contract drilling, 10% from oil and gas production and 11% from natural
gas transmission and compression activities.
Contract drilling revenues were $11,058,000 for the first half of 2003,
up 217% from $3,484,000 for the first half of 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 Program, we drilled a total of 41 gross (10.2072 net) natural gas wells
during the first half 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 17 gross (4.5625 net) natural gas wells during the first half of
2002.
Production revenues during the first six months of 2003 were
$1,066,290, an increase of 133% from $457,446 in the comparable period of 2002.
This primarily reflects an increase of 87% in our average sales price of natural
gas (before certain transportation charges) to $5.18 per Mcf in the first six
months of 2003 from $2.77 per Mcf in the first six months of 2002. It also
reflects a 29% increase in our production volumes to 198,886 Mcfe in the current
reported period. Our growth in production volumes resulted from new wells
brought on line since the end of June 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 production gas was sold under fixed-price
contracts and the balance primarily at prices determined monthly under formulas
based on prevailing spot market prices.
Gas transmission and compression revenues were $558,034 during the
first half of 2003, up 13% from $495,263 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 $155,320 for the first half of 2003 and $89,506 for the same period
last year, an increase of 74%. As of June 30, 2003, Sentra had total
transmission and distribution capabilities of 135,969 feet and 28,174 feet,
respectively.
Total direct expenses increased by 117% to $5,354,055 for the first six
months of 2003 compared to $2,468,176 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 72% in
contract drilling, 14% in oil and gas production and 14% in natural gas
transmission and compression.
Contract drilling expenses increased 163% to $4,678,349 in the first
half of 2003 from $1,776,634 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 21% to $420,944 in the first six months
of 2003 from $346,649 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 39% in the first six months of 2003 from 76% 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.
Gas transmission and compression expenses in the first half of 2003
decreased 46% to $254,762 from $344,893 in the same period last year. As a
percentage of gas transmission and compression revenues, these expenses
decreased to 43% in the current reported period from 70% in the first half of
2002.
19
SG&A expenses were $4,197,729 in the first six months of 2003, an
increase of 317% from $1,007,115 in the same period last year. As a percentage
of total revenues, SG&A expenses were 33% in the current reported period
compared to 23% in the first six 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 41 wells or 59% of the 69 total
wells for these three drilling Programs were drilled in the first six 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. In addition to those expenses, we recognized non-cash compensation
charges aggregating $589,200 from transactions in stock options and common stock
purchase warrants during the current reported period.
DD&A increased 34% to $373,160 in the first half of 2003 from $278,760
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 also incurred
higher interest expenses, up 68% to $204,633 in the first half of 2003 from
$121,767 in the same period last year.
We realized net income of $2,012,930 for the first six months of 2003,
an increase of 244% compared to $585,189 realized in the first six months of
2002, reflecting the foregoing factors. Basic earnings per share were $0.32
based on 6,249,688 weighted average common shares outstanding in the first six
months of 2003 compared to $0.11 based on 5,209,765 weighted average common
shares outstanding in the same period last year.
The results of operations for the quarter and six months ended June 30,
2003 are not necessarily indicative of results to be expected for the full year.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity. During the six months ended June 30, 2003, net cash of
$3,330,505 was provided by operating activities before working capital
adjustments, and net cash of $776,811 was used in operating activities after
accounting for changes in assets and liabilities for the period, including a
reduction of $4,281,184 in customers' drilling deposits under turnkey drilling
contracts with sponsored Drilling Programs. Our cash position during the first
six months of 2003 was increased by $4,839,184 provided by financing activities,
consisting primarily of proceeds from the issuance of our common shares and
convertible notes. See "Recent Developments - Equity Infusion" and "- Conversion
of Notes and Preferred Stock" above. The increase in our cash position from
financing activities during the first half of 2003 was partially offset by the
use of $3,085,604 of net cash in investing activities. Funds used in investing
activities were comprised primarily of $2,613,421 in net additions to our oil
and gas properties and $475,428 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 $7,450,076 as of June 30, 2003.
As of June 30, 2003, we had working capital of $3,230,928, 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.
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 half 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.
20
The means for developing our properties were also significantly enhanced by our
Drilling Program financings in the fourth quarter of 2002 and July 2003, with
contributed capital aggregating $15,525,000 from outside investors. Our 25%
contributions to these programs aggregated $5,175,000. 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 five separate series of convertible notes since 1999 in the aggregate
principal amount of $4,506,125, including $3,236,125 principal amount of
convertible notes issued in the first six months of 2003. The notes bear
interest payable semi-annually 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 $2.71 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 $1,260,000 by several holders in the first six months of 2003,
convertible notes in the aggregate principal amount of $3,246,125 were
outstanding at June 30, 2003. See "Recent Developments - Convertible Notes and
Preferred Stock" above.
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 June 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 June 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 $2,247,984
at December 31, 2002. During the first half of 2002, we repaid $2,000,000 of the
outstanding credit facility principal, reducing our borrowings under the
facility to $247,984 at June 30, 2003.
Our remaining long term debt outstanding at June 30, 2003, including
the current portions, aggregated $424,818 on a secured note issued in 1986 for
the acquisition of our mineral property in Alaska and $193,333 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 do not expect our cash flow from operations or borrowings under our
credit facility to provide adequate working capital to meet our capital
expenditure objectives beyond 2003. 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.
21
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 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.
22
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On June 26, 2003, we held our annual meeting of shareholders. All of
the incumbent directors listed in our proxy statement for the meeting were
reelected. The number of votes cast for and against each nominee is set forth
below.
VOTES
NOMINEE VOTES FOR WITHHELD
------- --------- --------
William S. Daugherty............... 3,738,286 18,068
James K. Klyman.................... 3,738,557 17,797
Charles L. Cotterell............... 3,738,569 17,785
Our shareholders also voted at the meeting to approve a proposal fixing
the size of our board at three members and to ratify our board's appointment of
Kraft, Berger, Grill, Schwartz, Cohen & March LLP as our independent public
accountants for the year ending December 31, 2003. The number of votes cast for
and against each of these proposals is set forth below.
VOTES VOTES
PROPOSAL VOTES FOR AGAINST WITHHELD
-------- --------- ------- --------
To fix the size of the board of
directors at three members....... 3,615,864 75,835 54,555
To ratify the appointment of
independent public accountants... 3,741,661 12,101 2,692
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
23
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).
21.1 Subsidiaries of Daugherty Resources: Sentra Corporation, a
Kentucky corporation, and Daugherty Petroleum, Inc., a
Kentucky corporation.
31.1 Certification of Chief Executive Officer Pursuant to Rules
13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934,
as amended.
31.2 Certification of Chief Financial Officer Pursuant to Rules
13a-14(a)/15d-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 June 13, 2003 regarding
completion of the transactions contemplated by a Securities
Purchase Agreement dated as of June 10, 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: August 11, 2003 By: /s/ William S. Daugherty
--------------------------------------
William S. Daugherty
Chief Executive Officer
(Duly Authorized Officer)
(Principal Executive Officer)
24