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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 JUNE 30, 2004
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF EXCHANGE ACT
COMMISSION FILE NO. 0-12185
NGAS RESOURCES, INC.
(FORMERLY 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 JULY 30, 2004
COMMON STOCK 14,599,053
Transitional Small Business Disclosure Format. Yes [ ] No [X]
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NGAS RESOURCES, INC.
(FORMERLY DAUGHERTY RESOURCES, INC.)
INDEX
PART I. FINANCIAL INFORMATION PAGE
----
ITEM 1. FINANCIAL STATEMENTS:
Review Engagement Report.................................................................................... 2
Condensed Consolidated Balance Sheets - June 30, 2004 (unaudited) and December 31, 2003..................... 3
Condensed Consolidated Statement of Operations and Deficit - Three months and six months ended
June 30, 2004 and 2003 (unaudited)....................................................................... 4
Condensed Consolidated Statement of Cash Flows - Three months and six months ended
June 30, 2004 and 2003 (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............................................................................ 24
PART II. OTHER INFORMATION................................................................................. 25
1
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
REVIEW ENGAGEMENT REPORT
To the Directors of NGAS RESOURCES, INC.
We have reviewed the condensed consolidated balance sheet of NGAS RESOURCES,
INC. (formerly Daugherty Resources, Inc.) as at June 30, 2004 and the condensed
consolidated statements of operations and deficit and cash flows for the three
months 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 and the United States of America, the consolidated balance
sheet as at December 31, 2003 and the related consolidated statements of
operations and deficit and cash flows for the year then ended (not presented
herein) and, in our report dated March 16, 2004, 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, 2003 is fairly
stated in all material respects in relation to the consolidated 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 9, 2004
2
NGAS RESOURCES, INC.
(FORMERLY DAUGHERTY RESOURCES, INC.)
CONDENSED CONSOLIDATED BALANCE SHEETS
(U.S. FUNDS)
JUNE 30, DECEMBER 31,
2004 2003
------------- --------------
ASSETS (UNAUDITED)
Current assets:
Cash.............................................................. $ 22,514,081 $ 22,594,993
Subscriptions receivable.......................................... -- 2,335,009
Accounts receivable............................................... 935,446 503,177
Prepaid expenses and other current assets......................... 996,091 773,415
Loans to related parties (Note 4)................................. 165,822 140,780
------------- --------------
Total current assets............................................ 24,611,440 26,347,374
Bonds and deposits.................................................. 124,400 99,000
Oil and gas properties (Note 2)..................................... 24,731,425 16,369,859
Property and equipment (Note 3)..................................... 1,957,617 2,054,088
Loans to related parties (Note 4)................................... 416,244 517,940
Investments (Note 5)................................................ 119,081 119,081
Deferred financing costs (Note 6)................................... 100,737 247,923
Goodwill (Note 7)................................................... 313,177 313,177
------------- --------------
Total assets.................................................. $ 52,374,121 $ 46,068,442
============= ==============
LIABILITIES
Current liabilities:
Accounts payable.................................................. 2,479,376 1,445,603
Accrued liabilities............................................... 2,910,327 2,865,045
Income taxes payable.............................................. 188,756 144,450
Customers' drilling deposits...................................... 6,152,600 10,162,600
Long term debt, current portion (Note 8).......................... 391,516 397,722
------------- --------------
Total current liabilities....................................... 12,122,575 15,015,420
Future income taxes................................................. 654,418 257,647
Long term debt (Note 8)............................................. 3,011,944 4,739,387
Deferred compensation............................................... 124,564 --
------------- --------------
Total liabilities............................................. 15,913,501 20,012,454
------------- --------------
SHAREHOLDERS' EQUITY
Capital stock (Note 9)
Authorized:
5,000,000 Preferred shares, non-cumulative, convertible
100,000,000 Common shares
Issued:
14,446,033 Common shares (December 31, 2003 - 10,676,030)....... 51,453,007 36,244,623
21,100 Common shares held in treasury, at cost.............. (23,630) (23,630)
Paid-in capital - options and warrants............... 1,228,553 1,140,321
To be issued:
10,070 Common shares (December 31, 2003 - 1,403,335)........ 50,350 5,917,958
------------- --------------
52,708,280 43,279,272
Deficit............................................................. (16,247,660) (17,223,284)
------------- --------------
Total shareholders' equity.................................... 36,460,620 26,055,988
------------- --------------
Total liabilities and shareholders' equity.................. $ 52,374,121 $ 46,068,442
============= ==============
See Notes to Condensed Consolidated Financial Statements.
3
NGAS RESOURCES, INC.
(FORMERLY DAUGHERTY RESOURCES, INC.)
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT
(U.S. FUNDS)
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------- --------
2004 2003 2004 2003
---- ---- ---- ----
REVENUE
Contract drilling.......................... $ 7,040,250 $ 3,025,000 $ 21,366,375 $ 11,058,000
Oil and gas production..................... 986,724 537,286 1,778,013 1,066,290
Gas transmission and compression........... 300,195 289,183 748,663 558,034
------------- -------------- ------------- --------------
Total revenue............................ 8,327,169 3,851,469 23,893,051 12,682,324
------------- -------------- ------------- --------------
DIRECT EXPENSES
Contract drilling.......................... 5,236,941 1,283,184 15,341,589 4,678,349
Oil and gas production..................... 392,379 104,930 670,087 420,944
Gas transmission and compression........... 114,326 146,573 514,192 254,762
------------- -------------- ------------- --------------
Total direct expenses.................... 5,743,646 1,534,687 16,525,868 5,354,055
------------- -------------- ------------- --------------
GROSS PROFIT.................................. 2,583,523 2,316,782 7,367,183 7,328,269
------------- -------------- ------------- --------------
OTHER INCOME (EXPENSES)
Selling, general and administrative........ (1,744,546) (1,505,514) (4,930,064) (4,197,729)
Compensation cost.......................... (202,972) (589,200) (233,046) (742,800)
Depreciation, depletion and amortization... (255,475) (194,080) (508,604) (373,160)
Interest expense........................... (107,535) (122,180) (196,703) (204,633)
Interest income............................ 81,344 28,707 168,206 57,535
Other, net................................. 104,483 (4,397) 112,229 (8,152)
------------- -------------- ------------- --------------
Total other income (expenses)............ (2,124,701) (2,386,664) (5,587,982) (5,468,939)
------------- -------------- ------------- --------------
INCOME (LOSS) BEFORE INCOME TAXES............. 458,822 (69,882) 1,779,201 1,859,330
------------- -------------- ------------- --------------
INCOME TAX EXPENSE
Current.................................... 38,743 26,555 149,159 275,369
Future..................................... 211,696 -- 654,418 489,545
Benefit realized on loss carried forward... -- (26,555) -- (764,914)
------------- -------------- ------------- --------------
250,439 -- 803,577 --
------------- -------------- ------------- --------------
NET INCOME (LOSS)............................. 208,383 (69,882) 975,624 1,859,330
DEFICIT, beginning of period.................. (16,456,043) (18,954,212) (17,223,284) (20,883,424)
------------- -------------- ------------- --------------
DEFICIT, end of period........................ $ (16,247,660) $ (19,024,094) $ (16,247,660) $ (19,024,094)
============= ============== ============= ==============
NET INCOME (LOSS) PER SHARE
Basic...................................... $ 0.02 $ (0.01) $ 0.08 $ 0.30
======== ======= ======== =======
Diluted.................................... $ 0.01 $ (0.01) $ 0.06 $ 0.20
======== ======= ======== =======
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING:
Basic...................................... 13,877,212 6,632,620 12,964,698 6,249,688
============= ============== ============= ==============
Diluted.................................... 16,706,462 6,632,620 16,005,368 9,523,329
============= ============== ============= ==============
See Notes to Condensed Consolidated Financial Statements.
4
NGAS RESOURCES, INC.
(FORMERLY DAUGHERTY RESOURCES, INC.)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(U.S. FUNDS)
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------- --------
2004 2003 2004 2003
---- ---- ---- ----
OPERATING ACTIVITIES
Net income (loss) $ 208,383 $ (69,882) 975,624 $ 1,859,330
Adjustments to reconcile net income (loss)
to net cash used in operating activities:
Incentive bonus paid in common shares -- 115,290 -- 351,420
Compensation cost 202,972 589,200 233,046 742,800
Depreciation, depletion and amortization 255,475 194,080 508,604 373,160
Notes issued in kind for interest on long
term debt 18,157 -- 55,359 --
Loss (gain) on sale of assets (348) -- (4,948) 3,795
Future income taxes (45,951) -- 396,771 --
Changes in assets and liabilities
Subscriptions receivable -- -- 2,335,009 --
Accounts receivable (176,398) (97,848) (432,269) (78,900)
Prepaid expenses and other assets (183,389) (146,891) (222,676) 90,235
Accounts payable 368,697 (81,684) 1,180,369 205,813
Accrued liabilities (766,269) (562,983) 45,282 627,036
Income taxes payable 3,890 -- 44,306 --
Customers' drilling deposits 3,165,000 953,500 (4,010,000) (4,951,500)
------------ ------------ ------------ ------------
Net cash provided by (used in) operating activities 3,050,219 892,782 1,104,477 (776,811)
------------ ------------ ------------ ------------
INVESTING ACTIVITIES
Proceeds from sale of assets 186,000 -- 190,600 3,245
Purchase of property and equipment (107,084) (99,622) (222,230) (475,428)
Bonds and deposits (25,400) (25,400)
Additions to oil and gas properties, net (2,452,882) (1,056,487) (8,719,016) (2,613,421)
------------ ------------ ------------ ------------
Net cash used in investing activities (2,399,366) (1,156,109) (8,776,046) (3,085,604)
------------ ------------ ------------ ------------
FINANCING ACTIVITIES
Decrease in loans to related parties 41,455 30,714 76,654 52,579
Proceeds from issuance of common shares 6,456,732 2,926,696 7,560,040 3,075,884
Proceeds from issuance of long term debt -- 2,170,625 -- 3,236,125
Payments of long term debt (23,167) (2,030,057) (46,037) (2,083,404)
------------ ------------ ------------ ------------
Net cash provided by financing activities 6,475,020 3,097,978 7,590,657 4,281,184
------------ ------------ ------------ ------------
Change in cash 7,125,873 2,834,651 (80,912) 418,769
Cash, beginning of period 15,388,208 4,615,425 22,594,993 7,031,307
------------ ------------ ------------ ------------
Cash, end of period $ 22,514,081 $ 7,450,076 $ 22,514,081 $ 7,450,076
============ ============ ============ ============
SUPPLEMENTAL DISCLOSURE
Interest paid $ 98,030 $ 68,364 $ 141,344 $ 172,942
Income taxes paid 34,853 -- 104,853 --
SUPPLEMENTAL SCHEDULE OF NONCASH
INVESTING AND FINANCING ACTIVITIES
Common shares issued for accounts payable 146,596 50,000 -- 164,126
Common shares issued upon conversion of notes 156,250 1,260,000 1,613,890 1,260,000
See Notes to Condensed Consolidated Financial Statements.
5
NGAS RESOURCES, INC.
(FORMERLY DAUGHERTY RESOURCES, INC.)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2004 - (UNAUDITED)
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) General. The accompanying unaudited condensed consolidated financial
statements of NGAS Resources, Inc., a British Columbia corporation formerly
named Daugherty Resources, Inc. (the "Company"), have been prepared in
accordance with generally accepted accounting principles in Canada and 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, 2004 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, 2003. The Company changed its corporate name from Daugherty
Resources, Inc. to NGAS Resources, Inc. in June 2004.
(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 25
drilling programs that it has sponsored and managed since 1996 to conduct
drilling operations on its prospects (the "Drilling Programs"). DPI maintains
combined interests as both general partner and an investor in the Drilling
Programs ranging between 25.75% and 66.67%. 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 periods.
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) Change in Accounting Policy. Effective January 1, 2004, the Company
adopted the fair value provisions of Canadian Institute of Chartered Accountants
("CICA") Handbook Section 3870, "Stock-Based Compensation and Other Stock-Based
Payments" and related interpretations for the recognition and measurement of
compensation costs associated with employee stock options. See Note 9 - Capital
Stock.
(e) Reclassification. Certain amounts reported in the condensed
consolidated financial statements for interim period in 2003 have been
reclassified to conform with the presentation in the current period.
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.
6
JUNE 30, 2004 DECEMBER 31,
------------------------------------------------- 2003
ACCUMULATED --------------
COST DD&A NET NET
-------------- ------------- ------------- --------------
Proved oil and gas properties......... $ 23,878,030 $ (2,737,531) $ 21,140,499 $ 14,053,881
Unproved oil and gas properties....... 872,879 -- 872,879 657,879
Wells and related equipment........... 2,998,793 (280,746) 2,718,047 1,658,099
-------------- ------------- ------------- --------------
Total oil and gas properties.......... $ 27,749,702 $ (3,018,277) $ 24,731,425 $ 16,369,859
============== ============= ============= ==============
NOTE 3. PROPERTY AND EQUIPMENT
The following table presents the capitalized costs and accumulated
depreciation for the Company's property and equipment as of June 30, 2004.
JUNE 30, 2004 DECEMBER 31,
----------------------------------------------- 2003
ACCUMULATED -----------
COST DEPRECIATION NET NET
----------- ------------- ----------- -----------
Land................................. $ 12,908 $ -- $ 12,908 $ 12,908
Building improvements................ 20,609 (3,702) 16,907 17,547
Machinery and equipment.............. 1,186,518 (286,074) 900,444 857,726
Office furniture and fixtures........ 48,980 (19,348) 29,632 26,220
Computer and office equipment........ 350,444 (111,339) 239,105 206,748
Vehicles and aircraft................ 995,600 (236,979) 758,621 932,939
----------- ----------- ----------- -----------
Total property and equipment......... $ 2,615,059 $ (657,442) $ 1,957,617 $ 2,054,088
=========== =========== =========== ===========
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 $410,637 at June 30,
2004 and $487,291 at December 31, 2003. These loans bear interest at 6% per
annum and are collateralized by ownership interests in Drilling Programs. The
loans receivable from officers totaled $171,429 at June 30, 2004 and December
31, 2003. These loans are non-interest bearing and unsecured.
NOTE 5. INVESTMENTS
The Company has investments 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, 2004 and December 31, 2003, the estimated market value of the bonds was
$36,970. See Note 13 - United States Accounting Principles.
NOTE 6. DEFERRED FINANCING COSTS
The Company incurred financing costs of $601,886 during 2003 in connection
with the issuance of $5,000,000 principal amount of its 7% convertible notes due
September 5, 2008. These costs were initially capitalized and were expected to
be amortized ratably over the life of the notes. During the fourth quarter of
2003, $2,800,000 principal amount of the notes were converted into common shares
and added to equity, net of $318,087, representing a proportionate amount of the
original financing costs. Additional notes in the principal amount of
7
$1,301,721 were converted into common shares in the first six months of 2004 and
added to equity, net of proportionate financing costs of $129,081. Accumulated
amortization for the remaining financing costs aggregated $53,981 at June 30,
2004. See Note 9 - Capital Stock.
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 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 June 30, 2004
and December 31, 2003.
NOTE 8. 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, 2004, 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, 2004. 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 June 30, 2004 and
December 31, 2003.
(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 AT
------------------------------- JUNE 30, 2004
JUNE 30, DECEMBER 31, CONVERSION UPON
TITLE OF NOTES 2004 2003 PRICE CONVERSION
- -------------- ---- ---- ----- ----------
10% Convertible Notes
due May 1, 2007 $ 560,500 $ 740,500 $1.50 373,666
8% Convertible Notes
due April 10, 2008 770,625 770,625 1.90 405,592
8% Convertible Notes
due May 1, 2008 238,750 500,000 2.25 106,111
7% Convertible Notes
due September 5, 2008 1,058,525 2,304,888 4.50 235,227
---------- ---------- ---------
Total $2,628,400 $4,316,013 1,120,596
========== ========== =========
The Company's 7% Convertible Notes due September 5, 2008 listed above were
originally issued during September 2003 in the aggregate principal amount of
$5,000,000 (the "Institutional Notes"). 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
$160,247 were issued as of June 30, 2004.
(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.
8
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
$402,818 at June 30, 2004 and $414,818 at December 31, 2003.
(d) Miscellaneous Debt. The following table summarizes the Company's other
outstanding debt obligations at June 30, 2004 and December 31, 2003.
PRINCIPAL AMOUNT OUTSTANDING AT
-------------------------------
JUNE 30, DECEMBER 31,
TERMS OF DEBT 2004 2003
- ------------- ---- ----
Notes issued to finance equipment and vehicles, payable
monthly in various amounts through 2005, with interest
ranging from 8.68% to 9.5% per annum, collateralized by
the acquired equipment and vehicles......................... $ 8,173 $ 23,451
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 2005..................................... 12,834 20,397
Loans payable to various banks, payable monthly in
various amounts, together with interest at rates ranging
from 4% to 9.75% per annum, through 2005,
collateralized by receivables and various vehicles.......... 34,410 45,605
--------- ---------
Total.......................................................... $ 120,196 $ 154,232
========= =========
(e) Total Long Term Debt. The following table sets forth the Company's
total long term debt and current portion at June 30, 2004 and December 31, 2003.
PRINCIPAL AMOUNT OUTSTANDING AT
-------------------------------
JUNE 30, DECEMBER 31,
2004 2003
---- ----
Total long term debt (including current portion) $3,403,460 $5,137,109
Less current portion ........................... 391,516 397,722
---------- ----------
Total long term debt ........................... $3,011,944 $4,739,387
========== ==========
NOTE 9. CAPITAL STOCK
(a) Preferred and Common Shares. The Company has 5,000,000 authorized
shares of preferred stock, none of which were outstanding at June 30, 2004 or
December 31, 2003. The following table reflects transactions involving the
Company's common stock during the reported periods.
9
NUMBER OF
COMMON SHARES ISSUED SHARES AMOUNT
- -------------------- ------ ------
Balance, December 31, 2002 .......................... 5,505,670 $24,589,797
Issued for cash .................................. 950,000 2,460,450
Issued to employees as incentive bonus ........... 360,500 364,680
Issued upon exercise of stock options and warrants 1,018,131 1,904,164
Issued upon conversion of preferred shares ....... 625,448 1,784,493
Issued upon conversion of convertible notes ...... 2,069,393 4,976,913
Issued for settlement of accounts payable ........ 146,888 164,126
----------- -----------
Balance, December 31, 2003 .......................... 10,676,030 36,244,623
Issued for cash .................................. 2,278,335 10,815,637
Issued upon exercise of stock options and warrants 842,802 2,200,391
Issued upon conversion of convertible notes ...... 525,379 1,613,890
Issued for settlement of accounts payable ........ 37,113 146,596
Issued for contract settlement ................... 86,374 431,870
----------- -----------
Balance, June 30, 2004 .............................. 14,446,033 $51,453,007
=========== ===========
COMMON SHARES TO BE ISSUED
Balance at June 30, 2004 ............................ 10,070 $ 50,350
=========== ===========
PAID IN CAPITAL - OPTIONS AND WARRANTS
Balance, December 31, 2002............................................. $ 763,635
Issued.............................................................. 376,686
-----------
Balance, December 31, 2003............................................. 1,140,321
Issued.............................................................. 108,482
Exercised........................................................... (20,250)
-----------
Balance, June 30, 2004................................................. $ 1,228,553
===========
During 2003, the Company completed two institutional private placements of
its common stock, issuing 900,000 shares at $2.85 per share for $2,565,000 in
June 2003 and an additional 1,303,335 shares at $4.50 per share for $5,865,000
at year end. A portion of the proceeds from the second equity financing were
received immediately after year end, resulting in all of the subscribed shares
being classified as common shares to be issued at December 31, 2003. All of the
shares were issued in the first week of January 2004 upon receipt of the
subscription proceeds.
In April 2004, the Company completed an institutional private placement of
975,000 common shares at $5.98 per share for $5,832,450. Proceeds from the April
2004 private placement and the 2003 equity financings were allocated primarily
to construction of new gathering systems and investments in sponsored Drilling
Programs.
(b) Stock Options. 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.
During 2003, the Company adopted a new incentive stock award and stock
option plan. The plan authorized the compensation committee of the Company's
board of directors to grant stock awards and stock options for an aggregate of
up to 4,000,000 common shares to its officers, directors and consultants. The
plan was approved by shareholders at the Company's annual meeting in June 2004.
10
The exercise prices of options outstanding at June 30, 2004 range from
$1.00 to $4.03 per share, and their weighted average remaining contractual life
is 3.72 years. The following table reflects transactions involving the Company's
stock options during 2003 and the first six months of 2004.
WEIGHTED AVERAGE
STOCK OPTIONS ISSUED EXERCISABLE EXERCISE PRICE
- ------------- ------ ----------- --------------
Balance, December 31, 2002..................... 1,585,210 1,585,210 1.30
---------
Issued(1)................................... 400,000 1.02
Exercised................................... (820,879) 1.17
Expired..................................... (45,000) 5.00
----------- --------
Balance, December 31, 2003..................... 1,119,331 1,119,331 1.10
---------
Issued(2)................................... 1,385,000 4.03
Exercised................................... (157,791) 1.00
Expired..................................... (25,000) 5.00
----------- --------
Balance, June 30, 2004......................... 2,321,540 936,540 $ 2.81
=========== ========= ========
- ------------------
(1) Granted to employees under stock option plans, exercisable through January
2, 2008 at an exercise price of $1.02 per share.
(2) Granted to employees and directors under stock option plans, exercisable
at $4.03 per share and vesting in increments under specified conditions.
In accounting for stock options, the Company follows the retroactive
method under CICA Handbook Section 3870. See Note 1 - Summary of Significant
Accounting Policies. For fiscal years beginning before December 15, 2003, the
statement permits compensation costs for stock options to be measured by the
intrinsic value method of accounting similar to the method prescribed by APB
Opinion No. 25, "Accounting for Stock Issued to Employees," with pro forma
disclosure of net income and earnings per share as if the fair value accounting
method had been applied. For fiscal years beginning after December 15, 2003, the
statement requires the fair value method of accounting for stock options,
consistent with the recognition and measurement provisions of SFAS Nos. 123 and
148, "Accounting for Stock-Based Compensation," with retroactive restatement of
prior periods to reflect fair value accounting. For the six months ended June
30, 2004, this resulted in the recognition of $108,482 for compensation cost of
options and warrants.
Under the fair value method, employee stock options are valued at grant
date using the Black-Scholes valuation model, and the compensation cost is
recognized ratably over the vesting period. For the three months ended June 30,
2004 and 2003 and the six months ended June 30, 2003, the fair value estimates
for each option grant assumed a risk free interest rate of 4.5%, a dividend
yield of 0%, a theoretical volatility of 0.30 and an expected life ranging from
one to five years based on the option's vesting provisions. There were no
options granted during the three months ended June 30, 2004. Adoption of fair
value accounting for stock options to replace the intrinsic value method
previously followed by the Company resulted in the restatement of net income
(loss) and income (loss) per share for the six months ended June 30, 2003 as
reflected in the table below, with related adjustments to the deficit as
previously reported since 1995.
INTRINSIC FAIR
VALUE VALUE
METHOD METHOD
----------- ------------
(PREVIOUSLY (RESTATED)
REPORTED)
SIX MONTHS ENDED JUNE 30, 2003
Net income......................................... $ 2,012,930 $ 1,859,330
Net earnings per share
Basic............................................ 0.32 0.30
Fully diluted.................................... 0.22 0.20
Weighted average fair value of options granted..... 0.38 0.38
AS OF DECEMBER 31, 2003
Deficit............................................ 16,306,049 17,223,284
11
(c) Common Stock Purchase Warrants. The Company has issued common stock
purchase warrants in various financing transactions. The exercise prices of
warrants outstanding at June 30, 2004 range from $1.03 to $6.25 per share, and
their weighted average remaining contractual life is 1.52 years. The following
table reflects transactions involving the Company's common stock purchase
warrants during 2003 and the first six months of 2004.
WEIGHTED AVERAGE
COMMON STOCK PURCHASE WARRANTS ISSUED EXERCISABLE EXERCISE PRICE
- ------------------------------ ------ ----------- --------------
Balance, December 31, 2002..................... 2,559,901 2,559,901 2.76
---------
Issued in financing transactions(1)......... 916,453 5.12
Issued for consulting services(2)........... 175,000 1.55
Exercised................................... (317,831) 2.40
----------- ------
Balance, December 31, 2003..................... 3,333,523 3,333,523 3.43
----------
Issued in financing transactions(3)......... 330,525 6.25
Exercised................................... (685,011) 2.95
----------- ------
Balance, June 30, 2004......................... 2,979,037 2,979,037 $ 3.82
=========== ========== ======
- ------------------
(1) Expiring from June 13, 2006 through December 31, 2008.
(2) Expiring from April 3, 2004 through April 2, 2008.
(3) Expiring from April 29, 2007 through April 29, 2009.
NOTE 10. INCOME PER SHARE
The Company follows CICA Handbook Section 3500, "Earnings per Share." The
statement requires the presentation of both basic and diluted earnings 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 six months ended June 30, 2004, the assumed exercise of outstanding stock
options and warrants and conversion of outstanding convertible notes would have
a dilutive effect on EPS because their exercise or conversion prices for some of
these instruments were below the average market price of the common stock during
the period. For the six months ended June 30, 2003, the assumed conversion of
preferred stock would also have a dilutive effect on EPS. Because the Company
recognized a net loss for the three months ended June 30, 2003, the assumed
exercise or conversion of these instruments would have been anti-dilutive in
that period. The following table sets forth the computation of diluted EPS for
the reported periods.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------- --------
DILUTED EPS 2004 2003 2004 2003
---- ---- ---- ----
Numerator:
Net income (loss) as reported for basic EPS.. $ 208,383 $ (69,882) $ 975,624 $ 1,859,330
Adjustments to income for diluted EPS........ 18,496 -- 46,943 65,959
------------- -------------- ------------- --------------
Net income (loss) for diluted EPS......... $ 226,879 $ (69,882) $ 1,022,567 $ 1,925,289
============= ============== ============= ==============
Denominator:
Weighted average shares for basic EPS........ 13,877,212 6,632,620 12,964,698 6,249,688
Effect of dilutive securities:
Stock options............................. 1,107,069 -- 1,096,844 943,262
Warrants.................................. 940,813 -- 982,953 296,185
Convertible notes......................... 781,368 -- 960,873 1,780,678
Convertible preferred shares.............. -- -- -- 253,516
------------- -------------- ------------- --------------
Adjusted weighted average shares and
assumed conversions for dilutive EPS...... 16,706,462 6,632,620 16,005,368 9,523,329
============= ============== ============= ==============
Diluted EPS.................................. $0.01 $(0.01) $0.06 $0.20
===== ====== ===== =====
12
NOTE 11. 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) 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 maintains a 1% interest as
general partner in each Drilling Program, resulting in a combined interest of at
least 25.75% in each Drilling Program organized as a limited partnership and up
to 66.67% in each Drilling Program organized as a joint venture. The agreements
for both the limited partnership and joint venture Drilling Programs generally
provide for specified increases in DPI's program interests, up to 15% of the
total program interests, after program distributions reach "payout," which
ranges from 100% to 110% of partners' investment. 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
the 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, 2004.......... $ 7,040,250
Three months ended June 30, 2003.......... 3,025,000
Six months ended June 30, 2004............ 21,366,375
Six months ended June 30, 2003............ 11,058,000
NOTE 12. 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,
-------- --------
2004 2003 2004 2003
---- ---- ---- ----
REVENUE, NET:
Oil and gas development ... $ 8,327,169 $ 3,851,469 $ 23,893,051 12,682,324
Corporate ................. -- -- -- --
------------ ------------ ------------ ------------
Total .................. 8,327,169 3,851,469 23,893,051 12,682,324
------------ ------------ ------------ ------------
DD&A:
Oil and gas development ... 227,150 174,800 446,150 336,267
Corporate ................. 28,325 19,280 62,454 36,893
------------ ------------ ------------ ------------
Total .................. 255,475 194,080 508,604 373,160
------------ ------------ ------------ ------------
INTEREST EXPENSE:
Oil and gas development ... 54,513 73,133 67,803 110,991
Corporate ................. 53,022 49,047 128,900 93,642
------------ ------------ ------------ ------------
Total .................. 107,535 122,180 196,703 204,633
------------ ------------ ------------ ------------
NET INCOME (LOSS):
Oil and gas development ... 485,099 414,801 1,477,295 3,010,193
Corporate ................. (276,716) (484,683) (501,671) (1,150,863)
------------ ------------ ------------ ------------
Total .................. 208,383 (69,882) 975,624 1,859,330
------------ ------------ ------------ ------------
CAPITAL EXPENDITURES:
Oil and gas development ... 2,524,271 1,122,902 8,867,169 2,930,373
Corporate ................. 35,695 33,207 74,077 158,476
------------ ------------ ------------ ------------
Total .................. $ 2,559,966 $ 1,156,109 8,941,246 3,088,849
============ ============ ------------ ============
13
JUNE 30, DECEMBER 31,
2004 2003
---- ----
IDENTIFIABLE ASSETS:
Oil and gas development ... $31,144,252 $29,702,445
Corporate ................. 21,229,869 16,365,997
----------- -----------
Total .................. $52,374,121 $46,068,442
=========== ===========
NOTE 13. UNITED STATES ACCOUNTING PRINCIPLES
(a) Differences Reflected in Consolidated Financial Statements. The
Company follows accounting principles generally accepted in Canada ("Canadian
GAAP"), which are different in some respects than accounting principles
generally accepted in the United States of America ("U.S. GAAP"). The only
differences that affect the Company's consolidated financial statements for the
reported periods involve the adoption of fair value accounting for stock options
described in Note 9, which would not be required until 2005 under U.S. GAAP, and
the accounting treatment of the Company's investment in municipal bonds
described in Note 5. Under Canadian GAAP, the decline in value of the Company's
long-term investment in these bonds is not being written-down to their estimated
realizable value. Under U.S. GAAP, this investment would be classified as
available-for-sale in accordance with SFAS No. 115 and would be reported at fair
value, with unrealized gains and losses excluded from earnings and reported in a
separate component of shareholders' equity, as other comprehensive income. For
the three months and six months ended June 30, 2004 and 2003, there were no
changes in bond values. Therefore, other comprehensive income under U.S. GAAP
was the same as net income under Canadian GAAP for the periods presented.
(b) Recent Accounting Pronouncements. Recent accounting pronouncements
followed by the Company under U.S. GAAP are summarized below.
(i) 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. Effective January 1,
2004, the Company adopted the statement to account for its employee stock
options under the fair market value method. See Note 9 - Capital Stock.
(ii) Financial Accounting Standards Board Interpretation ("FIN") No.
45. FIN No. 45, issued in November 2002, expands previously issued accounting
guidance and disclosure requirements for certain guarantees. It requires
companies to recognize an initial liability for the fair value of an obligation
assumed by issuing a guarantee. The provision for initial recognition and
measurement of the liability will be applied on a prospective basis to
guarantees issued or modified after December 31, 2002. The adoption of FIN No.
45 is not expected to have a material impact on the Company's condensed
consolidated financial statements.
(iii) 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
condensed consolidated financial statements.
(iv) 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 condensed consolidated financial statements.
14
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
NGAS Resources, Inc. (the "Company") is an independent energy and natural
resources company focused on natural gas development and production in the
Appalachian Basin, primarily in eastern Kentucky. Through our wholly owned
subsidiary, Daugherty Petroleum, Inc. ("DPI"), and DPI's interests in sponsored
drilling partnerships (the "Drilling Programs"), we actively acquire and develop
natural gas interests in our core operating areas. DPI also constructs and
maintains gas gathering systems for our wells, 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.
Our principal and administrative offices are located at 120 Prosperous Place,
Suite 201, Lexington, Kentucky 40509, near our core operating areas. Our common
stock is traded on the Nasdaq SmallCap Market under the symbol "NGAS," and we
maintain a website with information about us at www.ngas.com.
We commenced oil and gas operations in 1993 with the acquisition of DPI
and have sponsored 25 separate Drilling Programs through the date of this
report. In June 2004, we changed our corporate name from Daugherty Resources,
Inc. to NGAS Resources, Inc. The name change was implemented to reflect our
focus on natural gas development and production and to reinforce our association
with the NGAS acronym from its use as the Nasdaq trading symbol for our common
stock and the Internet address of our website. We have adopted the NGAS acronym
throughout our organization, with a view to building a consistent and
recognizable corporate identity. Unless otherwise indicated, references in this
report to "we," "our" or "us" include the Company as well as DPI and its
interests in the Drilling Programs and Sentra.
STRATEGY
We have structured our business to achieve capital appreciation through
growth in our natural gas reserves, production, cash flow and earnings per
share. Our strategy for continuing to realize our operational and financial
objectives emphasizes several components. Each is aimed at positioning us to
capitalize on natural gas development opportunities in our core operating areas
and long range pricing expectations for this commodity.
- Acceleration of Drilling Operations. Historically, we have relied almost
exclusively on development drilling for production and reserve growth,
concentrating on geographic areas of the Appalachian Basin where we have
established expertise and little competition from major independent energy
companies. To help finance our drilling initiatives, we sponsor and manage
Drilling Programs for private investors, historically contributing up to
30% of total program capital raised by each limited partnership Drilling
Program and up to 66.67% of joint venture Drilling Program capital. Since
1999, we drilled 245 natural gas wells though our Drilling Programs
without a dry hole, including 89 gross (26.7680 net) wells in 2003 and 78
gross (27.5691 net) wells in the first half of 2004. We are sponsoring
Drilling Programs for up to 140 new wells in 2004 and are increasing our
ownership interest in these new programs to 30.7%.
- Acquisition of Additional Drilling Prospects. As coal reserves are
exhausted in the Appalachian Basin, the lapse or relinquishment of the
coal companies' competing mineral claims has opened a window of
opportunity for extending our acreage position in the region to properties
with significant unproved gas development potential as well as established
infrastructure. Over the last several years, we have capitalized on these
opportunities, acquiring 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 Field"), as well as and gas leases and farmouts
covering 22,500 acres on the north side of the Pine Mountain Fault System
near the Leatherwood Field (the "Straight Creek Field"). We plan to
continue assembling former coal producing acreage for exploratory
prospects relatively close to fields with gas production histories and
pipelines. By conducting initial drilling operations on these higher risk
prospects through specially tailored joint venture Drilling Programs and
retaining majority ownership interests, we are expanding our inventory of
development locations with lower risk profiles for subsequent Drilling
Programs, while adding to our proved reserves, both developed and
undeveloped.
15
- Extension of Gas Gathering Systems. We construct and operate gas gathering
facilities to provide compression, connection and local distribution
capabilities for most of our wells. In addition to the revenues we
generate from gas transmission and compression, our 100% ownership of
these systems gives us access to major new natural gas markets and
competitive advantages in acquiring drilling rights on nearby acreage. As
of December 31, 2003, our gas gathering facilities aggregated
approximately 112 miles in our core operating areas, with connections to a
total of 292 natural gas wells. In the first half of 2004, we extended our
gathering systems by an additional 24 miles, including a four-mile,
eight-inch steel gathering line that connects our Straight Creek wells to
a major pipeline in southeastern Kentucky and eastern Tennessee owned by
Duke Energy Gas Services Corporation. We also began work on an 18-mile
extension of that system to connect our new wells in the Leatherwood
Field.
- Disciplined Drilling for Predictable Results. Most of our natural gas
wells are drilled to relatively shallow total depths from 2,600 to 4,800
feet, generally encountering five distinct and predictable pay zones. This
disciplined approach helps reduce drilling risks, as reflected in our 100%
success rate since 1999. We complete and produce our wells from multiple
pay zones whenever possible, eliminating the costs and complexities of
deferred completions with behind-pipe gas. As of June 30, 2004, we
operated a total of 415 natural gas wells, primarily in the Appalachian
Basin. While our wells typically produce at modest initial volumes and
pressures, they also demonstrate low annual decline rates, often producing
for 25 years or more.
- Acquisition of Producing Properties. The purchase of third party
production offers a means in addition to drilling for accelerating our
growth, while capitalizing on our experience as a regional operator. Our
acquisition criteria for producing properties include reserve life, profit
enhancement potential, geographic concentration and working interest
levels permitting operation of acquired properties. In addition to
acquisitions for our own account, we may begin to sponsor production
programs modeled on our structure for Drilling Programs to acquire
producing natural gas wells meeting defined criteria from unaffiliated
operators in our core geographic areas. If implemented, this strategy
would provide us with additional vehicles for increasing our stake in
Appalachian Basin gas reserves and production.
- Monetization of Gold and Silver Properties. We stopped exploration work on
our Alaskan gold and silver properties in 1996 based on operating and
commodity pricing considerations. The properties have remained dormant
since that time, and we elected to write off their carrying value for
accounting purposes in 2000, when the market price of gold was below $285
per ounce. In view of recent improvements in gold prices, we plan to
increase our efforts to monetize our interests in these properties by
seeking a joint venture partner to either provide funds for developing the
prospects or to acquire them from us.
FINANCING ACTIVITIES
During the last five years, we have funded a substantial part of our
capital expenditures with proceeds from private placements of our common stock
and convertible notes, including equity financings for $8,430,000 and
convertible note financings for $8,236,125 in 2003. Participants in our
convertible note financings elected to convert $5,295,000 of their notes into
2,069,393 shares of our common stock during 2003, with an additional $1,742,971
principal amount of the notes converted into 525,379 common shares in the first
six months of 2004. During April 2004, we raised an additional $5,832,450 in an
institutional private placement of our common stock, issuing 975,000 shares at
$5.98 per share. See "Liquidity and Capital Resources" below. Our proceeds from
these financings have been allocated primarily to our construction of new
gathering systems and our investments in sponsored Drilling Programs.
DRILLING OPERATIONS
Drilling Program Structure. Most of our Drilling Programs are limited
partnerships structured to minimize drilling risks and optimize tax advantages
for private investors. To develop exploratory prospects with higher risk
profiles, we generally rely on smaller, specialized Drilling Programs structured
as joint ventures with strategic and industry partners or other suitable
investors. At the commencement of operations, drilling rights for specified
wells are assigned by DPI to each Drilling Program, which enters into turnkey
drilling contracts with DPI for drilling and
16
completing the wells at specified prices. 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 contribute capital to each Drilling Program in proportion to our
initial ownership interest, and we share program distributions in the same
ratio. We also maintain a 1% interest as general partner of each Drilling
Program, and we are entitled to specified increases in our program interests, up
to 15% of the total program interests, after program distributions reach
"payout," which ranges from 100% to 110% of partners' investment. We bear all
selling costs for Drilling Program financings and all overhead and
administrative costs for program operations. The return on our investment is
limited to our share of program distributions and any cost savings we achieve
under our turnkey drilling contracts, net of our proportionate share of that
surplus. We also receive customary fees for well operating and gas gathering
services.
Drilling Program Benefits. Our structure for sharing Drilling Program
costs, risks and returns helps us attract outside capital from private
investors. This addresses the high capital costs of our business, enabling us to
accelerate the development of our properties without relinquishing control over
drilling and operating decisions. The structure also provides economies of scale
with operational benefits at several levels.
- Based on our 25% to 30% capital investment in limited partnership Drilling
Programs, we control a drilling budget up to four times greater than we
could support on our own. This increases our buying power for drilling
services and materials, contributing to lower overall development costs.
- Aggregating our capital with private investors in our Drilling Programs
enables us to maintain a larger and more capable staff than we could
otherwise support if we were operating solely for our own account.
- Accelerating the pace of our development activities expands the production
capacity we can make available to gas purchasers, contributing to higher
and more stable sales prices for our production.
Drilling Program Financings. During 2003, we raised outside capital of
$19,329,750 for our limited partnership Drilling Programs and $2,950,000 for
joint venture Drilling Programs. In the second quarter of 2004, we completed a
private placement of interests in the first 2004 limited partnership Drilling
Program, with contributed capital of $10,500,000 from outside investors. In
addition, as of the date of this report, we have accepted subscriptions of
$1,930,000 from outside investors in our second 2004 limited partnership
Drilling Program. We have a 30.7% interest in each of the 2004 Drilling
Programs, which have entered into turnkey drilling contracts for a total of 58
wells to date.
Drilling Results. The following table shows the number of gross and net
development and exploratory wells we drilled during the 2003 and the first half
of 2004. Gross wells are the total number of wells in which we have a working
interest. Net wells reflect our working interests in wells drilled through our
Drilling Programs, without giving effect to any reversionary interest we may
subsequently earn in those programs. Productive wells listed below include wells
that were drilled and successfully tested in at least one primary pay zone but
were awaiting construction of gathering systems prior to completion at the end
of the reported period.
DEVELOPMENT WELLS EXPLORATORY WELLS
----------------- -----------------
PRODUCTIVE DRY PRODUCTIVE DRY
---------- --- ---------- ---
GROSS NET GROSS GROSS NET GROSS
----- --- ----- ----- --- -----
Year ended December 31, 2003.......... 79 20.1013 -- 10 6.6667 --
Six months ended June 30, 2004........ 63 17.5691 -- 15 10.0000 --
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 million
cubic feet 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 or other impurities with the gas production.
This helps us minimize production (lifting) costs. In addition, the average
energy (or Btu) value of the natural gas produced in this area is substantially
higher than normal pipeline quality gas, ranging from 1,100 to 1,229 million
British thermal units ("MBtu") per thousand cubic feet ("Mcf") of gas
production. Our gas sales contracts generally provide upward
17
adjustments to index based pricing for our natural gas with an energy value
above 1,000 MBtu 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, 2004 and 2003. Total revenues for the quarter
ended June 30, 2004 were $8,327,169, an increase of 116% from $3,851,469 in the
same quarter last year. Our revenue mix for the second quarter of 2004 was 84%
contract drilling, 12% oil and gas production and 4% natural gas transmission
and compression. For the comparable quarter of 2003, our total revenues were
derived 79% from contract drilling, 14% from oil and gas production and 7% from
natural gas transmission and compression activities.
Contract drilling revenues were $7,040,250 for the second quarter of 2004,
up 133% from $3,025,000 in the comparable quarter of 2003. 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 the net proceeds from these financings 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 our initial 2004 limited partnership Drilling Program were
ongoing during the second quarter of 2004, when we drilled 25 gross (7.6311 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 $986,724 for the second quarter of 2004, an
increase of 84% from $537,286 in the comparable quarter of 2003. This reflects
an increase of 90% in our production volumes to 182,317 Mcf of gas equivalents
("Mcfe") in the second quarter of 2004 from 96,148 Mcfe in the same quarter
last year. Our growth in production volumes resulted from new wells brought
on line since the end of June 2003. Our average sales price of natural gas
(before certain transportation charges) was $5.50 in the second quarter of 2004
compared to $5.86 per Mcf in the corresponding quarter last year, reflecting
continued strength in natural gas prices. Principal purchasers of our natural
gas production are gas marketers and transmission companies with facilities
near our producing properties. During the second quarter of 2004, approximately
40% of 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 $300,195 during the second
quarter of 2004, up 4% from $289,183 in the comparable quarter of 2003. This
reflects continued reliance on our own gathering systems for our new wells,
generating transmission and compression revenues from the Drilling Programs, net
of our working interests in those wells. During the second quarter of 2004, we
extended our natural gas gathering systems for new wells by approximately 18
miles, including a four-mile line for connecting our Straight Creek wells. Our
gas transmission and compression revenues for the second quarter of 2004 also
reflect a contribution of $42,998 from Sentra's gas utility sales, up 9% from
$39,568 in the same quarter last year.
Total direct expenses increased by 274% to $5,743,646 for the second
quarter of 2004 compared to $1,534,687 for the second quarter of 2003. Our
direct expense mix for the current reported quarter was 91% contract drilling,
7% oil and gas production and 2% natural gas transmission and compression. For
the comparable quarter of 2003, our total direct expenses were incurred 84% in
contract drilling, 7% in oil and gas production and 9% in natural gas
transmission and compression.
Contract drilling expenses were $5,236,941 during the second quarter of
2004, an increase of 308% from $1,283,184 in the same quarter last year. This
reflects the substantial level of drilling activities on behalf of our sponsored
Drilling Programs, as well as an increase of approximately 800 feet in the
average depth of our new wells. The greater depth of these wells adds
incrementally to the variable costs paid to outside contractors and to well
completion complexities and expenditures. The greater depth also adds to steel
casing requirements, prices for which increased by approximately 50% in the
first six months of 2004, with further price increases anticipated on an
industry wide basis throughout the year. In response to these developments, we
increased the price established for drilling and completing new wells under
turnkey drilling contracts by 10%, starting with our second 2004 limited
partnership Drilling Program.
Production expenses increased 274% to $392,379 in the second quarter of
2004, compared to $104,930 in the same quarter last year, reflecting our
substantial growth in production volumes. As a percentage of oil and gas
18
production revenues, production expenses increased to 40% in the second quarter
of 2004 from 20% in the same quarter last year. The difference in margin
reflects a greater allocation of our field operating resources to oil and gas
production activities in the second quarter of 2004, including construction of
gas gathering lines.
Gas transmission and compression expenses in the second quarter of 2004
were $114,326, a decrease 22% from $146,573 in the same quarter last year,
reflecting economies of scale and field operating efficiencies. As a percentage
of gas transmission and compression revenues, these expenses decreased to 38% in
the current reported quarter from 51% in the second quarter of 2003. Gas
transmission and compression expenses do not reflect capitalized costs of
$520,447 in the second quarter of 2004 for extensions of our gas gathering
systems and compression capacity required to bring new wells on line.
Selling, general and administrative ("SG&A") expenses were $1,744,546 in
the second quarter of 2004, an increase of 16% from $1,505,514 in the same
quarter last year, primarily reflecting the timing and extent of our selling and
promotional costs for sponsored Drilling Programs. The higher SG&A expenses for
the second quarter of 2004 also reflect costs for supporting expanded operations
as a whole, including additions to our staff and technology infrastructure as
well as increased salary and other employee related expenses. With the expansion
of our operations, we also achieved various economies of scale, reflected by a
decrease in SG&A expenses as a percentage of total revenues to 21% in the
current reported quarter compared to 39% in the second quarter of 2003.
Beginning in 2004, we adopted the fair value method of accounting for
employee stock options, with retroactive prior period restatement to reflect
this method instead of the intrinsic value method we previously followed. Under
the new method, employee stock options are valued at the grant date using the
Black-Scholes valuation model, and the compensation cost is recognized ratably
over the vesting period. This resulted in the recognition of additional
compensation cost of $78,408 in the second quarter of 2004. We previously
recognized a compensation charge of $589,200 for the second quarter of 2003 from
the exercise of employee stock options with a stock-for-stock or "cashless"
exercise feature and from the issuance of common stock purchase warrants for
corporate consulting services.
Depreciation, depletion and amortization ("DD&A") increased 32% to
$255,475 in the second quarter of 2004 from $194,080 in the same quarter of
2003. The increase in DD&A expense reflects additions to oil and gas properties,
gas gathering systems and related equipment.
Interest expense for the second quarter of 2004 was $107,535, down 12%
from $122,180 in the second quarter of 2003. This reflects a reduction of our
total outstanding debt since June 2003, partially offset by higher interest
rates from the repayment of borrowings under our credit facility with proceeds
from convertible notes. See "Liquidity and Capital Resources" below.
We recognized income tax expense of $250,439 in the second quarter of
2004, of which $211,696 was recorded as a future tax liability. Our current
income tax expense for the second quarter of 2004 was reduced to $38,743,
primarily from our proportionate share of intangible drilling costs ("IDC") from
our Leatherwood joint venture Drilling Program and a 15% allocation of IDC from
our first 2004 limited partnership Drilling Program. The 15% functional
allocation of IDC from limited partnership Drilling Programs was initiated in
2004 to compensate for our full utilization of all loss carryforwards at the DPI
level in 2003.
We realized net income of $208,383 for the second quarter of 2004,
compared to a net loss of $69,882 recognized in the second quarter of 2003,
reflecting the foregoing factors. Basic earnings per share were $0.02 based on
13,877,212 weighted average common shares outstanding in the second quarter of
2004, compared to a net loss of $0.01 per share based on 6,632,620 weighted
average common shares outstanding in the same quarter last year.
Six Months Ended June 30, 2004 and 2003. Total revenues for the six months
ended June 30, 2004 were $23,893,051, an increase of 88% from $12,682,324 in the
same period last year. Our revenue mix for the first half of 2004 was 89%
contract drilling, 8% oil and gas production and 3% natural gas transmission and
compression. For the comparable period in 2003, our total revenues were derived
87% from contract drilling, 8% from oil and gas production and 5% from natural
gas transmission and compression activities.
19
Contract drilling revenues were $21,366,375 for the first six months of
2004, up 93% from $11,058,000 in the comparable period of 2003. This reflects
both the increased size of our recent Drilling Programs and the timing of the
Drilling Program financings. Drilling operations for our year-end 2003 limited
partnership and 2003 joint venture Drilling Programs were ongoing during the
first quarter of 2004, and our initial 2004 limited partnership Drilling Program
was actively engaged in the drilling phase in the second quarter of 2004. For
the first six months of 2004, we drilled a total of 78 gross (27.5691 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 $1,778,013 for the second half of 2004, an
increase of 67% from $1,066,290 in the comparable period in 2003. This reflects
an increase of 57% in our production volumes to 326,425 Mcfe in the first half
of 2004 from 207,290 Mcfe in the same period last year. Our growth in production
volumes resulted from new wells brought on line since the end of June 2003. The
growth in production revenues also reflects a 6% increase in our average sales
price of natural gas (before certain transportation charges) to $5.50 per Mcf
in the first half of 2004 from $5.19 per Mcf in the corresponding period in
2003, reflecting continued strength in natural gas prices. Principal purchasers
of our natural gas production are gas marketers and transmission companies with
facilities near our producing properties. During the first six months of 2004,
approximately 40% of 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 $748,663 during the first
half of 2004, up 34% from $558,034 in the comparable period in 2003. This
primarily reflects increased reliance on our own gathering systems for our new
wells, generating transmission and compression revenues from the Drilling
Programs holding the working interests in those wells. During the first half of
2004, we extended our natural gas gathering systems for new wells by
approximately 24 miles, including a four-mile line for connecting our Straight
Creek wells. Our gas transmission and compression revenues for the first half
of 2004 also reflect a contribution of $183,969 from Sentra's gas utility sales,
up 18% from $155,320 in the same period last year.
Total direct expenses increased by 209% to $16,525,868 for the first six
months of 2004 compared to $5,354,055 for the first six months of 2003. Our
direct expense mix for the current reported period was 93% contract drilling, 4%
oil and gas production and 3% natural gas transmission and compression. For the
comparable period in 2003, our total direct expenses were incurred 87% in
contract drilling, 8% in oil and gas production and 5% in natural gas
transmission and compression.
Contract drilling expenses were $15,341,589 during the first half of 2004,
an increase of 228% from $4,678,349 in the same period last year. This primarily
reflects the substantial level of drilling activities on behalf of our sponsored
Drilling Programs, as well as an increase of approximately 800 feet in the
average depth of our new wells. The greater depth of these wells adds
incrementally to the variable costs paid to outside contractors and to well
completion complexities and expenditures. The greater depth also adds to steel
casing requirements, prices for which increased by approximately 50% in the
first six months of 2004, with further price increases anticipated on an
industry wide basis throughout the year. In response to these developments, we
increased the price established for drilling and completing new wells under
turnkey drilling contracts by 10%, starting with our second 2004 limited
partnership Drilling Program.
Production expenses increased 59% to $670,087 in the first six months of
2004, compared to $420,944 in the same period last year, reflecting our
substantial growth in production volumes. As a percentage of oil and gas
production revenues, production expenses decreased slightly to 38% in the first
half of 2004 from 39% in the same period last year.
Gas transmission and compression expenses in the first six months of 2004
were $514,192, an increase 102% from $254,762 in the same period last year. As a
percentage of gas transmission and compression revenues, these expenses
increased to 69% in the current reported period from 46% in the first half of
2003. Gas transmission and compression expenses do not reflect capitalized costs
of $1,105,094 in the first half of 2004 for extensions of our gas gathering
systems and compression capacity required to bring new wells on line.
20
SG&A expenses were $4,930,064 in the first six months of 2004, an increase
of 17% from $4,197,729 in the same period last year, primarily reflecting the
timing and extent of our selling and promotional costs for sponsored Drilling
Programs, as well as costs for supporting expanded operations as a whole. With
the expansion of our operations, we also achieved various economies of scale,
reflected by a decrease in SG&A expenses as a percentage of total revenues to
21% in the current reported period compared to 33% in the first half of 2003.
Beginning in 2004, we adopted the fair value method of accounting for
employee stock options, with retroactive prior period restatement to reflect
this method instead of the intrinsic value method we previously followed. Under
the new method, employee stock options are valued at the grant date using the
Black-Scholes valuation model, and the compensation cost is recognized ratably
over the vesting period. We recognized additional compensation cost of $108,483
in the first six months of 2004 and restated our results for the first six
months of 2003 to record compensation cost of $153,600 under the fair value
method. We also recognized a previously reported compensation charge of $589,200
for the first six months of 2003 from the exercise of employee stock options
with a stock-for-stock or "cashless" exercise feature and from the issuance of
common stock purchase warrants for corporate consulting services.
DD&A increased 36% to $508,604 in the first half of 2004 from $373,160 for
the same period in 2003. The increase in DD&A expense reflects additions to oil
and gas properties, gas gathering systems and related equipment.
Interest expense for the first half of 2004 was $196,703, down 4% from
$204,633 in the first half of 2003. This reflects a reduction in our total
outstanding debt since June 2003, partially offset by higher interest rates from
the repayment of borrowings under our credit facility with proceeds from
convertible notes. See "Liquidity and Capital Resources" below.
We recognized income tax expense of $803,577 in the first six months of
2004, of which $654,418 was recorded as a future tax liability. Our current
income tax expense for the first six months of 2004 was reduced to $149,159,
primarily from our proportionate share of IDC from our Leatherwood joint
venture Drilling Program and a 15% allocation of IDC from our first 2004
limited partnership Drilling Program. The 15% functional allocation of IDC from
limited partnership Drilling Programs was initiated in 2004 to compensate for
our full utilization of all loss carryforwards at the DPI level in 2003.
We realized net income of $975,624 for the first six months of 2004,
compared to $1,859,330 in the first half of 2003, reflecting the foregoing
factors. Basic earnings per share were $0.08 based on 12,964,698 weighted
average common shares outstanding in the first half of 2004, compared to $0.30
per share based on 6,249,688 weighted average common shares outstanding in the
same period last year.
The results of operations for the quarter and six months ended June 30,
2004 are not necessarily indicative of results to be expected for the full year.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity. Net cash provided by our operating activities in the first six
months of 2004 was $2,164,456 before working capital adjustments and $1,104,477
after accounting for changes in assets and liabilities for the period. Our cash
position during the first six months of 2004 was decreased by the use of
$8,776,046 in investing activities, comprised primarily of net additions of
$8,719,016 to our oil and gas properties. This was partially offset by
$7,590,657 provided by financing activities, primarily reflecting an equity
financing in April 2004. See "Capital Resources" below. As a result of these
activities, net cash decreased slightly from $22,594,993 at December 31, 2003 to
$22,514,081 at June 30, 2004.
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 would 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 relied on a combination of cash flows
21
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.
On April 29, 2004, we completed a $5,832,450 equity infusion in a private
placement with institutional investors, issuing a total of 975,000 common shares
at $5.98 per share, reflecting the stock's average closing bid price for the
five trading days preceding the date of the purchase agreement for the
financing. During 2003, we completed two institutional private placements of
common stock, issuing 900,000 shares at $2.85 per share for $2,565,000 in June
2003 and an additional 1,303,335 shares at $4.50 per share for $5,865,000 at
year end. A portion of the proceeds from the second equity financing were
received immediately after year end, resulting in their classification as
subscriptions receivable. The proceeds from these equity financings and from
convertible note financings described below have been allocated primarily to
construction of gas gathering lines and our investments in sponsored Drilling
Programs. See "Drilling Operations - Drilling Program Financings" above.
We have issued five separate series of convertible notes since 2002 in the
aggregate principal amount of $8,656,125, 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
ranging 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 $1.50 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 $5,295,000 in 2003 and
$1,742,971 in the first six months of 2004, the aggregate principal amount of
our convertible notes outstanding at June 30, 2004 was reduced to $2,628,400.
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 $160,246 as of June 30, 2004. 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. As of June 30,
2004, Institutional Notes in the aggregate principal amount of $4,101,721 had
been converted into common shares at the original conversion price, leaving
$1,058,525 principal amount of the Institutional Notes and PIK Notes outstanding
at the end of the current reporting period.
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. Borrowings under the facility bear interest
payable monthly at 1.25% above the bank's prime rate, amounting to 5.25% at June
30, 2004. 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 June 30, 2004 and December 31, 2003.
Our remaining long term debt outstanding at June 30, 2004, including the
current portions, aggregated $402,818 on a secured note issued in 1986 for the
acquisition of our mineral property in Alaska and $120,196 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 financings 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.
22
We expect our cash reserves, cash flow from operations and funds available
under our credit facility to provide adequate working capital to meet our
capital expenditure objectives through the end of 2004, including our
anticipated contributions to Drilling Programs. See "Drilling Operations -
Drilling Program Financings" above. 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 11 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 Exchange Act relating to 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.
23
ITEM 3. CONTROLS AND PROCEDURES
Our management, with the participation or under the supervision of our
Chief Executive Officer and Chief Financial Officer, is responsible for
establishing and maintaining disclosure controls and procedures and internal
control over financial reporting for the Company in accordance with the
requirements of the Securities Exchange Act of 1934 (the "Exchange Act"). Our
disclosure controls and procedures are intended to provide a framework for
making sure that all information required to be disclosed in our current and
periodic reports under the Exchange Act is processed and publicly reported by us
within the prescribed time periods for our filing of those reports. Our internal
controls over financial reporting are designed to ensure the reliability of our
financial reporting and the preparation of our financial statements for external
purposes in accordance with generally accepted accounting principles. They
include policies and procedures for maintaining reasonably detailed records that
accurately and fairly reflect all our business transactions and dispositions of
assets, for ensuring that receipts and expenditures are made only in accordance
with management authorizations and for preventing or timely detecting of any
unauthorized acquisition, use or disposition of our assets that could have a
material effect on our financial statements.
Our Chief Executive Officer and Chief Financial Officer have evaluated the
effectiveness of the design and operation of our disclosure controls and
procedures and our internal control over financial reporting as of June 30,
2004. Based on their evaluation, they have concluded that our disclosure
controls and procedures are effective to ensure that material information about
our business and operations is recorded, processed, summarized and publicly
reported within the time period required under the Exchange Act. They have also
concluded that our internal controls over financial reporting are effective to
ensure the reliability of our financial reporting and the preparation of our
publicly reported financial statements in accordance with generally accepted
accounting principles. There were no changes in our controls or procedures
during the second quarter of 2004 that have materially affected or are
reasonably likely to materially affect our internal control of financial
reporting.
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On June 24, 2004, 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............... 11,235,436 141,193
James K. Klyman.................... 11,237,129 139,500
Charles L. Cotterell............... 11,239,939 136,690
Thomas F. Miller................... 11,235,430 141,196
Our shareholders also voted at the meeting to approve a series of
proposals relating to our corporate transition under the new business
corporations law in British Columbia, our jurisdiction of incorporation (the
"Corporate Transition"), along with a proposal to approve a new incentive stock
award and stock option plan, a proposal fixing the size of our board at four
members and a proposal 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, 2004. The number of votes cast for and against each of
these proposals is set forth below.
24
VOTES VOTES
PROPOSAL VOTES FOR AGAINST WITHHELD
-------- --------- ------- --------
Approval of the Corporate Transition,
including the name change........ 4,344,689 125,665 24,152
Increase in the shareholder quorum
threshold to one-third of the
outstanding shares............... 4,450,094 151,581 16,856
Decrease in the supermajority voting
threshold for non-routine matters to
two-thirds of the shares voting.. 4,226,031 375,153 20,147
Authorization of "blank check"
preferred shares................. 3,366,208 1,077,048 48,550
Approval of incentive stock
award and stock option plan...... 3,376,370 1,120,762 60,154
Fixing the size of the board of
directors at four members........ 11,019,808 312,601 31,987
Ratification of the appointment of
independent public accountants... 11,284,617 7,740 80,572
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits.
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------ ----------------------
3.1 Notice of Articles, certified on June 3, 2004 by the Registrar
of Corporations under the British Columbia Business
Corporations Act (incorporated by reference to Exhibit 3.1 to
Current Report on Form 8-K [File No. 0-12185], filed June 29,
2004).
3.2 Alteration to Notice of Articles, certified on June 25, 2004
by the Registrar of Corporations under the British Columbia
Business Corporations Act (incorporated by reference to
Exhibit 3.2 to Current Report on Form 8-K [File No. 0-12185],
filed June 29, 2004).
3.3 Articles dated June 25, 2004, as amended and restated for
corporate transition under the British Columbia Business
Corporations Act (incorporated by reference to Exhibit 3.3 to
Current Report on Form 8-K [File No. 0-12185], filed June 29,
2004).
10.1 1997 Stock Option Plan (incorporated by reference to Exhibit
10[a] to Annual Report on Form 10-KSB [File No. 0-12185] for
the year ended December 31, 2002).
10.2 2001 Stock Option Plan (incorporated by reference to Exhibit
10[b] to Annual Report on Form 10-KSB [File No. 0-12185] for
the year ended December 31, 2002).
10.3 2003 Incentive Stock and Stock Option Plan (incorporated by
reference to Exhibit 10.3 to Quarterly Report on Form 10-QSB
[File No. 0-12185] for the quarter ended March 31, 2004).
10.4 Form of Common Stock Purchase Warrant dated June 13, 2003
(incorporated by reference to Exhibit 10.1 to Current Report
on Form 8-K [File No. 0-12185] dated June 13, 2003).
10.5 Form of 7% Convertible Promissory Note dated as of September
5, 2003 (incorporated by reference to Exhibit 10.2 to Current
Report on Form 8-K [File No. 0-12185] dated September 5,
2003).
10.6 Form of Common Stock Purchase Warrant dated September 5, 2003
(incorporated by reference to Exhibit 10.3 to Current Report
on Form 8-K [File No. 0-12185] dated September 9, 2003).
25
10.7 Form of Common Stock Purchase Warrant dated December 31, 2003
(incorporated by reference to Exhibit 10.3 to Current Report
on Form 8-K [File No. 0-12185] dated January 2, 2003).
10.8 Form of Common Stock Purchase Warrant dated April 29, 2004
(incorporated by reference to Exhibit 10.4 to Current Report
on Form 8-K [File No. 0-12185] dated September 9, 2003).
10.9 Form of Change of Control Agreement dated as of February 25,
2004 (incorporated by reference to Exhibit 10.9 to Quarterly
Report on Form 10-QSB [File No. 0-12185] for the quarter ended
March 31, 2004).
10.10 Form of Indemnification Agreement dated as of February 25,
2004 (incorporated by reference to Exhibit 10.10 to Quarterly
Report on Form 10-QSB [File No. 0-12185] for the quarter ended
March 31, 2004).
10.11 Form of Long Term Incentive Agreement dated as of February 25,
2004 (incorporated by reference to Exhibit 10.11 to Quarterly
Report on Form 10-QSB [File No. 0-12185] for the quarter ended
March 31, 2004).
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 of Chief Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted under Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2 Certification of Chief Financial Officer 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 filed June 25, 2004.
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.
NGAS RESOURCES, INC.
(formerly Daugherty Resources, Inc.)
Date: August 10, 2004 By: /s/ William S. Daugherty
---------------------------------------
William S. Daugherty
Chief Executive Officer
(Duly Authorized Officer)
(Principal Executive Officer)
26