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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-QSB
[X] QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
FOR THE QUARTER ENDED SEPTEMBER 30, 2004
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF EXCHANGE ACT
COMMISSION FILE NO. 0-12185
NGAS 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
(Former name or former address, if changed since the last report)
Check whether the issuer (1) filed all reports required to be filed by Section
13 or 15(d) of the Exchange Act during the past 12 months and (2) has been
subject to those filing requirements for the past 90 days. Yes [X]
Number of shares outstanding of each of the issuer's classes of common equity,
as of the latest practicable date.
TITLE OF CLASS OUTSTANDING AT OCTOBER 31, 2004
COMMON STOCK 15,067,430
Transitional Small Business Disclosure Format. Yes [ ] No [X]
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NGAS RESOURCES, INC.
INDEX
PAGE
----
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS:
Review Engagement Report............................................................................. 2
Condensed Consolidated Balance Sheets - September 30, 2004 (unaudited) and December 31, 2003......... 3
Condensed Consolidated Statement of Operations and Deficit - Three months and nine months ended
September 30, 2004 and 2003 (unaudited).......................................................... 4
Condensed Consolidated Statement of Cash Flows - Three months and nine months ended
September 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....... 16
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. as at September 30, 2004 and the condensed consolidated statements of
operations and deficit and cash flows for the three months and nine 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 of NGAS RESOURCES, INC. 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 consolidated 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.
KRAFT, BERGER, GRILL, SCHWARTZ, COHEN & MARCH LLP
CHARTERED ACCOUNTANTS
Toronto, Ontario
November 5, 2004
2
NGAS RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(U.S. FUNDS)
SEPTEMBER 30, DECEMBER 31,
2004 2003
------------- ------------
(UNAUDITED)
ASSETS
Current assets:
Cash....................................................... $ 10,638,758 $ 22,594,993
Subscriptions receivable................................... -- 2,335,009
Accounts receivable........................................ 1,613,629 503,177
Prepaid expenses and other current assets.................. 1,012,922 773,415
Loans to related parties (Note 4).......................... 185,974 140,780
------------ ------------
Total current assets...................................... 13,451,283 26,347,374
Bonds and deposits.......................................... 124,400 99,000
Oil and gas properties (Note 2)............................. 35,589,214 16,369,859
Property and equipment (Note 3)............................. 2,022,422 2,054,088
Loans to related parties (Note 4)........................... 349,598 517,940
Investments (Note 5)........................................ 55,454 119,081
Deferred financing costs (Note 6)........................... 94,761 247,923
Goodwill (Note 7)........................................... 313,177 313,177
------------ ------------
Total assets............................................ $ 52,000,309 $ 46,068,442
============ ============
LIABILITIES
Current liabilities:
Accounts payable........................................... $ 2,324,531 $ 1,445,603
Accrued liabilities........................................ 2,405,217 2,865,045
Income taxes payable....................................... 3,107 144,450
Customers' drilling deposits............................... 5,071,100 10,162,600
Long term debt, current portion (Note 8)................... 376,995 397,722
------------ ------------
Total current liabilities................................. 10,180,950 15,015,420
Future income taxes......................................... 674,542 257,647
Long term debt (Notes 8 and 14)............................. 3,025,848 4,739,387
Deferred compensation....................................... 214,595 --
------------ ------------
Total liabilities....................................... 14,095,935 20,012,454
------------ ------------
SHAREHOLDERS' EQUITY
Capital stock (Note 9)
Authorized:
5,000,000 Preferred shares, non-cumulative, convertible
100,000,000 Common shares
Issued:
15,009,940 Common shares (December 31, 2003 - 10,676,030).. 52,578,020 36,244,623
21,100 Common shares held in treasury, at cost......... (23,630) (23,630)
Paid-in capital - options and warrants.......... 1,332,926 1,140,321
To be issued:
62,850 Common shares (December 31, 2003 - 1,403,335)... 247,650 5,917,958
------------ ------------
54,134,966 43,279,272
Deficit...................................................... (16,230,592) (17,223,284)
------------ ------------
Total shareholders' equity............................... 37,904,374 26,055,988
------------ ------------
Total liabilities and shareholders' equity............. $ 52,000,309 $ 46,068,442
============ ============
See Notes to Condensed Consolidated Financial Statements.
3
NGAS RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT
(U.S. FUNDS)
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------------- -----------------------------
2004 2003 2004 2003
------------ ------------ ------------ ------------
REVENUE
Contract drilling......................... $ 6,561,100 $ 3,866,000 $ 27,927,475 $ 14,924,000
Oil and gas production.................... 1,452,338 749,340 3,230,351 1,815,630
Gas transmission and compression.......... 344,633 269,801 1,093,296 827,835
------------ ------------ ------------ ------------
Total revenue............................ 8,358,071 4,885,141 32,251,122 17,567,465
------------ ------------ ------------ ------------
DIRECT EXPENSES
Contract drilling......................... 5,157,915 2,026,249 20,499,504 6,704,598
Oil and gas production.................... 517,113 227,853 1,187,200 648,797
Gas transmission and compression.......... 172,532 144,436 686,724 399,198
------------ ------------ ------------ ------------
Total direct expenses.................... 5,847,560 2,398,538 22,373,428 7,752,593
------------ ------------ ------------ ------------
GROSS PROFIT............................... 2,510,511 2,486,603 9,877,694 9,814,872
------------ ------------ ------------ ------------
OTHER INCOME (EXPENSES)
Selling, general and administrative....... (1,901,190) (1,437,407) (6,831,254) (5,635,136)
Compensation cost......................... (194,404) -- (427,450) (742,800)
Depreciation, depletion and amortization.. (324,946) (225,560) (833,550) (598,720)
Interest expense.......................... (87,550) (153,677) (284,253) (358,310)
Interest income........................... 80,076 48,001 248,282 105,536
Other, net................................ (35,954) 6,850 76,275 (1,302)
------------ ------------ ------------ ------------
Total other income (expenses)............ (2,463,968) (1,761,793) (8,051,950) (7,230,732)
------------ ------------ ------------ ------------
INCOME BEFORE INCOME TAXES................. 46,543 724,810 1,825,744 2,584,140
------------ ------------ ------------ ------------
INCOME TAX EXPENSE
Current................................... 9,351 96,168 416,157 861,082
Future.................................... 20,124 178,597 416,895 178,597
Benefit realized on loss carried forward.. -- -- -- (764,914)
------------ ------------ ------------ ------------
29,475 274,765 833,052 274,765
------------ ------------ ------------ ------------
NET INCOME................................. 17,068 450,045 992,692 2,309,375
DEFICIT, beginning of period............... (16,247,660) (19,024,094) (17,223,284) (20,883,424)
------------ ------------ ------------ ------------
DEFICIT, end of period..................... $(16,230,592) $(18,574,049) $(16,230,592) $(18,574,049)
============ ============ ============ ============
NET INCOME PER SHARE
Basic..................................... $ 0.00 $ 0.05 $ 0.07 $ 0.31
============ ============ ============ ============
Diluted................................... $ 0.00 $ 0.04 $ 0.07 $ 0.22
============ ============ ============ ============
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING:
Basic..................................... 14,725,187 9,557,613 13,555,811 7,364,447
============ ============ ============ ============
Diluted................................... 15,877,802 13,130,760 16,107,154 10,867,193
============ ============ ============ ============
See Notes to Condensed Consolidated Financial Statements.
4
NGAS RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(U.S. FUNDS) (UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------------- -----------------------------
2004 2003 2004 2003
------------ ------------ ------------ ------------
OPERATING ACTIVITIES
Net income............................................ $ 17,068 $ 450,045 992,692 $ 2,309,375
Adjustments to reconcile net income
to net cash used in operating activities:
Incentive bonus paid in common shares................ 159,705 -- 159,705 351,420
Compensation cost.................................... 194,404 -- 427,450 742,800
Depreciation, depletion and amortization............. 324,946 225,560 833,550 598,720
Write-down of investments............................ 63,627 -- 63,627 --
Write-off of deferred financing costs................ -- 29,786 -- 29,786
Notes issued in kind for interest on long term debt.. 18,677 23,973 74,036 23,973
Gain on sale of assets............................... -- (6,050) (4,948) (2,255)
Future income taxes.................................. 20,124 178,597 416,895 178,597
Changes in assets and liabilities
Subscriptions receivable........................... -- -- 2,335,009 --
Accounts receivable................................ (678,183) (135,316) (1,110,452) (214,216)
Prepaid expenses and other current assets.......... (16,831) (297,702) (239,507) (207,467)
Accounts payable................................... (119,922) (72,352) 1,060,447 133,461
Accrued liabilities................................ (505,110) (672,029) (459,828) (44,993)
Income taxes payable............................... (185,649) 96,168 (141,343) 96,168
Customers' drilling deposits....................... (1,081,500) 3,011,600 (5,091,500) (1,939,900)
------------ ------------ ------------ ------------
Net cash provided by (used in) operating activities.... (1,788,644) 2,832,280 (684,167) 2,055,469
------------ ------------ ------------ ------------
INVESTING ACTIVITIES
Proceeds from sale of assets......................... -- 17,500 190,600 20,745
Purchase of property and equipment................... (135,275) (236,678) (357,505) (712,106)
Bonds and deposits................................... -- -- (25,400) --
Additions to oil and gas properties, net............. (11,106,289) (1,012,445) (19,825,305) (3,625,866)
------------ ------------ ------------ ------------
Net cash used in investing activities.................. (11,241,564) (1,231,623) (20,017,610) (4,317,227)
------------ ------------ ------------ ------------
FINANCING ACTIVITIES
Decrease in loans to related parties................. 46,494 29,326 123,148 81,905
Proceeds from issuance of common shares.............. 1,127,685 509,815 8,687,725 3,585,699
Proceeds from issuance of long term debt............. -- 5,000,000 -- 8,236,125
Payments of deferred financing costs................. -- (410,000) -- (410,000)
Payments of long term debt........................... (19,294) (17,467) (65,331) (2,100,871)
------------ ------------ ------------ ------------
Net cash provided by financing activities.............. 1,154,885 5,111,674 8,745,542 9,392,858
------------ ------------ ------------ ------------
Change in cash......................................... (11,875,323) 6,712,331 (11,956,235) 7,131,100
Cash, beginning of period.............................. 22,514,081 7,450,076 22,594,993 7,031,307
------------ ------------ ------------ ------------
Cash, end of period.................................... $ 10,638,758 $ 14,162,407 $ 10,638,758 $ 14,162,407
============ ============ ============ ============
SUPPLEMENTAL DISCLOSURE
Interest paid.......................................... $ 39,379 $ 190,308 $ 180,723 $ 363,250
Income taxes paid...................................... 195,000 -- 299,853 --
SUPPLEMENTAL SCHEDULE OF NONCASH
INVESTING AND FINANCING ACTIVITIES
Common shares issued for accounts payable.............. 39,379 -- 180,723 164,126
Common shares issued upon conversion of notes.......... -- 1,235,000 1,613,890 2,495,000
See Notes to Condensed Consolidated Financial Statements.
5
NGAS RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 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 (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 September 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, Sentra Corporation ("Sentra"), a
Kentucky corporation wholly owned by DPI, and NGAS Securities, Inc. ("NGAS
Securities"), also a Kentucky corporation wholly owned by DPI. DPI conducts all
of the Company's oil and gas drilling and production operations. Sentra owns and
operates natural gas distribution facilities in Kentucky. NGAS Securities is a
registered broker-dealer and member of the National Association of Securities
Dealers, Inc. organized in 2004 to coordinate private placement financings by
the Company and DPI. The condensed consolidated financial statements also
reflect DPI's interests in a total of 26 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 periods in 2003 have been
reclassified to conform with the presentation in the current period.
NOTE 2. OIL AND GAS PROPERTIES
(a) Acquisitions. In two separate transactions during August, 2004, DPI
acquired oil and gas interests covering approximately 14,737 gross (7,604 net)
acres in Leslie and Bell Counties, Kentucky for a total of
6
$7.8 million. The Company has accounted for both acquisitions under the purchase
method. Additional oil and gas properties were acquired after September 30,
2004. See Note 14 - Subsequent Events.
(b) Capitalized Costs and DD&A. 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.
SEPTEMBER 30, 2004 DECEMBER 31,
------------------------------------------------ 2003
ACCUMULATED -----------
COST DD&A NET NET
----------- ----------- ----------- -----------
Proved oil and gas properties...... $33,281,389 $(2,873,369) $30,408,020 $14,053,881
Unproved oil and gas properties.... 1,017,879 -- 1,017,879 657,879
Wells and related equipment........ 4,556,723 (393,408) 4,163,315 1,658,099
----------- ----------- ----------- -----------
Total oil and gas properties....... $38,855,991 $(3,266,777) $35,589,214 $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 September 30, 2004.
SEPTEMBER 30, 2004 DECEMBER 31,
-------------------------------------------- 2003
ACCUMULATED ----------
COST DEPRECIATION NET NET
---------- ------------ ---------- ----------
Land............................ $ 12,908 $ -- $ 12,908 $ 12,908
Building improvements........... 20,609 (4,039) 16,570 17,547
Machinery and equipment......... 1,203,510 (318,521) 884,989 857,726
Office furniture and fixtures... 55,665 (20,737) 34,928 26,220
Computer and office equipment... 366,748 (126,192) 240,556 206,748
Vehicles and aircraft........... 1,090,894 (258,423) 832,471 932,939
---------- ---------- ---------- ----------
Total property and equipment.... $2,750,334 $ (727,912) $2,022,422 $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 $364,143 at
September 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 September 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, bearing interest
at rates ranging from 7% to 8.25% per annum and maturing through July 1, 2010.
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 December 31, 2003, the estimated market value of the bonds was
$36,970. During the third quarter of 2004, in accordance with accounting
principles generally accepted in Canada, the Company recorded a write-down of
$63,627 in the carrying value of the bonds to reflect a permanent decline in
value, resulting in a carrying value of $55,454 at September 30, 2004. See Note
13 - United States Accounting Principles.
7
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 $1,301,721
were converted into common shares in the first nine months of 2004 and added to
equity, net of proportionate financing costs of $129,081. Accumulated
amortization for the remaining financing costs aggregated $59,957 at September
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 September 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 September 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 5.75% at September 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 September 30, 2004
and December 31, 2003. The credit limit, borrowing base and total borrowings
under the facility were increased after September 30, 2004 in connection with an
asset acquisition in the fourth quarter. See Note 14 - Subsequent Events.
(b) Convertible Notes. The Company has issued a series of convertible
notes in private placements to finance a substantial part of its drilling and
acquisition activities, including a note private placement completed after
September 30, 2004. See Note 14 - Subsequent Events. 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
------------------------------- SEPTEMBER 30, 2004
SEPTEMBER 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... 1,077,202 2,304,888 4.50 239,378
---------- ---------- ---------
Total................... $2,647,077 $4,316,013 1,124,747
========== ========== =========
8
The Company's 7% Convertible Notes due September 5, 2008 were originally
issued during September 2003 in the aggregate principal amount of $5,000,000.
Interest on those notes is payable quarterly in cash or additional notes and was
required to be paid in kind through September 30, 2004, resulting in the
issuance of additional notes aggregating $178,924 as of September 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. 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 $396,818 at September 30, 2004 and $414,818 at December
31, 2003.
(d) Miscellaneous Debt. The following table summarizes other outstanding
debt obligations of the Company at September 30, 2004 and December 31, 2003.
PRINCIPAL AMOUNT OUTSTANDING AT
-------------------------------
SEPTEMBER 30, DECEMBER 31,
2004 2003
------------- ------------
TERMS OF DEBT
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......................... $ 6,334 $ 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....................................................... 8,938 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............................ 26,851 45,605
---------- ----------
Total............................................................................. $ 106,902 $ 154,232
========== ==========
(e) Total Long Term Debt. The following table sets forth the Company's
total long term debt and current portion at September 30, 2004 and December 31,
2003. See Note 14 - Subsequent Events.
PRINCIPAL AMOUNT OUTSTANDING AT
----------------------------------
SEPTEMBER 30, DECEMBER 31,
2004 2003
------------- -------------
Total long term debt (including current portion)........ $ 3,402,843 $ 5,137,109
Less current portion.................................... 376,995 397,722
------------- -------------
Total long term debt.................................... $ 3,025,848 $ 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 September 30, 2004
or December 31, 2003. The following table reflects transactions involving the
Company's common stock during the reported periods.
9
NUMBER OF
SHARES AMOUNT
---------- -------------
COMMON SHARES ISSUED
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........ 1,406,709 3,325,404
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, September 30, 2004........................... 15,009,940 $ 52,578,020
========== =============
COMMON SHARES TO BE ISSUED
Contract and accounts payable settlement.................. 19,309 $ 85,273
Exercise of options and warrants.......................... 1,291 2,672
Grants to employees as incentive bonus.................... 42,250 159,705
---------- -------------
Balance at September 30, 2004......................... 62,850 $ 247,650
========== =============
PAID IN CAPITAL - OPTIONS AND WARRANTS
Balance, December 31, 2002............................................... $ 763,635
Issued....................................................................... 376,686
-------------
Balance, December 31, 2003............................................... 1,140,321
Issued....................................................................... 212,855
Exercised.................................................................... (20,250)
-------------
Balance, September 30, 2004.............................................. $ 1,332,926
=============
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
September 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 and Awards. The Company maintains three stock plans for
the benefit of its directors, officers, employees and, in the case of the second
and third plans, 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. The third plan, adopted in 2003, provides for the grant of stock
awards and stock options for an aggregate of up to 4,000,000 common shares.
Stock awards may be subject to vesting conditions and trading restrictions
specified at the time of grant. Option grants must be at prevailing market
prices and may be subject to vesting requirements over a period of up to ten
years from the date of grant. During 2003, initial stock awards were made under
this plan for a total of 353,500 shares, subject to shareholder approval of the
plan, which was received in June 2004.
10
The exercise prices of options outstanding at September 30, 2004 under the
Company's stock plans range from $1.02 to $4.09 per share, and their weighted
average remaining contractual life is 4.70 years. The following table reflects
transactions involving the Company's stock options during 2003 and the first
nine 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)................................ 2,015,000 4.05
Exercised................................ (310,362) 1.00
Expired.................................. (438,969) 1.23
--------- ----------
Balance, September 30, 2004.......... 2,385,000 370,000 $ 3.58
========= ========= ==========
- ----------
(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 at exercise
prices ranging from $4.03 to $4.09 per share and vesting in increments
from February 25, 2005 through February 25, 2009.
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 nine months ended
September 30, 2004, this resulted in the recognition of $212,855 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 September
30, 2004 and the nine months ended September 30, 2004 and 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 September 30, 2003.
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 and income per share for the nine months ended September 30, 2003 as
reflected in the table below, with related adjustments to the deficit as
previously reported since 1995.
11
INTRINSIC FAIR
VALUE VALUE
METHOD METHOD
------------ ------------
(PREVIOUSLY (RESTATED)
REPORTED)
NINE MONTHS ENDED SEPTEMBER 30, 2003
Net income........................................... $ 2,462,975 $ 2,309,375
Net earnings per share
Basic............................................ 0.33 0.31
Fully diluted.................................... 0.24 0.22
Weighted average fair value of options granted....... 0.38 0.38
AS OF DECEMBER 31, 2003
Deficit.............................................. 16,306,049 17,223,284
(c) Common Stock Purchase Warrants. The Company has issued common stock
purchase warrants in various financing transactions. The exercise prices of
warrants outstanding at September 30, 2004 range from $1.03 to $6.25 per share,
and their weighted average remaining contractual life is 2.06 years. The
following table reflects transactions involving the Company's common stock
purchase warrants during 2003 and the first nine 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................................... (1,097,638) 2.73
Expired..................................... (689,062) 3.06
---------- ----------
Balance, September 30, 2004............. 1,877,348 1,877,348 $ 4.42
========== ========= ==========
- ----------
(1) Expiring from September 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
ended September 30, 2004, the assumed exercise of outstanding stock options and
warrants would have a dilutive effect on EPS because some of their exercise
prices were below the average market price of the common stock during the
period. For the three months ended September 30, 2003 and nine months ended
September 30, 2004 and 2003, the assumed exercise of outstanding stock options
and warrants and conversion of outstanding convertible notes and, for the 2003
periods, convertible preferred shares would have a dilutive effect on EPS
because the exercise or conversion prices for some of these instruments were
below the average market price of the common stock during the periods. The
following table sets forth the computation of diluted EPS for the reported
periods.
12
DILUTED EPS
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------- -----------------------------
2004 2003 2004 2003
----------- ------------- ----------- -----------
Numerator:
Net income as reported for basic EPS............ $ 17,068 $ 450,045 $ 992,692 $ 2,309,375
Adjustments to income for diluted EPS........... -- 48,347 56,520 124,600
----------- ------------- ----------- -----------
Net income for diluted EPS.................. $ 17,068 $ 498,392 $ 1,049,212 $ 2,433,975
=========== ============= =========== ===========
Denominator:
Weighted average shares for basic EPS........... 14,725,187 9,557,613 13,555,811 7,364,447
Effect of dilutive securities:
Stock options............................... 642,795 957,620 952,136 1,018,815
Warrants.................................... 509,820 980,486 806,119 568,204
Convertible notes........................... -- 1,588,196 793,088 1,705,969
Convertible preferred shares................ -- 46,845 -- 209,758
----------- ------------- ----------- -----------
Adjusted weighted average shares and
assumed conversions for dilutive EPS........ 15,877,802 13,130,760 16,107,154 10,867,193
=========== ============= =========== ===========
Diluted EPS..................................... $ 0.00 $ 0.04 $ 0.07 $ 0.22
=========== ============= =========== ===========
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 September 30, 2004.............. $ 6,561,100
Three months ended September 30, 2003.............. 3,866,000
Nine months ended September 30, 2004............... 27,927,475
Nine months ended September 30, 2003............... 14,924,000
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.
13
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------------- ----------------------------
2004 2003 2004 2003
----------- ----------- ----------- ----------
REVENUE, NET:
Oil and gas development................ $ 8,358,071 $ 4,885,141 $32,251,122 17,567,465
Corporate.............................. -- -- -- --
----------- ----------- ----------- ----------
Total.............................. 8,358,071 4,885,141 32,251,122 17,567,465
----------- ----------- ----------- ----------
DD&A:
Oil and gas development................ 295,479 199,800 741,629 536,067
Corporate.............................. 29,467 25,760 91,921 62,653
----------- ----------- ----------- ----------
Total.............................. 324,946 225,560 833,550 598,720
----------- ----------- ----------- ----------
INTEREST EXPENSE:
Oil and gas development................ 34,674 51,767 102,477 162,758
Corporate.............................. 52,876 101,910 181,776 195,552
----------- ----------- ----------- ----------
Total.............................. 87,550 153,677 284,253 358,310
----------- ----------- ----------- ----------
NET INCOME (LOSS):
Oil and gas development................ 184,791 782,349 1,662,086 3,792,542
Corporate.............................. (167,723) (332,304) (669,394) (1,483,167)
----------- ----------- ----------- ----------
Total.............................. 17,068 450,045 992,692 2,309,375
----------- ----------- ----------- ----------
CAPITAL EXPENDITURES:
Oil and gas development................ 11,196,473 1,170,230 20,063,642 4,100,603
Corporate.............................. 45,091 78,893 119,168 237,369
----------- ----------- ----------- ----------
Total.............................. $11,241,564 $ 1,249,123 20,182,810 4,337,972
=========== =========== ----------- ==========
SEPTEMBER 30, DECEMBER 31,
2004 2003
------------- ------------
IDENTIFIABLE ASSETS:
Oil and gas development.................................................... $43,165,618 $29,702,445
Corporate.................................................................. 8,834,691 16,365,997
----------- -----------
Total.................................................................. $52,000,309 $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, which would have partially reversed prior writedowns with
an addition of $18,484 to other comprehensive income under U.S. GAAP for the
nine months ended September 30, 2004..
(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.
14
(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 September 15, 2003. The statement is not expected to have
a material impact on the Company's condensed consolidated financial statements.
NOTE 14. SUBSEQUENT EVENTS
(a) Convertible Note Financing. On October 4, 2004, the Company completed
an institutional private placement of its 7% Convertible Note due October 4,
2009 in the principal amount of $6,100,000, along with warrants to purchase up
to 440,000 common shares at an exercise price of $6.00 per share. The Company
has the right to repay any unconverted portion of the note at maturity either in
cash or in common shares valued for that purpose at 90% of their prevailing
market price. The note is repayable upon any event of default in cash at the
greater of 115% of its principal amount or 100% of the prevailing market price
of the underlying conversion shares. The note is convertible into common shares
at the option the holder at an initial conversion price of $6.00. The conversion
price of the note and exercise price of the related warrants are subject to
anti-dilution adjustments for any recapitalization transaction and for any
issuance of common stock or rights to acquire common stock for consideration
less than the prevailing conversion or exercise price. For purposes of these
adjustments, dilutive issuances do not include securities issued under existing
instruments, under board-approved incentive plans or in a public offering,
business acquisition or strategic transaction. In addition, no anti-dilution
adjustments will be made to the extent they would increase the total shares
issuable under the Note and related warrants above 3,000,487 common shares.
(b) Asset Acquisition. On October 12, 2004, DPI acquired oil and gas
assets from Stone Mountain Energy, LLC ("SME") located in Bell, Harlan and
Leslie Counties, Kentucky and Lee County, Virginia, covering approximately
75,000 gross (61,875 net acres). The Company paid $27 million for the SME assets
and assumed future SME obligations under its oil and gas leases, farm-out
agreements and operating contracts. Funding for the acquisition was provided
from working capital, borrowings of $15 million the Company's secured credit
facility and part of the proceeds from the Company's institutional private
placement of its 7% convertible note. The Company will account for the SME asset
acquisition under the purchase method. The purchase price was allocated among
the acquired assets as of the closing date.
(c) Increase in Credit Facility. In connection with the SME acquisition,
the Company's credit facility with KeyBank NA was increased in October 2004 to
$20 million, subject to semi-annual borrowing base determinations by the bank.
The borrowing base at the time of the acquisition was established at $15
million, and the interest rate was lowered to 1% above the bank's prime rate.
15
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 inactive gold and silver
prospects in Alaska, owns and operates natural gas distribution facilities in
Kentucky through its wholly owned subsidiary, Sentra Corporation ("Sentra"), and
coordinates our private placement financings through its wholly owned
subsidiary, NGAS Securities, Inc. Our principal and administrative offices are
located at 120 Prosperous Place, Suite 201, Lexington, Kentucky 40509. 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 26 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 reflects our focus on natural gas
development and production and reinforces 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. Unless otherwise indicated, references in this report to
"we," "our" or "us" include the Company as well as DPI, its subsidiaries and its
interests in the Drilling Programs.
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 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 270 natural gas wells though our Drilling Programs,
including 89 gross (26.7680 net) wells in 2003 and 103 gross
(34.5631 net) wells in the first nine months of 2004. We sponsored
Drilling Programs for up to 140 new wells in 2004 and increased our
working interest in program wells to 30.7%.
- Acquisition of Producing Properties. The purchase of third party
production offers a means in addition to drilling for accelerating
our growth, while continuing to capitalize 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. During the third and fourth quarters of 2004,
we completed three separate acquisitions of oil and gas interests
covering a total of 89,737 acres near our core operating areas. See
"Acquisition Activity."
- Acquisition of Additional Drilling Prospects. We focus on expanding
our substantial inventory of drilling prospects that meet our
criteria for building predictable, long-lived reserves in our core
operating areas of the Appalachian Basin. Over the last several
years, we acquired oil and gas drilling rights covering
approximately 100,000 acres on the southeastern edge of the Big
Sandy Gas Field in eastern Kentucky (the "Leatherwood Field") as
well as 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 capitalizing on
opportunities to acquire large tracts with significant unproved gas
development potential as well as established infrastructure, adding
to our inventory of exploratory prospects relatively close to fields
with gas production histories and pipelines.
16
- Extension of Gas Gathering Systems. We construct and operate gas
gathering facilities to connect our wells to interstate pipelines
with access to major natural gas markets. In addition to generating
gas transmission and compression revenues, our 100% ownership of our
gathering systems gives us control over third-party access,
providing competitive advantages in acquiring and developing 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 nine
months of 2004, we extended our gathering systems by an additional
42 miles, including a four-mile, eight-inch steel gathering line
that connects our Straight Creek wells to a major regional pipeline
through a gathering system 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 Approach to Drilling. Most of our natural gas wells are
drilled to relatively shallow total depths up to 5,100 feet,
generally encountering five distinct and predictable pay zones. This
disciplined approach helps reduce drilling risks, as reflected in
our success rate. 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 September 30,
2004, we operated a total of 454 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 ACTIVITIES
In two separate transactions during August 2004, we acquired approximately
14,737 gross (7,604 net) acres of oil and gas leases in Leslie and Bell
Counties, Kentucky for a total of $7.8 million, or $1.20 per Mcfe, based on
estimated proved reserves of over 6.5 Bcfe for the acquired interests. We funded
the acquisitions from working capital.
In October 2004, we completed an additional acquisition of oil and gas
interests covering approximately 75,000 gross (61,875 net) acres from Stone
Mountain Energy Company, L.C. ("SME") in Bell, Harlan and Leslie Counties,
Kentucky and Lee County, Virginia. We paid $27 million for the acquired
interests, or $1.16 per Mcfe, based on their estimated proved gas reserves of
23.2 Bcfe of as of December 31, 2003. Funding for the SME acquisition was
provided from working capital, borrowings of $15 million under our secured
credit facility and part of the proceeds from our institutional private
placement of $6.1 million principal amount of our 7% convertible note due
October 4, 2009. See "Liquidity and Capital Resources." The SME acquisition,
along with our August 2004 acquisitions, increased our current net daily
production to approximately 6,000 Mcfe per day from over 570 wells we now
operate in the region.
Gas production from the SME properties was delivered through a gathering
system in southeastern Kentucky owned by Duke Energy Gas Services Corporation
and operated by SME. Prior to the acquisition, we delivered natural gas
production from our Straight Creek Field to Duke's gathering system. In
connection with the SME acquisition, we expanded our arrangements with Duke to
dedicate both our Straight Creek and acquired SME production for delivery to a
major regional pipeline through a gathering system in southeastern Kentucky and
eastern Tennessee through Duke's gathering system. By integrating operations on
the acquired acreage with our existing field activities in the region, we expect
to expand our throughput to major natural gas markets serviced through Duke's
system and strengthen our competitive position in the region.
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 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 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,
17
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 helps us complete for
attractive properties with by increasing our drilling commitments
under oil and gas leases and farmout agreements. It also 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.
- By conducting drilling operations on our undeveloped prospects
through specially tailored joint ventures and retaining majority
ownership interests, we are expanding our inventory of developmental
locations with lower risk profiles for subsequent Drilling Programs,
while adding to our proved reserves, both developed and undeveloped.
Drilling Program Financings. During 2003, we raised outside capital of
$19,329,750 for our limited partnership Drilling Programs and $2,950,000 for our
joint ventures. In 2004, we completed private placements of interests in two
separate limited partnership Drilling Programs, with contributed capital
aggregating $31,290,000 from outside investors. We have a 30.7% interest in each
of the 2004 Drilling Programs, which have entered into turnkey drilling
contracts for a total of 140 wells to be drilled through the first quarter of
2005.
Drilling Results. The following table shows the number of gross and net
development and exploratory wells we drilled during the 2003 and the first nine
months 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 --
Nine months ended September 30, 2004....... 88 24.5631 -- 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
18
("MBtu") per thousand cubic feet ("Mcf") of gas production. Our gas sales
contracts generally provide upward 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 September 30, 2004 and 2003 Total revenues for the quarter
ended September 30, 2004 were $8,358,071, an increase of 71% from $4,885,141 in
the same quarter last year. Our revenue mix for the third quarter of 2004 was
79% contract drilling, 17% 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, 15% from oil and gas
production and 6% from natural gas transmission and compression activities.
Contract drilling revenues were $6,561,100 for the third quarter of 2004,
up 70% from $3,866,000 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 both of our 2004 limited partnership Drilling Programs were
ongoing during the third quarter of 2004, when we drilled 25 gross (6.9940 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 $1,452,338 for the third quarter of 2004, an
increase of 94% from $749,340 in the comparable quarter of 2003. This reflects
an increase of 63% in our production volumes to 224,615 Mcf of gas equivalents
("Mcfe") in the third quarter of 2004 from 137,512 Mcfe in the same quarter last
year. Our growth in production volumes resulted from new wells brought on line
since the end of September 2003. Our average sales price of natural gas (before
certain transportation charges) was $6.54 in the third quarter of 2004 compared
to $5.46 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 third 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 $344,633 during the third
quarter of 2004, up 28% from $269,801 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 third quarter of 2004, we
extended our natural gas gathering systems for new wells by approximately 18
miles. Our gas transmission and compression revenues for the third quarter of
2004 also reflect a contribution of $36,818 from Sentra's gas utility sales, up
9% from $33,874 in the same quarter last year.
Total direct expenses increased by 144% to $5,847,560 for the third
quarter of 2004 compared to $2,398,538 for the third quarter of 2003. Our direct
expense mix for the current reported quarter was 88% contract drilling, 9% oil
and gas production and 3% natural gas transmission and compression. For the
comparable quarter of 2003, our total direct expenses were incurred 85% in
contract drilling, 9% in oil and gas production and 6% in natural gas
transmission and compression.
Contract drilling expenses were $5,157,915 during the third quarter of
2004, an increase of 155% from $2,026,249 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 1,000 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 nine 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.
19
Production expenses increased 127% to $517,113 in the third quarter of
2004, compared to $227,853 in the same quarter last year, reflecting our
substantial growth in production volumes. As a percentage of oil and gas
production revenues, production expenses increased to 36% in the third quarter
of 2004 from 30% 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 third quarter of 2004, including construction of
gas gathering lines.
Gas transmission and compression expenses in the third quarter of 2004
were $172,532, an increase 19% from $144,436 in the same quarter last year. As a
percentage of gas transmission and compression revenues, these expenses
decreased to 50% in the current reported quarter from 54% in the third quarter
of 2003, reflecting economies of scale and field operating efficiencies. Gas
transmission and compression expenses do not reflect capitalized costs of
$1,557,930 in the third 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 $1,901,190 in
the third quarter of 2004, an increase of 32% from $1,437,407 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 third 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 23% in the
current reported quarter compared to 29% in the third 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 $104,373 in the third quarter of 2004.
Depreciation, depletion and amortization ("DD&A") increased 44% to
$324,946 in the third quarter of 2004 from $225,560 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 third quarter of 2004 was $87,550, down 43% from
$153,677 in the third quarter of 2003. This reflects a reduction of our total
outstanding debt since September 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."
We realized net income of $17,068 for the third quarter of 2004, compared
to $450,045 realized in the third quarter of 2003, reflecting the foregoing
factors. Basic earnings per share were $0.00 based on 14,725,187 weighted
average common shares outstanding in the third quarter of 2004, compared to
$0.05 per share based on 9,557,613 weighted average common shares outstanding in
the same quarter last year.
Nine months Ended September 30, 2004 and 2003 Total revenues for the nine
months ended September 30, 2004 were $32,251,122, an increase of 84% from
$17,567,465 in the same period last year. Our revenue mix for the first nine
months of 2004 was 87% contract drilling, 10% oil and gas production and 3%
natural gas transmission and compression. For the comparable period in 2003, our
total revenues were derived 85% from contract drilling, 10% from oil and gas
production and 5% from natural gas transmission and compression activities.
Contract drilling revenues were $27,927,475 for the first nine months of
2004, up 87% from $14,924,000 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 and third quarters. For
the first nine months of 2004, we drilled a total of 103 gross (34.5631 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 $3,230,351 for the first nine months of 2004, an
increase of 78% from $1,815,630 in the comparable period in 2003. This reflects
an increase of 60% in our production volumes to
20
551,040 Mcfe in the first nine months of 2004 from 344,802 Mcfe in the same
period last year. Our growth in production volumes resulted from new wells
brought on line since the end of September 2003. The growth in production
revenues also reflects a 12% increase in our average sales price of natural gas
(before certain transportation charges) to $5.94 per Mcf in the first nine
months of 2004 from $5.30 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 nine 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 $1,093,296 during the first
nine months of 2004, up 32% from $827,835 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 nine
months of 2004, we extended our natural gas gathering systems for new wells by
approximately 42 miles. Our gas transmission and compression revenues for the
first nine months of 2004 also reflect a contribution of $220,787 from Sentra's
gas utility sales, up 17% from $189,194 in the same period last year.
Total direct expenses increased by 189% to $22,373,428 for the first nine
months of 2004 compared to $7,752,593 for the first nine months of 2003. Our
direct expense mix for the current reported period was 92% contract drilling, 5%
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 $20,499,504 during the first nine months
of 2004, an increase of 206% from $6,704,598 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 860 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 nine 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 83% to $1,187,200 in the first nine months
of 2004, compared to $648,797 in the same period last year, reflecting our
substantial growth in production volumes. As a percentage of oil and gas
production revenues, production expenses increased slightly to 37% in the first
nine months of 2004 from 36% in the same period last year.
Gas transmission and compression expenses in the first nine months of 2004
were $686,724, an increase 72% from $399,198 in the same period last year. As a
percentage of gas transmission and compression revenues, these expenses
increased to 63% in the current reported period from 48% in the first nine
months of 2003. Gas transmission and compression expenses do not reflect
capitalized costs of $2,670,124 in the first nine months of 2004 for extensions
of our gas gathering systems and compression capacity required to bring new
wells on line.
SG&A expenses were $6,831,254 in the first nine months of 2004, an
increase of 21% from $5,635,136 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 32% in the
first nine months 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 $212,855
in the first nine months of 2004 and restated our results for the first nine
months of 2003 to record compensation cost of $742,800, which includes a
previously reported compensation charge of $589,200 from the exercise of
employee stock options with a stock-for-stock or "cashless" exercise feature and
from
21
the issuance of common stock purchase warrants for corporate consulting
services.
DD&A increased 39% to $833,550 in the first nine months of 2004 from
$598,720 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 nine months of 2004 was $284,253, down 21%
from $358,310 in the first nine months of 2003. This reflects a reduction in our
total outstanding debt since September 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 $833,052 in the first nine months of
2004, of which $416,895 was recorded as a future tax liability. Our current
income tax expense for the first nine months of 2004 was reduced to $416,157,
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 $992,692 for the first nine months of 2004,
compared to $2,309,375 in the first nine months of 2003, reflecting the
foregoing factors. Basic earnings per share were $0.07 based on 13,555,811
weighted average common shares outstanding in the first nine months of 2004,
compared to $0.31 per share based on 7,364,447 weighted average common shares
outstanding in the same period last year.
The results of operations for the quarter and nine months ended September
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 nine
months of 2004 was $2,963,007 before working capital adjustments, with net cash
of $684,167 used in operating activities after accounting for changes in assets
and liabilities for the period. Our cash position during the first nine months
of 2004 was decreased by the use of $20,017,610 in investing activities,
comprised primarily of net additions of $19,825,305 to our oil and gas
properties. This was partially offset by $8,745,542 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 from
$22,594,993 at December 31, 2003 to $10,638,758 at September 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 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.
In April 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. 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 September 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 six separate series of convertible notes since 2002 in the
aggregate principal amount of $14,756,125, including convertible notes issued to
institutional investors (the "Institutional Notes") in the aggregate principal
amounts of $5,000,000 in September 2003 and $6,100,000 in October 2004. The
notes bear interest at
22
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 $0.85
to $6.00 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 nine months of 2004, the aggregate principal amount of
our convertible notes outstanding at September 30, 2004 was reduced to
$2,647,077, before accounting for the Institutional Note for $6,100,000 issued
in October 2004.
The Institutional Notes issued in September 2003 and October 2004 have
several features not provided under prior note financings. Interest at 7% per
annum on the Institutional Notes issued in September 2003 is payable quarterly
in cash or additional Institutional Notes ("PIK Notes") and was required to be
paid in PIK Notes through September 30, 2004. We issued PIK Notes aggregating
$178,923 as of September 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 September 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
$1,077,202 principal amount of those 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. As of September 30, 2004, the credit limit for the
facility was $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 5.75% at September 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 September 30, 2004 and December 31, 2003. In connection with our SME
acquisition in October 2004, the credit facility was increased to $20 million,
subject to semi-annual borrowing base determinations by the bank. The borrowing
base at the time of the acquisition was established at $15 million, and the
interest rate was lowered to 1% above the bank's prime rate. See "Acquisition
Activities."
Our remaining long term debt outstanding at September 30, 2004 aggregated
$396,818 on a secured note issued in 1986 for the acquisition of our mineral
property in Alaska and $106,902 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.
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.
23
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.
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 September 30,
2004. Based on their evaluation, they have concluded that our disclosure
controls and procedures are
24
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 third 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 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits.
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
- ------- --------------------------------------------------------------------
3.1 Notice of Articles, certified on September 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 September 29, 2004).
3.2 Alteration to Notice of Articles, certified on September 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 September 29,
2004).
3.3 Articles dated September 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 September 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 September 13, 2003
(incorporated by reference to Exhibit 10.1 to Current Report on Form
8-K [File No. 0-12185] dated September 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).
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).
25
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 September 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.
Date: November 9, 2004 By: /s/ William S. Daugherty
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William S. Daugherty
Chief Executive Officer
(Duly Authorized Officer)
(Principal Executive Officer)
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