Attached files
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EX-31.2 - EX-31.2 - NGAS Resources Inc | l38408exv31w2.htm |
EX-32.1 - EX-32.1 - NGAS Resources Inc | l38408exv32w1.htm |
EX-31.1 - EX-31.1 - NGAS Resources Inc | l38408exv31w1.htm |
Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
AMENDMENT NO. 1 TO
FORM 10-Q
þ | QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Quarter Ended September 30, 2009
o | 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 (State or other jurisdiction of incorporation or organization) |
Not Applicable (I.R.S. Employer Identification No.) |
|
120 Prosperous Place, Suite 201 Lexington, Kentucky (Address of principal executive offices) |
40509-1844 (Zip Code) |
Registrants telephone number, including area code: (859) 263-3948
(Former name or former address, if changed since the last report)
Indicate by check mark if the registrant (1) filed all reports required to be filed by
Section 13 or 15(d) of the Act during the past 12 months and (2) has been subject to those filing
requirements for the past 90 days. Yes
þ No o
Indicate by check mark if the registrant has submitted electronically and posted on its
corporate website every indicative data file required to be submitted and posted pursuant to
Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes
þ No o
Indicate by check mark if the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 under the Exchange
Act).
Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o | Smaller reporting company o |
Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2).
Yes o No þ
Number
of shares outstanding of each of the registrants classes of common stock as of the latest
practicable date.
Title of Class | Outstanding at November 1, 2009 | |
Common Stock | 30,484,361 |
NGAS Resources, Inc.
INDEX TO FORM 10-Q/A
Part I. Financial Information
Additional Information
We file annual, quarterly and other reports and information with the Securities Exchange
Commission. Promptly after their filing, we provide access to these reports without charge on our
website at www.ngas.com. Our principal and administrative offices are located in Lexington,
Kentucky. Our common stock is traded on the Nasdaq Global Select Market under the symbol NGAS.
Unless otherwise indicated, references in this report to the company or to we, our or us include
NGAS Resources, Inc., our direct and indirect wholly owned subsidiaries and our interests in
sponsored drilling partnerships. As used in this report, Dth means decatherm, MMBtu means million
British thermal units, Mcf means thousand cubic feet, Mcfe means thousand cubic feet of natural gas
equivalents, Mmcf means million cubic feet, Bcf means billion cubic feet and EUR means estimated
ultimately recoverable volumes of natural gas or oil.
Explanatory Note
This amended report (10-Q/A) modifies some of the disclosures in our quarterly report on
Form 10-Q for the quarter ended September 30, 2009 (10-Q) in response to review comments by the
staff of the SEC. The 10-Q/A restates Part I of the 10-Q in its entirety but does not change any
disclosures except as noted below, and it does not update the 10-Q to reflect any other
developments or events after the date of the original filing.
| Condensed Consolidated Financial Statements The condensed consolidated financial statements have been restated to account for the embedded conversion feature of our 6% convertible notes as a derivative liability under ASC 815-40-15 (formerly EITF 07-5), which became effective as of January 1, 2009. The impact of the change in accounting principles is set forth in Note 2 Restatement Adjustments. |
| MD&A The recognition of non-cash interest expense for accretion of the debt discount and related adjustments from the change in accounting principles are reflected under the caption Results of Operations. |
| Certifications The certifications in the exhibits to the 10-Q have been updated as the date of this 10-Q/A. |
Table of Contents
NGAS Resources, Inc.
CONDENSED CONSOLIDATED BALANCE SHEETS
September 30, | December 31, | |||||||
2009 | 2008 | |||||||
(Unaudited) | ||||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash |
$ | 970,467 | $ | 981,899 | ||||
Accounts receivable |
5,372,800 | 10,450,173 | ||||||
Note receivable |
6,124,570 | | ||||||
Prepaid expenses and other current assets |
869,224 | 540,253 | ||||||
Loans to related parties |
76,024 | 79,188 | ||||||
Total current assets |
13,413,085 | 12,051,513 | ||||||
Bonds and deposits |
258,695 | 623,898 | ||||||
Note receivable |
8,375,430 | | ||||||
Oil and gas properties |
181,158,605 | 229,218,344 | ||||||
Property and equipment |
5,278,048 | 3,285,925 | ||||||
Loans to related parties |
171,429 | 171,429 | ||||||
Deferred financing costs |
1,439,399 | 1,689,580 | ||||||
Goodwill |
313,177 | 313,177 | ||||||
Total assets |
$ | 210,407,868 | $ | 247,353,866 | ||||
LIABILITIES |
||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 5,092,604 | $ | 12,362,092 | ||||
Accrued liabilities |
619,117 | 675,141 | ||||||
Deferred compensation |
| 2,246,439 | ||||||
Customer drilling deposits |
2,621,671 | 2,262,955 | ||||||
Long-term debt |
88,643 | 24,000 | ||||||
Total current liabilities |
8,422,035 | 17,570,627 | ||||||
Deferred compensation |
497,650 | | ||||||
Deferred income taxes |
13,520,833 | 12,949,476 | ||||||
Long-term debt |
68,860,828 | 109,270,818 | ||||||
Fair value of derivative financial instruments |
10,360 | | ||||||
Other long-term liabilities |
4,163,766 | 3,685,849 | ||||||
Total liabilities |
95,475,472 | 143,476,770 | ||||||
SHAREHOLDERS EQUITY |
||||||||
Capital stock |
||||||||
Authorized: |
||||||||
5,000,000 Preferred shares |
||||||||
100,000,000 Common shares |
||||||||
Issued: |
||||||||
30,484,361 Common shares (2008 26,543,646) |
117,142,639 | 110,626,912 | ||||||
21,100 Common shares held in treasury, at cost |
(23,630 | ) | (23,630 | ) | ||||
Paid-in capital options and warrants |
4,336,463 | 3,774,600 | ||||||
To be issued: |
||||||||
9,185 Common shares (2008 9,185) |
45,925 | 45,925 | ||||||
121,501,397 | 114,423,807 | |||||||
Deficit |
(6,569,001 | ) | (10,546,711 | ) | ||||
Total shareholders equity |
114,932,396 | 103,877,096 | ||||||
Total liabilities and shareholders equity |
$ | 210,407,868 | $ | 247,353,866 | ||||
See accompanying notes.
1
Table of Contents
NGAS Resources, Inc.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
REVENUE |
||||||||||||||||
Contract drilling |
$ | 3,831,250 | $ | 9,799,561 | $ | 16,328,000 | $ | 24,027,035 | ||||||||
Oil and gas production |
6,239,324 | 11,222,879 | 20,198,187 | 30,891,933 | ||||||||||||
Gas transmission, compression
and processing |
1,123,921 | 2,567,852 | 6,528,132 | 7,662,504 | ||||||||||||
Total revenue |
11,194,495 | 23,590,292 | 43,054,319 | 62,581,472 | ||||||||||||
DIRECT EXPENSES |
||||||||||||||||
Contract drilling |
2,913,418 | 7,570,698 | 12,328,110 | 18,447,544 | ||||||||||||
Oil and gas production |
2,658,985 | 3,922,629 | 7,598,044 | 9,794,679 | ||||||||||||
Gas transmission, compression
and processing |
960,879 | 1,039,597 | 2,955,204 | 3,087,391 | ||||||||||||
Total direct expenses |
6,533,282 | 12,532,924 | 22,881,358 | 31,329,614 | ||||||||||||
OTHER EXPENSES (INCOME) |
||||||||||||||||
Selling, general and administrative |
2,601,514 | 3,551,908 | 8,404,519 | 10,282,485 | ||||||||||||
Options, warrants and deferred compensation |
285,309 | 229,209 | 1,022,774 | 601,691 | ||||||||||||
Depreciation, depletion and amortization |
3,304,139 | 3,318,320 | 10,610,630 | 9,451,272 | ||||||||||||
Bad debt expense |
| 342,195 | | 749,035 | ||||||||||||
Interest expense |
2,196,091 | 1,457,300 | 6,892,550 | 4,138,913 | ||||||||||||
Interest income |
(52,698 | ) | (10,774 | ) | (67,708 | ) | (89,577 | ) | ||||||||
Gain on sale of assets |
(3,356,177 | ) | | (3,369,082 | ) | | ||||||||||
Fair value (gain) loss on derivative financial instruments |
4,847 | | (4,477 | ) | | |||||||||||
Other, net |
292,073 | 87,584 | 600,896 | 115,939 | ||||||||||||
Total other expenses |
5,275,098 | 8,975,742 | 24,090,102 | 25,249,758 | ||||||||||||
INCOME (LOSS) BEFORE INCOME TAXES |
(613,885 | ) | 2,081,626 | (3,917,141 | ) | 6,002,100 | ||||||||||
INCOME TAX EXPENSE |
508,116 | 1,136,441 | 571,357 | 3,372,464 | ||||||||||||
NET INCOME (LOSS) |
$ | (1,122,001 | ) | $ | 945,185 | $ | (4,488,498 | ) | $ | 2,629,636 | ||||||
NET INCOME (LOSS) PER SHARE |
||||||||||||||||
Basic |
$ | (0.04 | ) | $ | 0.04 | $ | (0.16 | ) | $ | 0.10 | ||||||
Diluted |
$ | (0.04 | ) | $ | 0.04 | $ | (0.16 | ) | $ | 0.10 | ||||||
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING: |
||||||||||||||||
Basic |
28,873,105 | 26,508,570 | 27,508,925 | 26,364,158 | ||||||||||||
Diluted |
28,873,105 | 26,977,438 | 27,508,925 | 27,019,313 | ||||||||||||
See accompanying notes.
2
Table of Contents
NGAS Resources, Inc.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
OPERATING ACTIVITIES |
||||||||||||||||
Net income (loss) |
$ | (1,122,001 | ) | $ | 945,185 | $ | (4,488,498 | ) | $ | 2,629,636 | ||||||
Adjustments
to reconcile net income (loss) to net cash provided by operating activities: |
||||||||||||||||
Incentive bonus paid in common shares |
65,001 | 228,120 | 426,251 | 259,690 | ||||||||||||
Options, warrants and deferred compensation |
285,309 | 229,209 | 1,022,774 | 601,691 | ||||||||||||
Depreciation, depletion and amortization |
3,304,139 | 3,318,320 | 10,610,630 | 9,451,272 | ||||||||||||
Bad debt expense |
| 342,195 | | 749,035 | ||||||||||||
Gain on sale of assets |
(3,356,177 | ) | (10,761 | ) | (3,369,082 | ) | (11,116 | ) | ||||||||
Fair value (gain) loss on
derivative financial instruments |
4,847 | | (4,477 | ) | | |||||||||||
Accretion of debt discount |
1,004,682 | | 2,869,276 | | ||||||||||||
Deferred income taxes |
508,116 | 1,136,441 | 571,357 | 3,372,464 | ||||||||||||
Changes in assets and liabilities: |
||||||||||||||||
Accounts receivable |
311,360 | (1,840,648 | ) | 5,077,373 | (5,983,968 | ) | ||||||||||
Prepaid expenses and other current assets |
(353,376 | ) | (345,152 | ) | (328,971 | ) | (227,538 | ) | ||||||||
Other non-current assets |
| | | 3,242,790 | ||||||||||||
Accounts payable |
(144,533 | ) | 2,979,900 | (7,269,488 | ) | 3,684,584 | ||||||||||
Accrued liabilities |
(46,040 | ) | 261,981 | (56,024 | ) | 469,599 | ||||||||||
Deferred compensation |
(2,094,700 | ) | | (2,209,700 | ) | | ||||||||||
Customers drilling deposits |
1,923,271 | (1,630,304 | ) | 358,716 | (2,857,806 | ) | ||||||||||
Other long-term liabilities |
155,091 | | 477,917 | | ||||||||||||
Net cash provided by operating activities |
444,989 | 5,614,486 | 3,688,054 | 15,380,333 | ||||||||||||
INVESTING ACTIVITIES |
||||||||||||||||
Proceeds from sale of assets |
35,857,613 | 15,855 | 35,911,646 | 54,555 | ||||||||||||
Purchase of property and equipment |
(195,261 | ) | (155,170 | ) | (2,683,061 | ) | (459,671 | ) | ||||||||
Change in bonds and deposits |
5,000 | (95,250 | ) | 15,203 | (130,750 | ) | ||||||||||
Additions to oil and gas properties, net |
(3,841,799 | ) | (11,615,165 | ) | (7,918,894 | ) | (37,940,322 | ) | ||||||||
Net cash provided by (used in)
investing activities |
31,825,553 | (11,849,730 | ) | 25,324,894 | (38,476,188 | ) | ||||||||||
FINANCING ACTIVITIES |
||||||||||||||||
Decrease in loans to related parties |
890 | 1,861 | 3,164 | 4,538 | ||||||||||||
Proceeds from issuance of common shares |
6,089,476 | 81,200 | 6,089,476 | 1,190,006 | ||||||||||||
Payments of deferred financing costs |
(10,882 | ) | (297,440 | ) | (383,442 | ) | (440,983 | ) | ||||||||
Proceeds from issuance of long-term debt |
| 5,500,000 | | 22,240,000 | ||||||||||||
Payments of long-term debt |
(45,021,578 | ) | (6,000 | ) | (34,733,578 | ) | (2,032,175 | ) | ||||||||
Net cash provided by (used in)
financing activities |
(38,942,094 | ) | 5,279,621 | (29,024,380 | ) | 20,961,386 | ||||||||||
Change in cash |
(6,671,552 | ) | (955,623 | ) | (11,432 | ) | (2,134,469 | ) | ||||||||
Cash, beginning of period |
7,642,019 | 1,637,832 | 981,899 | 2,816,678 | ||||||||||||
Cash, end of period |
$ | 970,467 | $ | 682,209 | $ | 970,467 | $ | 682,209 | ||||||||
SUPPLEMENTAL DISCLOSURE |
||||||||||||||||
Interest paid |
$ | 1,204,354 | $ | 1,456,786 | $ | 4,026,548 | $ | 4,138,104 | ||||||||
Income taxes paid |
| | | |
See accompanying notes.
3
Table of Contents
NGAS Resources, Inc.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1. Summary of Significant Accounting Policies
(a) General. The accompanying condensed consolidated financial statements of NGAS
Resources, Inc. (NGAS) have been prepared in accordance with accounting principles generally
accepted in the United States (U.S. GAAP). Our accounting policies are described in Note 1 to the
consolidated financial statements in our annual report on Form 10-K for the year ended December 31,
2008. Our accounting policies and their method of application in the accompanying condensed
consolidated financial statements are consistent with those described in the annual report.
(b) Basis of Presentation. The accompanying condensed consolidated financial
statements include the accounts of NGAS, our wholly owned subsidiary, Daugherty Petroleum, Inc.
(DPI), and its wholly owned subsidiaries. The condensed consolidated financial statements also
reflect DPIs interests in a total of 39 drilling partnerships sponsored to participate in many of
our drilling initiatives. We account for those interests using the proportionate consolidation
method, with all material inter-company accounts and transactions eliminated on consolidation.
References to the company, we, our or us include DPI, its subsidiaries and interests in sponsored
drilling partnerships. These interim consolidated financial statements are unaudited and have been
restated for the three months and nine months ended September 30, 2009 to reflect the adoption of
Accounting Standards Codification (ASC) Topic 815-40-15, Contracts in Entitys Own Equity (formerly
EITF 07-5), which became effective as of January 1, 2009. See Note 2 Restatement Adjustments. In
the opinion of our management, the accompanying condensed consolidated financial statements reflect
all normal recurring adjustments that, in the opinion of our management, are necessary to fairly
present our financial position at September 30, 2009 and results of operations and cash flows for
the three months and nine months ended September 30, 2009 and 2008.
(c) Estimates. The preparation of financial statements in conformity with U.S. GAAP
requires us to make estimates and assumptions that affect the reported amounts of assets and
liabilities and the disclosure of contingent assets and liabilities as of the date of the
consolidated financial statements and the reported amounts of revenues and expenses during the
reporting periods. The most significant estimates pertain to proved oil and gas reserves and
related cash flow estimates used in impairment tests of goodwill and other long-lived assets,
estimates of future development, dismantlement and abandonment costs and estimates relating to
future oil and gas revenues and expenses. We also make estimates and assumptions in maintaining
allowances for doubtful accounts when appropriate to reflect losses that could result from payment
failures by our customers or counterparties. The evaluations required for these estimates involve
significant uncertainties, and actual results could differ from the estimates.
Note 2. Restatement Adjustments
(a) Change in Accounting Principle. Effective as of January 1, 2009, we adopted the
revised guidance for equity-linked financial instruments now codified in ASC 815-40-15, which
requires the embedded conversion feature of our 6% convertible notes to be bifurcated and treated
as a derivative liability based on its fair value as a stand-alone instrument. The notes were
issued in December 2005 in the principal amount of $37 million. See Note 8 Long-Term Debt.
Under the revised guidance, the notes are no longer considered to be linked to our own stock due to
the weighted average antidilution provisions in their embedded conversion feature. As a result,
the notes no longer qualify for the scope exception from derivative fair value accounting under
ASC 815-15, Derivatives and Hedging Embedded Derivatives (formerly contained in SFAS 133).
(b) Cumulative Effect Adjustments. The transition provisions of ASC 815-40-15 require
cumulative effect adjustments as of January 1, 2009 to reflect the amounts that would have been
recognized if derivative fair value accounting had been applied from the original issuance date of
an equity-linked financial instrument through the implementation date of the revised guidance. Our
fair value analysis of the notes reflects an initial derivative liability of $16,575,445 for their
embedded conversion feature, primarily reflecting their five-year maturity and 10% conversion
premium at issuance. From the note issuance date through the end of 2008, we would have recorded
fair value gains on derivative financial instruments of $16,560,608, offset by non-cash interest
expenses totaling $8,094,400, reflecting accretion of the debt discount under the effective
interest method. The following table shows the cumulative effect adjustment to retained deficit at
January 1, 2009.
4
Table of Contents
Retained Deficit | ||||
Cumulative Effect Adjustment: |
||||
As previously reported, December, 31, 2008 |
$ | (10,546,711 | ) | |
Cumulative effect adjustment |
8,466,208 | |||
As adjusted, January 1, 2009 |
$ | (2,080,503 | ) | |
(c) Impact on Interim Financial Statements. As restated at September 30, 2009, the
carrying amount of our convertible notes has been recorded at $31,388,231. This reflects the
unaccreted debt discount to their face amount of $37 million. In addition, a derivative liability
has been established at $10,360, representing the fair value of the embedded conversion feature at
the balance sheet date. The following table shows the adjustments on restatement of the condensed
consolidated statements of operations previously reported for the three months and nine months
ended September 30, 2009. The adjustments to interest expense reflect accretion of the debt
discount under the effective interest method. The fair value gains on derivative financial
instruments reflect mark-to market changes in the fair value of the embedded derivative.
As Previously | Restatement | As | ||||||||||
Reported | Adjustments | Restated | ||||||||||
Three Months Ended September 30, 2009: |
||||||||||||
Total revenue |
$ | 11,194,495 | $ | | $ | 11,194,495 | ||||||
Total direct expenses |
6,533,282 | | 6,533,282 | |||||||||
Other expenses (income) |
||||||||||||
Selling, general and administrative |
2,601,514 | | 2,601,514 | |||||||||
Options, warrants and deferred compensation |
285,309 | | 285,309 | |||||||||
Depreciation, depletion and amortization |
3,304,139 | | 3,304,139 | |||||||||
Interest expense |
1,191,409 | 1,004,682 | 2,196,091 | |||||||||
Interest income |
(52,698 | ) | | (52,698 | ) | |||||||
Gain on sale of assets |
(3,356,177 | ) | | (3,356,177 | ) | |||||||
Fair value loss on derivative financial instruments |
| 4,847 | 4,847 | |||||||||
Other, net |
292,073 | | 292,073 | |||||||||
Total other expenses |
4,265,569 | 1,009,529 | 5,275,098 | |||||||||
Income (loss) before income taxes |
395,644 | | (613,885 | ) | ||||||||
Income tax expense |
508,116 | | 508,116 | |||||||||
Net loss |
$ | (112,472 | ) | $ | (1,009,529 | ) | $ | (1,122,001 | ) | |||
EPS basic and diluted |
$ | (0.00 | ) | $ | (0.04 | ) | $ | (0.04 | ) | |||
As Previously | Restatement | As | ||||||||||
Reported | Adjustments | Restated | ||||||||||
Nine Months Ended September 30, 2009: |
||||||||||||
Total revenue |
$ | 43,054,319 | $ | | $ | 43,054,319 | ||||||
Total direct expenses |
22,881,358 | | 22,881,358 | |||||||||
Other expenses (income) |
||||||||||||
Selling, general and administrative |
8,404,519 | | 8,404,519 | |||||||||
Options, warrants and deferred compensation |
1,022,774 | | 1,022,774 | |||||||||
Depreciation, depletion and amortization |
10,610,630 | | 10,610,630 | |||||||||
Interest expense |
4,023,274 | 2,869,276 | 6,892,550 | |||||||||
Interest income |
(67,708 | ) | | (67,708 | ) | |||||||
Gain on sale of assets |
(3,369,082 | ) | | (3,369,082 | ) | |||||||
Fair value (gain) loss on derivative financial instruments |
| (4,477 | ) | (4,477 | ) | |||||||
Other, net |
600,896 | | 600,896 | |||||||||
Total other expenses |
21,225,303 | 2,864,799 | 24,090,102 | |||||||||
Loss before income taxes |
1,052,342 | (2,864,799 | ) | 3,917,141 | ||||||||
Income tax expense |
571,357 | | 571,357 | |||||||||
Net loss |
$ | (1,623,699 | ) | $ | (2,864,799 | ) | $ | (4,488,498 | ) | |||
EPS basic and diluted |
$ | (0.06 | ) | $ | (0.10 | ) | $ | (0.16 | ) | |||
5
Table of Contents
Note 3. Oil and Gas Properties
(a) Sale of Appalachian Gas Gathering Facilities. On July 15, 2009, we sold a 50%
undivided interest in 485 miles of our Appalachian gas gathering facilities (Gathering System) to
Seminole Gas Company, L.L.C. (Seminole) for $28 million. As part of the transaction, we entered
into various joint ownership, gas marketing and gas sales arrangements with Seminole and its parent
company, Seminole Energy Services, LLC (Seminole Energy). Under these arrangements, we retained
operating rights for the Gathering System and firm capacity rights for daily delivery of 30,000 Mcf
of controlled gas through the system. We also granted Seminole Energy a six-month option to
purchase our retained 50% interest in the Gathering System for $22 million, payable $7.5 million at
closing and the balance over 30 months under a promissory note bearing interest at 8% per annum.
See Note 5 Note Receivable. We reserved the right to require Seminole Energy to exercise its
purchase option, conditioned on our completion of an equity offering for at least $5 million. On
August 17, 2009, after satisfying that condition, we closed the sale of our remaining interest in
the Gathering System to Seminole Energy under the terms of its purchase option. See Note 10 -
Capital Stock. All of our proceeds from the Gathering System sale were applied to debt reduction.
See Note 9 Long-Term Debt.
(b) Capitalized Costs and DD&A. All of our oil and gas development and producing
activities are conducted within the continental United States. Capitalized costs and accumulated
depreciation, depletion and amortization (DD&A) for our oil and gas properties, gathering
facilities and well equipment as of September 30, 2009 and December 31, 2008 are summarized below.
Capitalized costs and accumulated DD&A for our gathering system and well equipment at September 30,
2009 were reduced by $51,571,070 and $5,301,027, respectively, from our sale of the Gathering
System during the third quarter of 2009.
September 30, | December 31, | |||||||
2009 | 2008 | |||||||
Proved oil and gas properties |
$ | 197,922,674 | $ | 192,186,676 | ||||
Unproved oil and gas properties |
5,209,182 | 5,065,835 | ||||||
Gathering facilities and well equipment |
17,421,334 | 67,326,445 | ||||||
220,553,190 | 264,578,956 | |||||||
Accumulated DD&A |
(39,394,585 | ) | (35,360,612 | ) | ||||
Net oil and gas properties and equipment |
$ | 181,158,605 | $ | 229,218,344 | ||||
(c) Suspended Well Costs. We had no suspended exploratory wells costs that were
required to be expensed during 2008 or the first nine months of 2009 based on the criteria of FSP
No. 19-1, Accounting for Suspended Well Costs.
Note 4. Property and Equipment
The following table presents the capitalized costs and accumulated depreciation for our other
property and equipment as of September 30, 2009 and December 31, 2008.
September 30, | December 31, | |||||||
2009 | 2008 | |||||||
Land |
$ | 12,908 | $ | 12,908 | ||||
Building improvements |
64,265 | 64,265 | ||||||
Machinery and equipment |
5,839,686 | 3,333,981 | ||||||
Office furniture and fixtures |
175,862 | 175,862 | ||||||
Computer and office equipment |
690,905 | 670,349 | ||||||
Vehicles |
1,811,276 | 1,951,279 | ||||||
8,594,902 | 6,208,644 | |||||||
Accumulated depreciation |
(3,316,854 | ) | (2,922,719 | ) | ||||
Net other property and equipment |
$ | 5,278,048 | $ | 3,285,925 | ||||
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Note 5. Note Receivable
As part of the purchase price for the Gathering System, we received a promissory note issued
by Seminole Energy on August 17, 2009 in the original principal amount of $14.5 million. See Note
3 Oil and Gas Properties. The note is payable in equal monthly installments through December
2011, with interest at 8% per annum. Performance of the note is secured by a second mortgage lien
on Seminole Energys 50% interest in the Gathering System assets. We have assigned the note as
part of the collateral package under our revolving credit facility and will apply all payments of
principal and interest under the note to reduce our credit facility debt. See Note 9 Long-Term
Debt.
Note 6. Deferred Financing Costs
Financing costs for our convertible notes and revolving credit facility are initially
capitalized and amortized at rates based on the terms of the underlying debt instruments. See
Note 9 Long-Term Debt. Upon conversion of convertible notes, the principal amount converted is
added to equity, net of a proportionate amount of the original financing costs. Unamortized
deferred financing costs for our outstanding notes and credit facility aggregated $1,439,399 at
September 30, 2009 and $1,689,580 at December 31, 2008.
Note 7. Goodwill
Goodwill of $1,789,564 was recorded in connection with our acquisition of DPI in 1993 and was
amortized over ten years on a straight-line basis until 2002, when we adopted the Canadian
equivalent of Financial Accounting Standards (SFAS) No. 142, Goodwill and Other Intangible Assets.
Under the adopted standard, goodwill is no longer amortized but is instead tested for impairment at
least annually. Our annual analyses indicated that no impairment charges were required.
Accordingly, accumulated amortization of goodwill remained at $1,476,387 as of September 30, 2009
and December 31, 2008, with unamortized goodwill of $313,177.
Note 8. Customer Drilling Deposits
Net proceeds received under drilling contracts with sponsored partnerships and joint ventures
are recorded as customer drilling deposits at the time of receipt. We recognize revenues from
drilling operations on the completed contract method as the wells are drilled, rather than when
funds are received. We had customer drilling deposits of $2,621,671 at September 30, 2009 and
$2,262,955 at December 31, 2008, representing unapplied drilling contract payments for wells that
were not yet drilled as of the balance sheet dates.
Note 9. Long-Term Debt
(a) Convertible Notes. We have an outstanding series of 6% convertible notes due
December 15, 2010 in the aggregate principal amount of $37 million. The notes are convertible into
our common shares at a conversion price of $11.16, reflecting an anti-dilution adjustment from our
registered direct placement in August 2009. See Note 10 Capital Stock. Upon any event of
default under the notes or any change of control, we may be required to redeem the notes at
specified premiums above their face amount. Notes that are neither redeemed nor converted prior to
maturity will be repayable in cash or common shares, valued for that purpose at 92.5% of their
market price.
(b) Credit Facility. We have a revolving credit facility maintained by DPI under a
credit agreement with KeyBank National Association, as administrative agent. The facility provides
for loans and letters of credit in an aggregate amount up to $125 million, with a scheduled
maturity in September 2011. Credit availability under the facility is subject to borrowing base
limits, as determined semi-annually by the lenders. Interest is payable at fluctuating rates
ranging from the agents prime rate to 2.25% above that rate, depending on borrowing base
utilization. We are also responsible for commitment fees ranging from 0.375% to 0.5% of the unused
borrowing base. The facility is guaranteed by NGAS and is secured by liens on DPIs oil and gas
properties.
As of September 30, 2009, we had outstanding borrowings of $35 million under the facility,
with a borrowing base of $55 million. This reflects debt reductions totaling $41.5 million from
proceeds of our Gathering System sale and equity raise in the third quarter of 2009 and a borrowing
base reduction of $25 million in July 2009 from lower commodity prices and the release of our
Gathering System assets from the collateral package. See Note 10 Capital Stock. A related
amendment to the credit agreement provides for the further debt reduction from payments under our
note receivable issued by Seminole Energy as part of the purchase price for our Gathering System.
See Note 5 Note Receivable.
(c) Installment Loan. In June 2009, DPI obtained a $2.3 million loan from Central
Bank & Trust Co. to finance the balance of its commitment under an airplane purchase contract
entered in 2005. The loan bears interest
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at 5.875% per annum and is repayable in monthly installments of $16,428 over a three-year
term, with the balance due at the end of the term, unless extended by the bank. The loan is
secured by a lien on the airplane and had an outstanding balance of $2,284,422 at September 30,
2009.
(d) Acquisition Debt. We issued a note for $854,818 in 1986 to finance our
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. The outstanding
acquisition debt was $276,818 at September 30, 2009.
(e) Total Long-Term Debt and Maturities. The following tables summarize our total
long-term debt at September 30, 2009, as restated, and December 31, 2008 and the principal payments
due each year through 2013 and thereafter.
Restated | ||||||||
September 30, | December 31, | |||||||
2009 | 2008 | |||||||
Principal Amount Outstanding |
||||||||
Total long-term debt (including current portion)(1) |
$ | 68,949,471 | $ | 109,294,818 | ||||
Less current portion |
88,643 | 24,000 | ||||||
Total long-term debt |
$ | 68,860,828 | $ | 109,270,818 | ||||
Maturities of Debt |
||||
Remainder of 2009 |
$ | 27,807 | ||
2010 |
31,477,828 | (1) | ||
2011 |
35,093,557 | |||
2012 |
2,157,461 | |||
2013 and thereafter |
192,818 |
(1) | Reflects the carrying amount of our 6% convertible notes in the principal amount of $37,000,000, net of the unamortized debt discount of $5,611,769 at September 30, 2009 attributable to their embedded conversion feature. See Note 2 Restatement Adjustments. |
Note 10. Capital Stock
(a) Preferred Shares. We have 5,000,000 authorized shares of preferred stock, none of
which were outstanding at September 30, 2009 or December 31, 2008.
(b) Common Shares. On August 13, 2009, we completed a registered direct placement of
3.48 million units under our existing shelf registration statement at $1.90 per unit. Each unit
consists of one share of our common stock and a warrant to buy 0.5 common share. The following
table reflects the direct placement and other transactions involving our equity securities during
the reported periods.
Number of | ||||||||
Shares | Amount | |||||||
Common Shares Issued |
||||||||
Balance, December 31, 2007 |
26,136,064 | $ | 108,842,526 | |||||
Issued to employees as incentive bonus |
50,000 | 259,690 | ||||||
Issued upon exercise of stock options |
357,582 | 1,524,696 | ||||||
Balance, December 31, 2008 |
26,543,646 | 110,626,912 | ||||||
Issued in registered direct placement |
3,480,000 | 6,089,476 | ||||||
Issued as stock awards under incentive plan |
460,715 | 426,251 | ||||||
Balance, September 30, 2009 |
30,484,361 | $ | 117,142,639 | |||||
Paid In Capital Options and Warrants |
||||||||
Balance, December 31, 2007 |
3,484,148 | |||||||
Recognized |
625,142 | |||||||
Exercised |
(334,690 | ) | ||||||
Balance, December 31, 2008 |
3,774,600 | |||||||
Recognized |
561,863 | |||||||
Balance, September 30, 2009 |
$ | 4,336,463 | ||||||
Common Shares to be Issued |
||||||||
Balance, September 30, 2009 and December 31, 2008 |
9,185 | $ | 45,925 | |||||
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(c) Stock Options and Awards. We maintain three equity incentive plans for the
benefit of our directors, officers, employees and certain consultants. The plans provide for the
grant of options to purchase up to 3.6 million common shares and, in the case of our most recent
plan, either stock awards or options for an aggregate of up to 4 million common shares. Stock
awards under the third plan may be subject to restrictions, and option grants under all three plans
must be at prevailing market prices and may be subject to vesting requirements. Stock awards were
made for a total of 460,715 shares during the first nine months of 2009 and 50,000 shares during
2008. Transactions in stock options during those periods are shown in the following table.
Weighted Average | ||||||||||||
Issued | Exercisable | Exercise Price | ||||||||||
Balance, December 31, 2007 |
2,681,250 | 1,739,583 | $ | 4.75 | ||||||||
Granted |
2,300,000 | | 2.93 | |||||||||
Vested |
| 41,667 | 6.02 | |||||||||
Exercised |
(357,582 | ) | (357,582 | ) | 3.33 | |||||||
Forfeited |
(10,000 | ) | (10,000 | ) | 7.04 | |||||||
Balance, December 31, 2008 |
4,613,668 | 1,413,668 | 3.95 | |||||||||
Vested |
| 1,225,000 | 4.69 | |||||||||
Expired |
(740,000 | ) | (740,000 | ) | 4.06 | |||||||
Balance, September 30, 2009 |
3,873,668 | 1,898,668 | 3.92 | |||||||||
At September 30, 2009, the exercise prices of options outstanding under our equity plans
ranged from $1.51 to $7.64 per share, and their weighted average remaining contractual life was
3.06 years. The following table provides additional information on the terms of stock options
outstanding at September 30, 2009.
Options Outstanding | Options Exercisable | |||||||||||||||||||||
Weighted | Weighted | Weighted | ||||||||||||||||||||
Exercise | Average | Average | Average | |||||||||||||||||||
Price | Remaining | Exercise | Exercise | |||||||||||||||||||
or Range | Number | Life (years) | Price | Number | Price | |||||||||||||||||
$ | 1.51 | 1,650,000 | 5.61 | $ | 1.51 | | $ | | ||||||||||||||
4.03 | 800,000 | 0.41 | 4.03 | 800,000 | 4.03 | |||||||||||||||||
6.02 7.64 | 1,423,668 | 1.61 | 6.66 | 1,098,668 | 6.70 | |||||||||||||||||
3,873,668 | 1,898,668 | |||||||||||||||||||||
In accounting for stock options, we apply the fair value recognition provisions of SFAS
No. 123(R), Share-Based Payment. We use the Black-Scholes pricing model to determine the fair
value of each stock option at the grant date, and we recognize the compensation cost ratably over
the vesting period. For the periods presented in the interim consolidated financial statements,
the fair value estimates for each option grant assumed a risk free interest rate ranging from 0.03%
to 6%, no dividend yield, a theoretical volatility ranging from 0.30 to 0.85 and an expected life
ranging from three months to six years based on the vesting provisions of the options. This
resulted in non-cash charges for options and warrants of $625,142 in 2008 and $561,863 in the first
nine months of 2009.
(d) Common Stock Purchase Warrants. As part of our registered direct equity placement
on August 13, 2009, we issued warrants to purchase 1.74 million shares of our common stock at $2.35
per share, subject to adjustment for certain dilutive issuances. The warrants will be exercisable
for four years, beginning six months after issuance.
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Note 11. Income (Loss) Per Share
The following table shows the computation of basic and diluted earnings (loss) per share (EPS)
for the reporting periods.
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Restated | Restated | |||||||||||||||
Numerator: |
||||||||||||||||
Net income (loss) as reported for basic EPS |
$ | (1,122,001 | ) | $ | 945,185 | $ | (4,488,498 | ) | $ | 2,629,636 | ||||||
Adjustments to income (loss) for diluted EPS |
| | | | ||||||||||||
Net income (loss) for diluted EPS |
$ | (1,122,001 | ) | $ | 945,185 | $ | (4,488,498 | ) | $ | 2,629,636 | ||||||
Denominator: |
||||||||||||||||
Weighted average shares for basic EPS |
28,873,105 | 26,508,570 | 27,508,925 | 26,364,158 | ||||||||||||
Effect of dilutive securities options/warrants |
| 468,868 | | 655,155 | ||||||||||||
Adjusted weighted average shares and
assumed conversions for diluted EPS |
28,873,105 | 26,977,438 | 27,508,925 | 27,019,313 | ||||||||||||
Basic EPS |
$ | (0.04 | ) | $ | 0.04 | $ | (0.16 | ) | $ | 0.10 | ||||||
Diluted EPS |
$ | (0.04 | ) | $ | 0.04 | $ | (0.16 | ) | $ | 0.10 | ||||||
Note 12. Segment Information
We have a single reportable operating segment for our oil and gas business based on the
integrated way we are organized by management in making operating decisions and assessing
performance. Although our financial reporting reflects our separate revenue streams from drilling,
production and transmission activities and the direct expenses for each component, we do not
consider the components as discreet operating segments under SFAS No. 131, Disclosure about
Segments of an Enterprise and Related Information.
Note 13. Commitments
(a) General. We incurred operating lease expenses of $2,583,417 in 2008 and
$2,024,745 in the first nine months of 2009. As of September 30, 2009, we had future obligations
under operating leases in the amounts listed below.
Maturities of Lease Obligations |
||||
Remainder of 2009 |
$ | 604,704 | ||
2010 |
2,350,495 | |||
2011 |
2,095,224 | |||
2012 |
847,442 | |||
2013 and thereafter |
73,284 | |||
Total |
$ | 5,971,149 | ||
(b) Gas Gathering and Sales Commitments. We have various long-term commitments under
our gas gathering and sales agreements entered with Seminole and Seminole Energy in connection with
our sale of the Gathering System during the third quarter of 2009. These include (i) base monthly
gathering fees of $850,000, with annual escalations at the rate of 1.5%, (ii) base monthly
operating fees of $175,000, plus $0.20 per Mcf of purchased gas, and (iii) monthly capital fees in
amounts intended to yield a 20% internal rate of return for all capital expenditures on the
Gathering System by Seminole and Seminole Energy. These agreements have an initial term of fifteen
years with extension rights.
Note 13. Recent Accounting Standards
SFAS No. 168. In July 2009, the FASB issued SFAS No. 168, Accounting Standards
Codification and the Hierarchy of Generally Accepted Accounting Principles. Effective for
financial statements covering periods ending after September 15, 2009, the Codification changes the
references to existing accounting pronouncements, superseding all prior accounting standards under
U.S. GAAP, aside from those issued by the SEC. The guidance currently provided in the Codification
has not had any impact on our consolidated financial statements.
Oil and Gas Reporting Requirements. In December 2008, the SEC amended its oil and gas
reporting rules under the Exchange Act and Industry Guides. The revisions are intended to provide
investors with a more meaningful and comprehensive understanding of oil and gas reserves by
aligning the oil and gas disclosure requirements with current industry practices and technology.
The amendments will be effective for fiscal years ending on or after December 31, 2009 and will
significantly impact reserve and resource reporting for all E&P companies.
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NGAS Resources, Inc.
Item 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Item 2. | MANAGEMENTS DISCUSSION AND ANALYSIS OF | |||
FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
General
We are an independent exploration and production company focused on unconventional natural gas
plays in the eastern United States, principally in the southern portion of the Appalachian Basin.
We have specialized for over 20 years in generating our own geological prospects in this region,
where we have established expertise and recognition. During the last two years, we have
successfully transitioned to horizontal drilling and extended our operations to the Illinois Basin.
We believe our extensive operating experience, coupled with our relationships with partners,
suppliers and mineral interest owners, gives us competitive advantages in developing these
resources to achieve sustained volumetric growth and strong financial returns on a long-term basis.
Recent Developments
Liquidity from Gathering System Sale and Equity Raise. On July 15, 2009, we sold a
50% undivided interest in 485 miles of our Appalachian gas gathering facilities (Gathering System)
to Seminole Gas Company, L.L.C. (Seminole) for $28 million. As part of the transaction, we entered
into various gas marketing and gas sales arrangements with Seminole and its parent company,
Seminole Energy Services, LLC (Seminole Energy). Under these arrangements, we retained operating
rights for the Gathering System and firm capacity rights for daily delivery of 30,000 Mcf of
controlled gas, ensuring long-term deliverability for our Appalachian production through the
system. We also granted Seminole Energy a six-month option to purchase our retained 50% interest
in the Gathering System for $22 million, payable $7.5 million in cash and the balance over
30 months under a promissory note bearing interest at 8% per annum. We reserved the right to
trigger the exercise of the purchase option, conditioned on our completion of a qualifying equity
offering. On August 17, 2009, after satisfying that condition, we closed the sale of our remaining
interest in the Gathering System to Seminole Energy under the terms of its purchase option.
Proceeds of $35.5 million from the Gathering System sale and approximately $6.1 million from the
equity raise were applied to debt reduction under our revolving credit facility. Liquidity from
these transactions has provided us with greater flexibility to take advantage of our development
opportunities.
Expansion of Leatherwood Position. In October 2009, we expanded our position in our
key Leatherwood field with the acquisition of a lease covering 10,300 gross (8,280 net) undeveloped
acres in Leslie and Harlan Counties, Kentucky. The lease provides the mineral interest owner with
participation rights for up to 50% of the working interest in wells drilled on the covered acreage
and requires us to drill at least three horizontal wells by the end of March 2011, followed by a
two-well annual drilling commitment. Combined with the farmout we acquired earlier in the year
from Chesapeake Appalachia, LLC for a significant tract next to the Amvest portion of our Stone
Mountain field in Letcher and Harlan Counties, Kentucky, this brings our holdings in the
Appalachian Basin to a total of 339,000 gross (241,000 net) acres.
Business Strategy
Over 70% of our properties in the Appalachian Basin are undeveloped, along with most of our
assembled acreage in the Illinois Basin. Our business is structured for efficient development of
these unconventional resource plays, which have been transformed by our use of horizontal drilling
throughout our operating areas. We began this transition early in 2008 and had 20 horizontal wells
on line at year-end, with an additional five horizontals producing to sales at the end of September
2009. Our success with these initiatives contributed to growth in our production volumes to
3.7 Bcfe in 2008, up 13% over 2007. Despite substantially reduced drilling activity this year, we
produced 997 Mmcf of natural gas equivalents in the third quarter of 2009. This represents a 5%
increase from the same quarter last year, but a 4% decline from record production volumes in the
2009 first quarter. Having strengthened our balance sheet with added liquidity in the third
quarter, our extensive inventory of horizontal drilling locations positions us for future growth
under a sustainable, low-cost structure with several components.
| Organic Growth through Drilling with Reduced Capital Spending. While we are committed to a long-term strategy of developing our reserves through the drillbit and retaining most of our available working interest in new wells, we have addressed the challenging conditions in our industry by reducing our 2009 capital spending budget to $15 million and returning to our successful partnership structure for sharing development costs on operated properties. We raised over $34 million for a non-operated program last year through our established sales network. To meet our near-term drilling commitments and objectives, we are currently sponsoring a partnership to participate in up to 53 horizontal wells throughout our operated |
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properties. The partnership commenced operations following an initial closing of its private placement in June 2009. We are maintaining a 20% interest in this years program and will earn an additional 15% reversionary interest after program payout. | ||
| Horizontal Drilling Initiatives. Recent advances in horizontal drilling and completion technology have enhanced the value proposition for our operated properties by substantially increasing our recovery volumes and rates at dramatically lower finding costs. Horizontal drilling also gives us access to areas where natural gas development would otherwise be delayed or constrained by coal mining activity or challenging terrain. We focused these initiatives during 2008 in our Leatherwood field, where we completed 20 horizontal wells last year. Each well has a single lateral leg up to 3,500 feet through the Devonian shale formation, which is present throughout our Appalachian operating areas. Initial 30-day flow rates for our Leatherwood horizontals averaged 309 Mcf per day. We achieved comparable results for our first two New Albany shale horizontals drilled late in 2008 on our Illinois Basin acreage and our initial Devonian shale horizontals completed this year in our Straight Creek, Fonde and Martins Fork fields. We plan to continue this transition throughout our operated properties, including 25 horizontal wells planned this year in Leatherwood. | |
| Advantages from Restructured Infrastructure Position. Although the sale of our Gathering System during the third quarter of 2009 eliminated the closed-access status for most of our field-wide infrastructure, we retained long-term capacity rights for the system, currently established at 30,000 Mcf per day. This ensures continued deliverability from our operated Appalachian properties serviced by these facilities. We also retained operating rights for the Gathering System, which provides deliverability from 90% of our Appalachian properties directly from the wellhead to major east coast natural gas markets through an interconnect with Spectra Energy Partners East Tennessee Interstate pipeline network. Our operating and capacity rights also preserve our competitive advantages from control of regional gas flow, enhancing our opportunities to acquire undeveloped acreage near our core producing fields upon completion of coal mining activities. We continue to own a 50% interest in a liquids extraction plant for production serviced by the Gathering System, located in Rogersville, Tennessee. This is within 5.5 miles of the proposed site for a 880-megawatt gas-fired power plant to be constructed by the Tennessee Valley Authority, which may provide us with opportunities for long-term gas sales arrangements. |
Drilling Operations
General. As of September 30, 2009, we had interests in over 1,400 wells, concentrated
on our Appalachian properties. We believe our long and successful operating history and proven
ability to drill a large number of wells year after year have positioned us as a leading producer
in this region. Historically, we conducted most of our drilling operations through sponsored
drilling partnerships with outside investors, enabling us to assemble our acreage positions on the
strength of our drilling commitments, while also funding infrastructure development on acquired
acreage for our own account. Beginning in the second half of 2007, with our core Appalachian
infrastructure in place, we changed our business model to limit our use of drilling partnerships to
participation in non-operated plays, retaining all of our available working interest in wells
drilled on operated properties through the end of 2008. To address part of the capital
requirements for meeting this years drilling commitments and objectives, we are sponsoring a
drilling partnership for up to $53.1 million to participate in our horizontal wells during 2009 and
the first quarter of 2010. The partnership commenced operations in June 2009 following the initial
closing of its private placement.
Geological Factors. Although mineral development in Appalachia has historically been
dominated by coal mining interests, it is also one of the oldest and most prolific natural gas
producing areas in the United States. Most of our vertical wells in this region were drilled to
relatively shallow total depths averaging 4,500 feet, generally encountering several predictable
natural gas pay zones. The primary pay zone throughout our Appalachian acreage is the Devonian
shale formation. This is considered an unconventional target due to its low permeability,
requiring effective treatment to enhance natural fracturing in these reservoirs. Estimated
ultimately recoverable volumes (EURs) of natural gas reported for vertical gas wells in this part
of Appalachia range between 100 to 450 Mmcf, with modest initial volumes offset by low annual
decline rates, resulting in a reserve life index of over 25 years. Our New Albany shale play in
the Illinois Basin has similar geological, production and reserve characteristics.
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Horizontal Drilling. Air-driven horizontal drilling advances and staged completion
technology optimized for our operating areas have dramatically improved the economics of our shale
plays in the Appalachian and Illinois Basins. In general, our horizontal wells use directional air
drilling to create a lateral leg up to 3,500 feet through the target formation. This allows the
well bore to stay in contact with the reservoir longer and to intersect more fractures in the
formation than conventional vertical wells. While up to four times more expensive than vertical
wells, horizontal drilling is improving overall performance by increasing recovery volumes and
rates, limiting the number of wells necessary to develop an area through conventional drilling and
reducing the costs and surface disturbances of multiple vertical wells. Typically, one horizontal
well replaces between three to four vertical locations, reducing the total footprint by drilling
fewer wells. Additional economies are being achieved with multiple horizontal wells on a single
drilling location. In addition to these operational advantages, the initial recovery rates for our
horizontals are averaging six to eight times the rates for vertical Devonian shale wells in the
same fields. Although not fully reflected in our 2008 year-end reserve estimates, we anticipate
substantial upside in both production and EURs from our ongoing transition to horizontal drilling.
Staged Completion Technology. Upon completion of drilling the lateral leg of our
horizontal wells, we run 4.5-inch casing and packers to the end of the leg. The packers are set at
intervals, allowing the well to be completed in up to eight separate stages within the horizontal
leg. A staged treatment process is then performed on our horizontal wells to enhance natural
fracturing with large volumes of nitrogen, generally over one-million standard cubic feet per
stage. After the well is blown back for approximately seven days, it is connected to our existing
field-wide gathering facilities to commence gas sales.
New Albany Shale Play. In addition to the recent expansion of our Leatherwood acreage
and our Chesapeake farmout, we are continuing to develop our New Albany shale play within the
southcentral portion of the Illinois Basin in western Kentucky. We began producing this project to
sales in September 2008 upon completion of our gas gathering and processing infrastructure for the
acreage, with a total of 33 wells on line at September 30, 2009. Based on encouraging results from
our New Albany shale horizontals, we have expanded our lease position and plan to drill up to five
horizontal wells on this acreage through our 2009 drilling partnership.
Drilling Results. The following table shows the number of gross and net development
and exploratory wells we drilled during 2008 and the first nine months of 2009. Drilling results
shown in the table for 2008 include 55 gross (24.18 net) wells that were drilled by year-end but
were awaiting installation of gathering lines or extensions prior to completion, primarily on
non-operated properties. Gross wells are the total number of wells in which we have a working
interest. Net wells reflect our working interests, without giving effect to any reversionary
interest we may subsequently earn in wells drilled through our sponsored drilling programs.
Development Wells | Exploratory Wells | |||||||||||||||||||||||
Productive | Dry | Productive | Dry | |||||||||||||||||||||
Gross | Net | Gross | Gross | Net | Gross | |||||||||||||||||||
Year Ended December 31, 2008 |
||||||||||||||||||||||||
Vertical |
137 | 58.8522 | | 9 | 8.8125 | | ||||||||||||||||||
Horizontal |
47 | 15.7254 | | | | | ||||||||||||||||||
Total |
184 | 74.5776 | | 9 | 8.8125 | | ||||||||||||||||||
Nine Months Ended
September 30, 2009 |
||||||||||||||||||||||||
Vertical |
10 | 1.6972 | | | | | ||||||||||||||||||
Horizontal |
14 | 2.7588 | | | | | ||||||||||||||||||
Total |
24 | 4.4560 | | | | | ||||||||||||||||||
Producing Activities
Regional Advantages. Our proved reserves, both developed and undeveloped, are
concentrated in the southern portion of the Appalachian Basin. The proximity of this region to
major east coast gas markets reduces our transportation costs, generating realization premiums
above Henry Hub spot prices and contributing to long-term returns on investment. Our Appalachian
gas production also has the advantage of a high energy content (Dth), ranging from 1.1 to 1.3 Dth
per Mcf. Historically, because our gas sales contracts yield upward adjustments from index based
pricing for throughput with an energy content above 1 Dth per Mcf, this resulted in realized
premiums averaging 17% over normal pipeline quality gas.
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Liquids Extraction. During 2007, in response to regulatory tariffs limiting the
upward range of pipeline throughput to 1.1 Dth per Mcf, we constructed a processing plant with
Seminole Energy in Rogersville, Tennessee for liquids extraction from our Appalachian production
delivered through the Gathering System. The plant was brought on line in February 2008, ensuring
our compliance with the new energy content standard. Sales of extracted natural gas liquids (NGL)
have partially offset the reduction in energy-related yields from our Appalachian gas production.
In addition, our margins for sales of extracted NGL have benefited from lower hauling costs
achieved through recently implemented rail shipping arrangements.
Oil and Gas Production. Our production revenues and estimated oil and gas reserves
are substantially dependent on prevailing market prices for natural gas, which comprised 78% of our
proved reserves on an energy equivalent basis at the end of 2008. The following table shows the
average sales prices for our natural gas, crude oil and NGL production during 2008 and the interim
reporting periods.
Three Months Ended | Nine Months Ended | Year Ended | ||||||||||||||||||
September 30, | September 30, | December 31, | ||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2008 | ||||||||||||||||
Production volumes: |
||||||||||||||||||||
Natural gas (Mcf) |
816,393 | 760,401 | 2,521,223 | 2,268,929 | 3,087,596 | |||||||||||||||
Oil (Bbl) |
11,887 | 16,235 | 37,313 | 44,718 | 57,291 | |||||||||||||||
Natural gas liquids (gallons) |
1,458,541 | 1,202,292 | 3,895,199 | 2,930,974 | 3,895,649 | |||||||||||||||
Equivalents (Mcfe) |
997,103 | 947,986 | 3,037,238 | 2,778,668 | 3,745,124 | |||||||||||||||
Average sales prices: |
||||||||||||||||||||
Natural gas (per Mcf) |
$ | 5.67 | $ | 9.80 | $ | 6.31 | $ | 9.40 | $ | 8.89 | ||||||||||
Oil (per Bbl) |
60.76 | 110.26 | 48.03 | 106.06 | 95.07 | |||||||||||||||
Natural gas liquids (per gallon) |
0.61 | 1.65 | 0.64 | 1.64 | 1.41 |
Future Gas Sales Contracts. We use fixed-price, fixed-volume physical delivery
contracts that cover portions of our natural gas production at specified prices during varying
periods of time to address commodity price volatility. Our physical delivery contracts are not
treated as financial hedging activities and are not subject to mark-to-market accounting. The
financial impact of these contracts is included in our oil and gas revenues at the time of
settlement. As of the date of this report, we have contracts in place for the following portions
of our anticipated natural gas production for each quarter of 2010 and the fourth quarter of 2009.
Fixed-Price Contracts for Natural Gas Production
2009 | 2010 | |||||||||||||||||||
Q4 | Q1 | Q2 | Q3 | Q4 | ||||||||||||||||
Percentage of gas contracted |
54 | % | 58 | % | 46 | % | 51 | % | 47 | % | ||||||||||
Average price per Mcf |
$ | 7.83 | $ | 7.54 | $ | 6.42 | $ | 6.51 | $ | 6.56 |
Results of Operations Three Months Ended September 30, 2009 and 2008
Revenues. The following table shows the components of our revenues for the three
months ended September 30, 2009 and 2008, together with their percentages of total revenue in the
current period and percentage change on a period-over-period basis.
Three Months Ended September 30, | ||||||||||||||||
% of | % | |||||||||||||||
2009 | Revenue | 2008 | Change | |||||||||||||
Revenue: |
||||||||||||||||
Contract drilling |
$ | 3,831,250 | 34 | % | $ | 9,799,561 | (61 | )% | ||||||||
Oil and gas production |
6,239,324 | 56 | 11,222,879 | (44 | ) | |||||||||||
Gas transmission, compression and processing |
1,123,921 | 10 | 2,567,852 | (56 | ) | |||||||||||
Total |
$ | 11,194,495 | 100 | % | $ | 23,590,292 | (53 | ) | ||||||||
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Our total revenues for the third quarter of 2009 reflect the impact of declining commodity
prices, reduced drilling activity and our sale of the Gathering System. In view of our reduction
in capital expenditures for 2009, we do not expect this trend to reverse without a significant
recovery in commodity prices and an increase in the level of drilling activity, which is directly
linked to partnership sales under our current business model. Although sales of partnership
interests are typically concentrated in the fourth quarter, they may continue to be impacted this
year by the challenging economic environment.
Contract drilling revenues reflect the size and timing of our drilling partnership
initiatives. Although we receive the proceeds from private placements in sponsored partnerships as
customers drilling deposits under our program drilling contracts, we recognize revenues from the
interests of outside investors in these programs on the completed contract method as the wells are
drilled, rather than when funds are received. Our contract drilling revenues in the third quarter
of 2009 reflect continued operations of our 2009 drilling partnership, which participated in six
horizontal wells during the quarter. We plan to drill a total of up to 53 horizontals on our
operated properties though that program, depending on the level of partnership participation.
Production revenues for the third quarter of 2009 reflect an increase of 5% in production
output to 997 Mmcfe, compared to 948 Mmcfe in the year-earlier period, offset by declines of 42% in
natural gas prices, 45% in oil prices and 63% for sales of natural gas liquids. Our volumetric
growth reflects strong performance from our horizontal wells and the commencement of production
from our Haleys Mill field in western Kentucky during August 2008, along with our share of
production from non-operated wells drilled for our 2008 drilling partnership. Approximately 50% of
our natural gas production in the current quarter was sold under fixed-price physical delivery
contracts, and the balance primarily at prices determined monthly under formulas based on
prevailing market indices. Realized natural gas prices in the 2009 third quarter averaged
$6.53 per Mcf for our Appalachian production and $5.67 per Mcf overall, compared to an average
overall realization of $9.80 per Mcf in the third quarter of 2008.
The contraction of gas transmission, compression and processing revenues for the current
quarter was driven our sale of a 50% interest in the Gathering System in mid-July and the balance
in mid-August 2009. See Recent Developments. Following the sale, our gas transmission,
compression and processing revenues were limited primarily to gas utility sales and our share of
third-party fees for liquids extraction through our Rogersville plant, which we continue to co-own
with Seminole Energy.
Expenses. The following table shows the components of our direct and other expenses
for the three months ended September 30, 2009 and 2008. Percentages listed in the table reflect
margins for each component of direct expenses and percentages of total revenue for each component
of other expenses. Certain non-cash expenses for the 2009 interim periods reflect adjustments for
the adoption of derivative fair value accounting for our 6% convertible notes as of January 1,
2009. The impact of these adjustments is discussed below and in Note 2 to the accompanying
condensed consolidated financial statements.
Three Months Ended September 30, | ||||||||||||||||
2009 | Margin | 2008 | Margin | |||||||||||||
Direct Expenses: |
||||||||||||||||
Contract drilling |
$ | 2,913,418 | 24 | % | $ | 7,570,698 | 23 | % | ||||||||
Oil and gas production |
2,658,985 | 57 | 3,922,629 | 65 | ||||||||||||
Gas transmission, compression and processing |
960,879 | 15 | 1,039,597 | 60 | ||||||||||||
Total direct expenses |
6,533,282 | 42 | 12,532,924 | 47 | ||||||||||||
(Restated) | % Revenue | % Revenue | ||||||||||||||
Other Expenses (Income): |
||||||||||||||||
Selling, general and administrative |
2,601,514 | 23 | % | 3,551,908 | 15 | % | ||||||||||
Options, warrants and deferred compensation |
285,309 | 3 | 229,209 | 1 | ||||||||||||
Depreciation, depletion and amortization |
3,304,139 | 30 | 3,318,320 | 14 | ||||||||||||
Bad debt expense |
| N/A | 342,195 | 1 | ||||||||||||
Interest expense, net of interest income |
2,143,393 | 19 | 1,446,526 | 6 | ||||||||||||
Gain on sale of assets |
(3,356,177 | ) | N/A | | N/A | |||||||||||
Fair value loss on derivative financial instruments |
4,847 | | N/A | |||||||||||||
Other, net |
292,073 | 3 | 87,584 | | ||||||||||||
Total other expenses |
$ | 5,275,098 | $ | 8,975,742 | ||||||||||||
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Contract drilling expenses reflect the level and timing of drilling initiatives conducted
through our sponsored partnerships. These expenses represented 76% of contract drilling revenues
in the current quarter, compared to 77% in the year-earlier period. Margins for contract drilling
operations reflect our cost-plus pricing model, which we adopted in 2006 to address price
volatility for drilling services, equipment and steel casing requirements.
Production expenses represent lifting costs, field operating and maintenance expenses, related
overhead, severance and other production taxes, third-party transportation fees and processing
costs. Historically, our ownership of the Gathering System eliminated transportation costs for our
share of Leatherwood, Straight Creek, Fonde and Stone Mountain production delivered through the
system. The increase in production expenses on a period-over-period basis primarily reflects
higher transportation costs following our sale of the Gathering System, which will further impact
these costs in future periods. See Recent Developments. As a percentage of revenues, overall
production expenses in the current quarter benefitted from lower severance taxes and various
cost-cutting measures for our field operations.
Our gas transmission and compression expenses, as well as capitalized costs for this part of
our business, were substantially reduced in the third quarter of 2009 following our sale of the
Gathering System. Our remaining infrastructure position is comprised of 100% interests in the gas
gathering facilities for our Haleys Mill and Kay Jay fields, 50% interests in our Haleys Mill and
Rogersville processing plants and a 25% interest in the gathering system for our non-operated
Arkoma properties. Our gas transmission, compression and processing expenses in future periods
will reflect this reduction in our infrastructure asset base.
Selling, general and administrative (SG&A) expenses are comprised primarily of selling and
promotional costs for our sponsored drilling partnerships and general overhead costs. Our SG&A
expenses in the current quarter decreased by 27% from the same period last year, primarily due to
the timing of partnership sales, and represented 23% of revenues in the current quarter, compared
to 15% in the third quarter of 2008.
Non-cash charges for options, warrants and deferred compensation reflect the fair value method
of accounting for employee stock options. Under this 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 also recognized an accrual of $153,637 for deferred
compensation cost in the current quarter.
Depreciation, depletion and amortization (DD&A) is recognized under the units-of-production
method, based on the estimated proved developed reserves of the underlying oil and gas properties,
and on a straight-line basis over the useful life of other property and equipment. The decrease in
DD&A charges reflects a reduction in historical depletion costs for our Gathering System following
its sale, partially offset by additions to our oil and gas properties.
Cash interest expense for the 2009 third quarter decreased 18% from the year-earlier period,
reflecting the reduction of debt levels under our revolving credit facility from proceeds of our
Gathering System sale and equity raise. In addition to improving our liquidity, the reduction in
our credit facility debt from these transactions will provide ongoing savings on future interest
expense. Non-cash interest expense of $1,004,682 for the third quarter of 2009 reflects the
application of the effective interest method for accretion of the debt discount attributable to the
embedded conversion feature of our 6% notes, which have of face amount of $37,000,000. See
Liquidity and Capital Resources.
We recognized a pre-tax gain of $3,356,367 during the third quarter of 2009 from the sale of
our interests in the Gathering System. See Recent Developments. We acquired the open-access
portion of the Gathering System from Duke Energy in March 2006 for $18 million and built out the
field-wide portions of the facilities at historical costs totaling approximately $33.5 million.
Deferred income tax expense represents future tax liabilities at the operating company level.
Although we have no current tax liability at that level due to the utilization of intangible
drilling costs, our consolidated income tax expense is negatively impacted by the non-recognition
of tax benefits at the parent company level.
Net Income (Loss) and EPS. We recognized a net loss of $1,122,001 in the third
quarter of 2009, as restated, reflecting the foregoing factors. Earnings (loss) per share (EPS)
was $(0.04) on 28,873,105 weighted average common shares outstanding. Before giving effect to the
after-tax gain from our sale of the Gathering System, we had a net loss of $3,135,821 or $(0.11)
per share in the third quarter of 2009, compared to net income of $945,185 realized in the same
quarter last year, with EPS of $0.04 on 26,977,438 fully diluted shares. Adjustments for
derivative treatment of our 6% convertible notes accounted for $960,622 of our restated net loss,
or $(0.03) per share, for the third quarter of 2009.
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Results of Operations Nine Months Ended September 30, 2009 and 2008
Revenues. The following table shows the components of our revenues for the nine
months ended September 30, 2009 and 2008, together with their percentages of total revenue in the
current period and percentage change on a period-over-period basis.
Nine Months Ended September 30, | ||||||||||||||||||
% of | % | |||||||||||||||||
2009 | Revenue | 2008 | Change | |||||||||||||||
Revenue: | ||||||||||||||||||
Contract drilling |
$ | 16,328,000 | 38 | % | $ | 24,027,035 | (32 | )% | ||||||||||
Oil and gas production |
20,198,187 | 47 | 30,891,933 | (35 | ) | |||||||||||||
Gas transmission, compression and processing |
6,528,132 | 15 | 7,662,504 | (15 | ) | |||||||||||||
Total |
$ | 43,054,319 | 100 | % | $ | 62,581,472 | (31 | ) | ||||||||||
Our contract drilling revenues in the first nine months of 2009 reflect the completion of
drilling operations for our 2008 drilling partnership, which participated in 89 wells on
non-operated properties in West Virginia and Virginia, as well as the commencement of operations
for our 2009 drilling partnership, which participated in nine horizontal wells through the end of
the third quarter.
Production revenues for the first nine months of 2009 reflect a 9% increase in production
output to 3,037 Mmcfe, compared to 2,779 Mmcfe in the year-earlier period, offset by declines of
33% in natural gas prices, 55% in oil prices and 61% for NGL sales. Our volumetric growth, while
negatively impacted by the reduction in drilling activity in the current period, reflects strong
performance from horizontal drilling initiatives beginning in February 2008 and the commencement of
production from our Haleys Mill field later in the year and non-operated wells in West Virginia.
Approximately 50% of our natural gas production in the first nine months of 2009 was sold under
fixed-price contracts, and the balance at index-based pricing. Realized natural gas prices in the
current period averaged $7.44 per Mcf for our Appalachian production and $6.31 per Mcf overall,
compared to an average overall realization of $8.25 per Mcf in the first nine months of 2008.
Gas transmission, compression and processing revenues for the current period were driven by
fees for moving our drilling program investors share of gas through the Gathering System prior to
its sale and processing fees for liquids extraction through our Rogersville plant. This component
of revenues also includes contributions from gas utility sales.
Expenses. The following table shows the components of our direct and other expenses
for the nine months ended September 30, 2009 and 2008. Percentages listed in the table reflect
margins for each component of direct expenses and percentages of total revenue for each component
of other expenses.
Nine Months Ended September 30, | ||||||||||||||||||
2009 | Margin | 2008 | Margin | |||||||||||||||
Direct Expenses: | ||||||||||||||||||
Contract drilling |
$ | 12,328,110 | 24 | % | $ | 18,447,544 | 23 | % | ||||||||||
Oil and gas production |
7,598,044 | 62 | 9,794,679 | 68 | ||||||||||||||
Gas transmission, compression and processing |
2,955,204 | 55 | 3,087,391 | 60 | ||||||||||||||
Total direct expenses |
22,881,358 | 47 | 31,329,614 | 50 | ||||||||||||||
(Restated) | % Revenue | % Revenue | ||||||||||||||||
Other Expenses (Income): | ||||||||||||||||||
Selling, general and administrative |
8,404,519 | 20 | % | 10,282,485 | 16 | % | ||||||||||||
Options, warrants and deferred compensation |
1,022,774 | 2 | 601,691 | 1 | ||||||||||||||
Depreciation, depletion and amortization |
10,610,630 | 25 | 9,451,272 | 15 | ||||||||||||||
Bad debt expense |
| N/A | 749,035 | 1 | ||||||||||||||
Interest expense, net of interest income |
6,824,842 | 16 | 4,049,336 | 6 | ||||||||||||||
Gain on sale of assets |
(3,369,082 | ) | N/A | | N/A | |||||||||||||
Fair value gain on derivative financial instruments |
(4,477 | ) | N/A | | N/A | |||||||||||||
Other, net |
600,896 | 1 | 115,939 | | ||||||||||||||
Total other expenses |
$ | 24,090,102 | $ | 25,249,758 | ||||||||||||||
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Contract drilling expenses decreased by 33% on a period-over-period basis and represented 76%
of contract drilling revenues in the first nine months of 2009, compared to 77% in the year-earlier
period. Our contract drilling activities in the current period were limited to the completion of
drilling on non-operated properties in West Virginia and Virginia for last years drilling
partnership and the commencement of operations for our 2009 drilling partnership in June 2009.
The decrease in production expenses on a period-over-period basis primarily reflects lower
severance taxes and the adoption of various cost-cutting measures for our field operations. Our
margins in both periods reflect cost savings realized from ownership of the Gathering System prior
to its sale during the third quarter of 2009.
Gas transmission, compression and processing expenses in the first nine months of 2009 were
45% of associated revenues, compared to 40% in the same period last year. These expenses do not
include capitalized costs of approximately $1.5 million in the current period for extensions of our
field-wide gas gathering systems and additions to dehydration and compression capacity required to
bring new wells on line.
SG&A expenses in the current period decreased 18% from the same period last year. This
primarily reflects the reduced level of drilling partnership sales. which are subject to
considerable fluctuation and generally ramp up toward the end the year. As a percentage of
revenues, SG&A expenses increased to 20% in the first nine months of 2009, compared to 16% of
revenues in the year-earlier period.
Non-cash charges for options, warrants and deferred compensation reflect the fair value method
of accounting for employee stock options. Under this 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 also recognized an accrual of $460,911 for deferred
compensation cost in the current period.
The increase in DD&A for the current period reflects additions to our oil and gas properties,
gas gathering systems and related equipment. We anticipate reductions in our DD&A rates of
approximately 10% from historical levels as a result of our Gathering System sale in the third
quarter of 2009.
We recognized a bad debt expense of $347,840 in the first nine months of 2008. Coupled with
prior-year reserves, this represented the entire amount due for oil sales to a regional refinery
prior to its filing for reorganization under the bankruptcy laws in 2008. See Critical Accounting
Policies and Estimates Allowance for Doubtful Accounts.
We recorded a pre-tax gain of $3,356,367 during the current period from the sale of our
interests in the Gathering System. See Recent Developments. We estimate an after-tax gain of
approximately $2.0 million from the sale.
Cash interest expense for the first nine months of 2009 decreased 3% from the year-earlier
period, reflecting lower rates under our revolving credit facility and a reduction of debt levels
from our liquidity initiatives in the third quarter this year. See Recent Developments -
Liquidity from Gathering System Sale and Equity Raise. Draws under the facility since the third
quarter of 2008 were used primarily to support our ongoing drilling initiatives and enhancements of
our field-wide gas gathering infrastructure. Non-cash interest expense of $2,869,276 reflects the
accretion of the debt discount on our 6% convertible notes.
Net Income (Loss) and EPS. We recognized a net loss of $4,488,498 in the first nine
months of 2009, as restated, reflecting the foregoing factors. EPS was $(0.16) on 27,508,925
weighted average common shares outstanding. Before giving effect to the after-tax gain from our
sale of the Gathering System, we had a net loss of $6,502,318 or $(0.23) per share in the first
nine months of 2009, compared to net income of $2,629,636 realized in the same period last year,
with EPS of $0.10 on 27,019,313 fully diluted shares. Adjustments for derivative treatment of our
6% convertible notes accounted for $2,864,799 of our restated net loss, or $(0.10) per share, for
the nine months ended September 30, 2009.
The results of operations for the three months and nine months ended September 30, 2009 are
not necessarily indicative of results to be expected for the full year.
Liquidity and Capital Resources
Liquidity. We completed a registered direct placement of 3.48 million units at $1.90
per unit on August 13, 2009, with net proceeds of approximately $6.1 million applied to debt
reduction under our revolving credit facility. Each unit consists of one share of our common stock
and a warrant to buy 0.5 common share. The warrants have a four-year term, beginning six months
after issuance, and will be exercisable during that period for a total of 1.74 million shares of
our common stock at $2.35 per share, subject to adjustment for certain dilutive issuances.
18
Table of Contents
During the first nine months of 2009, we generated net cash of $3,688,054 from operating
activities and $25,324,894 from investing activities, which included proceeds from our Gathering
System sale, all of which were applied to debt reduction under our revolving credit facility. Our
investing activities also included capital expenditures aggregating $6,089,476 for additions to oil
and gas properties. As a result of these activities, our net cash of $970,467 at the end of the
current period was substantially the same as our net cash position at December 31, 2008.
We had working capital of $4,991,050 as of September 30, 2009, compared to a working capital
deficit of $5,519,114 at December 31, 2008. This reflects the current portion of the note
receivable from the sale of our Gathering System and wide fluctuations in our current assets and
liabilities from the timing of customer deposits and expenditures under drilling contracts with our
sponsored partnerships. We also have substantial changes our cash position from draws and payments
under our credit facility. Since these fluctuations are normalized over relatively short time
periods, we do not consider working capital to be a reliable measure of our liquidity.
Capital Resources. Our business involves significant capital requirements. The rate
of production from oil and gas properties 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. We also have substantial annual drilling commitments under various
leases and farmouts for our Appalachian properties, including an annual 25-well commitment for our
Leatherwood field. Our long-term performance and profitability are dependent not only on meeting
these commitments and recovering existing oil and gas reserves, but also on our ability to find or
acquire additional reserves and fund their development on terms that are economically and
operationally advantageous.
We have relied on a combination of cash flows from operations, bank borrowings and private
placements of our convertible notes and equity securities to fund our reserve and infrastructure
development and acquisition activities. Historically, we also relied on participation in our
operated drilling initiatives by outside investors in our sponsored partnerships. For 2008, we
changed our business model to accelerate organic growth by retaining all of our available working
interest in wells drilled on operated properties, with a view to limiting our use of drilling
partnerships to non-operated initiatives.
While we are committed to continue expanding our reserves and production through the drillbit,
we have addressed the challenging conditions in our industry by reducing our 2009 capital spending
budget to $15 million, allocated primarily to drilling. This is in line with our anticipated cash
flow from operations and reflects a 73% reduction from our 2008 capital expenditures. To meet our
2009 drilling commitments and objectives with this reduced capital spending budget, we have
returned to our established partnership structure and sales network for a targeted raise of up to
$53.1 million from outside investors. We will contribute 20% of program capital and will have a
proportionate interest in our 2009 program, which will increase to 35% after program payout. With
our critical infrastructure in place, this will allow us to continue delivering organic growth,
although at lower rates than we could otherwise achieve.
We have a senior secured revolving credit facility maintained by DPI under a credit agreement
with KeyBank National Association, as administrative agent. The credit agreement provides for
revolving term loans and letters of credit in an aggregate amount up to $125 million, with a
scheduled maturity in September 2011. Credit availability under the facility is subject to
borrowing base limits, as determined semi-annually by the lenders. Outstanding borrowings bear
interest at fluctuating rates ranging from the agents prime rate to 2.25% above that rate,
depending on the amount of borrowing base utilization. We are also responsible for commitment fees
at rates ranging from 0.375% to 0.5% of the unused borrowing base. The facility is guaranteed by
NGAS and is secured by liens on DPIs oil and gas properties.
As of September 30, 2009, we had outstanding borrowings of $35 million under our credit
facility, with a borrowing base of $55 million. This reflects debt reductions totaling
$41.6 million from proceeds of our Gathering System sale and equity raise in the third quarter of
2009. At that time, our borrowing base was reduced by $25 million to reflect lower commodity
prices and the release of our Gathering System assets from the collateral package. A related
amendment to the credit agreement provides for the further debt reduction from payments under a
$14.5 million promissory note issued to us by Seminole Energy as part of the purchase price for our
Gathering System assets. The note is payable in monthly installments through December 2011, with
interest at 8% per annum. See Recent Developments.
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We have an outstanding series of 6% convertible notes due December 15, 2010 in the aggregate
principal amount of $37 million. The notes are convertible into our common shares at a conversion
price of $11.16, reflecting an anti-dilution adjustment from our registered direct placement of
common stock and warrants during the third quarter of 2009. In the event of a default under the
notes or any change of control, the holders may require us to redeem the notes at a default rate
equal to 125% of their principal amount or a change of control rate equal to the greater of 110% of
their principal amount or the consideration that would be received by the holders for the
underlying shares in the change of control transaction. Any notes that are neither redeemed nor
converted prior to maturity will be repayable in cash or in common shares, valued for that purpose
at 92.5% of their market price.
Our ability to repay our revolving credit and convertible debt will be subject to our future
performance and prospects as well as market and general economic conditions. 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 attract drilling partnership capital. While we have been able to
mitigate some of the steep decline in natural gas prices with fixed-price, fixed-volume physical
delivery contracts that cover portions of our natural gas production, we are exposed to price
volatility for future production not covered by these arrangements. See Quantitative and
Qualitative Disclosures about Market Risk.
We have addressed the general economic downturn and current unsettled conditions in natural
gas markets by monetizing our Gathering System, completing an equity raise, reducing our capital
expenditure budget and returning to our established drilling partnership structure for
participation in our development initiatives on operated properties. To realize our long-term
goals for growth in revenues and reserves, however, we will need to retain more of our available
working interest in future wells, requiring continued access to the credit and capital markets.
Any prolonged constraints on our access to those markets on acceptable terms could require us to
sell additional assets or pursue other financing or strategic arrangements to meet those objectives
and to repay or refinance our long-term debt at maturity.
Forward Looking Statements
Some statements made by us in this report are prospective and constitute forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act and Section 27A of the
Securities Act of 1933. Other than statements of historical fact, all statements that address
future activities, outcomes and other matters we plan, expect, budget, intend or estimate, and
other similar expressions, are forward-looking statements. These forward-looking statements
involve known and unknown risks, uncertainties and other factors, many of which are beyond our
control. Among other things, these include:
| uncertainty about estimates of future natural gas production and required capital expenditures; | ||
| commodity price volatility; | ||
| increases in the cost of developing and producing our reserves; | ||
| unavailability of drilling rigs and services; | ||
| drilling, operational and environmental risks; | ||
| regulatory changes and litigation risks; and | ||
| uncertainties in estimating oil and gas reserves and projecting future production rates. |
If the assumptions we use in making forward-looking statements prove incorrect or the risks
described in this report and incorporated by reference to our 2008 annual report were to occur, our
actual results could differ materially from future results expressed or implied by the
forward-looking statements in this report.
Contractual Obligations and Commercial Commitments
General. We are parties to leases for office facilities and various types of
equipment. We are also obligated to make payments at specified times and amounts under instruments
governing our long-term debt and other commercial commitments. The following table lists these
minimum annual obligations as of September 30, 2009. The table does not include
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Operating Leases | Long Term | |||||||||||||||
Equipment | Premises | Total | Debt | |||||||||||||
Year |
||||||||||||||||
Remainder of 2009 |
$ | 542,940 | $ | 61,764 | $ | 604,704 | $ | 27,807 | ||||||||
2010 |
2,102,680 | 247,815 | 2,350,495 | 31,477,828 | (1) | |||||||||||
2011 |
1,842,835 | 252,389 | 2,095,224 | 35,093,557 | ||||||||||||
2012 |
591,469 | 255,973 | 847,442 | 2,157,461 | ||||||||||||
2013 and thereafter |
51,929 | 21,355 | 73,284 | 192,818 | ||||||||||||
Total |
$ | 5,131,853 | $ | 839,296 | $ | 5,971,149 | $ | 68,949,471 | ||||||||
(1) | Excludes the unamortized debt discount of $5,611,769 at September 30, 2009 attributable to the embedded conversion feature of our 6% convertible notes in the principal amount of $37,000,000. |
Gas Gathering and Sales Commitments. We have various commitments under our gas
gathering and sales agreements entered with Seminole and Seminole Energy in connection with our
sale of the Gathering System during the third quarter of 2009. See Recent Developments. These
agreements provide us with firm capacity rights for daily delivery of 30,000 Mcf of controlled gas
and have an initial term of fifteen years with extension rights. Our commitments under these
agreements include:
| Base monthly gathering fees of $850,000, with annual escalations at the rate of 1.5%; | ||
| Base monthly operating fees of $175,000, plus $0.20 per Mcf of purchased gas; and | ||
| Monthly capital fees in amounts intended to yield a 20% internal rate of return for all capital expenditures on the Gathering System by Seminole and Seminole Energy. |
Critical Accounting Policies and Estimates
General. The preparation of financial statements requires management to utilize
estimates and make judgments that affect the reported amounts of assets, liabilities, revenues and
expenses and related disclosure of contingent assets and liabilities. These estimates are based on
historical experience and on various other assumptions that management believes to be reasonable
under the circumstances. The estimates are evaluated by management on an ongoing basis, and the
results of these evaluations form a basis for making decisions 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 the
estimates used in the preparation of our financial statements are reasonable. The critical
accounting policies affecting these aspects of our financial reporting are summarized or referenced
in Notes 1 and 2 to the consolidated financial statements included in this 10-Q/A. Policies
involving the more significant judgments and estimates used in the preparation of our consolidated
financial statements are summarized below.
Estimates of Proved Reserves and Future Net Cash Flows. Estimates of our proved oil
and gas reserves and related future net cash flows are used in impairment tests of goodwill and
other long-lived assets. These estimates are prepared as of year end by our independent petroleum
engineers and are updated internally at mid-year. There are many uncertainties inherent in
estimating quantities of proved reserves and in projecting future rates of production and timing of
development expenditures. The accuracy of any reserve estimate is dependent on the quality of
available data and is subject to engineering and geological interpretation and judgment. Results
of our drilling, testing and production after the date of these estimates may require future
revisions, and actual results could differ materially from the estimates.
Impairment of Long-Lived Assets. Our long-lived assets include property, 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.
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 settlements with customers.
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Item 3. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Risk
Our major market risk exposure is the pricing of natural gas production, which has been highly
volatile and unpredictable during the last several years. While we do not use financial hedging
instruments to manage our exposure to these fluctuations or for speculative trading purposes, we do
use fixed-price, fixed-volume physical delivery contracts that cover portions of our natural gas
production at specified prices during varying periods of time up to two years from the contract
date. Because these physical delivery contracts qualify for the normal purchase and sale exception
under SFAS No. 133, they are not treated as financial hedging activities and are not subject to
mark-to-market accounting. The financial impact of physical delivery contracts is included in our
oil and gas revenues at the time of settlement, which in turn affects our average realized natural
gas prices.
Financial Market Risks
Interest Rate Risk. Borrowings under our secured credit facility bear interest at
fluctuating market-based rates. Accordingly, our interest expenses are sensitive to market
changes, which exposes us to interest rate risk on current and future borrowings under the
facility.
Foreign Market Risk. We sell our products and services exclusively in the United
States and receive payment solely in United States dollars. As a result, our financial results are
unlikely to be affected by factors such as changes in foreign currency exchange rates or weak
economic conditions in foreign markets, except to the extent they affect domestic natural gas
markets.
Item 4. Controls and Procedures
Managements Responsibility for Financial Statements
Our management is responsible for the integrity and objectivity of all information presented
in this report. The consolidated financial statements included in this report have been prepared
in accordance with U.S. GAAP and reflect managements judgments and estimates on the effect of the
reported events and transactions.
Disclosure Controls and Procedures
Our management, with the participation of our chief executive officer and chief financial
officer, evaluated the effectiveness of our disclosure controls and procedures, as defined in
Rule 13a-15(e) under the Exchange Act, as of the end of the period covered by this report. Based
on managements evaluation as of September 30, 2009 and as of December 31, 2009 in connection with
the filing of this 10-Q/A, our chief executive officer and chief financial officer have concluded
that our disclosure controls and procedures are effective to ensure that material information about
our business and operations is recorded, processed, summarized and publicly reported within the
time periods required under the Exchange Act, and that this information is accumulated and
communicated to our management to allow timely decisions about required disclosures.
Managements Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. Management assessed the
effectiveness of our internal control over financial reporting as of September 30, 2009 and as of
December 31, 2009 in connection with the filing of this 10-Q/A, using the criteria established
under Internal Control Integrated Framework, issued by the Committee of Sponsoring Organizations
of the Treadway Commission. Based on that assessment, management concluded that our internal
control over financial reporting was effective based on those criteria as of September 30, 2009 and
December 31, 2009.
Changes in Internal Control over Financial Reporting
We regularly review our system of internal control over financial reporting to ensure the
maintenance of an effective internal control environment. There were no changes in our internal
control over financial reporting during the period covered by this report that have materially
affected or are reasonably likely to materially affect our internal control over financial
reporting.
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PART II. OTHER INFORMATION
Part II Item 6
Exhibit | ||
Number | Description of Exhibit | |
31.1
|
Certification of Chief Executive Officer pursuant to Exchange Act Rule 13a-14(a), as adopted under Section 302 of the Sarbanes-Oxley Act of 2002. | |
31.2
|
Certification of Chief Financial Officer pursuant to Exchange Act Rule 13a-14(a), as adopted under Section 302 of the Sarbanes-Oxley Act of 2002. | |
32.1
|
Certification of Chief Executive Officer pursuant to Exchange Act Rule 13a-14(b), as adopted under Section 906 of the Sarbanes-Oxley Act of 2002. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly
caused this amended report to be signed on its behalf by the undersigned thereunto duly authorized.
NGAS Resources, Inc. |
||||
Date: December 31, 2009 | By: | /s/ William S. Daugherty | ||
William S. Daugherty | ||||
Chief Executive Officer (Duly Authorized Officer) (Principal Executive Officer) |
||||
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