e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
| |
|
|
| þ |
|
Quarterly Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 |
For the period ended March 31, 2007
| |
|
|
| o |
|
Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 |
For the transition period from to
Commission
File Number 001-31759
PANHANDLE OIL AND GAS INC.
(Exact name of registrant as specified in its charter)
| |
|
|
| OKLAHOMA
|
|
73-1055775 |
| |
| (State or other jurisdiction of
|
|
(I.R.S. Employer |
| incorporation or organization)
|
|
Identification No.) |
Grand Centre Suite 300, 5400 N Grand Blvd., Oklahoma City, Oklahoma 73112
(Address of principal executive offices)
Registrant’s telephone number including area code (405) 948-1560
Indicate by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days.
þ Yes o No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer o Accelerated filer þ Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act).
o Yes þ No
Outstanding shares of Class A Common stock (voting) at May 4, 2007: 8,422,529
PART 1 FINANCIAL INFORMATION
PANHANDLE OIL AND GAS INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Information at March 31, 2007 is unaudited)
| |
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|
|
|
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|
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|
| |
|
March 31, 2007 |
|
|
September 30, 2006 |
|
Assets |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
865,235 |
|
|
$ |
434,353 |
|
Oil and gas sales receivables |
|
|
6,902,860 |
|
|
|
6,471,623 |
|
Income tax receivables and other |
|
|
1,949,640 |
|
|
|
1,889,636 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
9,717,735 |
|
|
|
8,795,612 |
|
|
|
|
|
|
|
|
|
|
Properties and equipment, at cost, based on
successful efforts accounting: |
|
|
|
|
|
|
|
|
Producing oil and gas properties |
|
|
111,622,862 |
|
|
|
103,129,158 |
|
Non-producing oil and gas properties |
|
|
10,476,098 |
|
|
|
11,273,373 |
|
Other |
|
|
583,443 |
|
|
|
562,047 |
|
|
|
|
|
|
|
|
|
|
|
122,682,403 |
|
|
|
114,964,578 |
|
Less accumulated depreciation, depletion and amortization |
|
|
60,031,226 |
|
|
|
53,654,385 |
|
|
|
|
|
|
|
|
Net properties and equipment |
|
|
62,651,177 |
|
|
|
61,310,193 |
|
|
|
|
|
|
|
|
|
|
Investments |
|
|
543,928 |
|
|
|
596,280 |
|
Other |
|
|
214,805 |
|
|
|
247,157 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
73,127,645 |
|
|
$ |
70,949,242 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders’ Equity |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
1,581,091 |
|
|
$ |
1,564,176 |
|
Accrued liabilities: |
|
|
|
|
|
|
|
|
Interest |
|
|
14,071 |
|
|
|
15,649 |
|
Fair value of natural gas collar contracts |
|
|
21,991 |
|
|
|
— |
|
Other |
|
|
326,926 |
|
|
|
218,069 |
|
Long-term debt due within one year |
|
|
1,499,946 |
|
|
|
2,000,004 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
3,444,025 |
|
|
|
3,797,898 |
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
1,868,555 |
|
|
|
1,166,649 |
|
Deferred income taxes |
|
|
16,211,250 |
|
|
|
15,498,750 |
|
Asset retirement obligations and other non-current liabilities |
|
|
1,585,188 |
|
|
|
1,420,248 |
|
|
|
|
|
|
|
|
|
|
Stockholders’ equity: |
|
|
|
|
|
|
|
|
Class A voting common stock, $.0166 par value;
24,000,000 shares authorized, 8,422,529
issued and outstanding at March 31, 2007
and 12,000,000 shares authorized,
8,422,529 issued and outstanding at
September 30, 2006 |
|
|
140,375 |
|
|
|
140,375 |
|
Capital in excess of par value |
|
|
1,924,587 |
|
|
|
1,924,587 |
|
Deferred directors’ compensation |
|
|
1,317,229 |
|
|
|
1,202,569 |
|
Retained earnings |
|
|
46,636,436 |
|
|
|
45,798,166 |
|
|
|
|
|
|
|
|
Total stockholders’ equity |
|
|
50,018,627 |
|
|
|
49,065,697 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders’ equity |
|
$ |
73,127,645 |
|
|
$ |
70,949,242 |
|
|
|
|
|
|
|
|
(1)
PANHANDLE OIL AND GAS INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
| |
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
| |
|
Three Months Ended March 31, |
|
|
Six Months Ended March 31, |
|
| |
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales |
|
$ |
8,455,378 |
|
|
$ |
8,347,054 |
|
|
$ |
16,536,586 |
|
|
$ |
20,052,018 |
|
Lease bonuses and rentals |
|
|
54,946 |
|
|
|
114,791 |
|
|
|
170,757 |
|
|
|
208,267 |
|
Realized gains on natural gas collar contracts |
|
|
49,200 |
|
|
|
— |
|
|
|
49,200 |
|
|
|
|
|
Unrealized losses on natural gas collar contracts |
|
|
(627,011 |
) |
|
|
— |
|
|
|
(21,991 |
) |
|
|
— |
|
Gain on sales, interest and other |
|
|
126,151 |
|
|
|
82,843 |
|
|
|
178,380 |
|
|
|
346,826 |
|
Income of partnerships |
|
|
85,069 |
|
|
|
183,818 |
|
|
|
162,696 |
|
|
|
329,074 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,143,733 |
|
|
|
8,728,506 |
|
|
|
17,075,628 |
|
|
|
20,936,185 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
833,591 |
|
|
|
691,896 |
|
|
|
1,733,559 |
|
|
|
1,522,165 |
|
Production taxes |
|
|
541,509 |
|
|
|
514,059 |
|
|
|
1,042,237 |
|
|
|
1,255,477 |
|
Exploration costs |
|
|
45,444 |
|
|
|
149,247 |
|
|
|
719,411 |
|
|
|
181,791 |
|
Depreciation, depletion, and amortization |
|
|
4,166,471 |
|
|
|
2,300,105 |
|
|
|
6,859,939 |
|
|
|
4,588,191 |
|
Provision for impairment |
|
|
1,577,266 |
|
|
|
107,743 |
|
|
|
1,629,833 |
|
|
|
136,395 |
|
Loss on sale of assets |
|
|
223,520 |
|
|
|
94,275 |
|
|
|
255,917 |
|
|
|
94,275 |
|
General and administrative |
|
|
995,466 |
|
|
|
960,442 |
|
|
|
2,142,714 |
|
|
|
1,716,659 |
|
Interest expense |
|
|
31,862 |
|
|
|
67,979 |
|
|
|
86,477 |
|
|
|
127,354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,415,129 |
|
|
|
4,885,746 |
|
|
|
14,470,087 |
|
|
|
9,622,307 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before provision (benefit) for income taxes |
|
|
(271,396 |
) |
|
|
3,842,760 |
|
|
|
2,605,541 |
|
|
|
11,313,878 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision (benefit) for income taxes |
|
|
(52,651 |
) |
|
|
1,189,000 |
|
|
|
840,793 |
|
|
|
3,766,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(218,745 |
) |
|
$ |
2,653,760 |
|
|
$ |
1,764,748 |
|
|
$ |
7,547,878 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share (Note 4) |
|
$ |
(0.03 |
) |
|
$ |
0.31 |
|
|
$ |
0.21 |
|
|
$ |
0.89 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends declared per share of
common stock and paid in period |
|
$ |
0.07 |
|
|
$ |
0.08 |
|
|
$ |
0.11 |
|
|
$ |
0.105 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2)
PANHANDLE OIL AND GAS INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(Unaudited)
Six Months Ended March 31, 2007
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Class A voting |
|
|
Capital in |
|
|
Deferred |
|
|
|
|
|
|
|
| |
|
Common Stock |
|
|
Excess of |
|
|
Directors’ |
|
|
Retained |
|
|
|
|
| |
|
Shares |
|
|
Amount |
|
|
Par Value |
|
|
Compensation |
|
|
Earnings |
|
|
Total |
|
Balances at September 30, 2006 |
|
|
8,422,529 |
|
|
$ |
140,375 |
|
|
$ |
1,924,587 |
|
|
$ |
1,202,569 |
|
|
$ |
45,798,166 |
|
|
$ |
49,065,697 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
1,764,748 |
|
|
|
1,764,748 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends ($.11 per share) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(926,478 |
) |
|
|
(926,478 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in deferred directors’
compensation charged to expense |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
114,660 |
|
|
|
— |
|
|
|
114,660 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at March 31, 2007 |
|
|
8,422,529 |
|
|
$ |
140,375 |
|
|
$ |
1,924,587 |
|
|
$ |
1,317,229 |
|
|
$ |
46,636,436 |
|
|
$ |
50,018,627 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3)
PANHANDLE OIL AND GAS INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| |
|
|
|
|
|
|
|
|
| |
|
Six months ended March 31, |
|
| |
|
2007 |
|
|
2006 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Net income |
|
$ |
1,764,748 |
|
|
$ |
7,547,878 |
|
Adjustments to reconcile net income to net
cash provided by operating activities: |
|
|
|
|
|
|
|
|
Unrealized losses on natural gas collar contracts |
|
|
21,991 |
|
|
|
— |
|
Depreciation, depletion, amortization |
|
|
6,859,939 |
|
|
|
4,588,191 |
|
Provision for impairment |
|
|
1,629,833 |
|
|
|
136,395 |
|
Deferred income taxes |
|
|
712,500 |
|
|
|
950,530 |
|
Lease bonus income |
|
|
(32,757 |
) |
|
|
(55,258 |
) |
Exploration costs |
|
|
719,411 |
|
|
|
181,791 |
|
(Gain) or loss on sale of assets |
|
|
66,711 |
|
|
|
(180,194 |
) |
Equity in earnings of partnerships |
|
|
(162,696 |
) |
|
|
(329,074 |
) |
Directors’ deferred compensation |
|
|
114,660 |
|
|
|
102,007 |
|
Cash provided by changes in assets and liabilities: |
|
|
|
|
|
|
|
|
Oil and gas sales receivables |
|
|
(431,237 |
) |
|
|
83,558 |
|
Income tax receivables and other |
|
|
(24,424 |
) |
|
|
(1,267,391 |
) |
Accounts payable |
|
|
(1,281,586 |
) |
|
|
(484,968 |
) |
Accrued directors’ deferred compensation |
|
|
— |
|
|
|
(281,897 |
) |
Accrued interest payable |
|
|
(1,578 |
) |
|
|
(3,335 |
) |
Other accrued liabilities |
|
|
108,857 |
|
|
|
(10,194 |
) |
Income taxes payable |
|
|
— |
|
|
|
(599,669 |
) |
|
|
|
|
|
|
|
Total adjustments |
|
|
8,299,624 |
|
|
|
2,830,492 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
10,064,372 |
|
|
|
10,378,370 |
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Capital expenditures, including dry hole costs |
|
|
(9,610,041 |
) |
|
|
(10,466,411 |
) |
Proceeds from leasing of fee mineral acreage |
|
|
153,908 |
|
|
|
289,192 |
|
Investments in partnerships |
|
|
11,280 |
|
|
|
— |
|
Distributions received from partnerships |
|
|
203,768 |
|
|
|
370,146 |
|
Proceeds from sale of assets |
|
|
332,225 |
|
|
|
92,485 |
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(8,908,860 |
) |
|
|
(9,714,588 |
) |
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Borrowings under credit facility |
|
|
5,365,337 |
|
|
|
— |
|
Payments of loan principal |
|
|
(5,163,489 |
) |
|
|
(1,000,002 |
) |
Payments of dividends |
|
|
(926,478 |
) |
|
|
(883,144 |
) |
|
|
|
|
|
|
|
Net cash used in financing activities |
|
|
(724,630 |
) |
|
|
(1,883,146 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents |
|
|
430,882 |
|
|
|
(1,219,364 |
) |
Cash and cash equivalents at beginning of period |
|
|
434,353 |
|
|
|
1,638,833 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
865,235 |
|
|
$ |
419,469 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Schedule of Noncash Investing and Financing Activities: |
|
|
|
|
|
|
|
|
Receivable from sale of assets |
|
$ |
176,381 |
|
|
$ |
— |
|
|
|
|
|
|
|
|
Reclassification of deferred compensation as equity |
|
$ |
— |
|
|
$ |
1,053,408 |
|
|
|
|
|
|
|
|
Additions and revisions, net, to asset retirement obligations |
|
$ |
197,697 |
|
|
$ |
— |
|
|
|
|
|
|
|
|
Additions to properties and equipment included in accounts payable |
|
$ |
1,298,501 |
|
|
$ |
1,492,703 |
|
|
|
|
|
|
|
|
(See accompanying notes)
(4)
PANHANDLE OIL AND GAS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1: Accounting Principles and Basis of Presentation
The accompanying unaudited condensed consolidated financial statements have been prepared in
accordance with the instructions to Form 10-Q as prescribed by the Securities and Exchange
Commission, and include the Company’s wholly owned subsidiary, Wood Oil Company (Wood). Management
of Panhandle Oil and Gas Inc. (formerly Panhandle Royalty Company) believes that all adjustments
necessary for a fair presentation of the consolidated financial position and results of operations
for the periods have been included. All such adjustments are of a normal recurring nature. The
consolidated results are not necessarily indicative of those to be expected for the full year. The
Company’s fiscal year runs from October 1 through September 30.
NOTE 2: Income Taxes
The Company’s provision (benefit) for income taxes is reflective of excess percentage
depletion, reducing the Company’s effective tax rate from the federal statutory rate.
NOTE 3: Stockholders’ Equity
On December 13, 2005, the Company’s Board of Directors declared a 2-for-1 stock split of
outstanding Class A common stock. The Class A common stock split was effected in the form of a
stock dividend, distributed on January 9, 2006 to shareholders of record on December 29, 2005.
All references to number of shares and per share information in the accompanying consolidated
financial statements have been adjusted to reflect the stock split.
NOTE 4: Earnings per Share
Earnings per share is calculated using net income (loss) divided by the weighted average
number of common shares outstanding (including unissued, vested directors’ shares (72,165 and
63,786 for fiscal 2007 and 2006, respectively) after October 19, 2005 – see Note 7) during the
period.
NOTE 5: Long-term Debt
In October 2006, the Company refinanced its credit facility with BancFirst of Oklahoma City,
Oklahoma with a credit facility from Bank of Oklahoma (BOK). The BOK Agreement consisted of a term
loan in the amount of $2,500,000 and a revolving loan in the amount of $50,000,000 which is subject
to a semi-annual borrowing base determination. The current borrowing base under the BOK Agreement
is $10,000,000. The term loan matures on September 1, 2007, and the revolving loan matures on
October 31, 2009. Monthly payments, which began December 1, 2006, on the term loan are $250,000,
plus accrued interest. Borrowings under the revolving loan are due at maturity. The term loan
bears interest at 30 day LIBOR plus .75%. The revolving loan bears interest at the national prime
rate minus from 1.375% to .75%, or 30 day LIBOR plus from 1.375% to 2.0%. The interest rate
charged will be based on the percent of the value advanced of the calculated loan value of
Panhandle’s oil and gas reserves. The interest rate spread from LIBOR or prime increases as a
larger percent of the loan value of Panhandle’s oil and gas properties is advanced. At March 31,
2007 the interest rate for the term note was 6.07% and for the revolving loan was 6.695%.
NOTE 6: Deferred Compensation Plan for Directors
No shares were issued under the Plan in the 2007 period. Effective October 19, 2005 the Plan
was amended such that upon retirement, termination or death of the director or upon a change in
control of the Company, the shares accrued under the Plan will be issued to the director. This
amendment removed the conversion to cash option available under the Plan, which eliminated
the requirement to adjust the deferred compensation liability for changes in the market value of
the Company’s common stock after October 19, 2005. The adjustment of the liability to market value
of the shares at the closing price on October 19, 2005 resulted in a credit to general and
administrative expense of approximately $288,000. This change reduced volatility in the Company’s
earnings resulting from the charges to expense caused by market value changes in the Company’s
common stock. The deferred compensation obligation at the date of the Plan’s amendment was
reclassified to stockholders’ equity.
(5)
NOTE 7: Capitalized Costs
Oil and gas properties include costs of $557,809 on exploratory wells which were drilling
and/or testing at March 31, 2007.
NOTE 8: Derivatives
The Company periodically utilizes certain derivative contracts, including collars, to reduce
its exposure to unfavorable changes in natural gas prices. Volumes under such contracts do not
exceed expected production. The Company’s collars contain a fixed floor price and a fixed ceiling
price. If market prices exceed the ceiling price or fall below the floor, then the Company will
receive the difference between the floor and market price or pay the difference between the ceiling
and market price. If market prices are between the ceiling and the floor, then no payments or
receipts related to the collars are required.
The Company accounts for its derivative contracts under Financial Accounting Standards Board
Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, (SFAS
No. 133). Under the provision of SFAS No. 133, the Company is required to recognize all derivative
instruments as either assets or liabilities in the consolidated balance sheet at fair value. The
accounting for changes in the fair value of a derivative depends on the intended use of the
derivative and resulting designation. For derivatives designated as cash flow hedges and meeting
the effectiveness guidelines of SFAS No. 133, changes in fair value are recognized in other
comprehensive income (loss) until the hedged item is recognized in earnings. Hedge effectiveness is
required to be measured at least quarterly based on relative changes in fair value between the
derivative contract and hedged item during the period of hedge designation. The ineffective portion
of a derivative’s change in fair value is recognized currently in earnings. For derivative
instruments not designated as hedging instruments, the change in fair value is recognized in
earnings during the period of change as a change in derivative fair value. Amounts recorded in
unrealized gains (losses) on derivative activities do not represent cash gains or losses. Rather,
these amounts are temporary valuation swings in contracts that are not entitled to receive hedge
accounting treatment.
The Company had not, through fiscal 2006, entered into derivative instruments to hedge the
price risk on its oil or gas production. Beginning in fiscal year 2007, the Company has entered in
costless collar arrangements intended to reduce the Company’s exposure to short-term fluctuations
in the price of natural gas. Collar contracts set a minimum price, or floor and provide for
payments to the Company if the basis adjusted price falls below the floor or require payments by
the Company if the basis adjusted price rises above the ceiling. These arrangements cover only a
portion of the Company’s production and provide only partial price protection against declines in
natural gas prices. These economic hedging arrangements may expose the Company to risk of
financial loss and limit the benefit of future increases in prices. The derivative instruments
will settle based on the prices below which are tied to indexes for certain pipelines in Oklahoma.
In December 2006, the Company entered into the following three natural gas collar contracts.
| |
|
|
First Contract: |
|
|
Production volume covered |
|
30,000 mmbtu/month |
Period covered |
|
January through December of 2007 |
Prices |
|
Floor of $6.00 and a ceiling of $9.20 |
Second Contract: |
|
|
Production volume covered |
|
40,000 mmbtu/month |
Period covered |
|
January through December of 2007 |
Prices |
|
Floor of $6.00 and a ceiling of $9.20 |
Third Contract: |
|
|
Production volume covered |
|
30,000 mmbtu/month |
Period covered |
|
January through December of 2007 |
Prices |
|
Floor of $6.00 and a ceiling of $10.20 |
(6)
In March 2007, the Company entered into the following three additional natural gas collar
contracts.
| |
|
|
First Contract: |
|
|
Production volume covered |
|
20,000 mmbtu/month |
Period covered |
|
April through September of 2007 |
Prices |
|
Floor of $7.00 and a ceiling of $7.85 |
Second Contract: |
|
|
Production volume covered |
|
30,000 mmbtu/month |
Period covered |
|
April through September of 2007 |
Prices |
|
Floor of $7.00 and a ceiling of $7.45 |
Third Contract: |
|
|
Production volume covered |
|
20,000 mmbtu/month |
Period covered |
|
April through September of 2007 |
Prices |
|
Floor of $7.00 and a ceiling of $7.45 |
While the Company believes that its derivative contracts are effective in achieving the risk
management objective for which they were intended, the Company has elected not to complete all of
the documentation requirements necessary under SFAS No. 133 to permit these derivative contracts to
be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was
($21,991) as of March 31, 2007 (none as of March 31, 2006) resulting in net unrealized losses of
$21,991 and realized gains of $49,200 in the six months ended March 31, 2007.
NOTE 9: Exploration Costs
Certain non-producing leases (aggregate carrying value of $177,954) which expired in March and
April of 2007 and certain non-producing leases (aggregate carrying value of $45,897) which will
expire in June and August of 2007 were fully impaired in fiscal 2007 and charged to exploration
costs. In addition, one large cost exploratory dry hole ($493,776 in cost) was charged to
exploration costs in 2007.
NOTE 10: Reserve Estimation
Changes in crude oil and natural gas reserve estimates affect the Company’s calculation of
depreciation, depletion and amortization, provision for abandonment and assessment of the need for
asset impairments. On an annual basis, with a semi-annual update, the Company’s consulting
engineer (the Company employed a new consulting engineer beginning with the March 31, 2007
semi-annual update), with assistance from Company geologists, prepares estimates of crude oil and
natural gas reserves. As required by the guidelines and definitions established by the SEC, these
estimates are based on current crude oil and natural gas
pricing. Crude oil and natural gas prices are volatile and largely affected by worldwide
production and consumption and are outside the control of management.
In the March 31, 2007 reserve report, changes in approximately fifty of the Company’s over
1,250 working interest wells reserve evaluations were reduced significantly enough by the Company’s
new consulting engineer to result in significant additional DD&A charges on those wells, which
total approximately $1,400,000.
The net carrying value of the Company’s oil and gas properties is compared to the estimated
future net cash flows from those properties on a field by field basis. Those fields on which the
carrying value exceeds the estimated future net cash flows are then impaired to the 10% discounted
amount of the estimated future net cash flows, the Company’s assumed fair value of those fields.
Projected future crude oil and natural gas pricing assumptions are based on NYMEX futures contract
prices adjusted for an average Oklahoma sales price differential. These prices are then used in
the above discussed calculation of estimated future net cash flows. Lower reserve estimates, and
associated estimated future net cash flow, on certain wells with declining production resulted in
$1,100,000 of impairment on one western Oklahoma field.
ITEM 2 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
Forward-Looking Statements for fiscal 2007 and later periods are made in this document. Such
statements represent estimates by management based on the Company’s historical operating trends,
its proved oil and gas reserves and other information currently available to management. The
Company cautions that the forward-looking statements provided herein are subject to all the risks
and uncertainties incident to the acquisition, development and marketing of, and exploration for
oil and gas reserves. These risks include, but are not limited to, oil and natural gas price risk,
drilling and equipment cost risk,
(7)
field services cost risk, environmental risks, drilling risk,
reserve quantity risk and operations and production risk. For all the above reasons, actual
results may vary materially from the forward-looking statements and there is no assurance that the
assumptions used are necessarily the most likely to occur.
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 2007, the Company had positive working capital of $6,273,710, as compared to
positive working capital of $4,997,714 at September 30, 2006. The increase results from increased
cash and oil and gas sales receivable and a decrease in debt due within one year.
Cash flow remains strong. Additions to properties and equipment for oil and gas activities
for the 2007 six-month period amounted to $10,908,542. Management currently expects to commit to
capital expenditures for oil and gas activities of approximately $31,000,000 for fiscal 2007. The
substantial increase in capital spending is a result of continued high drilling activity combined
with the implementation of management’s strategy to participate in new wells with larger interests
to increase the Company’s average overall working interest percentage. Drilling in the Woodford
Shale unconventional resource play in southeast Oklahoma is and will continue to be a large
component of expected capital additions for the next several years. As drilling activity remains
high, costs for drilling rigs, well equipment and services also remain high, and are expected to
remain so for the remainder of fiscal 2007. Any acquisitions of oil and gas properties would
further increase the capital addition amount.
The Company has historically funded capital additions, overhead costs and dividend payments
from operating cash flow and has utilized, at times, the revolving line-of-credit facility to help
fund these expenditures. With the uncertainty of natural gas prices, and their effect on cash
flow, some amounts have been and will be in the next several quarters borrowed on a temporary basis
under the Company’s credit facility. The Company has substantial availability under its bank debt
facility and the availability could be increased, if needed. In addition, the Company has entered
into natural gas collar contracts (discussed in Note 8 above) to help guard against potential
negative price fluctuations which would reduce capital available for drilling new oil and gas
wells.
RESULTS OF OPERATIONS
THREE MONTHS ENDED MARCH 31, 2007 – COMPARED TO THREE MONTHS ENDED MARCH 31, 2006
Overview:
The Company recorded a second quarter 2007 net loss of $218,745, or $.03 per share, as
compared to a net income of $2,653,760 or $.31 per share in the 2006 quarter. The 2007 loss is
principally the result of non-cash charges, including; impairment charges of approximately
$1,100,000 on one field in western Oklahoma which continues to have production declines
resulting in reduced estimated future cash flows, approximately fifty of the Company’s over 1,250
working interest wells reserve evaluations were reduced which resulted in significant additional
DD&A charges totaling approximately $1,400,000, and the Company recognized an unrealized loss on
the natural gas collar contracts in place of $627,011 in the quarter.
Revenues:
Total revenues decreased $584,773 or 7% for the 2007 quarter. The decrease was primarily the
result of $627,011 unrealized losses on natural gas collar contracts. A $108,324 increase in oil
and gas sales resulted from a 14% increase in gas sales volumes for the 2007 quarter offset by an
8% decline in gas sales prices. Both oil sales volumes and average oil sales prices decreased in
the 2007 quarter. The table below outlines the Company’s production and average sales prices for
oil and natural gas for the three month periods of fiscal 2007 and 2006:
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
BARRELS |
|
AVERAGE |
|
MCF |
|
AVERAGE |
|
MCFE |
| |
|
SOLD |
|
PRICE |
|
SOLD |
|
PRICE |
|
SOLD |
Three months ended 3/31/07 |
|
|
21,877 |
|
|
$ |
55.68 |
|
|
|
1,173,779 |
|
|
$ |
6.17 |
|
|
|
1,305,041 |
|
Three months ended 3/31/06 |
|
|
23,964 |
|
|
$ |
61.45 |
|
|
|
1,029,529 |
|
|
$ |
6.68 |
|
|
|
1,173,313 |
|
The continuing increase in drilling expenditures and the Company’s stated goal of increasing
its working interests in new wells drilled continues to result in increased production volumes for
gas, as compared to fiscal 2006. The Company’s drilling continues to be concentrated on gas
production. New wells coming on line are replacing the decline in production of older wells, and
the Company expects to continue to have additional new production come on line in the last six
months of 2007.
(8)
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Quarter ended |
|
Barrels Sold |
|
MCF Sold |
|
MCFE |
3/31/07 |
|
|
21,877 |
|
|
|
1,173,779 |
|
|
|
1,305,041 |
|
12/31/06 |
|
|
22,567 |
|
|
|
1,198,955 |
|
|
|
1,334,357 |
|
9/30/06 |
|
|
26,701 |
|
|
|
1,216,720 |
|
|
|
1,376,926 |
|
6/30/06 |
|
|
21,473 |
|
|
|
1,005,976 |
|
|
|
1,134,814 |
|
3/31/06 |
|
|
23,964 |
|
|
|
1,029,529 |
|
|
|
1,173,313 |
|
Unrealized Losses on Natural Gas Collar Contracts:
The Company’s fair value of derivative contracts was ($21,991) as of March 31, 2007 (none as
of March 31, 2006) resulting in an unrealized loss of $627,011 in the three months ended March 31,
2007. The Company received a cash payment of $49,200 in February 2007 under the contracts.
Gain on sales, interest, income of partnerships and other:
These items increased $43,308 in the 2007 period as compared to the 2006 period as a class
action lawsuit settlement of approximately $65,000 was received in the 2007 period. Partnership
income continues to be reduced in 2007 due to lower natural gas prices and partnership
expenditures.
Lease Operating Expenses (LOE):
LOE increased $141,695 or 21% in the 2007 quarter to $.64 per mcfe, as compared to $.59 per
mcfe in the 2006 quarter. The increase in per mcfe amounts result from the continuing increase in
general oilfield service and supply prices.
Production Taxes:
Production taxes increased $27,450 or 5% in the 2007 quarter. The increase is the result of
the larger oil and gas revenues in the 2007 quarter, as production taxes are paid as a percentage
of these revenues, and production tax refunds received reducing expenses in the 2006 quarter.
Exploration Costs:
These costs decreased $103,803 in the 2007 quarter as there were no dry holes in the quarter
as compared to one dry hole in the 2006 quarter. The 2007 costs related to expired leasehold.
Depreciation,
Depletion and Amortization (DD&A):
DD&A increased $1,866,366 or 81% in the 2007 quarter to $3.19 per mcfe as compared to $1.96
per mcfe in the 2006 quarter. Approximately fifty of the Company’s over 1,250 working interest
wells reserve evaluations were reduced significantly enough by the Company’s new consulting
engineer to result in significant additional DD&A charges on those wells, which total approximately
$1,400,000. Due to these reserve reductions, elevated DD&A costs are
expected on these wells through the remainder of fiscal 2007. Finally, the overall general price increases in drilling costs, completion costs and
equipment costs the last few years continues to increase DD&A costs.
Provision for Impairment:
The provision for impairment increased $1,469,523 in the 2007 quarter. Approximately
$1,100,000 of the impairment provision relates to one field in western Oklahoma, in which the
majority of the wells were drilled in the 2003-2006 time period. These wells continue to suffer
production declines and thus lower reserve estimates which then decrease future cash flow estimates
which cause the asset carrying value impairment.
General and Administrative Costs (G&A):
G&A costs increased $35,024 or 4% in the 2007 quarter principally due to increased personnel
related costs.
Income Taxes:
The 2007 quarter benefit for income taxes decreased net loss. The Company utilizes excess
percentage depletion to reduce its effective tax rate from the federal statutory rate. The
effective tax rate estimate was 31% for the 2006 period.
(9)
SIX MONTHS ENDED MARCH 31, 2007 – COMPARED TO SIX MONTHS ENDED MARCH 31, 2006
Overview:
The Company recorded a six month period 2007 net income of $1,764,748, or $.21 per share, as
compared to a net income of $7,547,878 or $.89 per share in the 2006 period.
Revenues:
Total revenues decreased $3,860,557 or 18% for the 2007 period. The decrease is principally
the result of a 28% decline in the average sales price for natural gas in the 2007 period somewhat
offset by a 14% increase in natural gas sales volumes in the 2007 period. The Company currently
expects natural gas prices to remain relatively flat for the upcoming summer months with oil prices
expected to somewhat trend upward during the summer months. Oil sales volumes decreased 9% and the
average sales price decreased 5%. The table below outlines the Company’s production and average
sales prices for oil and natural gas for the six month periods of fiscal 2007 and 2006:
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
BARRELS |
|
AVERAGE |
|
MCF |
|
AVERAGE |
|
MCFE |
| |
|
SOLD |
|
PRICE |
|
SOLD |
|
PRICE |
|
SOLD |
Six months ended 3/31/07 |
|
|
44,444 |
|
|
$ |
56.32 |
|
|
|
2,372,734 |
|
|
$ |
5.91 |
|
|
|
2,639,398 |
|
Six months ended 3/31/06 |
|
|
48,965 |
|
|
$ |
59.25 |
|
|
|
2,076,446 |
|
|
$ |
8.26 |
|
|
|
2,370,236 |
|
The continuing increase in drilling activities and the Company’s stated goal of increasing its
working interests in new wells drilled is expected to continue to result in increased production
volumes of natural gas in fiscal 2007 as compared to fiscal 2006. New drilling continues to be
concentrated on gas production. During the last year, new wells coming on line have more than
replaced the decline in production of older wells. The Company expects to continue to have
additional production come on line in future periods of 2007.
Production by quarter for the last five quarters was as follows:
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Quarter ended |
|
Barrels Sold |
|
MCF Sold |
|
MCFE |
3/31/07 |
|
|
21,877 |
|
|
|
1,173,779 |
|
|
|
1,305,041 |
|
12/31/06 |
|
|
22,567 |
|
|
|
1,198,955 |
|
|
|
1,334,357 |
|
9/30/06 |
|
|
26,701 |
|
|
|
1,216,720 |
|
|
|
1,376,926 |
|
6/30/06 |
|
|
21,473 |
|
|
|
1,005,976 |
|
|
|
1,134,814 |
|
3/31/06 |
|
|
23,964 |
|
|
|
1,029,529 |
|
|
|
1,173,313 |
|
Unrealized Losses on Natural Gas Collar Contracts:
The Company’s fair value of derivative contracts was ($21,991) as of March 31, 2006 (none as
of September 30, 2006) resulting in unrealized losses of $21,991 in the six months ended March 31,
2007.
Gain on sales, interest, income of partnerships and other:
These items decreased $168,446 in the 2007 period as compared to the 2006 period as certain
fee mineral acreage was sold in the 2006 period resulting in a gain of approximately $80,000 and a
class action lawsuit settlement of approximately $123,000 was also recorded in the 2006 period.
Partnership income continues to be reduced in 2007 due to lower natural gas prices and partnership
expenditures.
Lease Operating Expenses (LOE):
LOE increased $211,394 or 14% in the 2007 period to $.66 per mcfe, as compared to $.64 per
mcfe in the 2006 period. The increase in per mcfe amounts result from the continuing increase in
general oilfield service and supply prices.
Production Taxes:
Production taxes decreased $213,240 or 17% in the 2007 period. The decrease is the result of
the reduction in oil and gas revenues in the 2007 period, as production taxes are paid as a
percentage of these revenues.
Exploration Costs:
(10)
These costs increased $537,620 in the 2007 period. This increase is principally the result of
one exploratory dry hole drilled in the 2007 period in the Mystic Bayou prospect in Louisiana and a
charge to exploration costs of approximately $197,000 for leasehold with the lease terms expiring
in the 2007 period.
Depreciation,
Depletion and Amortization (DD&A):
DD&A increased $2,271,748 or 50% in the 2007 period to $2.60 per mcfe as compared to $1.94 per
mcfe in the 2006 period. Approximately fifty of the Company’s over 1,250 working interest wells
reserve evaluations were reduced significantly enough by the Company’s new consulting engineer to
result in significant additional DD&A charges on those wells, which total approximately $1,400,000.
Due to these reserve reductions, elevated DD&A costs are
expected on these wells through the remainder of fiscal 2007. Finally, the overall general price increases in drilling costs, completion costs and equipment
costs the last few years continues to increase DD&A costs.
Provision for Impairment:
The provision for impairment increased $1,493,438 in the 2007 period. Approximately
$1,100,000 of the impairment provision relates to one field in western Oklahoma, in which the
majority of the wells were drilled in the 2003-2006 time period. These wells continue to suffer
production declines and thus lower reserve estimates which then decrease future cash flow estimates
which cause the asset carrying value impairment.
General and Administrative Costs (G&A):
G&A costs increased $426,055 or 25% in the 2007 period. The increase is principally the
result of an amendment to the Directors’ Deferred Compensation Plan (the Plan). Effective October
19, 2005 the Plan was amended such that upon retirement, termination or death of the director or
upon a change in control of the Company, the shares accrued under the Plan will be issued to the
director. This amendment removed the conversion to cash option available under the Plan, which
eliminated the requirement to adjust the deferred compensation liability for changes in the market
value of the Company’s common stock after October 19, 2005. The adjustment of the liability to
market value of the shares at the closing price on October 19, 2005 resulted in a credit to G&A of
approximately $282,000 in the 2006 period. In addition, the deferred compensation liability after
the October 19, 2005 adjustment was reclassified to stockholders’ equity. Other G&A costs
increasing in the 2007 period included personnel related costs, professional fees and shareholder
reporting expenses.
Income Taxes:
The 2007 period provision for income taxes decreased due to reduced income before provision
for income taxes. The Company utilizes excess percentage depletion to reduce its effective tax
rate from the federal statutory rate. The effective tax rate estimate was 32% for the 2007 period
and 33% for the 2006 period.
CRITICAL ACCOUNTING POLICIES
Preparation of financial statements in conformity with accounting principles generally
accepted in the United States requires management to make estimates, judgments and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of
contingent assets and liabilities. However, the accounting principles used by the Company
generally do not change the Company’s reported cash flows or liquidity. Generally, accounting
rules do not involve a selection among alternatives, but involve a selection of the appropriate
policies for applying the basic principles. Interpretation of the existing rules must be done and
judgments made on how the specifics of a given rule apply to the Company.
The more significant reporting areas impacted by management’s judgments and estimates are
crude oil and natural gas reserve estimation, impairment of assets, oil and gas sales revenue
accruals and provision for income tax. Management’s judgments and estimates in these areas are
based on information available from both internal and external sources, including engineers,
geologists, consultants and historical experience in similar matters. Actual results could differ
from the estimates as additional information becomes known. The oil and gas sales revenue accrual
is particularly subject to estimates due to the Company’s status as a non-operator on all of its
properties. Production information obtained from well operators is substantially delayed. This
causes the estimation of recent production, used in the oil and gas revenue accrual, to be subject
to some variations.
(11)
Oil and Gas Reserves
Of these judgments and estimates, management considers the estimation of crude oil and nature
gas reserves to be the most significant. These estimates affect the unaudited standardized measure
disclosures, as well as DD&A and impairment calculations. Changes in crude oil and natural gas
reserve estimates affect the Company’s calculation of depreciation, depletion and amortization,
provision for abandonment and assessment of the need for asset impairments. On an annual basis,
with a semi-annual update, the Company’s consulting engineer (the Company employed a new consulting
engineer beginning with the March 31, 2007 semi-annual update), with assistance from Company
geologists, prepares estimates of crude oil and natural gas reserves based on available geologic
and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir
performance history, production data and other available sources of engineering, geological and
geophysical information. As required by the guidelines and definitions established by the SEC,
these estimates are based on current crude oil and natural gas pricing. Crude oil and natural gas
prices are volatile and largely affected by worldwide production and consumption and are outside
the control of management. Projected future crude oil and natural gas pricing assumptions are used
by management to prepare estimates of crude oil and natural gas reserves used in formulating
management’s overall operating decisions in the exploration and production segment.
Successful Efforts Method of Accounting
The Company has elected to utilize the successful efforts method of accounting for its oil and
gas exploration and development activities. Exploration expenses, including geological and
geophysical costs, rentals and exploratory dry holes, are charged against income as incurred.
Costs of successful wells and related production equipment and developmental dry holes are
capitalized and amortized by property using the unit-of-production method as oil and gas is
produced. This accounting method may yield significantly different operating results than the full
cost method.
Impairment of Assets
All long-lived assets, principally oil and gas properties, are monitored for potential
impairment when circumstances indicate that the carrying value of the asset may be greater than its
estimated future net cash flows. The evaluations involve significant judgment since the results
are based on estimated future events, such as inflation rates, future sales prices for oil and gas,
future production costs, estimates of future oil and gas reserves to be recovered and the timing
thereof, the economic and regulatory climates and other factors. The need to test a property for
impairment may result from significant declines in sales prices or unfavorable adjustments to oil
and gas reserves. Any assets held for sale are reviewed for impairment when the Company approves
the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to
material revision in future periods. Because of the uncertainty inherent in these factors, the
Company can not predict when or if future impairment charges will be recorded.
Oil and Gas Sales Revenue Accrual
The Company does not operate any of its oil and gas properties, and it primarily holds small
interests in several thousand wells. Thus, obtaining timely production data from the well
operators is extremely difficult. This requires the Company to utilize past production receipts
and estimated sales price information to estimate its oil and gas sales revenue accrual at the end
of each quarterly period. The oil and gas accrual can be impacted by many variables, including
initial high production rates of new wells and subsequent rapid decline rates of those wells and
rapidly changing market prices for natural gas. This could lead to an over or under accrual of oil
and gas sales at the end of any particular quarter. Based on past history, the estimated accrual
has been materially accurate.
Income Taxes
The estimation of the amounts of income tax to be recorded by the Company involves
interpretation of complex tax laws and regulations as well as the completion of complex
calculations, including the determination of the Company’s percentage depletion deduction.
Although the Company’s management believes its tax accruals are adequate, differences may occur in
the future depending on the resolution of pending and new tax matters.
The above description of the Company’s critical accounting policies is not intended to be an
all-inclusive discussion of the uncertainties considered and estimates made by management in
applying accounting principles and policies. Results may vary significantly if different policies
were used or required and if new or different information becomes known to management.
(12)
ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company’s results of operations and operating cash flows can be significantly impacted by
changes in market prices for oil and gas. Based on the Company’s 2006 production, a $.10 per Mcf
change in the price received for natural gas production would result in a corresponding $430,000
annual change in pre-tax operating cash flow. A $1.00 per barrel change in the price received for
oil production would result in a corresponding $97,100 annual change in pre-tax operating cash
flow. Cash flows could also be impacted, to a lesser extent, by changes in the market interest
rates related to the revolving credit facility which bears interest at an annual variable interest
rate equal to the national prime rate minus from 1.375% to .75% or 30 day LIBOR plus from 1.375% to
2.0%. At March 31, 2007 the Company had $1,868,555 outstanding under this facility. The Company
has a $2,500,000 term loan with an outstanding balance of $1,499,946 at March 31, 2007 maturing on
September 1, 2007. The interest rate is 30 day LIBOR plus .75%. Based on total debt outstanding
at March 31, 2007 a .5% change in interest rates would result in a $16,800 annual change in pre-tax
operating cash flow.
The Company periodically utilizes certain derivative contracts, including collars, to reduce
its exposure to unfavorable changes in natural gas prices. Volumes under such contracts do not
exceed expected production. The Company’s collars contain a fixed floor price and a fixed ceiling
price. If market prices exceed the ceiling price or fall below the floor, then the Company will
receive the difference between the floor and market price or pay the difference between the ceiling
and market price. If market prices are between the ceiling and the floor, then no payments or
receipts related to the collars are required. The Company had not, through fiscal 2006, entered
into derivative instruments to hedge the price risk on its oil or gas production. Beginning in
fiscal year 2007, the Company has entered in costless collar arrangements intended to reduce the
Company’s exposure to short-term fluctuations in the price of natural gas. Collar contracts set a
minimum price, or floor and provide for payments to the Company if the basis adjusted price falls
below the floor or require payments by the Company if the basis adjusted price rises above the
ceiling. These arrangements cover only a portion of the Company’s production and provide only
partial price protection against declines in natural gas prices. These economic hedging
arrangements may expose the Company to risk of financial loss and limit the benefit of future
increases in prices. The derivative instruments will settle based on the prices below which are
tied to indexes for certain pipelines in Oklahoma.
ITEM 4 CONTROLS AND PROCEDURES
The Company maintains “disclosure controls and procedures,” as such term is defined in Rules
13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information
required to be disclosed in reports the Company files or submits under the Exchange Act is
recorded, processed, summarized and reported within the time periods specified in SEC rules and
forms, and that such information is collected and communicated to management, including the
Company’s Co-President/Chief Executive Officer and Co-President/Chief Financial Officer, as
appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating
its disclosure controls and procedures, management recognized that no matter how well conceived and
operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance
that the
objectives of the disclosure controls and procedures are met. The Company’s disclosure controls
and procedures have been designed to meet, and management believes that they do meet, reasonable
assurance standards. Based on their evaluation as of the end of the fiscal period covered by this
report, the Chief Operating Officer and Chief Financial Officer have concluded that, subject to the
limitations noted above, the Company’s disclosure controls and procedures were effective to ensure
that material information relating to the Company, including its consolidated subsidiary, is made
known to them. There were no changes in the Company’s internal control over financial reporting
that have materially affected, or are reasonably likely to materially affect, the Company’s
internal control over financial reporting made during the fiscal quarter or subsequent to the date
the assessment was completed.
PART II OTHER INFORMATION
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
| |
(a) |
|
The annual meeting of shareholders was held on March 8, 2007. |
| |
| |
(b) |
|
Three directors were elected for three-year terms at the meeting. The
directors elected and the results of voting were as follow: |
| |
|
|
|
|
|
|
|
|
| |
|
SHARES |
| Directors |
|
FOR |
|
WITHHELD |
Bruce M. Bell |
|
|
6,451,211 |
|
|
|
35,457 |
|
Robert O. Lorenz |
|
|
6,454,680 |
|
|
|
31,988 |
|
Robert E. Robotti |
|
|
6,447,275 |
|
|
|
39,373 |
|
| |
(c) |
|
Two proposals were also voted upon (i) a proposal to increase the authorized shares of the Company’s Class A |
(13)
| |
|
|
common stock from 12,000,000 shares to 24,000,000
shares, (ii) a proposal to change the Company’s name to Panhandle Oil and Gas Inc. |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
SHARES |
| |
|
FOR |
|
AGAINST |
|
ABSTAINING |
Proposal (i) |
|
|
6,176,747 |
|
|
|
233,731 |
|
|
|
76,190 |
|
Proposal (ii) |
|
|
6,079,462 |
|
|
|
348,949 |
|
|
|
58,257 |
|
ITEM 6 EXHIBITS AND REPORT ON FORM 8-K
(a) EXHIBITS – Exhibit 3(i) – Articles of Incorporation
Exhibit 31.1 and 31.2 – Certification under Section 302 of the Sarbanes-Oxley Act of
2002
Exhibit 32.1 and 32.2 – Certification under Section 906 of the Sarbanes-Oxley
Act of 2002
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| |
|
|
|
|
|
|
|
|
|
|
|
PANHANDLE OIL AND GAS INC. |
|
|
|
|
|
|
|
May 7, 2007
|
|
/s/ Michael C. Coffman |
|
|
|
|
|
|
|
Date
|
|
Michael C. Coffman, Co-President, |
|
|
|
|
Chief Financial Officer and Treasurer |
|
|
|
|
|
|
|
May 7, 2007
|
|
/s/ Ben D. Hare |
|
|
|
|
|
|
|
Date
|
|
Ben D. Hare, Co-President |
|
|
|
|
and Chief Operating Officer |
|
|
|
|
|
|
|
May 7, 2007
|
|
/s/ Lonnie J. Lowry |
|
|
|
|
|
|
|
Date
|
|
Lonnie J. Lowry, Vice President |
|
|
|
|
and Chief Accounting Officer |
|
|
(14)
EXHIBIT INDEX
Exhibit 3(i) – Articles of Incorporation