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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

 

x	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the period ended March 31, 2012

 

¨	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 incorporation or organization)		(I.R.S. Employer 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.     x   Yes    ¨   No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive 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).     x   Yes    ¨   No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer		¨		Accelerated filer		x
Non-accelerated filer		¨		Smaller reporting company		¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    ¨  Yes    x  No

Outstanding shares of Class A Common stock (voting) at May 7, 2012: 8,239,532

 

 

 

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INDEX

 

Part I			Financial Information
									Page
			Item 1			Condensed Financial Statements
						Condensed Balance Sheets – March 31, 2012 and September 30, 2011			4
						Condensed Statements of Operations – Three months and six months ended March 31, 2012 and 2011			5
						Statements of Stockholders’ Equity – Six months ended March 31, 2012 and 2011			6
						Condensed Statements of Cash Flows – Six months ended March 31, 2012 and 2011			7
						Notes to Condensed Financial Statements			8
			Item 2			Management’s discussion and analysis of financial condition and results of operations			16
			Item 3			Quantitative and qualitative disclosures about market risk			21
			Item 4			Controls and procedures			22
Part II   Other Information									22
			Item 2			Unregistered Sales of Equity Securities and Use of Proceeds			22
			Item 4			Submission of matters to a vote of security holders			23
			Item 6			Exhibits and reports on Form 8- K			23
						Signatures			23

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The following defined terms are used in this report:

“Bbl” means barrel;

“Board” means board of directors;

“CEGT” means Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma;

“DD&A” means depreciation, depletion and amortization;

“ESOP” refers to the Panhandle Oil and Gas Inc. Employee Stock Ownership and 401(k) Plan, a tax qualified, defined contribution plan;

“FASB” means the Financial Accounting Standards Board;

“G&A” means general and administrative costs;

“Independent Consulting Petroleum Engineer(s)” or “Independent Consulting Petroleum Engineering Firm” refers to DeGolyer and MacNaughton of Dallas, Texas;

“LOE” means lease operating expense;

“Mcf” means thousand cubic feet;

“Mcfe” means natural gas stated on an Mcf basis and crude oil and natural gas liquids converted to a thousand cubic feet of natural gas equivalent by using the ratio of one Bbl of crude oil or natural gas liquids to six Mcf of natural gas;

“minerals”, “mineral acres” or “mineral interests” refers to fee mineral acreage owned in perpetuity by the Company;

“NGL” means natural gas liquids;

“NYMEX” refers to the New York Mercantile Exchange;

“PEPL” means Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline;

“play” is a term applied to identified areas with potential oil and/or natural gas reserves;

“SEC” means the United States Securities and Exchange Commission;

“working interest” refers to well interests in which the Company pays a share of the costs to drill, complete and operate a well and receives a proportionate share of production.

Fiscal year references

All references to years in this report, unless otherwise noted, refer to the Company’s fiscal year end of September 30. For example, references to 2012 mean the fiscal year ended September 30, 2012.

References to natural gas

Excluding 2012 amounts, all references to natural gas reserves, production, sales and prices include associated natural gas liquids.

References to oil and natural gas properties inherently include natural gas liquids associated with such properties.

 

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PART 1 FINANCIAL INFORMATION

PANHANDLE OIL AND GAS INC.

CONDENSED BALANCE SHEETS

 

		March 31, 2012				September 30, 2011
		(unaudited)
Assets
Current assets:
Cash and cash equivalents		$	1,119,676			$	3,506,999
Oil and natural gas sales receivables			6,950,126				8,811,404
Deferred income taxes			26,900				—
Refundable income taxes			—				354,246
Refundable production taxes			479,621				223,672
Derivative contracts			309,658				269,329
Other			195,792				95,408
Total current assets			9,081,773				13,261,058
Properties and equipment, at cost, based on successful efforts accounting:
Producing oil and natural gas properties			260,460,706				230,554,198
Non-producing oil and natural gas properties			9,889,633				11,100,350
Furniture and fixtures			655,201				628,929
			271,005,540				242,283,477
Less accumulated depreciation, depletion and amortization			(155,307,113	)			(146,147,514	)
Net properties and equipment			115,698,427				96,135,963
Investments			823,028				667,504
Refundable production taxes			1,031,146				1,359,668
Total assets		$	126,634,374			$	111,424,193
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable		$	3,399,998			$	4,899,593
Deferred income taxes			—				7,100
Income taxes payable			283,863				—
Accrued liabilities and other			1,024,793				1,040,269
Total current liabilities			4,708,654				5,946,962
Long-term debt			13,809,501				—
Deferred income taxes			25,170,393				24,777,650
Asset retirement obligations			1,934,291				1,843,875
Derivative contracts			—				53,389
Stockholders’ equity:
Class A voting common stock, $.0166 par value;
24,000,000 shares authorized, 8,431,502 issued at March 31, 2012 and September 30, 2011			140,524				140,524
Capital in excess of par value			1,844,004				1,924,507
Deferred directors’ compensation			2,475,538				2,665,583
Retained earnings			82,698,964				79,771,563
			87,159,030				84,502,177
Less treasury stock, at cost; 191,970 shares at March 31, 2012 and 175,331 shares at September 30, 2011			(6,147,495	)			(5,699,860	)
Total stockholders’ equity			81,011,535				78,802,317
Total liabilities and stockholders’ equity		$	126,634,374			$	111,424,193

(See accompanying notes)

 

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PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF OPERATIONS

 

		Three Months Ended March 31,								Six Months Ended March 31,
		2012				2011				2012				2011
Revenues:			(unaudited)								(unaudited)
Oil and natural gas (and associated natural gas liquids) sales		$	9,565,898			$	10,907,935			$	21,310,175			$	20,639,509
Lease bonuses and rentals			166,727				28,490				1,921,918				141,855
Gains (losses) on derivative contracts			590,912				8,766				368,833				(12,673	)
Income from partnerships			113,373				32,268				240,317				110,316
			10,436,910				10,977,459				23,841,243				20,879,007
Costs and expenses:
Lease operating expenses			2,051,487				2,081,579				4,316,399				4,279,449
Production taxes			343,852				422,428				782,351				767,072
Exploration costs			41,688				290,353				355,058				577,457
Depreciation, depletion and amortization			4,940,961				3,631,385				9,083,374				7,066,196
Provision for impairment			217,262				828,019				580,809				828,019
Loss (gain) on asset sales, interest and other			29,537				(13,499	)			(47,504	)			(19,226	)
General and administrative			1,606,157				1,465,941				3,303,680				3,105,938
			9,230,944				8,706,206				18,374,167				16,604,905
Income before provision for income taxes			1,205,966				2,271,253				5,467,076				4,274,102
Provision for income taxes			530,000				499,000				1,379,000				1,075,000
Net income		$	675,966			$	1,772,253			$	4,088,076			$	3,199,102
Basic and diluted earnings per common share (Note 3)		$	0.08			$	0.21			$	0.49			$	0.38
Basic and diluted weighted average shares outstanding:
Common shares			8,249,954				8,281,059				8,253,079				8,291,549
Unissued, directors’ deferred compensation shares			133,851				119,943				133,387				119,652
			8,383,805				8,401,002				8,386,466				8,411,201
Dividends declared per share of common stock and paid in period		$	0.07			$	0.07			$	0.14			$	0.14

(See accompanying notes)

 

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PANHANDLE OIL AND GAS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

Six Months Ended March 31, 2012

 

		Class A voting								Capital in				Deferred
		Common Stock								Excess of				Directors’				Retained				Treasury				Treasury
		Shares				Amount				Par Value				Compensation				Earnings				Shares				Stock				Total
Balances at September 30, 2011			8,431,502			$	140,524			$	1,924,507			$	2,665,583			$	79,771,563				(175,331	)		$	(5,699,860	)		$	78,802,317
Purchase of treasury stock			—				—				—				—				—				(38,771	)			(1,158,957	)			(1,158,957	)
Restricted stock awards			—				—				148,793				—				—				—				—				148,793
Net income			—				—				—				—				4,088,076				—				—				4,088,076
Dividends ($.14 per share)			—				—				—				—				(1,160,675	)			—				—				(1,160,675	)
Distribution of deferred directors’ compensation			—				—				(229,296	)			(406,772	)			—				22,132				711,322				75,254
Increase in deferred directors’ compensation charged to expense			—				—				—				216,727				—				—				—				216,727
Balances at March 31, 2012			8,431,502			$	140,524			$	1,844,004			$	2,475,538			$	82,698,964				(191,970	)		$	(6,147,495	)		$	81,011,535
(unaudited)

 

STATEMENTS OF STOCKHOLDERS' EQUITY

Six Months Ended March 31, 2011

 

		Class A voting								Capital in				Deferred
		Common Stock								Excess of				Directors’				Retained				Treasury				Treasury
		Shares				Amount				Par Value				Compensation				Earnings				Shares				Stock				Total
Balances at September 30, 2010			8,431,502			$	140,524			$	1,816,365			$	2,222,127			$	73,599,733				(120,560	)		$	(4,196,753	)		$	73,581,996
Purchase of treasury stock			—				—				—				—				—				(45,682	)			(1,264,965	)			(1,264,965	)
Restricted stock awards			—				—				58,846				—				—				—				—				58,846
Net income			—				—				—				—				3,199,102				—				—				3,199,102
Dividends ($.14 per share)			—				—				—				—				(1,163,329	)			—				—				(1,163,329	)
Increase in deferred directors’ compensation charged to expense			—				—				—				235,950				—				—				—				235,950
Balances at March 31, 2011			8,431,502			$	140,524			$	1,875,211			$	2,458,077			$	75,635,506				(166,242	)		$	(5,461,718	)		$	74,647,600
(unaudited)

(See accompanying notes)

 

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PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF CASH FLOWS

 

		Six months ended March 31,
		2012				2011
		(unaudited)
Operating Activities
Net income		$	4,088,076			$	3,199,102
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			9,083,374				7,066,196
Impairment			580,809				828,019
Provision for deferred income taxes			358,743				467,000
Exploration costs			355,058				577,457
Net (gain) loss on sale of assets			(2,042,337	)			(139,955	)
Income from partnerships			(240,317	)			(110,316	)
Distributions received from partnerships			290,861				175,813
Directors’ deferred compensation expense			216,724				235,950
Restricted stock awards			148,793				58,846
Cash provided by changes in assets and liabilities:
Oil and natural gas sales receivables			1,861,278				965,987
Fair value of derivative contracts			(93,718	)			1,498,523
Refundable production taxes			72,573				57,958
Other current assets			(48,078	)			261,954
Accounts payable			100,827				325,408
Income taxes receivable			354,246				(758,332	)
Other non-current assets			308				—
Income taxes payable			283,863				(922,136	)
Accrued liabilities			(309,323	)			(206,139	)
Total adjustments			10,973,684				10,382,233
Net cash provided by operating activities			15,061,760				13,581,335
Investing Activities
Capital expenditures, including dry hole costs			(12,074,991	)			(11,065,925	)
Acquisition of working interest properties			(17,399,052	)			—
Acquisition of minerals and overrides			(1,443,893	)			—
Proceeds from leasing of fee mineral acreage			1,978,410				155,908
Investments in partnerships			(206,376	)			46,809
Proceeds from sales of assets			131,693				938
Excess tax benefit on stock-based compensation			75,257				—
Net cash used in investing activities			(28,938,952	)			(10,862,270	)
Financing Activities
Borrowings under debt agreement			32,458,470				—
Payments of loan principal			(18,648,969	)			—
Purchase of treasury stock			(1,158,957	)			(1,264,965	)
Payments of dividends			(1,160,675	)			(1,163,329	)
Net cash provided by (used in) financing activities			11,489,869				(2,428,294	)
Increase (decrease) in cash and cash equivalents			(2,387,323	)			290,771
Cash and cash equivalents at beginning of period			3,506,999				5,597,258
Cash and cash equivalents at end of period		$	1,119,676			$	5,888,029
Supplemental Schedule of Noncash Investing and Financing Activities
Additions to asset retirement obligations		$	35,816			$	13,380
Gross additions to properties and equipment		$	29,559,055			$	9,704,758
Net (increase) decrease in accounts payable for properties
and equipment additions			1,358,881				1,361,167
Capital expenditures and acquisitions, including dry hole costs		$	30,917,936			$	11,065,925

(See accompanying notes)

 

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PANHANDLE OIL AND GAS INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: Accounting Principles and Basis of Presentation

The accompanying unaudited condensed financial statements of Panhandle Oil and Gas Inc. (the Company) have been prepared in accordance with the instructions to Form 10-Q as prescribed by the Securities and Exchange Commission (SEC). Management of the Company believes that all adjustments necessary for a fair presentation of the financial position and results of operations and cash flows for the periods have been included. All such adjustments are of a normal recurring nature. The 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.

Certain amounts and disclosures have been condensed or omitted from these financial statements pursuant to the rules and regulations of the SEC. Therefore, these condensed financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s 2011 Annual Report on Form 10-K.

NOTE 2: Income Taxes

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits.

Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume or income, reduce estimated taxable income or add to estimated taxable loss projected for any year. The federal and Oklahoma excess percentage depletion estimates will be updated throughout the year until finalized with the detail well-by-well calculations at fiscal year-end. Federal and Oklahoma excess percentage depletion benefits, when a provision for income taxes is recorded, decrease the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is recorded. The benefits of federal and Oklahoma excess percentage depletion are not directly related to the amount of pre-tax income recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the quarter ended March 31, 2012, was 44% as compared to 22% for the quarter ended March 31, 2011. This increase is the result of an increase in the estimated annual effective tax rate during the second quarter due to higher expected fiscal 2012 income before provision for income taxes (mostly related to higher expected lease bonus income) projected as of March 31, 2012, as compared to projections as of December 31, 2011.

NOTE 3: Basic and Diluted Earnings per Share

Basic and diluted earnings per share is calculated using net income divided by the weighted average number of voting common shares outstanding, including unissued, vested directors’ deferred compensation shares during the period. The Company’s restricted stock awards are not included in the diluted earnings per share calculation because the effect would be anti-dilutive.

NOTE 4: Long-term Debt

The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving loan in the amount of $80,000,000 which is subject to a semi-annual borrowing base determination, wherein BOK applies their own current pricing forecast and a 9% discount rate to the Company’s proved reserves as calculated by the Company’s Independent Consulting Petroleum Engineering Firm. When applying the discount rate, BOK also applies an advance rate percentage to certain proved non-producing and proved undeveloped reserves. The facility has a borrowing base of $35,000,000 and is secured by certain of the Company’s properties with a carrying value of $25,964,473 at March 31, 2012. The facility matures on November 30, 2014. The interest rate is based on national prime plus from .50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%. The election of national prime or LIBOR is at the Company’s discretion. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the loan value of the Company’s oil and natural gas properties is advanced. The interest rate spread from national prime or LIBOR will be charged based on the percent of the value advanced of the calculated loan value of the Company’s oil and natural gas properties. At March 31, 2012, the effective interest rate was 2.55%.

The Company’s debt is recorded at the carrying amount on its balance sheet. The carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates.

Since the bank charges a customary non-use fee of .25% annually of the unused portion of the borrowing base, the Company has not requested the bank to increase its borrowing base beyond $35 million. Determinations of the borrowing base are made semi-annually or whenever the bank, in its sole discretion, believes that there has been a material change in the value of the oil and natural gas properties. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and may limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At March 31, 2012, the Company was in compliance with the covenants of the BOK agreement.

 

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NOTE 5: Deferred Compensation Plan for Directors

The Company has a deferred compensation plan for non-employee directors (the Plan). The Plan provides that each eligible director can individually elect to receive shares of Company stock rather than cash for Board and committee chair retainers, Board meeting fees and Board committee meeting fees. These shares are unissued and are credited to each director’s deferred fee account at the closing market price of the stock on the date earned. 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.

NOTE 6: Restricted Stock Plan

On March 11, 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 100,000 shares of common stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. The 2010 Stock Plan is designed to provide as much flexibility as possible for future grants of restricted stock so that the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate officers of the Company and to align their interests with those of the Company’s shareholders.

Effective March 2010, the board of directors approved the purchase of the Company’s common stock, from time to time, equal to the aggregate number of shares of common stock awarded pursuant to the Company’s 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.

The following table summarizes the Company’s pre-tax compensation expense for the three and six months ended March 31, 2012 and 2011, related to the Company’s performance based and non-performance based restricted stock.

 

		Three Months Ended								Six Months Ended
		March 31,								March 31,
		2012				2011				2012				2011
Performance based, restricted stock		$	43,031			$	14,303			$	64,418			$	14,303
Non-performance based, restricted stock			48,033				32,515				84,375				44,543
Total compensation expense		$	91,064			$	46,818			$	148,793			$	58,846

A summary of the Company’s unrecognized compensation cost for its unvested performance based and non-performance based restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.

 

		As of March 31, 2012
		Unrecognized Compensation Cost				Weighted Average Period (in years)
Performance based, restricted stock		$	409,039				2.38
Non-performance based, restricted stock			466,655				2.54
Total		$	875,694

Upon vesting, shares are expected to be issued out of shares held in treasury.

NOTE 7: Oil and Natural Gas Reserves

Management considers the estimation of the Company’s crude oil, natural gas and NGL reserves to be the most significant of its judgments and estimates. Changes in crude oil, natural gas and NGL reserve estimates affect the Company’s calculation of DD&A, provision for abandonment and assessment of the need for asset impairments. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from Company staff, prepares estimates of crude oil, natural gas and NGL reserves based on available geological 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. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing prices current with the period. The estimated oil, natural gas and NGL reserves were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil, natural gas and NGL price for each month within the 12-month period prior to the balance sheet date, held flat over the life of the properties. Crude oil, natural gas and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. However, projected future crude oil, natural gas and NGL pricing assumptions are used by management to prepare estimates of crude oil, natural gas and NGL reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions.

 

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NOTE 8: Impairment

All long-lived assets, principally oil and natural 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, natural gas and NGL, future production costs, estimates of future oil, natural gas and NGL 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, natural gas and NGL reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing updated estimates of future prices. The assessments at March 31, 2012 and 2011, resulted in $217,262 and $828,019 of impairment, respectively. For the six months ended March 31, 2012 and 2011, the assessment resulted in $580,809 and $828,019 of impairment, respectively. A reduction in oil, natural gas or NGL prices or a decline in reserve volumes could lead to additional impairment that may be material to the Company.

NOTE 9: Capitalized Costs

At March 31, 2012 and 2011, non-producing oil and natural gas properties include costs of $251,601 and $406,674, respectively, on exploratory wells which were drilling and/or testing. On those wells drilling and/or testing as of March 31, 2012, the Company expects to have evaluation results within the next six months.

NOTE 10: Derivatives

The Company has entered into fixed swap contracts, basis protection swaps and costless collar contracts. These derivative instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. Fixed swap contracts set a fixed price and provide payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. Basis protection swaps guarantee a price differential to NYMEX for natural gas from a specified delivery point (CEGT and PEPL currently). The Company receives a payment from the counterparty if the price differential is greater than the agreed terms of the contract and pays the counterparty if the price differential is less than the agreed terms of the contract. Collar contracts set a fixed floor price and a fixed ceiling price 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 contracts cover only a portion of the Company’s natural gas and oil production and provide only partial price protection against declines in natural gas and oil prices. These derivative instruments may expose the Company to risk of financial loss and limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are unsecured. The derivative instruments have settled or will settle based on the prices below which are adjusted for location differentials and tied to certain pipelines in Oklahoma.

 

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Derivative contracts in place as of March 31, 2012

(prices below reflect the Company’s net price from the listed Oklahoma pipelines)

 

		Production volume		Indexed (1)
Contract period		covered per month		pipeline		Fixed price
Natural gas basis protection swaps
January—December 2012		50,000 Mmbtu		CEGT		NYMEX -$.29
January—December 2012		40,000 Mmbtu		CEGT		NYMEX -$.30
January—December 2012		50,000 Mmbtu		PEPL		NYMEX -$.29
January—December 2012		50,000 Mmbtu		PEPL		NYMEX -$.30
Natural gas costless collars
March—October 2012		50,000 Mmbtu		NYMEX Henry Hub		$2.50 floor/$3.25 ceiling
April—October 2012		120,000 Mmbtu		NYMEX Henry Hub		$2.50 floor/$3.10 ceiling
April—October 2012		60,000 Mmbtu		NYMEX Henry Hub		$2.50 floor/$3.20 ceiling
April—October 2012		50,000 Mmbtu		NYMEX Henry Hub		$2.50 floor/$3.20 ceiling
April—October 2012		50,000 Mmbtu		NYMEX Henry Hub		$2.50 floor/$3.45 ceiling
April—October 2012		50,000 Mmbtu		NYMEX Henry Hub		$2.50 floor/$3.30 ceiling
Oil costless collars
January—December 2012		2,000 Bbls		NYMEX WTI		$90 floor/$105 ceiling
February—December 2012		3,000 Bbls		NYMEX WTI		$90 floor/$110 ceiling

 

(1)	CEGT—Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma

PEPL—Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline

Derivative contracts in place as of September 30, 2011

(prices below reflect the Company’s net price from the listed Oklahoma pipelines)

 

		Production volume		Indexed (1)
Contract period		covered per month		pipeline		Fixed price
Natural gas fixed price swaps
April—October 2011		50,000 Mmbtu		NYMEX Henry Hub		$4.65
April—October 2011		50,000 Mmbtu		NYMEX Henry Hub		$4.65
April—October 2011		50,000 Mmbtu		NYMEX Henry Hub		$4.70
April—October 2011		50,000 Mmbtu		NYMEX Henry Hub		$4.75
May—October 2011		50,000 Mmbtu		NYMEX Henry Hub		$4.50
May—October 2011		50,000 Mmbtu		NYMEX Henry Hub		$4.60
June—October 2011		50,000 Mmbtu		NYMEX Henry Hub		$4.63
Natural gas basis protection swaps
January—December 2011		50,000 Mmbtu		CEGT		NYMEX -$.27
January—December 2011		50,000 Mmbtu		CEGT		NYMEX -$.27
January—December 2011		50,000 Mmbtu		PEPL		NYMEX -$.26
January—December 2011		50,000 Mmbtu		PEPL		NYMEX -$.27
January—December 2011		70,000 Mmbtu		PEPL		NYMEX -$.36
January—December 2012		50,000 Mmbtu		CEGT		NYMEX -$.29
January—December 2012		40,000 Mmbtu		CEGT		NYMEX -$.30
January—December 2012		50,000 Mmbtu		PEPL		NYMEX -$.29
January—December 2012		50,000 Mmbtu		PEPL		NYMEX -$.30
Oil costless collars
April—December 2011		5,000 Bbls		NYMEX WTI		$100 floor/$112 ceiling

 

(1)	CEGT—Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma

PEPL—Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline

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 to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was an asset of $309,658 as of March 31, 2012, and a net asset of $215,940 as of September 30, 2011. Realized and unrealized gains and (losses) for the periods ended March 31, 2012, and March 31, 2011, are scheduled below:

 

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Gains (losses) on		Three months ended								Six months ended
derivative contracts		3/31/2012				3/31/2011				3/31/2012				3/31/2011
Realized		$	(38,820	)		$	(90,650	)		$	275,115			$	1,485,850
Increase (decrease) in fair value			629,732				99,416				93,718				(1,498,523	)
Total		$	590,912			$	8,766			$	368,833			$	(12,673	)

To the extent that a legal right of offset exists, the Company nets the fair value of its derivative contracts with the same counterparty in the accompanying balance sheets. The following table summarizes the Company’s derivative contracts as of March 31, 2012, and September 30, 2011:

 

		Balance Sheet		3/31/2012				9/30/2011
		Location		Fair Value				Fair Value
Asset Derivatives:
Derivatives not designated as Hedging Instruments:
Commodity contracts		Short-term derivative contracts		$	309,658			$	269,329
Commodity contracts		Long-term derivative contracts			—				—
Total Asset Derivatives (a)				$	309,658			$	269,329
Liability Derivatives:
Derivatives not designated as Hedging Instruments:
Commodity contracts		Short-term derivative contracts		$	—			$	—
Commodity contracts		Long-term derivative contracts			—				53,389
Total Liability Derivatives (a)				$	—			$	53,389

 

(a)	See Fair Value Measurements section for further disclosures regarding fair value of financial instruments.

The fair value of derivative assets and derivative liabilities is adjusted for credit risk. The impact of credit risk was immaterial for all periods presented.

NOTE 11: Exploration Costs

In the quarter and six month period ended March 31, 2012, lease expirations and leasehold impairments of ($12,456) and $299,361, respectively, were charged to exploration costs. Leasehold impairments are recorded for individually insignificant non-producing leases which the Company believes will not be transferred to proved properties over the remaining lives of the leases. In the quarter and six month period ended March 31, 2012, the Company also incurred costs of $54,144 and $55,697, respectively, related to exploratory dry holes. In the quarter and six month period ended March 31, 2011, lease expirations and impairments of $77,246 and $150,331, respectively, were charged to exploration costs as well as costs of $213,106 and $427,127, respectively, related to exploratory dry holes.

NOTE 12: Fair Value Measurements

Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable for the asset or liability; or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 inputs are unobservable inputs for the financial asset or liability.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2012.

 

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		Quoted Prices in  Active Markets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total Fair Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps		$	—			$	(225,531	)		$	—			$	(225,531	)
Derivative Contracts - Collars		$	—			$	—			$	535,189			$	535,189

Level 2 – Market Approach—The fair values of the Company’s natural gas swaps are based on a third-party pricing model which utilizes inputs that are either readily available in the public market, such as natural gas curves, or can be corroborated from active markets. These values are based upon, among other things, future prices and time to maturity. These values are then compared to the values given by our counterparties for reasonableness.

Level 3 – The fair values of the Company’s oil and natural gas collar contracts are based on a pricing model which utilizes inputs that are unobservable or not readily available in the public market. These values are based upon, among other things, crude oil and natural gas future prices, volatility and time to maturity. These values are then compared to the values given by our counterparties for reasonableness.

A reconciliation of the Company’s assets classified as Level 3 measurements is presented below. All gains and losses are presented on the Gains (losses) on derivative contracts line item on our Statement of Operations.

 

		Derivatives
Balance of Level 3 as of October 1, 2011		$	293,847
Total gains or (losses) - realized and unrealized:
Included in earnings
Realized			163,815
Unrealized			77,527
Included in other comprehensive income (loss)			—
Purchases, issuances and settlements			—
Transfers in and out of Level 3			—
Balance of Level 3 as of March 31, 2012		$	535,189

The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.

 

		Quarter Ended March 31,
		2012								2011
		Fair Value				Impairment				Fair Value				Impairment
Producing Properties		$	489,841			$	217,262			$	1,041,744			$	828,019	(a)
		Six Months Ended March 31,
		2012								2011
		Fair Value				Impairment				Fair Value				Impairment
Producing Properties		$	908,963			$	580,809			$	1,041,744			$	828,019	(a)

 

(a)

At the end of each quarter, the Company assesses the carrying value of its producing properties for impairment. This assessment utilizes estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil and natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values.

NOTE 13: Fair Values of Financial Instruments

The carrying amounts reported in the balance sheets for cash and cash equivalents, receivables, refundable income taxes, accounts payable and accrued liabilities approximate their fair values due to the short maturity of these instruments. The fair value of Company’s debt approximates its carrying amount as the interest rates on the Company’s revolving line of credit are approximately equivalent to market rates for similar type debt based on the Company’s credit worthiness.

 

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NOTE 14: Acquisitions

On October 25, 2011, the Company closed an acquisition of certain Fayetteville Shale assets located in Van Buren, Conway and Cleburne Counties, Arkansas, in the core of the Fayetteville Shale. The Company acquired an average working interest of 2.3% in 193 producing non-operated natural gas wells and 1,531 acres of leasehold from a private seller. There were approximately 240 future infill drilling locations identified on the leasehold at the time of purchase. The purchase price was $17.4 million and was funded by utilizing cash on hand and $13.3 million from the Company’s bank credit facility. The purchase price was allocated to the producing wells based on fair value determined by estimated reserves. The purchase price allocation is preliminary, pending the finalization of asset valuations and working capital adjustments. Adjustments to the estimated fair values may be recorded during the allocation period, not to exceed one year from the date of acquisition.

Actual and Pro Forma Impact of Acquisitions (Unaudited)

Revenues attributable to this acquisition included in the Company’s statement of operations for the quarter and six months ended March 31, 2012, were $896,996 and $1,936,410, respectively. Net income attributable to the acquisition included in the statement of operations for the quarter and six months ended March 31, 2012, was $180,813 and $445,947, respectively.

The following table presents the unaudited pro forma financial information assuming the Company had acquired this business on October 1, 2010:

 

		For the Six Months Ended
		March 31
		2012				2011
Revenue:
As reported		$	23,841,243			$	20,879,007
Pro forma revenue			409,998				2,229,534
Pro forma		$	24,251,241			$	23,108,541
Net Income:
As reported		$	4,088,076			$	3,199,102
Pro forma income			136,315				504,095
Pro forma		$	4,224,391			$	3,703,197

The unaudited pro forma financial information is for informational purposes only and does not purport to present what our results would actually have been had this transaction actually occurred on the date presented or to project our results of operations or financial position for any future period.

NOTE 15: Recently Adopted Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board issued “Balance Sheet: Disclosures about Offsetting Assets and Liabilities.” The new standard requires entities to disclose information about financial instruments and derivative instruments that are either offset on the balance sheet or are subject to a master netting arrangement, including providing both gross information and net information for recognized assets and liabilities, the net amounts presented on an entity’s balance sheet and a description of the rights of offset associated with these assets and liabilities. The new standard is applicable for all entities that have financial instruments and derivative instruments shown using a net presentation on an entity’s balance sheet or are subject to a master netting arrangement. The new standard is effective for interim and annual reporting periods for fiscal years beginning on or after January 1, 2013 and should be applied retrospectively for all periods presented. The Company plans to adopt this new standard effective January 1, 2013 and will provide any additional disclosures necessary to comply with the new standard.

In May 2011, the FASB issued Accounting Standards Update 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This update does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. This update may require certain additional disclosures related to fair value measurements. This update was adopted in our second quarter ended March 31, 2012. The adoption of this update did not materially impact our financial statement disclosures.

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.

 

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NOTE 16: Subsequent Events

Effective April 13, 2012, the Company leased partial rights to 2,846 of its net mineral acres located in Roger Mills County, Oklahoma, to a large independent exploration and production company for $4,981,000. The Company retained a 3/16 royalty interest in all production from wells drilled on these leased rights. The rights leased were from the surface to 100 feet below the base of the Virgilian (the base of the Virgilian is equivalent to the base of the Tonkawa). The Company retained the rights to the deeper formations including the Hogshooter, Cleveland, Marmaton and Granite Wash. The transaction does not include any existing production or current proved reserves. The Company retains its perpetual mineral ownership.

 

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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 2012 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, natural gas and NGL 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, natural gas and NGL reserves. Investors should also read the other information in this Form 10-Q and the Company’s 2011 Annual Report on Form 10-K where risk factors are presented and further discussed. 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

The Company had positive working capital of $4,373,119 at March 31, 2012, compared to $7,314,096 at September 30, 2011.

Liquidity:

Cash and cash equivalents were $1,119,676 as of March 31, 2012, compared to $3,506,999 at September 30, 2011, a decrease of $2,387,323. Cash flows for the six months ended March 31 are summarized as follows:

Net cash provided (used) by:

 

		2012				2011				Change
Operating activities		$	15,061,760			$	13,581,335			$	1,480,425
Investing activities			(28,938,952	)			(10,862,270	)			(18,076,682	)
Financing activities			11,489,869				(2,428,294	)			13,918,163
Increase (decrease) in cash and cash equivalents		$	(2,387,323	)		$	290,771			$	(2,678,094	)

Operating activities:

Net cash provided by operating activities increased $1,480,425 during the first six months of 2012, the result of the following:

Higher collections of oil and natural gas sales and other receivables for the 2012 period compared to the 2011 period resulted in increased cash provided by operating activities of approximately $1.3 million.

Realized gains on derivative contracts decreased approximately $1.2 million in the 2012 period, as compared to the 2011 period.

In the first six months of fiscal 2012, payments for field related LOE were approximately $474,000 higher than in the first six months of fiscal 2011.

Expenditures for G&A, interest and other expenses during the 2012 period increased approximately $107,000, as compared to the 2011 period. These expenditures were the result of higher personnel, technical consulting, auditing, tax preparation and legal costs.

The Company had lower income tax payments during the 2012 period compared to the 2011 period of approximately $2 million.

Investing activities:

Net cash used in investing activities increased $18,076,682 during the first six months of 2012, the result of the following:

 

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For the six months ended March 31, 2012, increased drilling activity resulted in an increase in capital expenditures of $1,009,066, as compared to the six months ended March 31, 2011.

The Company acquired producing properties, leasehold and mineral acreage in Arkansas and Oklahoma totaling approximately $18.8 million in the 2012 period. These acquisitions are discussed below in Capital Resources.

Lease bonus payments received increased during the 2012 period approximately $1.8 million, as compared to the 2011 period. In December 2011, the Company leased 2,431 net mineral acres in the horizontal Mississippian play in northern Oklahoma and received approximately $1.7 million in lease bonus payments.

Financing activities:

Net cash of $11,489,869 was provided by financing activities in the first six months of 2012, as compared to net cash used in financing activities of $2,428,294 in the first six months of 2011. The change of $13,918,163 of net cash provided is the result of the following:

The Company financed the acquisition of producing properties and leasehold in Arkansas discussed above utilizing its credit facility with Bank of Oklahoma and cash. As of March 31, 2012 and 2011, net borrowings were $13,809,501 and $0, respectively.

Stock repurchases of $1,158,957 and $1,264,965 were made in the 2012 and 2011 periods, respectively.

Capital Resources:

Drilling capital expenditures in 2012 of $12,074,991 exceeded 2011 drilling capital expenditures of $11,065,925, a nine percent increase. During the first half of fiscal 2012, increased drilling activity in the Arkansas Fayetteville Shale area, combined with steady drilling activity in western Oklahoma, has resulted in the approximately $1 million increase in capital expenditures. A significant portion of the Fayetteville Shale drilling is occurring on the acreage we acquired during the 2012 first quarter, and at a faster rate than anticipated. Drilling in western Oklahoma continues to be where we own substantial mineral and leasehold acreage in oil and natural gas liquids-rich areas including the Anadarko (Cana) Woodford Shale, Horizontal Granite Wash, Hogshooter Wash, Cleveland, Tonkawa and Marmaton. Drilling in the Fayetteville Shale and in western Oklahoma is expected to continue at a rapid enough pace throughout the remainder of fiscal 2012 such that drilling capital expenditures for the second half of 2012 should approximate drilling capital expenditures during the first half. Accordingly, we expect 2012 capital expenditures for drilling projects to approximate $24 million and for 2012 acquired assets to approximate $22 million, totaling approximately $46 million. With these capital outlays, the Company’s oil, natural gas and natural gas liquids production should continue to increase through the end of fiscal 2012. To carry out our business strategy, we continue to search for opportunities to acquire additional production or acreage which will yield favorable returns on investment in areas that are complementary to our existing holdings.

In April 2012, the Company completed a transaction in which it leased partial rights on 2,846 of its net mineral acres located in Roger Mills County, Oklahoma, to a large independent exploration and production company for three years and received $4,981,000 as a cash bonus and retained a three-sixteenths non-cost bearing royalty interest in all production from wells drilled on these leased rights. The rights leased were from the surface to 100 feet below the base of the Virgilian (the base of the Virgilian is equivalent to the base of the Tonkawa). We retained the rights to the deeper formations including the Hogshooter, Cleveland, Marmaton and Granite Wash which we believe should yield better and more predictable well results. This transaction does not include any of the Company’s existing production or current proved oil, natural gas or natural gas liquids reserves. The Company retained its perpetual mineral ownership in the acreage. We routinely weigh the value of leasing our mineral rights against participation with a working interest in drilling opportunities, whether it be well-by-well or on a broader scope.

Production of oil, natural gas and NGL increased 20% on an Mcfe basis during 2012, as compared to 2011. The Company first reported NGL production in the first quarter of 2012. Increased drilling activity over the last 12–18 months in several western Oklahoma plays which produce significant NGL has resulted in meaningful NGL production and reserves for the Company, necessitating the inclusion of NGL production beginning with the first quarter of 2012. The inclusion of NGL in the reserve calculation began with the 2011 year-end reserve report. In previous quarters, all NGL sales revenues were included with natural gas sales revenues. Excluding the effect of the inclusion of NGL production during the six months ended March 31, 2012, production volumes increased 14% on an Mcfe basis. This increase was due to added production from the newly acquired wells and from wells that have recently come on line, which has exceeded the natural production decline of pre-existing wells. Looking forward, we expect 2012 production to continue to exceed 2011 production due to these newly acquired wells, wells that have recently come on line and wells that will come on line later in 2012.

 

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Since the Company is not the operator of any of its oil and natural gas properties, it is extremely difficult for us to predict levels of participation in drilling and completing new wells and our associated capital expenditures with certainty.

Natural gas prices have continued to decline and the high levels of natural gas in storage has resulted in announced cutbacks in domestic drilling activity and restricted natural gas production on existing wells by some operators. These factors point toward continued low natural gas price levels through the remainder of fiscal 2012. As of March 31, 2012, we had costless collar contracts covering 5,000 barrels per month of our oil production through December 2012 and 380,000 Mmbtu per month of our natural gas production through October 2012. We also had natural gas basis protection swap contracts as of March 31, 2012, covering 190,000 Mmbtu per month of natural gas production through December 2012. During this highly volatile period for oil and natural gas prices, management continues to evaluate opportunities for product price protection by hedging a portion of the Company’s future oil and natural gas production.

Through the first two quarters of 2012 cash provided by operating activities of $15,061,760 more than funded capital expenditures for drilling and equipping wells of $12,074,991. After payment of our regular $.07 per share quarterly dividends totaling $1,160,675 and other miscellaneous investing activities, cash was reduced during 2012 by $2,387,323 and the Company had net borrowings of $13,809,501 utilizing its credit facility. Looking forward, the Company expects to fund overhead costs, capital additions related to the drilling and equipping of wells, stock repurchases and dividend payments primarily from cash flow and cash on hand. During the first six months of 2012, the Company utilized excess cash and the bank credit facility to finance $18.8 million in asset purchases. As management evaluates opportunities to acquire additional assets, additional borrowings utilizing our bank credit facility could be necessary. Also, during times of oil and natural gas price decreases, or increased expenditures for drilling, it may be necessary for us to utilize the credit facility further in order to fund these expenditures. The Company has availability (approximately $21.2 million at March 31, 2012) under its revolving credit facility and is in compliance with its debt covenants (current ratio, debt to EBITDA, tangible net worth and dividends as a percent of operating cash flow). While the Company believes the availability could be increased (if needed) by placing more of the Company’s properties as security under the revolving credit facility, increases are at the discretion of the bank.

Based on expected capital expenditure levels and anticipated cash flows for 2012, the Company has sufficient liquidity to fund its ongoing operations and, combined with availability under its credit facility, to fund additional acquisitions.

RESULTS OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2012 – COMPARED TO THREE MONTHS ENDED MARCH 31, 2011

Overview:

The Company recorded a second quarter 2012 net income of $675,966, or $.08 per share, compared to a net income of $1,772,253, or $.21 per share, in the 2011 quarter. The decrease in net income was principally due to decreased oil and natural gas revenues, increased DD&A expense, partially offset by increased gains on derivative contracts, decreased impairment expense and a decrease in exploration costs. These items are further discussed below.

Oil and Natural Gas (and associated natural gas liquids) Sales:

Oil and natural gas sales decreased $1,342,037 or 12% for the 2012 quarter. The decrease was due to lower natural gas sales prices of 44%, offset by increased oil volumes of 16%, increased natural gas volumes of 16% and increased oil sales prices of 11%. The following table outlines the Company’s sales volumes and average sales prices for oil, natural gas and NGL for the three month periods of fiscal 2012 and 2011:

 

		Oil Bbls				Average				Mcf				Average				NGL Bbls				Average				Mcfe				Average
		Sold				Price				Sold				Price				Sold				Price				Sold				Price
Three months ended
3/31/2012			30,614			$	97.55				2,303,797			$	2.39				27,834			$	38.92				2,654,485			$	3.60
3/31/2011			26,376			$	88.20				1,993,755			$	4.30				*				*				2,152,011			$	5.07

The oil production increase is due to continued drilling in western Oklahoma oily plays such as the horizontal Granite Wash, Hogshooter Wash, Cleveland, Tonkawa and Marmaton. The natural gas production increase is mainly due to production attributable to the acquisition in the Fayetteville Shale in Arkansas that the Company completed effective October 25, 2011.

 

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Production for the last five quarters was as follows:

 

Quarter ended		Oil Bbls Sold				Mcf Sold				NGL Bbls Sold				Mcfe Sold
3/31/12			30,614				2,303,797				27,834				2,654,485
12/31/11			38,040				2,243,312				14,662				2,559,524
9/30/11			27,418				2,268,606				*				2,433,114
6/30/11			25,382				1,976,868				*				2,129,160
3/31/11			26,376				1,993,755				*				2,152,011

 

*

The Company reported NGL reserves for the first time in its 2011 year-end reserve report. Increased drilling activity over the last 12-18 months in several western Oklahoma plays which produce significant NGL has resulted in meaningful NGL reserves and production for the Company. These reserve and production increases necessitated inclusion of NGL in the 2011 year-end reserve calculation and 2012 production volumes. In quarters prior to 2012, all NGL sales revenues were included with natural gas sales revenues.

Gains (Losses) on Derivative Contracts:

At March 31, 2012, the Company’s fair value of derivative contracts was an asset of $309,658; whereas at March 31, 2011, the Company’s fair value of derivative contracts was an asset of $121,803. The Company had a net gain on derivative contracts of $590,912 in the 2012 quarter as compared to a net gain of $8,766 recorded in the 2011 quarter. The increase in gains is mostly due to new natural gas collars, which were added in the current year.

Production Taxes:

Production taxes decreased $78,576 or 19% in the 2012 quarter as compared to the 2011 quarter. Production taxes as a percentage of oil and natural gas sales decreased from 3.9% in the 2011 quarter to 3.6% in the 2012 quarter. This decrease in rate is a result of increased gas production in Arkansas, where the production tax rate is lower. The low overall production tax rate is due to a large proportion of the Company’s natural gas revenues coming from horizontally drilled wells, which are eligible for reduced Oklahoma and Arkansas production tax rates.

Exploration Costs:

Exploration costs decreased $248,665 in the 2012 quarter as compared to the 2011 quarter. During the 2012 quarter, leasehold impairment and expired leasehold totaled ($12,456) compared to $77,246 during the 2011 quarter, an $89,702 decrease. Charges on two exploratory dry holes and unsuccessful prospect costs totaled $54,144 during the 2012 quarter; whereas, in the 2011 quarter one exploratory dry hole was drilled with charges of $202,731.

Depreciation, Depletion and Amortization (DD&A):

DD&A increased $1,309,576 or 36% in the 2012 quarter. DD&A in the 2012 quarter was $1.86 per Mcfe as compared to $1.69 per Mcfe in the 2011 quarter. DD&A increased approximately $848,000 due to oil and natural gas production increasing 23% in the 2012 quarter. The remaining change was caused by a $.17 increase in the DD&A rate per Mcfe accounting for an increase of approximately $462,000. This rate increase was a result of higher finding cost experienced in oil and liquids rich projects where the Company is focusing a significant part of its drilling expenditures.

Provision for Impairment:

The provision for impairment decreased $610,757 in the 2012 quarter compared to the 2011 quarter. During the 2011 quarter, impairment of $828,019 was recorded on four small fields in Oklahoma and Texas. During the 2012 quarter, impairment of $217,262 was recorded on four small fields in Oklahoma. These fields have few wells and are more susceptible to impairment when a well in the field experiences downward reserve revisions due to pricing or performance.

General and Administrative Costs (G&A):

G&A costs increased $140,216 or 10% in the 2012 period. The increase is primarily related to increases in personnel expenses of $175,643, partially offset by a decrease in computer consulting and reservoir engineering fees of $43,368. The increase in personnel expense is due to compensation and employee insurance increases.

Income Taxes:

Provision for income taxes was $31,000 higher in the 2012 quarter than the 2011 quarter. While income before provision for income taxes decreased from $2,271,253 in the 2011 quarter to $1,205,966 in the 2012 quarter, the effective tax rate increased to 44% in the 2012 quarter from 22% in the 2011 quarter. This increase is the result of an increase in the estimated annual effective tax rate during the second quarter due to higher expected fiscal 2012 income before provision for

 

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income taxes (mostly related to higher expected lease bonus income) projected as of March 31, 2012, as compared to projections as of December 31, 2011. The net effect of the decreased income before provision for income taxes and the increased effective tax rate resulted in the slight increase in provision for income taxes.

SIX MONTHS ENDED MARCH 31, 2012 – COMPARED TO SIX MONTHS ENDED MARCH 31, 2011

Overview:

The Company recorded a six month period 2012 net income of $4,088,076, or $.49 per share, as compared to a net income of $3,199,102, or $.38 per share, in the 2011 period. Major contributing factors were increased lease bonuses, increased gains on derivative contracts and higher oil and natural gas sales, partially offset by increased DD&A and increased G&A expense. These items are further discussed below.

Oil and Natural Gas (and associated natural gas liquids) Sales:

Oil and natural gas sales increased $670,666 as a result of increased oil volumes of 34%, increased natural gas volumes of 12% and increasing oil sales prices of 11%, partially offset by lower natural gas sales prices of 28%. The table below outlines the Company’s sales volumes and average sales prices for oil, natural gas and NGL for the six month periods of fiscal 2012 and 2011:

 

		Oil Bbls				Average				Mcf				Average				NGL Bbls				Average				Mcfe				Average
		Sold				Price				Sold				Price				Sold				Price				Sold				Price
Six months ended
3/31/2012			68,654			$	93.03				4,547,109			$	2.91				42,496			$	39.31				5,214,009			$	4.09
3/31/2011			51,341			$	84.10				4,052,183			$	4.03				*				*				4,360,229			$	4.73

 

*

The Company reported NGL reserves for the first time in its 2011 year-end reserve report. Increased drilling activity over the last 12-18 months in several western Oklahoma plays which produce significant NGL has resulted in meaningful NGL reserves and production for the Company. These reserve and production increases necessitated inclusion of NGL in the 2011 year-end reserve calculation and 2012 production volumes. In quarters prior to 2012, all NGL sales revenues were included with natural gas sales revenues.

The oil production increase is due to continued drilling in western Oklahoma oily plays such as the horizontal Granite Wash, Hogshooter Wash, Cleveland, Tonkawa and Marmaton. The natural gas production increase is mainly due to production attributable to the acquisition in the Fayetteville Shale in Arkansas that the Company completed effective October 25, 2011. The Company owns a substantial acreage position in western Oklahoma and drilling in these plays is expected to continue at a rapid pace throughout fiscal 2012 giving the Company opportunity to continue to increase its oil and NGL production. Further, drilling for natural gas in the Fayetteville Shale play, both on legacy acreage and the recently acquired acreage, remains brisk. As a result, increases in gas production are expected throughout fiscal 2012.

Lease Bonuses and Rentals:

Lease bonuses and rentals increased $1,780,063 in the 2012 period. The increase was mainly due to the Company leasing 2,431 net acres in the horizontal Mississippian play, in northern Oklahoma, for $1.7 million.

Gains (Losses) on Derivative Contracts:

The fair value of derivative contracts was $309,658 as of March 31, 2012, and $121,803 as of March 31, 2011. The Company had a net gain of $368,833 in the six months ended March 31, 2012, compared to a loss of $12,673 for the six months ended March 31, 2011. The Company received net cash payments (realized gains) of $275,115 and $1,485,850 for the 2012 and 2011 periods, respectively.

Lease Operating Expenses (LOE):

LOE increased $36,950 or 1% in the 2012 period. LOE per Mcfe decreased in the fiscal 2012 period to $.83 compared to $.98 in the 2011 period. LOE related to field operating costs increased approximately $213,000 in the 2012 period compared to the 2011 period, an 11% increase. This increase is principally a result of production increasing 20%. In the 2012 period, field operating costs were $.42 per Mcfe compared to $.45 per Mcfe in the 2011 quarter. The decrease in rate is primarily due to lower workover costs in the 2012 period.

The increase in LOE related to field operating costs was partially offset by a decrease in value based fees (primarily gathering, transportation and marketing costs) of approximately $176,000 in the 2012 period compared to the 2011 period. On a per Mcfe basis, these fees were down $.12 due to lower natural gas prices, the addition of significant oil production and new natural gas wells producing in areas with lower value based fees. Value based fees are charged as a percent of natural gas sales.

 

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Exploration Costs:

Exploration costs decreased $222,399 in the 2012 period compared to the 2011 period. Charges on two exploratory dry holes and unsuccessful prospect costs totaled $55,697 during the 2012 period; whereas, in the 2011 period, the Company had two exploratory dry holes totaling $427,127. The decrease in dry hole costs was partially offset by an increase in leasehold impairment and expired leasehold. During the 2012 period, leasehold impairment and expired leasehold totaled $299,361, compared to $150,331 during the 2011 period, a $149,030 increase. This increase was principally on one leasehold prospect in Oklahoma.

Depreciation, Depletion and Amortization (DD&A):

DD&A increased $2,017,178 or 29% in the 2012 period. DD&A was $1.74 per Mcfe in the 2012 period compared to $1.62 per Mcfe in the 2011 period. DD&A increased $1,383,638 due to oil and natural gas production increasing 20% in the 2012 period compared to the 2011 period. The remaining increase of $633,540 was caused by a $.12 increase in the DD&A rate. This rate increase is due to higher finding cost experienced in oil and liquids rich areas where the Company is focusing a significant part of its drilling capital expenditures.

Provision for Impairment:

The provision for impairment decreased $247,210 in the 2012 period compared to the 2011 period. During the 2012 period, impairment of $580,809 was recorded on eight small fields in Oklahoma. During the 2011 period, impairment of $828,019 was recorded on four small fields in Oklahoma and Texas. These fields have few wells and are more susceptible to impairment when a well in the field experiences downward reserve revisions due to pricing or performance.

General and Administrative Costs (G&A):

G&A costs increased $197,742 or 6% in the 2012 period. The increase is primarily related to increases in personnel expenses of $246,305, partially offset by decreases in company insurance and Board of Directors expenses of $49,605.

Income Taxes:

The fiscal 2012 period provision for income taxes of $1,379,000 was a result of a pre-tax income of $5,467,076 as compared to a provision for income taxes of $1,075,000 in the fiscal 2011 period resulting from a pre-tax income of $4,274,102. The effective tax rate was 25% for both the 2012 and 2011 periods. Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for both the 2012 and the 2011 periods.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Critical accounting policies are those the Company believes are most important to portraying its financial conditions and results of operations and also require the greatest amount of subjective or complex judgments by management. Judgments and uncertainties regarding the application of these policies may result in materially different amounts being reported under various conditions or using different assumptions. There have been no material changes to the critical accounting policies previously disclosed in the Company’s Form 10-K for the fiscal year ended September 30, 2011.

ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

Oil and natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of natural gas and oil price trends, and there remains a rather wide divergence in the opinions held by some in the industry. Being primarily a natural gas producer, the Company is more significantly impacted by changes in natural gas prices than by changes in oil or natural gas liquids prices. Longer term natural gas prices will be determined by the supply of and demand for natural gas as well as the prices of competing fuels, such as crude oil and coal. The market price of natural gas, oil and natural gas liquids in 2012 will impact the amount of cash generated from operating activities, which will in turn impact the level of the Company’s capital expenditures and production. Excluding the impact of the Company’s 2012 derivative contracts, based on the Company’s estimated natural gas volumes for 2012, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $1,005,000 for operating revenue. Based on the Company’s estimated oil volumes for 2012, the price sensitivity in 2012 for each $1.00 per barrel change in wellhead oil price is approximately $112,000 for operating revenue.

 

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Commodity Price Risk

The Company periodically utilizes derivative contracts to reduce its exposure to unfavorable changes in natural gas and oil prices. The Company does not enter into these derivatives for speculative or trading purposes. As of March 31, 2012, the Company has basis protection swaps and oil and natural gas collars in place. All of our outstanding derivative contracts are with one counterparty and are unsecured. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas and oil prices. These derivative contracts may expose the Company to risk of financial loss and limit the benefit of future increases in prices. For the Company’s basis protection swaps, a change of $.10 in the basis differential from NYMEX and the indexed pipelines would result in a change to pre-tax operating income of approximately $169,000. For the Company’s natural gas collars, a change of $.10 in the forward strip prices would result in a change to pre-tax operating income of approximately $200,000. For the Company’s oil collars, a change of $1.00 in the forward strip prices would result in a change to pre-tax operating income of approximately $29,000.

Financial Market Risk

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to the Company’s credit facilities. The revolving loan bears interest at the national prime rate plus from .50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%. At March 31, 2012, the Company had $13,809,501 outstanding under these facilities. At this point, the Company does not believe that its liquidity has been materially affected by the debt market uncertainties noted in the last few years and the Company does not believe that its liquidity will be impacted in the near future.

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 President/Chief Executive Officer and Vice 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 Executive 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 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 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

During the three months ended March 31, 2012, the Company repurchased shares of the Company’s common stock as summarized in the table below.

 

Period		Total Number of Shares Purchased				Average Price Paid per Share				Total Number of Shares Purchased as Part of Publicly Announced Program				Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program
2/1—2/29/12			18,318			$	29.82				18,318			$	300,000
3/1—3/31/12			20,453			$	29.95				20,453			$	1,200,000
Total			38,771			$	29.89				38,771

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan on March 11, 2010, the Board of Directors approved repurchase of up to $1.5 million of the Company’s common stock, from time to time, equal to the aggregate number of shares of common stock awarded pursuant to the Company’s 2010 Restricted Stock Plan, contributed by

 

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the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. Pursuant to previously adopted board resolutions, the purchase of an additional $1.5 million of the Company’s common stock became authorized and approved effective March 14, 2012. The shares are held in treasury and are accounted for using the cost method.

ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

 

(a)

The annual meeting of shareholders was held on March 8, 2012.

 

(b)

Two 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
Darryl G. Smette			4,507,675				223,390
H. Grant Swartzwelder			4,592,697				138,368

 

(c)

A proposal was also voted upon to ratify the appointment of Ernst & Young, LLP as our independent registered public accounting firm for the fiscal year ending September 30, 2012.

 

SHARES

FOR

AGAINST

ABSTAINING

Proposal

6,083,083

27,473

45,168

ITEM 6 EXHIBITS AND REPORT ON FORM 8-K

 

		(a) EXHIBITS –		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
				Exhibit 101.INS – XBRL Instance Document
				Exhibit 101.SCH – XBRL Taxonomy Extension Schema Document
				Exhibit 101.CAL – XBRL Taxonomy Extension Calculation Linkbase Document
				Exhibit 101.LAB – XBRL Taxonomy Extension Labels Linkbase Document
				Exhibit 101.PRE – XBRL Taxonomy Extension Presentation Linkbase Document
				Exhibit 101.DEF – XBRL Taxonomy Extension Definition Linkbase Document
(b)		Form 8-K – Dated (3/12/12), item 5.02 – Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers
		Form 8-K – Dated (3/12/12), item 5.07 – Submission of Matters to a Vote of Security Holders

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, 2012		/s/ Michael C. Coffman
Date		Michael C. Coffman, President and
		Chief Executive Officer
May 7, 2012		/s/ Lonnie J. Lowry
Date		Lonnie J. Lowry, Vice President
		and Chief Financial Officer
May 7, 2012		/s/ Robb P. Winfield
Date		Robb P. Winfield, Controller
		and Chief Accounting Officer

 

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