10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

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

For the period ended  June 30, 2018

☐ 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.     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).     Yes  ☑    No  ☐

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

Large accelerated filer   ☐   Accelerated filer   ☑   Non-accelerated filer   ☐   Smaller reporting company   ☐  

Emerging growth company     ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.     ☐

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

Outstanding shares of Class A Common stock (voting) at August 6, 2018: 16,778,509

INDEX

Part I	Financial Information		Page
	Item 1	Condensed Financial Statements	1
		Condensed Balance Sheets – June 30, 2018, and September 30, 2017	1
		Condensed Statements of Operations – Three and nine months ended June 30, 2018 and 2017	2
		Statements of Stockholders’ Equity – Nine months ended June 30, 2018 and 2017	3
		Condensed Statements of Cash Flows – Nine months ended June 30, 2018 and 2017	4
		Notes to Condensed Financial Statements	5
	Item 2	Management's discussion and analysis of financial condition and results of operations	12
	Item 3	Quantitative and qualitative disclosures about market risk	18
	Item 4	Controls and procedures	19
Part II	Other Information
	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	19
	Item 6	Exhibits and reports on Form 8-K	19
	Signatures		20

The following defined terms are used in this report:

“Bbl” barrel.

“Board” board of directors.

“BTU” British Thermal Units.

“Company” Panhandle Oil and Gas Inc.

“completion” the process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.

“DD&A” depreciation, depletion and amortization.

“dry hole” exploratory or development well that does not produce crude oil and/or natural gas in economic quantities.

“EBITDA” earnings before interest, taxes, depreciation and amortization (including impairment). This is a Non-GAAP measure.

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

“exploratory well” a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir.

“FASB” the Financial Accounting Standards Board.

“field” an area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“G&A” general and administrative costs.

“gross acres” the total acres in which an interest is owned.

“held by production” or “HBP” an oil and gas lease continued into effect into its secondary term for so long as a producing oil and/or gas well is located on any portion of the leased premises or lands pooled therewith.

“horizontal drilling” a drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.

“IDC” intangible drilling costs.

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

“LOE” lease operating expense.

“Mcf” thousand cubic feet.

“Mcfe” 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.

“Mmbtu” million BTU.

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

“net acres” the sum of the fractional interests owned in gross acres.

“NGL” natural gas liquids.

“NYMEX” New York Mercantile Exchange.

“Panhandle” Panhandle Oil and Gas Inc.

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

“proved reserves” the quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.

“royalty interest” well interests in which the Company does not pay a share of the costs to drill, complete and operate a well, but receives a smaller proportionate share (as compared to a working interest) of production.

“SEC” the United States Securities and Exchange Commission.

“undeveloped acreage” acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.

“working interest” 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.

“WTI” West Texas Intermediate.

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 2018 mean the fiscal year ended September 30, 2018.

Fiscal quarter references

All references to quarters in this report, unless otherwise noted, refer to the Company’s fiscal quarter based on a fiscal year end of September 30. For example, references to first quarter mean the quarter of October 1 through December 31.

References to oil and natural gas properties

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

PART 1. FINANCIAL INFORMATION

PANHANDLE OIL AND GAS INC.

CONDENSED BALANCE SHEETS

	June 30, 2018			September 30, 2017
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	477,013		$	557,791
Oil, NGL and natural gas sales receivables (net of allowance for uncollectable accounts)		6,489,489			7,585,485
Refundable income taxes		209,970			489,945
Assets held for sale		-			557,750
Derivative contracts, net		-			544,924
Other		176,356			253,480
Total current assets		7,352,828			9,989,375
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties		418,338,755			434,571,516
Non-producing oil and natural gas properties		8,170,286			7,428,927
Other		1,515,076			1,067,894
		428,024,117			443,068,337
Less accumulated depreciation, depletion and amortization		(239,052,685	)		(246,483,979	)
Net properties and equipment		188,971,432			196,584,358
Investments		212,068			170,486
Total assets	$	196,536,328		$	206,744,219
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	1,163,424		$	1,847,230
Derivative contracts, net		3,014,511			-
Accrued liabilities and other		1,554,645			1,690,789
Total current liabilities		5,732,580			3,538,019
Long-term debt		40,400,000			52,222,000
Deferred income taxes, net		18,104,007			31,051,007
Asset retirement obligations		2,776,058			3,196,889
Derivative contracts, net		288,969			28,765
Stockholders' equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized,    16,896,455 issued at June 30, 2018, and 16,863,004 issued at September 30, 2017		281,495			280,938
Capital in excess of par value		2,690,834			2,726,444
Deferred directors' compensation		2,882,263			3,459,909
Retained earnings		125,386,738			113,330,216
		131,241,330			119,797,507
Less treasury stock, at cost; 117,946 shares at June 30, 2018, and 184,988 shares    at September 30, 2017		(2,006,616	)		(3,089,968	)
Total stockholders' equity		129,234,714			116,707,539
Total liabilities and stockholders' equity	$	196,536,328		$	206,744,219

(See accompanying notes)

(1)

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF OPERATIONS

	Three Months Ended June 30,					Nine Months Ended June 30,
	2018			2017		2018			2017
Revenues:	(unaudited)					(unaudited)
Oil, NGL and natural gas sales	$	11,202,680		$	9,997,898	$	36,356,135		$	27,788,018
Lease bonuses and rentals		484,298			819,591		1,080,455			3,991,752
Gains (losses) on derivative contracts		(2,129,041	)		1,619,697		(3,966,869	)		1,658,347
		9,557,937			12,437,186		33,469,721			33,438,117
Costs and expenses:
Lease operating expenses		3,233,172			3,391,079		10,077,449			9,545,990
Production taxes		485,157			390,387		1,471,970			1,129,785
Depreciation, depletion and amortization		4,619,509			4,714,350		14,136,411			13,654,268
Provision for impairment		-			-		-			10,788
Loss (gain) on asset sales and other		190,045			11,447		110,859			98,445
Interest expense		420,896			306,161		1,288,426			884,928
General and administrative		1,593,251			1,796,004		5,247,584			5,358,114
		10,542,030			10,609,428		32,332,699			30,682,318
Income (loss) before provision (benefit) for income taxes		(984,093	)		1,827,758		1,137,022			2,755,799
Provision (benefit) for income taxes		(209,000	)		567,000		(12,943,000	)		263,000
Net income (loss)	$	(775,093	)	$	1,260,758	$	14,080,022		$	2,492,799
Basic and diluted earnings (loss) per common share (Note 3)	$	(0.05	)	$	0.07	$	0.83		$	0.15
Basic and diluted weighted average shares outstanding:
Common shares		16,775,981			16,668,814		16,742,044			16,639,090
Unissued, directors' deferred compensation shares		206,202			254,891		205,867			277,294
		16,982,183			16,923,705		16,947,911			16,916,384
Dividends declared per share of common stock and paid in period	$	0.04		$	0.04	$	0.12		$	0.12

(See accompanying notes)

(2)

PANHANDLE OIL AND GAS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

Nine Months Ended June 30, 2018

	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, 2017		16,863,004	$	280,938	$	2,726,444		$	3,459,909		$	113,330,216			(184,988	)	$	(3,089,968	)	$	116,707,539
Net income (loss)		-		-		-			-			14,080,022			-			-			14,080,022
Purchase of treasury stock		-		-		-			-			-			(13,404	)		(272,100	)		(272,100	)
Issuance of treasury shares to ESOP		-		-		2,009			-			-			283			4,726			6,735
Restricted stock awards		-		-		501,626			-						-			-			501,626
Dividends ($.12 per share)		-		-		-			-			(2,023,500	)		-			-			(2,023,500	)
Distribution of restricted stock    to officers and directors		852		14		(808,357	)		-			-			48,325			809,162			819
Distribution of deferred    directors' compensation		32,599		543		269,112			(811,219	)		-			31,838			541,564			-
Increase in deferred directors'    compensation charged to    expense		-		-		-			233,573			-			-			-			233,573
Balances at June 30, 2018		16,896,455	$	281,495	$	2,690,834		$	2,882,263		$	125,386,738			(117,946	)	$	(2,006,616	)	$	129,234,714
(unaudited)

Nine Months Ended June 30, 2017

	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, 2016		16,863,004	$	280,938	$	3,191,056		$	3,403,213		$	112,482,284			(262,708	)	$	(4,165,672	)	$	115,191,819
Net income (loss)		-		-		-			-			2,492,799			-			-			2,492,799
Purchase of treasury stock		-		-		-			-			-			(17,119	)		(407,677	)		(407,677	)
Issuance of treasury shares to ESOP		-		-		(2	)		-			-			(1	)		(16	)		(18	)
Restricted stock awards		-		-		454,854			-			-			-			-			454,854
Dividends ($.12 per share)		-		-		-			-			(2,012,329	)		-			-			(2,012,329	)
Distribution of restricted stock    to officers and directors		-		-		(968,617	)		-			-			60,624			969,239			622
Distribution of deferred    directors' compensation		-		-		(145,469	)		(301,963	)		-			27,216			447,431			(1	)
Increase in deferred directors'    compensation charged to    expense		-		-		-			266,182			-			-			-			266,182
Balances at June 30, 2017		16,863,004	$	280,938	$	2,531,822		$	3,367,432		$	112,962,754			(191,988	)	$	(3,156,695	)	$	115,986,251
(unaudited)

(See accompanying notes)

(3)

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF CASH FLOWS

	Nine months ended June 30,
	2018			2017
Operating Activities	(unaudited)
Net income (loss)	$	14,080,022		$	2,492,799
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		14,136,411			13,654,268
Impairment		-			10,788
Provision for deferred income taxes		(12,947,000	)		149,000
Gain from leasing fee mineral acreage		(1,079,803	)		(3,999,632	)
Proceeds from leasing fee mineral acreage		1,102,818			4,026,283
Net (gain) loss on sales of assets		660,597			87,161
Directors' deferred compensation expense		233,573			266,182
Fair value of derivative contracts		3,819,639			(1,879,668	)
Restricted stock awards		501,626			454,854
Other		5,113			2,897
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables		1,095,996			(564,767	)
Other current assets		77,124			196,362
Accounts payable		(125,261	)		(127,375	)
Income taxes receivable		279,975			(488,112	)
Other non-current assets		(52,644	)		-
Accrued liabilities		(130,284	)		40,197
Total adjustments		7,577,880			11,828,438
Net cash provided by operating activities		21,657,902			14,321,237
Investing Activities
Capital expenditures		(7,743,097	)		(18,011,721	)
Acquisition of minerals and overrides		(966,279	)		-
Investments in partnerships		3,379			(18,531	)
Proceeds from sales of assets		1,085,137			718,700
Net cash provided (used) by investing activities		(7,620,860	)		(17,311,552	)
Financing Activities
Borrowings under debt agreement		13,529,879			16,702,602
Payments of loan principal		(25,352,099	)		(11,202,602	)
Purchases of treasury stock		(272,100	)		(407,677	)
Payments of dividends		(2,023,500	)		(2,012,329	)
Net cash provided (used) by financing activities		(14,117,820	)		3,079,994
Increase (decrease) in cash and cash equivalents		(80,778	)		89,679
Cash and cash equivalents at beginning of period		557,791			471,213
Cash and cash equivalents at end of period	$	477,013		$	560,892
Supplemental Schedule of Noncash Investing and Financing Activities:
Additions to asset retirement obligations	$	15,452		$	60,276
Gross additions to properties and equipment	$	8,150,830		$	19,579,304
Net (increase) decrease in accounts payable for properties and equipment additions		558,546			(1,567,583	)
Capital expenditures and acquisitions	$	8,709,376		$	18,011,721

(See accompanying notes)

(4)

PANHANDLE OIL AND GAS INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: Basis of Presentation and Accounting Principles

Basis of Presentation

The accompanying unaudited condensed financial statements of Panhandle Oil and Gas Inc. have been prepared in accordance with the instructions to Form 10-Q as prescribed by the 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 2017 Annual Report on Form 10-K.

Adoption of New Accounting Pronouncements

In January 2017, the FASB issued ASU 2017-01, which changed the definition of a business. The new guidance requires an entity to first evaluate whether substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets. If that threshold is met, the set of assets and activities is not a business. If it’s not met, the entity evaluates whether the set meets the definition of a business. The new definition requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue recognition guidance. The new guidance is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. The ASU will be applied prospectively to any transactions occurring within the period of adoption. Early adoption is permitted, including for interim or annual periods for which the financial statements have not been issued or made available for issuance. The Company early adopted ASU 2017-01 during the quarter ended June 30, 2018.

New Accounting Pronouncements yet to be Adopted

In February 2016, the FASB issued its new lease accounting guidance in ASU 2016-02, Leases (Topic 842). Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date: 1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and 2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new lease guidance simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. Lessees will no longer be provided with a source of off-balance sheet financing. The guidance is effective for us beginning October 1, 2019, including interim periods within the fiscal year. Early application is permitted for all public business entities upon issuance. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. We are assessing the potential impact that this standard will have on our financial statements.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The new guidance is intended to improve the recognition and measurement of financial instruments. The new guidance is effective for us beginning October 1, 2018, including interim periods within the fiscal year. This update is not expected to have a material impact on our financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which will supersede nearly all existing revenue recognition guidance under GAAP. The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. We are evaluating our existing revenue recognition policies to determine whether any contracts in the scope of the guidance will be affected by the new requirements.

(5)

Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis.

The standard is effective for us beginning October 1, 2018. The standard allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements and utilizes a cumulative effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. Panhandle intends to use the modified retrospective method upon adoption.

The Company is nearing completion of its evaluation of the impact of the new standard and related interpretive guidance on its financial statements, accounting policies, internal controls, and disclosures. Based on assessments performed to date, the standard is not expected to have a material effect on the timing or measurement of the Company's revenue recognition or its financial position, results of operations, net income, or cash flows, but is expected to have an impact on the Company's revenue-related disclosures and internal controls over financial reporting.

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.

NOTE 2: Income Taxes

The Tax Cuts and Jobs Act was enacted on December 22, 2017. The Act reduces the US federal corporate tax rate from 35% to 21%, requires companies to pay a one-time transition tax on earnings of certain foreign subsidiaries that were previously tax deferred and creates new taxes on certain foreign sourced earnings. As of June 30, 2018, we have not completed our accounting for the tax effects of enactment of the Act; however, in certain cases, as described below, we have made a reasonable estimate of the effects on our existing deferred tax balances. Based on these estimates, we recognized a provisional amount, which is included as a component of income tax expense (benefit) from continuing operations. In all cases, we will continue to make and refine our calculations as additional analysis is completed.

We remeasured certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. However, we are still analyzing certain aspects of the Act and refining our calculations, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. The provisional amount recorded related to the remeasurement of our deferred tax balance was $12,777,000 income tax benefit.

The Company has a year end of September 30. Because this differs from a normal calendar year end, we have calculated the current year’s federal tax provision using a blended rate of 24.53% to adjust for one quarter of our fiscal year being under the old rate of 35% and the remaining three quarters being under the new rate of 21%. The impact of using a blended rate versus the old rate in the current quarter resulted in a reduced federal tax benefit of $103,035.

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. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that it exceeds cost depletion which is calculated on a unit-of-production basis. Excess tax benefits and deficiencies of stock based compensation will be recognized as income tax expense (benefit) in the statement of operations prospectively versus additional paid in capital in the equity section of the balance sheet as was previously required.

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, 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 detailed well-by-well calculations at fiscal year-end. Federal and Oklahoma excess percentage depletion, when a provision for income taxes is expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock based compensation are not directly related to the amount of pre-tax income (loss) 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 nine months ended June 30, 2018, was an 1138% benefit as compared to a 10% provision for the nine months ended June 30, 2017. The effective tax rate for the quarter ended June 30, 2018, was a 21% benefit as compared to a 31% provision for the quarter ended June 30, 2017.

(6)

NOTE 3: Basic and Diluted Earnings (Loss) per Share

Basic and diluted earnings (loss) per share is calculated using net income (loss) divided by the weighted average number of voting common shares outstanding, including unissued, vested directors’ deferred compensation shares during the period. 

NOTE 4: Long-term Debt

The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a current borrowing base of $80,000,000 and a maturity date of November 30, 2022. The credit facility is subject to a semi-annual borrowing base determination, wherein BOK applies their commodity pricing forecast to the Company’s reserve forecast and determines a borrowing base. The facility is secured by certain of the Company’s properties (wellbore only) with a net book value of $138,566,462 at June 30, 2018. The interest rate is based on BOK prime plus from 0.375% to 1.250%, or 30 day LIBOR plus from 1.875% to 2.750%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from BOK prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as the ratio of loan balance to the borrowing base increases. At June 30, 2018, the effective interest rate was 4.20%.

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.

Determinations of the borrowing base are made semi-annually (usually June and December) or whenever the banks, in their discretion, believe that there has been a material change in the value of the oil and natural gas properties. On July 2, 2018, the borrowing base was redetermined by the banks and left unchanged at $80,000,000. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of indebtedness, liens, payment of dividends and acquisitions of stock. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined by the bank agreement – current assets includes availability under outstanding credit facility) of no less than 1.0 to 1.0 and a funded debt to EBITDA (trailing twelve months as defined by the bank agreement – traditional EBITDA with the unrealized gain or loss on derivative contracts also removed from earnings) of no more than 4.0 to 1.0. At June 30, 2018, the Company was in compliance with the covenants of the loan agreement and has $39,600,000 of availability under its outstanding credit facility.

NOTE 5: Deferred Compensation Plan for Non-Employee Directors

Annually, non-employee directors may elect to be included in the Deferred Compensation Plan for Non-Employee Directors. The Deferred Compensation Plan for Non-Employee Directors provides that each outside director may individually elect to be credited with future unissued shares of Company common stock rather than cash for all or a portion of the annual retainers, Board meeting fees and committee meeting fees. These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares (i) on the dates of the Board and committee meetings, and (ii) on the payment dates of the annual retainers. Only upon a director’s retirement, termination, death, or a change-in-control of the Company will the shares recorded for such director be issued under the Deferred Compensation Plan for Non-Employee Directors. Directors may elect to receive shares, when issued, over annual time periods up to ten years. The promise to issue such shares in the future is an unsecured obligation of the Company. During 2018, deferred directors’ compensation on the Balance Sheets was reduced $811,219 for shares issued to retired directors. Of the shares issued, 31,838 shares were issued out of treasury and 32,599 shares were newly issued.

NOTE 6: Restricted Stock Plan

In March 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 200,000 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. In March 2014, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan from 200,000 shares to 500,000 shares and to allow the grant of shares of restricted stock to our directors. The 2010 Stock Plan, as amended, 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 attract, retain and motivate directors and officers of the Company and to align their interests with those of the Company’s shareholders.

Effective in May 2014, the board of directors adopted resolutions to allow management, at their discretion, to purchase the Company’s common stock as treasury shares up to an amount equal to the aggregate number of shares of common stock awarded pursuant to the Company’s Amended 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.

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Effective in May 2018, the board of directors approved an amendment to the Company’s existing stock repurchase program. As amended, the Repurchase Program will continue to allow management to repurchase up to $1.5 million of the Company’s common stock at their discretion. The repurchase of an additional $1.5 million of the Company’s common stock continues to be authorized and approved effective when the previous amount is utilized, and the Board added language to clarify that this is intended to be an evergreen provision. The number of shares allowed to be purchased by the Company under the Repurchase Program is no longer capped at an amount equal to the aggregate number of shares of common stock (i) awarded pursuant to the Company’s Amended 2010 Restricted Stock Plan, (ii) contributed by the Company to its ESOP, and (iii) credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.

On December 12, 2017, the Company awarded 9,700 non-performance based shares and 29,099 performance based shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of a three-year period and contains non-forfeitable rights to receive dividends and voting rights during the vesting period. The non-performance and performance based shares had a fair value on their award date of $203,700 and $330,043, respectively. The fair value for the non-performance and the performance based awards will be recognized as compensation expense ratably over the vesting period. The fair value of the performance based shares on their award date is calculated by simulating the Company’s stock prices as compared to the Dow Jones Select Oil Exploration and Production Index (DJSOEP) prices utilizing a Monte Carlo model covering the performance period (December 12, 2017, through December 12, 2020).

On December 31, 2017, the Company awarded 10,218 non-performance based shares of the Company’s common stock as restricted stock to its non-employee directors. The restricted stock vests quarterly over one year starting on March 31, 2018. The restricted stock contains non-forfeitable rights to receive dividends and voting rights during the vesting period. These non-performance based shares had a fair value on their award date of $209,982.

The following table summarizes the Company’s pre-tax compensation expense for the three and nine months ended June 30, 2018 and 2017, related to the Company’s performance based and non-performance based restricted stock.

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2018		2017		2018		2017
Performance based, restricted stock	$	59,869	$	51,302	$	216,403	$	181,820
Non-performance based, restricted stock		93,919		85,919		285,223		273,034
Total compensation expense	$	153,788	$	137,221	$	501,626	$	454,854

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 June 30, 2018
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	381,258		1.97
Non-performance based, restricted stock		368,585		1.56
Total	$	749,843

NOTE 7: Properties and Equipment

Divestitures

During the first quarter of 2018, the Company sold 79 non-core marginal wells for $557,750 and recorded a loss on the sales of $272,236. The total net book value that was removed from the Balance Sheets due to these sales was approximately $0.8 million. All of the wells included in the Assets held for sale line item on the Balance Sheets at September 30, 2017, were sold during the first quarter of 2018.

During the second and third quarters of 2018, the Company sold 245 non-core marginal wells for $527,387 and recorded a loss on the sales of $388,361. The total net book value that was removed from the Balance Sheets due to these sales was approximately $0.9 million.

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Acquisitions

During the third quarter of 2018, the Company acquired 54 net mineral acres (which include producing oil and gas properties) in the SCOOP play in Grady and Stephens Counties, Oklahoma, with undeveloped locations identified in both the Woodford and Springer Shales for $966,279. This purchase was accounted for as an asset acquisition with $168,006 of the total purchase price allocated to producing oil and natural gas properties and $798,273 allocated to non-producing oil and natural gas properties.

On July 16, 2018, the Company entered into a Purchase and Sale Agreement to acquire certain mineral acreage and producing oil and gas properties, primarily located in the Bakken Shale, from a private seller for total consideration of $9,000,000 cash (pending any closing adjustments). The transaction is expected to close by late August and will have an effective date of June 1, 2018.

Oil, NGL and Natural Gas Reserves

Management considers the estimation of the Company’s crude oil, NGL and natural gas reserves to be the most significant of its judgments and estimates. Changes in crude oil, NGL and natural gas reserve estimates affect the Company’s calculation of DD&A, provision for retirement of assets 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, NGL 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, geologic and geophysical information. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing appropriate prices for the current period. The estimated oil, NGL and natural gas reserves were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil, NGL and natural gas price for each month within the 12-month period prior to the balance sheet date, held flat over the life of the properties. However, projected future crude oil, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions. Crude oil, NGL and natural gas prices are volatile and affected by worldwide production and consumption and are outside the control of management.

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 drilling and completion costs; future sales prices for oil, NGL and natural gas; future production costs; estimates of future oil, NGL and natural 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, NGL and natural gas reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations to reflect any material changes since the prior report was issued and then utilizes updated projected future price decks current with the period. For both the three months ended June 30, 2018 and 2017, the assessment resulted in no impairment provisions on producing properties. For the nine months ended June 30, 2018 and 2017, the assessment resulted in impairment provisions on producing properties of $0 and $10,788, respectively. A significant reduction in oil, NGL and natural gas prices or a decline in reserve volumes may lead to additional impairment in future periods that may be material to the Company.

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NOTE 8: Derivatives

The Company has entered into commodity price derivative agreements including fixed swap contracts and costless collar contracts. These 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. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index 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 currently with Bank of Oklahoma and are secured under its credit facility with Bank of Oklahoma. The derivative instruments have settled or will settle based on the prices below.

Derivative contracts in place as of June 30, 2018

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.30 ceiling
April - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.15 ceiling
Natural gas fixed price swaps
January - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.080
April - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.910
July - December 2018	100,000 Mmbtu	NYMEX Henry Hub	$2.835
July - December 2018	100,000 Mmbtu	NYMEX Henry Hub	$2.925
July - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$2.988
July 2018 - March 2019	50,000 Mmbtu	NYMEX Henry Hub	$3.065
Oil costless collars
January - December 2018	2,000 Bbls	NYMEX WTI	$47.50 floor / $52.50 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$48.00 floor / $53.25 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$50.00 floor / $55.75 ceiling
July - December 2018	3,000 Bbls	NYMEX WTI	$50.00 floor / $58.00 ceiling
January - June 2019	2,000 Bbls	NYMEX WTI	$55.00 floor / $63.45 ceiling
January - December 2019	1,000 Bbls	NYMEX WTI	$50.00 floor / $60.00 ceiling
January - December 2019	2,000 Bbls	NYMEX WTI	$60.00 floor / $69.25 ceiling
Oil fixed price swaps
January - December 2018	3,000 Bbls	NYMEX WTI	$50.72
January - December 2018	2,000 Bbls	NYMEX WTI	$52.02
April - December 2018	4,000 Bbls	NYMEX WTI	$54.14
July - December 2018	2,000 Bbls	NYMEX WTI	$58.20
January - June 2019	2,000 Bbls	NYMEX WTI	$59.69
January - June 2019	2,000 Bbls	NYMEX WTI	$57.15
January - June 2019	3,000 Bbls	NYMEX WTI	$58.02
January - December 2019	1,000 Bbls	NYMEX WTI	$56.15
January - December 2019	2,000 Bbls	NYMEX WTI	$56.71
January - December 2019	1,000 Bbls	NYMEX WTI	$58.56
July - December 2019	2,000 Bbls	NYMEX WTI	$56.85

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 a net liability of $3,303,480 as of June 30, 2018, and a net asset of $516,159 as of September 30, 2017. Net cash paid related to derivative contracts settled during the nine-month period ended June 30, 2018, was $147,230 compared to net cash paid of $221,321 in the same period in the prior year.

The fair value amounts recognized for the Company’s derivative contracts executed with the same counterparty under a master netting arrangement may be offset. The Company has the choice to offset or not, but that choice must be applied consistently.

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A master netting arrangement exists if the reporting entity has multiple contracts with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for the derivative contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Balance Sheets.

The following table summarizes and reconciles the Company's derivative contracts’ fair values at a gross level back to net fair value presentation on the Company's Condensed Balance Sheets at June 30, 2018, and September 30, 2017. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at June 30, 2018, and September 30, 2017.

	June 30, 2018												September 30, 2017
	Fair Value (a)												Fair Value (a)
	Commodity Contracts												Commodity Contracts
	Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities			Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities
Gross amounts recognized	$	84,260		$	3,098,771		$	7,943		$	296,912		$	735,702		$	190,778		$	9,439		$	38,204
Offsetting adjustments		(84,260	)		(84,260	)		(7,943	)		(7,943	)		(190,778	)		(190,778	)		(9,439	)		(9,439	)
Net presentation on Condensed Balance Sheets	$	-		$	3,014,511		$	-		$	288,969		$	544,924		$	-		$	-		$	28,765

(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 9: 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 June 30, 2018.

	Fair Value Measurement at June 30, 2018
	Quoted Prices in Active Markets		Significant Other Observable Inputs			Significant Unobservable Inputs			Total Fair
	(Level 1)		(Level 2)			(Level 3)			Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	(2,190,162	)	$	-		$	(2,190,162	)
Derivative Contracts - Collars	$	-	$	-		$	(1,113,318	)	$	(1,113,318	)

Level 2 – Market Approach - The fair values of the Company’s 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 future prices, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.

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Level 3 – The fair values of the Company’s costless 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 future prices, volatility, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.

The significant unobservable inputs for Level 3 derivative contracts include market volatility and credit risk of counterparties. Changes in these inputs will impact the fair value measurement of our derivative contracts. An increase (decrease) in the volatility of oil and natural gas prices will decrease (increase) the fair value of oil and natural gas derivatives and adverse changes to our counterparties’ creditworthiness will decrease the fair value of our derivatives.

The following table represents quantitative disclosures about unobservable inputs for Level 3 Fair Value Measurements.

Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value June 30, 2018
Oil Collars	Oil price volatility curve	0% - 31.24%	17.16%	$	(1,119,628	)
Natural Gas Collars	Gas price volatility curve	0% - 16.25%	9.08%	$	6,310

A reconciliation of the Company’s derivative contracts 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 Condensed Statements of Operations.

	Derivatives
Balance of Level 3 as of October 1, 2017	$	151,553
Total gains or (losses)
Included in earnings		(1,255,605	)
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		(9,266	)
Transfers in and out of Level 3		-
Balance of Level 3 as of June 30, 2018	$	(1,113,318	)

 At June 30, 2018, and September 30, 2017, the fair value of financial instruments approximated their carrying amounts. Financial instruments include long-term debt, which the valuation is classified as Level 2 as the carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.

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 2018 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, NGL and natural 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, NGL and natural gas reserves. Investors should also read the other information in this Form 10-Q and the Company’s 2017 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.

RESULTS OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2018 – COMPARED TO THREE MONTHS ENDED JUNE 30, 2017

Overview:

The Company recorded a third quarter 2018 net loss of $775,093, or $0.05 per share, as compared to net income of $1,260,758, or $0.07 per share, in the 2017 quarter. The change in net income (loss) was principally the result of losses on derivative

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contracts and decreased lease bonuses; partially offset by increased oil, NGL and natural gas sales and changes in tax provision (benefit). These items are further discussed below.

Oil, NGL and Natural Gas Sales:

Oil, NGL and natural gas sales increased $1,204,782 or 12% for the 2018 quarter. Oil, NGL and natural gas sales were up due to increases in oil and NGL prices of 49% and 15%, respectively, and increased oil and NGL sales volumes of 6% and 71%, respectively, partially offset by decreased natural gas prices and sales volumes of 17% and 8%, respectively. The following table outlines the Company’s production and average sales prices for oil, NGL and natural gas for the three-month periods of fiscal 2018 and 2017:

	Oil Bbls		Average		NGL Bbls		Average		Mcf		Average		Mcfe		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Three months ended
6/30/2018		80,298	$	66.15		67,142	$	19.20		2,082,700	$	2.21		2,967,340	$	3.78
6/30/2017		75,467	$	44.38		39,337	$	16.63		2,265,091	$	2.65		2,953,915	$	3.38

The oil production increase is a result of the ten-well drilling program in the Eagle Ford Shale and the six-well program in the Anadarko Basin Woodford Shale. New production from successful drilling in the STACK play in western Oklahoma and new royalty production in Eddy County, New Mexico, add to the increase. The growth is partially offset by natural declining production from the Bakken in North Dakota and, to a lesser extent, in the Anadarko Basin Granite Wash in western Oklahoma and Northern Oklahoma Mississippian. The NGL production increase is attributed to the liquid-rich production from the six-well drilling program in the Anadarko Basin Woodford Shale. Decreased gas production was due to naturally declining production in the southeastern Oklahoma Woodford Shale and the Fayetteville Shale in Arkansas and, to a lesser extent, the result of marginal property divestitures. These decreases were partially offset by the six-well drilling program in the Anadarko Basin Woodford Shale and new drilling in the STACK play in western Oklahoma.

Production for the last five quarters was as follows:

Quarter ended	Oil Bbls Sold		NGL Bbls Sold		Mcf Sold		Mcfe Sold
6/30/2018		80,298		67,142		2,082,700		2,967,340
3/31/2018		82,312		56,747		2,107,920		2,942,274
12/31/2017		90,837		72,401		2,442,384		3,421,812
9/30/2017		93,027		65,034		2,330,838		3,279,204
6/30/2017		75,467		39,337		2,265,091		2,953,915

Lease Bonuses and Rentals:

Lease bonuses and rentals decreased $335,293 in the 2018 quarter. The decrease was mainly due to the Company completing smaller mineral lease packages during the 2018 quarter.

Gains (Losses) on Derivative Contracts:

The fair value of derivative contracts was a net liability of $3,303,480 as of June 30, 2018, and a net asset of $1,451,397 as of June 30, 2017. We had a net loss on derivative contracts of $2,129,041 in the 2018 quarter as compared to a net gain of $1,619,697 in the 2017 quarter. The change is principally due to the oil collars and fixed price swaps being less favorable in the 2018 quarter, as NYMEX oil futures experienced a large increase in price in relation to the collars and the fixed prices of the swaps. During the 2017 quarter, the oil and natural gas collars and fixed price swaps experienced a very favorable change as the NYMEX futures prices (at that time) for both commodities decreased significantly from where they were at the end of the second quarter in 2017. The Company utilizes derivative contracts for the purpose of protecting its return on investments.

Lease Operating Expenses (LOE):

LOE decreased $157,907 or 5% in the 2018 quarter. LOE per Mcfe decreased in the 2018 quarter to $1.09 compared to $1.15 in the 2017 quarter. LOE related to field operating costs decreased $150,418 or 9% in the 2018 quarter compared to the 2017 quarter. Field operating costs were $.53 per Mcfe in the 2018 quarter as compared to $.58 per Mcfe in the 2017 quarter. The decrease in rate in the 2018 quarter is principally the result of significant new low-cost production coming on line late in fiscal 2017 and the first quarter of 2018 and the Company selling some marginal properties which had higher operating costs.

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The decrease in LOE related to field operating costs was coupled with a decrease in handling fees (primarily gathering, transportation and marketing costs) of $7,489 in the 2018 quarter compared to the 2017 quarter. On a per Mcfe basis, these handling fees were $0.56 in the 2018 quarter as compared to $0.57 in the 2017 quarter. The decrease in rate was due to new natural gas production coming on (since the 2017 quarter) with lower handling charges and increased oil production. Natural gas sales bear the large majority of the handling fees while oil sales incur a much smaller amount. Handling fees are charged either as a percent of sales or based on production volumes.

Loss (Gain) on Asset Sales and Other:

Loss on asset sales increased $195,076 in the 2018 quarter. This increase is primarily related to the sale of marginal properties in the 2018 quarter. There were no asset sales in the 2017 quarter.

Interest Expense:

Interest expense increased $114,735 or 37% in the 2018 quarter. The increase was the result of a higher interest rate of 4.08% during the 2018 quarter as compared to 3.15% in the 2017 quarter.

General and Administrative Costs (G&A):

G&A decreased $202,753 or 11% in the 2018 quarter. The decrease was the result of lower legal expenses and audit and tax fees. The decrease in legal fees was mainly due to less legal time spent on SEC filings (e.g. the S-3) and other matters during the 2018 quarter. The decrease in audit and tax fees was mainly due to timing of work performed.

Income Taxes:

Income taxes changed $776,000, from a $567,000 provision in the 2017 quarter to a $209,000 benefit in the 2018 quarter. This was mainly the result of the new Tax Cuts and Jobs Act enacted in December 2017 that reduces the US federal corporate tax rate from 35% to 21%. An estimate of the tax effects of this law change on our existing deferred tax liabilities of $48,000 was made in the 2018 quarter and is directly affecting the effective tax rate noted for this period. Additionally, due to the Company having a September 30 year end versus a calendar year end, we have calculated the current year’s federal tax provision using a blended rate of 24.53% to adjust for one quarter of our fiscal year being under the old rate of 35% and the remaining three quarters being under the new rate of 21%. The effective tax rate changed from a 31% provision in the 2017 quarter to a 21% benefit in the 2018 quarter.

When a provision for income taxes is expected for the year, federal and Oklahoma excess percentage depletion decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is recorded.

NINE MONTHS ENDED JUNE 30, 2018– COMPARED TO NINE MONTHS ENDED JUNE 30, 2017

Overview:

The Company recorded nine month net income of $14,080,022, or $0.83 per share, in the 2018 period, as compared to net income of $2,492,799, or $0.15 per share, in the 2017 period. The change in net income (loss) was principally the result of increased tax benefits (due to new federal tax law), increases in oil, NGL and natural gas sales; partially offset by decreased lease bonuses and rentals, losses on derivative contracts and increased LOE, production taxes, DD&A and interest expense. These items are further discussed below.

Oil, NGL and Natural Gas Sales:

Oil, NGL and natural gas sales increased $8,568,117 or 31% for the 2018 period. Oil, NGL and natural gas sales were higher due to increases in oil and NGL prices of 32% and 27%, respectively, and increases in oil, NGL and natural gas sales volumes of 16%, 80% and 13%, respectively, partially offset by a decrease in natural gas sales prices of 8%. The following table outlines the Company’s production and average sales prices for oil, NGL and natural gas for the nine-month periods of fiscal 2018 and 2017:

	Oil Bbls		Average		NGL Bbls		Average		Mcf		Average		Mcfe		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Nine months ended
6/30/2018		253,447	$	60.77		196,290	$	23.02		6,633,005	$	2.48		9,331,427	$	3.90
6/30/2017		217,650	$	46.06		108,824	$	18.08		5,863,692	$	2.69		7,822,536	$	3.55

(14)

Oil production increased as a result of the ten-well drilling program in the Eagle Ford Shale and the six-well program in the Anadarko Basin Woodford Shale. New production from successful drilling in the STACK play in western Oklahoma and new royalty production in Eddy County, New Mexico, added to the increase. The gain is partially offset by natural declining production from the Bakken in North Dakota and Northern Oklahoma Mississippian. The NGL production increase is attributed to the liquid-rich production from the six-well drilling program in the Anadarko Basin Woodford Shale. Increased gas production is realized from the eight-well drilling program in the southeastern Oklahoma Woodford Shale, the six-well drilling program in the Anadarko Basin Woodford Shale, and new completions in the STACK play in western Oklahoma. The gas production increase was partially offset by naturally declining production in the Fayetteville Shale in Arkansas and marginal property divestitures.

Lease Bonuses and Rentals:

Lease bonuses and rentals decreased $2,911,297 in the 2018 period. The decrease was mainly due to the Company completing significant mineral lease packages covering several counties in New Mexico and Oklahoma in the 2017 period. There were no significant lease packages in the 2018 period.

Gains (Losses) on Derivative Contracts:

The fair value of derivative contracts was a net liability of $3,303,480 as of June 30, 2018, and a net asset of $1,451,397 as of June 30, 2017. We had a net loss on derivative contracts of $3,966,869 in the 2018 period as compared to a net gain of $1,658,347 recorded in the 2017 period. The change is principally due to the oil collars and fixed price swaps being less favorable in the 2018 period, as NYMEX oil futures increased further above the ceiling of the collars and the fixed prices of the swaps. The natural gas collars and fixed price swaps in place during the 2018 period were very beneficial and the largest part of the gain from these contracts (covering January through March 2018 production) cash settled during the period. The Company utilizes derivative contracts for the purpose of protecting its return on investments.

Lease Operating Expenses (LOE):

LOE increased $531,459 or 6% in the 2018 period. LOE per Mcfe decreased in the 2018 period to $1.08 compared to $1.22 in the 2017 period. LOE related to field operating costs decreased $103,689 or 2% in the 2018 period compared to the 2017 period. Field operating costs were $.54 per Mcfe in the 2018 period as compared to $.66 per Mcfe in the 2017 period. The decrease in rate in the 2018 period is principally the result of significant new low-cost production coming on line late in fiscal 2017 and the first quarter of 2018 and the Company selling some marginal properties which had higher operating costs.

The decrease in LOE related to field operating costs was more than offset by an increase in handling fees (primarily gathering, transportation and marketing costs) of $635,148 in the 2018 period compared to the 2017 period. On a per Mcfe basis, these fees decreased $.02 due to new natural gas production coming on since the 2017 period with lower handling charges and increased oil production. Natural gas sales bear the large majority of the handling fees while oil sales incur a much smaller amount. Handling fees are charged either as a percent of sales or based on production volumes.

Production Taxes

Production taxes increased $342,185 or 30% in the 2018 period. The increase is primarily the result of increased oil, NGL and natural gas sales of $8,568,117 during the 2018 period. Production taxes as a percentage of oil, NGL and natural gas sales were 4.0% for the 2018 period and 4.1% for the 2017 period.

Depreciation, Depletion and Amortization (DD&A):

DD&A increased $482,143 or 4% in the 2018 period. DD&A in the 2018 period was $1.51 per Mcfe as compared to $1.75 per Mcfe in the 2017 period. DD&A increased $2,633,775 as a result of production increasing 19% in the 2018 period compared to the 2017 period. An offsetting decrease of $2,151,632 was the result of a $.24 decrease in the DD&A rate per Mcfe. The rate decrease is mainly due to higher oil prices utilized in the reserve calculations during the 2018 period, as compared to 2017 period, lengthening the economic life of wells thus resulting in higher projected remaining reserves on a number of wells. The Company had new high-volume wells with low finding costs begin producing in the latter half of 2017 and the first quarter of 2018, which also contributed to the rate decrease.

(15)

Interest Expense:

Interest expense increased $403,498 or 46% in the 2018 period. The increase was the result of higher average outstanding balances and a higher interest rate of 3.79% during the 2018 period as compared to 2.92% in the 2017 period.

Income Taxes:

Income taxes changed $13,206,000, from a $263,000 provision in the 2017 period to a $12,943,000 benefit in the 2018 period. This was mostly the result of the new Tax Cuts and Jobs Act enacted in December 2017 that reduces the US federal corporate tax rate from 35% to 21%. An estimate of the tax effects of this law change on our existing deferred tax liabilities of $12,777,000 was made in the 2018 period and is directly affecting the effective tax rate noted for this period. Additionally, due to the Company having a September 30 year end versus a calendar year end, we have calculated the current year’s federal tax provision using a blended rate of 24.53% to adjust for one quarter of our fiscal year being under the old rate of 35% and the remaining three quarters being under the new rate of 21%. The effective tax rate changed from a 10% provision in the 2017 period to an 1138% benefit in the 2018 period.

When a provision for income taxes is expected for the year, federal and Oklahoma excess percentage depletion decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is recorded.

LIQUIDITY AND CAPITAL RESOURCES

The Company had positive working capital of $1,620,248 at June 30, 2018, compared to positive working capital of $6,451,356 at September 30, 2017. The change in working capital was mainly due to the net change in receivables (payables) for derivative contracts and decreased payables for drilling activity as of June 30, 2018.

Liquidity:

Cash and cash equivalents were $477,013 as of June 30, 2018, compared to $557,791 at September 30, 2017, a decrease of $80,778. Cash flows for the nine months ended June 30 are summarized as follows:

Net cash provided (used) by:

	2018			2017			Change
Operating activities	$	21,657,902		$	14,321,237		$	7,336,665
Investing activities		(7,620,860	)		(17,311,552	)		9,690,692
Financing activities		(14,117,820	)		3,079,994			(17,197,814	)
Increase (decrease) in cash and cash equivalents	$	(80,778	)	$	89,679		$	(170,457	)

Operating activities:

Net cash provided by operating activities increased $7,336,665 during the 2018 period, as compared to the 2017 period, primarily the result of the following:

• Decreased receipts from leasing of fee mineral acreage of $2,923,465.

• Receipts of oil, NGL and natural gas sales (net of production taxes and gathering, transportation and marketing costs) and other increased $12,756,360.

• Decreased income tax payments of $881,052.

• Decreased net payments on derivative contracts of $74,091.

• Increased interest payments of $453,514.

• Increased payments for G&A and other expense of $319,705.

• Increased payments for field operating expenses of $2,678,153.

(16)

Investing activities:

Net cash used by investing activities decreased $9,690,692 during the 2018 period, as compared to the 2017 period, primarily due to lower payments of $10,268,624 for drilling and completion activity, higher acquisition costs of $966,279 and higher proceeds from the sale of assets during 2018 of $366,437.

Financing activities:

Net cash used by financing activities increased $17,197,814 during the 2018 period, as compared to the 2017 period, primarily the result of higher net payments on long-term debt of $17,322,220.

Capital Resources:

Capital expenditures to drill and complete wells decreased $10,268,624 (57%) from the 2017 to the 2018 period. The Company completed the last of its significant drilling projects that were started in 2017 during the first quarter of 2018. The final four wells of the ten-well Eagle Ford Shale drilling program (from 2017) were completed and started producing in 2018. New drilling in the Eagle Ford began in June 2018 as the operator has committed to a seven-well program that could be extended to a total of fourteen depending on market conditions. Even with the current uncertainty around drilling expectations for the remainder of the year, management believes that 2018 capital expenditures will be lower than 2017 capital expenditures.

On July 16, 2018, the Company entered into a Purchase and Sale Agreement to acquire certain mineral acreage and producing oil and gas properties, primarily located in the Bakken Shale, from a private seller for total consideration of $9,000,000 cash (pending any closing adjustments). The transaction is expected to close by late August and will have an effective date of June 1, 2018. The acquisition will be funded utilizing the Company’s bank credit facility.

Since the Company is not the operator of any of its oil and natural gas properties, it is difficult for us to predict the level of future participation in and precise timing of the drilling and completion of new wells. Thus capital expenditures for drilling and completion projects are difficult to forecast.

The Company received lease bonus payments during 2018 totaling $1,102,818. Looking forward, the cash flow benefit from bonus payments associated with the leasing of drilling rights on the Company’s mineral acreage is very difficult to project as the Company’s mineral acreage position is so diverse and spread across several states. However, management will continue to strategically evaluate the merit of proactively leasing certain of the Company’s mineral acres.

With continued oil and natural gas price volatility, management continues to evaluate opportunities for product price protection through additional hedging of the Company’s future oil and natural gas production. See NOTE 8– “Derivatives” for a complete list of the Company’s outstanding derivative contracts.

The use of the Company’s cash provided by operating activities and resultant change to cash is summarized in the table below:

	Nine months ended
	June 30, 2018
Cash provided by operating activities	$	21,657,902
Cash provided (used) by:
Capital expenditures - acquisitions		(966,279	)
Capital expenditures - drilling and completion of wells		(7,743,097	)
Quarterly dividends of $.12 per share		(2,023,500	)
Treasury stock purchases		(272,100	)
Net borrowings (payments) on credit facility		(11,822,220	)
Proceeds from sale of assets		1,085,137
Other investing and financing activities		3,379
Net cash used		(21,738,680	)
Net increase (decrease) in cash	$	(80,778	)

(17)

Outstanding borrowings on the credit facility at June 30, 2018, were $40,400,000.

Looking forward, the Company expects to fund overhead costs, capital additions related to the drilling and completion of wells, acquisitions, treasury stock purchases, if any, and dividend payments from cash provided by operating activities, cash on hand and borrowings utilizing our bank credit facility. Any excess cash is intended to be used to reduce existing bank debt. The Company had availability ($39,600,000 at June 30, 2018) under its revolving credit facility and is in compliance with its debt covenants (current ratio, debt to trailing 12-month EBITDA, as defined by bank agreement, and restricted payments limited by leverage ratio). The debt covenants limit the maximum ratio of the Company’s debt to EBITDA to no more than 4:1.

The borrowing base under the credit facility was redetermined in July 2018 and left unchanged at $80 million, which is a level that is expected to provide ample liquidity for the Company to continue to execute its normal operating strategies. The next redetermination is scheduled for December 2018.

Based on expected capital expenditure levels, anticipated cash provided by operating activities for 2018 and availability under its credit facility, the Company has sufficient liquidity to fund its ongoing operations.

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, 2017.

ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

Oil, NGL and natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of oil, NGL and natural gas price trends, and there remains a rather wide divergence in the opinions held in the industry. The Company can be significantly impacted by changes in oil and natural gas prices. The market price of oil, NGL and natural gas in 2018 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 2018 derivative contracts, the price sensitivity in 2018 for each $1.00 per barrel change in wellhead oil price is $310,677 for operating revenue based on the Company’s prior year oil volumes. The price sensitivity in 2018 for each $0.10 per Mcf change in wellhead natural gas price is $819,453 for operating revenue based on the Company’s prior year natural gas volumes.

Commodity Price Risk

The Company periodically utilizes derivative contracts to reduce its exposure to unfavorable changes in oil and natural gas prices. The Company does not enter into these derivatives for speculative or trading purposes. All of our outstanding derivative contracts are currently with Bank of Oklahoma and are secured. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in oil and natural gas prices. These derivative contracts expose the Company to risk of financial loss and limit the benefit of future increases in prices. For the Company’s oil fixed price swaps, a change of $1.00 in the NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $181,000. For the Company’s oil collars, a change of $1.00 in the NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $95,000. For the Company’s natural gas fixed price swaps, a change of $.10 in the NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $249,000. For the Company’s natural gas collars, a change of $.10 in the NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $29,700.

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 BOK prime rate plus from 0.375% to 1.250%, or 30 day LIBOR plus from 1.875% to 2.750%. At June 30, 2018, the Company had $40,400,000 outstanding under this facility and the effective interest rate was 4.20%. At this point, the Company does not believe that its liquidity has been materially affected by the interest rate uncertainties noted in the last few years and the Company does not believe that its liquidity will be significantly impacted in the near future.

(18)

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 and Controller, 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 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, subject to the limitations noted above, the Company’s disclosure controls and procedures were effective to ensure 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 June 30, 2018, the Company did not repurchase shares of the Company’s common stock.

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan in March 2010, as amended in May 2018, the board of directors approved to continue to allow management to repurchase up to $1.5 million of the Company’s common stock at their discretion. The repurchase of an additional $1.5 million of the Company’s common stock continues to be authorized and approved effective when the previous amount is utilized, and the Board added language to clarify that this is intended to be an evergreen provision. The number of shares allowed to be purchased by the Company under the Repurchase Program is no longer capped at an amount equal to the aggregate number of shares of common stock (i) awarded pursuant to the Company’s Amended 2010 Restricted Stock Plan, (ii) contributed by the Company to its ESOP, and (iii) credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.

ITEM 6 EXHIBITS

(a)	EXHIBITS	Exhibit 31.1 – Certification under Section 302 of the Sarbanes-Oxley Act of 2002
		Exhibit 31.2 – Certification under Section 302 of the Sarbanes-Oxley Act of 2002
		Exhibit 32.1 – Certification under Section 906 of the Sarbanes-Oxley Act of 2002
		Exhibit 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 (5/29/18), item 8.01 – Other Events
	Form 8-K	Dated (7/2/18), item 5.02 – Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers
	Form 8-K	Dated (7/2/18), item 1.01 – Enter Into a Material Definitive Agreement
	Form 8-K	Dated (7/19/18), item 8.01 – Other Events
	Form 8-K	Dated (7/23/18), item 5.02 – Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers

(19)

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.
	PANHANDLE OIL AND GAS INC.
August 6, 2018	/s/ Paul F. Blanchard Jr.
Date	Paul F. Blanchard Jr., President and
	Chief Executive Officer
August 6, 2018	/s/ Robb P. Winfield
Date	Robb P. Winfield, Vice President,
	Chief Financial Officer and Controller

(20)

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Paul F. Blanchard Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Panhandle Oil and Gas Inc. (the Company);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d -15(f), for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Paul F. Blanchard Jr.

Paul F. Blanchard Jr.

Chief Executive Officer

Date: August 6, 2018

EX-31.2

EXHIBIT 31. 2

CERTIFICATION

I, Robb P. Winfield, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Panhandle Oil and Gas Inc. (the Company);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d -15(f), for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Robb P. Winfield

Robb P. Winfield

Chief Financial Officer

Date: August 6, 2018

EX-32.1

EXHIBIT 32.1

Panhandle Oil and Gas Inc.

5400 North Grand Blvd. Suite #300

Oklahoma City, OK 73112

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Paul F. Blanchard Jr., Chief Executive Officer of Panhandle Oil and Gas Inc., (the “Issuer”), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify in connection with the Issuer’s Quarterly Report on Form 10-Q for the period that ended June 30, 2018, as filed with the Securities and Exchange Commission (the “Report”) that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Issuer.

/s/ Paul F. Blanchard Jr.

Paul F. Blanchard Jr.

President &

Chief Executive Officer

August 6, 2018

EX-32.2

EXHIBIT 32.2

Panhandle Oil and Gas Inc.

5400 North Grand Blvd. Suite #300

Oklahoma City, OK 73112

CERTIFICATION OF CHIEF FINANCIAL OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Robb P. Winfield, Chief Financial Officer of Panhandle Oil and Gas Inc., (the “Issuer”), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify in connection with the Issuer’s Quarterly Report on Form 10-Q for the period that ended June 30, 2018, as filed with the Securities and Exchange Commission (the “Report”) that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Issuer.

/s/ Robb P. Winfield

Robb P. Winfield

Vice-President,

Chief Financial Officer and Controller

August 6, 2018

XML

Document and Entity Information - shares	9 Months Ended
	Jun. 30, 2018	Aug. 06, 2018
Document And Entity Information [Abstract]
Entity Registrant Name	PANHANDLE OIL & GAS INC
Entity Central Index Key	0000315131
Trading Symbol	PHX
Document Type	10-Q
Document Period End Date	Jun. 30, 2018
Amendment Flag	false
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--09-30
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		16,778,509

XML

Condensed Balance Sheets - USD ($)		Jun. 30, 2018	Sep. 30, 2017
Current assets:
Cash and cash equivalents		$ 477,013	$ 557,791
Oil, NGL and natural gas sales receivables (net of allowance for uncollectable accounts)		6,489,489	7,585,485
Refundable income taxes		209,970	489,945
Assets held for sale			557,750
Derivative contracts, net	[1]		544,924
Other		176,356	253,480
Total current assets		7,352,828	9,989,375
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties		418,338,755	434,571,516
Non-producing oil and natural gas properties		8,170,286	7,428,927
Other		1,515,076	1,067,894
Gross properties and equipment, at cost, based on successful efforts accounting		428,024,117	443,068,337
Less accumulated depreciation, depletion and amortization		(239,052,685)	(246,483,979)
Net properties and equipment		188,971,432	196,584,358
Investments		212,068	170,486
Total assets		196,536,328	206,744,219
Current liabilities:
Accounts payable		1,163,424	1,847,230
Derivative contracts, net	[1]	3,014,511
Accrued liabilities and other		1,554,645	1,690,789
Total current liabilities		5,732,580	3,538,019
Long-term debt		40,400,000	52,222,000
Deferred income taxes, net		18,104,007	31,051,007
Asset retirement obligations		2,776,058	3,196,889
Derivative contracts, net	[1]	288,969	28,765
Stockholders' equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 16,896,455 issued at June 30, 2018, and 16,863,004 issued at September 30, 2017		281,495	280,938
Capital in excess of par value		2,690,834	2,726,444
Deferred directors' compensation		2,882,263	3,459,909
Retained earnings		125,386,738	113,330,216
Stockholders' Equity		131,241,330	119,797,507
Less treasury stock, at cost; 117,946 shares at June 30, 2018, and 184,988 shares at September 30, 2017		(2,006,616)	(3,089,968)
Total stockholders' equity		129,234,714	116,707,539
Total liabilities and stockholders' equity		$ 196,536,328	$ 206,744,219

[1] See Fair Value Measurements section for further disclosures regarding fair value of financial instruments.

XML

Condensed Balance Sheets (Parenthetical) - $ / shares	Jun. 30, 2018	Sep. 30, 2017
Statement Of Financial Position [Abstract]
Common stock, par value	$ 0.0166	$ 0.0166
Common stock, shares authorized	24,000,000	24,000,000
Common stock, shares issued	16,896,455	16,863,004
Treasury stock, shares	117,946	184,988

XML

Condensed Statements Of Operations - USD ($)	3 Months Ended		9 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues:
Revenues	$ 9,557,937	$ 12,437,186	$ 33,469,721	$ 33,438,117
Lease bonuses and rentals	484,298	819,591	1,080,455	3,991,752
Gains (losses) on derivative contracts	(2,129,041)	1,619,697	(3,966,869)	1,658,347
Costs and expenses:
Lease operating expenses	3,233,172	3,391,079	10,077,449	9,545,990
Production taxes	485,157	390,387	1,471,970	1,129,785
Depreciation, depletion and amortization	4,619,509	4,714,350	14,136,411	13,654,268
Provision for impairment	0	0	0	10,788
Loss (gain) on asset sales and other	190,045	11,447	110,859	98,445
Interest expense	420,896	306,161	1,288,426	884,928
General and administrative	1,593,251	1,796,004	5,247,584	5,358,114
Total costs and expenses	10,542,030	10,609,428	32,332,699	30,682,318
Income (loss) before provision (benefit) for income taxes	(984,093)	1,827,758	1,137,022	2,755,799
Provision (benefit) for income taxes	(209,000)	567,000	(12,943,000)	263,000
Net income (loss)	$ (775,093)	$ 1,260,758	$ 14,080,022	$ 2,492,799
Basic and diluted earnings (loss) per common share	$ (0.05)	$ 0.07	$ 0.83	$ 0.15
Basic and diluted weighted average shares outstanding:
Common shares	16,775,981	16,668,814	16,742,044	16,639,090
Unissued, directors' deferred compensation shares	206,202	254,891	205,867	277,294
Basic and diluted weighted average shares outstanding	16,982,183	16,923,705	16,947,911	16,916,384
Dividends declared per share of common stock and paid in period	$ 0.04	$ 0.04	$ 0.12	$ 0.12
Oil, NGL and Natural Gas [Member]
Revenues:
Revenues	$ 11,202,680	$ 9,997,898	$ 36,356,135	$ 27,788,018

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Statements Of Stockholders' Equity - USD ($)	Total	Class A voting Common Stock [Member]	Capital in Excess of Par Value [Member]	Deferred Directors' Compensation [Member]	Retained Earnings [Member]	Treasury Stock [Member]
Balances at Sep. 30, 2016	$ 115,191,819	$ 280,938	$ 3,191,056	$ 3,403,213	$ 112,482,284	$ (4,165,672)
Balances, shares at Sep. 30, 2016		16,863,004
Balances, Treasury shares at Sep. 30, 2016						(262,708)
Net income (loss)	2,492,799				2,492,799
Purchase of treasury stock	(407,677)					$ (407,677)
Purchase of treasury stock, shares						(17,119)
Issuance of treasury shares to ESOP	(18)		(2)			$ (16)
Issuance of treasury shares to ESOP, shares						(1)
Restricted stock awards	454,854		454,854
Dividends ($.12 per share)	(2,012,329)				(2,012,329)
Distribution of restricted stock to officers and directors	622		(968,617)			$ 969,239
Distribution of restricted stock to officers and directors, shares						60,624
Distribution of deferred directors' compensation	(1)		(145,469)	(301,963)		$ 447,431
Distribution of deferred directors' compensation, shares						27,216
Increase in deferred directors' compensation charged to expense	266,182			266,182
Balances at Jun. 30, 2017	115,986,251	$ 280,938	2,531,822	3,367,432	112,962,754	$ (3,156,695)
Balances, shares at Jun. 30, 2017		16,863,004
Balances, Treasury shares at Jun. 30, 2017						(191,988)
Balances at Sep. 30, 2017	$ 116,707,539	$ 280,938	2,726,444	3,459,909	113,330,216	$ (3,089,968)
Balances, shares at Sep. 30, 2017		16,863,004
Balances, Treasury shares at Sep. 30, 2017	(184,988)					(184,988)
Net income (loss)	$ 14,080,022				14,080,022
Purchase of treasury stock	(272,100)					$ (272,100)
Purchase of treasury stock, shares						(13,404)
Issuance of treasury shares to ESOP	6,735		2,009			$ 4,726
Issuance of treasury shares to ESOP, shares						283
Restricted stock awards	501,626		501,626
Dividends ($.12 per share)	(2,023,500)				(2,023,500)
Distribution of restricted stock to officers and directors	819	$ 14	(808,357)			$ 809,162
Distribution of restricted stock to officers and directors, shares		852				48,325
Distribution of deferred directors' compensation		$ 543	269,112	(811,219)		$ 541,564
Distribution of deferred directors' compensation, shares		32,599				31,838
Increase in deferred directors' compensation charged to expense	233,573			233,573
Balances at Jun. 30, 2018	$ 129,234,714	$ 281,495	$ 2,690,834	$ 2,882,263	$ 125,386,738	$ (2,006,616)
Balances, shares at Jun. 30, 2018		16,896,455
Balances, Treasury shares at Jun. 30, 2018	(117,946)					(117,946)

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Statements Of Stockholders' Equity (Parenthetical) - $ / shares	9 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Statement Of Stockholders Equity [Abstract]
Dividends per share	$ 0.12	$ 0.12

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Condensed Statements Of Cash Flows - USD ($)	9 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Operating Activities
Net income (loss)	$ 14,080,022	$ 2,492,799
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	14,136,411	13,654,268
Impairment	0	10,788
Provision for deferred income taxes	(12,947,000)	149,000
Gain from leasing fee mineral acreage	(1,079,803)	(3,999,632)
Proceeds from leasing fee mineral acreage	1,102,818	4,026,283
Net (gain) loss on sales of assets	660,597	87,161
Directors' deferred compensation expense	233,573	266,182
Fair value of derivative contracts	3,819,639	(1,879,668)
Restricted stock awards	501,626	454,854
Other	5,113	2,897
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables	1,095,996	(564,767)
Other current assets	77,124	196,362
Accounts payable	(125,261)	(127,375)
Income taxes receivable	279,975	(488,112)
Other non-current assets	(52,644)
Accrued liabilities	(130,284)	40,197
Total adjustments	7,577,880	11,828,438
Net cash provided by operating activities	21,657,902	14,321,237
Investing Activities
Capital expenditures	(7,743,097)	(18,011,721)
Acquisition of minerals and overrides	(966,279)
Investments in partnerships	3,379	(18,531)
Proceeds from sales of assets	1,085,137	718,700
Net cash provided (used) by investing activities	(7,620,860)	(17,311,552)
Financing Activities
Borrowings under debt agreement	13,529,879	16,702,602
Payments of loan principal	(25,352,099)	(11,202,602)
Purchases of treasury stock	(272,100)	(407,677)
Payments of dividends	(2,023,500)	(2,012,329)
Net cash provided (used) by financing activities	(14,117,820)	3,079,994
Increase (decrease) in cash and cash equivalents	(80,778)	89,679
Cash and cash equivalents at beginning of period	557,791	471,213
Cash and cash equivalents at end of period	477,013	560,892
Supplemental Schedule of Noncash Investing and Financing Activities:
Additions to asset retirement obligations	15,452	60,276
Gross additions to properties and equipment	8,150,830	19,579,304
Net (increase) decrease in accounts payable for properties and equipment additions	558,546	(1,567,583)
Capital expenditures and acquisitions	$ 8,709,376	$ 18,011,721

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Basis of Presentation and Accounting Principles

9 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

Basis Of Presentation And Accounting Principles

NOTE 1: Basis of Presentation and Accounting Principles

Basis of Presentation

The accompanying unaudited condensed financial statements of Panhandle Oil and Gas Inc. have been prepared in accordance with the instructions to Form 10-Q as prescribed by the 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 2017 Annual Report on Form 10-K.

Adoption of New Accounting Pronouncements

In January 2017, the FASB issued ASU 2017-01, which changed the definition of a business. The new guidance requires an entity to first evaluate whether substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets. If that threshold is met, the set of assets and activities is not a business. If it’s not met, the entity evaluates whether the set meets the definition of a business. The new definition requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue recognition guidance. The new guidance is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. The ASU will be applied prospectively to any transactions occurring within the period of adoption. Early adoption is permitted, including for interim or annual periods for which the financial statements have not been issued or made available for issuance. The Company early adopted ASU 2017-01 during the quarter ended June 30, 2018.

New Accounting Pronouncements yet to be Adopted

In February 2016, the FASB issued its new lease accounting guidance in ASU 2016-02, Leases (Topic 842). Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date: 1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and 2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new lease guidance simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. Lessees will no longer be provided with a source of off-balance sheet financing. The guidance is effective for us beginning October 1, 2019, including interim periods within the fiscal year. Early application is permitted for all public business entities upon issuance. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. We are assessing the potential impact that this standard will have on our financial statements.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The new guidance is intended to improve the recognition and measurement of financial instruments. The new guidance is effective for us beginning October 1, 2018, including interim periods within the fiscal year. This update is not expected to have a material impact on our financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which will supersede nearly all existing revenue recognition guidance under GAAP. The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. We are evaluating our existing revenue recognition policies to determine whether any contracts in the scope of the guidance will be affected by the new requirements.

Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis.

The standard is effective for us beginning October 1, 2018. The standard allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements and utilizes a cumulative effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. Panhandle intends to use the modified retrospective method upon adoption.

The Company is nearing completion of its evaluation of the impact of the new standard and related interpretive guidance on its financial statements, accounting policies, internal controls, and disclosures. Based on assessments performed to date, the standard is not expected to have a material effect on the timing or measurement of the Company's revenue recognition or its financial position, results of operations, net income, or cash flows, but is expected to have an impact on the Company's revenue-related disclosures and internal controls over financial reporting.

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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Income Taxes

9 Months Ended

Jun. 30, 2018

Income Tax Disclosure [Abstract]

Income Taxes

NOTE 2: Income Taxes

The Tax Cuts and Jobs Act was enacted on December 22, 2017. The Act reduces the US federal corporate tax rate from 35% to 21%, requires companies to pay a one-time transition tax on earnings of certain foreign subsidiaries that were previously tax deferred and creates new taxes on certain foreign sourced earnings. As of June 30, 2018, we have not completed our accounting for the tax effects of enactment of the Act; however, in certain cases, as described below, we have made a reasonable estimate of the effects on our existing deferred tax balances. Based on these estimates, we recognized a provisional amount, which is included as a component of income tax expense (benefit) from continuing operations. In all cases, we will continue to make and refine our calculations as additional analysis is completed.

We remeasured certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. However, we are still analyzing certain aspects of the Act and refining our calculations, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. The provisional amount recorded related to the remeasurement of our deferred tax balance was $12,777,000 income tax benefit.

The Company has a year end of September 30. Because this differs from a normal calendar year end, we have calculated the current year’s federal tax provision using a blended rate of 24.53% to adjust for one quarter of our fiscal year being under the old rate of 35% and the remaining three quarters being under the new rate of 21%. The impact of using a blended rate versus the old rate in the current quarter resulted in a reduced federal tax benefit of $103,035.

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. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that it exceeds cost depletion which is calculated on a unit-of-production basis. Excess tax benefits and deficiencies of stock based compensation will be recognized as income tax expense (benefit) in the statement of operations prospectively versus additional paid in capital in the equity section of the balance sheet as was previously required.

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, 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 detailed well-by-well calculations at fiscal year-end. Federal and Oklahoma excess percentage depletion, when a provision for income taxes is expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock based compensation are not directly related to the amount of pre-tax income (loss) 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 nine months ended June 30, 2018, was an 1138% benefit as compared to a 10% provision for the nine months ended June 30, 2017. The effective tax rate for the quarter ended June 30, 2018, was a 21% benefit as compared to a 31% provision for the quarter ended June 30, 2017.

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Basic And Diluted Earnings (Loss) Per Share

9 Months Ended

Jun. 30, 2018

Earnings Per Share [Abstract]

Basic And Diluted Earnings (Loss) Per Share

NOTE 3: Basic and Diluted Earnings (Loss) per Share

Basic and diluted earnings (loss) per share is calculated using net income (loss) divided by the weighted average number of voting common shares outstanding, including unissued, vested directors’ deferred compensation shares during the period. 

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Long-Term Debt

9 Months Ended

Jun. 30, 2018

Debt Disclosure [Abstract]

Long-Term Debt

NOTE 4: Long-term Debt

The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a current borrowing base of $80,000,000 and a maturity date of November 30, 2022. The credit facility is subject to a semi-annual borrowing base determination, wherein BOK applies their commodity pricing forecast to the Company’s reserve forecast and determines a borrowing base. The facility is secured by certain of the Company’s properties (wellbore only) with a net book value of $138,566,462 at June 30, 2018. The interest rate is based on BOK prime plus from 0.375% to 1.250%, or 30 day LIBOR plus from 1.875% to 2.750%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from BOK prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as the ratio of loan balance to the borrowing base increases. At June 30, 2018, the effective interest rate was 4.20%.

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.

Determinations of the borrowing base are made semi-annually (usually June and December) or whenever the banks, in their discretion, believe that there has been a material change in the value of the oil and natural gas properties. On July 2, 2018, the borrowing base was redetermined by the banks and left unchanged at $80,000,000. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of indebtedness, liens, payment of dividends and acquisitions of stock. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined by the bank agreement – current assets includes availability under outstanding credit facility) of no less than 1.0 to 1.0 and a funded debt to EBITDA (trailing twelve months as defined by the bank agreement – traditional EBITDA with the unrealized gain or loss on derivative contracts also removed from earnings) of no more than 4.0 to 1.0. At June 30, 2018, the Company was in compliance with the covenants of the loan agreement and has $39,600,000 of availability under its outstanding credit facility.

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Deferred Compensation Plan For Non-Employee Directors

9 Months Ended

Jun. 30, 2018

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Deferred Compensation Plan For Non-Employee Directors

NOTE 5: Deferred Compensation Plan for Non-Employee Directors

Annually, non-employee directors may elect to be included in the Deferred Compensation Plan for Non-Employee Directors. The Deferred Compensation Plan for Non-Employee Directors provides that each outside director may individually elect to be credited with future unissued shares of Company common stock rather than cash for all or a portion of the annual retainers, Board meeting fees and committee meeting fees. These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares (i) on the dates of the Board and committee meetings, and (ii) on the payment dates of the annual retainers. Only upon a director’s retirement, termination, death, or a change-in-control of the Company will the shares recorded for such director be issued under the Deferred Compensation Plan for Non-Employee Directors. Directors may elect to receive shares, when issued, over annual time periods up to ten years. The promise to issue such shares in the future is an unsecured obligation of the Company. During 2018, deferred directors’ compensation on the Balance Sheets was reduced $811,219 for shares issued to retired directors. Of the shares issued, 31,838 shares were issued out of treasury and 32,599 shares were newly issued.

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Restricted Stock Plan

9 Months Ended

Jun. 30, 2018

Restricted Stock Plan [Abstract]

Restricted Stock Plan

NOTE 6: Restricted Stock Plan

In March 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 200,000 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. In March 2014, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan from 200,000 shares to 500,000 shares and to allow the grant of shares of restricted stock to our directors. The 2010 Stock Plan, as amended, 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 attract, retain and motivate directors and officers of the Company and to align their interests with those of the Company’s shareholders.

Effective in May 2014, the board of directors adopted resolutions to allow management, at their discretion, to purchase the Company’s common stock as treasury shares up to an amount equal to the aggregate number of shares of common stock awarded pursuant to the Company’s Amended 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.

Effective in May 2018, the board of directors approved an amendment to the Company’s existing stock repurchase program. As amended, the Repurchase Program will continue to allow management to repurchase up to $1.5 million of the Company’s common stock at their discretion. The repurchase of an additional $1.5 million of the Company’s common stock continues to be authorized and approved effective when the previous amount is utilized, and the Board added language to clarify that this is intended to be an evergreen provision. The number of shares allowed to be purchased by the Company under the Repurchase Program is no longer capped at an amount equal to the aggregate number of shares of common stock (i) awarded pursuant to the Company’s Amended 2010 Restricted Stock Plan, (ii) contributed by the Company to its ESOP, and (iii) credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.

On December 12, 2017, the Company awarded 9,700 non-performance based shares and 29,099 performance based shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of a three-year period and contains non-forfeitable rights to receive dividends and voting rights during the vesting period. The non-performance and performance based shares had a fair value on their award date of $203,700 and $330,043, respectively. The fair value for the non-performance and the performance based awards will be recognized as compensation expense ratably over the vesting period. The fair value of the performance based shares on their award date is calculated by simulating the Company’s stock prices as compared to the Dow Jones Select Oil Exploration and Production Index (DJSOEP) prices utilizing a Monte Carlo model covering the performance period (December 12, 2017, through December 12, 2020).

On December 31, 2017, the Company awarded 10,218 non-performance based shares of the Company’s common stock as restricted stock to its non-employee directors. The restricted stock vests quarterly over one year starting on March 31, 2018. The restricted stock contains non-forfeitable rights to receive dividends and voting rights during the vesting period. These non-performance based shares had a fair value on their award date of $209,982.

The following table summarizes the Company’s pre-tax compensation expense for the three and nine months ended June 30, 2018 and 2017, related to the Company’s performance based and non-performance based restricted stock.

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2018		2017		2018		2017
Performance based, restricted stock	$	59,869	$	51,302	$	216,403	$	181,820
Non-performance based, restricted stock		93,919		85,919		285,223		273,034
Total compensation expense	$	153,788	$	137,221	$	501,626	$	454,854

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 June 30, 2018
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	381,258		1.97
Non-performance based, restricted stock		368,585		1.56
Total	$	749,843

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Properties And Equipment

9 Months Ended

Jun. 30, 2018

Property Plant And Equipment [Abstract]

Properties And Equipment

NOTE 7: Properties and Equipment

Divestitures

During the first quarter of 2018, the Company sold 79 non-core marginal wells for $557,750 and recorded a loss on the sales of $272,236. The total net book value that was removed from the Balance Sheets due to these sales was approximately $0.8 million. All of the wells included in the Assets held for sale line item on the Balance Sheets at September 30, 2017, were sold during the first quarter of 2018.

During the second and third quarters of 2018, the Company sold 245 non-core marginal wells for $527,387 and recorded a loss on the sales of $388,361. The total net book value that was removed from the Balance Sheets due to these sales was approximately $0.9 million.

Acquisitions

During the third quarter of 2018, the Company acquired 54 net mineral acres (which include producing oil and gas properties) in the SCOOP play in Grady and Stephens Counties, Oklahoma, with undeveloped locations identified in both the Woodford and Springer Shales for $966,279. This purchase was accounted for as an asset acquisition with $168,006 of the total purchase price allocated to producing oil and natural gas properties and $798,273 allocated to non-producing oil and natural gas properties.

On July 16, 2018, the Company entered into a Purchase and Sale Agreement to acquire certain mineral acreage and producing oil and gas properties, primarily located in the Bakken Shale, from a private seller for total consideration of $9,000,000 cash (pending any closing adjustments). The transaction is expected to close by late August and will have an effective date of June 1, 2018.

Oil, NGL and Natural Gas Reserves

Management considers the estimation of the Company’s crude oil, NGL and natural gas reserves to be the most significant of its judgments and estimates. Changes in crude oil, NGL and natural gas reserve estimates affect the Company’s calculation of DD&A, provision for retirement of assets 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, NGL 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, geologic and geophysical information. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing appropriate prices for the current period. The estimated oil, NGL and natural gas reserves were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil, NGL and natural gas price for each month within the 12-month period prior to the balance sheet date, held flat over the life of the properties. However, projected future crude oil, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions. Crude oil, NGL and natural gas prices are volatile and affected by worldwide production and consumption and are outside the control of management.

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 drilling and completion costs; future sales prices for oil, NGL and natural gas; future production costs; estimates of future oil, NGL and natural 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, NGL and natural gas reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations to reflect any material changes since the prior report was issued and then utilizes updated projected future price decks current with the period. For both the three months ended June 30, 2018 and 2017, the assessment resulted in no impairment provisions on producing properties. For the nine months ended June 30, 2018 and 2017, the assessment resulted in impairment provisions on producing properties of $0 and $10,788, respectively. A significant reduction in oil, NGL and natural gas prices or a decline in reserve volumes may lead to additional impairment in future periods that may be material to the Company.

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Derivatives

9 Months Ended

Jun. 30, 2018

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivatives

NOTE 8: Derivatives

The Company has entered into commodity price derivative agreements including fixed swap contracts and costless collar contracts. These 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. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index 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 currently with Bank of Oklahoma and are secured under its credit facility with Bank of Oklahoma. The derivative instruments have settled or will settle based on the prices below.

Derivative contracts in place as of June 30, 2018

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.30 ceiling
April - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.15 ceiling
Natural gas fixed price swaps
January - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.080
April - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.910
July - December 2018	100,000 Mmbtu	NYMEX Henry Hub	$2.835
July - December 2018	100,000 Mmbtu	NYMEX Henry Hub	$2.925
July - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$2.988
July 2018 - March 2019	50,000 Mmbtu	NYMEX Henry Hub	$3.065
Oil costless collars
January - December 2018	2,000 Bbls	NYMEX WTI	$47.50 floor / $52.50 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$48.00 floor / $53.25 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$50.00 floor / $55.75 ceiling
July - December 2018	3,000 Bbls	NYMEX WTI	$50.00 floor / $58.00 ceiling
January - June 2019	2,000 Bbls	NYMEX WTI	$55.00 floor / $63.45 ceiling
January - December 2019	1,000 Bbls	NYMEX WTI	$50.00 floor / $60.00 ceiling
January - December 2019	2,000 Bbls	NYMEX WTI	$60.00 floor / $69.25 ceiling
Oil fixed price swaps
January - December 2018	3,000 Bbls	NYMEX WTI	$50.72
January - December 2018	2,000 Bbls	NYMEX WTI	$52.02
April - December 2018	4,000 Bbls	NYMEX WTI	$54.14
July - December 2018	2,000 Bbls	NYMEX WTI	$58.20
January - June 2019	2,000 Bbls	NYMEX WTI	$59.69
January - June 2019	2,000 Bbls	NYMEX WTI	$57.15
January - June 2019	3,000 Bbls	NYMEX WTI	$58.02
January - December 2019	1,000 Bbls	NYMEX WTI	$56.15
January - December 2019	2,000 Bbls	NYMEX WTI	$56.71
January - December 2019	1,000 Bbls	NYMEX WTI	$58.56
July - December 2019	2,000 Bbls	NYMEX WTI	$56.85

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 a net liability of $3,303,480 as of June 30, 2018, and a net asset of $516,159 as of September 30, 2017. Net cash paid related to derivative contracts settled during the nine-month period ended June 30, 2018, was $147,230 compared to net cash paid of $221,321 in the same period in the prior year.

The fair value amounts recognized for the Company’s derivative contracts executed with the same counterparty under a master netting arrangement may be offset. The Company has the choice to offset or not, but that choice must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for the derivative contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Balance Sheets.

The following table summarizes and reconciles the Company's derivative contracts’ fair values at a gross level back to net fair value presentation on the Company's Condensed Balance Sheets at June 30, 2018, and September 30, 2017. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at June 30, 2018, and September 30, 2017.

	June 30, 2018												September 30, 2017
	Fair Value (a)												Fair Value (a)
	Commodity Contracts												Commodity Contracts
	Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities			Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities
Gross amounts recognized	$	84,260		$	3,098,771		$	7,943		$	296,912		$	735,702		$	190,778		$	9,439		$	38,204
Offsetting adjustments		(84,260	)		(84,260	)		(7,943	)		(7,943	)		(190,778	)		(190,778	)		(9,439	)		(9,439	)
Net presentation on Condensed Balance Sheets	$	-		$	3,014,511		$	-		$	288,969		$	544,924		$	-		$	-		$	28,765

(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.

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Fair Value Measurements

9 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements

NOTE 9: 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 June 30, 2018.

	Fair Value Measurement at June 30, 2018
	Quoted Prices in Active Markets		Significant Other Observable Inputs			Significant Unobservable Inputs			Total Fair
	(Level 1)		(Level 2)			(Level 3)			Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	(2,190,162	)	$	-		$	(2,190,162	)
Derivative Contracts - Collars	$	-	$	-		$	(1,113,318	)	$	(1,113,318	)

Level 2 – Market Approach - The fair values of the Company’s 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 future prices, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.

Level 3 – The fair values of the Company’s costless 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 future prices, volatility, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.

The significant unobservable inputs for Level 3 derivative contracts include market volatility and credit risk of counterparties. Changes in these inputs will impact the fair value measurement of our derivative contracts. An increase (decrease) in the volatility of oil and natural gas prices will decrease (increase) the fair value of oil and natural gas derivatives and adverse changes to our counterparties’ creditworthiness will decrease the fair value of our derivatives.

The following table represents quantitative disclosures about unobservable inputs for Level 3 Fair Value Measurements.

Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value June 30, 2018
Oil Collars	Oil price volatility curve	0% - 31.24%	17.16%	$	(1,119,628	)
Natural Gas Collars	Gas price volatility curve	0% - 16.25%	9.08%	$	6,310

A reconciliation of the Company’s derivative contracts 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 Condensed Statements of Operations.

	Derivatives
Balance of Level 3 as of October 1, 2017	$	151,553
Total gains or (losses)
Included in earnings		(1,255,605	)
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		(9,266	)
Transfers in and out of Level 3		-
Balance of Level 3 as of June 30, 2018	$	(1,113,318	)

 At June 30, 2018, and September 30, 2017, the fair value of financial instruments approximated their carrying amounts. Financial instruments include long-term debt, which the valuation is classified as Level 2 as the carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.

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Basis of Presentation and Accounting Principles (Policies)

9 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

Basis Of Presentation

Basis of Presentation

The accompanying unaudited condensed financial statements of Panhandle Oil and Gas Inc. have been prepared in accordance with the instructions to Form 10-Q as prescribed by the 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 2017 Annual Report on Form 10-K.

Adoption of New Accounting Pronouncements

Adoption of New Accounting Pronouncements

In January 2017, the FASB issued ASU 2017-01, which changed the definition of a business. The new guidance requires an entity to first evaluate whether substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets. If that threshold is met, the set of assets and activities is not a business. If it’s not met, the entity evaluates whether the set meets the definition of a business. The new definition requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue recognition guidance. The new guidance is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. The ASU will be applied prospectively to any transactions occurring within the period of adoption. Early adoption is permitted, including for interim or annual periods for which the financial statements have not been issued or made available for issuance. The Company early adopted ASU 2017-01 during the quarter ended June 30, 2018.

New Accounting Pronouncements Yet To Be Adopted

New Accounting Pronouncements yet to be Adopted

In February 2016, the FASB issued its new lease accounting guidance in ASU 2016-02, Leases (Topic 842). Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date: 1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and 2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new lease guidance simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. Lessees will no longer be provided with a source of off-balance sheet financing. The guidance is effective for us beginning October 1, 2019, including interim periods within the fiscal year. Early application is permitted for all public business entities upon issuance. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. We are assessing the potential impact that this standard will have on our financial statements.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The new guidance is intended to improve the recognition and measurement of financial instruments. The new guidance is effective for us beginning October 1, 2018, including interim periods within the fiscal year. This update is not expected to have a material impact on our financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which will supersede nearly all existing revenue recognition guidance under GAAP. The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. We are evaluating our existing revenue recognition policies to determine whether any contracts in the scope of the guidance will be affected by the new requirements.

Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis.

The standard is effective for us beginning October 1, 2018. The standard allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements and utilizes a cumulative effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. Panhandle intends to use the modified retrospective method upon adoption.

The Company is nearing completion of its evaluation of the impact of the new standard and related interpretive guidance on its financial statements, accounting policies, internal controls, and disclosures. Based on assessments performed to date, the standard is not expected to have a material effect on the timing or measurement of the Company's revenue recognition or its financial position, results of operations, net income, or cash flows, but is expected to have an impact on the Company's revenue-related disclosures and internal controls over financial reporting.

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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Restricted Stock Plan (Tables)

9 Months Ended

Jun. 30, 2018

Restricted Stock Plan [Abstract]

Summary Of Pre-Tax Compensation Expense

The following table summarizes the Company’s pre-tax compensation expense for the three and nine months ended June 30, 2018 and 2017, related to the Company’s performance based and non-performance based restricted stock.

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2018		2017		2018		2017
Performance based, restricted stock	$	59,869	$	51,302	$	216,403	$	181,820
Non-performance based, restricted stock		93,919		85,919		285,223		273,034
Total compensation expense	$	153,788	$	137,221	$	501,626	$	454,854

Summary Of Unrecognized Compensation Cost

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 June 30, 2018
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	381,258		1.97
Non-performance based, restricted stock		368,585		1.56
Total	$	749,843

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Derivatives (Tables)

9 Months Ended

Jun. 30, 2018

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Summary Of Derivative Instruments Contracts

Derivative contracts in place as of June 30, 2018

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.30 ceiling
April - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.15 ceiling
Natural gas fixed price swaps
January - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.080
April - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.910
July - December 2018	100,000 Mmbtu	NYMEX Henry Hub	$2.835
July - December 2018	100,000 Mmbtu	NYMEX Henry Hub	$2.925
July - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$2.988
July 2018 - March 2019	50,000 Mmbtu	NYMEX Henry Hub	$3.065
Oil costless collars
January - December 2018	2,000 Bbls	NYMEX WTI	$47.50 floor / $52.50 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$48.00 floor / $53.25 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$50.00 floor / $55.75 ceiling
July - December 2018	3,000 Bbls	NYMEX WTI	$50.00 floor / $58.00 ceiling
January - June 2019	2,000 Bbls	NYMEX WTI	$55.00 floor / $63.45 ceiling
January - December 2019	1,000 Bbls	NYMEX WTI	$50.00 floor / $60.00 ceiling
January - December 2019	2,000 Bbls	NYMEX WTI	$60.00 floor / $69.25 ceiling
Oil fixed price swaps
January - December 2018	3,000 Bbls	NYMEX WTI	$50.72
January - December 2018	2,000 Bbls	NYMEX WTI	$52.02
April - December 2018	4,000 Bbls	NYMEX WTI	$54.14
July - December 2018	2,000 Bbls	NYMEX WTI	$58.20
January - June 2019	2,000 Bbls	NYMEX WTI	$59.69
January - June 2019	2,000 Bbls	NYMEX WTI	$57.15
January - June 2019	3,000 Bbls	NYMEX WTI	$58.02
January - December 2019	1,000 Bbls	NYMEX WTI	$56.15
January - December 2019	2,000 Bbls	NYMEX WTI	$56.71
January - December 2019	1,000 Bbls	NYMEX WTI	$58.56
July - December 2019	2,000 Bbls	NYMEX WTI	$56.85

Summary Of Derivative Contracts

	June 30, 2018												September 30, 2017
	Fair Value (a)												Fair Value (a)
	Commodity Contracts												Commodity Contracts
	Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities			Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities
Gross amounts recognized	$	84,260		$	3,098,771		$	7,943		$	296,912		$	735,702		$	190,778		$	9,439		$	38,204
Offsetting adjustments		(84,260	)		(84,260	)		(7,943	)		(7,943	)		(190,778	)		(190,778	)		(9,439	)		(9,439	)
Net presentation on Condensed Balance Sheets	$	-		$	3,014,511		$	-		$	288,969		$	544,924		$	-		$	-		$	28,765

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

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Fair Value Measurements (Tables)

9 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

Summary Of Fair Value Measurement Information For Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis

	Fair Value Measurement at June 30, 2018
	Quoted Prices in Active Markets		Significant Other Observable Inputs			Significant Unobservable Inputs			Total Fair
	(Level 1)		(Level 2)			(Level 3)			Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	(2,190,162	)	$	-		$	(2,190,162	)
Derivative Contracts - Collars	$	-	$	-		$	(1,113,318	)	$	(1,113,318	)

Summary Of Unobservable Inputs For Level 3 Fair Value Measurements

Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value June 30, 2018
Oil Collars	Oil price volatility curve	0% - 31.24%	17.16%	$	(1,119,628	)
Natural Gas Collars	Gas price volatility curve	0% - 16.25%	9.08%	$	6,310

Summary Of Reconciliation Of Derivative Contracts Classified As Level 3 Measurements

	Derivatives
Balance of Level 3 as of October 1, 2017	$	151,553
Total gains or (losses)
Included in earnings		(1,255,605	)
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		(9,266	)
Transfers in and out of Level 3		-
Balance of Level 3 as of June 30, 2018	$	(1,113,318	)

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Income Taxes (Details) - USD ($)	3 Months Ended			9 Months Ended			12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017	Sep. 30, 2018	Jun. 30, 2018	Jun. 30, 2017	Sep. 30, 2018
Income Tax Contingency [Line Items]
Provisional amount, remeasurement of deferred income tax benefit					$ 12,777,000
US federal corporate tax rate		35.00%
Federal tax benefit resulting from the use of blend rate versus old rate	$ 103,035
Effective tax rate	(21.00%)		31.00%		(1138.00%)	10.00%
Scenario, Forecast [Member]
Income Tax Contingency [Line Items]
US federal corporate tax rate				21.00%			24.53%

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Long-Term Debt (Details) - Revolving Credit Facility [Member] - USD ($)	9 Months Ended
	Jun. 30, 2018	Jul. 02, 2018
Line Of Credit Facility [Line Items]
Revolving loan credit facility	$ 200,000,000
Borrowing base of credit facility	$ 80,000,000
Credit facility maturity	Nov. 30, 2022
Properties net book value	$ 138,566,462
Effective Interest rate	4.20%
Funded debt to EBITDA ratio	400.00%
Availability under outstanding credit facility	$ 39,600,000
Subsequent Event [Member]
Line Of Credit Facility [Line Items]
Borrowing base of credit facility		$ 80,000,000
Minimum [Member]
Line Of Credit Facility [Line Items]
Current ratio	100.00%
Minimum [Member] | Prime Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	0.375%
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	1.875%
Maximum [Member] | Prime Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	1.25%
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	2.75%

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Deferred Compensation Plan For Non-Employee Directors (Details)	9 Months Ended
	Jun. 30, 2018 USD ($) shares
Deferred Compensation Plan For Directors [Line Items]
Shares issued out of treasury	31,838
Maximum [Member]
Deferred Compensation Plan For Directors [Line Items]
Period outside directors may elect to receive shares	10 years
Director [Member]
Deferred Compensation Plan For Directors [Line Items]
Decrease in deferred compensation | $	$ (811,219)
Class A Common Stock [Member]
Deferred Compensation Plan For Directors [Line Items]
New shares issued	32,599

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Restricted Stock Plan (Narrative) (Details) - USD ($)			9 Months Ended
	Dec. 31, 2017	Dec. 12, 2017	Jun. 30, 2018	May 31, 2018	Mar. 31, 2014	Mar. 31, 2010
Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock vesting period			3 years
Non Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock vesting period			1 year
Non Performance Based Restricted Stock [Member] | Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded		9,700
Fair value of shares awarded		$ 203,700
Non Performance Based Restricted Stock [Member] | Non Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded	10,218
Fair value of shares awarded	$ 209,982
Performance Based Restricted Stock [Member] | Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded		29,099
Fair value of shares awarded		$ 330,043
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Repurchase of common stock authorized				$ 1,500,000
2010 Stock Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock authorized					500,000	200,000

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Restricted Stock Plan (Summary Of Pre-Tax Compensation Expense) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 153,788	$ 137,221	$ 501,626	$ 454,854
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	59,869	51,302	216,403	181,820
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 93,919	$ 85,919	$ 285,223	$ 273,034

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Restricted Stock Plan (Summary Of Unrecognized Compensation Cost) (Details)	9 Months Ended
	Jun. 30, 2018 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 749,843
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 381,258
Weighted Average Period (in years)	1 year 11 months 19 days
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 368,585
Weighted Average Period (in years)	1 year 6 months 21 days

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Properties And Equipment (Details)		3 Months Ended			6 Months Ended	9 Months Ended
	Jul. 16, 2018 USD ($)	Jun. 30, 2018 USD ($) a	Dec. 31, 2017 USD ($) Item	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) Item	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)
Property Plant And Equipment [Line Items]
Number of non-core marginal wells sold | Item			79		245
Proceeds from sales of assets			$ 557,750		$ 527,387	$ 1,085,137	$ 718,700
Loss on sale of assets			272,236		388,361	$ 660,597	87,161
Decrease in gross asset value on balance sheets due to sales of non-core marginal wells			$ 800,000		$ 900,000
Computation of Oil, Natural Gas and NGL Reserves						12 months
Impairment		$ 0		$ 0		$ 0	$ 10,788
Grady and Stephens Counties, Oklahoma [Member]
Property Plant And Equipment [Line Items]
Mineral acreage acquired | a		54
Purchase price of mineral acreage acquired		$ 966,279
Grady and Stephens Counties, Oklahoma [Member] | Producing Oil and Natural Gas Properties [Member]
Property Plant And Equipment [Line Items]
Purchase price of mineral acreage acquired		168,006
Grady and Stephens Counties, Oklahoma [Member] | Non-Producing Oil and Natural Gas Properties [Member]
Property Plant And Equipment [Line Items]
Purchase price of mineral acreage acquired		$ 798,273
Bakken Shale, North Dakota [Member] | Subsequent Event [Member]
Property Plant And Equipment [Line Items]
Purchase price of mineral acreage acquired	$ 9,000,000

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Derivatives (Summary Of Derivative Instruments Contracts) (Details)	Jun. 30, 2018 MMBTU $ / MMBTU $ / bbl bbl
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	40,000
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU	2.75
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU	3.35
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	40,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU	2.75
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU	3.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU	2.80
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU	3.15
Natural Gas Fixed Price Swaps | Derivative Contract Period Four [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000
Contract price | $ / MMBTU	3.080
Natural Gas Fixed Price Swaps | Derivative Contract Period Five [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	40,000
Contract price | $ / MMBTU	2.910
Natural Gas Fixed Price Swaps | Derivative Contract Period Six [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price | $ / MMBTU	2.835
Natural Gas Fixed Price Swaps | Derivative Contract Period Seven [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price | $ / MMBTU	2.925
Natural Gas Fixed Price Swaps | Derivative Contract Period Eight [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000
Contract price | $ / MMBTU	2.988
Natural Gas Fixed Price Swaps | Derivative Contract Period Nine [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000
Contract price | $ / MMBTU	3.065
Oil Costless Collars [Member] | Derivative Contract Period Ten [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Ten [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	47.50
Oil Costless Collars [Member] | Derivative Contract Period Ten [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	52.50
Oil Costless Collars [Member] | Derivative Contract Period Eleven [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	48.00
Oil Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	53.25
Oil Costless Collars [Member] | Derivative Contract Period Twelve [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Twelve [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	50.00
Oil Costless Collars [Member] | Derivative Contract Period Twelve [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	55.75
Oil Costless Collars [Member] | Derivative Contract Period Thirteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	3,000
Oil Costless Collars [Member] | Derivative Contract Period Thirteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	50.00
Oil Costless Collars [Member] | Derivative Contract Period Thirteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	58.00
Oil Costless Collars [Member] | Derivative Contract Period Fourteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Fourteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	55.00
Oil Costless Collars [Member] | Derivative Contract Period Fourteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	63.45
Oil Costless Collars [Member] | Derivative Contract Period Fifteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	1,000
Oil Costless Collars [Member] | Derivative Contract Period Fifteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	50.00
Oil Costless Collars [Member] | Derivative Contract Period Fifteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	60.00
Oil Costless Collars [Member] | Derivative Contract Period Sixteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Sixteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	60.00
Oil Costless Collars [Member] | Derivative Contract Period Sixteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	69.25
Oil Fixed Price Swaps [Member] | Derivative Contract Period Seventeen [Member]
Derivative [Line Items]
Contract price	50.72
Production volume covered per month - Oil | bbl	3,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Eighteen [Member]
Derivative [Line Items]
Contract price	52.02
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Nineteen [Member]
Derivative [Line Items]
Contract price	54.14
Production volume covered per month - Oil | bbl	4,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty [Member]
Derivative [Line Items]
Contract price	58.20
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty One [Member]
Derivative [Line Items]
Contract price	59.69
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Two [Member]
Derivative [Line Items]
Contract price	57.15
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Three [Member]
Derivative [Line Items]
Contract price	58.02
Production volume covered per month - Oil | bbl	3,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Four [Member]
Derivative [Line Items]
Contract price	56.15
Production volume covered per month - Oil | bbl	1,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Five [Member]
Derivative [Line Items]
Contract price	56.71
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Six [Member]
Derivative [Line Items]
Contract price	58.56
Production volume covered per month - Oil | bbl	1,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Seven [Member]
Derivative [Line Items]
Contract price	56.85
Production volume covered per month - Oil | bbl	2,000

XML

Derivatives (Narrative) (Details) - USD ($)	9 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Sep. 30, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Fair value of derivative contracts, liability	$ 3,303,480
Fair value of derivative contracts, asset			$ 516,159
Net cash paid related to derivative contracts settled	$ 147,230	$ 221,321

XML

Derivatives (Summary Of Derivative Contracts) (Details) - USD ($)		Jun. 30, 2018	Sep. 30, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gross amounts recognized - Current Assets	[1]	$ 84,260	$ 735,702
Offsetting adjustments - Current Assets	[1]	(84,260)	(190,778)
Net presentation on Condensed Balance Sheets - Current Assets	[1]		544,924
Gross amounts recognized - Current Liabilities	[1]	3,098,771	190,778
Offsetting adjustments - Current Liabilities	[1]	(84,260)	(190,778)
Net presentation on Condensed Balance Sheets - Current Liabilities	[1]	3,014,511
Gross amounts recognized - Non-Current Assets	[1]	7,943	9,439
Offsetting adjustments - Non-Current Assets	[1]	(7,943)	(9,439)
Gross amounts recognized - Non-Current Liabilities	[1]	296,912	38,204
Offsetting adjustments - Non-Current Liabilities	[1]	(7,943)	(9,439)
Net presentation on Condensed Balance Sheets - Non-Current Liabilities	[1]	$ 288,969	$ 28,765

[1] See Fair Value Measurements section for further disclosures regarding fair value of financial instruments.

XML

Fair Value Measurements (Summary Of Fair Value Measurement Information For Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details)	Jun. 30, 2018 USD ($)
Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	$ (2,190,162)
Swap [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	(2,190,162)
Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	(1,113,318)
Collars [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	$ (1,113,318)

XML

Fair Value Measurements (Summary Of Unobservable Inputs For Level 3 Fair Value Measurements) (Details)	9 Months Ended
	Jun. 30, 2018 USD ($)
Oil Costless Collars [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Unobservable Input	Oil price volatility curve
Fair Value Assets (Liabilities)	$ (1,119,628)
Oil Costless Collars [Member] | Valuation Technique, Option Pricing Model [Member] | Measurement Input, Price Volatility [Member] | Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Alternative Investment, Measurement Input	0
Oil Costless Collars [Member] | Valuation Technique, Option Pricing Model [Member] | Measurement Input, Price Volatility [Member] | Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Alternative Investment, Measurement Input	31.24
Oil Costless Collars [Member] | Valuation Technique, Option Pricing Model [Member] | Measurement Input, Price Volatility [Member] | Weighted Average [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Alternative Investment, Measurement Input	17.16
Natural Gas Costless Collars [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Unobservable Input	Gas price volatility curve
Fair Value Assets (Liabilities)	$ 6,310
Natural Gas Costless Collars [Member] | Valuation Technique, Option Pricing Model [Member] | Measurement Input, Price Volatility [Member] | Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Alternative Investment, Measurement Input	0
Natural Gas Costless Collars [Member] | Valuation Technique, Option Pricing Model [Member] | Measurement Input, Price Volatility [Member] | Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Alternative Investment, Measurement Input	16.25
Natural Gas Costless Collars [Member] | Valuation Technique, Option Pricing Model [Member] | Measurement Input, Price Volatility [Member] | Weighted Average [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Alternative Investment, Measurement Input	9.08

XML

Fair Value Measurements (Summary Of Reconciliation Of Derivative Contracts Classified As Level 3 Measurements) (Details)	9 Months Ended
	Jun. 30, 2018 USD ($)
Fair Value Disclosures [Abstract]
Balance of Level 3 as of October 1, 2017	$ 151,553
Total gains or (losses) included in earnings	(1,255,605)
Purchases, issuances and settlements	(9,266)
Balance of Level 3 as of June 30, 2018	$ (1,113,318)