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, 2019

☐ 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

Securities registered pursuant in Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class A Common Stock, $0.0166 par value	PHX	New York Stock Exchange

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 8, 2019: 16,388,724

INDEX

Part I	Financial Information		Page
	Item 1	Condensed Financial Statements	1
		Condensed Balance Sheets – June 30, 2019, and September 30, 2018	1
		Condensed Statements of Operations – Three and nine months ended June 30, 2019 and 2018	2
		Statements of Stockholders’ Equity – Nine months ended June 30, 2019 and 2018	3
		Condensed Statements of Cash Flows – Nine months ended June 30, 2019 and 2018	5
		Notes to Condensed Financial Statements	6
	Item 2	Management's discussion and analysis of financial condition and results of operations	14
	Item 3	Quantitative and qualitative disclosures about market risk	20
	Item 4	Controls and procedures	20
Part II	Other Information
	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	21
	Item 6	Exhibits	21
	Signatures		22

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.

“GAAP” generally accepted accounting principles.

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

“held by production” or “HBP” an oil and natural gas lease continued into effect into its secondary term for so long as a producing oil and/or natural 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.

“NRI” net revenue interest.

“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 2019 mean the fiscal year ended September 30, 2019.

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, 2019			September 30, 2018
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	1,530,477		$	532,502
Oil, NGL and natural gas sales receivables (net of allowance for uncollectable accounts)		5,503,962			7,101,629
Refundable income taxes		510,011			33,165
Derivative contracts, net		2,489,373			-
Other		1,438,138			578,880
Total current assets		11,471,961			8,246,176
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties		435,425,936			427,448,584
Non-producing oil and natural gas properties		12,518,885			12,563,519
Other		1,717,769			1,529,770
		449,662,590			441,541,873
Less accumulated depreciation, depletion and amortization		(254,954,381	)		(243,257,472	)
Net properties and equipment		194,708,209			198,284,401
Investments		207,225			219,109
Derivative contracts, net		222,136			-
Total assets	$	206,609,531		$	206,749,686
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	563,642		$	881,130
Derivative contracts, net		-			3,064,046
Accrued liabilities and other		1,880,199			1,791,950
Total current liabilities		2,443,841			5,737,126
Long-term debt		41,500,000			51,000,000
Deferred income taxes, net		23,238,007			18,088,007
Asset retirement obligations		2,927,487			2,809,378
Derivative contracts, net		-			349,970
Stockholders' equity:
Class A voting common stock, $0.0166 par value; 24,000,000 shares authorized,    16,897,306 issued at June 30, 2019, and 16,896,881 issued at September 30, 2018		281,509			281,502
Capital in excess of par value		2,937,874			2,824,691
Deferred directors' compensation		2,481,109			2,950,405
Retained earnings		138,662,782			125,266,945
		144,363,274			131,323,543
Less treasury stock, at cost; 508,582 shares at June 30, 2019, and 145,467 shares    at September 30, 2018		(7,863,078	)		(2,558,338	)
Total stockholders' equity		136,500,196			128,765,205
Total liabilities and stockholders' equity	$	206,609,531		$	206,749,686

(See accompanying notes)

(1)

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF OPERATIONS

	Three Months Ended June 30,					Nine Months Ended June 30,
	2019		2018			2019		2018
Revenues:	(unaudited)					(unaudited)
Oil, NGL and natural gas sales	$	9,782,337	$	11,202,680		$	31,214,375	$	36,356,135
Lease bonuses and rental income		229,075		484,298			952,378		1,080,455
Gains (losses) on derivative contracts		2,313,195		(2,129,041	)		5,026,123		(3,966,869	)
Gain on asset sales		4,017,787		-			13,114,725		-
		16,342,394		9,557,937			50,307,601		33,469,721
Costs and expenses:
Lease operating expenses		3,148,960		3,233,172			9,241,708		10,077,449
Production taxes		488,779		485,157			1,565,038		1,471,970
Depreciation, depletion and amortization		4,383,043		4,619,509			11,820,705		14,136,411
Interest expense		526,677		420,896			1,551,831		1,288,426
General and administrative		1,809,439		1,593,251			5,881,432		5,247,584
Loss on asset sales and other expense (income)		66,260		190,045			82,045		110,859
		10,423,158		10,542,030			30,142,759		32,332,699
Income (loss) before provision (benefit) for income taxes		5,919,236		(984,093	)		20,164,842		1,137,022
Provision (benefit) for income taxes		1,315,000		(209,000	)		4,756,000		(12,943,000	)
Net income (loss)	$	4,604,236	$	(775,093	)	$	15,408,842	$	14,080,022
Basic and diluted earnings (loss) per common share (Note 4)	$	0.28	$	(0.05	)	$	0.92	$	0.83
Basic and diluted weighted average shares outstanding:
Common shares		16,515,498		16,775,981			16,646,828		16,742,044
Unissued, directors' deferred compensation shares		170,066		206,202			183,206		205,867
		16,685,564		16,982,183			16,830,034		16,947,911
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, 2019

	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, 2018		16,896,881	$	281,502	$	2,824,691		$	2,950,405		$	125,266,945			(145,467	)	$	(2,558,338	)	$	128,765,205
Net income (loss)		-		-		-			-			12,735,940			-			-			12,735,940
Purchase of treasury stock		-		-		-			-			-			(74,457	)		(1,140,559	)		(1,140,559	)
Restricted stock awards		-		-		159,469			-						-			-			159,469
Dividends ($0.08 per share)		-		-		-			-			(1,347,789	)		-			-			(1,347,789	)
Distribution of restricted stock    to officers and directors		425		7		(159,869	)		-			-			9,194			160,022			160
Distribution of deferred    directors' compensation		-		-		(8	)		8			-			-			-			-
Increase in deferred directors'    compensation charged to    expense		-		-		-			80,287			-			-			-			80,287
Balances at December 31, 2018		16,897,306	$	281,509	$	2,824,283		$	3,030,700		$	136,655,096			(210,730	)	$	(3,538,875	)	$	139,252,713
Net income (loss)		-		-		-			-			(1,931,334	)		-			-			(1,931,334	)
Purchase of treasury stock		-		-		-			-			-			(175,175	)		(2,827,126	)		(2,827,126	)
Restricted stock awards		-		-		286,852			-						-			-			286,852
Dividends		-		-		-			-			(381	)		-			-			(381	)
Distribution of restricted stock    to officers and directors		-		-		(73,069	)		-			-			4,441			73,144			75
Distribution of deferred    directors' compensation		-		-		(207,842	)		(667,124	)		-			52,399			874,963			(3	)
Increase in deferred directors'    compensation charged to    expense		-		-		-			51,993			-			-			-			51,993
Balances at March 31, 2019		16,897,306	$	281,509	$	2,830,224		$	2,415,569		$	134,723,381			(329,065	)	$	(5,417,894	)	$	134,832,789
Net income (loss)		-		-		-			-			4,604,236			-			-			4,604,236
Purchase of treasury stock		-		-		-			-			-			(182,901	)		(2,497,501	)		(2,497,501	)
Restricted stock awards		-		-		159,911			-						-			-			159,911
Dividends ($0.04 per share)		-		-		-			-			(664,835	)		-			-			(664,835	)
Distribution of restricted stock    to officers and directors		-		-		(52,261	)		-			-			3,384			52,317			56
Increase in deferred directors'    compensation charged to    expense		-		-		-			65,540			-			-			-			65,540
Balances at June 30, 2019		16,897,306	$	281,509	$	2,937,874		$	2,481,109		$	138,662,782			(508,582	)	$	(7,863,078	)	$	136,500,196
(unaudited)

(See accompanying notes)

(3)

PANHANDLE OIL AND GAS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY (continued)

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)		-		-		-			-			13,784,939			-			-			13,784,939
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		-		-		194,050			-			-			-			-			194,050
Dividends ($0.08 per share)		-		-		-			-			(1,347,608	)		-			-			(1,347,608	)
Distribution of restricted stock    to officers and directors		-		-		(735,965	)		-			-			44,065			736,699			734
Increase in deferred directors'    compensation charged to    expense		-		-		-			108,384			-			-			-			108,384
Balances at December 31, 2017		16,863,004	$	280,938	$	2,186,538		$	3,568,293		$	125,767,547			(154,044	)	$	(2,620,643	)	$	129,182,673
Net income (loss)		-		-		-			-			1,070,176			-			-			1,070,176
Restricted stock awards		-		-		153,788			-			-			-			-			153,788
Distribution of restricted stock    to officers and directors		-		-		(43,435	)		-			-			2,556			43,478			43
Distribution of deferred    directors' compensation		32,599		543		269,112			(811,219	)		-			31,838			541,564			-
Increase in deferred directors'    compensation charged to    expense		-		-		-			62,442			-			-			-			62,442
Balances at March 31, 2018		16,895,603	$	281,481	$	2,566,003		$	2,819,516		$	126,837,723			(119,650	)	$	(2,035,601	)	$	130,469,122
Net income (loss)		-		-		-			-			(775,093	)		-			-			(775,093	)
Restricted stock awards		-		-		153,788			-			-			-			-			153,788
Dividends ($0.04 per share)		-		-		-			-			(675,892	)		-			-			(675,892	)
Distribution of restricted stock    to officers and directors		852		14		(28,957	)		-			-			1,704			28,985			42
Increase in deferred directors'    compensation charged to    expense		-		-		-			62,747			-			-			-			62,747
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)

(See accompanying notes)

(4)

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF CASH FLOWS

	Nine months ended June 30,
	2019			2018
Operating Activities	(unaudited)
Net income (loss)	$	15,408,842		$	14,080,022
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		11,820,705			14,136,411
Provision for deferred income taxes		5,150,000			(12,947,000	)
Gain from leasing fee mineral acreage		(951,832	)		(1,079,803	)
Proceeds from leasing fee mineral acreage		967,337			1,102,818
Net (gain) loss on sales of assets		(13,114,725	)		660,597
Directors' deferred compensation expense		197,820			233,573
Fair value of derivative contracts		(6,125,525	)		3,819,639
Restricted stock awards		606,232			501,626
Other		15,848			5,113
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables		1,597,667			1,095,996
Other current assets		(859,258	)		77,124
Accounts payable		3,270			(125,261	)
Income taxes receivable		(476,846	)		279,975
Other non-current assets		6,949			(52,644	)
Accrued liabilities		86,467			(130,284	)
Total adjustments		(1,075,891	)		7,577,880
Net cash provided by operating activities		14,332,951			21,657,902
Investing Activities
Capital expenditures		(3,349,640	)		(7,743,097	)
Acquisition of minerals and overrides		(5,120,466	)		(966,279	)
Investments in partnerships		(1,648	)		3,379
Proceeds from sales of assets		13,114,969			1,085,137
Net cash provided (used) by investing activities		4,643,215			(7,620,860	)
Financing Activities
Borrowings under debt agreement		15,053,345			13,529,879
Payments of loan principal		(24,553,345	)		(25,352,099	)
Purchases of treasury stock		(6,465,186	)		(272,100	)
Payments of dividends		(2,013,005	)		(2,023,500	)
Net cash provided (used) by financing activities		(17,978,191	)		(14,117,820	)
Increase (decrease) in cash and cash equivalents		997,975			(80,778	)
Cash and cash equivalents at beginning of period		532,502			557,791
Cash and cash equivalents at end of period	$	1,530,477		$	477,013
Supplemental Schedule of Noncash Investing and Financing Activities:
Additions to asset retirement obligations	$	27,782		$	15,452
Gross additions to properties and equipment	$	8,149,347		$	8,150,830
Net (increase) decrease in accounts payable for properties and equipment additions		320,759			558,546
Capital expenditures and acquisitions	$	8,470,106		$	8,709,376

(See accompanying notes)

(5)

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 2018 Annual Report on Form 10-K.

Certain amounts (loss (gain) on asset sales and other in the Statements of Operations) in the prior years have been reclassified to conform to the current year presentation.

Adoption of New Accounting Pronouncements

Revenue recognition and presentation – In May 2014, the FASB issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes nearly all previously existing revenue recognition guidance under U.S. GAAP. Subsequently, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This new guidance became effective for reporting periods beginning after December 15, 2017. The Company adopted the new revenue recognition and presentation guidance on October 1, 2018, as required. See Note 2: Revenues for discussion of the adoption impact and the applicable disclosures required by the new guidance.

New Accounting Pronouncements yet to be Adopted

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which will supersede the lease requirements in Topic 840, Leases by requiring lessees to recognize lease assets and lease liabilities classified as operating leases on the balance sheet. The new lease standard will be effective for us beginning October 1, 2019, including interim periods within the fiscal year.

The FASB recently issued ASU 2018-11, Leases (Topic 842), Targeted Improvements, which would allow entities to apply the transition provisions of the new standard at the adoption date instead of at the earliest comparative period presented in the consolidated financial statements, and will also allow entities to continue to apply the legacy guidance in Topic 840, including disclosure requirements, in the comparative period presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if any, rather than in the earliest period presented. The Company plans to use a modified retrospective transition method to apply the new standard to leases that exist as of the adoption date of October 1, 2019. The Company does not plan to early adopt.

Based on evaluations to-date, the new guidance will not have a material impact on the Company's consolidated financial statements and related disclosures as this guidance does not apply to leases to explore for or use minerals, oil, natural gas, and similar resources. The Company also plans to elect a policy to not recognize right-of-use assets and lease liabilities related to short-term leases.

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.

(6)

NOTE 2: Revenues

Adoption of new revenue recognition and disclosure guidance

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition.

Subsequent to the issuance of ASU 2014-09, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. This guidance requires an entity to record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer.

The Company adopted the new revenue recognition and presentation guidance on 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. The Company chose to use the modified retrospective method upon adoption and has applied the guidance only to contracts that are not complete at the date of initial application. Adoption of the new guidance had no cumulative effect impact on the Company's retained earnings at October 1, 2018.

The standard did not have a material effect on the timing or measurement of the Company's revenue recognition or its financial position, results of operations, net income and cash flows. Additionally, the application of ASU 2016-08’s gross versus net presentation guidance did not impact the Company’s presentation of revenues and expenses. As the Company’s interests in oil and natural gas properties are non-operated interests or royalty interests, the Company evaluated its agreements with operators in connection with the ASC 606 principal versus agent indicators. Consistent with previous conclusions under ASC 605, the Company concluded that the operators act as an agent in the transfer of commodities to third-party customers. This determination required judgment in the application of the guidance for principal versus agent under ASC 606.

Revenues from Contracts with Customers

Oil, NGL and natural gas sales

Sales of oil, NGL and natural gas are recognized at the point in time that control of the product is transferred to the customer and collectability of the sales price is reasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Company receives for natural gas and NGL is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. Each unit of commodity is considered a separate performance obligation, however, as consideration is variable, the Company utilizes the variable consideration allocation exception permitted under the standard to allocate the variable consideration to the specific units of commodity to which they relate.

Lease bonus income

The Company also earns revenue from lease bonuses. The Company generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any oil, NGL or natural gas discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances in accordance with the guidance set forth in ASC 932, and it recognizes the lease bonus as a cost recovery with any excess above its cost basis in the mineral being treated as a gain. The excess of lease bonus above the mineral basis is shown in the lease bonuses and rental income line item on the Company’s Statements of Operations.

Oil and natural gas derivative contracts – See Note 9 for discussion of the Company’s accounting for derivative contracts.

(7)

Disaggregation of oil, NGL and natural gas revenues

The following table presents the disaggregation of the Company's oil, NGL and natural gas revenues for the three and nine months ended June 30, 2019.

	Three Months Ended		Nine Months Ended
	June 30, 2019		June 30, 2019
Oil revenue	$	5,523,467	$	13,932,052
NGL revenue		826,282		3,097,479
Natural gas revenue		3,432,588		14,184,844
Oil, NGL and natural gas sales	$	9,782,337	$	31,214,375

Performance obligations

The Company satisfies the performance obligations under its oil and natural gas sales contracts upon delivery of its production and related transfer of title to purchasers. Upon delivery of production, the Company has a right to receive consideration from its purchasers in amounts that correspond with the value of the production transferred.

Allocation of transaction price to remaining performance obligations

Oil, NGL and natural gas sales

As the Company has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company has utilized the practical expedient in ASC 606 which permits the Company to allocate variable consideration to one or more but not all performance obligations in the contract if the terms of the variable payment relate specifically to the Company’s efforts to satisfy that performance obligation and allocating the variable amount to the performance obligation is consistent with the allocation objective under ASC 606. Additionally, the Company will not disclose variable consideration subject to this practical expedient.

Prior-period performance obligations and contract balances

The Company records revenue in the month production is delivered to the purchaser. As a non-operator, the Company has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Oil, NGL and natural gas sales receivables line item in the accompanying balance sheets. The difference between the Company's estimates and the actual amounts received for oil, NGL and natural gas sales is recorded in the quarter that payment is received from the third party. For the three and nine months ended June 30, 2019, and June 30, 2018, revenue recognized in these reporting periods related to performance obligations satisfied in prior reporting periods was immaterial and considered a change in estimate.

NOTE 3: Income Taxes

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from 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 are recognized as provision (benefit) for income taxes in the statements of operations.

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,

(8)

2019, was a 24%provision as compared to a 1138% benefit for the nine months ended June 30, 2018. The effective tax rate for the quarter ended June 30, 2019, was a 22%provision as compared to a 21%benefit for the quarter ended June 30, 2018.

NOTE 4: Basic and Diluted Earnings (Loss) per Common Share

Basic and diluted earnings (loss) per common 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 5: 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 $70,000,000 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 $128,427,806 at June 30, 2019. The interest rate is based on BOK prime plus from 0.50% to 1.25%, or 30-day LIBOR plus from 2.00% to 2.75%. 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, 2019, the effective interest rate was 4.76%.

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 August 6, 2019, the borrowing base was redetermined by the banks and reduced from $80,000,000 to $70,000,000. 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, 2019, the Company was in compliance with the covenants of the loan agreement. Due to the redetermination, the availability under the facility has decreased from $38,500,000 at June 30, 2019, to $28,500,000 currently.

NOTE 6: 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.

NOTE 7: 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 stock repurchase 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

(9)

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 the Company to repurchase up to $1.5 million of the Company’s common stock at management’s discretion. The Board added language to clarify that this is intended to be an evergreen program as the repurchase of an additional $1.5 million of the Company’s common stock is authorized and approved whenever the previous amount is utilized. In addition, 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. During the third quarter of 2019, the Company repurchased $2.5 million of the Company’s common stock.

On December 11, 2018, the Company awarded 14,430 non-performance based shares and 43,287 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. Upon vesting, the performance based shares that do not meet the performance criteria are forfeited. The non-performance and performance based shares had a fair value on their award date of $226,840 and $356,567, 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 11, 2018, through December 11, 2021).

On December 31, 2018, the Company awarded 13,548 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, 2019. The restricted stock contains non-forfeitable rights to receive dividends and to vote the shares during the vesting period. These non-performance based shares had a fair value on their award date of $209,994.

The following table summarizes the Company’s pre-tax compensation expense for the three and nine months ended June 30, 2019 and 2018, related to the Company’s performance based and non-performance based restricted stock.

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
Performance based, restricted stock	$	60,406	$	59,869	$	306,685	$	216,403
Non-performance based, restricted stock		99,505		93,919		299,547		285,223
Total compensation expense	$	159,911	$	153,788	$	606,232	$	501,626

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, 2019
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	371,271		1.97
Non-performance based, restricted stock		394,537		1.58
Total	$	765,808

NOTE 8: Properties and Equipment

Divestitures

During the first quarter of 2019, the Company sold 206 net mineral acres and producing oil and natural gas properties located in Lea and Eddy Counties, New Mexico, to a private buyer for total net consideration of $9,096,938 and recorded a gain on the sale of $9,096,938. The cash from the sale was used to reduce the Company’s outstanding bank debt.

(10)

During the second quarter of 2019, there were no assets sold.

During the third quarter of 2019, the Company sold 166 net mineral acres and producing oil and natural gas properties located in Martin County, Texas, to private buyers for total net consideration of $4,018,031 and recorded a gain on the sale of $4,017,787. The cash from the sale was used to purchase minerals and reduce the Company’s outstanding bank debt.

Acquisitions

During the first quarter of 2019, the Company acquired 45 net mineral acres (which include producing oil and natural gas properties) in the STACK play in Blaine County, Oklahoma, with undeveloped locations identified in both the Woodford and Meramac Shales for $423,000.

During the second quarter of 2019, the Company acquired 329 net mineral acres (which include producing oil and natural gas properties) in the STACK play in Blaine and Caddo Counties, Oklahoma, for $1,386,775.

During the third quarter of 2019, the Company acquired 313 net mineral acres (which include producing oil and natural gas properties) in the Bakken/Three Forks play in North Dakota and in the STACK play in Blaine County, Oklahoma, for $3,310,691.

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 and nine months ended June 30, 2019 and 2018, the assessment resulted in no impairment provisions on producing properties. A significant reduction in oil, NGL and natural gas prices or a decline in reserve volumes may lead to impairment in future periods that may be material to the Company.

NOTE 9: 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. The Company’s derivative contracts are currently with Bank of

(11)

Oklahoma and Koch Supply and Trading LP. The derivative contracts with Bank of Oklahoma are secured under the credit facility with Bank of Oklahoma. The derivative contracts with Koch are unsecured. The derivative instruments have settled or will settle based on the prices below.

Derivative contracts in place as of June 30, 2019

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas fixed price swaps
January - July 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.867
July - December 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.960
July - December 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.950
July - December 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.995
July 2019 - March 2020	100,000 Mmbtu	NYMEX Henry Hub	$2.982
August - December 2019	100,000 Mmbtu	NYMEX Henry Hub	$3.004
January - December 2020	80,000 Mmbtu	NYMEX Henry Hub	$2.750
Oil costless collars
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
July - December 2019	3,000 Bbls	NYMEX WTI	$60.00 floor / $70.75 ceiling
July 2019- June 2020	2,000 Bbls	NYMEX WTI	$65.00 floor / $76.15 ceiling
January - June 2020	2,000 Bbls	NYMEX WTI	$60.00 floor / $67.00 ceiling
January - December 2020	2,000 Bbls	NYMEX WTI	$55.00 floor / $62.00 ceiling
Oil fixed price swaps
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
July - December 2019	5,000 Bbls	NYMEX WTI	$58.50
July - December 2019	1,000 Bbls	NYMEX WTI	$60.60
January - December 2020	2,000 Bbls	NYMEX WTI	$55.28
January - December 2020	2,000 Bbls	NYMEX WTI	$58.65
January - December 2020	2,000 Bbls	NYMEX WTI	$60.00

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 asset of $2,711,509 as of June 30, 2019, and a net liability of $3,414,016 as of September 30, 2018. Net cash paid related to derivative contracts settled during the nine-month period ended June 30, 2019, was $1,099,402 compared to net cash paid of $147,230 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.

(12)

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, 2019, and September 30, 2018. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at June 30, 2019, and September 30, 2018.

	June 30, 2019								September 30, 2018
	Fair Value (a)								Fair Value (a)
	Commodity Contracts								Commodity Contracts
	Current Assets			Current Liabilities			Non-Current Assets		Current Assets			Current Liabilities			Non-Current Liabilities
Gross amounts recognized	$	2,552,237		$	62,864		$	222,136	$	42,150		$	3,106,196		$	349,970
Offsetting adjustments		(62,864	)		(62,864	)		-		(42,150	)		(42,150	)		-
Net presentation on Condensed Balance Sheets	$	2,489,373		$	-		$	222,136	$	-		$	3,064,046		$	349,970

(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 10: 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, 2019.

	Fair Value Measurement at June 30, 2019
	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	$	-	$	2,281,860	$	-	$	2,281,860
Derivative Contracts - Collars	$	-	$	429,650	$	-	$	429,650

Level 2 – Market Approach - The fair values of the Company’s swaps and collars 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 and volatility 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.

At June 30, 2019, and September 30, 2018, the carrying values of cash and cash equivalents, receivables, and payables are considered to be representative of their respective fair values due to the short-term maturities of those instruments. 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

(13)

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.

NOTE 11: Subsequent Events

Subsequent to June 30, 2019, the Company sold an additional 383 net mineral and royalty acres in the Permian Basin in Texas for $4,954,832. These proceeds added to our cash position and will be used to finance future acquisitions.

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 2019 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 2018 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, 2019 – COMPARED TO THREE MONTHS ENDED JUNE 30, 2018

Overview:

The Company recorded a third quarter 2019 net income of $4,604,236, or $0.28 per share, as compared to net loss of $775,093, or $0.05 per share, in the 2018 quarter. The change in net income (loss) was principally the result of gain on assets sales, gains on derivative contracts, and decreased LOE and DD&A; partially offset by decreased oil, NGL and natural gas sales, increased interest and G&A expenses and changes in tax provision (benefit). These items are further discussed below.

Oil, NGL and Natural Gas Sales:

Oil, NGL and natural gas sales decreased $1,420,343 or 13% for the 2019 quarter. Oil, NGL and natural gas sales were down due to decreased NGL and natural gas sales volumes of 20% and 17%, respectively, and decreases in oil, NGL and natural gas prices of 13%, 20% and 10%, respectively, slightly offset by an increase in oil volumes of 20%. 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 2019 and 2018:

	Oil Bbls		Average		NGL Bbls		Average		Mcf		Average		Mcfe		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Three months ended
6/30/2019		96,065	$	57.50		53,903	$	15.33		1,718,561	$	2.00		2,618,369	$	3.74
6/30/2018		80,298	$	66.15		67,142	$	19.20		2,082,700	$	2.21		2,967,340	$	3.78

The oil production increase is a result of a seven-well drilling program in the Eagle Ford Shale that came on line in March 2019 and a mineral acquisition of producing properties in the Bakken in August 2018. The increase is slightly offset by natural production decline in the Anadarko Woodford Shale. The NGL production decrease is attributed to natural production decline and operators electing to remove less NGL from the natural gas stream due to lower NGL prices. These decreases in the liquid-rich production from the prior year’s drilling program in the Anadarko Basin Woodford Shale and Eagle Ford Shale, were partially offset by a mineral acquisition of producing properties in the Bakken. Decreased natural gas production is due to naturally declining production in the Anadarko Woodford, Arkoma Woodford and Fayetteville shales. This decrease was slightly offset by natural gas production from the mineral acquisition in the Bakken.

The total production in the third quarter of 2018 was significantly higher due to our substantial 2017 drilling program in the Arkoma Woodford (8 wells), Anadarko Woodford (6 wells) and Eagle Ford (10 wells) shales, which began production in early 2018. All of these wells had significantly higher than average NRI’s and were producing at high rates during that time. As with virtually all horizontal wells, production from these wells experienced significant declines during their first year. This decline, along with

(14)

materially lower capital expenditures during fiscal 2018 andfiscal 2019, accounted for a material portion of the Company’s production decline experienced in the 2019 quarter.

Production for the last five quarters was as follows:

Quarter ended	Oil Bbls Sold		NGL Bbls Sold		Mcf Sold		Mcfe Sold
6/30/2019		96,065		53,903		1,718,561		2,618,369
3/31/2019		74,372		47,875		1,688,043		2,421,525
12/31/2018		82,828		62,262		1,893,990		2,764,530
9/30/2018		83,118		58,886		2,088,258		2,940,282
6/30/2018		80,298		67,142		2,082,700		2,967,340

Lease Bonuses and Rental Income:

Lease bonuses and rental income decreased $255,223 in the 2019 quarter. The decrease was due to a lower level of leasing by the Company during the 2019 quarter.

Gains (Losses) on Derivative Contracts:

The fair value of derivative contracts was a net asset of $2,711,509 as of June 30, 2019, and a net liability of $3,303,480 as of June 30, 2018. We had a net gain on derivative contracts of $2,313,195 in the 2019 quarter as compared to a net loss of $2,129,041 in the 2018 quarter. During the 2019 quarter, the oil and natural gas collars and fixed price swaps experienced a favorable change as NYMEX oil and natural gas futures experienced a decrease in price during the quarter in relation to their previous position to the collars and the fixed prices of the swaps at the beginning of the 2019 quarter. During the 2018 quarter, the oil and natural gas collars and fixed price swaps experienced an unfavorable change as the NYMEX futures prices (at that time) increased from where they were at the end of the previous quarter in 2018. The Company utilizes derivative contracts for the purpose of protecting its return on investments and cash flow.

Gain on Asset Sales:

Gain on asset sales was $4,017,787 in the 2019 quarter. During this quarter, the Company sold 166 net mineral acres in Martin County, Texas. In the 2018 quarter, the Company did not have a gain on asset sales.

Lease Operating Expenses (LOE):

Total LOE decreased $84,212 or 3% in the 2019 quarter. LOE per Mcfe increased in the 2019 quarter to $1.20 compared to $1.09 in the 2018 quarter. LOE related to field operating costs increased $59,803 or 4% in the 2019 quarter compared to the 2018 quarter. Field operating costs were $0.62 per Mcfe in the 2019 quarter as compared to $0.53 per Mcfe in the 2018 quarter. The increase in rate in the 2019 quarter was principally the result of production decline.

The increase in LOE related to field operating costs was offset by a decrease in handling fees (primarily gathering, transportation and marketing costs) of $144,015 in the 2019 quarter compared to the 2018 quarter. On a per Mcfe basis, these handling fees were $0.58 in the 2019 quarter as compared to $0.56 in the 2018 quarter. The increase in rate was primarily due to natural gas production (with lower handling fees) declining from peak rates noted in 2018, partially offset by oil production (with lower handling fees) increasing in the 2019 quarter. 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.

Depreciation, Depletion and Amortization (DD&A):

DD&A decreased $236,466 or 5% in the 2019 quarter. DD&A in the 2019 quarter was $1.67 per Mcfe as compared to $1.56 per Mcfe in the 2018 quarter. DD&A decreased $543,273 as a result of production decreasing 12% in the 2019 quarter compared to the 2018 quarter. An offsetting increase of $306,807 was the result of the $0.11 increase in the DD&A rate per Mcfe. The rate increase was mainly due to decreased production from wells with lower finding costs which had peak production in early 2018 and new production coming on in the Eagle Ford (higher DD&A) during the 2019 quarter.

(15)

Interest Expense:

Interest expense increased $105,781 or 25% in the 2019 quarter. The increase was the result of a higher average interest rate of 4.80% during the 2019 quarter as compared to 4.08% in the 2018 quarter. This was partially offset by lower average outstanding debt balances during the 2019 quarter.

General and Administrative Costs (G&A):

G&A increased $216,188 or 14% in the 2019 quarter. The increase was primarily the result of higher personnel expenses and timing of billings of work performed by outside firms.

Income Taxes:

Income taxes changed $1,524,000, from a $209,000 benefit in the 2018 quarter to a $1,315,000 provision in the 2019 quarter. The effective tax rate changed from a 21% benefit in the 2018 quarter to a 22% provision in the 2019 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, 2019 – COMPARED TO NINE MONTHS ENDED JUNE 30, 2018

Overview:

The Company recorded a nine-month net income of $15,408,842, or $0.92 per share, in the 2019 period, as compared to net income of $14,080,022, or $0.83 per share, in the 2018 period. The change in net income (loss) was principally the result of gain on assets sales, gains on derivative contracts and decreased LOE and DD&A; partially offset by decreased tax benefits (due to new federal tax law change in 2018), decreased oil, NGL and natural gas sales and increased interest and G&A expenses. These items are further discussed below.

Oil, NGL and Natural Gas Sales:

Oil, NGL and natural gas sales decreased $5,141,760 or 14% for the 2019 period. Oil, NGL and natural gas sales were down due to decreases in oil and NGL prices of 9% and 18%, respectively, and decreases in NGL and natural gas sales volumes of 16% and 20%, respectively, slightly offset by an increase 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 2019 and 2018:

	Oil Bbls		Average		NGL Bbls		Average		Mcf		Average		Mcfe		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Nine months ended
6/30/2019		253,265	$	55.01		164,040	$	18.88		5,300,594	$	2.68		7,804,424	$	4.00
6/30/2018		253,447	$	60.77		196,290	$	23.02		6,633,005	$	2.48		9,331,427	$	3.90

Oil production was basically flat, a combined result of naturally declining production from the 2017 drilling program in the Eagle Ford and Anadarko Woodford shales, offset by the 2018 seven-well drilling program in the Eagle Ford Shale that came on line in March 2019 and a mineral acquisition of Bakken producing properties in August 2018. The NGL production decrease is attributed to natural production decline and operators electing to remove less NGL from the natural gas stream due to lower NGL prices. These decreases in the liquid-rich production from the prior year’s drilling program in the Anadarko Basin Woodford Shale and Eagle Ford Shale were slightly offset by a mineral acquisition of producing properties in the Bakken. Decreased natural gas production is due to naturally declining production in the Anadarko Woodford and Arkoma Woodford shales and, to a lesser extent, the Fayetteville Shale.

The total production in the 2018 period saw significant increases due to our substantial 2017 drilling program in the Arkoma Woodford (8 wells), Anadarko Woodford (6 wells) and Eagle Ford (10 wells) shales, which began production just before or during the period. All of these wells had significantly higher than average NRI’s and were producing at high rates during that time. As with virtually all horizontal wells, production from these wells experienced significant declines during their first year. This decline, along with materially lower capital expenditures during fiscal 2018 and fiscal 2019, accounted for a material portion of the Company’s production decline experienced in the 2019 period.

(16)

Gains (Losses) on Derivative Contracts:

The fair value of derivative contracts was a net asset of $2,711,509 as of June 30, 2019, and a net liability of $3,303,480 as of June 30, 2018. We had a net gain on derivative contracts of $5,026,123 in the 2019 period as compared to a net loss of $3,966,869 recorded in the 2018 period. The change was principally due to the oil and natural gas collars and fixed price swaps being more favorable in the 2019 period, as NYMEX oil and natural gas futures decreased (during the period) in relation to where they were at the beginning of the period. During the 2018 period, the loss was principally due to the oil collars and fixed price swaps being less favorable as NYMEX oil futures experienced large increases in price in relation to the collars and the fixed prices of the swaps. The Company utilizes derivative contracts for the purpose of protecting its return on investments.

Gain on Asset Sales:

Gain on asset sales was $13,114,725 in the 2019 period. During this period, the Company sold mineral acreage in Lea and Eddy Counties, New Mexico, for a gain of $9,096,938 and Martin County, Texas, for a gain of $4,017,787. In the 2018 period, the Company did not have a gain on asset sales.

Lease Operating Expenses (LOE):

LOE decreased $835,741 or 8% in the 2019 period. LOE per Mcfe increased in the 2019 period to $1.18 compared to $1.08 in the 2018 period. LOE related to field operating costs decreased $403,677 in the 2019 period compared to the 2018 period, an 8% decrease. Field operating costs were $0.59 per Mcfe in the 2019 period as compared to $0.54 per Mcfe in the 2018 period. The increase in rate in the 2019 period was principally the result of decreased production partially offset by the Company selling some marginal properties which had higher operating costs.

The decrease in LOE related to field operating costs was coupled with a decrease in handling fees (primarily gathering, transportation and marketing costs) of $432,064 in the 2019 period compared to the 2018 period. On a per Mcfe basis, these handling fees were $0.59 in the 2019 period as compared to $0.54 in the 2018 period. The increase in rate was primarily due to natural gas production (with lower handling fees) declining from peak rates noted in 2018 and oil production (with lower handling fees) declining. 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.

Depreciation, Depletion and Amortization (DD&A):

DD&A decreased $2,315,706 or 16% in the 2019 period. The DD&A rate in both the 2019 and 2018 periods was $1.51 per Mcfe. DD&A decreased primarily as a result of production decreasing 16% in the 2019 period compared to the 2018 period.

Interest Expense:

Interest expense increased $263,405 or 20% in the 2019 period. The increase was the result of a higher average interest rate of 4.70% during the 2019 period as compared to 3.79% in the 2018 period.

General and Administrative Costs (G&A):

G&A increased $633,848 or 12% in the 2019 period. The increase was primarily the result of higher personnel expenses. The increase in personnel expenses was mainly due to increased restricted stock expenses as a retirement clause in the restricted stock agreements caused some of the grants to become fully expensed during the period. This was coupled with higher salary expenses due to employee retirements and changes; as well as other compensation increases compared to the 2018 period. Approximately $200,000 of these expenses are nonrecurring.

Income Taxes:

Income taxes changed $17,699,000, from a $12,943,000 benefit in the 2018 period to a $4,756,000 provision in the 2019 period. This was mostly the result of the new Tax Cuts and Jobs Act enacted in December 2017 that reduced the US federal corporate tax rate from 35% to 21%. The $12,777,000 tax benefit of this law change on our existing deferred tax liabilities was recorded in the 2018 period and directly affected the effective tax rate for the 2018 period. The effective tax rate changed from a 1138% benefit in the 2018 period to a 24% provision in the 2019 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.

(17)

LIQUIDITY AND CAPITAL RESOURCES

The Company had positive working capital of $9,028,120 at June 30, 2019, compared to positive working capital of $2,509,050 at September 30, 2018. The change in working capital was mainly due to the net change in receivables (payables) for derivative contracts.

Liquidity:

Cash and cash equivalents were $1,530,477 as of June 30, 2019, compared to $532,502 at September 30, 2018, an increase of $997,975. Cash flows for the nine months ended June 30 are summarized as follows:

Net cash provided (used) by:

	2019			2018			Change
Operating activities	$	14,332,951		$	21,657,902		$	(7,324,951	)
Investing activities		4,643,215			(7,620,860	)		12,264,075
Financing activities		(17,978,191	)		(14,117,820	)		(3,860,371	)
Increase (decrease) in cash and cash equivalents	$	997,975		$	(80,778	)	$	1,078,753

Operating activities:

Net cash provided by operating activities decreased $7,324,951 during the 2019 period, as compared to the 2018 period, primarily the result of the following:

• Increased net payments on derivative contracts of $952,172.

• Receipts of oil, NGL and natural gas sales (net of production taxes and gathering, transportation and marketing costs) and other decreased $5,422,970.

• Decreased receipts from leasing of fee mineral acreage of $134,934.

• Increased payments for G&A and other expense of $599,211.

• Increased net payments for income tax of $358,823.

• Decreased field operating expenses of $390,706.

• Increased interest payments of $247,548.

Investing activities:

Net cash provided by investing activities increased $12,264,075 during the 2019 period, as compared to the 2018 period, primarily due to higher net proceeds from the sale of assets of $12,029,832 and lower payments of $4,393,457 for drilling and completion activity, partially offset by higher acquisition costs of $4,154,187 during 2019.

Financing activities:

Net cash used by financing activities increased $3,860,371 during the 2019 period, as compared to the 2018 period, primarily the result of increased stock repurchases of $6,193,086, partially offset by lower net payments on long-term debt of $2,322,220.

Capital Resources:

Capital expenditures to drill and complete wells decreased $4,393,457 (57%) from the 2018 to the 2019 period. The Company has a working interest in seven Eagle Ford Shale wells that started producing at the end of March 2019. The outstanding capital commitment on those wells, net of prepayments, was minimal as of June 30, 2019. The Company currently has no well proposals that would require significant capital commitments to drill and complete.

(18)

On November 30, 2018, the Company closed on a transaction to sell certain mineral acreage and producing oil and natural gas properties, primarily located in Lea and Eddy Counties, New Mexico, to a private buyer for total net consideration of $9.1 million cash. Near the end of June 2019, the Company closed on two additional mineral sales transactions in Martin County, Texas, to private buyers for $4.0 million of cash consideration. Like the vast majority of Panhandle’s mineral acreage, these minerals were purchased by Panhandle several years ago for a minimal cost. At the time of sale, the assets were almost completely amortized and therefore had minimal net book value. Almost all of the value received was a gain on the sale of assets in the first and third quarters of 2019. The Company utilized like-kind exchanges under IRS Code 1031 to defer income tax on most of the gains by offsetting it with the Bakken and STACK/SCOOP mineral acreage acquisitions that have been purchased throughout the year using qualified exchange accommodation agreements.

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 has not elected to participate in any working interest drilling proposals during the current fiscal year.

The Company received lease bonus payments during 2019 totaling $967,337. The Company began actively marketing its open acreage in STACK/SCOOP to lease in the third quarter of 2019. 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 9: 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, 2019
Cash provided by operating activities	$	14,332,951
Cash provided (used) by:
Capital expenditures - acquisitions		(5,120,466	)
Capital expenditures - drilling and completion of wells		(3,349,640	)
Quarterly dividends of $0.12 per share		(2,013,005	)
Treasury stock purchases		(6,465,186	)
Net borrowings (payments) on credit facility		(9,500,000	)
Proceeds from sale of assets		13,114,969
Other investing and financing activities		(1,648	)
Net cash used		(13,334,976	)
Net increase (decrease) in cash	$	997,975

Outstanding borrowings on the credit facility at June 30, 2019, were $41,500,000.

Looking forward, the Company expects to fund overhead costs, capital additions related to the drilling and completion of wells, acquisitions, treasury stock purchases and dividend payments from cash provided by operating activities, cash on hand and borrowings utilizing our bank credit facility. The Company intends to use any excess cash to reduce existing bank debt. The Company had availability of $38,500,000 at June 30, 2019, 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 August 2019 and reduced from $80 million to $70 million, which is a level that is expected to provide ample liquidity for the Company to continue to execute its normal operating strategies (current availability of $28,500,000). Even though the borrowing base was reduced, the Company has approximately the same availability now that it did at the beginning of the 2019 fiscal year. The next redetermination is scheduled for December 2019.

(19)

On November 6, 2017, the Company filed a shelf registration statement with the SEC on Form S-3. This filing gives us the authorization to sell up to $75 million in securities, including common stock, preferred stock, debt securities, warrants and units in amounts to be determined at the time of an offering. Any such offering, if it does occur, may happen in one or more transactions. The specific terms of any securities to be sold will be described in supplemental filings with the SEC. The registration statement will expire on November 6, 2020. The Company currently has no plans to issue securities under the shelf registration statement.

Based on expected capital expenditure levels, anticipated cash provided by operating activities for 2019 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. Other than the adoption of ASC 606 on October 1, 2019, (see Note 2: Revenues) 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, 2018.

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 2019 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 2019 derivative contracts, the price sensitivity in 2019 for each $1.00 per barrel change in wellhead oil price is $336,565 for operating revenue based on the Company’s prior year oil volumes. The price sensitivity in 2019 for each $0.10 per Mcf change in wellhead natural gas price is $872,126 for operating revenue based on the Company’s prior year natural gas volumes.

Commodity Price Risk

The Company 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. The Company’s derivative contracts are currently with Bank of Oklahoma and Koch Supply and Trading LP. The derivative contracts with Bank of Oklahoma are secured under the credit facility with Bank of Oklahoma. The derivative contracts with Koch are unsecured. 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 $155,000. For the Company’s oil collars, a change of $1.00 (below or above the collar) in the NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $98,000. For the Company’s natural gas fixed price swaps, a change of $0.10 in the NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $417,900.

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 0.50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%. At June 30, 2019, the Company had $41,500,000 outstanding under this facility and the effective interest rate was 4.76%. 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.

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

(20)

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, 2019, the Company repurchased shares of the Company’s common stock as summarized in the table below.

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program
4/1 - 4/30/19		-	$	-		-	$	1,213,443
5/1- 5/31/19		79,574	$	14.12		79,574	$	89,749
6/1 - 6/30/19		103,327	$	13.30		103,327	$	215,942
Total		182,901	$	13.65		182,901

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 the Company to repurchase up to $1.5 million of the Company’s common stock at management’s discretion. The Board added language to clarify that this is intended to be an evergreen program as the repurchase of an additional $1.5 million of the Company’s common stock is authorized and approved whenever the previous $1.5 million is utilized. In addition, 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 10 - Sixth Amendment to Amended and Restated Credit Agreement and Joinder dated August 6, 2019
		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

(21)

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 8, 2019	/s/ Paul F. Blanchard Jr.
Date	Paul F. Blanchard Jr., President and
	Chief Executive Officer
August 8, 2019	/s/ Robb P. Winfield
Date	Robb P. Winfield, Vice President,
	Chief Financial Officer and Controller

(22)

EX-10

Exhibit 10

SIXTH AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT

THIS SIXTH AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT is dated and effective as of August 6, 2019, by and among PANHANDLE OIL AND GAS INC., formerly named Panhandle Royalty Company, an Oklahoma corporation (referred to herein as the “Borrower”), each lender from time to time party hereto (collectively, the “Lenders” and individually, a “Lender”), MIDFIRST BANK, a federally chartered savings association, as Documentation Agent, and BOKF, NA dba Bank of Oklahoma, as Administrative Agent and L/C Issuer.

W I TN E S S E T H:

WHEREAS, Borrower, Administrative Agent, Documentation Agent, and Lenders entered into that certain Amended and Restated Credit Agreement dated as of November 25, 2013 as modified by (i) letter amendment dated as of March 5, 2014, (ii) Second Amendment to Amended and Restated Credit Agreement dated as of June 17, 2014, (iii) Third Amendment to Amended and Restated Credit Agreement dated as of December 8, 2016, (iv) Fourth Amendment to Amended and Restated Credit Agreement dated as of October 25, 2017, and (v) Fifth Amendment to Amended and Restated Credit Agreement dated as of July 2, 2018 (the “Existing Credit Agreement”), for the purpose and consideration therein expressed, whereby Lenders made loans to Borrower as therein provided; and

WHEREAS, Borrower, Administrative Agent and Lenders desire to amend the Existing Credit Agreement for the sixth time to modify same in accordance herewith;

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein and in the Existing Credit Agreement, in consideration of the loans and other extensions of credit which may hereafter be made by Lenders to Borrower, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto do hereby agree as follows:

ARTICLE I.

DEFINITIONS AND REFERENCES

Section 1.1Terms Defined in the Existing Credit Agreement. Unless the context otherwise requires or unless otherwise expressly defined herein, the terms defined in the Existing Credit Agreement shall have the same meanings whenever used in this Amendment.

Section 1.2Other Defined Terms. Unless the context otherwise requires, the following terms when used in this Amendment shall have the meanings assigned to them in this Section 1.2.

“Amendment” means this Sixth Amendment to Amended and Restated Credit Agreement.

Sixth Amendment to Amended and Restated

Credit Agreement

“Amendment Documents” means this Amendment and all other Loan Documentsexecuted and delivered in connection herewith including but not limited to notes andmortgages covering such of Borrower’s oil and gas properties as deemed necessary byAdministrative Agent in its sole discretion. All of the Amendment Documents shall be deemed to constitute Loan Documents.

“Credit Agreement” (or “this Agreement” wherever referred to within the Existing Credit Agreement) means the Existing Credit Agreement as amended by the Amendment, and as the same may hereafter be further amended, restated, modified and/or otherwise supplemented from time to time.

ARTICLE II.

AMENDMENTS TO EXISTING CREDIT AGREEMENT

Section 2.1Borrowing Base Notification.  From the date of this Sixth Amendment to, but excluding, the next redetermination of the Borrowing Base, as set forth in the Existing Credit Agreement, as amended hereby, the Borrowing Base shall be Seventy Million and No/100ths Dollars ($70,000,000.00). Borrower and Lenders hereby agree that this provision satisfies all notification requirements as set forth in the Credit Agreement.

Section 2.2Amendment and Restatement of Section 2.1. Section 2.1 of the Existing Credit Agreement is hereby amended and restated in its entirety as follows:

“2.1 Revolving Line of Credit Commitment.  Subject to the terms and conditions set forth herein, each Lender severally agrees to lend to Borrower, through one or more Loans, its Commitment Percentage of the lesser of (x) such Lender’s Committed Sum under the Revolver Facility, or (y) the Borrowing Base; provided, however, that (i) each Loan must occur on a Business Day and no later than the Business Day immediately preceding the Maturity Date; and (ii) on any date of determination, after giving effect to the requested Loan, (A) the Commitment Usage may not exceed the Revolving Commitment then in effect, (B) the Commitment Usage may not exceed the Available Commitment then in effect, and (C) for any Lender, its Commitment Percentage of the Commitment Usage may not exceed the lesser of (x) such Lender’s Committed Sum under the Revolver Facility, or (y) the Borrowing Base.  Revolver Loans may be repaid or re borrowed from time to time in accordance with the terms and provisions herein and in the Loan Documents.  The Borrowing Base component of the Revolving Commitment shall be reduced by the Monthly Commitment Reduction, if applicable, pursuant to Section 2.6, on the first (1st) day of each month during the term hereof.  The obligation of the Borrower hereunder shall be evidenced by this Agreement and the Notes issued in connection herewith, said Notes to be as described in Section 2.2(a) hereof.  Notwithstanding any other provision of this Agreement, no Advance shall be required to be made hereunder if any Event of Default (as hereinafter defined) has occurred and is continuing or if any event or condition has occurred or failed to occur which with the passage of time or service of notice, or both, would constitute an Event of Default.  Irrespective of the face amount of the Notes, the Lenders shall never have the obligation to Advance any amount or amounts in excess of the Available Commitment or to increase the Borrowing Base.  Within the limit of the Revolving Commitment, the Borrower may borrow, repay and re-borrow under this Section 2.1 prior to the Maturity Date.”

2 Sixth Amendment to Amended and Restated

Credit Agreement

Section 2.3Amendment and Restatement of Schedule 2.01. Schedule 2.01, as previously attached to the Existing Credit Agreement, is hereby amended and restated in its entirety and replaced by new Schedule 2.01 attached as Exhibit A to this Amendment.

ARTICLE III.

CONDITIONS OF EFFECTIVENESS

Section 3.1Effective Date. This Amendment shall become effective as of the date hereof when and only when:

(a)Amendment Documents. Administrative Agent shall have received duly executed and delivered counterparts of each Amendment Document (i) in form, substance and date satisfactory to Administrative Agent and each Lender as required pursuant to the terms of the Credit Agreement, and (ii) in such numbers as Administrative Agent or its counsel may reasonably request.

(b)Certificates and Resolutions. Administrative Agent shall have received such certificates and resolutions or consents of the governing body of the Borrower authorizing the transactions described in this Amendment and certifying as to the completeness of the Organizational Documents of the Borrower.

(c)No Default. No event shall have occurred and be continuing that would constitute an Event of Default or a Default.

(d)Opinions of Counsel. Administrative Agent shall have received originally executed copies of the favorable written opinions of Borrower’s counsel opining as to such matters as Administrative Agent may reasonably request, dated as of the effectiveness of this Amendment and otherwise in form and substance reasonably satisfactory to Administrative Agent.

ARTICLE IV.

REPRESENTATIONS AND WARRANTIES

Section 4.1Representations and Warranties of Borrower. In order to induce each Lender to enter into this Amendment, Borrower represents and warrants to Administrative Agent and each Lender that:

(a)All representations and warranties made by Borrower in any Loan Document are true and correct in all material respects (without duplication of any materiality qualifier contained therein) on and as of time of the effectiveness hereof as if such representations and warranties had been made as of the time of the effectiveness hereof (except to the extent that such representation or warranty was made as of a specific date, in which case such representation

3 Sixth Amendment to Amended and Restated

Credit Agreement

or warranty shall be true and correct in all material respects (withoutduplication of any materiality qualifier contained therein) as of such specific date).

(b)Borrower has duly taken all corporate action necessary to authorize the execution and delivery by it of the Amendment Documents to which it is a party and to authorize the consummation of the transactions contemplated thereby and the performance of its obligations thereunder.

(c)The execution and delivery by Borrower of the Amendment Documents to which it is a party, the performance by it of its obligations under such Amendment Documents, and the consummation of the transactions contemplated by such Amendment Documents, do not and will not (a) conflict with, violate or result in a breach of any provision of (i), to its knowledge, any Law, (ii) its Organizational Documents, or (iii) any material agreement, judgment, license, order or permit applicable to or binding upon it, (b) result in the acceleration of any Indebtedness owed by it, or (c) result in or require the creation of any Lien upon any of its assets or properties except as expressly contemplated or permitted in the Loan Documents. Except (x) as expressly contemplated in the Amendment Documents and (y) such as have been obtained or made and are in full force and effect, to its knowledge, no permit, consent, approval, authorization or order of, and no notice to or filing with, any Governmental Authority or third party is required on the part of or in its respect in connection with the execution, delivery or performance by it of any Amendment Document or to consummate any transactions contemplated by the Amendment Documents.

(d)This Amendment is, and the other Amendment Documents when duly executed and delivered will be, legal, valid and binding obligations of it, enforceable against it in accordance with their terms except as such enforcement may be limited by bankruptcy, insolvency or similar Laws of general application relating to the enforcement of creditors ‘ rights and by general principles of equity.

ARTICLE V.

MISCELLANEOUS

Section 5.1 Release. In consideration of the amendments contained herein, Borrower hereby waives and releases each of the Lenders and the Administrative Agent from any and all claims and defenses, known or unknown, with respect to the Existing Credit Agreement and the other Loan Documents and the transactions contemplated thereby.

Section 5.2Ratification and Affirmation. Borrower hereby acknowledges the terms of the Existing Credit Agreement, as amended, and ratifies and affirms its obligations under, and acknowledges, renews and extends its continued liability under, each Loan Document to which it is a party and agrees that each Loan Document to which it is a party remains in full force and effect.

4 Sixth Amendment to Amended and Restated

Credit Agreement

Section 5.3Survival of Agreements. All of Borrower’s various representations,warranties, covenants and agreements in the Amendment Documents shall survive the execution and delivery thereof and the performance thereof, including the making or granting of the Loansand the delivery of the other Loan Documents, and shall further survive until all of theObligations are paid in full to each Lender and all of Lenders’ obligations to Borrower are terminated.

Section 5.4 Authorization. The Lenders hereby authorize the Administrative Agent to execute any and all amendments to any Loan Documents deemed necessary by Administrative Agent to evidence the extension of the term of the Loan as described herein.

Section 5.5Interpretive Provisions. Sections 1.2 and 1.3 of the Existing Credit Agreement are incorporated herein by reference herein as if fully set forth.

Section 5.6Loan Documents. The Amendment Documents are each a Loan Document, and all provisions in the Existing Credit Agreement pertaining to Loan Documents apply thereto.

Section 5.7Governing Law. This Amendment shall be governed by, and construed in accordance with, the Laws of the State of Oklahoma.

Section 5.8Counterparts; Fax. This Amendment may be separately executed in counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same Amendment. The Amendment Documents may be validly executed by facsimile or other electronic transmission.

THIS AMENDMENT AND THE OTHER AMENDMENT DOCUMENTS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS OF THE PARTIES.

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed as of the date first above written.

[The remainder of this page has been intentionally left blank.]

5 Sixth Amendment to Amended and Restated

Credit Agreement

Signature Page to Sixth Amendment to Amended and Restated Credit Agreement

BORROWER:	PANHANDLE OIL AND GAS INC.,
	an Oklahoma corporation
	/s/ Paul Blanchard
	By:Paul Blanchard
	Title:President, CEO

Signature Page to Sixth Amendment to Amended and Restated Credit Agreement

LENDERS:	BOKF, NA dba Bank of Oklahoma
	By:/s/ Jeffrey Hall
	Name:Jeffrey Hall
	Title:Senior Vice President

Signature Page to Sixth Amendment to Amended and Restated Credit Agreement

LENDERS:	MIDFIRST BANK, as lender and Document
	Agent
	By: /s/ W. Thomas Portman
	Name:W. Thomas Portman
	Title:Vice President

Signature Page to Sixth Amendment to Amended and Restated Credit Agreement

LENDERS:	BANCFIRST
	By: /s/ Heather H. Whiteside
	Name:Heather H. Whiteside
	Title:Assistant Vice President

Signature Page to Sixth Amendment to Amended and Restated Credit Agreement

LENDERS:	AMARILLO NATIONAL BANK
	By: /s/ Rob Mansfield
	Name:Rob Mansfield
	Title:Vice President

Signature Page to Sixth Amendment to Amended and Restated Credit Agreement

ADMINISTRATIVE AGENT:	BOKF, NA dba Bank of Oklahoma
	By: /s/ Jeffrey Hall
	Name:Jeffrey Hall
	Title:Senior Vice President

EXHIBIT A TO

SIXTH AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT

SCHEDULE 2.01

COMMITTED SUMS AND COMMITMENT PERCENTAGES

Lender	Committed Sums	Commitment Percentage
	(based off face amount of Notes)
BOKF, NA	$100,000,000.00	50.0000000%
MidFirst Bank	$  50,000,000.00	25.0000000%
BancFirst	$  34,615,384.62	17.3076923%
Amarillo National Bank	$  15,384,615.38	7.6923077%
TOTAL	$200,000,000.00	100.0000000%

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 8, 2019

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 8, 2019

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, 2019, 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 8, 2019

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, 2019, 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 8, 2019

XML

Document and Entity Information - shares	9 Months Ended
	Jun. 30, 2019	Aug. 08, 2019
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, 2019
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--09-30
Entity Filer Category	Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Current Reporting Status	Yes
Entity Shell Company	false
Entity File Number	001-31759
Entity Tax Identification Number	731055775
Entity Address, Address Line One	Grand Centre
Entity Address, Address Line Two	Suite 300
Entity Address, Address Line Three	5400 N Grand Blvd
Entity Address, City or Town	Oklahoma City
Entity Address, State or Province	Oklahoma
Entity Address, Postal Zip Code	73112
City Area Code	(405)
Local Phone Number	948-1560
Entity Common Stock, Shares Outstanding		16,388,724

XML

Condensed Balance Sheets - USD ($)		Jun. 30, 2019	Sep. 30, 2018
Current assets:
Cash and cash equivalents		$ 1,530,477	$ 532,502
Oil, NGL and natural gas sales receivables (net of allowance for uncollectable accounts)		5,503,962	7,101,629
Refundable income taxes		510,011	33,165
Derivative contracts, net	[1]	2,489,373
Other		1,438,138	578,880
Total current assets		11,471,961	8,246,176
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties		435,425,936	427,448,584
Non-producing oil and natural gas properties		12,518,885	12,563,519
Other		1,717,769	1,529,770
Gross properties and equipment, at cost, based on successful efforts accounting		449,662,590	441,541,873
Less accumulated depreciation, depletion and amortization		(254,954,381)	(243,257,472)
Net properties and equipment		194,708,209	198,284,401
Investments		207,225	219,109
Derivative contracts, net	[1]	222,136
Total assets		206,609,531	206,749,686
Current liabilities:
Accounts payable		563,642	881,130
Derivative contracts, net	[1]		3,064,046
Accrued liabilities and other		1,880,199	1,791,950
Total current liabilities		2,443,841	5,737,126
Long-term debt		41,500,000	51,000,000
Deferred income taxes, net		23,238,007	18,088,007
Asset retirement obligations		2,927,487	2,809,378
Derivative contracts, net	[1]		349,970
Stockholders' equity:
Class A voting common stock, $0.0166 par value; 24,000,000 shares authorized, 16,897,306 issued at June 30, 2019, and 16,896,881 issued at September 30, 2018		281,509	281,502
Capital in excess of par value		2,937,874	2,824,691
Deferred directors' compensation		2,481,109	2,950,405
Retained earnings		138,662,782	125,266,945
Stockholders' Equity		144,363,274	131,323,543
Less treasury stock, at cost; 508,582 shares at June 30, 2019, and 145,467 shares at September 30, 2018		(7,863,078)	(2,558,338)
Total stockholders' equity		136,500,196	128,765,205
Total liabilities and stockholders' equity		$ 206,609,531	$ 206,749,686

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

XML

Condensed Balance Sheets (Parenthetical) - $ / shares	Jun. 30, 2019	Sep. 30, 2018
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	16,897,306	16,896,881
Treasury stock, shares	508,582	145,467

XML

Condensed Statements Of Operations - USD ($)	3 Months Ended		9 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Revenues:
Revenues	$ 9,782,337		$ 31,214,375
Gains (losses) on derivative contracts	2,313,195	$ (2,129,041)	5,026,123	$ (3,966,869)
Gain on asset sales	4,017,787		13,114,725
Revenues	16,342,394	9,557,937	50,307,601	33,469,721
Costs and expenses:
Lease operating expenses	3,148,960	3,233,172	9,241,708	10,077,449
Production taxes	488,779	485,157	1,565,038	1,471,970
Depreciation, depletion and amortization	4,383,043	4,619,509	11,820,705	14,136,411
Interest expense	526,677	420,896	1,551,831	1,288,426
General and administrative	1,809,439	1,593,251	5,881,432	5,247,584
Loss on asset sales and other expense (income)	66,260	190,045	82,045	110,859
Total costs and expenses	10,423,158	10,542,030	30,142,759	32,332,699
Income (loss) before provision (benefit) for income taxes	5,919,236	(984,093)	20,164,842	1,137,022
Provision (benefit) for income taxes	1,315,000	(209,000)	4,756,000	(12,943,000)
Net income (loss)	$ 4,604,236	$ (775,093)	$ 15,408,842	$ 14,080,022
Basic and diluted earnings (loss) per common share	$ 0.28	$ (0.05)	$ 0.92	$ 0.83
Basic and diluted weighted average shares outstanding:
Common shares	16,515,498	16,775,981	16,646,828	16,742,044
Unissued, directors' deferred compensation shares	170,066	206,202	183,206	205,867
Basic and diluted weighted average shares outstanding	16,685,564	16,982,183	16,830,034	16,947,911
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	$ 9,782,337	$ 11,202,680	$ 31,214,375	$ 36,356,135
Lease Bonuses and Rental Income [Member]
Revenues:
Revenues	$ 229,075	$ 484,298	$ 952,378	$ 1,080,455

XML

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, 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)
Net income (loss)	13,784,939				13,784,939
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	194,050		194,050
Dividends	(1,347,608)				(1,347,608)
Distribution of restricted stock to officers and directors	734		(735,965)			$ 736,699
Distribution of restricted stock to officers and directors, shares						44,065
Increase in deferred directors' compensation charged to expense	108,384			108,384
Balances at Dec. 31, 2017	129,182,673	$ 280,938	2,186,538	3,568,293	125,767,547	$ (2,620,643)
Balances, shares at Dec. 31, 2017		16,863,004
Balances, Treasury shares at Dec. 31, 2017						(154,044)
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)
Net income (loss)	14,080,022
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)
Balances at Dec. 31, 2017	129,182,673	$ 280,938	2,186,538	3,568,293	125,767,547	$ (2,620,643)
Balances, shares at Dec. 31, 2017		16,863,004
Balances, Treasury shares at Dec. 31, 2017						(154,044)
Net income (loss)	1,070,176				1,070,176
Restricted stock awards	153,788		153,788
Distribution of restricted stock to officers and directors	43		(43,435)			$ 43,478
Distribution of restricted stock to officers and directors, shares						2,556
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	62,442			62,442
Balances at Mar. 31, 2018	130,469,122	$ 281,481	2,566,003	2,819,516	126,837,723	$ (2,035,601)
Balances, shares at Mar. 31, 2018		16,895,603
Balances, Treasury shares at Mar. 31, 2018						(119,650)
Net income (loss)	(775,093)				(775,093)
Restricted stock awards	153,788		153,788
Dividends	(675,892)				(675,892)
Distribution of restricted stock to officers and directors	42	$ 14	(28,957)			$ 28,985
Distribution of restricted stock to officers and directors, shares		852				1,704
Increase in deferred directors' compensation charged to expense	62,747			62,747
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)
Balances at Sep. 30, 2018	$ 128,765,205	$ 281,502	2,824,691	2,950,405	125,266,945	$ (2,558,338)
Balances, shares at Sep. 30, 2018		16,896,881
Balances, Treasury shares at Sep. 30, 2018	(145,467)					(145,467)
Net income (loss)	$ 12,735,940				12,735,940
Purchase of treasury stock	(1,140,559)					$ (1,140,559)
Purchase of treasury stock, shares						(74,457)
Restricted stock awards	159,469		159,469
Dividends	(1,347,789)				(1,347,789)
Distribution of restricted stock to officers and directors	160	$ 7	(159,869)			$ 160,022
Distribution of restricted stock to officers and directors, shares		425				9,194
Distribution of deferred directors' compensation			(8)	8
Increase in deferred directors' compensation charged to expense	80,287			80,287
Balances at Dec. 31, 2018	139,252,713	$ 281,509	2,824,283	3,030,700	136,655,096	$ (3,538,875)
Balances, shares at Dec. 31, 2018		16,897,306
Balances, Treasury shares at Dec. 31, 2018						(210,730)
Balances at Sep. 30, 2018	$ 128,765,205	$ 281,502	2,824,691	2,950,405	125,266,945	$ (2,558,338)
Balances, shares at Sep. 30, 2018		16,896,881
Balances, Treasury shares at Sep. 30, 2018	(145,467)					(145,467)
Net income (loss)	$ 15,408,842
Balances at Jun. 30, 2019	$ 136,500,196	$ 281,509	2,937,874	2,481,109	138,662,782	$ (7,863,078)
Balances, shares at Jun. 30, 2019		16,897,306
Balances, Treasury shares at Jun. 30, 2019	(508,582)					(508,582)
Balances at Dec. 31, 2018	$ 139,252,713	$ 281,509	2,824,283	3,030,700	136,655,096	$ (3,538,875)
Balances, shares at Dec. 31, 2018		16,897,306
Balances, Treasury shares at Dec. 31, 2018						(210,730)
Net income (loss)	(1,931,334)				(1,931,334)
Purchase of treasury stock	(2,827,126)					$ (2,827,126)
Purchase of treasury stock, shares						(175,175)
Restricted stock awards	286,852		286,852
Dividends	(381)				(381)
Distribution of restricted stock to officers and directors	75		(73,069)			$ 73,144
Distribution of restricted stock to officers and directors, shares						4,441
Distribution of deferred directors' compensation	(3)		(207,842)	(667,124)		$ 874,963
Distribution of deferred directors' compensation, shares						52,399
Increase in deferred directors' compensation charged to expense	51,993			51,993
Balances at Mar. 31, 2019	134,832,789	$ 281,509	2,830,224	2,415,569	134,723,381	$ (5,417,894)
Balances, shares at Mar. 31, 2019		16,897,306
Balances, Treasury shares at Mar. 31, 2019						(329,065)
Net income (loss)	4,604,236				4,604,236
Purchase of treasury stock	(2,497,501)					$ (2,497,501)
Purchase of treasury stock, shares						(182,901)
Restricted stock awards	159,911		159,911
Dividends	(664,835)				(664,835)
Distribution of restricted stock to officers and directors	56		(52,261)			$ 52,317
Distribution of restricted stock to officers and directors, shares						3,384
Increase in deferred directors' compensation charged to expense	65,540			65,540
Balances at Jun. 30, 2019	$ 136,500,196	$ 281,509	$ 2,937,874	$ 2,481,109	$ 138,662,782	$ (7,863,078)
Balances, shares at Jun. 30, 2019		16,897,306
Balances, Treasury shares at Jun. 30, 2019	(508,582)					(508,582)

XML

Statements Of Stockholders' Equity (Parenthetical) - $ / shares	3 Months Ended
	Jun. 30, 2019	Dec. 31, 2018	Jun. 30, 2018	Dec. 31, 2017
Statement Of Stockholders Equity [Abstract]
Dividends per share	$ 0.04	$ 0.08	$ 0.04	$ 0.08

XML

Condensed Statements Of Cash Flows - USD ($)	9 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Operating Activities
Net income (loss)	$ 15,408,842	$ 14,080,022
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	11,820,705	14,136,411
Provision for deferred income taxes	5,150,000	(12,947,000)
Gain from leasing fee mineral acreage	(951,832)	(1,079,803)
Proceeds from leasing fee mineral acreage	967,337	1,102,818
Net (gain) loss on sales of assets	(13,114,725)	660,597
Directors' deferred compensation expense	197,820	233,573
Fair value of derivative contracts	(6,125,525)	3,819,639
Restricted stock awards	606,232	501,626
Other	15,848	5,113
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables	1,597,667	1,095,996
Other current assets	(859,258)	77,124
Accounts payable	3,270	(125,261)
Income taxes receivable	(476,846)	279,975
Other non-current assets	6,949	(52,644)
Accrued liabilities	86,467	(130,284)
Total adjustments	(1,075,891)	7,577,880
Net cash provided by operating activities	14,332,951	21,657,902
Investing Activities
Capital expenditures	(3,349,640)	(7,743,097)
Acquisition of minerals and overrides	(5,120,466)	(966,279)
Investments in partnerships	(1,648)	3,379
Proceeds from sales of assets	13,114,969	1,085,137
Net cash provided (used) by investing activities	4,643,215	(7,620,860)
Financing Activities
Borrowings under debt agreement	15,053,345	13,529,879
Payments of loan principal	(24,553,345)	(25,352,099)
Purchases of treasury stock	(6,465,186)	(272,100)
Payments of dividends	(2,013,005)	(2,023,500)
Net cash provided (used) by financing activities	(17,978,191)	(14,117,820)
Increase (decrease) in cash and cash equivalents	997,975	(80,778)
Cash and cash equivalents at beginning of period	532,502	557,791
Cash and cash equivalents at end of period	1,530,477	477,013
Supplemental Schedule of Noncash Investing and Financing Activities:
Additions to asset retirement obligations	27,782	15,452
Gross additions to properties and equipment	8,149,347	8,150,830
Net (increase) decrease in accounts payable for properties and equipment additions	320,759	558,546
Capital expenditures and acquisitions	$ 8,470,106	$ 8,709,376

XML

Basis of Presentation and Accounting Principles

9 Months Ended

Jun. 30, 2019

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 2018 Annual Report on Form 10-K.

Certain amounts (loss (gain) on asset sales and other in the Statements of Operations) in the prior years have been reclassified to conform to the current year presentation.

Adoption of New Accounting Pronouncements

Revenue recognition and presentation – In May 2014, the FASB issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes nearly all previously existing revenue recognition guidance under U.S. GAAP. Subsequently, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This new guidance became effective for reporting periods beginning after December 15, 2017. The Company adopted the new revenue recognition and presentation guidance on October 1, 2018, as required. See Note 2: Revenues for discussion of the adoption impact and the applicable disclosures required by the new guidance.

New Accounting Pronouncements yet to be Adopted

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which will supersede the lease requirements in Topic 840, Leases by requiring lessees to recognize lease assets and lease liabilities classified as operating leases on the balance sheet. The new lease standard will be effective for us beginning October 1, 2019, including interim periods within the fiscal year.

The FASB recently issued ASU 2018-11, Leases (Topic 842), Targeted Improvements, which would allow entities to apply the transition provisions of the new standard at the adoption date instead of at the earliest comparative period presented in the consolidated financial statements, and will also allow entities to continue to apply the legacy guidance in Topic 840, including disclosure requirements, in the comparative period presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if any, rather than in the earliest period presented. The Company plans to use a modified retrospective transition method to apply the new standard to leases that exist as of the adoption date of October 1, 2019. The Company does not plan to early adopt.

Based on evaluations to-date, the new guidance will not have a material impact on the Company's consolidated financial statements and related disclosures as this guidance does not apply to leases to explore for or use minerals, oil, natural gas, and similar resources. The Company also plans to elect a policy to not recognize right-of-use assets and lease liabilities related to short-term leases.

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.

XML

Revenues

9 Months Ended

Jun. 30, 2019

Revenue From Contract With Customer [Abstract]

Revenues

NOTE 2: Revenues

Adoption of new revenue recognition and disclosure guidance

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition.

Subsequent to the issuance of ASU 2014-09, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. This guidance requires an entity to record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer.

The Company adopted the new revenue recognition and presentation guidance on 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. The Company chose to use the modified retrospective method upon adoption and has applied the guidance only to contracts that are not complete at the date of initial application. Adoption of the new guidance had no cumulative effect impact on the Company's retained earnings at October 1, 2018.

The standard did not have a material effect on the timing or measurement of the Company's revenue recognition or its financial position, results of operations, net income and cash flows. Additionally, the application of ASU 2016-08’s gross versus net presentation guidance did not impact the Company’s presentation of revenues and expenses. As the Company’s interests in oil and natural gas properties are non-operated interests or royalty interests, the Company evaluated its agreements with operators in connection with the ASC 606 principal versus agent indicators. Consistent with previous conclusions under ASC 605, the Company concluded that the operators act as an agent in the transfer of commodities to third-party customers. This determination required judgment in the application of the guidance for principal versus agent under ASC 606.

Revenues from Contracts with Customers

Oil, NGL and natural gas sales

Sales of oil, NGL and natural gas are recognized at the point in time that control of the product is transferred to the customer and collectability of the sales price is reasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Company receives for natural gas and NGL is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. Each unit of commodity is considered a separate performance obligation, however, as consideration is variable, the Company utilizes the variable consideration allocation exception permitted under the standard to allocate the variable consideration to the specific units of commodity to which they relate.

Lease bonus income

The Company also earns revenue from lease bonuses. The Company generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any oil, NGL or natural gas discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances in accordance with the guidance set forth in ASC 932, and it recognizes the lease bonus as a cost recovery with any excess above its cost basis in the mineral being treated as a gain. The excess of lease bonus above the mineral basis is shown in the lease bonuses and rental income line item on the Company’s Statements of Operations.

Oil and natural gas derivative contracts – See Note 9 for discussion of the Company’s accounting for derivative contracts.

Disaggregation of oil, NGL and natural gas revenues

The following table presents the disaggregation of the Company's oil, NGL and natural gas revenues for the three and nine months ended June 30, 2019.

	Three Months Ended		Nine Months Ended
	June 30, 2019		June 30, 2019
Oil revenue	$	5,523,467	$	13,932,052
NGL revenue		826,282		3,097,479
Natural gas revenue		3,432,588		14,184,844
Oil, NGL and natural gas sales	$	9,782,337	$	31,214,375

Performance obligations

The Company satisfies the performance obligations under its oil and natural gas sales contracts upon delivery of its production and related transfer of title to purchasers. Upon delivery of production, the Company has a right to receive consideration from its purchasers in amounts that correspond with the value of the production transferred.

Allocation of transaction price to remaining performance obligations

Oil, NGL and natural gas sales

As the Company has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company has utilized the practical expedient in ASC 606 which permits the Company to allocate variable consideration to one or more but not all performance obligations in the contract if the terms of the variable payment relate specifically to the Company’s efforts to satisfy that performance obligation and allocating the variable amount to the performance obligation is consistent with the allocation objective under ASC 606. Additionally, the Company will not disclose variable consideration subject to this practical expedient.

Prior-period performance obligations and contract balances

The Company records revenue in the month production is delivered to the purchaser. As a non-operator, the Company has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Oil, NGL and natural gas sales receivables line item in the accompanying balance sheets. The difference between the Company's estimates and the actual amounts received for oil, NGL and natural gas sales is recorded in the quarter that payment is received from the third party. For the three and nine months ended June 30, 2019, and June 30, 2018, revenue recognized in these reporting periods related to performance obligations satisfied in prior reporting periods was immaterial and considered a change in estimate.

XML

Income Taxes

9 Months Ended

Jun. 30, 2019

Income Tax Disclosure [Abstract]

Income Taxes

NOTE 3: Income Taxes

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from 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 are recognized as provision (benefit) for income taxes in the statements of operations.

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, 2019, was a 24% provision as compared to a 1138% benefit for the nine months ended June 30, 2018. The effective tax rate for the quarter ended June 30, 2019, was a 22% provision as compared to a 21% benefit for the quarter ended June 30, 2018.

XML

Basic And Diluted Earnings (Loss) Per Common Share

9 Months Ended

Jun. 30, 2019

Earnings Per Share [Abstract]

Basic And Diluted Earnings (Loss) Per Common Share

NOTE 4: Basic and Diluted Earnings (Loss) per Common Share

Basic and diluted earnings (loss) per common 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. 

XML

Long-Term Debt

9 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Long-Term Debt

NOTE 5: 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 $70,000,000 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 $128,427,806 at June 30, 2019. The interest rate is based on BOK prime plus from 0.50% to 1.25%, or 30-day LIBOR plus from 2.00% to 2.75%. 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, 2019, the effective interest rate was 4.76%.

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 August 6, 2019, the borrowing base was redetermined by the banks and reduced from $80,000,000 to $70,000,000. 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, 2019, the Company was in compliance with the covenants of the loan agreement. Due to the redetermination, the availability under the facility has decreased from $38,500,000 at June 30, 2019, to $28,500,000 currently.

XML

Deferred Compensation Plan For Non-Employee Directors

9 Months Ended

Jun. 30, 2019

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Deferred Compensation Plan For Non-Employee Directors

NOTE 6: 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.

XML

Restricted Stock Plan

9 Months Ended

Jun. 30, 2019

Restricted Stock Plan [Abstract]

Restricted Stock Plan

NOTE 7: 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 stock repurchase 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 the Company to repurchase up to $1.5 million of the Company’s common stock at management’s discretion. The Board added language to clarify that this is intended to be an evergreen program as the repurchase of an additional $1.5 million of the Company’s common stock is authorized and approved whenever the previous amount is utilized. In addition, 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. During the third quarter of 2019, the Company repurchased $2.5 million of the Company’s common stock.

On December 11, 2018, the Company awarded 14,430 non-performance based shares and 43,287 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. Upon vesting, the performance based shares that do not meet the performance criteria are forfeited. The non-performance and performance based shares had a fair value on their award date of $226,840 and $356,567, 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 11, 2018, through December 11, 2021).

On December 31, 2018, the Company awarded 13,548 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, 2019. The restricted stock contains non-forfeitable rights to receive dividends and to vote the shares during the vesting period. These non-performance based shares had a fair value on their award date of $209,994.

The following table summarizes the Company’s pre-tax compensation expense for the three and nine months ended June 30, 2019 and 2018, related to the Company’s performance based and non-performance based restricted stock.

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
Performance based, restricted stock	$	60,406	$	59,869	$	306,685	$	216,403
Non-performance based, restricted stock		99,505		93,919		299,547		285,223
Total compensation expense	$	159,911	$	153,788	$	606,232	$	501,626

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, 2019
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	371,271		1.97
Non-performance based, restricted stock		394,537		1.58
Total	$	765,808

XML

Properties And Equipment

9 Months Ended

Jun. 30, 2019

Property Plant And Equipment [Abstract]

Properties And Equipment

NOTE 8: Properties and Equipment

Divestitures

During the first quarter of 2019, the Company sold 206 net mineral acres and producing oil and natural gas properties located in Lea and Eddy Counties, New Mexico, to a private buyer for total net consideration of $9,096,938 and recorded a gain on the sale of $9,096,938. The cash from the sale was used to reduce the Company’s outstanding bank debt.

During the second quarter of 2019, there were no assets sold.

During the third quarter of 2019, the Company sold 166 net mineral acres and producing oil and natural gas properties located in Martin County, Texas, to private buyers for total net consideration of $4,018,031 and recorded a gain on the sale of $4,017,787. The cash from the sale was used to purchase minerals and reduce the Company’s outstanding bank debt.

Acquisitions

During the first quarter of 2019, the Company acquired 45 net mineral acres (which include producing oil and natural gas properties) in the STACK play in Blaine County, Oklahoma, with undeveloped locations identified in both the Woodford and Meramac Shales for $423,000.

During the second quarter of 2019, the Company acquired 329 net mineral acres (which include producing oil and natural gas properties) in the STACK play in Blaine and Caddo Counties, Oklahoma, for $1,386,775.

During the third quarter of 2019, the Company acquired 313 net mineral acres (which include producing oil and natural gas properties) in the Bakken/Three Forks play in North Dakota and in the STACK play in Blaine County, Oklahoma, for $3,310,691.

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 and nine months ended June 30, 2019 and 2018, the assessment resulted in no impairment provisions on producing properties. A significant reduction in oil, NGL and natural gas prices or a decline in reserve volumes may lead to impairment in future periods that may be material to the Company.

XML

Derivatives

9 Months Ended

Jun. 30, 2019

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivatives

NOTE 9: 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. The Company’s derivative contracts are currently with Bank of Oklahoma and Koch Supply and Trading LP. The derivative contracts with Bank of Oklahoma are secured under the credit facility with Bank of Oklahoma. The derivative contracts with Koch are unsecured. The derivative instruments have settled or will settle based on the prices below.

Derivative contracts in place as of June 30, 2019

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas fixed price swaps
January - July 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.867
July - December 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.960
July - December 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.950
July - December 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.995
July 2019 - March 2020	100,000 Mmbtu	NYMEX Henry Hub	$2.982
August - December 2019	100,000 Mmbtu	NYMEX Henry Hub	$3.004
January - December 2020	80,000 Mmbtu	NYMEX Henry Hub	$2.750
Oil costless collars
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
July - December 2019	3,000 Bbls	NYMEX WTI	$60.00 floor / $70.75 ceiling
July 2019- June 2020	2,000 Bbls	NYMEX WTI	$65.00 floor / $76.15 ceiling
January - June 2020	2,000 Bbls	NYMEX WTI	$60.00 floor / $67.00 ceiling
January - December 2020	2,000 Bbls	NYMEX WTI	$55.00 floor / $62.00 ceiling
Oil fixed price swaps
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
July - December 2019	5,000 Bbls	NYMEX WTI	$58.50
July - December 2019	1,000 Bbls	NYMEX WTI	$60.60
January - December 2020	2,000 Bbls	NYMEX WTI	$55.28
January - December 2020	2,000 Bbls	NYMEX WTI	$58.65
January - December 2020	2,000 Bbls	NYMEX WTI	$60.00

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 asset of $2,711,509 as of June 30, 2019, and a net liability of $3,414,016 as of September 30, 2018. Net cash paid related to derivative contracts settled during the nine-month period ended June 30, 2019, was $1,099,402 compared to net cash paid of $147,230 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, 2019, and September 30, 2018. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at June 30, 2019, and September 30, 2018.

	June 30, 2019								September 30, 2018
	Fair Value (a)								Fair Value (a)
	Commodity Contracts								Commodity Contracts
	Current Assets			Current Liabilities			Non-Current Assets		Current Assets			Current Liabilities			Non-Current Liabilities
Gross amounts recognized	$	2,552,237		$	62,864		$	222,136	$	42,150		$	3,106,196		$	349,970
Offsetting adjustments		(62,864	)		(62,864	)		-		(42,150	)		(42,150	)		-
Net presentation on Condensed Balance Sheets	$	2,489,373		$	-		$	222,136	$	-		$	3,064,046		$	349,970

(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.

XML

Fair Value Measurements

9 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements

NOTE 10: 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, 2019.

	Fair Value Measurement at June 30, 2019
	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	$	-	$	2,281,860	$	-	$	2,281,860
Derivative Contracts - Collars	$	-	$	429,650	$	-	$	429,650

Level 2 – Market Approach - The fair values of the Company’s swaps and collars 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 and volatility 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.

At June 30, 2019, and September 30, 2018, the carrying values of cash and cash equivalents, receivables, and payables are considered to be representative of their respective fair values due to the short-term maturities of those instruments. 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.

XML

Subsequent Events

9 Months Ended

Jun. 30, 2019

Subsequent Events [Abstract]

Subsequent Events

NOTE 11: Subsequent Events

Subsequent to June 30, 2019, the Company sold an additional 383 net mineral and royalty acres in the Permian Basin in Texas for $4,954,832. These proceeds added to our cash position and will be used to finance future acquisitions.

XML

Basis of Presentation and Accounting Principles (Policies)

9 Months Ended

Jun. 30, 2019

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 2018 Annual Report on Form 10-K.

Certain amounts (loss (gain) on asset sales and other in the Statements of Operations) in the prior years have been reclassified to conform to the current year presentation.

Adoption of New Accounting Pronouncements

Adoption of New Accounting Pronouncements

Revenue recognition and presentation – In May 2014, the FASB issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes nearly all previously existing revenue recognition guidance under U.S. GAAP. Subsequently, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This new guidance became effective for reporting periods beginning after December 15, 2017. The Company adopted the new revenue recognition and presentation guidance on October 1, 2018, as required. See Note 2: Revenues for discussion of the adoption impact and the applicable disclosures required by the new guidance.

New Accounting Pronouncements yet to be Adopted

New Accounting Pronouncements yet to be Adopted

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which will supersede the lease requirements in Topic 840, Leases by requiring lessees to recognize lease assets and lease liabilities classified as operating leases on the balance sheet. The new lease standard will be effective for us beginning October 1, 2019, including interim periods within the fiscal year.

The FASB recently issued ASU 2018-11, Leases (Topic 842), Targeted Improvements, which would allow entities to apply the transition provisions of the new standard at the adoption date instead of at the earliest comparative period presented in the consolidated financial statements, and will also allow entities to continue to apply the legacy guidance in Topic 840, including disclosure requirements, in the comparative period presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if any, rather than in the earliest period presented. The Company plans to use a modified retrospective transition method to apply the new standard to leases that exist as of the adoption date of October 1, 2019. The Company does not plan to early adopt.

Based on evaluations to-date, the new guidance will not have a material impact on the Company's consolidated financial statements and related disclosures as this guidance does not apply to leases to explore for or use minerals, oil, natural gas, and similar resources. The Company also plans to elect a policy to not recognize right-of-use assets and lease liabilities related to short-term leases.

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.

XML

Revenues (Tables)

9 Months Ended

Jun. 30, 2019

Revenue From Contract With Customer [Abstract]

Summary of Disaggregation of Oil, NGL and Natural Gas Revenues

The following table presents the disaggregation of the Company's oil, NGL and natural gas revenues for the three and nine months ended June 30, 2019.

	Three Months Ended		Nine Months Ended
	June 30, 2019		June 30, 2019
Oil revenue	$	5,523,467	$	13,932,052
NGL revenue		826,282		3,097,479
Natural gas revenue		3,432,588		14,184,844
Oil, NGL and natural gas sales	$	9,782,337	$	31,214,375

XML

Restricted Stock Plan (Tables)

9 Months Ended

Jun. 30, 2019

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, 2019 and 2018, related to the Company’s performance based and non-performance based restricted stock.

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
Performance based, restricted stock	$	60,406	$	59,869	$	306,685	$	216,403
Non-performance based, restricted stock		99,505		93,919		299,547		285,223
Total compensation expense	$	159,911	$	153,788	$	606,232	$	501,626

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, 2019
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	371,271		1.97
Non-performance based, restricted stock		394,537		1.58
Total	$	765,808

XML

Derivatives (Tables)

9 Months Ended

Jun. 30, 2019

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Summary Of Derivative Instruments Contracts

Derivative contracts in place as of June 30, 2019

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas fixed price swaps
January - July 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.867
July - December 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.960
July - December 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.950
July - December 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.995
July 2019 - March 2020	100,000 Mmbtu	NYMEX Henry Hub	$2.982
August - December 2019	100,000 Mmbtu	NYMEX Henry Hub	$3.004
January - December 2020	80,000 Mmbtu	NYMEX Henry Hub	$2.750
Oil costless collars
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
July - December 2019	3,000 Bbls	NYMEX WTI	$60.00 floor / $70.75 ceiling
July 2019- June 2020	2,000 Bbls	NYMEX WTI	$65.00 floor / $76.15 ceiling
January - June 2020	2,000 Bbls	NYMEX WTI	$60.00 floor / $67.00 ceiling
January - December 2020	2,000 Bbls	NYMEX WTI	$55.00 floor / $62.00 ceiling
Oil fixed price swaps
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
July - December 2019	5,000 Bbls	NYMEX WTI	$58.50
July - December 2019	1,000 Bbls	NYMEX WTI	$60.60
January - December 2020	2,000 Bbls	NYMEX WTI	$55.28
January - December 2020	2,000 Bbls	NYMEX WTI	$58.65
January - December 2020	2,000 Bbls	NYMEX WTI	$60.00

Summary Of Derivative Contracts

	June 30, 2019								September 30, 2018
	Fair Value (a)								Fair Value (a)
	Commodity Contracts								Commodity Contracts
	Current Assets			Current Liabilities			Non-Current Assets		Current Assets			Current Liabilities			Non-Current Liabilities
Gross amounts recognized	$	2,552,237		$	62,864		$	222,136	$	42,150		$	3,106,196		$	349,970
Offsetting adjustments		(62,864	)		(62,864	)		-		(42,150	)		(42,150	)		-
Net presentation on Condensed Balance Sheets	$	2,489,373		$	-		$	222,136	$	-		$	3,064,046		$	349,970

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

XML

Fair Value Measurements (Tables)

9 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

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

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, 2019.

	Fair Value Measurement at June 30, 2019
	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	$	-	$	2,281,860	$	-	$	2,281,860
Derivative Contracts - Collars	$	-	$	429,650	$	-	$	429,650

Level 2 – Market Approach - The fair values of the Company’s swaps and collars 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 and volatility 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.

XML

Revenues (Narrative) (Details) - USD ($)		9 Months Ended
	Oct. 01, 2018	Jun. 30, 2019
Disaggregation Of Revenue [Line Items]
Revenue, practical expedient, financing component		true
Minimum [Member]
Disaggregation Of Revenue [Line Items]
New wells production statements period		30 days
Maximum [Member]
Disaggregation Of Revenue [Line Items]
New wells production statements period		90 days
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | ASU 2014-09, Revenue from Contracts with Customers [Member]
Disaggregation Of Revenue [Line Items]
Cumulative effect on retained earnings	$ 0

XML

Revenues (Summary Of Disaggregation Of Company's Oil, NGL And Natural Gas Revenues) (Details) - USD ($)	3 Months Ended	9 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	$ 9,782,337	$ 31,214,375
Oil [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	5,523,467	13,932,052
NGL [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	826,282	3,097,479
Natural Gas [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	$ 3,432,588	$ 14,184,844

XML

Income Taxes (Narrative) (Details)	3 Months Ended		9 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Effective tax rate	22.00%	(21.00%)	24.00%	(1138.00%)

XML

Long-Term Debt (Details) - Revolving Credit Facility [Member] - USD ($)	9 Months Ended
	Jun. 30, 2019	Aug. 06, 2019
Line Of Credit Facility [Line Items]
Revolving loan credit facility	$ 200,000,000
Credit facility maturity	Nov. 30, 2022
Mortgaged properties net book value	$ 128,427,806
Effective Interest rate	4.76%
Borrowing base of credit facility	$ 80,000,000
Funded debt to EBITDA ratio	400.00%
Availability under outstanding credit facility	$ 38,500,000
Subsequent Event [Member]
Line Of Credit Facility [Line Items]
Borrowing base of credit facility		$ 70,000,000
Availability under outstanding credit facility		$ 28,500,000
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	0.50%
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	2.00%
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%

XML

Deferred Compensation Plan For Non-Employee Directors (Details)	9 Months Ended
	Jun. 30, 2019
Maximum [Member]
Deferred Compensation Plan For Directors [Line Items]
Period outside directors may elect to receive shares	10 years

XML

Restricted Stock Plan (Narrative) (Details) - USD ($)			3 Months Ended
	Dec. 31, 2018	Dec. 11, 2018	Jun. 30, 2019	May 31, 2018	Mar. 31, 2014	Mar. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock repurchased			$ 2,500,000
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		14,430
Fair value of shares awarded		$ 226,840
Non Performance Based Restricted Stock [Member] | Non Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded	13,548
Fair value of shares awarded	$ 209,994
Performance Based Restricted Stock [Member] | Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded		43,287
Fair value of shares awarded		$ 356,567
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

XML

Restricted Stock Plan (Summary Of Pre-Tax Compensation Expense) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 159,911	$ 153,788	$ 606,232	$ 501,626
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	60,406	59,869	306,685	216,403
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 99,505	$ 93,919	$ 299,547	$ 285,223

XML

Restricted Stock Plan (Summary Of Unrecognized Compensation Cost) (Details)	9 Months Ended
	Jun. 30, 2019 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 765,808
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 371,271
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	$ 394,537
Weighted Average Period (in years)	1 year 6 months 29 days

XML

Properties And Equipment (Details)	3 Months Ended				9 Months Ended
	Jun. 30, 2019 USD ($) a	Mar. 31, 2019 USD ($) a	Dec. 31, 2018 USD ($) a	Jun. 30, 2018 USD ($)	Jun. 30, 2019 USD ($) a	Jun. 30, 2018 USD ($)
Property Plant And Equipment [Line Items]
Gain on sale of oil and gas properties	$ 4,017,787				$ 13,114,725
Computation of Oil, Natural Gas and NGL Reserves					12 months
Impairment	$ 0			$ 0	$ 0	$ 0
Lea and Eddy Counties, New Mexico [Member]
Property Plant And Equipment [Line Items]
Mineral acreage sold | a			206
Proceeds from sales of assets			$ 9,096,938
Gain on sale of oil and gas properties			$ 9,096,938
Martin County, Texas [Member]
Property Plant And Equipment [Line Items]
Mineral acreage sold | a	166				166
Proceeds from sales of assets	$ 4,018,031
Gain on sale of oil and gas properties	$ 4,017,787
Blaine County, Oklahoma [Member]
Property Plant And Equipment [Line Items]
Mineral acreage acquired | a			45
Purchase price of mineral acreage acquired			$ 423,000
Blaine and Caddo Counties, Oklahoma [Member]
Property Plant And Equipment [Line Items]
Mineral acreage acquired | a		329
Purchase price of mineral acreage acquired		$ 1,386,775
Bakken/Three Forks, Dakota and STACK Blaine County, Oklahoma [Member]
Property Plant And Equipment [Line Items]
Mineral acreage acquired | a	313
Purchase price of mineral acreage acquired	$ 3,310,691

XML

Derivatives (Summary Of Derivative Instruments Contracts) (Details)	Jun. 30, 2019 MMBTU $ / MMBTU $ / bbl bbl
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period One [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price | $ / MMBTU	2.867
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Two [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price | $ / MMBTU	2.960
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Three [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price | $ / MMBTU	2.950
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Four [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price | $ / MMBTU	2.995
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Five [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price | $ / MMBTU	2.982
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Six [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price | $ / MMBTU	3.004
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Seven [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	80,000
Contract price | $ / MMBTU	2.750
Oil Costless Collars [Member] | Derivative Contract Period Nine [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	1,000
Oil Costless Collars [Member] | Derivative Contract Period Nine [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	50.00
Oil Costless Collars [Member] | Derivative Contract Period Nine [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	60.00
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	60.00
Oil Costless Collars [Member] | Derivative Contract Period Ten [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	69.25
Oil Costless Collars [Member] | Derivative Contract Period Eleven [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	3,000
Oil Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	60.00
Oil Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	70.75
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	65.00
Oil Costless Collars [Member] | Derivative Contract Period Twelve [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	76.15
Oil Costless Collars [Member] | Derivative Contract Period Thirteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Thirteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	60.00
Oil Costless Collars [Member] | Derivative Contract Period Thirteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	67.00
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	62.00
Oil Fixed Price Swaps [Member] | Derivative Contract Period Fifteen [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 Sixteen [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 Seventeen [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 Eighteen [Member]
Derivative [Line Items]
Contract price	56.85
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Nineteen [Member]
Derivative [Line Items]
Contract price	58.50
Production volume covered per month - Oil | bbl	5,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty [Member]
Derivative [Line Items]
Contract price	60.60
Production volume covered per month - Oil | bbl	1,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty One [Member]
Derivative [Line Items]
Contract price	55.28
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	58.65
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	60.00
Production volume covered per month - Oil | bbl	2,000

XML

Derivatives (Narrative) (Details) - USD ($)	9 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Sep. 30, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Fair value of derivative contracts, liability			$ 3,414,016
Fair value of derivative contracts, asset	$ 2,711,509
Net cash paid related to derivative contracts settled	$ 1,099,402	$ 147,230

XML

Derivatives (Summary Of Derivative Contracts) (Details) - USD ($)		Jun. 30, 2019	Sep. 30, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gross amounts recognized - Current Assets	[1]	$ 2,552,237	$ 42,150
Offsetting adjustments - Current Assets	[1]	(62,864)	(42,150)
Net presentation on Condensed Balance Sheets - Current Assets	[1]	2,489,373
Gross amounts recognized - Non-Current Assets	[1]	222,136
Net presentation on Condensed Balance Sheets - Non-Current Assets	[1]	222,136
Gross amounts recognized - Current Liabilities	[1]	62,864	3,106,196
Offsetting adjustments - Current Liabilities	[1]	$ (62,864)	(42,150)
Net presentation on Condensed Balance Sheets - Current Liabilities	[1]		3,064,046
Gross amounts recognized - Non-Current Liabilities	[1]		349,970
Net presentation on Condensed Balance Sheets - Non-Current Liabilities	[1]		$ 349,970

[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, 2019 USD ($)
Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	$ 2,281,860
Swap [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	2,281,860
Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	429,650
Collars [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	$ 429,650

XML

Subsequent Events (Details) - Permian Basin in Texas [Member]	1 Months Ended	3 Months Ended
	Aug. 08, 2019 USD ($) a	Jun. 30, 2019 USD ($)
Subsequent Event [Line Items]
Proceeds from sales of assets		$ 4,018,031
Subsequent Event [Member]
Subsequent Event [Line Items]
Mineral and royalty acreage sold | a	383
Proceeds from sales of assets	$ 4,954,832