phx-10q_20191231.htm

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):

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 February 5, 2020: 16,344,169

“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.

“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.

“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.

“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.

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

“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.

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

“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.

“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.

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 2020 mean the fiscal year ended September 30, 2020.

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 inherently include natural gas liquids associated with such properties.

	December 31, 2019			September 30, 2019
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	268,707		$	6,160,691
Oil, NGL and natural gas sales receivables (net of allowance for uncollectable accounts)		4,321,486			4,377,646
Refundable income taxes		1,917,515			1,505,442
Derivative contracts, net		774,106			2,256,639
Other		776,672			177,037
Total current assets		8,058,486			14,477,455

Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties		358,110,146			354,718,398
Non-producing oil and natural gas properties		19,131,441			14,599,023
Other		1,731,037			1,722,080
		378,972,624			371,039,501
Less accumulated depreciation, depletion and amortization		(260,155,491	)		(259,314,590	)
Net properties and equipment		118,817,133			111,724,911

Investments		202,172			205,076

Derivative contracts, net		371			237,505

Total assets	$	127,078,162		$	126,644,947

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	670,175		$	665,160
Accrued liabilities and other		1,824,408			2,433,466
Total current liabilities		2,494,583			3,098,626

Long-term debt		35,000,000			35,425,000
Deferred income taxes, net		6,634,007			5,976,007
Asset retirement obligations		2,840,639			2,835,781

Stockholders' equity:
Class A voting common stock, $0.01666 par value; 24,000,000 shares authorized; 16,897,306 issued at December 31, 2019, and at September 30, 2019		281,509			281,509
Capital in excess of par value		3,033,678			2,967,984
Deferred directors' compensation		2,641,993			2,555,781
Retained earnings		82,420,516			81,848,301
		88,377,696			87,653,575
Less treasury stock, at cost; 553,137 shares at December 31, 2019, and 558,051 shares at September 30, 2019		(8,268,763	)		(8,344,042	)
Total stockholders' equity		80,108,933			79,309,533
Total liabilities and stockholders' equity	$	127,078,162		$	126,644,947

	Three Months Ended December 31,
	2019			2018
Revenues:	(unaudited)
Oil, NGL and natural gas sales	$	7,593,838		$	12,210,719
Lease bonuses and rental income		527,699			514,557
Gains (losses) on derivative contracts		(817,894	)		4,506,780
Gain on asset sales		3,272,888			9,096,938
		10,576,531			26,328,994
Costs and expenses:
Lease operating expenses		2,564,672			3,104,570
Production taxes		327,281			608,951
Depreciation, depletion and amortization		2,955,701			3,813,686
Interest expense		370,665			539,370
General and administrative		2,223,028			1,938,840
Loss on asset sales and other expense (income)		(10,930	)		16,637
		8,430,417			10,022,054
Income (loss) before provision (benefit) for income taxes		2,146,114			16,306,940

Provision (benefit) for income taxes		254,000			3,571,000

Net income (loss)	$	1,892,114		$	12,735,940




Basic and diluted earnings (loss) per common share (Note 5)	$	0.11		$	0.75

Basic and diluted weighted average shares outstanding:
Common shares		16,339,673			16,745,076
Unissued, directors' deferred compensation shares		180,864			213,932
		16,520,537			16,959,008




Dividends declared per share of common stock and paid in period	$	0.04		$	0.04

Dividends declared per share of
common stock and to be paid in quarter ended March 31	$	0.04		$	0.04

	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, 2019		16,897,306	$	281,509	$	2,967,984		$	2,555,781	$	81,848,301			(558,051	)	$	(8,344,042	)	$	79,309,533

Net income (loss)		-		-		-			-		1,892,114			-			-			1,892,114
Purchase of treasury stock		-		-		-			-		-			(632	)		(7,635	)		(7,635	)
Restricted stock awards		-		-		148,515			-					-			-			148,515
Dividends ($0.08 per share)		-		-		-			-		(1,319,899	)		-			-			(1,319,899	)
Distribution of restricted stock to officers and directors		-		-		(82,821	)		-		-			5,546			82,914			93
Increase in deferred directors' compensation charged to expense		-		-		-			86,212		-			-			-			86,212
Balances at December 31, 2019		16,897,306	$	281,509	$	3,033,678		$	2,641,993	$	82,420,516			(553,137	)	$	(8,268,763	)	$	80,108,933
(unaudited)

	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
(unaudited)

	Three months ended December 31,
	2019			2018
Operating Activities	(unaudited)
Net income (loss)	$	1,892,114		$	12,735,940

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		2,955,701			3,813,686
Provision for deferred income taxes		658,000			4,314,000
Gain from leasing fee mineral acreage		(523,384	)		(514,557	)
Proceeds from leasing fee mineral acreage		537,777			528,374
Net (gain) loss on sales of assets		(3,272,888	)		(9,096,938	)
Directors' deferred compensation expense		86,213			80,287
Fair value of derivative contracts		1,719,667			(6,206,181	)
Restricted stock awards		148,515			159,469
Other		8,896			7,163
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables		56,160			(77,414	)
Other current assets		(407,610	)		(261,308	)
Accounts payable		(73,831	)		(2,971	)
Income taxes receivable		(412,073	)		(754,153	)
Other non-current assets		1,090			28,899
Accrued liabilities		(1,275,906	)		(744,553	)
Total adjustments		206,327			(8,726,197	)
Net cash provided by operating activities		2,098,441			4,009,743

Investing Activities
Capital expenditures		(105,265	)		(1,445,939	)
Acquisition of minerals and overrides		(10,172,594	)		(423,000	)
Proceeds from sales of assets		3,376,049			9,096,938
Net cash provided (used) by investing activities		(6,901,810	)		7,227,999

Financing Activities
Borrowings under debt agreement		4,774,297			3,832,557
Payments of loan principal		(5,199,297	)		(13,332,557	)
Purchases of treasury stock		(7,635	)		(1,140,559	)
Payments of dividends		(655,980	)		(673,892	)
Net cash provided (used) by financing activities		(1,088,615	)		(11,314,451	)

Increase (decrease) in cash and cash equivalents		(5,891,984	)		(76,709	)
Cash and cash equivalents at beginning of period		6,160,691			532,502
Cash and cash equivalents at end of period	$	268,707		$	455,793

Supplemental Schedule of Noncash Investing and Financing Activities:

Dividends declared and unpaid	$	663,919		$	673,897
Additions to asset retirement obligations	$	4		$	5,371

Gross additions to properties and equipment	$	10,164,680		$	1,894,741

Net (increase) decrease in accounts payable for properties and equipment additions		113,179			(25,802	)
Capital expenditures and acquisitions	$	10,277,859		$	1,868,939

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 2019 Annual Report on Form 10-K.

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. See Note 2: Impact of ASC 842 Adoption for further details related the Company’s adoption of this standard.

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 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.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. This standard will be effective for Panhandle starting October 1, 2020. The Company is evaluating the new standard and is currently in the process of estimating its financial statement impact at this time; however, the impact is not expected to be material. Historically, the Company's credit losses on oil, NGL and natural gas sales receivables have been immaterial.

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.

On October 1, 2019, the Company adopted ASU 2016-02, Leases (Topic 842) using the modified retrospective method. This ASU, as subsequently amended by ASU 2081-01, ASU 2018-10, ASU 2018-11, ASU 2018-20, requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under the previous guidance. The Company elected the adoption practical expedient under ASU2018-11, and used October 1, 2019, the beginning of the period of adoption, as its date of initial application. The Company elected the set of practical expedients upon transition which will retain the lease classification for leases and any unamortized initial direct costs that existed prior to the adoption of the standard.

The Company’s operating lease right-of-use (“ROU”) assets and operating lease obligations were less than 1% of the Company's total assets as of December 31, 2019, had remaining terms of less than 12 months and were not considered material to the Company; and therefore the adoption of the standard had no related impact on the balance sheets as of October 1, 2019. There was no related impact on the statement of operations. The standard had no impact on the Company’s debt covenant compliance under existing agreements.

The Company determines if an arrangement is a lease at inception by considering whether (i) explicitly or implicitly identified assets have been deployed in the agreement and (ii) the Company obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the agreement. As of December 31, 2019, none of the Company’s leases were classified as financing leases. Operating lease liabilities represent the Company’s obligation to make lease payments arising from the lease.

ROU assets represent the Company’s right to use an underlying asset for the lease term and operating lease liabilities represent the Company’s obligation to make lease payments arising from the lease. ROU assets are recognized at commencement date and consist of the present value of remaining lease payments over the lease term, initial direct costs, prepaid lease payments less any lease incentives. Operating lease liabilities are recognized at commencement date based on the present value of remaining lease payments over the lease term. The Company uses the implicit rate, when readily determinable, or its incremental borrowing rate based on the information available at commencement date to determine the present value of lease payments.

The lease terms may include periods covered by options to extend the lease when it is reasonably certain that the Company will exercise that option and periods covered by options to terminate the lease when it is not reasonably certain that the Company will exercise that option. Lease expense for lease payments will be recognized on a straight-line basis over the lease term. The Company made an accounting policy election to not recognize leases with terms, including applicable options, of less than twelve months on the balance sheets and recognize those lease payments in the statements of operations on a straight-line basis over the lease term. In the event that the Company’s assumptions and expectations change, it may have to revise its ROU assets and operating lease liabilities.

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 10 for discussion of the Company’s accounting for derivative contracts.

Sales of oil, NGL and natural gas are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. 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.

The following table presents the disaggregation of the Company's oil, NGL and natural gas revenues for the three months ended December 31, 2019 and 2018.

	Three Months Ended December 31, 2019
	Royalty Interest		Working Interest		Total
Oil revenue	$	1,413,211	$	2,052,301	$	3,465,512
NGL revenue		222,777		392,106	$	614,883
Natural gas revenue		1,273,113		2,240,330	$	3,513,443
Oil, NGL and natural gas sales	$	2,909,101	$	4,684,737	$	7,593,838


	Three Months Ended December 31, 2018
	Royalty Interest		Working Interest		Total
Oil revenue	$	2,294,102	$	2,184,878	$	4,478,980
NGL revenue		441,227		1,013,608	$	1,454,835
Natural gas revenue		2,031,112		4,245,792	$	6,276,904
Oil, NGL and natural gas sales	$	4,766,441	$	7,444,278	$	12,210,719

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.

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.

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 months ended December 31, 2019, and December 31, 2018, revenue recognized in these reporting periods related to performance obligations satisfied in prior reporting periods was immaterial and considered a change in estimate.

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 quarter ended December 31, 2019, was a 12% provision as compared to a 22% provision for the quarter ended December 31, 2018.

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.

The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a borrowing base of $70,000,000 at December 31, 2019, a current borrowing base of $45,000,000 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 $66,360,004 at December 31, 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 December 31, 2019, the effective interest rate was 3.95%.

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 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 January 31, 2020, the borrowing base was redetermined by the banks and reduced from $70,000,000 to $45,000,000. The drop in the borrowing base was mostly due to the continued decline in natural gas futures prices. To a lesser extent, the Company’s strategic decision to cease participating with a working interest going forward and the removal of all working interest PUDs as of September 30, 2019, also caused a reduction. 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 December 31, 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 $35,000,000 at December 31, 2019, to $11,250,000 currently.

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.

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.

On December 11, 2019, the Company awarded 10,038 time-based shares and 15,058 market-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 market-based shares that do not meet certain market performance criteria are forfeited. The time-based and market-based shares had a fair value on their award date of $122,062 and $160,401, respectively. The fair value for the time-based and the market-based awards will be recognized as compensation expense ratably over the vesting period. The fair value of the market-based shares on their award date is calculated by simulating the Company’s stock prices as compared to the S&P Oil & Gas Exploration & Production ETF (XOP) prices utilizing a Monte Carlo model covering the market performance period (December 11, 2019, through December 11, 2022).

Compensation expense for the restricted stock awards is recognized in G&A. Forfeitures of awards are recognized when they occur. The dilutive impact of all restricted stock plans is immaterial for all periods presented.

The following table summarizes the Company’s pre-tax compensation expense for the three months ended December 31, 2019 and 2018, related to the Company’s market-based and time-based restricted stock.

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

Subsequent to quarter end, additional time-based shares, market-based shares, and performance-based shares were granted to officers and directors, that will result in approximately $430,000 of additional expense in second quarter of 2020, of which approximately $307,000 is non-recurring.

On November 14, 2019, Panhandle closed on the sale of 530 net mineral acres in Eddy County, New Mexico, for $3.4 million. At the time of sale, the assets were mostly amortized and therefore had minimal net book value. Almost all of the value received was a gain on the sale of assets ($3.3 million) in the first quarter of 2020. The Company utilized a like-kind exchange under IRS Code 1031 to defer income tax on all of the gain by offsetting it with the STACK/SCOOP mineral acreage acquisition that was purchased during the quarter using qualified exchange accommodation agreements.

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 $9.1 million and recorded a gain on the sale of $9.1 million. The cash from the sale was used to reduce the Company’s outstanding bank debt.

On December 18, 2019, Panhandle closed on the purchase of 700 net mineral acres in Kingfisher, Canadian and Garvin Counties, Oklahoma, for a purchase price of $9.3 million (after normal closing adjustments).

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.

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.

All long-lived assets, principally oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as: inflation rates; future drilling and completion costs; future sales prices for oil, NGL and natural gas; future production costs; estimates of future oil, NGL and natural gas reserves to be recovered and the timing thereof; the economic and regulatory climates and other factors. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil, NGL and natural gas reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations to reflect any material changes since the prior report was issued and then utilizes updated projected future price decks current with the period. For both the three months ended December 31, 2019 and 2018, the assessment resulted in no impairment provisions on producing properties. A further 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. Specifically, we have fields with approximately $25 million net book value at risk of impairment if forward natural gas prices were to decrease $0.10 on average over the life of the reserves.

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.

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
April - October 2020	100,000 Mmbtu	NYMEX Henry Hub	$2.20 floor / $2.59 ceiling
Natural gas fixed price swaps
July 2019 - March 2020	100,000 Mmbtu	NYMEX Henry Hub	$2.982
January - December 2020	80,000 Mmbtu	NYMEX Henry Hub	$2.750
April - October 2020	100,000 Mmbtu	NYMEX Henry Hub	$2.405
November 2020 - March 2021	100,000 Mmbtu	NYMEX Henry Hub	$2.661
Oil costless collars
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 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
January - December 2020	2,000 Bbls	NYMEX WTI	$58.05
July - December 2020	2,000 Bbls	NYMEX WTI	$58.10

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 $774,477 as of December 31, 2019, and a net asset of $2,494,144 as of September 30, 2019. Net cash received related to derivative contracts settled during the three-month period ended December 31, 2019, was $901,773 compared to net cash paid of $1,699,401 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 December 31, 2019, and September 30, 2019. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at December 31, 2019, and September 30, 2019.

	December 31, 2019								September 30, 2019
	Fair Value (a)								Fair Value (a)
	Commodity Contracts								Commodity Contracts
	Current Assets			Current Liabilities			Non-Current Assets		Current Assets		Non-Current Assets
Gross amounts recognized	$	883,167		$	(109,061	)	$	371	$	2,256,639	$	237,505
Offsetting adjustments		(109,061	)		109,061			-		-		-
Net presentation on Condensed Balance Sheets	$	774,106		$	-		$	371	$	2,256,639	$	237,505

(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.

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 December 31, 2019.

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 December 31, 2019, and September 30, 2019, 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.

Subsequent to December 31, 2019, the borrowing base under the credit facility was redetermined on January 31, 2020, and reduced from $70 million to $45 million. The drop in the borrowing base was mostly due to the continued decline in natural gas futures prices. To a lesser extent, the Company’s strategic decision to cease participating with a working interest going forward and the removal of all working interest PUDs as of September 30, 2019, also caused a reduction. Even though the borrowing base was reduced, we do not expect that it will impact the liquidity needed to maintain our normal operating strategies. See additional discussion in MD&A.

Forward-Looking Statements for fiscal 2020 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 2019 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.

THREE MONTHS ENDED DECEMBER 31, 2019 – COMPARED TO THREE MONTHS ENDED DECEMBER 31, 2018

The Company recorded first quarter 2020 net income of $1,892,114, or $0.11 per share, as compared to net income of $12,735,940, or $0.75 per share, in the 2019 quarter. The change in net income (loss) was principally the result of decreased gain on assets sales, decreased gains on derivative contracts, and decreased oil, NGL and natural gas sales; partially offset by decreased LOE, DD&A, production taxes and changes in tax provision (benefit). These items are further discussed below.

Oil, NGL and natural gas sales decreased $4,616,881 or 38% for the 2020 quarter. Oil, NGL and natural gas sales were down due to decreased oil, NGL and natural gas sales volumes of 20%, 37% and 13%, respectively, and decreases in oil, NGL and natural gas prices of 3%, 33% and 36%, respectively. The following table outlines the Company’s production and average sales prices for oil, NGL and natural gas for the three-month periods of fiscal 2020 and 2019:

	Oil Bbls		Average		NGL Bbls		Average		Mcf		Average		Mcfe		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Three months ended
12/31/2019		65,880	$	52.60		39,230	$	15.67		1,647,827	$	2.13		2,278,487	$	3.33
12/31/2018		82,828	$	54.08		62,262	$	23.37		1,893,990	$	3.31		2,764,530	$	4.42

The oil production decrease is a result of naturally declining production in the Eagle Ford Shale and STACK and mineral sales in Martin County, Texas, and Lea and Eddy Counties, New Mexico. These decreases were partially offset by seven new wells in

the Eagle Ford that began producing in third quarter 2019 and mineral acquisitions in the Bakken. 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, and to a lesser extent, the sale of minerals in New Mexico. Decreased natural gas production is due to naturally declining production in the Anadarko STACK, Arkoma Stack and Fayetteville Shale.

Quarter ended	Oil Bbls Sold		NGL Bbls Sold		Mcf Sold		Mcfe Sold
12/31/2019		65,880		39,230		1,647,827		2,278,487
9/30/2019		75,934		52,219		1,786,167		2,555,085
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

Quarter ended	Oil Bbls Sold		NGL Bbls Sold		Mcf Sold		Mcfe Sold
12/31/2019		25,701		11,402		562,813		785,431
9/30/2019		28,411		16,323		591,773		860,177
6/30/2019		27,895		15,797		526,138		788,290
3/31/2019		30,587		11,959		515,179		770,455
12/31/2018		37,056		19,244		592,077		929,877

Quarter ended	Oil Bbls Sold		NGL Bbls Sold		Mcf Sold		Mcfe Sold
12/31/2019		40,179		27,828		1,085,014		1,493,056
9/30/2019		47,523		35,896		1,194,394		1,694,908
6/30/2019		68,170		38,106		1,192,423		1,830,079
3/31/2019		43,785		35,916		1,172,864		1,651,070
12/31/2018		45,772		43,018		1,301,913		1,834,653

The fair value of derivative contracts was a net asset of $774,477 as of December 31, 2019, and a net asset of $2,792,165 as of December 31, 2018. We had a net loss on derivative contracts of $817,894 in the 2020 quarter as compared to a net gain of $4,506,780 in the 2019 quarter. During the 2020 quarter, the oil collars and fixed price swaps experienced an unfavorable change as NYMEX oil futures experienced an increase 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 2020 quarter. During the 2019 quarter, the oil collars and fixed price swaps experienced a favorable change as the NYMEX futures prices (at that time) decreased from where they were at the beginning of the 2019 quarter. The Company utilizes derivative contracts for the purpose of protecting its return on investments and cash flow.

During the 2020 quarter, the Company sold 530 net mineral acres in Eddy County, New Mexico, for a gain of $3,272,888. In the 2019 quarter, the Company sold mineral acreage in Lea and Eddy Counties, New Mexico, for a gain of $9,096,938.

Total LOE decreased $539,898 or 17% in the 2020 quarter. LOE per Mcfe increased in the 2020 quarter to $1.13 compared to $1.12 in the 2019 quarter. LOE related to field operating costs decreased $332,882 or 22% in the 2020 quarter compared to the 2019 quarter. Field operating costs were $0.52 per Mcfe in the 2020 quarter as compared to $0.55 per Mcfe in the 2019 quarter. The

decrease in rate in the 2020 quarter was principally the result of lower costs in the Eagle Ford and lower workovers costs, as the Company is going non-consent on most workover AFE’s. The Company also sold marginal producing properties with high operating costs in fourth quarter of 2019 and the first quarter of 2020.

The decrease in LOE related to field operating costs was coupled with a decrease in handling fees (primarily gathering, transportation and marketing costs) of $207,016 in the 2020 quarter compared to the 2019 quarter. This decrease in costs was primarily driven by lower production in the 2020 quarter compared to the 2019 quarter. On a per Mcfe basis, these handling fees were $0.61 in the 2020 quarter as compared to $0.57 in the 2019 quarter. The increase in rate was primarily due to natural gas production with lower handling fees (royalty production) declining in the 2020 quarter. Natural gas sales bear the large majority of the handling fees while oil sales incur a much smaller amount. Most handling fees are charged based on production volumes but some fees are calculated as a percent of sales.

DD&A decreased $857,985 or 22% in the 2020 quarter. DD&A in the 2020 quarter was $1.30 per Mcfe as compared to $1.38 per Mcfe in the 2019 quarter. DD&A decreased $670,499 as a result of production decreasing 18% in the 2020 quarter compared to the 2019 quarter. An additional decrease of $187,486 was the result of the $0.08 decrease in the DD&A rate per Mcfe. The rate decrease was mainly due to the impairment taken on the Eagle Ford at the end of fiscal 2019, which lowered the basis of the assets. The rate decrease was partially offset by lower oil, NGL and natural gas prices utilized in the reserve calculations during the 2020 quarter, as compared to 2019 quarter, shortening the economic life of wells. This resulted in lower projected remaining reserves on a significant number of wells causing increased units of production DD&A.

Interest expense decreased $168,705 or 31% in the 2020 quarter. The decrease was the result of lower average outstanding debt balances during the 2020 quarter.

G&A increased $284,188 or 15% in the 2020 quarter. The increase was primarily the result of technical consulting, legal expenses and timing of billings of work performed by outside firms. The increase in technical consulting was due to increased cost for geologic and engineering fees. The increase in legal was primarily due to additional work provided pertaining to the Company’s strategy change.

Income taxes changed $3,317,000, from a $3,571,000 provision in the 2019 quarter to a $254,000 provision in the 2020 quarter. The effective tax rate changed from a 22% provision in the 2019 quarter to a 12% provision in the 2020 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.

The Company had positive working capital of $5,563,903 at December 31, 2019, compared to positive working capital of $11,378,829 at September 30, 2019. The change in working capital was mainly due to the change in cash from sales and purchases and the net change in receivables (payables) for derivative contracts.

Cash and cash equivalents were $268,707 as of December 31, 2019, compared to $6,160,691 at September 30, 2019, a decrease of $5,891,984. Cash flows for the three months ended December 31 are summarized as follows:

Net cash provided by operating activities decreased $1,911,302 during the 2020 period, as compared to the 2019 period, primarily the result of the following:

Net cash provided by investing activities decreased $14,129,809 during the 2020 period, as compared to the 2019 period, primarily due to lower net proceeds from the sale of assets of $5,720,889 and higher acquisition costs of $9,749,594, partially offset by lower payments of $1,340,674 for drilling and completion activity during 2020.

Net cash used by financing activities decreased $10,225,836 during the 2020 period, as compared to the 2019 period, primarily the result of lower net payments on long-term debt of $9,075,000 and decreased stock repurchases of $1,132,924.

Capital expenditures to drill and complete wells decreased $1,340,674 (93%) from the 2019 to the 2020 period. The Company currently has no remaining commitments that would require significant capital to drill and complete.

At the end of 2019, the Company made the strategic decision to cease taking any working interest positions on its mineral or leasehold acreage going forward. The Company plans to focus on growth through mineral acquisitions and through development of its significant mineral acreage inventory in its core areas of focus. The Company believes that this is the best path to giving our stockholders the greatest risk-weighted returns on their investments going forward.

Since the Company has decided to cease any further participation in wells with a working interest on its mineral and leasehold acreage, we anticipate that capital expenditures for working interest properties to be minimal going forward, as the expenditures will be limited to capital workovers to enhance existing wells.

The Company plans to focus on growing its assets through acquisitions of mineral acreage. We have a significant inventory of leased and unleased locations in the core of our major focus areas, which we believe will generate future revenue streams from bonus and royalty payments.

The Company received lease bonus payments during the 2020 first quarter totaling $537,777. The Company has been actively marketing its open acreage in STACK/SCOOP to lease since the third quarter of 2019. Looking forward, the cash flow from bonus payments associated with the leasing of drilling rights on the Company’s mineral acreage is difficult to project as the Company’s mineral acreage position is diverse and spread across several states and oil and gas plays. However, management plans to continue to actively pursue leasing opportunities. The Company may also evaluate the sale of certain of the Company’s mineral acres when valuations are greater than our internal estimates of present value are presented.

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 10: 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:

Outstanding borrowings on the credit facility at December 31, 2019, were $35,000,000.

Looking forward, the Company expects to fund overhead costs 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. Any acquisitions of minerals would be funded with a combination of cash on hand, bank debt and equity. The Company had availability of $35 million at December 31, 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.

Subsequent to December 31, 2019, the borrowing base under the credit facility was redetermined on January 31, 2020, and reduced from $70 million to $45 million. The drop in the borrowing base was primarily due to the continued decline in natural gas futures prices and, to a lesser extent, the Company’s strategic decision to cease participating with a working interest going forward and the corresponding removal of all working interest PUDs as of September 30, 2019. Despite the reduction in the borrowing base, we do not expect that it will impact the liquidity needed to maintain our normal operating strategies (current availability of $11,250,000).

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.

Going forward, we expect that capital expenditures to drill and complete wells will be immaterial. Based on anticipated cash provided by operating activities for 2020 and availability under its credit facility, the Company has sufficient liquidity to fund its ongoing operations.

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 842 on October 1, 2019, (see Note 2: Impact of ASC 842 Adoption) 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, 2019.

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 2020 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 2020 derivative contracts, the price sensitivity in 2020 for each $1.00 per barrel change in wellhead oil price is $329,199 for operating revenue based on the Company’s prior year oil volumes. The price sensitivity in 2020 for each $0.10 per Mcf change in wellhead natural gas price is $708,676 for operating revenue based on the Company’s prior year natural gas volumes.

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 $120,000. 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 $56,000. 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 $138,000. For the Company’s natural gas collars, a change of $.10 (below or above the collar) in the NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $7,000.

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 December 31, 2019, the Company had $35,000,000 outstanding under this facility and the effective interest rate was 3.95%. 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 to fund its ongoing operations will be significantly impacted in the near future.

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 Chief Executive Officer and Vice President/Chief Financial Officer and Controller, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating its disclosure controls and procedures, management recognized that no matter how well conceived and operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. The Company’s disclosure controls and procedures have been designed to meet, and management believes they do meet, reasonable assurance standards. Based on their evaluation as of the end of the fiscal period covered by this report, the Chief Executive Officer and Chief Financial Officer have concluded, subject to the limitations noted above, the Company’s disclosure controls and procedures were effective to ensure material information relating to the Company is made known to them. There were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting made during the fiscal quarter or subsequent to the date the assessment was completed.

During the three months ended December 31, 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
10/1 - 10/31/19		-	$	-		-	$	727,128
11/1- 11/30/19		-	$	-		-	$	727,128
12/1 - 12/31/19		632	$	12.08		632	$	719,493
Total		632	$	-		632

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.

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.


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class A Common Stock, $0.01666 par value	PHX	New York Stock Exchange

Part I	Financial Information		Page

	Item 1	Condensed Financial Statements	1

		Condensed Balance Sheets – December 31, 2019, and September 30, 2019	1

		Condensed Statements of Operations – Three months ended December 31, 2019 and 2018	2

		Statements of Stockholders’ Equity – Three months ended December 31, 2019 and 2018	3

		Condensed Statements of Cash Flows – Three months ended December 31, 2019 and 2018	4

		Notes to Condensed Financial Statements	5

	Item 2	Management's discussion and analysis of financial condition and results of operations	13

	Item 3	Quantitative and qualitative disclosures about market risk	18

	Item 4	Controls and procedures	18

Part II	Other Information

	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	19

	Item 6	Exhibits	19

	Signatures		20

	Three Months Ended
	December 31,
	2019		2018
Market-based, restricted stock	$	74,142	$	63,537
Time-based, restricted stock		74,373		95,932
Total compensation expense	$	148,515	$	159,469

	As of December 31, 2019
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Market-based, restricted stock	$	191,851		2.37
Time-based, restricted stock		213,789		2.37
Total	$	405,640

	Fair Value Measurement at December 31, 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	$	-	$	647,842	$	-	$	647,842
Derivative Contracts - Collars	$	-	$	126,635	$	-	$	126,635

	2019			2018			Change

Operating activities	$	2,098,441		$	4,009,743		$	(1,911,302	)
Investing activities		(6,901,810	)		7,227,999			(14,129,809	)
Financing activities		(1,088,615	)		(11,314,451	)		10,225,836
Increase (decrease) in cash and cash equivalents	$	(5,891,984	)	$	(76,709	)	$	(5,815,275	)

	Three months ended
	December 31, 2019
Cash provided by operating activities	$	2,098,441
Cash provided (used) by:

Capital expenditures – acquisitions		(10,172,594	)
Capital expenditures – drilling and completion of wells		(105,265	)
Quarterly dividends of $0.04 per share		(655,980	)
Treasury stock purchases		(7,635	)
Net borrowings (payments) on credit facility		(425,000	)
Proceeds from sale of assets		3,376,049
Net cash used		(7,990,425	)

Net increase (decrease) in cash	$	(5,891,984	)

(a)	EXHIBITS	Exhibit 31.1 – Certification under Section 302 of the Sarbanes-Oxley Act of 2002
		Exhibit 31.2 – Certification under Section 302 of the Sarbanes-Oxley Act of 2002
		Exhibit 32.1 – Certification under Section 906 of the Sarbanes-Oxley Act of 2002
		Exhibit 32.2 – Certification under Section 906 of the Sarbanes-Oxley Act of 2002
		Exhibit 101.INS – XBRL Instance Document
		Exhibit 101.SCH – XBRL Taxonomy Extension Schema Document
		Exhibit 101.CAL – XBRL Taxonomy Extension Calculation Linkbase Document
		Exhibit 101.LAB – XBRL Taxonomy Extension Labels Linkbase Document
		Exhibit 101.PRE – XBRL Taxonomy Extension Presentation Linkbase Document
		Exhibit 101.DEF – XBRL Taxonomy Extension Definition Linkbase Document

PANHANDLE OIL AND GAS INC.
		PANHANDLE OIL AND GAS INC.

February 5, 2020		/s/ Chad L. Stephens
Date		Chad L. Stephens,
		Chief Executive Officer

February 5, 2020		/s/ Robb P. Winfield
Date		Robb P. Winfield, Vice President,
		Chief Financial Officer and Controller